Exploration and Production

        (InIn the discussion that follows regarding our exploration and production operations, references to "net"“net” wells, productionsales or salesinvestment indicate our ownership interest or share, as the context requires.)

        We conductAt the end of 2009, we were conducting oil and gas exploration, development and production activities in ten countries, with a focus on international growth while continuing to maintain our position in the United States. Principal exploration activities were ineight countries: the United States, Angola, Canada, Equatorial Guinea, Indonesia, Libya, Norway Angola and Indonesia. Principal development and production activities were in the United States, the United Kingdom, Norway, Equatorial GuineaKingdom. During 2009, we exited Gabon and Libya.Ireland. We plan to begin exploration activities in Poland during 2010.

Our 20062009 worldwide net liquid hydrocarbon sales from continuing operations averaged 223243 thousand barrels per day ("mbpd"(“mbpd”), an increase of 36 percent from 2005 levels.. Our 20062009 worldwide net natural gas sales, including natural gas acquired for injection and subsequent resale, averaged 847941 million cubic feet per day ("mmcfd"(“mmcfd”), a decrease of 9 percent compared to 2005.. In total, our 20062009 worldwide net sales from continuing operations averaged 365400 thousand barrels of oil equivalent ("mboe") per day compared to 319 mboe per day in 2005. (For(“mboepd”). For purposes of determining boe,barrels of oil equivalent (“boe”), natural gas volumes are converted to approximate liquid hydrocarbon barrels by dividing the natural gas volumes expressed in thousands of cubic feet ("mcf"(“mcf”) by six. The liquid hydrocarbon volume is added to the barrel equivalent of natural gas volume to obtain boe.) In 2007, our worldwide net production available for sale is expected These volumes exclude 7 mboepd related to average 390 to 425 mboe per day, excluding future acquisitions and dispositions.discontinued operations.

        The above projections of 2007 worldwide net liquid hydrocarbon and natural gas production available for sale volumes are forward-looking statements. Some factors that could potentially affect levels of production available for sale include pricing, supply and demand for petroleum products, the amount of capital available for exploration and development, regulatory constraints, production decline rates of mature fields, timing of commencing production from new wells, drilling rig availability, inability to or delay in obtaining necessary government and third-party approvals and permits, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other geological, operating and economic considerations. These factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Exploration

In the United States during 2006,2009, we drilled 3376 gross (16(50 net) exploratory wells of which 2172 gross (10(48 net) wells encountered commercial quantities of hydrocarbons. Of these 2172 wells, 6 gross (4 net) wells were temporarily suspended or were in the process of completingbeing completed at year end. Internationally, we drilled 219 gross (4(1 net) exploratory wells of which 166 gross (3(1 net) wells encountered commercial quantities of hydrocarbons. Of these 16 wells, 9 gross (3 net)All 6 wells were temporarily suspended or were in the process of being completed at December 31, 2006.2009.

North America

United States– Our U.S. operations accounted for 26 percent of our 2009 worldwide net liquid hydrocarbon sales volumes and 40 percent of our worldwide net natural gas sales volumes.

Offshore – The Gulf of Mexico continues to be a core area for us. At the end of 2006, we had interests in 129 blocks in the Gulf of Mexico, including 100 in the deepwater area.

During 2006, we increased our interest from 20 percent to 30 percent in the Stones prospect (Walker Ridge Block 508). An appraisal well is planned for 2007 on this outside-operated 2005 discovery.

        In 2001, a successful discovery well was drilled on the Ozona prospect (Garden Banks Block 515) in the Gulf of Mexico and, in 2002, two sidetrack wells were drilled, one of which was successful. We are continuing to evaluate options to develop the Ozona prospect. Commercial terms have been secured for the tie-back and processing of Ozona production and we have been actively searching for a rig to drill the development well. We hold a 68 percent operated interest in the Ozona prospect.

        A well on the Flathead prospect (Walker Ridge Block 30) in the Gulf of Mexico was suspended in 2002. Technical evaluations are complete and commercial evaluations continued in 2006. The drilling of this prospect is delayed due to the shortage of available deepwater rigs. We continue to pursue partnering opportunities with other oil and gas companies that have deepwater rigs under contract. We hold a 100 percent operated interest in the Flathead prospect.

        Norway  –  We hold interests in over 700,000 gross acres offshore Norway and plan to continue our exploration effort there. In 2006, we participated in a successful appraisal well on the Gudrun field, located 120 miles off the coast. Marathon holds a 28 percent outside-operated interest in Gudrun where we are primarily focused on evaluating development scenarios.

        Angola  –  Offshore Angola, we hold a 10 percent outside-operated interest in Block 31 and a 30 percent outside-operated interest in Block 32. Through February 2007, we have announced 20 discoveries on these blocks. We have

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also participated in four wells that have reached total depth, the results of which will be announced upon government and partner approvals. We expect to participate in 10 or 11 wells on these blocks in 2007.

        On Block 31, four previously announced discoveries (Plutao, Saturno, Marte and Venus) and one successful appraisal well form a planned development area in the northeastern portion of the block. Also on Block 31, we had five previously announced discoveries located in the southeastern portion of the block (Palas, Ceres, Juno, Astraea and Hebe). In 2006 and early 2007, we announced discoveries at Urano, Titania, Terra and an unnamed well. We are integrating the results of these wells with our previously announced discoveries.

        On Block 32, we previously announced three discoveries (Gindungo, Canela and Gengibre). In 2006, we announced the fourth discovery on Block 32, the Mostarda-1, and a successful deepwater delineation well, Gengibre-2. We also announced that hydrocarbons were encountered in the Salsa well, but additional drilling is required to assess its commerciality. In early 2007, we announced two additional discoveries, the Manjericao and Caril wells. These discoveries move Block 32 closer toward establishment of a commercial development.

        Equatorial Guinea  –  During 2004, we participated in two natural gas and condensate discoveries on the Alba Block offshore Equatorial Guinea. The Deep Luba discovery well, drilled from the Alba field production platform, encountered natural gas and condensate in several pay zones. The Gardenia discovery well is located 11 miles southwest of the Alba Field. We are currently evaluating development scenarios for both the Deep Luba and Gardenia discoveries. We hold a 63 percent operated interest in the Alba Block.

        In 2004, we announced the results of the Corona well drilled on Block D offshore Equatorial Guinea, where we are the operator with a 90 percent working interest. The Corona well confirmed an extension of the Alba field on to Block D. An application for an Area of Commercial Discovery was submitted prior to the end of the production sharing contract's exploration period, which expired at the end of 2006. We are currently in discussions with the Equatorial Guinea government regarding our rights to develop the Block D extension of the Alba Field.

        Libya  –  We hold a 16 percent outside-operated interest in the Waha concessions, which encompass almost 13 million acres located in the Sirte Basin. Our exploration program in 2006 included the drilling of 12 wells, nine of which were successful. Most of these discoveries extended previously defined hydrocarbon accumulations.

        Canada  –  We are the operator and own a 30 percent interest in the Annapolis lease offshore Nova Scotia, where we continue to evaluate further drilling. In late 2006, we decided to withdraw from the adjacent Cortland lease, where we hold a 75 percent interest, and the adjacent Empire lease, where we hold a 50 percent interest. As a result of this withdrawal, a charge equal to 25 percent of the remaining work commitment, or $47 million, was recorded as exploration expense in 2006 and the cash payment will be due to the Canadian provincial government in 2007.

        Indonesia  –  We are the operator and hold a 70 percent interest in the Pasangkayu Block offshore Indonesia. The 1.2 million acre block is located mostly in deep water, predominantly offshore of the island of Sulawesi in the Makassar Strait, directly east of the Kutei Basin oil and natural gas production region. The production sharing contract with the Indonesian government was signed in 2006. We expect to begin collecting geophysical data in 2007, followed by exploratory drilling in 2008 and 2009.

Production (including development activities)

        United States  –  Our U.S. operation accounted for 34 percent of our 2006 worldwide net liquid hydrocarbon sales from continuing operations and 63 percent of our worldwide net natural gas sales.

        During 2006,2009, our net sales in the Gulf of Mexico averaged 3524 mbpd of liquid hydrocarbons representing 46 percent of our total U.S. net liquid hydrocarbon sales, and 4320 mmcfd of natural gas, representing 8 percent of our total U.S. net natural gas sales. Net liquid hydrocarbon sales in the Gulf of Mexico increased slightly from the priorgas. At year mainly due to the effects of five tropical storms/hurricanes in 2005. Net natural gas sales decreased by 41 mmcfd from the prior year primarily because natural gas sales from the Camden Hills field ended in early 2006 as a result of increased water production. At year-end 2006,end 2009, we held interests in seven producing fields and eightfour platforms in the Gulf of Mexico, of which four platforms are operated by Marathon.we operate one platform.

We operate the Ewing Bank 873 platform which is located 130 miles south of New Orleans, Louisiana. The majority of our salesplatform started operations in 1994 and serves as a production hub for the Lobster, Oyster and Arnold fields. The facility also processes third-party production via subsea tie-backs.

We own a 50 percent interest in the Gulf of Mexico comes from theoutside-operated Petronius development infield on Viosca Knoll Blocks 786 and 830. We own a 50 percent outside-operated interestAn additional development well was successfully completed in these blocks.2009. The Petronius platform providesis capable of providing processing and transportation services to adjacentnearby third-party fields. For example, Petronius processes the production from our Perseus field which

The Neptune development commenced production of liquid hydrocarbons and natural gas in April 2005 and is located five miles from the platform.

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July 2008. We hold a 30 percent outside-operatedworking interest in the Neptune deepwaterthis outside-operated development located on Atwater Valley Blocks 573, 574, 575, 617 and 618 in the Gulf of Mexico, 120 miles off the coast of Louisiana. The initialcompleted Phase I development plan for Neptune was sanctioned in 2005 and includes sevenincluded six subsea wells tied back to a stand-alone mini-tension leg platform. ConstructionPhase II development activities have begun and the first well in this program was successfully drilled and completed in late 2009.

Development of the platform and facilityDroshky discovery, located on Green Canyon Block 244, continued through 2006in 2009. Droshky Phase I is a four well liquid hydrocarbon development with first production targeted for mid-year 2010. Ongoing development activities include running intelligent well completions, installation of the subsea facilities and topside modifications to the third-party Bullwinkle host platform. Expected net peak production is approximately 50 mboepd. We hold a 100 percent operated working interest in Droshky.

Development of the Ozona prospect, located on Garden Banks Block 515, has also continued. We have secured a rig to complete the previously drilled appraisal well and tie back to the nearby third-party Auger platform. First production is expected in early 2008.2011. We hold a 68 percent working interest in Ozona.

