UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2005

Commission file number 1-5153

Marathon Oil Corporation

(Exact name of registrant as specified in its charter)

5555 San Felipe Road, Houston, TX 77056-2723

(Address of principal executive offices)

Tel. No. (713) 629-6600

Securities registered pursuant to Section 12 (b) of the Act:*

Title of Each Class

Common Stock, par value $1.00

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes þ    No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months and (2) has been subject to such filing requirements for the past 90 days.    Yes þ    No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ         Accelerated filer o         Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes o    No þ

The aggregate market value of Common Stock held by non-affiliates as of June 30, 2005: $19.5 billion. This amount is based on the closing price of the registrant’s Common Stock on the New York Stock Exchange composite tape on that date. Shares of Common Stock held by executive officers and directors of the registrant are not included in the computation. However, the registrant has made no determination that such individuals are “affiliates” within the meaning of Rule 405 of the Securities Act of 1933.

There were 366,808,670 shares of Marathon Oil Corporation Common Stock outstanding as of January 31, 2006.

Documents Incorporated By Reference:

Portions of the registrant’s proxy statement relating to its 2006 annual meeting of stockholders, to be filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934, are incorporated by reference to the extent set forth in Part III, Items 10-14 of this report.

MARATHON OIL CORPORATION

      Unless the context otherwise indicates, references in this Annual Report on Form 10-K to “Marathon,” “we,” “our,” or “us” are references to Marathon Oil Corporation, including its wholly-owned and majority-owned subsidiaries, and its ownership interests in equity method investees (corporate entities, partnerships, limited liability companies and other ventures over which Marathon exerts significant influence by virtue of its ownership interest, typically between 20 and 50 percent). Effective September 1, 2005, subsequent to the acquisition discussed in Note 5 to the consolidated financial statements, Marathon Ashland Petroleum LLC changed its name to Marathon Petroleum Company LLC. References to Marathon Petroleum Company LLC (“MPC”) are references to the entity formerly known as Marathon Ashland Petroleum LLC.

TABLE OF CONTENTS

Disclosures Regarding Forward-Looking Statements

      This Annual Report on Form 10-K, particularly Item 1. Business, Item 1A. Risk Factors, Item 3. Legal Proceedings, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures about Market Risk, includes forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. These statements typically contain words such as “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “plan,” “predict” “target,” “project,” “could,” “may,” “should,” “would” or similar words, indicating that future outcomes are uncertain. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

     Forward-looking statements in this Report may include, but are not limited to, levels of revenues, gross margins, income from operations, net income or earnings per share; levels of capital, exploration, environmental or maintenance expenditures; the success or timing of completion of ongoing or anticipated capital, exploration or maintenance projects; volumes of production, sales, throughput or shipments of liquid hydrocarbons, natural gas and refined products; levels of worldwide prices of liquid hydrocarbons, natural gas and refined products; levels of reserves, proved or otherwise, of liquid hydrocarbons and natural gas; the acquisition or divestiture of assets; the effect of restructuring or reorganization of business components; the potential effect of judicial proceedings on our business and financial condition; and the anticipated effects of actions of third parties such as competitors, or federal, state or local regulatory authorities.

PART I

Item 1. Business

General

      Marathon Oil Corporation was originally organized in 2001 as USX HoldCo, Inc., a wholly-owned subsidiary of the former USX Corporation. As a result of a reorganization completed in July 2001, USX HoldCo, Inc. (1) became the parent entity of the consolidated enterprise (the former USX Corporation was merged into a subsidiary of USX HoldCo, Inc.) and (2) changed its name to USX Corporation. In connection with the transaction described in the next paragraph (the “Separation”), USX Corporation changed its name to Marathon Oil Corporation.

     Before December 31, 2001, Marathon had two outstanding classes of common stock: USX-Marathon Group common stock, which was intended to reflect the performance of our energy business, and USX-U.S. Steel Group common stock (“Steel Stock”), which was intended to reflect the performance of our steel business. On December 31, 2001, we disposed of our steel business through a tax-free distribution of the common stock of our wholly-owned subsidiary United States Steel Corporation (“United States Steel”) to holders of Steel Stock in exchange for all outstanding shares of Steel Stock on a one-for-one basis.

     In connection with the Separation, our certificate of incorporation was amended on December 31, 2001 and, from that date, Marathon has only one class of common stock authorized.

     On June 30, 2005, we acquired the 38 percent ownership interest in Marathon Ashland Petroleum LLC (“MAP”) previously held by Ashland Inc. (“Ashland”). In addition, we acquired a portion of Ashland’s Valvoline Instant Oil Change business, its maleic anhydride business, its interest in LOOP LLC, which owns and operates the only U.S. deepwater oil port, and its interest in LOCAP LLC, which owns a crude oil pipeline. As a result of the transactions (the “Acquisition”), MAP is now wholly owned by Marathon and its name was changed to Marathon Petroleum Company LLC (“MPC”) effective September 1, 2005.

Segment and Geographic Information

      Our operations consist of three operating segments: 1) Exploration and Production (“E&P”) – explores for and produces crude oil and natural gas on a worldwide basis; 2) Refining, Marketing and Transportation (“RM&T”) – refines, markets and transports crude oil and petroleum products, primarily in the Midwest, the upper Great Plains and southeastern United States; and 3) Integrated Gas (“IG”) – markets and transports natural gas and products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol on a worldwide basis. For operating segment and geographic financial information, see Note 8 to the consolidated financial statements.

Exploration and Production

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

     As of December 31, 2005 we were conducting exploration, development and production activities in nine countries. Principal exploration activities were in the United States, Norway, Angola, Equatorial Guinea, the United Kingdom and Canada. Principal development and production activities were in the United States, the United Kingdom, Ireland, Norway, Equatorial Guinea, Gabon and Russia.

     On December 29, 2005, in conjunction with our partners in the former Oasis Group, we entered into an agreement with the National Oil Corporation of Libya on the terms under which the companies would return to their oil and natural gas exploration and production operations in the Waha concessions in Libya. See Note 5 to the consolidated financial statements.

     Our 2005 worldwide net liquid hydrocarbon sales averaged 191,000 barrels per day (“bpd”), an increase of 12 percent from 2004 levels. Our 2005 worldwide net natural gas sales, including gas acquired for injection and subsequent resale, averaged 932 million cubic feet per day (“mmcfd”), a decrease of 7 percent compared to 2004. In total, our 2005 worldwide net sales averaged 346,000 barrels of oil equivalent (“boe”) per day, compared to 337,000 boe per day in 2004. (For purposes of determining boe, natural gas volumes are converted to approximate liquid hydrocarbon barrels by dividing the natural gas volumes expressed in thousands of cubic feet (“mcf”) by six. The liquid hydrocarbon volume is added to the barrel equivalent of gas volume to obtain boe.) In 2006, our worldwide net production available for sale is expected to average approximately 365,000 to 395,000 boe per day, including 40,000 to 45,000 bpd from our Libya operations, excluding future acquisitions and dispositions.

     The above projections of 2006 Libya and worldwide net liquid hydrocarbon and natural gas sales and production volumes are forward-looking statements. Some factors that could potentially affect timing and 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 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 government or military response thereto, 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 2005, we drilled 33 gross (21 net) exploratory wells of which 29 gross (18 net) wells encountered hydrocarbons. Of these 29 wells, one gross (zero net) well was temporarily suspended. Internationally, we drilled 13 gross (six net) exploratory wells of which 11 gross (five net) wells encountered hydrocarbons. Of these 11 gross (five net) wells, all were temporarily suspended or are in the process of completing.

     United States – The Gulf of Mexico continues to be a core area for us with the potential to add new reserves. At the end of 2005, we had interests in 129 blocks in the Gulf of Mexico, including 96 in the deepwater area.

     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. Our plans are to develop this as a subsea tieback to area infrastructure. Commercial terms have been secured for the tieback and processing of Ozona production and we are attempting to secure a drilling 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 continued during 2005 and are progressing towards a possible re-entry and sidetrack before 2008. In 2005, a well drilled on a block directly offsetting the Flathead prospect encountered hydrocarbons. We hold a 100 percent operated interest in the Flathead prospect.

     In 2005, we drilled a well on the Stones prospect located on Walker Ridge block 508 in the Gulf of Mexico to total depth and encountered hydrocarbons. Additional drilling is required to determine the commerciality of this prospect. We hold a 20 percent outside-operated interest in the Stones prospect.

     Other United States exploration activity during 2005 included three gross (three net) wells in the Cook Inlet area of Alaska, all of which were discoveries, and 14 gross (six net) wells in the Anadarko Basin in Oklahoma, 13 gross (six net) of which were discoveries.

     Norway – We hold interests in over 1 million gross acres offshore Norway and plan to continue our exploration effort there. In late 2005, we began drilling an appraisal well at the outside-operated Gudrun discovery, which we expect will be completed in the first quarter of 2006 and followed by an evaluation of the well results.

     Results for the Volund well (formerly Hamsun) are being analyzed and development scenarios are being examined including a possible tie-back to the Alvheim development. We own a 65 percent interest in Volund and serve as operator.

     Angola – Offshore Angola, we own a 10 percent interest in Block 31 and a 30 percent interest in Block 32. To date we have announced 13 discoveries on these blocks, which reinforces the potential of this trend. On Block 31, we have four previously announced discoveries which form a potential development area in the northeastern portion of the block (Plutao, Saturo, Marte and Venus). In 2005, we announced five additional discoveries located in the southeastern part of Block 31 (Palas, Ceres, Juno, Astraea and Hebe). On Block 32, we previously announced the Gindungo and Canela discoveries. In 2005, we announced the Gengibre discovery and also had a successful appraisal well on this discovery. Lastly, in early 2006, we announced another discovery on the Mostarda prospect. Continued exploration success reinforces the potential for a commercial development on Block 32.

     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 approximately 11 miles southwest of the Alba Field. We are currently evaluating development scenarios for both the Deep Luba and Gardenia discoveries. These discoveries reinforce the potential of the Alba Block, in which we own a 63 percent interest.

     In 2003, we announced a natural gas discovery on Block D offshore Equatorial Guinea, where we are the operator with a 90 percent interest. The discovery well is on the Bococo prospect, which is approximately six miles west of the Alba field. The well has been suspended for re-entry at a later date. Development scenarios for the Bococo gas discovery along with three earlier dry gas discoveries on Block D are being considered for further development.

     Canada – We are the operator and own a 30 percent interest in the Annapolis lease offshore Nova Scotia. In addition, we operate the adjacent Cortland lease where we own a 75 interest and the adjacent Empire lease where we own a 50 percent interest.

Production (including development activities)

     United States – Approximately 40 percent of our 2005 worldwide net liquid hydrocarbon sales and 62 percent of our worldwide net natural gas sales were produced from U.S. operations.

     During 2005, our production in the Gulf of Mexico averaged 33,800 bpd of liquid hydrocarbons, representing 44 percent of our total U.S. net liquid hydrocarbon sales, and 84 mmcfd of natural gas, representing 14 percent of our total U.S. net natural gas sales. Net liquid hydrocarbon production in the Gulf of Mexico decreased by 1,900 bpd and net natural gas production decreased by 16 mmcfd from the prior year. The decrease in production is mainly due to natural field declines and the effects of five tropical storms or hurricanes during 2005. In September 2004, our Petronius platform suffered damage from Hurricane Ivan and was out of service until March 2005. At year-end 2005, we held interests in eight producing fields and seven platforms in the Gulf of Mexico, of which four platforms are operated by Marathon.

     We are one of the largest natural gas producers in the Cook Inlet and adjacent Kenai Peninsula of Alaska. In 2005 our Alaskan net natural gas sales averaged 167 mmcfd, representing 29 percent of our total U.S. net natural gas sales. Our natural gas production from Alaska is seasonal in nature, trending down during the second and third quarters and increasing during the fourth and first quarters to meet local market winter demands. 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 32-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 2005 development program in the Cook Inlet included participation in the drilling of six wells.

     Net liquid hydrocarbon sales from our Wyoming fields averaged 20,700 bpd in 2005 compared to 21,200 bpd in 2004. Net natural gas sales from our Wyoming fields averaged 104 mmcfd in 2005 compared to 108 mmcfd in 2004. The decrease in our Wyoming net natural gas sales is primarily attributed to lower production from the Powder River Basin, which averaged 66 mmcfd in 2005 compared to 69 mmcfd in 2004 primarily as a result of natural field decline, partially offset by development drilling. Development of the Powder River Basin continued in 2005 with approximately 195 wells drilled, compared to approximately 230 wells drilled in 2004. Water discharge regulations impacted the pace of development in the Powder River Basin in 2005. Additional development of our southwest Wyoming interests continued in 2005 where we participated in the drilling of 35 wells.

     Net natural gas sales from our Oklahoma fields averaged 77 mmcfd in 2005 compared to 82 mmcfd in 2004 primarily as a result of natural field decline, partially offset by development and exploratory drilling. Our 2005 development program continued to focus in the Anadarko Basin where we participated in the drilling of 82 wells.

     Our share of liquid hydrocarbon sales from the Permian Basin region, which extends from southeast New Mexico to west Texas, averaged 15,900 bpd in 2005, compared to 18,900 bpd in 2004. Net natural gas sales from our New Mexico fields, primarily the Indian Basin field, averaged 59 mmcfd in 2005 compared to 85 mmcfd in 2004. These decreases in net sales are due to natural field declines.

     Net natural gas sales from our Texas fields, primarily located in East Texas, averaged 73 mmcfd in 2005 compared to 65 mmcfd in 2004. This increase is primarily attributable to drilling in the Pearwood and Giddings fields. In addition, active development of the Mimms Creek field in East Texas continued in 2005.

