Back to GetFilings.com

Use these links to rapidly review the document
TABLE OF CONTENTS
TABLE OF CONTENTS 2

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, 2004

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:*

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 at least 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 (§229.405 of this chapter) 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. o

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

Aggregate market value of Common Stock held by non-affiliates as of June 30, 2004: $13 billion. The amount shown 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 under the Securities Act of 1933.

There were 347,013,291 shares of Marathon Oil Corporation Common Stock outstanding as of February 28, 2005.

Documents Incorporated By Reference:

Portions of the registrant's proxy statement relating to its 2005 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.

*

The Common Stock is listed on the New York Stock Exchange, the Chicago Stock Exchange and the Pacific Stock Exchange.

MARATHON OIL CORPORATION

        Unless the context otherwise indicates, references in this Form 10-K to "Marathon," "we," "our," or "us" are references to Marathon Oil Corporation, its wholly-owned and majority-owned subsidiaries, and its ownership interest in equity investees (corporate entities, partnerships, limited liability companies and other ventures, in which Marathon exerts significant influence by virtue of its ownership interest, typically between 20 and 50 percent).

TABLE OF CONTENTS

Disclosures Regarding Forward-Looking Statements

        This annual report on Form 10-K, particularly Item 1. and Item 2. Business and Properties, 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 "anticipates," "believes," "estimates," "expects," "forecasts," "plans," "predicts" or "projects" or variations of these words, suggesting 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 with respect to Marathon 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 or natural gas; the acquisition or divestiture of assets; the effect of restructuring or reorganization of business components; the potential effect of judicial proceedings on the 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. and 2. Business and Properties

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, Marathon disposed of its steel business through a tax-free distribution of the common stock of its 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, Marathon's certificate of incorporation was amended on December 31, 2001 and, from that date, Marathon has only one class of common stock authorized.

        Our principal operating subsidiaries are Marathon Oil Company and Marathon Ashland Petroleum LLC ("MAP"). Marathon Oil Company and its predecessors have been engaged in the oil and gas business since 1887. MAP is 62-percent owned by Marathon and 38-percent owned by Ashland Inc. ("Ashland").

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; 2) Refining, Marketing and Transportation ("RM&T") – refines, markets and transports crude oil and petroleum products; and 3) Integrated Gas ("IG") – markets and transports natural gas and products manufactured from natural gas, such as liquefied natural gas ("LNG") and methanol. For operating segment and geographic information, see Note 8 to the Consolidated Financial Statements on page F-19.

Exploration and Production

        We are currently conducting exploration, development and production activities in nine countries. Principal exploration activities are in the United States, Norway, Angola, Equatorial Guinea and Canada. Principal development and production activities are in the United States, the United Kingdom, Ireland, Norway, Equatorial Guinea, Gabon and Russia. We are also pursuing opportunities in north and west Africa and the Middle East.

2

        Our 2004 worldwide liquid hydrocarbon production averaged 170,000 barrels per day ("bpd"), a decrease of 12 percent from 2003 levels. Our 2004 worldwide sales of natural gas production, including gas acquired for injection and subsequent resale, averaged 999 million cubic feet per day ("mmcfd"), a decrease of 15 percent compared to 2003. In total, our 2004 worldwide production averaged 337,000 barrels of oil equivalent ("boe") per day, compared to 389,000 boe per day in 2003. (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 2005, our worldwide production is expected to average approximately 325,000 to 350,000 boe per day, excluding acquisitions and dispositions.

        The above projection of 2005 worldwide liquid hydrocarbon and natural gas production volumes is a forward-looking statement. Some factors that could potentially affect timing and levels of production include pricing, supply and demand for petroleum products, 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, future acquisitions or dispositions of producing properties, 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 statement.

Exploration

        In the United States during 2004, we drilled 35 gross (17 net) exploratory wells of which 22 gross (10 net) wells encountered hydrocarbons. Of these 22 wells, 3 gross (1 net) wells were temporarily suspended or are in the process of completing. Internationally, we drilled 21 gross (16 net) exploratory wells of which 13 gross (10 net) wells encountered hydrocarbons. Of these 13 wells, 13 gross (9 net) wells 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 2004, we had interests in 123 blocks in the Gulf of Mexico, including 94 in the deepwater area.

        During 2004, we announced that the Neptune 7 appraisal well on the Neptune Unit in the Gulf of Mexico encountered hydrocarbons. This discovery follows the Neptune 3 discovery in 2002 and the Neptune 5 discovery in 2003. Two successful appraisal sidetrack wells also were drilled from the original Neptune 5 location. Front end engineering and design for a Neptune development is currently underway. We hold a 30 percent interest in the Neptune Unit.

        Announced in 2003, the Perseus discovery is located on Viosca Knoll Block 830 in the Gulf of Mexico approximately five miles from the existing Petronius platform. The Perseus discovery was expected to begin production in 2004 via an extended-reach well drilled from the Petronius platform. Due to hurricane activity in September 2004 and the resulting damage to the Petronius platform, production from Perseus has been delayed until repairs of the Petronius platform can be completed. We hold a 50 percent interest in the Perseus discovery.

        In 2001 a successful discovery well was drilled on the Ozona prospect in the Gulf of Mexico and in 2002 two sidetrack wells were drilled, one of which was successful. We have established an integrated project team to formulate a development plan. We are currently negotiating commercial terms of a production handling agreement with a nearby operator. We are also in the process of reviewing seismic data to obtain a better understanding of the complex salt formations in the area and to optimize the location of the next well. We hold a 68 percent interest in the Ozona prospect.

        Other United States exploration activity during 2004 included three wells in the Cook Inlet area of Alaska, two of which were discoveries, and 11 wells in the Anadarko Basin in Oklahoma, nine of which were discoveries.

        Norway  –  During 2004 we announced the Hamsun discovery. The well is located on production license (PL) 150, which is approximately 136 miles from Stavanger, Norway, and approximately six miles south of the Alvheim area. The discovery well and three sidetracks encountered oil and gas. Results are being analyzed and development scenarios are being examined including a possible tie-back to the Alvheim development. We are the operator of PL150, owning a 65 percent interest. The Hamsun well builds on our successful 2003 Norwegian drilling program, which resulted in three discoveries, the Kneler and Boa discoveries in the Alvheim development and the Vilje (formerly known as Klegg) discovery. In December 2004 we acquired four new Norwegian exploration licenses, three of which we are designated as operator.

        Angola  –  Offshore Angola, we own a 10 percent interest in Block 31 and a 30 percent interest in Block 32. During 2004, we participated in the Venus-1 well, the fourth oil discovery on Block 31. The Venus well is located near the

3

Plutao, Saturno and Marte discoveries in the northeast portion of Block 31. These discoveries are the basis for a planned development of the northeast area of Block 31. Development options are currently being evaluated.

        During late 2004, we participated in a well on the Palas prospect in the southern portion of Block 31, and in early 2005, it was announced as a discovery. Also, at the end of 2004, operations were ongoing at the Ceres prospect, located in the central portion of Block 31.