In 2008, we drilled a successful liquid hydrocarbon appraisal well on the Stones prospect located on Walker Ridge Block 508. We hold a 25 percent interest in the outside-operated Stones prospect. In the third quarter of 2008, we announced deepwater liquid hydrocarbon discovery on the Gunflint prospect located on Mississippi Canyon Block 948. We own a 13 percent interest in this outside-operated prospect. In the first quarter of 2009, we participated in a deepwater liquid hydrocarbon discovery on the Shenandoah prospect located on Walker Ridge Block 52. We own a 20 percent interest in the outside-operated prospect. In December 2009, we began drilling the Flying Dutchman well, on Green Canyon Block 511, where we have 63 percent ownership and are onethe operator of this liquid hydrocarbon prospect.

In addition to the largestprospects listed above, we held interests in 103 blocks in the Gulf of Mexico at the end of 2009, including 97 in the deepwater area. Our plans call for exploration drilling on some of these leases in 2010 and 2011.

Onshore – We produce natural gas producers in the Cook Inlet and adjacent Kenai Peninsula of Alaska. We have operated and outside-operated interests in 10 fields and hold a 51 to 100 percent working interest in each. In 2006,2009, our Alaskan net natural gas sales from Alaska averaged 156 mmcfd, representing 29 percent of87 mmcfd. Typically, our total U.S. net natural gas sales. Our natural gas sales from Alaska are seasonal in nature, trending down during the second and third quarters of each year and increasing during the fourth and first quarters. In May 2006, upon receipt of regulatory approvals,To manage supplies to meet contractual demand we began to produce and store natural gas in a partially depleted reservoir in the Kenai natural gas field. TheIn 2009, we drilled six wells in Alaska and plan to drill four to six wells per year during 2010 through 2012.

We hold leases with natural gas in storage will be used to manage supplies to meet contractual demand. In addition to our operations in other established Alaskan fields, production from the Ninilchik field began in 2003 and development continues on the field. Ninilchik natural gas is transported through the 35-mile portion of the Kenai Kachemak Pipeline which connects Ninilchik to the existing natural gas pipeline infrastructure serving residential, utility and industrial markets on the Kenai Peninsula, in Anchorage and in other parts of south central Alaska. We operate Ninilchik and own a 60 percent interest in it and the section of the Kenai Kachemak Pipeline described above. Our 2006 development program in the Cook Inlet included participation in the drilling of seven wells.

        Net liquid hydrocarbon sales from our Wyoming fields averaged 21 mbpd in 2006 and 2005. Net natural gas sales from our Wyoming fields averaged 119 mmcfd in 2006 compared to 107 mmcfd in 2005. The increase in our Wyoming net natural gas sales is primarily attributed to higher net sales from the Powder River Basin, which averaged 77 mmcfd in 2006 compared to 66 mmcfd in 2005 as a result of 2005 drilling activity. Development of the Powder River Basin continued in 2006 with 119 wells drilled, which was down from the 195 wells drilled in 2005 due to project delays primarily caused by regulatory and produced water management issues. Additional development of our southwest Wyoming interests continued in 2006 where we participated in the drilling of 27 wells.

        Net natural gas sales from our Oklahoma fields averaged 87 mmcfd in 2006 compared to 77 mmcfd in 2005 primarily as a result of development and exploratory drilling. Our 2006 development program continued to focus in the Anadarko Basin where we participated in the drilling of 75 wells.

        Net natural gas sales from our east Texas and north Louisiana fields averaged 71 mmcfd in 2006 compared to 75 mmcfd in 2005. This decrease is primarily attributable to sour gas handling capacity limits at the natural gas plants that purchase our east Texas natural gas, partially offset by development drilling results. Active development of the Mimms Creek field in east Texas continued in 2006.

        Net liquid hydrocarbon sales from the Permian Basin region, which extends from southeast New Mexico to west Texas, averaged 14 mbpd in 2006 compared to 16 mbpd in 2005. This decrease in net sales was due to natural field declines partially offset by development project results in the Indian Basin and Drinkard areas of southeast New Mexico.

        In the first half of 2006, we completed leasehold acquisitions totaling approximately 200,000 acres in the Bakken Shale oil play. The majority of the acreage is located in North Dakota with the remainder in eastern Montana. We now own a substantial position in the Bakken Shale with approximately 300 locations to be drilled over the next five years. Our initial focus has been to evaluate our leasehold position.

        In July 2006, we completed a natural gas leasehold acquisition in the Piceance Basin of Colorado, located in Garfield County in the Greater Grand Valley field complex. The acreage is located near adjacent production. Our plans include drilling approximately 70065 wells over the next ten years with first production expectedfive years. We currently have one operated drilling rig running and averaged net sales of 15 mmcfd in late 2007.2009.

We continue to assess our acreage positionhold 336,000 acres over the Bakken Shale oil play in the BarnettWilliston Basin of North Dakota with a working interest of approximately 84 percent. Approximately 225 locations will be drilled over the next four to five years. We are evaluating other potential horizons above and below the Middle Bakken. We currently have four operated drilling rigs running in our Bakken program. We exited 2009 with average net sales of 11 mboepd in December.

In 2008, we successfully completed our first horizontal well in the Woodford Shale natural gas play in the Anadarko Basin of Oklahoma. We are currently participating in additional horizontal wells in the area where we hold 52,000 net acres. In 2009, we drilled 13 wells, five of which were operated. We plan to drill 10 to 15 wells in 2010.

We also have domestic natural gas operations in Oklahoma, east Texas and north centralLouisiana, with combined net sales of 121 mmcfd in 2009, and liquid hydrocarbon operations in the Permian Basin of west Texas, with net sales of 8 mbpd in 2009. In June 2009, we completed the sales of our operated and a portion of our outside-operated Permian Basin producing assets in New Mexico and west Texas. To date,We still retain interests in 12 Permian Basin fields.

We hold acreage in two additional emerging shale resource plays in the U.S. In the Appalachian Basin we have leased approximately 85,000hold 70,000 net acres in the Marcellus Shale natural gas play in Pennsylvania and West Virginia. We drilled five wells

in 2009 and plan to drill another 8 to 12 wells in 2010. In Louisiana and east Texas, we hold 25,000 net acres in the Haynesville Shale natural gas play, where we drilled one well in 2009. We plan to drill three to four wells in 2010.

Net liquid hydrocarbon and natural gas sales from our Wyoming fields averaged 18 mbpd and 113 mmcfd in 2009. We plan to drill 24 wells in 2010.

Canada – We hold interests in both operated and outside-operated exploration stage in-situ oil sand leases as a result of the acquisition of Western in 2007. The three potential in-situ developments are Namur, in which we hold a 60 percent operated interest, Birchwood, in which we hold a 100 percent operated interest, and Ells River, in which we hold a 20 percent outside-operated interest. Initial test drilling on the Birchwood prospect positively confirmed bitumen presence with additional test drilling required to confirm reservoir quality.

Africa

Equatorial Guinea – We own a 63 percent operated working interest in the Alba field which is offshore Equatorial Guinea. During 2009, net liquid hydrocarbon sales averaged 42 mbpd, or 17 percent of our worldwide net liquid hydrocarbon sales volumes, and net natural gas sales averaged 426 mmcfd, or 45 percent of our worldwide net natural gas sales. Net liquid hydrocarbon sales volumes in 2009 included 30 mbpd of primary condensate.

We also own a 52 percent interest in Alba Plant LLC, an equity method investee that operates an onshore liquefied petroleum gas (“LPG”) processing plant. Alba field natural gas is processed by the LPG plant under a long-term contract at a fixed price for the British thermal units used in the operations of the LPG plant and for the hydrocarbons extracted from the natural gas stream in the form of secondary condensate and LPG. During 2009, a gross 943 mmcfd of natural gas was supplied to the LPG production facility and the resulting net liquid hydrocarbon sales volumes in 2009 included 4 mbpd of secondary condensate and 12 mbpd of LPG produced by Alba Plant LLC.

As part of our Integrated Gas segment, 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 as equity method investments. AMPCO operates a methanol plant and EGHoldings operates a liquefied natural gas (“LNG”) production facility, both located on Bioko Island. Dry natural gas from the Alba field, which remains after the condensate and LPG are removed, is supplied to both of these facilities under long-term contracts at fixed prices. Because of the location of and limited local demand for natural gas in Equatorial Guinea, we consider the prices under the contracts with Alba Plant LLC, AMPCO and EGHoldings to be comparable to the price that could be realized from transactions with unrelated parties in this market under the same or similar circumstances. Our share of the income ultimately generated by the subsequent export of secondary condensate and LPG produced by Alba Plant LLC is reflected in our E&P segment. Our share of the income ultimately generated by the subsequent export of methanol produced by AMPCO and LNG produced by EGHoldings is reflected in our Integrated Gas segment as discussed below. During 2009, a gross 115 mmcfd of dry natural gas was supplied to the methanol plant and a gross 647 mmcfd of dry gas was supplied to the LNG production facility. Any remaining dry gas is returned offshore and reinjected back into the Alba field for later production.

We hold a 63 percent operated interest in the Deep Luba and Gardenia discoveries on the Alba Block and we are the operator with a 90 percent interest in the Corona well on Block D. These wells are part of our long-term LNG strategy. We expect these discoveries to be developed when the natural gas supply from the nearby Alba field starts to decline.

Angola –Offshore Angola, we hold 10 percent interests in Block 31 and Block 32, both of which are outside-operated. The discoveries on Blocks 31 and 32 represent four potential development hubs. The Plutao, Saturno, Venus and Marte discoveries and one successful appraisal well form a planned development area in the northeastern portion of Block 31. In 2008, we received approval to proceed with this first deepwater development project, called the PSVM development. The PSVM development will utilize a floating, production, storage and offloading (“FPSO”) vessel. A total of 48 production and injection wells are planned with the drilling of the first three to four development wells planned in 2010. First production is anticipated in late 2011 to early 2012. Other discoveries on Block 31 comprise potential development areas in the southeast and middle portions of the block. Eight of the Block 32 discoveries form a potential development in the eastern area of that block. We expect first production on Block 32 in 2015 or 2016.

Libya – We hold a 16 percent interest in the outside-operated Waha concessions, which encompass almost 13 million acres located in the Sirte Basin. Our exploration program in 2009 included the drilling of four wells. One well is waiting on completion, one was dry and abandoned, and two counties. Oneare currently drilling. We also drilled 5 development wells in Libya during the year. Net liquid hydrocarbon sales in Libya averaged 46 mbpd in 2009. The 2009 net liquid hydrocarbon sales in Libya represented 19 percent of our worldwide net liquid hydrocarbon sales volumes. Net natural gas sales in Libya averaged 4 mmcfd in 2009.

Our Faregh Phase II Gas Plant project is expected to deliver a gross 180 mmcfd of natural gas and 15 mbpd of liquid hydrocarbons into the Libyan domestic market. Commissioning will begin in 2010, with startup planned for first quarter of 2011.

Europe

Norway – Norway is a growing core area, which complements our long-standing operations in the U.K. sector of the North Sea discussed below. We were approved for our first operatorship on the offshore Norwegian continental shelf in 2002, where today we operate eight licenses and hold interests in over 600,000 gross acres.