     During 2005, we announced the sanctioning of the Neptune deepwater development on Atwater Valley Blocks 573, 574, 575, 617 and 618 in the Gulf of Mexico. In 2004, we announced that the Neptune 7 appraisal well encountered hydrocarbons. This discovery followed the Neptune 3 discovery in 2002 and the Neptune 5 discovery in 2003. Two successful appraisal sidetrack wells were also drilled from the original Neptune 5 location. We hold a 30 percent interest in the Neptune unit which is located approximately 120 miles off the coast of Louisiana. The field will be developed with seven initial subsea wells tied back to a stand alone tension leg platform. Fabrication of the platform commenced in late 2005. The drilling and completion of the development wells is expected to begin during the first half of 2006. Neptune is expected to begin production in late 2007 or early 2008 reaching full production during 2008.

     In 2003, we announced the Perseus discovery located on Viosca Knoll Block 830 in the Gulf of Mexico approximately five miles from the Petronius platform. Production from the initial development well at Perseus was expected to begin in 2004 but, due to hurricane activity in September 2004 and the resulting damage to the Petronius platform, production was delayed. The initial long-reach development well was drilled from the Petronius platform reaching a total depth of 30,855 feet, and first production commenced in April 2005. Drilling of a second long-reach development well began in September 2005 and is expected to reach the planned total depth of 31,598 feet in the first quarter of 2006. First production from this second well is anticipated in the second quarter of 2006. We own a 50 percent outside-operated interest in this block.

     United Kingdom – Our largest asset in the U.K. North Sea is the Brae area complex where we are the operator and have a 42 percent interest in the South, Central, North, and West Brae fields and a 38 percent interest in the East Brae field. The Brae A platform and facilities host the underlying South Brae field and the adjacent Central Brae field and West Brae/Sedgwick fields. The North Brae field, which is produced via the Brae B platform, and the East Brae field are gas condensate fields. Our share of sales from the Brae area averaged 18,300 bpd of liquid hydrocarbons in 2005, compared with 15,900 bpd in 2004. The increase primarily resulted from the timing of sales of liquid hydrocarbons and improved performance from the West Brae reservoir. Our share of Brae natural gas sales averaged 169 mmcfd, which was lower than the 197 mmcfd in 2004 as a result of natural field declines in the North and East Brae gas condensate fields.

     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 are 23 agreements with third-party fields 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”) system. The Beryl group owns the remaining 50 percent. The SAGE pipeline transports gas from the Brae and Beryl areas and has a total wet natural gas capacity of approximately 1.1 billion cubic feet (“bcf”) per day. The SAGE terminal at St. Fergus in northeast Scotland processes natural gas from the SAGE pipeline and 0.8 bcf per day of third-party natural gas from the Britannia field.

     In the U.K. Atlantic Margin, we own an approximate 30 percent interest in the outside-operated Foinaven area complex, consisting of a 28 percent interest in the main Foinaven field, 47 percent of East Foinaven and 20 percent of the T35 and T25 accumulations, each of which has a single well. Our share of sales from the Foinaven fields averaged 16,000 bpd of liquid hydrocarbons and 9 mmcfd of natural gas in 2005, compared to 21,900 bpd and 10 mmcfd in 2004, primarily as a result of the timing of sales of liquid hydrocarbons; however, reliability issues and natural field declines also contributed to the decrease.

     Norway – We are the operator and own a 65 percent interest in the Alvheim complex located on the Norwegian Continental Shelf. This development is comprised of the Kneler and Boa discoveries and the previously undeveloped Kameleon accumulation. During 2004, we received approval from the Norwegian authorities for our Alvheim plan of 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 signed a purchase and sale agreement in 2004 for the Odin multipurpose shuttle tanker, which will be modified to an FPSO. In 2004,

the Alvheim partners reached agreement to tie-in the nearby Vilje discovery, in which we own a 47 percent interest, subject to the approval of the Norwegian government. In 2005, the Norwegian government approved the Vilje PDO. Our share of production from a combined Alvheim/Vilje development is expected to reach more than 50,000 boe per day with first production starting in early 2007.

     During 2005, net liquid hydrocarbon and natural gas sales in Norway from the Heimdal, Vale, Byggve and Skirne fields averaged 2,000 bpd and 34 mmcfd. We own a 24 percent interest in the Heimdal field, a 47 percent interest in the Vale field and a 20 percent interest in the Skirne field, which came on stream during 2004.

     Ireland – We own a 100 percent interest in the Kinsale Head, Ballycotton and Southwest Kinsale fields in the Celtic Sea offshore Ireland. Net natural gas sales were 50 mmcfd in 2005, compared with 58 mmcfd in 2004. In February 2006, we acquired an 86.5 percent operated 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.

     We own an 18.5 percent interest in the outside-operated Corrib natural gas development project, located approximately 40 miles off Ireland’s west coast. During 2004, 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 in 2005 pending resolution of issues raised by opponents of the project. A government-commissioned independent safety review of the onshore pipeline associated with the proposed development has been completed and we are awaiting publication of the related report.

     Equatorial Guinea – We own a 63 percent interest in the Alba field offshore Equatorial Guinea and a 52 percent interest in an onshore liquefied petroleum gas processing plant held through an equity method investee. During 2005, net liquid hydrocarbon sales averaged 39,600 bpd and net natural gas sales averaged 92 mmcfd, compared to 18,900 bpd and 76 mmcfd in 2004. A condensate expansion project in Equatorial Guinea was completed during 2004 and ramped up to full production in early 2005. This expansion project increased condensate production from approximately 15,000 gross bpd to approximately 67,000 gross bpd (38,000 bpd net to Marathon). A liquefied petroleum gas (“LPG”) expansion project in Equatorial Guinea ramped up to full production in the third quarter of 2005. Gross LPG production increased from approximately 3,000 gross bpd to 19,000 gross bpd (11,000 bpd net to Marathon). Liquid hydrocarbon production continues to increase as a result of the expansion projects. Total production available for sale in January 2006 was approximately 90,000 gross bpd (51,000 bpd net to Marathon).

     Approximately 130 mmcfd of dry gas remaining after the condensate and LPG are removed is supplied to Atlantic Methanol Production Company LLC (“AMPCO”), where it is used to manufacture methanol. We own 45 percent of AMPCO, which is reported in the Integrated Gas segment. Remaining dry gas is returned offshore and reinjected into the Alba reservoir for later production when the LNG plant construction project on Bioko Island, discussed below under Integrated Gas, is completed.

     Libya – We hold a 16.33 percent interest in the Waha concessions, which currently produce approximately 350,000 gross boe per day and encompass almost 13 million acres located in the Sirte Basin. As a result of our return to operations in Libya, we expect to add approximately 40,000 to 45,000 net bpd of production available for sale during 2006.

     Gabon – We are the operator of the Tchatamba South, Tchatamba West and Tchatamba Marin fields offshore Gabon with a 56 percent interest. Net sales in Gabon averaged 12,100 bpd of liquid hydrocarbons in 2005, compared with 13,600 bpd in 2004. Production from these three fields is processed on a single 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 (“KMOC”). KMOC’s fields are located in the Khanty Mansiysk region of western Siberia. Net liquid hydrocarbon sales from these assets averaged 26,600 bpd during 2005, primarily from the East Kamennoye and Potenay fields. Development activities continued in 2005, with 82 wells drilled in East Kamennoye.

Other Matters

     We hold an interest in an exploration and production license in Sudan. We suspended operations in Sudan in 1985. We have had no employees in the country and have derived no economic benefit from those interests since that time. 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.

     We discovered the Ash Shaer and Cherrife gas fields in Syria in the 1980s. We submitted four plans of development to the Syrian Petroleum Company in the 1990s, but none were approved. The Syrian government subsequently claimed that the production sharing contract for these fields had expired. We have been involved in an

ongoing dispute with the Syrian Petroleum Company and government of Syria over our interest in these fields. We are discussing a settlement under which a new production sharing contract would be executed to provide us the right to sell all or a significant portion of our interest to a third party. We have and will continue to comply with all U.S. sanctions related to Syria.

     The above discussion of the E&P segment includes forward-looking statements with respect to the timing of completion of the Gudrun appraisal well, the possibility of developing Blocks 31 and 32 offshore Angola, the timing and levels of production from the Neptune development, the Perseus discovery, the combined Alvheim/Vilje development and estimated levels of production associated with our re-entry into Libya. Some factors which could affect the timing of completion of the Gudrun appraisal well, the possible development of Blocks 31 and 32, the timing and production levels of the Neptune development, the Perseus discovery, the Alvheim/Vilje development and estimated levels of production in Libya include pricing, supply and demand for petroleum products, amount of capital available for exploration and development, regulatory constraints, drilling rig availability, inability or delays in obtaining necessary government or third-party approvals or permits, timing of commencing production from new wells, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other geological, operating and economic considerations. The estimated levels of production in Libya and possible developments in Blocks 31 and 32 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.

     At December 31, 2005, our net proved liquid hydrocarbon and natural gas reserves totaled approximately 1.295 billion boe, of which 44 percent were located in Organization for Economic Cooperation and Development (“OECD”) countries. The following table sets forth estimated quantities of net proved oil and natural gas reserves at the end of each of the last three years.

Estimated Quantities of Net Proved Liquid Hydrocarbon and Natural Gas Reserves at December 31

     Proved developed reserves represented 71 percent of total proved reserves as of December 31, 2005, as compared to 62 percent as of December 31, 2004. Of the 374 million boe of proved undeveloped reserves at year-end 2005, less than 20 percent have been included as proved reserves for more than three years while approximately 18 percent were added during 2005.

     During 2005, we added net proved reserves of 282 million boe, excluding 2 million boe of dispositions, while producing 124 million boe. These net additions included 165 million boe as a result of our re-entry into Libya, 50 million boe of extensions, discoveries and other additions, and total revisions of 58 million boe. Of the total net reserve additions, 215 million boe were proved developed and 67 million boe were proved undeveloped. Additionally, we transferred 121 million boe from proved undeveloped to proved developed during 2005. Costs incurred for the periods ended December 31, 2005, 2004 and 2003 relating to the development of proved undeveloped oil and natural gas reserves, were $955 million, $708 million and $780 million. These amounts include our proportionate share of equity method investees’ costs incurred as these were costs necessary for the development of proved undeveloped reserves. As of December 31, 2005, estimated future development costs relating to the development of proved undeveloped oil and natural gas reserves for the years 2006 through 2008 are projected to be $868 million, $340 million and $175 million.

     The Alba field in Equatorial Guinea had the most significant positive revisions, totaling 47 million boe. Of this volume, 21 million boe was added due to the progress on the Equatorial Guinea LNG project, which will provide a market for the Alba field’s natural gas reserves sooner and to a greater extent under the current production sharing contract than was expected when proved reserves were estimated at the end of 2004. At the end of 2005, our total proved reserves associated with the Alba field offshore Equatorial Guinea totaled 505 million boe, or 39 percent of our total proved reserves.

     The above estimated quantities of net proved oil and natural gas reserves, estimated future development costs relating to the development of proved undeveloped oil and natural gas reserves and timing of production from development projects are forward-looking statements and are based on a number of assumptions, including (among others) 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 could be different than current estimates.

     For additional details of estimated quantities of net proved oil and natural gas reserves at the end of each of the last three years, see “Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities – Estimated Quantities of Proved Oil and Natural Gas Reserves” on pages F-46 through F-47. We filed reports with the U.S. Department of Energy (“DOE”) for the years 2004 and 2003 disclosing the year-end estimated oil and natural gas reserves. We will file a similar report for 2005. The year-end estimates reported to the DOE are the same as the estimates reported in the Supplementary Information on Oil and Gas Producing Activities.

     We have committed to deliver fixed and determinable quantities of natural gas to customers under a variety of contractual arrangements.

     In Alaska, we have two long-term sales contracts with local utility companies, which obligate us to supply approximately 152 bcf of natural gas over the remaining lives of these contracts, which terminate in 2012 and 2018. During 2005, we entered into another agreement with a local utility company which, pending Regulatory Commission of Alaska approval, will obligate us to supply approximately 60 bcf of natural gas between 2009 and 2018. In addition, we own a 30 percent interest in a Kenai, Alaska LNG plant and a proportionate share of the long-term LNG sales obligation to two Japanese utility companies. This obligation is estimated to total 62 bcf through the remaining life of the contract, which terminates in 2009. These commitments are structured with variable-pricing terms. Our production from various natural gas fields in the Cook Inlet supply the natural gas to service these contracts. Our proved reserves in the Cook Inlet are sufficient to meet these contractual obligations.

     In the U.K., we have two long-term sales contracts with utility companies, which obligate us to supply approximately 190 bcf of natural gas through the remaining lives of these contracts, which terminate in 2009. Our Brae area proved reserves, acquired natural gas contracts and estimated production rates are sufficient to meet these contractual obligations. Pricing under these natural gas sales contracts is variable. See Note 17 to the consolidated financial statements for further discussion of these contracts.

     The following tables set forth daily average net sales of liquid hydrocarbons and natural gas for each of the last three years:

Net Liquid Hydrocarbon Sales^(a)(b)

Net Natural Gas Sales^(b)(f)

     The following tables set forth productive wells and service wells for each of the last three years and drilling wells as of December 31, 2005.

Gross and Net Wells

     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:

Net Productive and Dry Wells Completed^(a)

     The following table sets forth, by geographic area, the developed and undeveloped oil and natural gas acreage that we held as of December 31, 2005:

Gross and Net Acreage

Refining, Marketing and Transportation

      Our RM&T operations are primarily conducted by MPC and its subsidiaries, including its wholly-owned subsidiaries Speedway SuperAmerica LLC (“SSA”) and Marathon Pipe Line LLC.

Refining

     We own and operate seven refineries with an aggregate refining capacity of 974,000 barrels of crude oil per day. The table below sets forth the location and daily throughput capacity of each of our refineries as of December 31, 2005:

     Our refineries include crude oil atmospheric and vacuum distillation, fluid catalytic cracking, catalytic reforming, desulfurization and sulfur recovery units. The refineries can process a wide variety of crude oils and produce typical refinery products, including reformulated and low sulfur gasolines. Our refineries are integrated via pipelines and barges to maximize operating efficiency. The transportation links that connect the refineries allow the movement of intermediate products to optimize operations and the production of higher margin products. For example, naphtha may be moved from Texas City to Robinson where excess reforming capacity is available. By shipping intermediate products between facilities during partial refinery shutdowns, we are able to utilize processing capacity that is not directly affected by the shutdown work.