        During 2004, we announced the Canela discovery on Block 32, located about 10 miles south of the 2003 Gindungo discovery. Also in 2004, wells on the Cola and Gengibre prospects, both on Block 32, reached total depth. The Cola well encountered hydrocarbons, but additional drilling will be required to determine commerciality. The results of the Gengibre well will be announced following government approval.

        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 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 reentry 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  –  In 2002, we announced a gas discovery at the Annapolis G-24 deepwater wildcat well approximately 215 miles south of Halifax, Nova Scotia in 5,504 feet of water. The G-24 encountered gas pay over several zones. The Crimson well, six miles southeast of the Annapolis discovery, was drilled in 2004 and was plugged and abandoned. We are the operator and own a 30 percent interest in the Annapolis lease. 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 48 percent of our 2004 worldwide liquid hydrocarbon production and 63 percent of our worldwide natural gas production was produced from U.S. operations.

        During 2004, our production in the Gulf of Mexico averaged 35,700 bpd of liquid hydrocarbons, representing 44 percent of our total U.S. liquid hydrocarbon production, and 100 mmcfd of natural gas, representing 16 percent of our total U.S. natural gas production. Liquid hydrocarbon production decreased by 17,800 net bpd and natural gas production decreased by 36 net mmcfd from the prior year. The decrease in production is mainly due to natural field declines and the effects of hurricane activity. Our Petronius platform suffered significant damage from Hurricane Ivan and was out of service part of September and the entire fourth quarter of 2004. Repair activity is underway, but production of liquid hydrocarbons of approximately 19,000 net bpd and natural gas of approximately 32 net mmcfd remains shut in. Production is not expected to come back on stream until the second quarter of 2005. At year-end 2004, we held interests in eight producing fields and 11 platforms in the Gulf of Mexico, of which seven platforms are operated by Marathon.

        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 quarter. In 2004 our Alaskan natural gas production averaged 174 net mmcfd, representing 28 percent of our total U.S. gas production. The increase from 2003 production of 166 net mmcfd is primarily due to a full year of production from the Ninilchik field. Production from the Ninilchik field began in 2003 and development continues on the field. Ninilchik 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 the Ninilchik Unit and own a 60 percent interest in it and the Kenai Kachemak Pipeline.

        Liquid hydrocarbon production from our Wyoming fields averaged 21,200 net bpd in 2004 compared to 21,400 net bpd in 2003. Gas production from our Wyoming fields averaged 108 net mmcfd in 2004 compared to 127 net mmcfd in 2003. The decrease in our Wyoming gas production is primarily attributed to lower production from the Powder River Basin, which averaged 69 net mmcfd in 2004 compared to 82 net mmcfd in 2003. This decrease is primarily attributed to natural field decline. Development of the Powder River Basin continued in 2004 with approximately 230 wells drilled, of which 145 are yet to be completed, compared to approximately 320 wells drilled in 2003. Additional development of our southwest Wyoming interests continued in 2004 where we participated in the drilling of 18 wells. Gas production from our Oklahoma fields averaged 82 net mmcfd in 2004 compared to 96 net mmcfd in 2003. This

4

decrease is primarily attributed to natural field decline. Our 2004 development program continued to focus in the Anadarko Basin where we participated in the drilling of 53 wells.

        Our share of liquid hydrocarbon production from the Permian Basin region, which extends from southeast New Mexico to west Texas averaged 18,900 bpd in 2004, compared to 30,200 bpd in 2003. This decrease is principally due to natural field decline and the sale of the Yates field in November 2003. Gas production from our New Mexico fields, primarily the Indian Basin field, averaged 85 net mmcfd in 2004 compared to 122 net mmcfd in 2003. The decrease in natural gas production is due to natural field decline. Gas production from our Texas fields, primarily located in East Texas, averaged 65 net mmcfd in 2004 compared to 73 net mmcfd in 2003. This decrease is mostly due to natural field decline. Active development of the Mimms Creek field in East Texas continued in 2004 with the drilling of 26 wells.

        United Kingdom  –  Our largest asset in the U.K. North Sea is the Brae area complex where we are the operator and own 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 production from the Brae area averaged 15,900 bpd of liquid hydrocarbons in 2004, compared with 17,500 bpd in 2003. The decrease primarily resulted from natural field decline. Our share of Brae gas sales averaged 197 mmcfd in 2004 compared with 198 mmcfd in 2003.

        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 22 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 gas capacity of approximately 1,000 mmcfd. The SAGE terminal at St. Fergus in northeast Scotland processes gas from the SAGE pipeline and 0.8 billion cubic feet ("bcf") per day of third party gas from the Britannia field.

        In the U.K. Atlantic Margin, we own an approximately 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 production from the Foinaven fields averaged 21,900 bpd of liquid hydrocarbons and 10 mmcfd of natural gas in 2004, compared to 22,400 net bpd and 10 mmcfd in 2003.

        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. Also during 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 Vilje PDO which was submitted to the Norwegian government in December 2004. Production from a combined Alvheim/Vilje development is expected to reach more than 50,000 net boe per day with first production starting in 2007.

        During 2004, production in Norway from the Heimdal, Vale and Byggve/Skirne fields averaged 2,000 net bpd and 27 net 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 Byggve/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. Natural gas sales were 58 mmcfd in 2004, compared with 62 mmcfd in 2003. We have agreed with the Seven Heads group to process and transport gas, as well as to provide field operating services, through our existing Kinsale Head facilities. Production from Seven Heads commenced in December 2003.

        We own an 18.5 percent interest in the Corrib gas development project, located approximately 40 miles off Ireland's west coast. During 2004, the An Bord Pleanála 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 gas from the

5

Corrib field. This decision represents a major step forward for the outside-operated Corrib gas project. Development work on the Corrib project has resumed and first gas production is expected in mid-year 2007.

        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 2004 liquid hydrocarbon production averaged 18,900 bpd and natural gas production averaged 76 mmcfd, compared to 12,400 bpd and 66 mmcfd in 2003. The condensate expansion project was completed during 2004 and began its production ramp up. This expansion project is expected to increase total liquids production from approximately 20,000 gross bpd to approximately 57,000 gross bpd (32,000 bpd net to Marathon). By the end of 2004 liquids production had increased to approximately 45,800 gross bpd. The liquefied petroleum gas ("LPG") expansion project progressed during 2004 and is expected to start-up in the second quarter of 2005. When completed, gross liquids production is expected to increase from approximately 57,000 gross bpd to 79,000 gross bpd (44,500 bpd net to Marathon).

        Approximately 125 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 project on Bioko Island is completed.

        Gabon  –  We are the operator of the Tchatamba South, Tchatamba West and Tchatamba Marin fields offshore Gabon with a 56 percent working interest. Production in Gabon averaged 13,600 net bpd of liquid hydrocarbons in 2004, compared with 14,700 net bpd in 2003. 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 a non-operated storage facility. During 2004, we extended our license in Gabon for 10 years which will now expire in 2018.

        Russia  –  During 2003 we acquired Khanty Mansiysk Oil Corporation ("KMOC"). KMOC's fields are located in the Khanty Mansiysk region of western Siberia. Production from these assets averaged 16,600 net bpd during 2004, primarily from the Potanay and East Kamennoye fields. Development activities continued in these fields in 2004, with 35 wells drilled in East Kamennoye and 17 wells drilled in Potanay. Additionally, one well was drilled in 2004 on the Paitykhskoye license.