The operated Alvheim complex located on the Norwegian continental shelf commenced production in June 2008. The complex consists of an FPSO with subsea infrastructure. Improved reliability, combined with optimization work, increased the throughput of the FPSO to 142 mbpd, up from the original design of 120 mbpd. Produced oil is transported by shuttle tanker and produced natural gas is transported to the existing U.K. Scottish Area Gas Evacuation (“SAGE”) system using a 14-inch diameter, 24-mile cross border pipeline. First production to the complex was from the Alvheim development which is comprised of the Kameleon, East Kameleon and Kneler fields, in which we have a 65 percent working interest, and the Boa field, in which we have a 58 percent working interest. At the end of 2009, the Alvheim development included ten producing wells and two water disposal wells. A Phase 2 drilling program targeting three additional production wells, and a Phase 2b drilling program with two additional production wells, is planned in 2010 through 2012. Net sales for 2009 averaged 56 mbpd of liquid hydrocarbons and 30 mmcfd of natural gas.

The nearby outside-operated Vilje field, in which we own a 47 percent working interest, began producing through the Alvheim complex in August 2008. During 2009, net liquid hydrocarbon sales from Vilje averaged 12 mbpd.

In June 2009, we completed the drilling program for the Volund field as a subsea tieback to the Alvheim complex. The Volund development, in which we own a 65 percent operated interest, is located approximately five miles south of the Alvheim area and consists of one production well and five horizontalone water disposal well. First production from Volund was announced in September 2009. The Volund owners have contracted for 25 gross mbpd (16 mbpd net) firm capacity on the Alvheim FPSO beginning in July 2010. Until that date, Volund will act as a swing producer, filling any available capacity and allowing the FPSO to be fully utilized.

Also offshore Norway, we and our partners announced the Marihone and Viper discoveries, both located within tie-back distance of the Alvheim FPSO. 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. The Viper oil discovery is located immediately next to Volund field in PL203, about 12 miles south of the Alvheim FPSO. We are the operator and hold a 65 percent interest in Viper. Conceptual development studies for both discoveries have begun.

In addition, we hold a 28 percent interest in the outside-operated Gudrun field, located 120 miles off the coast of Norway. In January 2009, the operator announced a development concept that includes a fixed processing platform with seven production wells have been drilledthat would be tied to existing facilities on the Sleipner field, and completion activity is underway on these first wells. Seismic data was acquired in 2006 and is being evaluated.one water disposal well.

United Kingdom – Our largest asset in the U.K. sector of the North Sea is the Brae area complex where we are the operator and have a 42 percent working interest in the South, Central, North and West Brae fields and a 38 percent working interest in the East Brae field. The Brae A platform and facilities host the underlying South Brae field and the adjacent Central and West Brae fields. A two well development program is scheduled in 2010 for West Brae. The North Brae field, which is produced via the Brae B platform, and the East Brae field, which is produced via the East Brae platform, are natural gas condensate fields. Our share ofThe East Brae platform hosts the nearby Braemar field in which we have a 28 percent working interest. Net liquid hydrocarbon sales from the Brae area

averaged 15 mbpd of liquid hydrocarbons in 2006, compared with 1811 mbpd in 2005. This reduction primarily resulted from West Brae field decline and the timing of sales of liquid hydrocarbons. Our share of2009. Net Brae natural gas sales averaged 151101 mmcfd, which was lower than the 169 mmcfdor 11 percent of our worldwide net natural gas sales volumes, in 2005 as a result of natural field declines in the North and East Brae gas condensate fields.2009.

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The strategic location of the Brae platforms along with pipeline and onshore infrastructure has generated third-party processing and transportation business since 1986. Currently, there arethe operators of 28 third-party fields have contracted to use the Brae system. In addition to generating processing and pipeline tariff revenue, this third-party business also has a favorable impact on Brae area operations by optimizing infrastructure usage and extending the economic life of the complex.

The Brae group owns a 50 percent interest in the outside-operated Scottish Area Gas Evacuation ("SAGE"(“SAGE”) system. The SAGE pipeline transports natural gas from the Brae area, and the third-party Beryl areasarea, and has a total wet natural gas capacity of 1.1 billion cubic feet ("bcf"(“bcf”) per day. The SAGE terminal at St. Fergus in northeast Scotland processes natural gas from the SAGE pipeline and almostas well as approximately 1 bcf per day of third-party natural gas from the third-party Britannia field.gas.

In the U.K. Atlantic Margin west of the Shetland Islands, we own an approximateaverage 30 percent working interest in the outside-operated Foinaven area complex, consisting of a 28 percent working interest in the main Foinaven field, 47 percent ofworking interest in East Foinaven and 20 percent ofworking interest in the T35 and T25 accumulations. Our share offields. Net sales from the Foinaven fields averaged 1713 mbpd of liquid hydrocarbons and 107 mmcfd of natural gas in 2006, compared to 16 mbpd and 9 mmcfd2009. We are upgrading the FPSO which will extend the life of this project through 2021.

We have a 45 percent interest in 2005, primarily asfive exploratory U.K. onshore coal seam gas licenses. Drilling has been completed in five exploration wells in three of the licenses. We also hold a result of increased liquid handling capacity following facility modifications, increased well potential and improved operating efficiency.55 percent operated working interest in 11 blocks awarded in a 2008 bid round. Our interest covers 520,000 gross acres.

        NorwayPoland – Norway isWe have recently added a strategicnew opportunity to our portfolio, Poland shale gas. In November we were awarded the 296,000 acre Kwidzyn Block, followed by the 249,000 acre Orzechow Block in December. The five and growing core area, which complements our long-standing operations in the U.K. sector of the North Sea discussed above.a half year exploration phase for each block includes 2D seismic and at least one well. We were approvedawarded the 269,000 acre Brodnica Block in January 2010, and we continue to look for our firstadditional opportunities in Poland. We hold a 100 percent interest and operatorship onin all three blocks.

Other International

Indonesia – We are the Norwegian continental shelf in 2002, where today we operate seven licenses.

        During 2006, net liquid hydrocarbonoperator and natural gas sales in Norway from the Heimdal, Vale and Skirne fields averaged 2 mbpd and 36 mmcfd. We ownhold a 2470 percent outside-operated interest in the Heimdal field, a 47 percent outside-operated interestPasangkayu Block offshore Indonesia. The block is located mostly in deep water, predominantly offshore of the island of Sulawesi in the Vale fieldMakassar Strait, directly east of the Kutei Basin production region. The production sharing contract with the Indonesian government was signed in 2006 and we completed 3D seismic acquisition in May 2008. A mandatory 25 percent relinquishment was submitted to the Indonesian government in September 2009 and upon approval, the block size will be reduced from 1.2 million gross acres to 872,400 gross acres. We expect to drill two wells in 2010.

In October 2008, we were granted a 2049 percent outside-operated interest and operatorship in the Skirne field.Bone Bay Block offshore Sulawesi. An increase in ownership to 55 percent is pending Indonesian government approval. The Bone Bay Block covers an area of 1.23 million acres and is 200 miles southeast of our Pasangkayu Block. Current exploration plans for Bone Bay call for the acquisition of seismic data starting in 2010, followed by drilling of one exploration well in 2011. In the second quarter of 2009, we were awarded a 49 percent interest and operatorship in the Kumawa Block, our third Indonesia offshore exploration block, located offshore West Papua. An increase in ownership to 55 percent is pending Indonesian government approval. The Kumawa Block encompasses 1.24 million acres. A 2D seismic survey is planned in the first quarter of 2010 and we expect to drill one exploration well in 2011-2012.

We are the operator of the Alvheim complex located on the Norwegian Continental Shelf. This development is comprised of the Kameleon and Kneler discoveries,a drilling rig consortium, with five other operators, that has secured a deepwater exploration drilling rig to drill exploratory wells in which we haveIndonesia over a 65 percent interest, and the Boa discovery, in which we have a 58 percent interest. During 2004, we received approval from the Norwegian authorities for our Alvheim plan for development and operation ("PDO"), which will consist of a floating production, storage and offloading vessel ("FPSO") with subsea infrastructure for five drill centers and associated flow lines. The PDO also outlines transportation of produced oil by shuttle tanker and transportation of produced natural gas to the SAGE system using a new 14-inch, 24-mile cross border pipeline. Marathon and its Alvheim project partners acquired the Odin multipurpose shuttle tanker early in 2005. The vessel is currently being modified to serve as an FPSO and has been renamed "Alvheim." In 2004, the Alvheim partners reached agreement to tie-in the nearby Vilje discovery, in which we own a 47 percent outside-operated interest, subject to the approval of the Norwegian government. In 2005, the Norwegian government approved the Vilje PDO. Progress also continues on the Vilje project, where the subsea preparation is 98 percent complete and development drilling is expected to commencetwo-year period commencing in the second quarter of 2007. First2010. The participants have the right to extend this rig contract for up to one additional year.

We continue to participate in joint study agreements in Indonesia, which provide a right of first refusal in future bid rounds. We completed two joint study agreements in 2008 and have one in progress.

Divestitures

Angola –In February 2010, we closed the sale of an undivided 20 percent interest in the outside-operated production sharing contract and joint operating agreement on Block 32 offshore Angola for $1.3 billion, excluding any purchase price adjustments, with an effective date of January 1, 2009. We retained a 10 percent interest in Block 32.

Gabon –In December 2009, we closed the sale of our operated properties in Gabon. Net production from these operations averaged 6 mbpd in 2009. The results of our Gabonese operations have been reported as discontinued operations.

United States –In June 2009, we completed the Alvheim/Vilje development is expected duringsale of our operated and a portion 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 secondsale was recorded. Net production from these sold properties averaged 8,150 boepd in the first quarter of 2007. Four wells will be available at first production and drilling activities will continue into 2008. A peak net rate of approximately 75,000 boepd is expected in early 2008.

        In 2006, we submitted a PDO for the Volund field to the Norwegian government, with a recommendation that the field be developed as a subsea tie-back to the Alvheim FPSO. In December 2006, the Ministry of Petroleum and Energy forwarded the PDO to the Norwegian King in Council for approval. Approval was received in early 2007. The Volund development will include three producing wells and a water injection well. The crude oil production will be exported via the shuttle tankers discussed above and the associated natural gas will be exported via the Alvheim-to-SAGE pipeline. The Volund development, in which we own a 65 percent interest and serve as operator, is expected to begin production in the second quarter of 2009.

Ireland– We own aIn April 2009, we closed the sale of our operated properties offshore Ireland, which consisted of our 100 percent working interest in the Kinsale Head, Ballycotton and Southwest Kinsale natural gas fields in the Celtic Sea offshore Ireland. In February 2006, we acquired anand our 87 percent operatedworking interest in the Seven Heads natural gas field. Previously, we processed and transported natural gas and we provided field operating services to the Seven Heads group through our existing Kinsale Head facilities. Net natural gas salesproduction from these operations averaged 5 mboepd in Ireland were 46 mmcfd in 2006, compared with 50 mmcfd in 2005. In June 2006, we were awarded the first commercial natural gas storage license in Ireland, which allows us to provide full third-party storage services fromquarter of 2009.