     We increased our overall crude oil refining capacity during 2005 from 948,000 bpd to 974,000 bpd after completing the expansion project at our Detroit refinery. This expansion increased crude oil capacity at Detroit from 74,000 bpd to 100,000 bpd. The project also improves operating efficiency and enables the Detroit refinery to meet new lower gasoline and diesel sulfur specifications.

     During 2005, we announced plans to evaluate a 180,000 bpd expansion of our Garyville refinery. The initial phase of the potential expansion includes front-end engineering and design (“FEED”) work which began in December 2005 and could lead to the start of construction in 2007. The project, estimated to cost approximately $2.2 billion, could be completed as early as the fourth quarter of 2009. The final investment decision is subject to completion of the FEED work and the receipt of applicable permits.

     We also produce asphalt cements, polymerized asphalt, asphalt emulsions and industrial asphalts. We manufacture petroleum pitch, primarily used in the graphite electrode, clay target and refractory industries. Additionally, we manufacture aromatics, aliphatic hydrocarbons, cumene, base lube oil, polymer grade propylene, maleic anhydride and slack wax.

     During 2005, our refineries processed 973,000 bpd of crude oil and 205,000 bpd of other charge and blend stocks. The following table sets forth our refinery production by product group for each of the last three years:

Refined Product Yields

     Planned maintenance activities requiring temporary shutdown of certain refinery operating units, or turnarounds, are periodically performed at each refinery. We completed major turnarounds at our Detroit and Catlettsburg refineries in 2005.

Marketing

     In 2005, our refined product sales volumes (excluding matching buy/sell transactions) totaled 21.1 billion gallons (1,378,000 bpd). The wholesale distribution of petroleum products to private brand marketers and to large commercial and industrial consumers, primarily located in the Midwest, the upper Great Plains and the Southeast, and sales in the spot market, accounted for approximately 71 percent of our refined product sales volumes in 2005, excluding sales related to matching buy/sell transactions. Approximately 53 percent of our gasoline sales volumes and 91 percent of our distillate sales volumes were sold on a wholesale or spot market basis.

     Approximately half of our propane is sold into the home heating market, with the balance being purchased by industrial consumers. Propylene, cumene, aromatics, aliphatics, and sulfur are domestically marketed to customers in the chemical industry. Base lube oils, maleic anhydride, slack wax, extract and pitch are sold throughout the United States and Canada, with pitch products also being exported worldwide.

     We market asphalt through owned and leased terminals throughout the Midwest, the upper Great Plains and the Southeast. Our customer base includes approximately 830 asphalt-paving contractors, government entities (states, counties, cities and townships) and asphalt roofing shingle manufacturers.

     The following table sets forth our refined product sales by product group for each of the last three years:

Refined Product Sales

     We sell reformulated gasoline in parts of our marketing territory, primarily Chicago, Illinois; Louisville, Kentucky; northern Kentucky; and Milwaukee, Wisconsin. We also sell low-vapor-pressure gasoline in nine states.

     As of December 31, 2005, we supplied petroleum products to about 4,000 Marathon branded retail outlets located primarily in Michigan, Ohio, Indiana, Kentucky and Illinois. Branded retail outlets are also located in Florida, Georgia, Minnesota, Wisconsin, West Virginia, Tennessee, Virginia, North Carolina, Pennsylvania, Alabama and South Carolina.

     SSA sells gasoline and diesel fuel through company-operated retail outlets. As of December 31, 2005, SSA had 1,638 retail outlets in nine states that sold petroleum products and convenience store merchandise and services, primarily under the brand names “Speedway” and “SuperAmerica.” SSA’s revenues from the sale of non-petroleum merchandise totaled $2.5 billion in 2005, compared with $2.3 billion in 2004. Profit levels from the sale of such merchandise and services tend to be less volatile than profit levels from the retail sale of gasoline and diesel fuel. SSA also operates 60 Valvoline Instant Oil Change retail outlets located in Michigan and northwest Ohio.

     Pilot Travel Centers LLC (“PTC”), our joint venture with Pilot Corporation (“Pilot”), is the largest operator of travel centers in the United States with approximately 260 locations in 37 states at December 31, 2005. The travel centers offer diesel fuel, gasoline and a variety of other services, including on-premises brand-name restaurants. Pilot and Marathon each own a 50 percent interest in PTC.

     Our marketing strategy is focused on SSA’s Midwest operations, additional growth of the Marathon brand and continued growth for PTC.

Supply and Transportation

     We obtain the crude oil we process from negotiated contracts and spot purchases or exchanges. In 2005, our net purchases of U.S. produced crude oil for refinery input averaged 447,000 bpd, or 46 percent of crude oil processed, including a net 12,000 bpd from our production operations. In 2005, Canada was the source for 11 percent, or 111,000 bpd, of crude oil processed and other foreign sources supplied 43 percent, or 415,000 bpd, of the crude oil processed by our refineries, including approximately 221,000 bpd from the Middle East. This crude was acquired from various foreign national oil companies, producing companies and trading companies.

     We operate a system of pipelines and terminals to provide crude oil to our refineries and refined products to our marketing areas. At December 31, 2005, we owned or leased approximately 2,774 miles of crude oil trunk lines and 3,824 miles of refined product trunk lines. At December 31, 2005 we had interests in the following pipelines:

     Our 85 light product and asphalt terminals are strategically located throughout the Midwest, upper Great Plains and Southeast. These facilities are supplied by a combination of pipelines, barges, rail cars and/or trucks. Our marine transportation operations include towboats and barges that transport refined products on the Ohio, Mississippi and Illinois rivers, their tributaries and the Intercoastal Waterway. We also lease and own rail cars of various sizes and capacities for movement and storage of petroleum products and a large number of tractors and tank trailers.

     Effective October 15, 2006, most of the diesel fuel sold for highway use must contain no more than 15 parts per million of sulfur at the retail outlet. This new ultra low sulfur diesel (“ULSD”) fuel requirement will place a premium on ensuring that there is no contamination of the ULSD while it is in transit to the retail outlet. We expect to be able to meet these requirements.

     The above discussion of the RM&T segment includes forward-looking statements concerning the possible expansion of the Garyville refinery. Some factors that could affect the Garyville expansion project include the results of the FEED work, necessary regulatory approvals, crude oil supply and transportation logistics, necessary permits and continued favorable investment climate, availability of materials and labor, unforeseen hazards such as weather conditions and other risks customarily associated with construction projects. These factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Integrated Gas

      Our integrated gas operations include natural gas liquefaction and regasification operations, methanol operations, certain other gas processing facilities and pipeline operations, and marketing and transportation of natural gas. Also included in the financial results of the Integrated Gas segment are the costs associated with ongoing development of certain integrated gas projects.

Alaska LNG

     We own a 30 percent interest in a Kenai, Alaska, natural gas liquefaction plant and 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, the LNG has been sold under a long-term contract with two of Japan’s largest utility companies. This contract continues through March 2009, with 2005 LNG deliveries totaling 65 gross bcf (22 net bcf).

Equatorial Guinea LNG Project

     In 2004, we and our partner, Compania Nacional de Petroleos de Guinea Ecuatorial (“GEPetrol”), the National Oil Company of Equatorial Guinea, through Equatorial Guinea LNG Holdings Limited (“EGHoldings”), began construction of an LNG plant on Bioko Island that will initially deliver a contracted offtake of 3.4 million metric tons per year beginning in 2007 (approximately 460 mmcfd) under a Sales and Purchase Agreement with a subsidiary of BG Group plc (“BGML”). BGML will purchase the LNG plant’s production for a period of 17 years on an FOB Bioko Island basis with pricing linked principally to the Henry Hub index. The LNG plant is ultimately expected to have the ability to operate at higher rates and for a longer period than the current contracted offtake rate and term. This project will allow us to monetize our natural gas reserves from the Alba field, as natural gas for the plant will be purchased from the Alba field participants under a long-term natural gas supply agreement. Construction of the plant is ahead of schedule with first shipment of LNG expected in the third quarter of 2007.

     On July 25, 2005, Marathon and GEPetrol entered into agreements under which Mitsui & Co., Ltd. (“Mitsui”) and a subsidiary of Marubeni Corporation (“Marubeni”) acquired 8.5 percent and 6.5 percent interests, respectively, in EGHoldings. Following the transaction, we hold a 60 percent interest in EGHoldings, with GEPetrol holding a 25 percent interest and Mitsui and Marubeni holding the remaining interests.

     The EGHoldings partners are also exploring the feasibility of adding a second LNG train in an effort to create a regional gas hub that would commercialize stranded natural gas from various sources in the surrounding Gulf of Guinea region.

Elba Island LNG

     In April 2004, we began delivering LNG cargoes as part of our Elba Island, Georgia LNG regasification terminal capacity rights agreement. Under the terms of the agreement, we can supply up to 58 billion cubic feet of natural gas (as LNG) per year into the terminal through 2021 with a possible extension to 2023.

     In September 2004, we signed an agreement with BP Energy Company (“BP”) under which BP will supply us with 58 bcf of natural gas per year, as LNG, for a minimum period of five years. The agreement allows for delivery of LNG at the Elba Island LNG regasification terminal with pricing linked to the Henry Hub index. This supply agreement with BP enables us to fully utilize our capacity rights at Elba Island during the period of this agreement, while affording us the flexibility to access this capacity to commercialize other stranded natural gas resources beyond the term of the BP contract. The agreement commenced in 2005.

Methanol

     We own a 45 percent interest in Atlantic Methanol Production Company LLC (“AMPCO”), which owns a methanol plant located in Malabo, Equatorial Guinea. Feedstock for the plant is supplied from a portion of our natural gas production in the Alba field. Methanol sales totaled 1,052,000 gross metric tons (473,000 net metric tons) in 2005. Production from the plant is used to supply customers in Europe and the U.S.

     AMPCO will undergo a scheduled maintenance shutdown during the second quarter of 2006. During the outage, AMPCO will also seek to remove bottlenecks in several parts of the plant.

Natural Gas Marketing and Transportation Activities

     In addition to the sale of our own natural gas production, we purchase gas from third-party producers and marketers for resale.

     During 2005, we sold our 24 percent interest in Nautilus Pipeline Company, LLC and our 24 percent interest in Manta Ray Offshore Gathering Company, LLC, which are both Gulf of Mexico natural gas pipeline systems. We still own a 34 percent interest in the Neptune natural gas processing plant located in St. Mary Parish, Louisiana. The plant has the capacity to process 600 mmcfd of natural gas, which is supplied by the Nautilus pipeline system.

Gas Technology

     We invest in gas technology research, including gas-to-liquids (“GTL”) technology which was successfully applied in a GTL demonstration plant at the Port of Catoosa, Oklahoma in 2004. In addition to GTL, we are continuing to explore gas technologies including methanol to power, gas to fuels and compressed natural gas technologies.

     The above discussion of the integrated gas segment contains forward looking statements with respect to the timing and levels of production associated with the LNG plant and the possible expansion thereof. Factors that could affect the LNG plant include, unforeseen problems arising from construction, inability or delay in obtaining necessary government and third-party approvals, unanticipated changes in market demand or supply, environmental issues, availability or construction of sufficient LNG vessels, and unforeseen hazards such as weather conditions. In addition to these factors, other factors that could potentially affect the possible expansion of the current LNG project and the development of additional LNG capacity through additional projects include partner 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.

Competition and Market Conditions

      Strong competition exists in all sectors of the oil and gas industry and, in particular, in the exploration and development of new reserves. We compete with major integrated and independent oil and gas companies for the acquisition of oil and natural gas leases and other properties. We compete with these companies, as well as national oil 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. As a consequence, we may be at a competitive disadvantage in bidding for the rights to explore for oil and natural gas. 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 on industry sources, we believe we currently rank ninth among U.S.-based petroleum companies on the basis of 2005 worldwide liquid hydrocarbon and natural gas production.

     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. We rank fifth among U.S. petroleum companies on the basis of U.S. crude oil refining capacity as of December 31, 2005. We compete in four distinct markets – wholesale, spot, branded and retail distribution – for the sale of refined products. We believe we compete with about 30 companies in the wholesale distribution of petroleum products to private brand marketers and large commercial and industrial consumers; about 75 companies in the sale of petroleum products in the spot market; nine refiner/marketers in the supply of branded petroleum products to dealers and jobbers; and approximately 220 petroleum product retailers in the retail sale of petroleum products. 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. Some locations also have on-premises brand-name restaurants such as Subway^tm. We also compete in the travel center industry through our 50 percent ownership in PTC.

     Our operating results are affected by price changes in crude oil, natural gas and petroleum products, as well as changes in competitive conditions in the markets we serve. Generally, results from production operations benefit from higher crude oil and natural gas prices while refining and marketing margins 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.

The Separation

      On December 31, 2001, pursuant to an Agreement and Plan of Reorganization dated as of July 31, 2001, Marathon completed the Separation, in which:

     As a result of the Separation, Marathon and United States Steel are separate companies, and neither has any ownership interest in the other. Effective January 31, 2006, Thomas J. Usher retired as chairman of the board of directors and as a director of United States Steel, and Dr. Shirley Ann Jackson retired as a director of United States Steel. As a result, three remaining members of our board of directors are also directors of United States Steel.

     In connection with the Separation and pursuant to the Plan of Reorganization, Marathon and United States Steel have entered into a series of agreements governing their relationship after the Separation and providing for the allocation of tax and certain other liabilities and obligations arising from periods before the Separation. The following is a description of the material terms of two of those agreements.

Financial Matters Agreement

     Under the financial matters agreement, United States Steel has assumed and agreed to discharge all Marathon’s principal repayment, interest payment and other obligations under the following, including any amounts due on any default or acceleration of any of those obligations, other than any default caused by Marathon:

     The financial matters agreement also provides that, on or before the tenth anniversary of the Separation, United States Steel will provide for Marathon’s discharge from any remaining liability under any of the assumed industrial revenue bonds. United States Steel may accomplish that discharge by refinancing or, to the extent not refinanced, paying Marathon an amount equal to the remaining principal amount of all accrued and unpaid debt service outstanding on, and any premium required to immediately retire, the then outstanding industrial revenue bonds.