        Libya  –  We own a 16.3 percent interest in the approximately 13 million acre Waha concession in Libya. In 1986, we ceased active participation in the concessions following the imposition of trade sanctions by the U.S. government. In 2004 the U.S. government lifted the sanctions, allowing us to advance plans to return to production operations. We continue to work with our partners, including the Libyan government, to finalize the terms of a reentry agreement.

        Gas-to-liquids  –  During 2004, Marathon and Syntroleum Corporation ("Syntroleum") successfully completed the construction and operation of a gas-to-liquids ("GTL") demonstration plant at the Port of Catoosa, Oklahoma. This GTL project was part of an ultra-clean fuels production and demonstration project sponsored by the U.S. Department of Energy's National Energy Technology Laboratory. The Catoosa plant, which mirrors a commercial scale plant, successfully demonstrated a fully integrated GTL technology that converted natural gas into a finished fuel, producing more than 5,500 barrels of synthetic products, including ultra-clean diesel fuel, which was delivered to Integrated Concepts Research Corporation, a project partner, for fleet vehicle testing in Washington, DC and Denali National Park, Alaska. The Catoosa GTL plant supports our ongoing efforts to explore the potential of GTL technology, and demonstrates how such technology could be incorporated into the design of a commercial GTL facility such as our proposed gas processing project in Qatar. Future research of GTL technology as well as other gas technologies is being conducted in our integrated gas segment.

        In connection with construction of the Catoosa GTL plant, we advanced Syntroleum $21.3 million under a secured promissory note. The note bears interest at a rate of eight percent per year and matures on June 30, 2006. If Syntroleum does not repay the note by June 30, 2006, we will have the right to convert the note into credits against future license fees or into Syntroleum common stock at no less than $6.00 per share and no more than $8.50 per share.

        The above discussion of the E&P segment includes forward-looking statements with respect to the timing of resumption of production from the Petronius platform and the timing and levels of production from the combined Alvheim/Vilje project, the Corrib project, the LPG expansion project and other expansion projects. Some factors which could affect the timing of the resumption of production from the Petronius platform include unforeseen problems arising from the repair work or further severe weather conditions. Some factors which could affect the timing and production levels of the Alvheim/Vilje project, the Corrib project, the LPG expansion project and other expansion projects 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, including Norwegian regulatory approval for the Vilje PDO, unforeseen problems arising from construction, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the

6

governmental or military response, and other geological, operating and economic considerations. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Reserves

        At December 31, 2004, our net proved liquid hydrocarbon and natural gas reserves totaled approximately 1.139 billion boe, of which 37 percent were located in the United States. The following table sets forth estimated quantities of net proved oil and gas reserves at the end of each of the last three years.

Estimated Quantities of Net Proved Oil and Gas Reserves at December 31

^(a)

Represents Marathon's equity interests in LLC JV Chernogorskoye ("Chernogorskoye"), MKM Partners L.P. ("MKM") and CLAM Petroleum B.V. ("CLAM"). Our interest in Chernogorskoye was sold in 2004. MKM was dissolved and the Yates interest was sold in 2003. Our interest in CLAM was sold in 2003.

^(b)

Represents Marathon's western Canadian assets, which were sold in 2003.

^(c)

Represents Marathon's equity interest in CLAM, which was sold in 2003.

        Proved developed reserves represented 62 percent of total proved reserves as of December 31, 2004, as compared to 70 percent as of December 31, 2003. Of the 430 million boe of proved undeveloped reserves at year-end 2004, only 22 percent have been included as proved reserves for more than two years while 56 percent were added during 2004.

7

        During 2004, we added net proved reserves of 221 million boe, excluding 2 million boe of dispositions, while producing 122 million boe. These net additions included extensions, discoveries and other additions of 136 million boe and total revisions of 81 million boe. Of the total net reserve additions, 25 million boe were proved developed and 194 million boe were proved undeveloped. Additionally, we transferred 78 million boe from proved undeveloped to proved developed during 2004. Costs incurred for the periods ended December 31, 2004, 2003 and 2002 relating to the development of proved undeveloped oil and gas reserves, were $708 million, $780 million and $404 million. These amounts include our proportionate share of equity investees' costs incurred as these were costs necessary for the development of proved undeveloped reserves. As of December 31, 2004, estimated future development costs relating to the development of proved undeveloped oil and gas reserves for the years 2005 through 2007 are projected to be $718 million, $629 million, and $105 million.

        The most significant extensions, discoveries and other additions in 2004 are related to the Alvheim/Vilje developments in Norway and the Corrib development in Ireland. Reserve additions for the Alvheim/Vilje developments totaled 63 million boe, or 46% of total extensions, discoveries and other additions. The PDO for the Alvheim development was approved by the Norwegian authorities during 2004 and approval of the Vilje PDO, which was submitted to the Norwegian government in December 2004, is expected in 2005. Production from the Alvheim/Vilje developments is expected to begin in 2007. Reserve additions for the Corrib development totaled 16 million boe, or 12% of total extensions, discoveries and other additions. With the planning permission received from the Irish authorities for the proposed natural gas terminal, which is to be built to bring gas from the Corrib field ashore, development activities are underway. First gas production is expected in 2007.

        The Alba field in Equatorial Guinea had the most significant positive revisions – 162 million boe. Of this volume, 84 million boe was added due to the final investment decision on the Equatorial Guinea LNG project, which will use the gas from the Alba field to produce LNG. Startup of the LNG plant is expected in 2007. An additional 66 million boe is related to additional compression that is expected to be installed in 2010 and will be necessary for the LNG plant to meet its requirements. At the end of 2004, our total proved reserves associated with the Alba field offshore Equatorial Guinea totaled 471 million boe, or 41 percent of our total proved reserves.

        We had negative revisions of 51 million boe in Russia and 40 million boe in the Powder River Basin due to disappointing results from development activity. These revisions, combined with extensions, discoveries and other additions and a small disposition, resulted in total net reductions in reserves of 46 million boe for Russia and 35 million boe for the Powder River Basin.

        The above estimated quantities of reserves, estimated future development costs relating to the development of proved undeveloped oil and gas reserves, timing of production from development projects and timing of the LNG plant activities are forward-looking statements, are based on a number of assumptions, including (among others) prices, presently known physical data concerning size and character of the reservoirs, economic recoverability, production experience and other operating considerations. To the extent these assumptions prove inaccurate, actual recoveries could be different than current estimates. With respect to additional factors that may affect the Alvheim/Vilje developments, the Corrib development and the LNG plant, please refer to page 6.

        For additional details of estimated quantities of net proved oil and gas reserves at the end of each of the last three years, see "Consolidated Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities – Estimated Quantities of Proved Oil and Gas Reserves" on pages F-45 through F-46. We filed reports with the U.S. Department of Energy ("DOE") for the years 2003 and 2002 disclosing the year-end estimated oil and gas reserves. We will file a similar report for 2004. 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.