In July 2009 we closed the Southwest Kinsale field. In 2006, we began to produce and hold in storage natural gas from the Kinsale Head field for future delivery under a contract that expires in March 2009. Additionally, natural gas produced fromsale of our other fields or purchased from other parties can be stored at Southwest Kinsale for future sale to customers.

        We own asubsidiary holding our 19 percent interest in the outside-operated Corrib natural gas development project, located 40 miles off Ireland's northwest coast, where fiveoffshore Ireland. As a result of these dispositions, our Irish exploration and production businesses have been reported as discontinued operations.

The above discussion of the seven wells necessaryE&P segment includes forward-looking statements with respect to developanticipated future exploratory and development drilling, the field have been drilled. During 2004,

6

An Bord Pleanála (the Planning Board) upheld the Mayo County Council's decision to grant planning approval for the proposed natural gas terminal at Bellanaboy Bridge, County Mayo, which will process natural gas from the Corrib field. Development activities started in late 2004 but were suspended to facilitate dialogue and clarificationtiming of issues raised by opponents of the project. In July 2006, the partners in this project accepted the findings of a government-commissioned independent safety review and the report of an independent mediator regarding the onshore pipeline associated with the proposed development. The onshore pipeline will be re-routed and routing studies are underway. Construction of the natural gas plant re-commenced in the third quarter of 2006. First production from the field is expectedDroshky and Ozona developments in the Gulf of Mexico, the Faregh Phase II Gas Plant, the PSVM development on Block 31 offshore Angola and Block 32 and other possible developments. Some factors which could potentially affect these forward-looking statements include pricing, supply and demand for petroleum products, the amount of capital available for exploration and development, regulatory constraints, drilling rig availability, unforeseen hazards such as weather conditions, natural disasters, 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 offshore developments could further be affected by presently known data concerning size and character of reservoirs, economic recoverability, future drilling success and production experience. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Productive and Drilling Wells

For our E&P segment, the following tables set forth productive wells and service wells as of December 31, 2009, 2008 and 2007 and drilling wells as of December 31, 2009.

Gross and Net Wells

        Equatorial GuineaDrilling Activity

The following table sets forth, by geographic area, the number of net productive and dry development and exploratory wells completed in each of the last three years.

  –  We ownNet Productive and Dry Wells Completed

Acreage

The following table sets forth, by geographic area, the developed and undeveloped exploration and production acreage held in our E&P segment as of December 31, 2009.

Gross and Net Acreage

Oil Sands Mining

Through our acquisition of Western in 2007, we hold a 6320 percent operatedoutside-operated interest in the AOSP, an oil sands mining joint venture located in Alberta, Canada. The joint venture produces bitumen from oil sands deposits in the Athabasca region utilizing mining techniques and upgrades the bitumen to synthetic crude oils and vacuum gas oil. The AOSP’s mining and extractions assets are located near Fort McMurray, Alberta and include the Muskeg River mine which began bitumen production in 2003 and the Jackpine mine which is currently under construction and anticipated to commence bitumen production in the second half of 2010. The underlying developed leases are held for the duration of the project, with royalties payable to the province of Alberta. The upgrading assets are located at Fort Saskatchewan, northeast of Edmonton, Alberta. Additional upgrading capacity is being constructed with an anticipated startup in late 2010 or early 2011.

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 bitumen reserves increased 168 million barrels. See Item 1. Business – Reserves for comprehensive discussion of reserves related to our oil sands mining and conventional exploration and production operations. As of December 31, 2009, we have rights to participate in developed and undeveloped leases totaling approximately 215,000 gross (45,000 net) acres.

Current AOSP operations use established processes to mine oil sands deposits from an open-pit mine, extract the bitumen and upgrade it into synthetic crude oils. Ore is mined using traditional truck and shovel mining techniques. The mined ore passes through primary crushers to reduce the ore chunks in size and is then sent to rotary breakers where the ore chunks are further reduced to smaller particles. The particles are combined with hot water to create slurry. The slurry moves through the extraction process where it separates into sand, clay and bitumen-rich froth. A solvent is added to the bitumen froth to separate out the remaining solids, water and heavy asphaltenes. The solvent washes the sand and produces clean bitumen that is required for the upgrader to run efficiently. The process yields a mixture of solvent and bitumen which is then transported from the mine to the Scotford upgrader via the approximately 300 mile Corridor Pipeline.

The bitumen is upgraded at Scotford using both hydrotreating and hydroconversion processes to remove sulfur and break the heavy bitumen molecules into lighter products. Blendstocks acquired from outside sources are utilized in the production of our saleable products. The three major products that the Scotford upgrader produces are light synthetic crude oil, heavy synthetic crude oil and vacuum gas oil. The vacuum gas oil is sold to an affiliate of the operator under a long term contract at market-related prices, and the other products are sold in the marketplace.

Net synthetic crude oil sales were 32 mbpd in both 2009 and 2008, but were 4 mbpd in 2007. Daily volumes for 2007 represent total volumes since the acquisition date over total days in the period.

Prior to our acquisition of Western, the first fully integrated expansion of the existing AOSP facilities was approved in 2006. Expansion 1, which includes construction of mining and extraction facilities at the Jackpine mine, new treatment facilities at the existing Muskeg River mine, addition of a new processing train at the Scotford upgrading facility and development of related infrastructure, is on track and anticipated to begin mining operations in the second half of 2010, and upgrader operations in late 2010 or early 2011. When Expansion 1 is complete, we will have more than 50 mbpd of production and upgrading capacity in the Canadian oil sands. The timing and scope of potential future expansions and debottlenecking opportunities on existing operations remain under review.

The above discussion of the Oil Sands Mining segment includes forward-looking statements concerning the anticipated completion of AOSP Expansion 1 and the timing of production. Factors which could affect the expansion project 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. The AOSP expansion could be further affected by commissioning and start-up risks associated with prototype equipment and new technology.

Reserves

In December 2008, the Securities and Exchange Commission (“SEC”) announced revisions to its regulations on oil and gas reporting. In January 2010, the Financial Accounting Standards Board issued an accounting standards update which was intended to harmonize the accounting literature with the SEC’s new regulations. See Item 8. Financial Statements and Supplementary Data – Note 2 to the consolidated financial statements for a summary of the changes. The revised regulations were applied in estimating and reporting our reserves as of December 31, 2009, which totaled 1,679 mmboe.

Estimated Reserve Quantities

The following table sets forth estimated quantities of our net proved liquid hydrocarbon, natural gas and synthetic crude oil reserves based upon an unweighted average of closing prices for the first day of each month in the 12-month period ended December 31, 2009. Approximately 61 percent of our proved reserves are located in Organization for Economic Cooperation and Development (“OECD”) countries.

Under the new regulations, reserves are now disclosed by continent, by country, if the proved reserves related to any geographic area, on an oil-equivalent barrel basis represent 15 percent or more of our total proved reserves. A geographic area can be an individual country, group of countries within a continent, or a continent. Reserve quantities previously reported for 2008 and 2007 have been reorganized into these geographic groupings below for comparability.

The following table sets forth estimated quantities of our net proved liquid hydrocarbon and natural gas reserves based upon year end prices as of December 31, 2008 and 2007.

		North America									Africa									Europe
December 31, 2007		United States			Canada(a)			Total			EG			Other			Total			Total			Disc. Ops.(b)			Grand Total
Proved Developed Reserves
Liquid hydrocarbon(mmbbl)		135			-			135			113			183			296			32			8			471
Natural gas(bcf)		761			-			761			1,405			110			1,515			127			46			2,449
Total proved developed reserves(mmboe)		262			-			262			347			202			549			52			16			879
Total Proved Reserves
Liquid hydrocarbon(mmbbl)		166			-			166			150			210			360			115			9			650
Natural gas(bcf)		1,007			-			1,007			1,951			110			2,061			238			144			3,450
Total proved reserves(mmboe)		334			-			334			475			228			703			155			33			1,225
Developed reserves as a percent of total proved reserves		78	%		-			78	%		73	%		89	%		78	%		34	%		48	%		72	%

(a)	Before December 31, 2009, reserves related to oil sands mining were not included in the SEC’s definition of oil and gas producing activities; therefore, these reserves are not reported for 2008 and 2007.

(b)	Our businesses in Ireland and Gabon were sold in 2009. All periods have been recast to reflect these businesses as discontinued operations.

We previously reported OSM segment reserves as bitumen because oil sands mining was not considered an oil and gas producing activity by the SEC. Proved bitumen reserves reported as of December 31, 2008 and 2007 were 388 mmboe and 421 mmboe. December 31, 2009 reserve quantities under the new regulations include 603 mmboe of proved synthetic crude oil (bitumen after upgrading excluding blendstocks) related to our oil sands mining operations. While the change from bitumen to synthetic crude oil is responsible for some of the 2008 to 2009 increase in reported OSM segment reserves, the majority of the reserve increase is related to the three leases added to the Muskeg River mine in the second quarter of 2009. There were no other significant changes to our proved reserves in 2009.

The above estimated quantities of net proved liquid hydrocarbon and natural gas reserves are forward-looking statements and are based on a number of assumptions, including (among others) commodity prices, presently known physical data concerning size and character of the reservoirs, economic recoverability, technology developments, future drilling success, industry economic conditions, levels of cash flow from operations, production experience and other operating considerations. The above estimated quantities of synthetic crude oil reserves are forward-looking statements and are based on presently known physical data, economic recoverability and operating conditions. To the extent these assumptions prove inaccurate, actual recoveries and development costs could be different than current estimates. For additional details of the estimated quantities of proved reserves at the end of each of the last three years, see Item 8. Financial Statements and Supplementary Data— Supplementary Information on Oil and Gas Producing Activities.

Preparation of Reserve Estimates

Our estimation of net recoverable quantities of liquid hydrocarbons and natural gas is a highly technical process performed primarily by in-house teams of reservoir engineers and geoscience professionals. All estimates are made in compliance with SEC Rule 4-10 of Regulation S-X. Beginning December 31, 2009, reserve estimates are based upon the average of closing prices for the first day of each month in the 12-month period ended December 31, 2009. In previous periods, reserve estimates were based on prices at December 31.

Liquid hydrocarbon, natural gas and synthetic crude oil reserve estimates are reviewed and approved by our Corporate Reserves Group, which includes our Director of Corporate Reserves and her staff of Reserves Coordinators. Reserves estimates are developed and reviewed by Qualified Reserves Estimators (“QRE”). QRE are engineers or geoscientists with a minimum of a bachelor of science degree in the appropriate technical field, have a minimum of 3 years of industry experience with at least one year in reserve estimation and have completed Marathon’s Qualified Reserve Estimator training course. The Reserve Coordinators review all reserves estimates for all fields with proved reserves greater than 3 million boe at a minimum of once every 3 years. Any change to proved reserve estimates in excess of 2.5 million boe on a total field basis, within a single month, must be approved by the Director of Corporate Reserves. All other proved reserve changes must be approved by a Reserve Coordinator.