     Under the financial matters agreement, United States Steel shall have the right to exercise all of the existing contractual rights under the lease obligations assumed from Marathon, including all rights related to purchase options, prepayments or the grant or release of security interests. United States Steel shall have no right to increase amounts due under or lengthen the term of any of the assumed lease obligations without the prior consent of Marathon other than extensions set forth in the terms of the assumed lease obligations.

     The financial matters agreement also requires United States Steel to use commercially reasonable efforts to have Marathon released from its obligations under a guarantee Marathon provided with respect to all United States Steel’s obligations under a partnership agreement between United States Steel, as general partner, and General Electric Credit Corporation of Delaware and Southern Energy Clairton, LLC, as limited partners. United States Steel may dissolve the partnership under certain circumstances including if it is required to fund accumulated cash shortfalls of the partnership in excess of $150 million. In addition to the normal commitments of a general partner, United States Steel has indemnified the limited partners for certain income tax exposures.

     The financial matters agreement requires Marathon to use commercially reasonable efforts to take all necessary action or refrain from acting so as to assure compliance with all covenants and other obligations under the documents relating to the assumed obligations to avoid the occurrence of a default or the acceleration of the payment obligations under the assumed obligations. The agreement also obligates Marathon to use commercially reasonable efforts to obtain and maintain letters of credit and other liquidity arrangements required under the assumed obligations.

     United States Steel’s obligations to Marathon under the financial matters agreement are general unsecured obligations that rank equal to United States Steel’s accounts payable and other general unsecured obligations. The financial matters agreement does not contain any financial covenants, and United States Steel is free to incur additional debt, grant mortgages on or security interests in its property and sell or transfer assets without our consent.

Tax Sharing Agreement

     Marathon and United States Steel have a tax sharing agreement that applies to each of their consolidated tax reporting groups. Provisions of this agreement include the following:

     Under the general tax sharing principles in effect before the Separation:

     In accordance with the tax sharing agreement, at the time of the Separation, Marathon made a preliminary settlement with United States Steel of approximately $440 million as the net tax sharing payments owed to it for the year ended December 31, 2001 under the pre-Separation tax sharing principles.

     The tax sharing agreement also addresses the handling of tax audits and contests and other matters respecting taxable periods, or portions of taxable periods, ended before December 31, 2001.

     In the tax sharing agreement, each of Marathon and United States Steel promised the other party that it:

     The prescribed actions and transactions include:

     In case a taxing authority seeks to collect a tax liability from one party that the tax sharing agreement has allocated to the other party, the other party has agreed in the sharing agreement to indemnify the first party against that liability.

     Even if the Separation otherwise qualified for tax-free treatment under section 355 of the Internal Revenue Code, the Separation may become taxable to Marathon under section 355(e) of the Internal Revenue Code if capital stock representing a 50 percent or greater interest in either Marathon or United States Steel is acquired, directly or indirectly, as part of a plan or series of related transactions that include the Separation. For this purpose, a “50 percent or greater interest” means capital stock possessing at least 50 percent of the total combined voting power of all classes of stock entitled to vote or at least 50 percent of the total value of shares of all classes of capital stock. To minimize this risk, both Marathon and United States Steel agreed in the tax sharing agreement that they would not enter into any transactions or make any change in their equity structures that could cause the Separation to be treated as part of a plan or series of related transactions to which those provisions of section 355(e) of the Internal Revenue Code may apply. If an acquisition occurs that results in the Separation being taxable under section 355(e) of the Internal Revenue Code, the agreement provides that the resulting corporate tax liability will be borne by the party involved in that acquisition transaction.

     Although the tax sharing agreement allocates tax liabilities relating to taxable periods ending on or prior to the Separation, each of Marathon and United States Steel, as members of the same consolidated tax reporting group during any portion of a taxable period ended on or prior to the date of the Separation, is jointly and severally liable under the Internal Revenue Code for the federal income tax liability of the entire consolidated tax reporting group for that year. To address the possibility that the taxing authorities may seek to collect all or part of a tax liability from one party where the tax sharing agreement allocates that liability to the other party, the agreement includes

indemnification provisions that would entitle the party from whom the taxing authorities are seeking collection to obtain indemnification from the other party, to the extent the agreement allocates that liability to that other party. Marathon can provide no assurance, however, that United States Steel will be able to meet its indemnification obligations, if any, to Marathon that may arise under the tax sharing agreement.

Obligations Associated with the Separation as of December 31, 2005

     See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Obligations Associated with the Separation of United States Steel” for a discussion of Marathon’s obligations associated with the Separation.

Environmental Matters

      We maintain a comprehensive environmental policy overseen by the Corporate Governance and Nominating Committee of our Board of Directors. Our Corporate Responsibility organization has the responsibility to ensure that our operating organizations maintain environmental compliance systems that are in accordance with applicable laws and regulations. The Corporate Responsibility Management Committee, which is comprised of certain of our officers, is charged with reviewing our overall performance with various environmental compliance programs. We also have a Crisis Management Team, composed primarily of senior management, which oversees the response to any major emergency environmental incident involving Marathon or any of our properties.

     Our businesses are subject to numerous 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 similar laws dealing with the same matters. New laws are being enacted and regulations are being adopted by various regulatory agencies on a continuing 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 cleanup 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 always 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 standards 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 “Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies” and “Legal Proceedings.”

Air

     Of particular significance to our refining operations are U.S. Environmental Protection Agency (“EPA”) regulations that require reduced sulfur levels starting in 2004 for gasoline and 2006 for diesel fuel. Our combined capital costs to achieve compliance with these rules are expected to approximate $900 million over the period between 2002 and 2006, which includes costs that could be incurred as part of other refinery upgrade projects. Costs incurred through December 31, 2005 were approximately $825 million, with the remainder expected to be incurred in 2006. This is a forward-looking statement. Some factors (among others) that could potentially affect gasoline and diesel fuel compliance costs include completion of construction and start-up activities.

     The EPA has finalized new and revised National Ambient Air Quality Standards (“NAAQS”) for fine particulate emissions (PM2.5) and ozone. In connection with these new 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, in January 2004, the EPA proposed a rule called the Interstate Air Quality Rule (“IAQR”) that would require significant reductions of SO₂ and NOx emissions in numerous states. The final rule was promulgated on May 12, 2005, and the rule 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 (“EGUs”), states will have the final say on what sources they regulate to meet attainment criteria. Our refinery operations are located in affected states and some states may choose to propose more stringent fuels requirements to meet the CAIR requirements; however we cannot reasonably estimate the final financial impact of the state actions to implement the CAIR until the states have taken further action.

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 such releases OPA-90 requires responsible companies to pay resulting removal costs and damages, 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. As of December 31, 2005, all of the barges used for river transport of our feedstocks and refined products meet the double-hulled requirements of OPA-90.

     We operate facilities at which spills of oil and hazardous substances could occur. Several 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.

Solid Waste

     We continue to seek methods to minimize the generation of hazardous wastes in our operations. 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 some of our RM&T facilities and primarily utilize offsite third-party treatment and disposal facilities. Ongoing RCRA-related costs are not expected to be material.

Remediation

     We own or operate certain retail outlets where, during the normal course of operations, releases of petroleum products from USTs have occurred. Federal and state laws require that contamination caused by such releases at these sites be assessed and remediated to meet applicable standards. The enforcement of the UST 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 the stringency of the laws and regulations of the states in which we operate. A portion of these remediation costs may be recoverable from the appropriate state UST reimbursement funds once the applicable deductibles have been satisfied. Accruals for remediation expenses and associated reimbursements are established for sites where contamination has been determined to exist and the amount of associated costs is reasonably determinable.

Employees

      We had 27,756 active employees as of December 31, 2005. Of that number, 18,257 were employees of Speedway SuperAmerica LLC, most of which were employed at retail marketing outlets.

     Certain hourly employees at our Catlettsburg and Canton refineries are represented by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers Union under labor agreements that expire on January 31, 2009. The same union represents certain hourly employees at our Texas City refinery under a labor agreement that expires on March 31, 2009. The International Brotherhood of Teamsters represents certain hourly employees under labor agreements that are scheduled to expire on May 31, 2006 at our St. Paul Park refinery and January 31, 2007 at our Detroit refinery.

Available Information

      General information about Marathon, including the Corporate Governance Principles and Charters for the Audit Committee, Compensation Committee, Corporate Governance and Nominating Committee, and Committee on Financial Policy, can be found at www.marathon.com. In addition, our Code of Business Conduct and Code of Ethics for Senior Financial Officers are available on the website at www.marathon.com/Values/Corporate Governance/. Marathon’s Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through the website as soon as reasonably practicable after the reports are filed or furnished with the SEC. These documents are also available in hard copy, free of charge, by contacting our Investor Relations office. Information contained on our website is not incorporated into this Annual Report on Form 10-K or other securities filings.

Item 1A. Risk Factors

      Marathon is subject to various risks and uncertainties in the course of its business. The following summarizes some, but not all, of the risks and uncertainties that may adversely affect our business, financial condition or results of operations.

A substantial or extended decline in oil or natural gas prices would reduce our revenues, operating results and future rate of growth.

     Prices for oil and natural gas fluctuate widely. Our revenues, operating results and future rate of growth are highly dependent on the prices we receive for our oil, natural gas and refined products. Historically, the markets for oil, natural gas and refined products have been volatile and may continue to be volatile in the future. Many of the factors influencing prices of oil, natural gas and refined products are beyond our control. These factors include:

     The long-term effects of these and other conditions on the prices of oil and natural gas are uncertain.

     Lower oil and natural gas prices may reduce the amount of oil and natural gas that we produce, which may reduce our revenues and operating income. Significant reductions in oil and natural gas prices could require us to reduce our capital expenditures.

Estimates of oil and natural gas reserves depend on many factors and assumptions, including various assumptions that are based on conditions in existence as of the dates of the estimates. Any material changes in those conditions or other factors affecting those assumptions could impair the quantity and value of our oil and natural gas reserves.

     The proved oil and natural gas reserve information included in this Report has been derived from engineering estimates. Those estimates were prepared by our personnel and reviewed, on a selected basis, by third-party petroleum engineers. The estimates were calculated using oil and natural gas prices in effect as of December 31, 2005, as well as other conditions in existence as of that date. Any significant future price changes may have a material effect on the quantity and present value of our proved reserves. Future reserve revisions could also result from changes in, among other things, governmental regulation and severance and other production taxes.

     Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of oil and natural gas that cannot be directly measured. As a result, different petroleum engineers, each using industry-accepted geologic and engineering practices and scientific methods, may produce different estimates of reserves and future net cash flows based on the same available data. Because of the subjective nature of oil and natural gas reserve estimates, each of the following items may differ materially from the amounts or other factors estimated:

     The discounted future net revenues from our proved reserves included in this Report should not be considered as the market value of the reserves attributable to our properties. As required by generally accepted accounting principles, the estimated discounted future net revenues from our proved reserves are based generally on prices and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower.

     In addition, the 10 percent discount factor that is required to be used to calculate discounted future net revenues for reporting purposes under generally accepted accounting principles is not necessarily the most appropriate discount factor based on the cost of capital in effect from time to time and risks associated with our business and the oil and natural gas industry in general.

If we are unsuccessful in acquiring or finding additional reserves, our future oil and natural gas production would decline, thereby reducing our cash flows and results of operations and impairing our financial condition.

     The rate of production from oil and natural gas properties generally declines as reserves are depleted. Except to the extent we acquire additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, identify additional behind-pipe zones or secondary recovery reserves, our proved reserves will decline materially as oil and natural gas is produced.

Increases in crude oil prices and environmental regulations may reduce our refined product margins.

     The profitability of our refining, marketing and transportation operations depends largely on the margin between the cost of crude oil and other feedstocks we refine and the selling prices we obtain for refined products. We are a net purchaser of crude oil. A significant portion of our crude oil is purchased from various foreign national oil companies, producing companies and trading companies, including suppliers from the Middle East. These purchases are subject to political, geographic and economic risks attendant to doing business with suppliers located in that area of the world. Our overall RM&T profitability could be adversely affected by the availability of supply and rising crude oil and other feedstock prices which we do not recover in the marketplace. Refined product margins have been historically volatile and vary with the level of economic activity in the various marketing areas, the regulatory climate, logistical capabilities and the available supply of refined products.

     In addition, environmental regulations, particularly the 1990 amendments to the Clean Air Act, have imposed, and are expected to continue to impose, increasingly stringent and costly requirements on refining and marketing operations, which may reduce our refined product margins.

If we do not compete successfully with our competitors, our future operating performance and profitability could materially decline.

     We compete with major integrated and independent oil and natural gas companies for the acquisition of oil and natural gas leases and other properties. We compete with these companies, as well as national oil 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. In addition, in implementing our integrated gas strategy, we compete with major integrated energy companies in bidding for and developing liquefied natural gas projects, which are very capital intensive. Many of our competitors have financial and other resources substantially greater than those available to us. As a consequence, we may be at a competitive disadvantage in acquiring additional properties and bidding for and developing additional projects, such as LNG plants. Many of our larger competitors in the LNG market can complete more projects than we have the capacity to complete, which could lead those competitors to realize economies of scale that we are unable to realize. In addition, many of our larger competitors may be better able to respond to factors that affect the demand for oil and natural gas, such as changes in worldwide prices and levels of production, the cost and availability of alternative fuels and the application of government regulations.

We will continue to incur substantial capital expenditures and operating costs as a result of environmental laws and regulations, and, as a result, our profitability could be materially reduced.

     Our businesses are subject to numerous laws and regulations relating to the protection of the environment. We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, operating results will be adversely affected. The specific impact of these laws and regulations on each of our competitors may vary depending on a number of factors, including the age and location of their operating facilities, marketing area and production processes. We may also be required to make material expenditures or may become subject to liabilities that we currently do not anticipate in connection with new, amended or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination. In addition, any failure by us to comply with existing or future laws could result in civil or criminal fines and other enforcement action against us.