Delivery Commitments

        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 the local utility companies, which obligate us to supply approximately 181 bcf of natural gas over the remaining life of these contracts, which terminate in 2012 and 2016. 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 110 bcf through the remaining life of the contract, which terminates March 31, 2009. These commitments are structured with variable-pricing terms. Our production from various gas fields in the Cook Inlet supply the natural gas to service these contracts. Our proved reserves and estimated production rates in the Cook Inlet sufficiently meet these contractual obligations.

8

        In the U.K., we have two long-term sales contracts with utility companies, which obligate us to supply approximately 210 bcf of natural gas through the remaining life of these contracts, which terminate in September 2009. Our Brae area production, together with natural gas acquired for injection and subsequent resale, will supply the natural gas to service these contracts. Our Brae area proved reserves, acquired natural gas contracts and estimated production rates sufficiently meet these contractual obligations. Pricing under these gas sales contracts is variable.

Oil and Natural Gas Production

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

Net Liquid Hydrocarbons Production^(a)(b)

Net Natural Gas Production^(b)(g)

^(a)

Includes crude oil, condensate and natural gas liquids.

^(b)

Amounts represent production after royalties, excluding the U.K., Ireland and the Netherlands where amounts shown are before royalties.

^(c)

Amounts represent production from leasehold ownership, after royalties and interests of others.

^(d)

Amounts represent equity tanker liftings and direct deliveries of liquid hydrocarbons. The amounts correspond with the basis for fiscal settlements with governments. Crude oil purchases, if any, from host governments are excluded.

^(e)

Represents Marathon's equity interests in Chernogorskoye, MKM and CLAM.

^(f)

Amounts represent Marathon's western Canadian operations, which were sold in 2003.

^(g)

Amounts exclude volumes purchased from third parties for injection and subsequent resale of 19 mmcfd in 2004, 23 mmcfd in 2003 and 4 mmcfd in 2002.

^(h)

Represents Marathon's equity interests in CLAM.

9

Productive and Drilling Wells

        The following tables set forth productive wells and service wells for each of the last three years and drilling wells as of December 31, 2004.

Gross and Net Wells

^(a)

Includes active wells and wells temporarily shut-in. Of the gross productive wells, gross wells with multiple completions operated by Marathon totaled 273 in 2004, 273 in 2003, and 357 in 2002. Information on wells with multiple completions operated by other companies is unavailable to Marathon.

^(b)

Consist of injection, water supply and disposal wells.

^(c)

Consists of exploratory and development wells.

^(d)

Represents Chernogorskoye in 2003, and MKM and CLAM in 2002.

10

Drilling Activity

        The following table sets forth, by geographic area, the number of net productive and dry development and exploratory wells completed in each of the last three years (references to "net" wells or production indicate our ownership interest or share, as the context requires):

Net Productive and Dry Wells Completed^(a)

^(a)

Includes the number of wells completed during the applicable year regardless of the year in which drilling was initiated. Excludes any wells where drilling operations were continuing or were temporarily suspended as of the end of the applicable year. A dry well is a well found to be incapable of producing hydrocarbons in sufficient quantities to justify completion. A productive well is an exploratory or development well that is not a dry well.

^(b)

Includes Marathon's equity interest in MKM in 2003 and 2002.

^(c)

Indicates wells drilled in the proved area of an oil or gas reservoir.

^(d)

Includes Marathon's equity interests in Chernogorskoye in 2004 and 2003 and CLAM in 2003 and 2002.

Oil and Gas Acreage

        The following table sets forth, by geographic area, the developed and undeveloped oil and gas acreage that we held as of December 31, 2004:

Gross and Net Acreage

11

Refining, Marketing and Transportation

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

Refining

        MAP owns and operates seven refineries with an aggregate refining capacity of 948,000 barrels of crude oil per day. The table below sets forth the location and daily throughput capacity of each of MAP's refineries as of December 31, 2004:

        MAP's 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 gasoline. MAP's 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; gas oil may be moved from Robinson to Detroit where excess fluid catalytic cracking unit capacity is available; and light cycle oil may be moved from Texas City to Robinson where excess desulfurization capacity is available.

        MAP also produces asphalt cements, polymerized asphalt, asphalt emulsions and industrial asphalts. MAP manufactures petroleum pitch, primarily used in the graphite electrode, clay target and refractory industries. Additionally, MAP manufactures aromatics, aliphatic hydrocarbons, cumene, base lube oil, polymer grade propylene and slack wax.

        During 2004, MAP's refineries processed 939,000 bpd of crude oil and 171,000 bpd of other charge and blend stocks. The following table sets forth MAP's 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. MAP completed major turnarounds at its Garyville, Catlettsburg and Canton refineries during 2004.

        MAP increased its overall crude oil refining capacity during 2004 from 935,000 bpd to 948,000 bpd after completing the planned turnaround and expansion project at the Garyville refinery. This expansion increased crude oil capacity at Garyville from 232,000 bpd to 245,000 bpd.

12

        The Catlettsburg refinery multi-year improvement project was completed during early 2004. At a cost of approximately $440 million, the project improves product yields and lowers overall refinery costs while making gasoline with less than 30 parts per million of sulfur, which allows MAP to meet Tier II gasoline regulations which became effective on January 1, 2004.

        MAP is constructing approximately $300 million in new capital projects for its 74,000 bpd Detroit, Michigan refinery. One of the projects, a $110 million expansion project, is expected to raise the crude oil capacity at the refinery by 35 percent to 100,000 bpd. Other projects are expected to enable the refinery to produce new clean fuels and further control regulated air emissions. Completion of the projects is scheduled for the fourth quarter of 2005.

Marketing

        In 2004 MAP's refined product sales volumes (excluding matching buy/sell transactions) totaled 20.4 billion gallons (1,329,000 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 70 percent of MAP's refined product sales volumes in 2004, excluding sales related to matching buy/sell transactions. Approximately 52 percent of MAP's gasoline sales volumes and 92 percent of its distillate sales volumes were sold on a wholesale or spot market basis to independent unbranded customers or other wholesalers in 2004.

        Approximately 55 percent of MAP's propane is sold into the home heating markets and industrial consumers purchase the balance. Propylene, cumene, aromatics, aliphatics, and sulfur are marketed to customers in the chemical industry. Base lube oils and slack wax are sold throughout the United States. Pitch is also sold domestically, but approximately 16 percent of pitch products are exported into growing markets in Canada, Mexico, India and South America.

        MAP markets asphalt through owned and leased terminals throughout the Midwest, the upper Great Plains and the Southeast. The MAP customer base includes approximately 800 asphalt-paving contractors, government entities (states, counties, cities and townships) and asphalt roofing shingle manufacturers.

        The following table sets forth the volume of MAP's consolidated refined product sales by product group for each of the last three years:

Refined Product Sales

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

        As of December 31, 2004, MAP supplied petroleum products to about 3,900 Marathon and Ashland branded retail outlets located primarily in Michigan, Ohio, Indiana, Kentucky and Illinois. Branded retail outlets are also located in Florida, Georgia, Wisconsin, West Virginia, Tennessee, Minnesota, Virginia, Pennsylvania, North Carolina, Alabama, and South Carolina.

        SSA sells gasoline and diesel fuel through company-operated retail outlets. As of December 31, 2004, SSA had 1,669 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 $2.3 billion in 2004, compared with $2.2 billion in 2003. 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.