Our Director of Corporate Reserves, who reports to our Chief Financial Officer, has a bachelor of science degree in petroleum engineering and a master of business administration. Her 35 years of experience in the industry include 24 with Marathon. She is active in industry and professional groups, having served on the Society of Petroleum Engineers (“SPE”) Oil and Gas Reserves Committee (“OGRC”) since 2004, chairing in 2008 and 2009. As a member of the OGRC, she participated in the development of the Petroleum Resource Management System (“PRMS”) and served on the Technical Program Committee for a 2007 SPE Reserves Estimation Workshop: Sharing the Vision focusing on PRMS. She chaired the development of the OGRC comments on the SEC’s proposed modernization of oil and gas reporting and was a member of the American Petroleum Institute’s Ad Hoc group that provided comments on the same topic.

Estimates of synthetic crude oil reserves are prepared by GLJ Petroleum Consultants of Calgary, Canada, third-party consultants. A copy of their report is filed as Exhibit 99.1 to this Form 10-K. The engineer responsible for the estimates of our oil sands mining reserves has 31 years of experience in petroleum engineering and has conducted surface mineable oil sands evaluations since 1986. He is a member of SPE, having served as regional director 1998 through 2001 and is a registered Practicing Professional Engineer in the Province of Alberta.

Audits of Estimates

Third-party consultants are engaged to audit the in-house reserve estimates for fields that comprise the top 80 percent of our total proved reserves over a rolling four-year period. We met this goal for the four-year period ended December 31, 2009. We established a tolerance level of 10 percent for reserve audits such that initial estimates by the third-party consultants are accepted if they are within 10 percent of our internal estimates. Should the third-party consultants’ initial analysis fail to reach our tolerance level, both our team and the consultants re-examine the information provided, request additional data and refine their analysis if appropriate. This resolution process is continued until both estimates are within 10 percent. This process did not result in significant changes to our reserve estimates in 2009, 2008, or 2007.

Netherland, Sewell and Associates, Inc. (“NSAI”) prepared an independent estimate of December 31, 2008 reserves for Alba field offshorefield. This reserve estimate was used by Corporate Reserves in much the same way third-party audits are now used. The NSAI summary report is filed as Exhibit 99.2 to this Form 10-K. The senior members of the NSAI team have over fifty years of industry experience between them, having worked for large, international oil and gas companies before joining NSAI. The team lead has a master of science in mechanical engineering and is a member of SPE. The senior technical advisor has a bachelor of science in geophysics and is a member of the Society of Exploration Geophysicists, the American Association of Petroleum Geologists and the European Association of Geoscientists and Engineers. Both are licensed in the state of Texas.

Ryder Scott Company (“Ryder Scott”) performed audits of several of our fields in 2009. Their summary report on audits performed in 2009 is filed as Exhibit 99.3 to this Form 10-K. The team lead for Ryder Scott has over 18 years of industry experience, having worked for a major international oil and gas company before joining Ryder Scott. He has a bachelor of science in mechanical engineering, is a member of SPE and is a registered Professional Engineer in the state of Texas.

The Corporate Reserves Group may also perform separate, detailed technical reviews of reserve estimates for significant fields that were acquired recently or for properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operating conditions.

Changes in Proved Undeveloped Reserves

As of December 31, 2009, 492 mmboe of proved undeveloped reserves were reported, an increase of 203 mmboe from December 31, 2008, primarily due to the inclusion of synthetic crude oil. Of the 492 mmboe of proved undeveloped reserves at year end 2009, 31 percent of the volume is associated with projects that have been included in proved reserves for more than five years. The majority of this volume is related to a compression project in Equatorial Guinea that was sanctioned by the Board of Directors in 2004 and is expected to be completed in 2014. There are no other significant undeveloped reserves expected to be developed more than five years from now. Projects can remain in proved undeveloped reserves for extended periods in many situations such as behind-pipe zones where reserves will not be accessed until the primary producing zone depletes, large development projects which take more than five years to complete, and the timing of when additional gas compression is needed. During 2009, we added 290 mmboe to proved undeveloped reserves and transferred 38 mmboe from proved undeveloped to proved developed reserves. Costs incurred for the periods ended December 31, 2009, 2008 and 2007 relating to the development of proved undeveloped reserves, were $792 million, $1,189 million and $1,250 million.

As of December 31, 2009, future development costs estimated to be required for the development of proved undeveloped liquid hydrocarbon, natural gas and synthetic crude oil reserves for the years 2010 through 2014 are projected to be $1,083 million, $565 million, $244 million, $331 million, and $123 million.

The above estimated future development costs relating to the development of proved undeveloped liquid hydrocarbon, natural gas and synthetic crude oil reserves are forward-looking statements and are based on a 52number of assumptions, including (among others) commodity prices, presently known physical data concerning size and character of the reservoirs, economic recoverability, technology developments, future drilling success, industry economic conditions, levels of cash flow from operations, production experience and other operating considerations. To the extent these assumptions prove inaccurate, actual recoveries and development costs could be different than current estimates.

Net Production Sold

Average Sales Price per Unit

Average Production Cost per Unit^(a)

Integrated Gas

Our integrated gas operations include natural gas liquefaction and regasification operations and methanol production operations. Also included in the financial results of the Integrated Gas segment are the costs associated with ongoing development of projects to link stranded natural gas resources with key demand areas.

We hold a 60 percent interest in an onshore liquefied petroleum gas ("LPG") processing plant held through anEGHoldings, which is accounted for under the equity method investee. During 2006, net liquid hydrocarbon sales averaged 48 mbpd and net natural gas sales averaged 68 mmcfd, compared to 40 mbpd and 92 mmcfd in 2005. A condensate expansion project ramped up to full production andof accounting. In May 2007, EGHoldings completed construction of a new, larger LPG plant was completed in 2005. Net sales in 2006 averaged 36 mbpd of condensate and 12 mbpd of LPG.

        We own 45 percent of Atlantic Methanol Production Company LLC ("AMPCO"3.7 million metric tonnes per annum (“mmtpa”), the results of which are included in the Integrated Gas segment. In 2006, we supplied a gross 99 mmcfd of dry gas, which remains after the condensate and LPG are removed, to AMPCO, where it was used to manufacture methanol. Remaining dry gas is returned offshore and reinjected into the Alba reservoir for later production when the LNG production facility on Bioko Island. LNG from the production facility is sold under a 3.4 mmtpa, or 460 mmcfd, sales and purchase agreement with a 17-year term. The purchaser under the agreement takes delivery of the LNG on Bioko Island, discussed belowwith pricing linked principally to the Henry Hub index, regardless of destination. This production facility allows us to monetize our natural gas reserves from the Alba field, as natural gas for the facility is purchased from the Alba field participants under a long-term natural gas supply agreement. Gross sales of LNG from this production facility totaled 3.9 million metric tonnes in 2009. In 2009, we continued discussions with the government of Equatorial Guinea and our partners regarding a potential second LNG production facility on Bioko Island.

We also own a 30 percent interest in a Kenai, Alaska, natural gas liquefaction plant, and lease two 87,500 cubic meter tankers used to transport LNG to customers in Japan. Feedstock for the plant is supplied from a portion of our natural gas production in the Cook Inlet. From the first production in 1969, we have sold our share of the LNG plant’s production under long-term contracts with two of Japan’s largest utility companies. In June 2008 we, along with our partner, received approval from the U.S. Department of Energy to extend the export license for this natural gas liquefaction plant through March 2011.

We own a 45 percent interest in AMPCO, which is accounted for under the equity method of accounting. AMPCO owns a methanol plant located in Malabo, Equatorial Guinea. Feedstock for the plant is supplied from our natural gas production from the Alba field. Gross sales of methanol from the plant totaled 960,374 metric tonnes in 2009. Production from the plant is used to supply customers in Europe and the United States.

In addition to our expertise in utilizing existing gas technologies to manufacture and market products such as LNG and methanol, we continue to conduct research to develop new leading-edge natural gas technologies. While existing known natural gas resources are much more abundant than the world’s remaining oil resources, natural gas is more difficult to transport to global markets without the use of advanced gas technologies. Our Gas-to-Fuels (“GTF™”) technology is one such promising technology.

Our GTF^TM technology program is focused on converting natural gas into gasoline blendstocks and petrochemicals. Global markets for these products are significantly larger than the global markets for either LNG or methanol, further expanding the uses of natural gas. During 2009, we completed the initial run program of our newly-constructed GTF process demonstration unit, which was commissioned during 2008. This technology demonstration program has provided valuable information about materials of construction, process chemistry, and GTF plant operations.

During 2008, we entered into agreements with GRT, Inc., a Delaware corporation, to cooperate on the advancement of gas-to-fuels-related technology. This transaction provides us with access to additional specialized

technical and research personnel and lab facilities, and significantly expanded the portfolio of patents available to us via license and through a cooperative development program. In addition, we have acquired a 20 percent interest in GRT, Inc.

The GTF^TM technology is protected by an intellectual property protection program. The U.S. has granted 17 patents for the technology, with another 22 pending. Worldwide, there are over 300 patents issued or pending, covering over 100 countries including regional and direct foreign filings.

Another innovative technology that we are developing focuses on reducing the processing and transportation costs of natural gas by artificially creating natural gas hydrates, which are more easily transportable than natural gas in its gaseous form. Much like LNG, gas hydrates would then be regasified upon delivery to the receiving market. We have an active pilot program in place to test and further develop a proprietary natural gas hydrates manufacturing system.

The above discussion of the Integrated Gas segment contains forward-looking statements with respect to the possible expansion of the LNG production facility. Factors that could potentially affect the possible expansion of the LNG production facility include partner and government approvals, access to sufficient natural gas volumes through exploration or commercial negotiations with other resource owners and access to sufficient regasification capacity. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Refining, Marketing and Transportation

We have refining, marketing and transportation operations concentrated primarily in the Midwest, upper Great Plains, Gulf Coast and Southeast regions of the U.S. We rank as the fifth largest crude oil refiner in the U.S. and the largest in the Midwest. Our operations include a seven-plant refining network and an integrated terminal and transportation system which supplies wholesale and Marathon-brand customers as well as our own retail operations. Our wholly-owned retail marketing subsidiary Speedway SuperAmerica LLC (“SSA”) is completed.the third largest chain of company-owned and -operated retail gasoline and convenience stores in the U.S. and the largest in the Midwest.

Refining

We own and operate seven refineries with an aggregate refining capacity of 1.188 million barrels per day (“mmbpd”) of crude oil as of December 31, 2009. During 2009, our refineries processed 957 mbpd of crude oil and 196 mbpd of other charge and blend stocks. The table below sets forth the location and daily crude oil refining capacity of each of our refineries as of December 31, 2009.