     Our operations and those of our predecessors could expose us to civil claims by third parties for alleged liability resulting from contamination of the environment or personal injuries caused by releases of hazardous substances.

     Environmental laws are subject to frequent change and many of them have become more stringent. In some cases, they can impose liability for the entire cost of cleanup 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.

Worldwide political and economic developments could damage our operations and materially reduce our profitability.

     Local political and economic factors in international markets could have a material adverse effect on us. Approximately 50 percent of our oil and natural gas production in 2005 was derived from production outside the United States and approximately 70 percent of our proved reserves as of December 31, 2005 were located outside the United States. In addition, we are increasing the focus of our development operations on areas outside the United States.

     There are many risks associated with operations in international markets, including changes in foreign governmental policies relating to crude oil, natural gas or refined product pricing and taxation, other political, economic or diplomatic developments and international monetary fluctuations. These risks include:

     Continued hostilities in the Middle East and the occurrence or threat of future terrorist attacks could cause a downturn in the economies of the United States and other developed countries. A lower level of economic activity could result in a decline in energy consumption, which could cause our revenues and margins to decline and limit our future growth prospects. More specifically, these risks could lead to increased volatility in prices for crude oil, natural gas and refined products. In addition, these risks could increase instability in the financial and insurance markets and make it more difficult for us to access capital and to obtain insurance coverages that we consider adequate.

     Actions of the United States government through tax and other legislation, executive order and commercial restrictions could reduce our operating profitability both in the United States and overseas. The United States government can prevent or restrict us from doing business in foreign countries. These restrictions and those of foreign governments have in the past limited our ability to operate in or gain access to opportunities in various countries. Actions by both the United States and host governments have affected operations significantly in the past and will continue to do so in the future.

Our operations are subject to business interruptions and casualty losses, and we do not insure against all potential losses and therefore we could be seriously harmed by unexpected liabilities.

     Our exploration and production operations are subject to unplanned occurrences, including blowouts, explosions, fires, loss of well control, spills, hurricanes and other adverse weather, labor disputes and maritime accidents. In addition, our refining, marketing and transportation operations are subject to business interruptions due to scheduled refinery turnarounds and unplanned events such as explosions, fires, pipeline interruptions, crude oil or refined product spills, inclement weather or labor disputes. They are also subject to the additional hazards of marine operations, such as capsizing, collision and damage or loss from severe weather conditions. We maintain insurance against many, but not all, potential losses or liabilities arising from these operating hazards in amounts that we believe to be prudent. Uninsured losses and liabilities arising from operating hazards could reduce the funds available to us for exploration, drilling and production and could materially reduce our profitability.

If Ashland fails to pay its taxes, we could be responsible for satisfying various tax obligations of Ashland.

     As a result of the transactions in which we acquired the minority interest in MPC from Ashland, Marathon is severally liable for federal income taxes (and in some cases for certain state taxes) for tax years of Ashland still open as of the date we completed the transactions. We have entered into a tax matters agreement with Ashland, which provides that:

If Ashland fails to pay any tax obligation for which we are severally liable, we may be required to satisfy this tax obligation. That would leave us in the position of having to seek indemnification from Ashland. In that event, our

indemnification claims against Ashland would constitute general unsecured claims, which would be effectively subordinate to the claims of secured creditors of Ashland, and we would be subject to collection risk associated with collecting unsecured debt from Ashland.

Marathon is required to pay Ashland for deductions relating to various contingent liabilities of Ashland, which could be material.

     We are required to claim tax deductions for certain contingent liabilities that will be paid by Ashland after completion of the transactions. Under the tax matters agreement, we are required to pay the benefit of those deductions to Ashland, with the computation and payment terms for such tax benefit payments divided into two “baskets,” as described below:

Basket One – This applies to the first $30 million of contingent liability deductions (increased by inflation each year up to a maximum of $60 million) that we may claim in each year for the first 20 years following the acquisition. The benefit of Basket One deductions is determined by multiplying the amount of the deduction by 32% (or, if different, by a percentage equal to three percentage points less than the highest federal income tax rate during the applicable tax year). We are obligated to pay this amount to Ashland. The computation and payment of Basket One amounts does not depend on our ability to generate actual tax savings from the use of the contingent liability deductions in Basket One. Upon specified events related to Ashland (or after 20 years), the contingent liability deductions that would otherwise have been compensated under Basket One will be taken into account in Basket Two. In addition, Basket One applies only for Federal income tax purposes; state, local or foreign tax benefits attributable to specified liability deductions will be compensated only under Basket Two.

     Because we are required to make payments to Ashland whether or not we generate any actual tax savings from the Basket One contingent liability deductions, the amount of our tax benefit payments to Ashland with respect to Basket One contingent liability deductions may exceed the aggregate tax benefits that we derive from these deductions. We are obligated to make these payments to Ashland even if we do not have sufficient taxable income to realize any benefit for the deductions.

Basket Two – All contingent liability deductions relating to Ashland’s pre-transactions operations that are not subject to Basket One are considered and compensated under Basket Two. The benefit of Basket Two deductions is determined on a “with and without” basis; that is, the contingent liability deductions are treated as the last deductions used by the Marathon group. Thus, if the Marathon group has deductions, tax credits or other tax benefits of its own, it will be deemed to use them to the maximum extent possible before it will be deemed to use the contingent liability deductions. To the extent that we have the capacity to use the contingent liability deductions based on this methodology, the actual amount of tax saved by the Marathon group through the use of the contingent liability deductions will be calculated and paid to Ashland. Because Basket Two amounts are calculated based on the actual tax saved by the Marathon group from the use of Basket Two deductions, those amounts are subject to recalculation in the event there is a change in the Marathon group’s tax liability for a particular year. This could occur because of audit adjustments or carrybacks of losses or credits from other years, for example. To the extent that such a recalculation results in a smaller Basket Two benefit with respect to a contingent liability deduction for which Ashland has already received compensation, Ashland is required to repay such compensation to Marathon. In the event we become entitled to any repayment, we would be subject to collection risks associated with collecting an unsecured claim from Ashland.

If the transactions resulting in our acquisition of the minority interest in MPC previously owned by Ashland were found to constitute a fraudulent transfer or conveyance, we could be required to provide additional consideration to Ashland or to return a portion of the interest in MPC, and either of those results could have a material adverse effect on us.

     In a bankruptcy case or lawsuit initiated by one or more creditors or a representative of creditors of Ashland, a court may review our recently completed transactions with Ashland under the fraudulent transfer provisions of the U.S. Bankruptcy Code and comparable provisions of state fraudulent transfer or conveyance laws. Under those laws, the transactions would be deemed fraudulent if the court determined that the transactions were undertaken for the purpose of hindering, delaying or defrauding creditors or that the transactions were constructively fraudulent. If the transactions were found to be a fraudulent transfer or conveyance, we might be required to provide additional consideration to Ashland or to return all or a portion of the interest in MPC and the other assets we acquired from Ashland.

     Under the U.S. Bankruptcy Code and the laws of most states, a transaction could be held to be constructively fraudulent if a court determined that:

     In connection with our recently completed transactions with Ashland, we delivered part of the overall consideration (specifically, shares of our common stock having a value of $915 million) to Ashland’s shareholders. In order to help establish that Ashland nevertheless received reasonably equivalent value or fair consideration from us in the transactions, we obtained a written opinion from a nationally recognized appraisal firm to the effect that Ashland received amounts that were reasonably equivalent to the combined value of Ashland’s interest in MPC and the other assets we acquired. We also obtained a favorable opinion from that appraisal firm relating to various financial tests that supported our conclusion and Ashland’s representation to us that Ashland was not insolvent either before or after giving effect to the closing of the transactions. Those opinions were based on specific information provided to it and were subject to various assumptions, including assumptions relating to Ashland’s existing and contingent liabilities and insurance coverages. Although we are confident in our conclusions regarding (1) Ashland’s receipt of reasonably equivalent value or fair consideration and (2) Ashland’s solvency, it should be noted that the valuation of any business and a determination of the solvency of any entity involve numerous assumptions and uncertainties, and it is possible that a court could disagree with our conclusions.

If United States Steel fails to perform any of its material obligations to which we have financial exposure, we could be required to pay those obligations, and any such payment could materially reduce our cash flows and profitability and impair our financial condition.

     In connection with the separation of United States Steel from Marathon, United States Steel agreed to hold Marathon harmless from and against various liabilities. While we cannot estimate some of these liabilities, the portion of these liabilities that we can estimate amounts to $597 million as of December 31, 2005, including accrued interest of $9 million. If United States Steel fails to satisfy any of those obligations, we would be required to satisfy them and seek indemnification from United States Steel. In that event, our indemnification claims against United States Steel would constitute general unsecured claims, effectively subordinate to the claims of secured creditors of United States Steel.

     Under applicable law and regulations, we also may be liable for any defaults by United States Steel in the performance of its obligations to pay federal income taxes, fund its ERISA pension plans and pay other obligations related to periods prior to the effective date of the separation.

     United States Steel has non-investment grade credit ratings and has granted security interests in some of its assets. The steel business is highly competitive and a large number of industry participants have sought protection under bankruptcy laws in the past. The enforceability of our claims against United States Steel could become subject to the effect of any bankruptcy, fraudulent conveyance or transfer or other law affecting creditors’ rights generally, or of general principles of equity, which might become applicable to those claims or other claims arising from the facts and circumstances in which the separation was effected.

If the transfer of ownership of various assets and operations by Marathon’s former parent entity to Marathon was held to be a fraudulent conveyance or transfer, United States Steel’s creditors may be able to obtain recovery from us or other relief detrimental to the holders of our common stock.

     In July 2001, USX Corporation (“Old USX”) effected a reorganization of the ownership of its businesses in which it created Marathon as its publicly owned parent holding company and transferred ownership of various assets and operations to Marathon, and it merged into a newly formed subsidiary which survived as United States Steel.

     If a court in a bankruptcy case regarding United States Steel or a lawsuit brought by its creditors or their representative were to find that, under the applicable fraudulent conveyance or transfer law:

then that court could determine those transactions entitled one or more classes of creditors of United States Steel to equitable relief from us. Such a determination could permit the unpaid creditors to obtain recovery from us or could result in other actions detrimental to the holders of our common stock. The measure of insolvency for purposes of these considerations would vary depending on the law of the jurisdiction being applied.

We may issue preferred stock whose terms could dilute the voting power or reduce the value of our common stock.

     Our restated certificate of incorporation authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such preferences, powers and relative, participating, optional and other rights, including preferences over our common stock respecting dividends and distributions, as our board of directors generally may determine. The terms of one or more classes or series of preferred stock could dilute the voting power or reduce the value of our common stock. For example, we could grant holders of preferred stock the right to elect some number of our directors in all events or on the happening of specified events or the right to veto specified transactions. Similarly, the repurchase or redemption rights or liquidation preferences we could assign to holders of preferred stock could affect the residual value of the common stock.

Item 1B. Unresolved Staff Comments

      As of the date of this filing, we have no unresolved comments from the staff of the Securities and Exchange Commission.

      The location and general character of the principal oil and gas properties, refineries and gas plants, pipeline systems and other important physical properties of Marathon have been described previously. Except for oil and gas producing properties, which generally are leased, or as otherwise stated, such properties are held in fee. The plants and facilities have been constructed or acquired over a period of years and vary in age and operating efficiency. At the date of acquisition of important properties, titles were examined and opinions of counsel obtained, but no title examination has been made specifically for the purpose of this document. The properties classified as owned in fee generally have been held for many years without any material unfavorably adjudicated claim.

     The basis for estimating oil and gas reserves is set forth in “Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities – Estimated Quantities of Proved Oil and Gas Reserves” on pages F-46 through F-47.

Property, Plant and Equipment Additions

      For property, plant and equipment additions, see “Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity – Capital Expenditures.”

      Marathon is the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. Certain of these matters are included below. The ultimate resolution of these contingencies could, individually or in the aggregate, be material. However, management believes that Marathon will remain a viable and competitive enterprise even though it is possible that these contingencies could be resolved unfavorably.

Natural Gas Royalty Litigation

      Marathon was served in two qui tam cases, which allege that federal and Indian lessees violated the False Claims Act with respect to the reporting and payment of royalties on natural gas and natural gas liquids. The first case, U.S. ex rel Jack J. Grynberg v. Alaska Pipeline Co., et al is primarily a gas measurement case and the second case, U.S. ex rel Harrold E. Wright v. Agip Petroleum Co. et al, is primarily a gas valuation case. These cases assert that false claims have been filed by lessees and that penalties, damages and interest total more than $25 billion. The Department of Justice has announced that it would intervene or has reserved judgment on whether to intervene against specified oil and gas companies and also announced that it would not intervene against certain other defendants including Marathon. In the Grynberg case, the parties have briefed and argued their motions

regarding whether the District Court should adopt the recommendations of the Magistrate which would dismiss Marathon and many other defendants on jurisdictional grounds. The Wright case is in the discovery phase. Marathon intends to continue to vigorously defend these cases.

Powder River Basin Litigation

      The U.S. Bureau of Land Management (“BLM”) completed multi-year reviews of potential environmental impacts from coal bed methane development on federal lands in the Powder River Basin, including those in Wyoming. The BLM signed a Record of Decision (“ROD”) on April 30, 2003 supporting increased coal bed methane development. Plaintiff environmental and other groups filed suit in May 2003 in federal court against the BLM to stop coal bed methane development on federal lands in the Powder River Basin until the BLM conducted additional environmental impact studies. Marathon intervened as a party in the ongoing litigation before the Wyoming Federal District Court.

     As these lawsuits to delay energy development in the Powder River Basin progress through the courts, the Wyoming BLM continues to process permits to drill under the ROD.

     In May 2004, plaintiff environmental groups Environmental Defense et al filed suit against the U.S. BLM in Montana Federal District Court, alleging the agency did not adequately consider air quality impacts of coal bed methane and oil and gas operations in the Powder River Basin in Montana and Wyoming when preparing its environmental impact statements. Plaintiffs request that the BLM be ordered to cease issuing leases and permits for energy development, until additional analysis of predicted air impacts is conducted. Marathon and its subsidiary Pennaco Energy, Inc. intervened in this litigation.