        Pilot Travel Centers LLC ("PTC"), a joint venture with Pilot Corporation ("Pilot"), is the largest operator of travel centers in the United States with approximately 250 locations in 35 states at December 31, 2004. The travel centers

13

offer diesel fuel, gasoline and a variety of other services, including on-premises brand name restaurants. Pilot and MAP each own a 50 percent interest in PTC.

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

Supply and Transportation

        MAP obtains the crude oil it processes from negotiated contracts and spot purchases or exchanges. In 2004, MAP's net purchases of U.S. produced crude oil for refinery input averaged 416,000 bpd, including a net 20,000 bpd from Marathon. In 2004, Canada was the source for 14 percent or 130,000 bpd of crude oil processed and other foreign sources supplied 42 percent or 393,000 bpd of the crude oil processed by MAP's refineries, including approximately 245,000 bpd from the Middle East. This crude was acquired from various foreign national oil companies, producing companies and traders.

        MAP operates a system of pipelines and terminals to provide crude oil to its refineries and refined products to its marketing areas. At December 31, 2004, MAP owned, leased, or had an ownership interest in approximately 2,860 miles of crude oil trunk lines and 3,850 miles of product trunk lines. At December 31, 2004 MAP had interests in the following pipelines:

•

100 percent ownership of Ohio River Pipe Line LLC, which owns the Cardinal Products Pipeline, a refined products pipeline extending from Kenova, West Virginia to Columbus, Ohio;



•

50 percent interest in Centennial Pipeline LLC, which owns a system connecting Gulf Coast refineries with the Midwest market;



•

47 percent interest in LOOP LLC ("LOOP"), which is the owner and operator of the only U.S. deepwater oil port, located 18 miles off the coast of Louisiana;



•

50 percent interest in LOCAP LLC, which owns a crude oil pipeline connecting LOOP and the Capline system;



•

37 percent interest in the Capline system, a large diameter crude oil pipeline extending from St. James, Louisiana to Patoka, Illinois; and



•

33 percent interest in Minnesota Pipe Line Company, which owns a crude oil pipeline extending from Clearbrook, Minnesota to Cottage Grove, Minnesota, which is in the vicinity of MAP's St. Paul Park, Minnesota refinery.

        MAP's 84 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. MAP's marine transportation operations include towboats and barges that transport refined products on the Ohio, Mississippi and Illinois rivers, their tributaries and the Intercoastal Waterway. MAP also leases and owns rail cars in various sizes and capacities for movement and storage of petroleum products and a large number of tractors, tank trailers and general service trucks.

        Marathon also has interests in two refined product pipelines which are not part of MAP:

•

17 percent interest in Explorer Pipeline Company, which is a light-product pipeline system extending from the Gulf of Mexico to the Midwest; and



•

6 percent interest in Wolverine Pipe Line Company, a light-product pipeline system extending from Chicago, Illinois to Toledo, Ohio.

        The above discussion of the RM&T segment includes forward-looking statements concerning anticipated completion of the Detroit refinery capital projects. Some factors that could affect the Detroit projects include unforeseen problems arising from construction, regulatory approval constraints, 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.

14

Integrated Gas

        Our integrated gas operations include natural gas liquefication and regasification operations, methanol operations, certain other gas processing facilities and pipeline operations, and marketing and transportation of natural gas. Also included are the costs associated with ongoing development of certain integrated gas projects.

Methanol

        We own a 45 percent interest in 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 980,000 gross metric tons (441,000 net metric tons) in 2004. Production from the plant is used to supply customers in Europe and the U.S.

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.

        We own a 24 percent interest in Nautilus Pipeline Company, LLC and a 24 percent interest in Manta Ray Offshore Gathering Company, LLC, which are both Gulf of Mexico natural gas pipeline systems. Additionally, we 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.

Alaska LNG

        We own a 30 percent interest in a Kenai, Alaska, natural gas liquefication 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. LNG deliveries totaled 62 gross bcf (24 net bcf) in 2004.

Equatorial Guinea LNG Project

        During 2004, Marathon and its 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 deliver a contracted offtake of 3.4 million metric tons per year (approximately 460 mmcfd). This project will allow us to monetize our gas reserves from the Alba field, as natural gas for the plant will be purchased from the Alba field participants under a long-term gas supply agreement. Construction of the plant continues to progress and startup is projected for late 2007.

        At the end of 2004, we held a 75 percent economic interest in EGHoldings, with GEPetrol holding the remaining 25 percent economic interest. In connection with the formation of EGHoldings, GEPetrol was given certain contractual rights with respect to the purchase and resale to a third party of a 13 percent interest in EGHoldings currently held by Marathon. These rights give GEPetrol the option to purchase this 13 percent interest and resell it to a third party. These rights specify that we will be reimbursed for our historical costs plus an additional specified rate of return, which escalates depending on the time period during which such purchase and resale occurs, and a right to share in additional proceeds above those amounts under certain circumstances of resale. If GEPetrol's rights are not exercised within one year from date of project sanction, which was in June 2004, the rights expire.

        EGHoldings has signed a Sales and Purchase Agreement with a subsidiary of BG Group plc ("BGML") under which BGML would 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 would be targeted primarily to a receiving terminal in Lake Charles, Louisiana, where it would be regasified and delivered into the Gulf Coast natural gas pipeline grid.

Elba Island LNG

        During 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, for up to 22 years.

        Also during 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 beginning in the second half of 2005. We will

15

take 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 gas resources beyond the term of the BP contract. We continue to actively seek additional cargoes prior to the start of deliveries from BP.

        The above discussion of the integrated gas segment contains forward looking statements with respect to the estimated construction and startup dates of a LNG liquefaction plant and related facilities. Factors that could affect the estimated construction and startup dates of the LNG plant and related facilities include, without limitation, 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. 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 gas leases and other properties, 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 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 eighth among U.S.-based petroleum companies on the basis of 2003 worldwide liquid hydrocarbon and natural gas production.

        Marathon through MAP 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. MAP believes it ranks fifth among U.S. petroleum companies on the basis of crude oil refining capacity as of December 31, 2004. MAP competes in four distinct markets – wholesale, spot, branded and retail distribution – for the sale of refined products and believes it competes with about 40 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; 8 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™. 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 ("Reorganization Agreement"), Marathon completed the Separation, in which:

•

its wholly-owned subsidiary United States Steel LLC converted into a Delaware corporation named United States Steel Corporation and became a separate, publicly traded company; and



•

USX Corporation changed its name to Marathon Oil Corporation.

        As a result of the Separation, Marathon and United States Steel are separate companies, and neither has any ownership interest in the other. Thomas J. Usher is the non-executive chairman of the board of both companies, and, as of December 31, 2004, four of the ten remaining members of Marathon's board of directors are also directors of United States Steel.

16

        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:

•

obligations under industrial revenue bonds related to environmental projects for current and former U.S. Steel Group facilities, with maturities ranging from 2009 through 2033;



•

sale-leaseback financing obligations under a lease for equipment at United States Steel's Fairfield Works facility, with the lease term extending to 2012, subject to extensions;



•

obligations relating to various lease arrangements accounted for as operating leases and various guarantee arrangements, all of which were assumed by United States Steel; and



•

certain other guarantees.