Crude Oil Refining Capacity

Our refineries include crude oil atmospheric and vacuum distillation, fluid catalytic cracking, catalytic reforming, desulfurization and sulfur recovery units. The refineries process a wide variety of crude oils and produce numerous refined products, ranging from transportation fuels, such as reformulated gasolines, blend-grade gasolines intended for blending with fuel ethanol and ultra-low sulfur diesel fuel, to heavy fuel oil and asphalt. Additionally, we manufacture aromatics, cumene, propane, propylene, sulfur and maleic anhydride.

Our Garyville, Louisiana, refinery is located along the Mississippi River in southeastern Louisiana between New Orleans and Baton Rouge. The Garyville refinery predominantly processes heavy sour crude oil into products

such as gasoline, distillates, sulfur, asphalt, propane, polymer grade propylene, isobutane and coke. Our Garyville refinery has earned designation as a U.S. Occupational Safety and Health Administration (OSHA) Voluntary Protection Program (VPP) STAR site.

The Garyville Major Expansion project, completed on schedule during the fourth quarter of 2009, is currently being fully integrated into the base Garyville refinery. As a result of the expansion, the refinery’s crude oil refining capacity has grown from 256 mbpd to 436 mbpd, making it among the largest crude oil refineries in the country. The expansion also improves scale efficiencies, feedstock flexibility and refined product yields. The expansion project cost approximately $3.9 billion (excluding capitalized interest).

Our Catlettsburg, Kentucky, refinery is located in northeastern Kentucky on the western bank of the Big Sandy River, near the confluence with the Ohio River. The Catlettsburg refinery processes sweet and sour crude oils into products such as gasoline, asphalt, diesel, jet fuel, petrochemicals, propane, propylene and sulfur.

Our Robinson, Illinois, refinery is located in southeastern Illinois. The Robinson refinery processes sweet and sour crude oils into products such as multiple grades of gasoline, jet fuel, kerosene, diesel fuel, propane, propylene, sulfur and anode-grade coke. The Robinson refinery has earned designation as an OSHA VPP STAR site.

Our Detroit, Michigan, refinery is located near Interstate 75 in southwest Detroit. It is the only petroleum refinery currently operating in Michigan. The Detroit refinery processes light sweet and heavy sour crude oils, including Canadian crude oils, into products such as gasoline, diesel, asphalt, slurry, propane, chemical grade propylene and sulfur. In 2007, we approved a heavy oil upgrading and expansion project at this refinery, with a current projected cost of $2.2 billion (excluding capitalized interest). This project will enable the refinery to process an additional 80 mbpd of heavy sour crude oils, including Canadian bitumen blends, and will increase its crude oil refining capacity by about 10 percent. Construction began in the first half of 2008 and is presently expected to be complete in the second half of 2012. Our Detroit refinery is certified as a Michigan VPP site, receiving Rising Star status, and expects to satisfy the requirements for STAR status in the first quarter of 2010.

Our Canton, Ohio, refinery is located approximately 60 miles southeast of Cleveland, Ohio. The Canton refinery processes sweet and sour crude oils into products such as gasoline, diesel fuels, kerosene, propane, sulfur, asphalt, roofing flux, home heating oil and No. 6 industrial fuel oil.

Our Texas City, Texas, refinery is located on the Texas gulf coast approximately 30 miles south of Houston, Texas. The refinery processes sweet crude oil into products such as gasoline, propane, chemical grade propylene, slurry, sulfur and aromatics.

Our St. Paul Park, Minnesota, refinery is located in southeastern Minnesota where it is one of only two refineries in the state. The St. Paul Park refinery processes predominantly Canadian crude oils into products such as gasoline, diesel, jet fuel, kerosene, asphalt, propane, propylene and sulfur. Our St. Paul Park refinery is certified as a Minnesota VPP site, receiving Rising Star status, and expects to satisfy the requirements for STAR status in 2010.

The above discussion includes forward-looking statements concerning the Detroit refinery heavy oil upgrading and expansion project. Some factors that could affect this project 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.

Our refineries are integrated with each other via pipelines, terminals and barges to maximize operating efficiency. The transportation links that connect our refineries allow the movement of crude oil, feedstocks and intermediate products between refineries to optimize operations, produce higher margin products and utilize our processing capacity efficiently.

The following table sets forth our refinery production by product group for each of the last three years.

Refined Product Yields

Planned maintenance activities, or turnarounds, requiring temporary shutdown of certain refinery operating units, are periodically performed at each refinery. In recent years, planned turnarounds have occurred at two or three refineries per year.

        LibyaCrude oil supply – We obtain most of the crude oil we refine through negotiated contracts and purchases or exchanges on the spot market. Our crude oil supply contracts are generally term contracts with market related pricing provisions. The following table provides information on our sources of crude oil for each of the last three years. The crude oil sourced outside of North America was acquired from various foreign national oil companies, producing companies and trading companies. Of the U.S. and Canadian sourced crude processed at our refineries, 33 mbpd, or four percent, was supplied by a combination of our E&P and OSM production operations for the year 2009.

Sources of Crude Oil Refined

Our refineries receive crude oil and other feedstocks and distribute our refined products through a variety of channels, including pipelines, trucks, railcars, ships and barges.

Refined products marketing and distribution –  Net liquid hydrocarbonWe are a supplier of refined products to resellers and consumers within our 24-state market area in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the United States. Our market area includes approximately 4,600 Marathon branded-retail outlets concentrated in the Midwest and southeastern states. We currently own and distribute from 64 light product and 22 asphalt terminals. In addition, we distribute through 60 third-party terminals in our market area. Our marine transportation operations include 16 towboats, as well as 183 owned and 8 leased barges that transport refined products on the Ohio, Mississippi and Illinois rivers and their tributaries as well as the Intercoastal Waterway. We lease or own approximately 2,400 railcars of various sizes and capacities for movement and storage of refined products. In addition, we own over 120 transport trucks for the movement of light products.

The following table sets forth, as a percentage of total refined product sales, sales of refined products to our different customer types for the past three years.

The following table sets forth our refined products sales by product group and our average sales price for each of the last three years.

Refined Product Sales

We sell gasoline, gasoline blendstocks and No. 1 and No. 2 fuel oils (including kerosene, jet fuel and diesel fuel) to wholesale marketing customers in Libya averagedthe Midwest, upper Great Plains, Gulf Coast and southeastern regions of the United States. We sold 51 percent of our gasoline volumes and 87 percent of our distillates volumes on a wholesale or spot market basis in 2009. The demand for gasoline is seasonal in many of our markets, with demand typically being at its highest levels during the summer months.

We have blended ethanol into gasoline for over 20 years and began expanding our blending program in 2007, in part due to federal regulations that require us to use specified volumes of renewable fuels. Ethanol volumes sold in blended gasoline were 60 mbpd in 2009, 54 mbpd in 2006,2008 and 40 mbpd in 2007. The future expansion or contraction of our ethanol blending program will be driven by the economics of the ethanol supply and by government regulations. We sell reformulated gasoline, which is also blended with ethanol, in parts of our marketing territory, including: Chicago, Illinois; Louisville, Kentucky; northern Kentucky; Milwaukee, Wisconsin, and Hartford, Illinois. We also sell biodiesel-blended diesel in Minnesota, Illinois and Kentucky.

We produce propane at all seven of our refineries. Propane is primarily used for home heating and cooking, as a totalfeedstock within the petrochemical industry, for grain drying and as a fuel for trucks and other vehicles. Our propane sales are typically split evenly between the home heating market and industrial consumers.

We are a producer and marketer of 8 mbpd were owedpetrochemicals and specialty products. Product availability varies by refinery and includes benzene, cumene, dilute naphthalene oil, molten maleic anhydride, molten sulfur, propylene, toluene and xylene. We market propylene, cumene and sulfur domestically to customers in the chemical industry. We sell maleic anhydride throughout the United States and Canada. We also have the capacity to produce 1,400 tons per day of anode grade coke at our Robinson refinery, which is used to make carbon anodes for the aluminum smelting industry, and 5,500 tons per day of fuel grade coke at the Garyville refinery, which is used for power generation and in miscellaneous industrial applications. In early 2009, we discontinued production and sales of petroleum pitch and aliphatic solvents at our Catlettsburg refinery.

We produce and market heavy residual fuel oil or related components at all seven of our refineries. Another product of crude oil, heavy residual fuel oil, is primarily used in the utility and ship bunkering (fuel) industries, though there are other more specialized uses of the product.

We have refinery based asphalt production capacity of up to 108 mbpd. We market asphalt through 33 owned or leased terminals throughout the Midwest and Southeast. We have a broad customer base, including approximately 675 asphalt-paving contractors, government entities (states, counties, cities and townships) and asphalt roofing shingle manufacturers. We sell asphalt in the wholesale and cargo markets via rail and barge. We also produce asphalt cements, polymer modified asphalt, emulsified asphalt and industrial asphalts.

In 2007, we acquired a 35 percent interest in an entity which owns and operates a 110-million-gallon-per-year ethanol production facility in Clymers, Indiana. We also own a 50 percent interest in an entity which owns a 110-million-gallon-per-year ethanol production facility in Greenville, Ohio. The Greenville plant began production in February 2008. Both of these facilities are managed by a co-owner.

Pipeline transportation – We own a system of pipelines through Marathon Pipe Line LLC (“MPL”) and Ohio River Pipe Line LLC (“ORPL”), our wholly-owned subsidiaries. Our pipeline systems transport crude oil and refined products primarily in the Midwest and Gulf Coast regions to our account uponrefineries, our terminals and other pipeline systems. Our MPL and ORPL wholly-owned and undivided interest common carrier systems consist of 1,737 miles of crude oil lines and 1,825 miles of refined product lines comprising 32 systems located in 11 states. The MPL common carrier pipeline network is one of the resumptionlargest petroleum pipeline systems in the United States, based on total barrels delivered. Our common carrier pipeline systems are subject to state and Federal Energy Regulatory Commission regulations and guidelines, including published tariffs for the transportation of crude oil and refined products. Third parties generated 13 percent of the crude oil and refined product shipments on our MPL and ORPL common carrier pipelines in 2009. Our MPL and ORPL common carrier pipelines transported the volumes shown in the following table for each of the last three years.

Pipeline Barrels Handled

We also own 196 miles of private crude oil pipelines and 850 miles of private refined products pipelines, and we lease 217 miles of common carrier refined product pipelines. We have partial ownership interests in several pipeline companies that have approximately 780 miles of crude oil pipelines and 3,600 miles of refined products pipelines, including about 970 miles operated by MPL. In addition, MPL operates most of our operationsprivate pipelines and 985 miles of crude oil and 160 miles of natural gas pipelines owned by our E&P segment.

Our major refined product pipelines include the owned and operated Cardinal Products Pipeline and the Wabash Pipeline. The Cardinal Products Pipeline delivers refined products from Kenova, West Virginia, to Columbus, Ohio. The Wabash Pipeline system delivers product from Robinson, Illinois, to various terminals in Libya. the area of Chicago, Illinois. Other significant refined product pipelines owned and operated by MPL extend from: Robinson, Illinois, to Louisville, Kentucky; Garyville, Louisiana, to Zachary, Louisiana; and Texas City, Texas, to Pasadena, Texas.