MTBE Litigation

      Marathon is a defendant along with many other refining companies in over 40 cases in 11 states alleging methyl tertiary-butyl ether (“MTBE”) contamination in groundwater. All of these cases have been consolidated in a multi-district litigation in the Southern District of New York for preliminary proceedings. The judge in this multi-district litigation ruled on April 20, 2005 that some form of market share liability would apply. Market share liability enables a plaintiff to sue manufacturers who represent a substantial share of a market for a particular product and shift the burden of identification of who actually made the product to the defendants, effectively forcing a defendant to show that it did not produce the MTBE which allegedly caused the damage. The judge further allowed cases to go forward in New York and 11 other states, based upon varying theories of collective liability, and predicted that a new theory of market share liability would be recognized in Connecticut, Indiana and Kansas. The plaintiffs generally are water providers or governmental authorities and they allege that refiners, manufacturers and sellers of gasoline containing MTBE are liable for manufacturing a defective product and that owners and operators of retail gasoline sites have allowed MTBE to be discharged into the groundwater. Several of these lawsuits allege contamination that is outside of Marathon’s marketing area. A few of the cases seek approval as class actions. Many of the cases seek punitive damages or treble damages under a variety of statutes and theories. Marathon stopped producing MTBE at its refineries in October 2002. The potential impact of these recent cases and future potential similar cases is uncertain. The Company will defend these cases vigorously.

Acquisition Litigation

      On April 8, 2005, Shiva Singh instituted a class action in the Supreme Court of the State of New York in New York County against Ashland, and the individual members of Ashland’s Board of Directors. The complaint also named Marathon, MPC and Credit Suisse First Boston LLC (“CSFB”) as defendants. The complaint stated that Mr. Singh held Ashland common stock and that the complaint was brought on behalf of Mr. Singh and others similarly situated. The action arose from the transaction proposed at that time in which Ashland would transfer its entire 38 percent interest in MPC as well as certain other businesses to Marathon. The complaint alleged breach of fiduciary duty as well as aiding and abetting breach of fiduciary duty and negligence against Ashland, its directors, Marathon and MPC. The complaint alleged breach of fiduciary duty and negligence as well as aiding and abetting breach of fiduciary duty and negligence against CSFB.

     On September 20, 2005, the federal judge entered an order dismissing certain of the plaintiff’s negligence claims against CSFB and the aiding and abetting claims against all defendants and directed the court clerk to “mark the case closed.” This case is not currently pending.

Product Contamination Litigation

      A lawsuit was filed in the United States District Court for the Southern District of West Virginia and alleges that Marathon’s Catlettsburg refinery sold defective gasoline to wholesalers and retailers, causing permanent damage to storage tanks, dispensers and related equipment, resulting in lost profits, business disruption, and

personal and real property damages. Plaintiffs seek class action status. In 2002, MPC conducted extensive cleaning operations at affected facilities but denies that any permanent damages resulted from the incident. MPC previously settled with many of the potential class members in this case and intends to vigorously defend this action.

Environmental Proceedings

      The following is a summary of proceedings involving Marathon that were pending or contemplated as of December 31, 2005 under federal and state environmental laws. Except as described herein, it is not possible to predict accurately the ultimate outcome of these matters; however, management’s belief set forth in the first paragraph under “Item 3. Legal Proceedings” above takes such matters into account.

     Claims under CERCLA and related state acts have been raised with respect to the cleanup of various waste disposal and other sites. CERCLA is intended to facilitate the cleanup of hazardous substances without regard to fault. Potentially responsible parties (“PRPs”) for each site include present and former owners and operators of, transporters to and generators of the substances at the site. Liability is strict and can be joint and several. Because of various factors including the difficulty of identifying the responsible parties for any particular site, the complexity of determining the relative liability among them, the uncertainty as to the most desirable remediation techniques and the amount of damages and cleanup costs and the time period during which such costs may be incurred, Marathon is unable to reasonably estimate its ultimate cost of compliance with CERCLA.

     Projections, provided in the following paragraphs, of spending for and/or timing of completion of specific projects are forward-looking statements. These forward-looking statements are based on certain assumptions including, but not limited to, the factors provided in the preceding paragraph. To the extent that these assumptions prove to be inaccurate, future spending for, or timing of completion of environmental projects may differ materially from those stated in the forward-looking statements.

     At December 31, 2005, Marathon had been identified as a PRP at a total of seven CERCLA waste sites. Based on currently available information, which is in many cases preliminary and incomplete, Marathon believes that its liability for cleanup and remediation costs in connection with six of these sites will be under $1 million per site, and most will be under $100,000. Marathon believes that its liability for cleanup and remediation costs in connection with the one remaining site will be under $3 million.

     In addition, there is one site where Marathon has received information requests or other indications that it may be a PRP under CERCLA but where sufficient information is not presently available to confirm the existence of liability.

     There are also 123 additional sites, excluding retail marketing outlets, related to Marathon where remediation is being sought under other environmental statutes, both federal and state, or where private parties are seeking remediation through discussions or litigation. Based on currently available information, which is in many cases preliminary and incomplete, Marathon believes that its liability for cleanup and remediation costs in connection with 29 of these sites will be under $100,000 per site, 51 sites have potential costs between $100,000 and $1 million per site and 18 sites may involve remediation costs between $1 million and $5 million per site. Nine sites have incurred remediation costs of more than $5 million per site and there are 16 sites with insufficient information to estimate future remediation costs.

     There is one site that involves a remediation program in cooperation with the Michigan Department of Environmental Quality (“MDEQ”) at a closed and dismantled refinery site located near Muskegon, Michigan. During the next five years, Marathon anticipates spending approximately $5 million at this site. Appropriate site characterization and risk-based assessments necessary for closure will be refined during 2006 and may change the estimated future expenditures for this site. The closure strategy being developed for this site and ongoing work at the site are subject to approval by the MDEQ. Expenditures in 2005 were approximately $540,000, with expenditures in 2006 expected to be $1 million.

     MPC has had a pending enforcement matter with the Illinois Environmental Protection Agency and the Illinois Attorney General’s Office since 2002 concerning its self-reporting of possible emission exceedences and permitting issues related to storage tanks at its Robinson, Illinois refinery. MPC anticipates more discussions with Illinois officials in 2006.

     In August of 2004, the West Virginia Department of Environmental Protection (“WVDEP”) submitted a draft consent order to MPC regarding its handling of alleged hazardous waste generated from tank cleanings in the State of West Virginia. The proposed order sought a civil penalty of $337,900. MPC resolved this matter in 2005 by entering an administrative order with WVDEP where no civil penalty was imposed but MPC agreed to pay $95,297 as an administrative settlement, a contribution to the State Department of Natural Resources for park remediation efforts unrelated to this matter and a reimbursement of WVDEP’s costs.

SEC Investigation Relating to Equatorial Guinea

      By letter dated July 15, 2004, the United States Securities and Exchange Commission (“SEC”) notified Marathon that it was conducting an inquiry into payments made to the government of Equatorial Guinea, or to officials and persons affiliated with officials of the government of Equatorial Guinea. This inquiry followed an investigation and public hearing conducted by the United States Senate Permanent Subcommittee on Investigations, which reviewed the transactions of various foreign governments, including that of Equatorial Guinea, with Riggs Bank. The investigation and hearing also reviewed the operations of U.S. oil companies, including Marathon, in Equatorial Guinea. There was no finding in the Subcommittee’s report that Marathon violated the U.S. Foreign Corrupt Practices Act or any other applicable laws or regulations. Marathon has been voluntarily producing documents requested by the SEC in that inquiry. On August 1, 2005, Marathon received a subpoena issued by the SEC pursuant to a formal order of investigation requiring the production of the documents that have already been produced or that are in the process of being identified and produced in response to the SEC’s prior requests, and requesting additional materials. Marathon has been and intends to continue cooperating with the SEC in this investigation.

      Not applicable.

PART II

      The principal market on which Marathon’s common stock is traded is the New York Stock Exchange. Marathon’s common stock is also traded on the Chicago Stock Exchange and the Pacific Exchange. Information concerning the high and low sales prices for the common stock as reported in the consolidated transaction reporting system and the frequency and amount of dividends paid during the last two years is set forth in “Selected Quarterly Financial Data (Unaudited)” on page F-42.

     As of January 31, 2006, there were 67,230 registered holders of Marathon common stock.

     The Board of Directors intends to declare and pay dividends on Marathon common stock based on the financial condition and results of operations of Marathon Oil Corporation, although it has no obligation under Delaware law or the Restated Certificate of Incorporation to do so. In determining its dividend policy with respect to Marathon common stock, the Board will rely on the consolidated financial statements of Marathon. Dividends on Marathon common stock are limited to legally available funds of Marathon.

     The following table provides information about purchases by Marathon and its affiliated purchaser during the quarter ended December 31, 2005 of equity securities that are registered by Marathon pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASES OF EQUITY SECURITIES

      See page F-52.

      Marathon is engaged in worldwide exploration and production of crude oil and natural gas; domestic refining, marketing and transportation of crude oil and petroleum products, primarily in the Midwest, the upper Great Plains and southeastern United States; and worldwide marketing and transportation of natural gas and products manufactured from natural gas, such as LNG and methanol. Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with Item 1. Business, Item 1A. Risk Factors, Item 6. Selected Financial Data and Item 8. Financial Statements and Supplementary Data.

     Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as “anticipates,” “believes,” “estimates,” “expects,” “targets,” “plans,” “projects,” “could,” “may,” “should,” “would” or similar words indicating that future outcomes are uncertain. In accordance with ”safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements.

     Unless specifically noted, amounts for MPC include the 38 percent interest held by Ashland prior to the Acquisition on June 30, 2005, and amounts for EGHoldings include the 25 percent interest held by GEPetrol, and the 8.5 percent interest held by Mitsui and the 6.5 percent interest held by Marubeni subsequent to July 25, 2005.

Overview

Exploration and Production

     Exploration and production segment revenues correlate closely with prevailing prices for the various qualities of crude oil and natural gas produced. The increase in our E&P segment revenues during 2005 tracked the increase in prices for these commodities. Higher prices for crude oil during 2005 reflected concerns about international supply and hurricane damage in the U.S. Gulf of Mexico. The average spot price during 2005 for West Texas Intermediate (“WTI”), a benchmark crude oil, was $56.70 per barrel, up from an average of $41.47 in 2004, and ended the year at $61.04. The average differential between WTI and Brent (an international benchmark crude oil) narrowed to $2.18 in 2005 from $3.20 in 2004. Our domestic crude production is on average heavier and higher in sulfur content than light sweet WTI. Heavier and higher sulfur crude oil (commonly referred to as sour crude) sells at a discount to light sweet crude oil. The majority of OPEC spare capacity and new production worldwide is medium sour or heavy sour, so the discount for medium and heavy sour crudes has increased relative to light sweet crude and thus reduced the relative profitability of sour crude production. Outside of Russia, our international crude production is relatively sweet and is generally sold in relation to the Brent crude benchmark.

     Natural gas prices were also higher in 2005 compared to 2004. A significant portion of our United States lower 48 natural gas production is sold at bid-week prices or first-of-month indices relative to our specific producing areas. Our natural gas prices in Alaska are largely contractual, while natural gas production there is seasonal in nature, trending down during the second and third quarters and increasing during the fourth and first quarters. Our other major natural gas-producing regions are Europe and Equatorial Guinea, where large portions of our natural gas are sold at contractual prices, making realized prices in these areas less volatile.

     For information on price risk management, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”

     E&P segment income during 2005 was up approximately 76 percent from 2004 levels, impacted by higher product prices as discussed above and increased liquid hydrocarbon sales volumes. We estimate that our 2006 production available for sale will average approximately 365,000 to 395,000 boe per day, excluding the impact of acquisitions and dispositions. This includes an estimated 40,000 to 45,000 boe per day as a result of our return to operations in the Waha concessions in Libya. With the developments we have under construction, we estimate our production will grow to 475,000 to 525,000 boe per day by 2008, excluding acquisitions and divestitures.

     Projected production levels for liquid hydrocarbons and natural gas are based on a number of assumptions, including (among others) 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 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 government or military response thereto, and other geological, operating and economic

considerations. These assumptions may prove to be inaccurate. Prices have historically been volatile and have frequently been driven by unpredictable changes in supply and demand resulting from fluctuations in economic activity and political developments in the world’s major oil and gas producing areas, including OPEC member countries. Any substantial decline in such prices could have a material adverse effect on our results of operations. A decline in such prices could also adversely affect the quantity of liquid hydrocarbons and natural gas that can be economically produced and the amount of capital available for exploration and development.

Refining, Marketing and Transportation

     We refine, market and transport crude oil and petroleum products, primarily in the Midwest, upper Great Plains and southeastern United States. RM&T segment income depends largely on our refining and wholesale marketing margin, refinery throughputs, retail marketing margins for gasoline, distillates and merchandise, and the profitability of our pipeline transportation operations.

     The refining and wholesale marketing margin is the difference between the wholesale prices of refined products sold and the cost of crude oil and other feedstocks refined, the cost of purchased products and manufacturing costs. We purchase crude oil to satisfy our refineries’ throughput requirements. As a result, our refining and wholesale marketing margin could be adversely affected by rising crude oil and other feedstock prices that are not recovered in the marketplace. The crack spread, which is generally a measure of the difference between spot market gasoline and distillate prices and spot market crude costs, is an industry indicator of refining margins. In addition to changes in the crack spread, our refining and wholesale marketing margin is impacted by the types of crude oil we process, the wholesale selling prices we realize for all the products we sell and our level of manufacturing costs. We process significant amounts of sour crude oil which enhances our competitive position in the industry as sour crude oil typically can be purchased at a discount to sweet crude oil. Over the last three years, approximately 60 percent of the crude oil throughput at our refineries has been sour crude oil. As the largest U.S. producer of asphalt, our refining and wholesale marketing margin is significantly impacted by the selling price of asphalt. Sales of asphalt increase during the highway construction season in our market area, which is typically in the second and third quarters. The selling price of asphalt is dependent on the cost of crude oil, the price of alternative paving materials and the level of construction activity in both the private and public sectors. Finally, our refining and wholesale marketing margin is impacted by changes in manufacturing costs from period to period, which are primarily driven by the level of maintenance activities at the refineries, and the price of purchased natural gas. Our refining and wholesale marketing margin has been historically volatile and varies with the level of economic activity in our various marketing areas, the regulatory climate, logistical capabilities and the expectations regarding the adequacy of the supply of refined products and raw materials.