        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. $2 million of the industrial revenue bonds are scheduled to mature in the period extending through December 31, 2009.

        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:

•

for any taxable period, or any portion of any taxable period, ended on or before December 31, 2001, unpaid tax sharing payments will be made between Marathon and United States Steel generally in accordance with the general tax sharing principles in effect before the Separation;

17

•

no tax sharing payments will be made with respect to taxable periods, or portions thereof, beginning after December 31, 2001; and



•

provisions relating to the tax and related liabilities, if any, that result from the Separation ceasing to qualify as a tax-free transaction and limitations on post-Separation activities that might jeopardize the tax-free status of the Separation.

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

•

the taxes payable by each of the Marathon Group and the U.S. Steel Group were determined as if each of them had filed its own consolidated, combined or unitary tax return; and



•

the U.S. Steel Group would receive the benefit, in the form of tax sharing payments by the parent corporation, of the tax attributes, consisting principally of net operating losses and various credits, that its business generated and the parent used on a consolidated basis to reduce its taxes otherwise payable.

        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:

•

would not, before January 1, 2004, take various actions or enter into various transactions that might, under section 355 of the Internal Revenue Code of 1986, jeopardize the tax-free status of the Separation; and



•

would be responsible for, and indemnify and hold the other party harmless from and against, any tax and related liability, such as interest and penalties, that results from the Separation ceasing to qualify as tax-free because of its taking of any such action or entering into any such transaction.

        The prescribed actions and transactions include:

•

the liquidation of Marathon or United States Steel; and



•

the sale by Marathon or United States Steel of its assets, except in the ordinary course of business.

        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.

18

Obligations Associated with the Separation as of December 31, 2004

        See "Management's Discussion and Analysis of Financial Condition and Results of Operations – Obligations Associated with the Separation of United States Steel" on page 42 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 Health, Environment and Safety organization has the responsibility to ensure that our operating organizations maintain environmental compliance systems that are in accordance with applicable laws and regulations. The Health, Environment and Safety Management Committee, which is comprised of our officers, is charged with reviewing its overall performance with various environmental compliance programs. We also have an Emergency Management Team, composed 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. These laws and their associated regulations 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 Marathon for the conduct of others or conditions others have caused, or for Marathon's 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" on page 44 and "Legal Proceedings" on page 21.

Air

        Of particular significance to MAP are EPA regulations that require reduced sulfur levels starting in 2004 for gasoline and 2006 for diesel fuel. MAP's 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, 2004 were approximately $520 million. Some factors that could potentially affect MAP's gasoline and diesel fuel compliance costs include completion of project detailed engineering, construction and startup activities.

        The U.S. 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, 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 EPA has proposed a rule called the Interstate Air Quality Rule ("IAQR") that will require significant reductions of SO₂ and NOx emissions in numerous states. All of our refinery operations are located in these affected states. If this rule is finalized, it could have a significant impact on our operations as well as the operations of many of our competitors. At this time, we cannot determine whether the IAQR will be finalized or whether it will be substantially changed before it is final. As a result, we cannot presently reasonably estimate the financial impact of such a rule.

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

19

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, 2004, all of the barges used in MAP's river transportation operations 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. Since the EPA has not yet promulgated implementing regulations for all provisions of RCRA and has not yet made clear the practical application of all the implementing regulations it has promulgated, the ultimate cost of compliance with this statute cannot be accurately estimated. In addition, 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.

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 fund once the applicable deductible has 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.

        As a general rule, Marathon and Ashland retained responsibility for certain remediation costs arising out of the prior ownership and operation of businesses transferred to MAP. Such continuing responsibility, in certain situations, may be subject to threshold or sunset agreements, which gradually diminish this responsibility over time.

Properties

        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 "Consolidated Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities – Estimated Quantities of Proved Oil and Gas Reserves" on pages F-45 through F-46.

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" on page 39.

20

Employees

        We had 25,804 active employees as of December 31, 2004, including 22,661 MAP employees. Of the total number of MAP employees, 16,413 were employees of Speedway SuperAmerica LLC, most of which were employed at retail marketing outlets.

        Certain hourly employees at the Catlettsburg and Canton refineries are represented by the Paper, Allied-Industrial, Chemical and Energy Workers International Union under labor agreements that expire on January 31, 2006. The same union represents certain hourly employees at the Texas City refinery under a labor agreement that expires on March 31, 2006. The International Brotherhood of Teamsters represents certain hourly employees under labor agreements that are scheduled to expire on May 31, 2006 at the St. Paul Park refinery and January 31, 2007 at the 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 Form 10-K or other securities filings.

Item 3. Legal Proceedings

        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 in this discussion. 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. The matters are in the discovery phase and Marathon intends to vigorously defend these cases.

Powder River Basin Litigation

        The U.S. Bureau of Land Management ("BLM") completed a multi-year review of potential environmental impacts from coal bed methane development on federal lands in the Powder River Basin in Montana and Wyoming. The Agency's Record of Decision ("ROD") was signed on April 30, 2003 supporting increased coal bed methane development. Plaintiff environmental and other groups filed four suits in May 2003 in the U.S. District Court for the District of Montana against the BLM alleging the Agency's environmental impact review was not adequate. Plaintiffs seek a court order enjoining coal bed methane development on federal lands in the Powder River Basin until BLM conducts additional studies on the environmental impact. Marathon has been allowed to intervene as a party in all four of the cases. As the lawsuits to delay energy development in the Powder River Basin progress through the courts, BLM continues to process permits to drill under the ROD. In January 2004, the Court over protests of Plaintiffs, transferred to the District Court of Wyoming, portions of two of the cases dealing with the sufficiency of the environmental impact review as to lands in Wyoming.

        In May 2004, plaintiff environmental groups Environmental Defense et al, filed suit against the U.S. Bureau of Land Management ("BLM") in Montana Federal District Court, alleging the agency did not adequately consider air

21

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 BLM be ordered to cease issuing leases and permits for energy development, until additional analysis of predicted air impacts is conducted. Marathon and Pennaco Energy, Inc. have intervened in the litigation.

Environmental Proceedings

        The following is a summary of proceedings involving Marathon that were pending or contemplated as of December 31, 2004, 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 the Comprehensive Environmental Response, Compensation and Liability Act ("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, 2004, Marathon had been identified as a PRP at a total of six 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 all but one 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 $4 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 131 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. Of these sites, 14 were associated with properties conveyed to MAP by Ashland which has retained liability for all costs associated with remediation. 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 25 of these sites will be under $100,000 per site, 53 sites have potential costs between $100,000 and $1 million per site, 19 sites may involve remediation costs between $1 million and $5 million per site and 8 sites have incurred remediation costs of more than $5 million per site. There are 11 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 less than $7 million at this site. Expenditures in 2004 were approximately $391,000, and expenditures in 2005 are expected to be $600,000 as technical evaluation continues, and could be as much as $3,900,000 if soil remediation is commenced in the second half of the year. Ongoing work at this site is subject to approval by the MDEQ, and a risk-based closure strategy is being developed for approval by the MDEQ.