In addition, as of December 31, 2009, we had interests in the following refined product pipelines:

Our major owned and operated crude oil lines run from: Patoka, Illinois, to Catlettsburg, Kentucky; Patoka, Illinois, to Robinson, Illinois; Patoka, Illinois, to Lima, Ohio; Lima, Ohio to Canton, Ohio; Samaria, Michigan, to Detroit, Michigan; and St. James, Louisiana, to Garyville, Louisiana.

As of December 31, 2009, we had interests in the following crude oil pipelines:

We plan to construct, by the year 2012, a new section of pipeline connecting with the existing crude line from Samaria, Michigan, to Detroit, Michigan. This new section will deliver additional supplies of Canadian crude to our Detroit refinery.

The 2006 salesabove discussion includes forward-looking statements concerning the construction of a new section of pipeline in Libya represented 37Michigan. Some factors that could affect this project include transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by government or third-party approvals and other risks customarily associated with construction projects.

Retail Marketing

SSA, our wholly-owned subsidiary headquartered in Enon, Ohio, sells gasoline and merchandise through owned and operated retail outlets primarily under the Speedway^® and SuperAmerica^® brands. Diesel fuel is also sold at a number of these outlets. SSA retail outlets offer a wide variety of merchandise, such as prepared foods, beverages, and non-food items, as well as a significant number of proprietary items. For eight consecutive quarters, SSA has been rated as the best convenience store chain in terms of overall customer satisfaction in a national consumer perception survey conducted by Corporate Research International^®. In 2009, Harris Interactive’s EquiTrend^® annual brand equity study named Speedway^® the number one gasoline brand with consumers. SSA’s Speedy Rewards™, an industry-leading customer loyalty program, has built active membership to 3.2 million customers.

As of December 31, 2009, SSA had 1,603 retail outlets in nine states. Sales of refined products through these retail outlets accounted for 15 percent of our internationalrefined product sales volumes in 2009 and provide us with a base of ratable sales. Revenues from sales of non-petroleum merchandise through these retail outlets totaled $3,109 million in 2009, $2,838 million in 2008 and $2,796 million in 2007. The demand for gasoline is seasonal in a majority of SSA markets, with the highest demand usually occurring during the summer driving season. Margins from the sale of merchandise and services tend to be less volatile than margins from the retail sale of gasoline and diesel fuel.

Competition and Market Conditions

Strong competition exists in all sectors of the oil and gas industry and, in particular, in the exploration for and development of new reserves. We compete with major integrated and independent oil and gas companies, as well as national oil companies, for the acquisition of oil and natural gas leases and other properties. We compete with these companies for the equipment and labor required to develop and operate those properties and in the marketing of oil and natural gas to end-users. Many of our competitors have financial and other resources greater than those available to us. Acquiring the more attractive exploration opportunities frequently requires competitive bids involving front-end bonus payments or commitments-to-work programs. We also compete in attracting and retaining personnel, including geologists, geophysicists and other specialists. Based upon statistics compiled in the “2009 Global Upstream Performance Review” published by IHS Herold Inc., we rank eighth among U.S.-based petroleum companies on the basis of 2008 worldwide liquid hydrocarbon salesand natural gas production.

We also compete with other producers of synthetic and conventional crude oil for the sale of our synthetic crude oil to refineries primarily in North America. There are several additional synthetic crude oil projects being contemplated by various competitors and, if undertaken and completed, these projects may result in a significant increase in the supply of synthetic crude oil to the market. Since not all refineries are able to process or refine synthetic crude oil in significant volumes, there can be no assurance that sufficient market demand will exist at all times to absorb our share of the synthetic crude oil production from the AOSP at economically viable prices.

We must also compete with a large number of other companies to acquire crude oil for refinery processing and in the distribution and marketing of a full array of petroleum products. Based upon the “The Oil & Gas Journal

2010 Worldwide Refinery Survey”, we rank fifth among U.S. petroleum companies on the basis of U.S. crude oil refining capacity as of December 31, 2009. We compete in four distinct markets for the sale of refined products – wholesale, spot, branded and retail distribution. We believe we compete with about 64 companies in the sale of refined products to wholesale marketing customers, including private-brand marketers and large commercial and industrial consumers; about 75 companies in the sale of refined products in the spot market; ten refiners or marketers in the supply of refined products to refiner branded jobbers and dealers; and approximately 290 retailers in the retail sale of refined products. (A jobber is a business that does not carry out refining operations but supplies refiner-branded products to gasoline stations or convenience stores. Dealers refer to retail service station or convenience store operators affiliated with a brand identity.) We compete in the convenience store industry through SSA’s retail outlets. The retail outlets offer consumers gasoline, diesel fuel (at selected locations) and a broad mix of other merchandise and services. Several nontraditional fuel retailers, such as supermarkets, club stores and mass merchants, have affected the convenience store industry and the National Petroleum News estimates such retailers had 11 percent of the U.S. gasoline market in 2009.

Our operating results are affected by price changes in conventional and synthetic crude oil, natural gas and petroleum products, as well as changes in competitive conditions in the markets we serve. Generally, results from production and oil sands mining operations benefit from higher crude oil prices while the refining and wholesale marketing gross margin may be adversely affected by crude oil price increases. Price differentials between sweet and sour crude oil also affect operating results. Market conditions in the oil and gas industry are cyclical and subject to global economic and political events and new and changing governmental regulations.

Environmental Matters

The Public Policy Committee of our Board of Directors is responsible for overseeing our position on public issues, including environmental matters. Our Corporate Health, Environment, Safety and Security organization has the responsibility to ensure that our operating organizations maintain environmental compliance systems that support and foster our compliance with applicable laws and regulations. Committees comprised of certain of our officers review our overall performance associated with various environmental compliance programs. We also have a Crisis Management Team which oversees our response to any major environmental or other emergency incident involving us or any of our properties.

State, national and international legislation to reduce greenhouse gas emissions are being proposed and, in some cases, promulgated. This legislation applies or could apply in countries in which we operate. Potential legislation and regulations pertaining to climate change could also affect our operations. The cost to comply with these laws and regulations cannot be estimated at this time, but could be significant. For additional information, see Item 1A. Risk Factors. As part of our commitment to environmental stewardship, we estimate and publicly report greenhouse gas emissions from our operations. We are working to continuously improve the accuracy and completeness of these estimates. In addition, we continuously strive to improve operational and energy efficiencies through resource and energy conservation where practicable and cost effective.

Our businesses are also subject to numerous other laws and regulations relating to the protection of the environment. These environmental laws and regulations include the Clean Air Act (“CAA”) with respect to air emissions, the Clean Water Act (“CWA”) with respect to water discharges, the Resource Conservation and Recovery Act (“RCRA”) with respect to solid and hazardous waste treatment, storage and disposal, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) with respect to releases and remediation of hazardous substances and the Oil Pollution Act of 1990 (“OPA-90”) with respect to oil pollution and response. In addition, many states where we operate have their own similar laws dealing with similar matters. New laws are being enacted, and regulations are being adopted by various regulatory agencies on a continuing operations. basis and the costs of compliance with these new rules can only be broadly appraised until their implementation becomes more accurately defined. In some cases, they can impose liability for the entire cost of clean-up on any responsible party without regard to negligence or fault and impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. The ultimate impact of complying with existing laws and regulations is not clearly known or determinable because certain implementing regulations for some environmental laws have not yet been finalized or, in some instances, are undergoing revision. These environmental laws and regulations, particularly the 1990 Amendments to the CAA and its implementing regulations, new water quality requirements and stricter fuel regulations, could result in increased capital, operating and compliance costs.

For a discussion of environmental capital expenditures and costs of compliance for air, water, solid waste and remediation, see Item 3. Legal Proceedings and Item 7. Management’s Discussion and Analysis of Financial

Condition and Results of Operations – Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies.

Air

The EPA is in the process of implementing regulations to address the National Ambient Air Quality Standards (“NAAQS”) for fine particulate emissions and ozone. In connection with these standards, the EPA will designate certain areas as “nonattainment,” meaning that the air quality in such areas does not meet the NAAQS. To address these nonattainment areas, the EPA proposed a rule in 2004 called the Interstate Air Quality Rule (“IAQR”) that would require significant emissions reductions in numerous states. The final rule, promulgated in 2005, was renamed the Clean Air Interstate Rule (“CAIR”). While the EPA expects that states will meet their CAIR obligations by requiring emissions reductions from electric generating units, states were to have the final say on what sources they regulate to meet attainment criteria. Significant uncertainty in the final requirements of this rule resulted from litigation (State of North Carolina, et al. v. EPA). In July 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAIR in its entirety and remanded it to EPA to promulgate a rule consistent with the Court’s opinion. In December 2008, the Court modified its July ruling to leave the CAIR in effect until EPA develops a new rule and control program. The EPA has announced that it plans to propose a new Clean Air Transport Rule in July of 2010. It is expected that the CAIR will be significantly altered, and it could result in changes in emissions control strategies. Our refinery operations are located in affected states, and some of these states may choose to propose more stringent fuels requirements on our refineries in order to meet the CAIR. We cannot reasonably estimate the final financial impact of the state actions to implement the CAIR until the EPA has issued a revised rule and states have taken further action to implement that rule.

The EPA is reviewing and is proposing to revise, all NAAQS for criteria air pollutants. The EPA promulgated a revised ozone standard in March 2008, and commenced the multi-year process to develop the implementing rules required by the Clean Air Act. On September 16, 2009, the EPA announced that they would reconsider the level of the ozone standard. By court order a final rule is to be signed by August 31, 2010. Also, on July 15, 2009, the EPA proposed a new short-term nitrogen dioxide standard. The final standard was issued January 22, 2010. In addition, on December 8, 2009, the EPA proposed a new short term standard for sulfur dioxide. This final standard is to be issued no later than June 2, 2010. We cannot reasonably estimate the final financial impact of these revised NAAQS standard until the implementing rules are established and judicial challenges over the revised NAAQS standards are resolved.

Water

We maintain numerous discharge permits as required under the National Pollutant Discharge Elimination System program of the CWA and have implemented systems to oversee our compliance efforts. In addition, we are regulated under OPA-90, which amended the CWA. Among other requirements, OPA-90 requires the owner or operator of a tank vessel or a facility to maintain an emergency plan to respond to releases of oil or hazardous substances. Also, in case of any such release, OPA-90 requires the responsible company to pay resulting removal costs and damages. OPA-90 also provides for civil penalties and imposes criminal sanctions for violations of its provisions.

Additionally, OPA-90 requires that new tank vessels entering or operating in U.S. waters be double-hulled and that existing tank vessels that are not double-hulled be retrofitted or removed from U.S. service, according to a phase-out schedule. All of the barges used for river transport of our raw materials and refined products meet the double-hulled requirements of OPA-90. We operate facilities at which spills of oil and hazardous substances could occur. Some coastal states in which we operate have passed state laws similar to OPA-90, but with expanded liability provisions, including provisions for cargo owner responsibility as well as ship owner and operator responsibility. We have implemented emergency oil response plans for all of our components and facilities covered by OPA-90, and we have established Spill Prevention, Control and Countermeasures (“SPCC”) plans for facilities subject to CWA SPCC requirements.