     For information on price risk management, see “Item 7A. Quantitative and Qualitative Disclosures about Market Risk.”

     Our retail marketing margin for gasoline and distillates, which is the difference between the ultimate price paid by consumers and the wholesale cost of the refined products, including secondary transportation, also plays an important part in RM&T profitability. Factors affecting our retail gasoline and distillate margin include competition, seasonal demand fluctuations, the available wholesale supply, the level of economic activity in our marketing areas and weather situations that impact driving conditions. Gross margins on merchandise sold at retail outlets tend to be less volatile than the gross margin from the retail sale of gasoline and diesel fuel. Factors affecting the gross margin on retail merchandise sales include consumer demand for merchandise items, the impact of competition and the level of economic activity in our marketing areas.

     The profitability of our pipeline transportation operations is primarily dependent on the volumes shipped through the pipelines. The volume of crude oil that we transport is directly affected by the supply of, and refiner demand for, crude oil in the markets served directly by our crude oil pipelines. Key factors in this supply and demand balance are the production levels of crude oil by producers, the availability and cost of alternative modes of transportation, and refinery and transportation system maintenance levels. The throughput of the refined products that we transport is directly affected by the production levels of, and user demand for, refined products in the markets served by our refined product pipelines. In most of our markets, demand for gasoline peaks during the summer driving season, which extends from May through September, and declines during the fall and winter months. The seasonal pattern for distillates is the reverse of this, helping to level overall variability on an annual basis. As with crude oil, other transportation alternatives and system maintenance levels influence refined product movements.

Integrated Gas

     Our integrated gas strategy is to link stranded natural gas resources with areas where a supply gap is emerging due to declining production and growing demand. LNG, particularly in regard to our operations in Equatorial Guinea, is a key component of that integrated gas strategy. Our integrated gas operations include

marketing and transportation of natural gas and products manufactured from natural gas, such as LNG and methanol, primarily in the United States, Europe and West Africa. Also included in the financial results of the IG segment are the costs associated with ongoing development of certain integrated gas projects. The profitability of these operations depends largely on commodity prices, volume deliveries, margins on resale gas, and demand. Methanol spot pricing is volatile largely because global methanol demand is only 33 million tons and any major unplanned shutdown of or addition to production capacity can have a significant impact on the supply-demand balance.

2005 Operating Highlights

Critical Accounting Estimates

      The preparation of financial statements in accordance with generally accepted accounting principles requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from the estimates and assumptions used.

     Certain accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material.

Estimated Net Recoverable Quantities of Oil and Natural Gas

     We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved oil and natural gas reserves, both developed and undeveloped. The existence and the estimated amount of proved reserves affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depreciated, depleted or amortized into income and the presentation of supplemental information on oil and gas producing activities. Both the expected

future cash flows to be generated by oil and gas producing properties used in testing such properties for impairment and the expected future taxable income available to realize deferred tax assets also rely, in part, on estimates of net recoverable quantities of oil and natural gas.

     Proved reserves are the estimated quantities of oil and natural gas that geologic and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change. During 2005, net revisions of previous estimates increased total proved reserves by 58 million boe (five percent of the beginning-of-the-year reserves estimate). Positive revisions of 82 million boe were partially offset by 24 million boe in negative revisions.

     Our estimation of net recoverable quantities of oil and natural gas is a highly technical process performed by in-house teams of reservoir engineers and geoscience professionals. All estimates prepared by these teams are approved by members of our Corporate Reserves Group. Any revisions of proved reserves estimates in excess of 2.5 million boe on a total-field basis must be approved by the Director of Corporate Reserves, who reports to our Chief Financial Officer. The Corporate Reserves Group audits recent acquisitions of material fields and properties with problematic indicators such as excessively long lives, sudden changes in performance or changes in economic or operating conditions. In addition, third-party consultants are engaged to audit reserve estimates with the stated objective of reviewing the top 80 percent of our reserves over a three-year period. Third-party audits did not result in any significant changes to reserve estimates during 2005, 2004 and 2003.

     The reserves of the Alba field offshore Equatorial Guinea comprise approximately 39 percent of our total proved oil and natural gas reserves as of December 31, 2005. The reserves of the Waha concession in Libya that were acquired at the end of 2005 comprise approximately 13 percent of our total proved oil and natural gas reserves at that date. The next five largest oil and gas producing asset groups – the Alvheim development offshore Norway, the Brae Area Complex offshore the United Kingdom (“U.K.”), the Kenai field in Alaska, the Petronius development in the Gulf of Mexico and the East Kamennoye license in Russia – comprise a total of approximately 15 percent of our total proved oil and natural gas reserves.

     Depreciation and depletion of producing oil and natural gas properties is determined by the units-of-production method and could change with revisions to estimated proved developed reserves. The change in the depreciation and depletion rate over the past three years due to revisions of previous reserve estimates has not been significant. A five percent increase in the amount of oil and natural gas reserves would change the depreciation and depletion rate from $6.04 per barrel to $5.75 per barrel, which would increase pretax income by approximately $36 million annually, based on 2005 production. A five percent decrease in the amount of oil and natural gas reserves would change the depreciation and depletion rate from $6.04 per barrel to $6.36 per barrel and would result in a decrease in pretax income of approximately $40 million annually, based on 2005 production.

Fair Value Estimates

     We are required to develop estimates of fair value to allocate the purchase prices paid to acquire businesses to the assets acquired and liabilities assumed, to assess impairment of long-lived assets and goodwill and to record non-exchange traded derivative instruments. Other items which require estimates of fair value include asset retirement obligations, guarantee obligations and stock-based compensation.

     Under the purchase method of accounting, the purchase price paid to acquire a business is allocated to its assets and liabilities based on the estimated fair values of the assets acquired and liabilities assumed as of the date of acquisition. The excess of the purchase price over the fair value of the net tangible and identifiable intangible assets acquired is recorded as goodwill. The most difficult estimations of individual fair values are those involving property, plant and equipment and identifiable intangible assets. We use all available information to make these fair value determinations and, for certain acquisitions, engage third-party consultants for assistance. During 2005, we made two significant acquisitions with an aggregate purchase price of $3.153 billion that was allocated to the assets acquired and liabilities assumed based on their estimated fair values. See Note 5 to the consolidated financial statements for information on these acquisitions. As of December 31, 2005, we have recorded goodwill of $1.307 billion. Such goodwill is not amortized, but rather is tested for impairment annually, and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value.

     The fair values used to allocate the purchase prices of acquisitions and to test goodwill for impairment are often estimated using the expected present value of future cash flows method, which requires us to project related future revenues and expenses and apply an appropriate discount rate. The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain and unpredictable. Accordingly, actual results may differ from the projected results used to determine fair value.

     Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate that the carrying value of the assets may not be recoverable. For purposes of impairment evaluation, long-lived assets must be grouped at the lowest level for which independent cash flows can be identified, which generally is field-by-field for E&P assets, refinery and associated distribution system level or pipeline system level for refining and transportation assets, or site level for retail stores. If the sum of the undiscounted pretax cash flows is less than the carrying value of an asset group, the carrying value is written down to the estimated fair value.

     Estimating the expected future cash flows from our oil and gas producing asset groups requires assumptions about matters such as future oil and natural gas prices, estimated recoverable quantities of oil and natural gas, expected field performance and the political environment in the host country. An impairment of any of our large oil and gas producing properties could have a material impact on our consolidated financial condition and results of operations.

     We evaluate our unproved property investment for impairment based on time or geologic factors in addition to the use of an undiscounted future net cash flow approach. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage are also considered. The expected future cash flows from our RM&T assets require assumptions about matters such as future product prices, future crude oil and other feedstock costs, estimated remaining lives of the assets and future expenditures necessary to maintain the assets’ existing service potential.

     We did not have significant impairment charges during 2005 or 2003. During 2004, we recorded an impairment of $32 million related to unproved properties and $12 million related to producing properties primarily as a result of unsuccessful developmental drilling activity in Russia.

     We record all derivative instruments at fair value. We have two long-term contracts for the sale of natural gas in the U.K. which are accounted for as derivative instruments. These contracts expire in September 2009. These contracts were entered into in the early 1990s in support of our investments in the East Brae field and the SAGE pipeline. Contract prices are linked to a basket of energy and other indices. The contract price is reset annually in October based on the previous twelve-month changes in the basket of indices. Consequently, the prices under these contracts do not track forward natural gas prices. The fair value of these contracts is determined by applying the difference between the contract price and the U.K. forward natural gas strip price to the expected sales volumes for the next eighteen months under these contracts. Adjustments to the fair value of these contracts result in non-cash charges or credits to income from operations. The difference between the contract price and the U.K. forward natural gas strip price may fluctuate widely from time to time and may significantly affect income from operations. The non-cash losses related to changes in fair value recognized in income from operations were $386 million in 2005, $99 million in 2004, and $66 million in 2003. These effects are primarily due to the U.K. 18-month forward natural gas price curve strengthening 90 percent, 36 percent and 26 percent during 2005, 2004 and 2003, respectively.

Expected Future Taxable Income

     We must estimate our expected future taxable income to assess the realizability of our deferred income tax assets. As of December 31, 2005, we reported deferred tax assets of $1.782 billion, which represented gross assets of $2.409 billion net of valuation allowances of $627 million.

     Numerous assumptions are inherent in the estimation of future taxable income, including assumptions about matters that are dependent on future events, such as future operating conditions (particularly as related to prevailing oil and natural gas prices) and future financial conditions. The estimates and assumptions used in determining future taxable income are consistent with those used in our internal budgets, forecasts and strategic plans.

     In determining our overall estimated future taxable income for purposes of assessing the need for additional valuation allowances, we consider proved and risk-adjusted probable and possible reserves related to our existing producing properties, as well as estimated quantities of oil and natural gas related to undeveloped discoveries if, in our judgment, it is likely that development plans will be approved in the foreseeable future. In assessing the propriety of releasing an existing valuation allowance, we consider the preponderance of evidence concerning the realization of the impaired deferred tax asset.

     Additionally, we must consider any prudent and feasible tax planning strategies that might minimize the amount of deferred tax liabilities recognized or the amount of any valuation allowance recognized against deferred tax assets, if we can implement these strategies and if we expect to implement these strategies in the event the forecasted conditions actually occurred. The principal tax planning strategy available to us relates to the permanent reinvestment of the earnings of our foreign subsidiaries. Assumptions related to the permanent reinvestment of the earnings of our foreign subsidiaries are reconsidered quarterly to give effect to changes in our portfolio of producing properties and in our tax profile.

Pensions and Other Postretirement Benefit Obligations

     Accounting for pension and other postretirement benefit obligations involves numerous assumptions, the most significant of which relate to the following:

     We develop our demographics and utilize the work of third-party actuaries to assist in the measurement of these obligations. We have selected different discount rates for our funded U.S. pension plans and our unfunded U.S. retiree health plans due to the different projected liability durations of nine years and 13 years. In determining the assumed discount rates, our methods include a review of market yields on high-quality corporate debt and use of our third-party actuary’s discount rate modeling tool. This tool applies a yield curve to the projected benefit plan cash flows using a hypothetical Aa yield curve. The yield curve represents a series of annualized individual discount rates from 1.5 to 30 years. The bonds used are rated Aa or higher by a recognized rating agency and only non-callable bonds are included. Each issue is required to have at least $150 million par value outstanding. The top quartile bonds are selected within each maturity group to construct the yield curve.

     The asset rate of return assumption considers the asset mix of the plans (currently targeted at approximately 75 percent equity securities and 25 percent debt securities for the funded U.S. pension plans), past performance and other factors. Certain components of the asset mix are modeled with various assumptions regarding inflation, debt returns and stock yields. Our assumptions are compared to those of peer companies and to historical returns for reasonableness.

     Compensation increase assumptions are based on historical experience, anticipated future management actions and demographics of the benefit plans.

     Health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends.

     Note 23 to the consolidated financial statements includes detailed information for the three years ended December 31, 2005, on the components of pension and other postretirement benefit expense and the underlying assumptions.

     Of the assumptions used to measure the December 31, 2005 obligations and estimated 2006 net periodic benefit cost, the discount rate has the most significant effect on the periodic benefit costs reported for the plans. A ..25 percent decrease in the discount rates of 5.50 percent for our domestic pension plan and 5.75 percent for our domestic postretirement benefit plan would increase pension expense and other postretirement benefit plan expense by approximately $13 million and $3 million, respectively.

     In 2005, we decreased our retirement age assumption by two years and also increased our lump sum election rate from 90 percent to 96 percent based on changing trends in our experience. This change increased our benefit obligations by approximately $109 million.

Contingent Liabilities

     We accrue contingent liabilities for income and other tax deficiencies, environmental remediation, product liability claims and litigation claims when such contingencies are probable and estimable. Actual costs can differ from estimates for many reasons. For instance, the costs from settlement of claims and litigation can vary from estimates based on differing interpretations of laws, opinions on responsibility and assessments of the amount of damages. Similarly, liabilities for environmental remediation may vary because of changes in laws, regulations and their interpretation; the determination of additional information on the extent and nature of site contamination; and improvements in technology. Our in-house legal counsel regularly assesses these contingent liabilities. In certain circumstances, outside legal counsel is utilized.

     A liability is recorded for these types of contingencies if we determine the loss to be both probable and estimable. We generally record these losses as “Cost of revenues” or “Selling, general and administrative expenses” in the consolidated statements of income, except for tax contingencies, which are recorded as “Other taxes” or “Provision for income taxes.” For additional information on contingent liabilities, see “Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies.”