        MAP has had a pending enforcement matter with the Illinois Environmental Protection Agency and the Illinois Attorney General's Office since 2002 concerning MAP's self-reporting of possible emission exceedences and permitting issues related to storage tanks at its Robinson, Illinois refinery. MAP has had periodic discussions with Illinois officials regarding this matter and more discussions may occur in 2005.

22

        In July, 2002, Marathon received a Notice of Enforcement from the State of Texas for alleged excess air emissions from its Yates Gas Plant and production operations on its Kloh lease. A settlement of this matter was finalized in 2004, with Marathon and its co-owners paying a civil penalty of $74,000 and the donation of land as a Supplemental Environmental Project in lieu of a further penalty of $74,000. Marathon is owner of a 38% interest in the facilities.

        In May, 2003, Marathon received a Consolidated Compliance Order & Notice or Potential Penalty from the State of Louisiana for alleged various air permit regulatory violations. This matter was settled for a civil penalty of $148,628 and awaits formal closure with the State.

        In August of 2004, the West Virginia Department of Environmental Protection ("WVDEP") submitted a draft consent order to MAP regarding MAP's handling of alleged hazardous waste generated from tank cleanings in the State of West Virginia. The proposed order seeks a civil penalty of $337,900. MAP has met with the WVDEP and discussions are ongoing in an attempt to resolve this matter.

Item 4. Submission of Matters to a Vote of Security Holders

        Not applicable.

PART II

Item 5. Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities

        The principal market on which the Company's common stock is traded is the New York Stock Exchange. The Company'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-41.

        As of January 31, 2005, there were 58,340 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 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 fourth quarter ended December 31, 2004 of equity securities that are registered by Marathon pursuant to Section 12 of the Exchange Act:

ISSUER PURCHASES OF EQUITY SECURITIES

⁽¹⁾

42,749 shares were repurchased in open-market transactions under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the "Plan") by the administrator of the Plan. Stock needed to meet the requirements of the Plan are either purchased in the open market or issued directly by Marathon.

⁽²⁾

2,936 shares of restricted stock were delivered by employees to Marathon, upon vesting, to satisfy tax withholding requirements.

Item 6. Selected Financial Data

        See page F-49 through F-51.

23

Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

        Marathon Oil Corporation 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 through our 62 percent owned subsidiary, Marathon Ashland Petroleum LLC ("MAP"); and integrated gas. Management's Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with Items 1. and 2. Business and Properties, 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 businesses. 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 MAP include the 38 percent interest held by Ashland Inc. ("Ashland"), and amounts for Equatorial Guinea LNG Holdings Limited ("EGHoldings") include the 25 percent interest held by Compania Nacional de Petroleos de Guinea Ecuatorial ("GEPetrol").

Overview

Exploration and Production

        Exploration and production ("E&P") 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 2004 tracked the increase in prices for these commodities. The robust prices for crude oil during 2004 were caused in part by increased demand in strengthening economies, particularly in the United States and China, weather related damages and disruptions, the influence of OPEC, as well as civil and political unrest and military actions in various oil exporting countries. The average spot price during 2004 for West Texas Intermediate ("WTI"), a benchmark crude oil, was $41.47 per barrel – up from an average of $30.99 in 2003 – and ended the year at $43.45. The differential between WTI and Brent (an international benchmark crude oil) widened to $3.20 in 2004 from $2.16 in 2003, primarily because shipping freight rates were much higher in 2004 and it cost more to transport a Brent-based international barrel to the U.S. Marathon's 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. Marathon's international crude production is relatively sweet and is generally sold in relation to the Brent crude benchmark.

        Natural gas prices were higher in 2004 as compared to 2003. A significant portion of our United States lower 48 natural gas production is sold at bid week prices, making this indicator particularly important. The average quarterly bid week prices for 2004 were $5.69, $6.00, $5.75 and $7.07 for the first to fourth quarter. 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 gas-producing regions are Europe and Equatorial Guinea, where large portions of our gas are sold at contractual prices, making realized prices in these areas less volatile.

        For additional information on price risk management, see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" on page 50.

        E&P segment income during 2004 was impacted by lower production (on an equivalent barrel basis) – down approximately 13 percent from 2003 levels. We estimate that our 2005 production will average approximately 325,000 to 350,000 barrels of oil equivalent per day ("BOEPD"), excluding the impact of acquisitions, dispositions or potential reentry into Libya. Our continued exploration success coupled with ongoing development of our base businesses and new core areas, provides defined production growth that is expected to increase our average daily production by an estimated compounded average growth rate of five to nine percent between 2005 and 2008.

        Projected production levels for liquid hydrocarbons and natural gas are based on a number of assumptions, including (among others) prices, supply and demand, regulatory constraints, reserve estimates, production decline

24

rates for mature fields, reserve replacement rates, drilling rig availability and geological and operating 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.

        E&P operations are subject to various hazards, including acts of war or terrorist acts and the governmental or military response thereto, explosions, fires and uncontrollable flows of oil and gas. Offshore production and marine operations in areas such as the Gulf of Mexico, the North Sea, the U.K. Atlantic Margin, the Celtic Sea, offshore Nova Scotia and offshore West Africa are also subject to severe weather conditions such as hurricanes or violent storms or other hazards. Development of new production properties in countries outside the United States may require protracted negotiations with host governments and are frequently subject to political considerations, such as tax regulations, which could adversely affect the economics of projects.

Refining, Marketing and Transportation

        MAP refines, markets and transports crude oil and petroleum products, primarily in the Midwest, the upper Great Plains and southeastern United States. Refining, marketing and transportation ("RM&T") segment income primarily represents MAP's income from operations which depends largely on the refining and wholesale marketing margin, refinery throughputs, retail marketing margins for gasoline, distillates and merchandise, and the profitability of its 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. MAP purchases crude oil to satisfy the throughput requirements of its refineries. As a result, its 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 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, MAP's refining and wholesale marketing margin is impacted by the types of crude oil processed, the wholesale selling prices realized for all the products sold and the level of manufacturing costs. MAP processes significant amounts of sour crude oil which enhances its competitive position in the industry as sour crude oil typically can be purchased at a discount to sweet crude oil. As crude oil production increases in the coming years, heavy sour crude oil production growth is expected to outpace sweet crude oil production growth, which may translate into higher sour crude oil discounts going forward. Over the last three years, approximately 60 percent of the crude oil throughput at MAP's refineries has been sour crude oil. Sales of asphalt increase during the highway construction season in MAP's market area which is primarily in the second and third calendar 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. Changes in manufacturing costs from period to period are primarily dependent on the level of maintenance activities at the refineries and the price of purchased natural gas. The refining and wholesale marketing margin has been historically volatile and varies with the level of economic activity in the 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" on page 50.