Solid Waste

We continue to workseek methods to minimize the generation of hazardous wastes in our operations. The Resource Conservation and Recovery Act (“RCRA”) establishes standards for the management of solid and hazardous wastes. Besides affecting waste disposal practices, RCRA also addresses the environmental effects of certain past waste disposal operations, the recycling of wastes and the regulation of underground storage tanks (“USTs”)

containing regulated substances. We have ongoing RCRA treatment and disposal operations at one of our RM&T facilities and primarily utilize offsite third-party treatment and disposal facilities. In 2010, Canada will implement a ban on the land application of certain wastes. However, the ongoing waste handling and disposal-related costs associated with our partnersthe Canadian land disposal restrictions are not material because we have identified alternative hazardous waste treatment options within the United States.

Remediation

We own or operate certain retail outlets where, during the normal course of operations, releases of refined products from USTs have occurred. Federal and state laws require that contamination caused by such releases at these sites be assessed and remediated to define and implement growth plans for this business.

        Gabon  –  We are the operatormeet applicable standards. The enforcement of the Tchatamba South, Tchatamba WestUST regulations under RCRA has been delegated to the states, which administer their own UST programs. Our obligation to remediate such contamination varies, depending on the extent of the releases and Tchatamba Marin fields offshore Gabon with a 56 percent interest. Net salesthe stringency of the laws and regulations of the states in Gabon averaged 10 mbpdwhich we operate. A portion of liquid hydrocarbons in 2006, compared with 12 mbpd in 2005. Production from these three fields is processed on a single offshore facility at Tchatamba Marin, with processed oil being transported through an offshore and onshore pipeline to an outside-operated storage facility.

        Russia  –  During 2003 we acquired Khanty Mansiysk Oil Corporation which operated oil fields located in the Khanty Mansiysk region of western Siberia. Net liquid hydrocarbon sales were primarilyremediation costs may be recoverable from the East Kamennoyeappropriate state UST reimbursement funds once the applicable deductibles have been satisfied. We also have other facilities which are subject to remediation under federal or state law. See Item 3. Legal Proceedings – Environmental Proceedings – Other Proceedings for a discussion of these sites.

The AOSP operations use established processes to mine deposits of bitumen from an open-pit mine, extract the bitumen and Potenay fields.upgrade it into synthetic crude oils. Tailings are waste products created from the oil sands extraction process which are placed in ponds. The AOSP is required to reclaim its tailing ponds as part of its on going reclamation work. The reclamation process uses developing technology and there is an inherent risk that the current process may not be as effective or perform as required in order to meet the approved closure and reclamation plan. The AOSP continues to develop its current reclamation technology and continues to investigate other alternate tailings management technologies. In June 2006, we sold these RussianFebruary 2009, the Alberta Energy Resources Conservation Board (“ERCB”) issued a directive which more clearly defines criteria for managing oil exploration and production businesses.sands tailings. In September 2009, the AOSP Joint Venture Operator submitted a tailings management paper to the ERCB, that sets forth its plan to comply with the Directive. This plan is currently under review by the ERCB. Increased compliance costs may result if tailing pond reclamation technologies prove unsuccessful or less effective than anticipated.

Other MattersProductive and Drilling Wells

        We hold an interestFor our E&P segment, the following tables set forth productive wells and service wells as of December 31, 2009, 2008 and 2007 and drilling wells as of December 31, 2009.

Gross and Net Wells

Drilling Activity

The following table sets forth, by geographic area, the number of net productive and dry development and exploratory wells completed in aneach of the last three years.

Net Productive and Dry Wells Completed

Acreage

The following table sets forth, by geographic area, the developed and undeveloped exploration and production licenseacreage held in Sudan. We suspended all operationsour E&P segment as of December 31, 2009.

Gross and Net Acreage

Oil Sands Mining

Through our acquisition of Western in Sudan in 1985 due to civil unrest. We have had no employees in the country and have derived no economic benefit from those interests since that time. The U.S. government imposed sanctions against Sudan in 1997 and2007, we have not made any payments related to Sudan since then. We have abided and will continue to abide by all U.S. sanctions related to Sudan and will not consider resuming any activity regarding our interests there until such time as it is permitted under U.S. law. Our intention is to exit this license in 2007.

        We discovered the Ash Shaer and Cherrife gas fields in Syria in the 1980s. We have recognized no revenues in any period from activities in Syria and we impaired our entire investment in Syria in 1998. In July 2006, the new production sharing contract awarded by the Syrian government was signed into law. This contract gave us the right to assign all or part of our interest in these fields tohold a third party, subject to the consent of the Syrian government, and also resolved the previous disputes between us, the Syrian Petroleum Company and the Syrian government over our interest in these fields. In October 2006, the Syrian government approved the assignment of 9020 percent of ouroutside-operated interest in the Ash ShaerAOSP, an oil sands mining joint venture located in Alberta, Canada. The joint venture produces bitumen from oil sands deposits in the Athabasca region utilizing mining techniques and Cherrife naturalupgrades the bitumen to synthetic crude oils and vacuum gas fieldsoil. The AOSP’s mining and extractions assets are located near Fort McMurray, Alberta and include the Muskeg River mine which began bitumen production in 2003 and the Jackpine mine which is currently under construction and anticipated to a non-U.S. company. We closedcommence bitumen production in the second half of 2010. The underlying developed leases are held for the duration of the project, with royalties payable to the province of Alberta. The upgrading assets are located at Fort Saskatchewan, northeast of Edmonton, Alberta. Additional upgrading capacity is being constructed with an anticipated startup in late 2010 or early 2011.

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 on November 1, 2006,were as agreed in the original 1999 AOSP joint venture agreement. We elected to participate in these leases and received cash proceedsour net proved bitumen reserves increased 168 million barrels. See Item 1. Business – Reserves for comprehensive discussion of $46 million. While we continue to hold a 10 percent outside-operated interest, we continue to comply with all U.S. sanctionsreserves related to Syria. We expectour oil sands mining and conventional exploration and production operations. As of December 31, 2009, we have rights to sellparticipate in developed and undeveloped leases totaling approximately 215,000 gross (45,000 net) acres.

Current AOSP operations use established processes to mine oil sands deposits from an open-pit mine, extract the bitumen and upgrade it into synthetic crude oils. Ore is mined using traditional truck and shovel mining techniques. The mined ore passes through primary crushers to reduce the ore chunks in size and is then sent to rotary breakers where the ore chunks are further reduced to smaller particles. The particles are combined with hot water to create slurry. The slurry moves through the extraction process where it separates into sand, clay and bitumen-rich froth. A solvent is added to the bitumen froth to separate out the remaining 10 percent interestsolids, water and heavy asphaltenes. The solvent washes the sand and produces clean bitumen that is required for the upgrader to run efficiently. The process yields a mixture of solvent and bitumen which is then transported from the mine to the Scotford upgrader via the approximately 300 mile Corridor Pipeline.

The bitumen is upgraded at Scotford using both hydrotreating and hydroconversion processes to remove sulfur and break the heavy bitumen molecules into lighter products. Blendstocks acquired from outside sources are utilized in 2007.the production of our saleable products. The three major products that the Scotford upgrader produces are light synthetic crude oil, heavy synthetic crude oil and vacuum gas oil. The vacuum gas oil is sold to an affiliate of the operator under a long term contract at market-related prices, and the other products are sold in the marketplace.

Net synthetic crude oil sales were 32 mbpd in both 2009 and 2008, but were 4 mbpd in 2007. Daily volumes for 2007 represent total volumes since the acquisition date over total days in the period.

Prior to our acquisition of Western, the first fully integrated expansion of the existing AOSP facilities was approved in 2006. Expansion 1, which includes construction of mining and extraction facilities at the Jackpine mine, new treatment facilities at the existing Muskeg River mine, addition of a new processing train at the Scotford upgrading facility and development of related infrastructure, is on track and anticipated to begin mining operations in the second half of 2010, and upgrader operations in late 2010 or early 2011. When Expansion 1 is complete, we will have more than 50 mbpd of production and upgrading capacity in the Canadian oil sands. The timing and scope of potential future expansions and debottlenecking opportunities on existing operations remain under review.

The above discussion of the E&POil Sands Mining segment includes forward-looking statements with respect toconcerning the anticipated future exploratorycompletion of AOSP Expansion 1 and development drilling, the possibility of developing the Gudrun field offshore Norway and Blocks 31 and 32 offshore Angola, the timing of production from the Neptune development, the Piceance Basin, the Alvheim/Vilje development, the Volund field and the Corrib project. Some factorsproduction. Factors which could potentially affect these forward-looking statementsthe expansion project include pricing, supplytransportation logistics, availability of materials and demand for petroleum products, the amount of capital available for exploration and development, regulatory constraints, drilling rig availability,labor, unforeseen hazards such as weather conditions, acts of wardelays in obtaining or terrorist acts and the governmental or military response, and other geological, operating and

7

economic considerations. Except for the Alvheim/Vilje and Volund developments, the foregoing forward-looking statements may be further affectedconditions imposed by the inability to obtain or delay in obtaining necessary government and third-party approvals and permits.other risks customarily associated with construction projects. The possible developments on the Gudrun field and Blocks 31 and 32AOSP expansion could be further be affected by presently known data concerning sizecommissioning and characterstart-up risks associated with prototype equipment and new technology.

Reserves

In December 2008, the Securities and Exchange Commission (“SEC”) announced revisions to its regulations on oil and gas reporting. In January 2010, the Financial Accounting Standards Board issued an accounting standards update which was intended to harmonize the accounting literature with the SEC’s new regulations. See Item 8. Financial Statements and Supplementary Data – Note 2 to the consolidated financial statements for a summary of reservoirs, economic recoverability, future drilling successthe changes. The revised regulations were applied in estimating and production experience. reporting our reserves as of December 31, 2009, which totaled 1,679 mmboe.

Estimated Reserve Quantities

The foregoing factors (among others) could cause actual results to differ materially from those setfollowing table sets forth estimated quantities of our net proved liquid hydrocarbon, natural gas and synthetic crude oil reserves based upon an unweighted average of closing prices for the first day of each month in the forward-looking statements.

Reserves

        At12-month period ended December 31, 2006,2009. Approximately 61 percent of our proved reserves are located in Organization for Economic Cooperation and Development (“OECD”) countries.

Under the new regulations, reserves are now disclosed by continent, by country, if the proved reserves related to any geographic area, on an oil-equivalent barrel basis represent 15 percent or more of our total proved reserves. A geographic area can be an individual country, group of countries within a continent, or a continent. Reserve quantities previously reported for 2008 and 2007 have been reorganized into these geographic groupings below for comparability.