     An estimate as to the sensitivity to earnings if other assumptions had been used in recording these liabilities is not practical because of the number of contingencies that must be assessed, the number of underlying assumptions

and the wide range of reasonably possible outcomes, in terms of both the probability of loss and the estimates of such loss.

Management’s Discussion and Analysis of Income and Operations

      Revenues for each of the last three years are summarized in the following table:

     E&P segment revenues increased by $1.490 billion in 2005 from 2004 and by $119 million in 2004 from 2003. The 2005 increase was primarily due to higher worldwide liquid hydrocarbon and natural gas prices and international liquid hydrocarbon sales volumes partially offset by lower domestic natural gas and liquid hydrocarbon sales volumes. Derivative losses included in E&P segment revenues totaled $5 million in 2005, $169 million in 2004 and $110 million in 2003. Excluded from E&P segment revenues were losses of $386 million in 2005, $99 million in 2004 and $66 million in 2003 related to long-term natural gas sales contracts in the U.K. that are accounted for as derivative instruments. See “Item 7A. Quantitative and Qualitative Disclosures about Market Risk” on page 53. Matching buy/sell transactions decreased by $44 million in 2005 from 2004 and by $55 million in 2004 from 2003. The 2005 and 2004 decreases were primarily due to decreased crude oil buy/sell volumes, partially offset by higher domestic liquid hydrocarbon prices.

     RM&T segment revenues increased by $12.373 billion in 2005 from 2004 and by $9.116 billion in 2004 from 2003. The 2005 increase primarily reflected higher refined product and crude oil prices and increased refined product sales volumes, partially offset by decreased crude oil sales volumes. The 2004 increase primarily reflected higher refined product and crude oil prices and increased refined product and crude oil sales volumes. Matching buy/sell transactions increased by $3.438 billion in 2005 from 2004 and by $2.114 billion in 2004 from 2003. The 2005 and 2004 increases were primarily due to increased crude oil prices and volumes and higher refined product prices and volumes.

     IG segment revenues increased by $345 million in 2005 from 2004 and decreased by $509 million in 2004 from 2003. The increase in 2005 is a result of higher natural gas prices. The decrease in 2004 is due to a decrease in natural gas marketing activities, partially offset by higher natural gas prices. Derivative gains included in IG segment revenues totaled $13 million in 2005, compared to gains of $17 million in 2004 and $19 million in 2003.

     For additional information on segment results, see the discussion on income from operations on page 39.

     Income from equity method investments increased by $96 million in 2005 from 2004 and by $141 million in 2004 from 2003. The increase in 2005 is primarily due to higher income from Alba Plant, LLC as a result of higher LPG and condensate production volume and higher income from PTC as a result of higher distillate gross margins. The increase in 2004 resulted from a $124 million loss on the dissolution of MKM Partners L.P. recorded in 2003. Results for 2004 also include increased earnings of other equity method investments, primarily AMPCO.

     Cost of revenues increased by $7.107 billion in 2005 from 2004 and by $5.840 billion in 2004 from 2003. The increases are primarily in the RM&T segment and resulted from an increase in acquisition costs for crude oil, an increase in the cost of refined product purchases, an increase in the cost of other refinery charge and blend stocks and higher manufacturing expenses, primarily the result of higher purchased energy and depreciation.

     Purchases related to matching buy/sell transactions increased by $3.314 billion in 2005 from 2004 and $1.837 billion in 2004 from 2003, primarily in the RM&T segment. The increases in both years are primarily due to

increased crude oil prices. Differences between revenues from matching buy/sell transactions and purchases related to matching buy/sell transactions are primarily grade/quality and location differentials.

     Selling, general and administrative expenses increased by $133 million in 2005 from 2004 and by $105 million in 2004 from 2003. The increase in 2005 was primarily a result of increased stock-based compensation expense due to the increase in the stock price during the year as well as an increase in equity-based awards. This was partially offset by a decrease as a result of severance and pension plan curtailment charges and start-up costs related to EGHoldings in 2004. The increase in 2004 was primarily due to increased stock-based compensation and higher costs associated with business transformation and outsourcing. Our 2004 results were also impacted by the start-up costs discussed above and the increased cost of complying with governmental regulations.

     Other taxes increased by $144 million in 2005 from 2004 and increased $39 million in 2004 from 2003. The increase in 2005 is primarily a result of increased payments of mineral extraction tax and export duty in Russia due to higher sales volumes and crude oil prices.

     Net interest and other financial costs decreased by $16 million in 2005 from 2004 and by $25 million in 2004 from 2003. The decrease in 2005 is primarily a result of increased interest income on higher average cash balances and capitalized interest, partially offset by increased interest on potential tax deficiencies and higher foreign exchange losses. The decrease in 2004 is primarily due to an increase in interest income on higher cash balances. Included in net interest and other financing costs are foreign currency losses of $17 million, and gains of $9 million and $13 million for 2005, 2004 and 2003.

     Minority interest in income of MPC decreased by $148 million in 2005 from 2004 due to the acquisition of Ashland’s 38 percent interest in MPC on June 30, 2005.

     Provision for income taxes increased by $1.003 billion in 2005 from 2004 and by $143 million in 2004 from 2003, primarily due to $2.797 billion and $388 million increases in income from continuing operations before income taxes.

     The effective tax rate for 2005 was 36.2 percent compared to 36.6 percent for both 2004 and 2003. The following is an analysis of the effective tax rate for the periods presented:

     Discontinued operations in 2004 and 2003 primarily relates to our E&P operations in western Canada, which were sold in 2003 for a gain of $278 million, including a tax benefit of $8 million. Also, included in 2003 results is an $8 million adjustment to a tax liability due to United States Steel Corporation.

     Cumulative effect of changes in accounting principles in 2005 was an unfavorable effect of $19 million, net of taxes of $12 million, representing the adoption of Financial Accounting Standards Board Interpretation (“FIN”) No. 47, “Accounting for Conditional Asset Retirement Obligations – an interpretation of FASB Statement No. 143,” as of December 31, 2005. The cumulative effect of a change in accounting principle in 2003 was a favorable effect of $4 million, net of taxes of $4 million, representing the adoption of Statement of Financial Accounting Standards (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations.”

     Income from operations for each of the last three years is summarized in the following table:

Average Volumes, Selling Prices and Other Statistics

     Domestic E&P income increased by $491 million in 2005 from 2004 following a decrease of $82 million in 2004 from 2003. The increase in 2005 was primarily due to higher natural gas and liquid hydrocarbon prices partially offset by lower sales volumes. The lower volumes in 2005 resulted primarily from weather-related downtime in the Gulf of Mexico and natural declines in field production rates. The decrease in 2004 was due to lower liquid hydrocarbon and natural gas volumes primarily resulting from natural field declines, weather-related downtime in the Gulf of Mexico and the sale of the Yates field in late 2003, partially offset by higher liquid hydrocarbon and natural gas prices. Derivative losses totaled $5 million in 2005, compared to $118 million in 2004 and $91 million in 2003.

     Our cost of storm-related repairs as a result of 2005 hurricane activity in the Gulf of Mexico was not significant. Our Gulf of Mexico production has returned to pre-storm levels. In late September 2004, certain production platforms in the Gulf of Mexico were evacuated due to hurricane activity. All facilities were back on line by October 1, 2004 with the exception of the Petronius platform which came back on line in March 2005. As a result of the damage to the Petronius platform, we recorded expense of $11 million in 2004 representing repair costs incurred, partially offset by the net effects of the property damage insurance recoveries and the related retrospective insurance premiums. We recorded income of $53 million in 2005 and $34 million in 2004 for business interruption insurance recoveries.

     Our domestic average realized liquid hydrocarbons price excluding derivative activity was $45.41 per barrel (“bbl”) in 2005, compared to $32.76 per bbl in 2004 and $27.02 per bbl in 2003. Domestic average natural gas prices were $6.42 per thousand cubic feet (“mcf”) excluding derivative activity in 2005, compared with $4.89 per mcf in 2004 and $4.53 per mcf in 2003.

     Domestic net liquid hydrocarbon sales volumes decreased to 76 thousand barrels per day (“mbpd”) in 2005, down 6 percent from 2004 primarily as a result of storm-related downtime in the Gulf of Mexico and natural field declines in the Permian Basin. Domestic net natural gas sales volumes averaged 578 million cubic feet per day (“mmcfd”), down 8 percent from 2004, primarily as a result of lower production in the Permian Basin and Camden Hills in the Gulf of Mexico due to natural field declines and downtime associated with Hurricane Ivan. Domestic net liquid hydrocarbon sales volumes decreased 27 percent to 81 mbpd in 2004 from 2003 as a result of natural declines mainly in the Gulf of Mexico, hurricane damage to the Petronius platform and the sale of the Yates field in November 2003. Domestic net natural gas sales volumes decreased 14 percent to 631 mmcfd in 2004 from 2003 as a result of hurricane damage to the Petronius platform and natural declines in the Permian Basin and the Gulf of Mexico.

     International E&P income increased by $801 million in 2005 from 2004 and by $198 million in 2004 from 2003. The increase in 2005 was primarily the result of higher product prices and liquid hydrocarbon sales volumes, partially offset by higher production taxes in Russia, dry well expenses and lower natural gas sales volumes. The increase in 2004 was primarily due to higher liquid hydrocarbon and natural gas prices and volumes partially offset by higher derivative losses. Derivative losses totaled $386 million in 2005, compared to $51 million in 2004 and $19 million in 2003.

     Our international average realized liquid hydrocarbon price excluding derivative activity was $45.43 per bbl in 2005, compared with $33.68 per bbl in 2004 and $26.24 per bbl in 2003. International average gas prices were $4.28 per mcf excluding derivative activity in 2005, compared with $3.33 per mcf in 2004 and $2.80 per mcf in 2003.

     International net liquid hydrocarbon sales volumes increased to 115 mbpd in 2005, up 29 percent from 2004, as a result of increased production in Equatorial Guinea and Russia. International net natural gas sales volumes averaged 354 mmcfd in 2005, down 4 percent from 2004, primarily as a result of reduced U.K. spot gas sales. International net liquid hydrocarbon sales volumes increased 11 percent to 89 mbpd in 2004 from 2003 primarily due to increased production in Equatorial Guinea and a full year of production from Khanty Mansiysk Oil Corporation (“KMOC”) which was acquired in 2003. International net natural gas sales volumes averaged 368 mmcfd, up 1 percent from 2003 due to increased production from the condensate expansion project in Equatorial Guinea, offset by the disposition in 2003 of our interest in CLAM.

     RM&T segment income increased by $1.607 billion in 2005 from 2004 and by $587 million in 2004 from 2003. The increases were primarily due to higher refining and wholesale marketing margins. The refining and wholesale marketing margin in 2005 averaged 15.8 cents per gallon, versus a 2004 level of 8.8 cents and a 2003 level of 6.0 cents. Margins improved initially in 2005 due to wider sweet/sour crude differentials, and more recently, due to the temporary impact that Hurricanes Katrina and Rita had on refined product margins and concerns about the adequacy of distillate supplies heading into winter. Margins improved initially in 2004 due to the market’s concerns about refiners’ ability to supply the new Tier II low sulfur gasolines which were required effective January 1, 2004. We also benefited from wider sweet/sour crude differentials in 2004. We averaged 973,000 barrels of crude oil throughput per day in 2005, or 102 percent of average system capacity. We averaged 939,000 barrels of crude oil throughput per day in 2004 and 917,000 in 2003, representing 99 percent and 98 percent of average system capacity for those years.

     The portion of derivative losses included in the refining and wholesale marketing margin were $238 million in 2005 compared to $272 million in 2004 and $158 million in 2003. Generally, losses on derivatives included in the refining and wholesale marketing margin are offset by gains on the underlying physical transactions. These derivative losses were primarily incurred to mitigate the price risk of certain crude oil and other feedstock purchases, to protect carrying values of excess inventories and to protect crack spread values.

     IG segment income decreased by $17 million in 2005 from 2004, following an increase of $51 million in 2004 from 2003. The decrease in 2005 was primarily due to increased income taxes for AMPCO as a result of the expiration of a tax holiday. The increase in 2004 was primarily due to increased earnings from our investment in AMPCO and higher income from our Alaska LNG operations, partially offset by costs associated with ongoing development of certain integrated gas projects and lower margins from gas marketing activities, including recognized changes in the fair value of derivatives used to support those activities. Additionally, the 2003 results included an impairment charge of $22 million on an equity method investment and a loss of $17 million on the termination of two operating leases for tankers used in our Alaska LNG operations. The AMPCO methanol plant in Equatorial Guinea operated at a 98 percent on-stream factor in 2005 and a 95 percent on-stream factor in 2004, and posted index prices for methanol remained strong.

Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity

Financial Condition

     Both our acquisition of the minority interest in MPC and our re-entry to Libya discussed in Note 5 to the consolidated financial statements had a significant impact on our December 31, 2005 consolidated balance sheet. The MPC transaction closed June 30, 2005 and was accounted for under the purchase method of accounting. As a result, we established a new accounting basis for the tangible and identifiable intangible net assets of MPC to the extent of the 38 percent of MPC not previously owned by us, based on the estimated fair values of those net assets as of June 30, 2005. On December 29, 2005, we entered into an agreement with the National Oil Corporation of Libya to return to our oil and natural gas exploration and production operations in the Waha concessions in Libya. This transaction was also accounted for under the purchase method of accounting.

     Changes in the consolidated balance sheets from 2004 to 2005 were significantly impacted by the acquisitions noted above. For additional information on the effects of both of these transactions on our financial condition, see Note 5 to the consolidated financial statements. Other significant changes in the consolidated balance sheets are noted below.

     Net property, plant and equipment increased $3.201 billion from year-end 2004 due to the acquisitions noted above as well as the projects in Equatorial Guinea and the Alvheim development offshore Norway affecting International E&P, the Detroit refinery expansion affecting RM&T and the EG LNG plant affecting IG. Net property, plant and equipment for each of the last two years is summarized in the following table: