Marathon Oil Corporation is engaged in worldwide exploration, production and marketing of liquid hydrocarbons and natural gas; mining, extraction and transportation of bitumen from oil sands deposits in Alberta, Canada, and upgrading of the bitumen for the production and marketing of synthetic crude oil and by-products; domestic refining, marketing and transportation of crude oil and petroleum products, primarily in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the 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 the Consolidated Financial Statements and Selected Notes to Consolidated Financial Statements, the Supplemental Statistics and our 2007 Annual Report on Form 10-K.

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. For additional risk factors affecting our business, see Item 1A. Risk Factors in our 2007 Annual Report on Form 10-K.

We hold a 60 percent interest in Equatorial Guinea LNG Holdings Limited ("EGHoldings"). Effective May 1, 2007, we no longer consolidate EGHoldings. Our investment is accounted for prospectively 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.

Overview and Outlook

Exploration and Production ("E&P")

Production

Net liquid hydrocarbon and natural gas sales averaged 379 and 369 thousand barrels of oil equivalent per day ("mboepd") during the third quarter and first nine months of 2008, an increase of 2 percent and 5 percent over the same periods of 2007. Sales from the Alvheim/Vilje development offshore Norway and the Neptune development in the Gulf of Mexico more than offset declines in sales due to the deferral of certain production in the Gulf of Mexico as a result of hurricanes. Natural gas sales from the Alba field in Equatorial Guinea contributed to the increased sales in the year-to-date period.

The Alvheim development offshore Norway commenced production in June 2008. The Vilje field, which is tied back to the Alvheim floating production, storage and offloading vessel, began producing July 31, 2008. Commissioning of the Alvheim/Vilje project is continuing with a total of 10 wells currently available for production, out of 12 producing wells planned for the first phase. We have seen extended periods of production at facility capacity of 125 mboepd (75 mboepd net to Marathon) and expect further stabilization at these rates. We have a 65 percent operated interest in the Alvheim fields and a 47 percent outside-operated interest in the Vilje field.

The Neptune development in the Gulf of Mexico commenced production of liquid hydrocarbons and natural gas in early July 2008 and reached full oil capacity after 15 days of operations. The field is currently producing from 6 wells. Marathon has a 30 percent outside-operated interest in the Neptune development. The facility's design capacity is 50 thousand barrels per day ("mbpd") of oil and 50 million cubic feet per day ("mmcfd") of natural gas.

Hurricanes Gustav and Ike impacted Gulf of Mexico production in the latter part of the third quarter, resulting in 9,500 net barrels of oil equivalent per day ("boepd") being shut-in during the quarter. The Ewing Bank development resumed production in late October. The outside-operated Troika and Ursa fields remain shut-in for repairs. These fields are expected to impact fourth quarter 2008 sales by approximately 6 mboepd. We have an approximate 65 percent working interest in Ewing Bank, a 50 percent working interest in Troika and a 4 percent overriding royalty interest in Ursa.

We continue to increase sales from the Williston Basin (the Bakken shale formation) in North Dakota. We currently have 7 rigs drilling. We expect to drill 71 company-operated wells in 2008 and will have over 100 wells in the play by the end of 2008.

Exploration

During the first nine months of 2008, we announced the Portia and the Dione discoveries on Block 31 offshore Angola which were our 27th and 28th discoveries on Blocks 31 and 32. We also participated in 3 wells in our Angola exploration and appraisal program that have reached total depth, the results of which will be announced upon receipt of government and partner approval. At September 30, 2008 we were participating in one appraisal well in Block 32. On Block 31 we are currently drilling an exploratory well and plan to drill two additional exploratory wells the remainder of 2008. We hold a 10 percent outside-operated interest in Block 31 and a 30 percent outside-operated interest in Block 32.

Offshore Angola, we have received approval to proceed with the first deepwater oil development project in Block 31. The development is comprised of the Plutao, Saturno, Venus and Marte ("PSVM") fields. Key contracts are ready to be awarded and construction work is expected to begin later this year. A total of 48 production and injection wells are planned for the PSVM development.

In the third quarter of 2008, we announced a Gulf of Mexico deepwater discovery on the Gunflint prospect located on Mississippi Canyon Block 948. We own a 13 percent outside-operated interest in the block. We are also currently participating in another deepwater exploration well in the Gulf of Mexico and an appraisal well on the Stones prospect located on Walker Ridge Block 508. We hold a 25 percent outside-operated interest in Stones.

In October 2008, development of the Droshky discovery, located in the Gulf of Mexico on Green Canyon Block 244, was authorized by our board of directors. The initial Droshky discovery well and two sidetracks were drilled in 2007, followed in 2008 by a second delineation and sidetrack well. The project will consist of four development wells, which will be tied back to the nearby outside-operated Bullwinkle platform. We have secured a rig to begin drilling in 2009, and first production is targeted for 2010. Our share of sales is expected to peak at about 45 mbpd of liquid hydrocarbons and 43 mmcfd of natural gas, after royalties. We hold a 100 percent working interest in Droshky.

Also in October 2008, development of the Ozona prospect, located in the Gulf of Mexico on Garden Banks Block 515 was authorized. We have secured a rig to complete the previously drilled appraisal well and tie back to the nearby outside-operated Auger platform. First production is expected in 2011. We hold a 68 percent working interest in Ozona.

During the second quarter of 2008 we were awarded all 15 blocks bid in the Central Gulf of Mexico Lease Sale No. 206 conducted by the Minerals Management Service in the first quarter of 2008. Two blocks are 100 percent Marathon, and the remaining blocks were bid with partners, at a total cost of $121 million. Initial drilling on these leases, and those acquired at Lease Sale No. 205 in October 2007, is planned for 2009.

In Indonesia, we are the operator of a drilling rig consortium which has secured a two-year contract for a deepwater exploration drilling rig. The rig will be used for deepwater exploration activities by us and four other companies in Indonesia. The participants have the right to extend this rig commitment. Additionally, in October 2008, we were granted a 49 percent interest and operatorship in the Bone Bay Block offshore Indonesia. The Bone Bay Block is 200 miles southeast of our PasangkayuBlock, which was awarded in 2006. Current exploration plans call for the acquisition of 2D seismic starting in 2009, followed by drilling in 2011.

We ceased efforts to pursue exploration opportunities in Ukraine and closed our Kiev office in the third quarter of 2008.

Divestitures

On October 31, 2008, we closed the sale of our outside-operated interests (24 percent of Heimdal field, 47 percent of Vale field and 20 percent of Skirne field) and associated undeveloped acreage offshore Norway for proceeds of $320 million, before post-closing adjustments. When post-closing adjustments are finalized, the pretax gain on the sale is expected to be between $250 and $270 million.

During the first quarter of 2008, we transferred our interest in an exploration and production license in Sudan to the operator, and as a result, we no longer have any interests in Sudan.

The above discussions include forward-looking statements with respect to the timing and levels of future production, and anticipated future exploratory 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 disposition of interests 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, before royalties, was 28 thousand barrels per day ("mbpd") in the third quarter and 25 mbpd in the first nine months of 2008. Third quarter production increased 15 percent over second quarter as a result of a greater volume of ore being mined and available to the mine processing facility. This improvement is largely a result of additional shovel excavation locations being opened in the mine enabling more consistency in ore availability.

The Athabasca Oil Sands Project ("AOSP") Expansion 1, which includes construction of mining and extraction facilities at the Jackpine mine, expansion of treatment facilities at the existing Muskeg River mine, expansion of the Scotford upgrader and development of related infrastructure, is anticipated to begin operations in 2010 or 2011. As recently announced by the operator, a final investment decision on Expansion 2 has been postponed.

In the third quarter of 2008, following achievement of project payout, the royalty rate increased to the 25 percent of net revenue post-payout rate from the one percent of gross revenue rate that had been in effect for most of the year. During the first quarter of 2008, the royalty calculation methodology for the AOSP was revised to allow for additional eligible costs to the project such that the royalty calculation adjusted retroactively to the one percent as of July 1, 2007.

The above discussion includes forward-looking statements with respect to the start of operations of AOSP Expansion 1. Factors that could be affected 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.

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

Our total refinery throughputs were 8 percent lower in the third quarter and first nine months of 2008 than in the third quarter and first nine months of 2007. Crude oil refined likewise decreased 8 percent in the same periods. Third quarter throughput declines were primarily weather-related, while planned maintenance activities at several of our refineries earlier in the year also contributed to the year-to-date throughput declines.

Our ethanol blending program in the third quarter of 2008 increased 50 percent compared to the same period of 2007. For the first nine months of 2008 we blended 36 percent more ethanol than in the same period of 2007. The future expansion or contraction of our ethanol blending program will be driven by the economics of ethanol supply and government regulations.

Third quarter 2008 Speedway SuperAmerica LLC same store gasoline sales volume decreased 12 percent when compared to the third quarter of 2007 while same store merchandise sales increased by 2 percent for the same period. Our 2007 gasoline sales included the effect of a special sales promotion.

The expansion of our Garyville refinery is 70 percent complete with an on-schedule startup expected in the fourth quarter 2009. We have identified minor cost increases for additional quantities of materials required, material and labor cost escalation and some additional costs associated with the recent hurricanes in the Gulf Coast region. We now project the expansion will cost about $3.4 billion, excluding capitalized interest, or about 5 percent more than the original estimate.

All the permits have been received for the upgrading and expansion project at the Detroit refinery. Construction started at the end of the second quarter of 2008. Due to the current market conditions, we are reevaluating the project construction schedule and expect to defer the project completion. We are currently compiling the new project schedule and cost, and expect to complete this analysis by year end 2008.

In October 2008, we completed the sale of our 50 percent ownership interest in PTC. Sale proceeds, before closing costs, were $625 million, with a pretax gain on the sale of approximately $125 million expected. Immediately preceding the sale, we received a $75 million redemption of our partnership interest from PTC that was accounted for as a return of investment.

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")

We own 45 percent of Atlantic Methanol Production Company LLC ("AMPCO") and 60 percent of Equatorial Guinea LNG Holdings Limited ("EGHoldings"), both of which are accounted for under the equity method of accounting. AMPCO operates a methanol plant and EGHoldings operates a liquefied natural gas ("LNG") production facility, both located on

Bioko Island, Equatorial Guinea. Alba field dry natural gas, which remains after the condensate and liquefied petroleum gas ("LPG") are removed, is supplied to both of these facilities under long-term, fixed price contracts. We consider the prices under these contracts to be comparable to the price that could be realized from transactions with unrelated parties in this market under the same or similar circumstances, because of the location of the natural gas and limited local demand for natural gas in Equatorial Guinea.

The EGHoldings LNG production facility delivered 13 cargoes during the third quarter of 2008. Our share of LNG sales worldwide totaled 6,048 metric tonnes per day ("mtpd") for the third quarter of 2008 compared to 6,137 mtpd in the third quarter of 2007 and 6,453 mtpd in the first nine months of 2008 compared to 3,117 mtpd in the first nine months of 2007. 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.

Production at the LNG facility in Equatorial Guinea was curtailed in July while scheduled repairs and modifications were completed on the facility to improve the overall efficiency of the plant. The methanol plant experienced a series of planned and unplanned maintenance events, but the facility returned to full production in October 2008. Neither situation significantly impacted our financial results for the quarter.

We continue to invest in the development of new technologies to create value and supply new energy sources. In the first nine months of 2008, we recorded costs of approximately $59 million related to natural gas technology research, including completing construction and beginning the commissioning of the demonstration plant for Gas-To-FuelsTM technology.

Management's Discussion and Analysis of Results of Operations

Consolidated Results of
Operations

    Revenues are summarized by segment in the following table:

                                   Three Months Ended       Nine Months Ended
                                     September 30,            September 30,
(In millions)                      2008         2007        2008        2007
E&P                              $   3,873    $  2,447    $ 10,289    $  6,437
OSM                                    600           -         815           -
RM&T                                18,766      14,605      52,767      40,424
IG                                      24          64          64         188
  Segment revenues                  23,263      17,116      63,935      47,049

Elimination of intersegment
revenues                              (347)       (231)     (1,050)       (571)
Gain (loss) on U.K. natural gas
contracts                              198        (123)        (37)       (111)
  Total revenues                 $  23,114    $ 16,762    $ 62,848    $ 46,367

Items included in both revenues
and costs and
   expenses:

  Consumer excise taxes on
petroleum products and
merchandise                      $   1,273    $  1,352    $  3,784    $  3,856

E&P segment revenues increased $1,426 million in the third quarter and $3,852 million in the first nine months of 2008 from the comparable prior-year periods. Increased liquid hydrocarbon realizations, averaging $111.33 per barrel in the third quarter and $104.33 in the first nine months of 2008, account for the majority of the revenue increase in both periods. Additionally, sales from our new Alvheim/Vilje development in Norway increased international liquid hydrocarbon sales volumes in the third quarter. Partially offsetting the increase in liquid hydrocarbon realizations were lower natural gas sales volumes in third quarter due to more natural gas storage in Ireland and Alaska. Liquid hydrocarbon and natural gas sales volumes in the U.S. were lower in both periods primarily due to shutdowns in the third quarter for hurricanes and natural production declines in the Gulf of Mexico. Sales from the new Neptune development in the Gulf of Mexico reversed the decline trend in the third quarter, keeping liquid hydrocarbon sales volumes flat in spite of the hurricanes. For the nine-month period, international natural gas sales volumes continue to reflect an increase related to sales to the EGHoldings LNG production facility that began operations in the second quarter of 2007. This increase in fixed-price sales volumes limited the increase in our average international natural gas realizations. 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.

See Supplemental Statistics for information regarding net sales volumes and average realizations by geographic area.

Excluded from E&P segment revenues were gains of $198 million and losses of $123 million for the third quarters of 2008 and 2007 related to natural gas sales contracts in the U.K. that are accounted for as derivative instruments. For the first nine months of 2008 and 2007 losses of $37 million and $111 million are excluded from E&P segment revenues.

OSM segment revenues totaled $600 million in the third quarter and $815 million in the first nine months of 2008. Revenues in both periods include the impact of derivative instruments intended to mitigate price risk related to future sales of synthetic crude. Pretax gains of $255 million were included in the third quarter and pretax losses of $131 million in the first nine months of 2008. Net synthetic crude sales for the third quarter of 2008 were 32 mbpd at an average realized price of $113.42 per barrel.

See Item 3. Quantitative and Qualitative Disclosures About Market Risk for additional discussion about derivative instruments.

RM&T segment revenues increased $4,161 million in the third quarter of 2008 and $12,343 million in the first nine months of 2008 from the comparable prior-year periods. The third quarter increase primarily reflects increased refined product selling prices, slightly offset by lower refined product and liquid hydrocarbon sales volumes. For the nine -month period the increase primarily reflects increased refined product and liquid hydrocarbon selling prices, slightly offset by lower refined product and liquid hydrocarbon sales volumes.

For information on segment income, see Segment Results.

Income from equity method investments increased $100 million in the third quarter of 2008 and $341 million in the first nine months of 2008 from the comparable prior-year periods. Income from the EGHoldings LNG production facility accounts for most of the increase, as it began operations in May 2007. Forty-two cargoes of LNG were delivered during the first nine months of 2008, an average of 14 per quarter, as compared to an average of 5 per quarter in the first nine months of 2007.

Cost of revenues increased $4,041 million and $15,074 million in the third quarter and first nine months of 2008 from the comparable prior-year periods. These increases resulted primarily from increases in acquisition costs of crude oil, refinery charge and blend stocks and purchased refined products in the RM&T segment.

Exploration expenses were $109 million and $368 million in the third quarter and first nine months of 2008, including expenses related to dry wells of $24 million and $106 million. Exploration expenses were $88 million and $264 million in the third quarter and first nine months of 2007, including expenses related to dry wells of $22 million and $76 million. Other exploration expense increases in the first nine months of 2008 relate to the acquisition of seismic data in Indonesia and the evaluation of Canadian in-situ oil sands leases.

Gain on foreign currency derivative instruments in the third quarter of 2007 primarily represents unrealized gains on foreign currency derivative instruments entered to limit our exposure to changes in the Canadian dollar exchange rate related to the cash portion of the purchase price for Western.

Provision for income taxes increased $911 million and $437 million in the third quarter and first nine months of 2008 from the comparable periods of 2007 as a result of increases in income before income taxes. The geographic sources of income and related tax expense contributed to the increase in the effective income tax rates for the first nine months of 2008 when compared to the same period in 2007. The estimated 2008 effective tax rate was reduced by less than 4 percentage points by the reversal of previously recorded valuation allowances on Norwegian net operating losses.

The following is an analysis of the effective income tax rates for the first nine months of 2008 and 2007:

                                                 Nine Months Ended September 30,
                                                  2008                 2007
Statutory U.S. income tax rate                          35  %                35  %
Effects of foreign operations, including
foreign tax credits                                     11                    8
State and local income taxes, net of federal
income tax effects                                       1                    2
Other tax effects                                       (1)                  (1)
    Effective income tax rate for continuing
operations                                              46  %                44  %

Discontinued operations in 2007 is a sales price adjustment on the June 2006 sale of our Russian oil exploration and production businesses.

Segment Results

    Segment income is summarized in the following table:

                                   Three Months Ended       Nine Months Ended
                                     September 30,            September 30,
(In millions)                       2008         2007       2008       2007
E&P

  United States                  $      285    $   147    $     888    $   470
  International                         654        332        1,563        794
      E&P segment                       939        479        2,451      1,264

OSM                                     288          -          158          -
RM&T                                    771        482          854      2,073
IG                                       65         52          266         83

      Segment income                  2,063      1,013        3,729      3,420
Items not allocated to segments,
net of income taxes:
  Corporate and other
unallocated items                      (100)         3         (141)      (149)
  Gain (loss) on U.K. natural
gas contracts                           101        (62)         (19)       (56)
  Gain on foreign currency
derivative instruments                    -         74            -         74
  Loss on early extinguishment
of debt                                   -         (7)           -         (9)
  Discontinued operations                 -          -            -          8

Net income                       $    2,064    $ 1,021    $   3,569    $ 3,288

United States E&P income increased $138 million, or 94 percent, and $418 million, or 89 percent, in the third quarter and first nine months of 2008 compared to the same periods of 2007. Pretax income increased $214 million and $665 million in the same periods. The higher pretax income in both periods is primarily a result of higher liquid hydrocarbon and natural gas realizations, partially offset by increased production taxes and higher depletion, depreciation and amortization, primarily related to new production.

International E&P income increased $322 million, or 97 percent, and $769 million, or 97 percent, in the third quarter and first nine months of 2008 compared to the same periods of 2007. Pretax income increased $693 million and $1,616 million in the same periods. The higher pretax income in both periods is . . .