        Additionally, the retail marketing gasoline and distillate margin, which is the difference between the ultimate price paid by consumers and the wholesale cost of the refined products, including secondary transportation, plays an important part in downstream profitability. The retail gasoline and distillate margin has been historically volatile, but tends to be countercyclical to the refining and wholesale marketing margin. Factors affecting the retail gasoline and distillate margin include competition, seasonal demand fluctuations, the available wholesale supply, the level of economic activity in the 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 the marketing areas. The profitability of MAP's pipeline transportation operations is primarily dependent on the volumes shipped through the pipelines. The volume of crude oil that MAP transports is directly affected by the supply of, and refiner demand for, crude oil in the markets served directly by MAP's 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 transportation modes, and the refinery and

25

transportation system maintenance levels. The throughput of the refined products that MAP transports is directly affected by the production level of, and user demand for, refined products in the markets served by MAP's refined product pipelines. In most of MAP's 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 movements on an annual basis. As with crude oil, other transportation alternatives and maintenance levels influence refined product movements.

        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 that may have an adverse effect on margins and financial condition. Refining, marketing and transportation operations are subject to business interruptions due to unforeseen events such as explosions, fires, 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.

Integrated Gas

        Our integrated gas ("IG") operations include marketing and transporting natural gas and products manufactured from natural gas, such as liquefied natural gas ("LNG") and methanol, primarily in the United States, Europe and West Africa. Also included are the costs associated with ongoing development of certain integrated gas projects, such as the LNG project in Equatorial Guinea. 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 or addition in production capacity can have a significant impact on the supply-demand balance. IG operations could be impacted by unforeseen events such as explosions, fires, product spills, inclement weather or availability of LNG vessels. They are also subject to the additional hazards of marine operations, such as capsizing, collision and damage or loss from severe weather conditions.

2004 Operating Highlights

•

We realized continued exploration success with six discoveries including the Deep Luba and Gardenia wells in Equatorial Guinea, the Venus and Canela wells in Angola, the Hamsun well in Norway and the Neptune 7 well in the Gulf of Mexico.



•

We strengthened core areas by:



•

Receiving approval of the plan of development and operation ("PDO") for the Alvheim project in Norway and reaching agreement to develop Vilje through the Alvheim infrastructure;



•

Completing the Equatorial Guinea condensate expansion project and advancing the liquefied petroleum gas ("LPG") expansion project; and



•

Receiving planning permission from the Irish authorities for the Corrib development.



•

We added net proved reserves of 221 million barrels of oil equivalent ("BOE"), excluding 2 million BOE of dispositions, while producing 122 million BOE of production during 2004. Over the past three years, we have added net proved reserves of 782 million BOE, excluding dispositions of 280 million, while producing 411 million BOE. Three-year amounts include 7 million BOE of net proved reserve additions, 19 million BOE of dispositions and 7 million BOE of production related to equity investees.



•

We strengthened MAP assets by:



•

Completing the Catlettsburg, Kentucky refinery repositioning project, which has improved product yields, lowered overall refinery costs and allowed MAP to meet the Tier II gasoline regulations;



•

Increasing crude oil capacity at our Garyville, Louisiana refinery from 232,000 barrels per day ("bpd") to 245,000 bpd, which allowed us to achieve record crude oil and other feedstock refinery throughputs of 1,110,000 bpd;



•

Progressing an expansion project to increase the capacity of the Detroit, Michigan refinery; and



•

Increasing same store merchandise sales by 11 percent at Speedway SuperAmerica LLC ("SSA").



•

We advanced our integrated gas strategy by:



•

Reaching final investment decision and beginning construction on a 3.4 million metric tonnes per year LNG plant in Equatorial Guinea;

26

•

Signing an agreement with BP Energy Company under which BP will supply us with 58 billion cubic feet ("bcf") of natural gas per year, as LNG, for a minimum period of 5 years, beginning in the second half of 2005;



•

Securing six cargos of LNG utilizing our Elba Island, Georgia LNG regasification terminal delivery rights; and



•

Completing the construction and operation of a gas-to-liquids ("GTL") demonstration plant at the Port of Catoosa, Oklahoma.



•

We signed an agreement to acquire Ashland's 38 percent interest in MAP and continue to pursue completion of the transaction.



•

We continued our business transformation programs, including implementation of two outsourcing agreements, to achieve further business process improvements and cost reductions.



•

We increased the quarterly dividend to 28 cents per share.

Management's Discussion and Analysis of 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, the disclosure of contingent assets and liabilities at year end and the reported amounts of revenues and expenses during the year. Actual results could differ from the estimates and assumptions used.

        Certain accounting estimates are considered to be critical if a) 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 b) the impact of the estimates and assumptions on financial condition or operating performance is material.

Estimated Net Recoverable Quantities of Oil and 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 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 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 for impairment of such properties and the expected future taxable income available to realize the value of deferred tax assets also rely in part on estimates of net recoverable quantities of oil and gas.

        Proved reserves are the estimated quantities of oil and 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 and negatively, as additional information becomes available and as contractual, economic and political conditions change. During 2004, net revisions of previous estimates increased total proved reserves by 81 million BOE as a result of 190 million BOE in positive revisions which were partially offset by 109 million BOE in negative revisions.

        Our estimation of net recoverable quantities of oil and gas is a highly technical process performed primarily by internal teams of in-house reservoir engineers and geoscience professionals. All estimates prepared by these internal teams are approved by members of the Corporate Reserve Group upon input into Marathon's Reserve System. Any change to proved reserves in excess of 2.5 million BOE, on a field-total basis for a single month, must be approved by the Director of Corporate Reserves. In 2003, we implemented a process to have third party consultants audit the top 80 percent of our reserves over a 3 year period. Those third party audits have been completed on roughly 50 percent of our year-end 2004 reserves and have not resulted in any reserve changes. In addition to third party audits, the Corporate Reserve Group routinely audits properties with problematic indicators such as excessively long reserves life, sudden changes in performance, changes in economic or operating conditions, or recent acquisitions of material fields.

        The reserves of the Alba field offshore Equatorial Guinea comprise approximately 40 percent of our total proved oil and gas reserves. The next five largest oil and gas producing asset groups – the Brae Area Complex offshore the United Kingdom, the Alvheim/Vilje development offshore Norway, the Kenai field in Alaska, the Petronius

27

development in the Gulf of Mexico and the Foinaven area complex offshore the United Kingdom – comprise a total of approximately 20 percent of our total proved oil and gas reserves.

Impairment of Long-lived Assets

        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 is generally on a field-by-field basis for E&P assets, at the refinery and associated distribution system level or at the pipeline system level for downstream assets, or at a 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 estimated fair value.

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

        Marathon evaluates its 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 downstream 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.

        During the fourth quarter of 2004, we recorded an impairment of $32 million related to unproved properties and $12 million related to producing properties primarily due to unsuccessful developmental drilling activity in Russia. During the years ended December 31, 2003 and 2002, we did not have significant impairment charges.

Suspended Exploratory Well Costs

        We use the successful efforts method of accounting for oil and gas producing activities. Costs to acquire mineral interests in oil and gas properties, to drill and equip exploratory wells that find proved reserves, and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves that cannot yet be classified as proved are capitalized on our balance sheet if (a) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (b) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Otherwise, well costs are expensed if a determination as to whether proved reserves were found cannot be made within one year following the completion of drilling and these criteria are not met. It is not unusual for costs associated with complex deepwater or international discoveries to be suspended on our balance sheet for more than a year while we are performing additional appraisal work, determining an optimal plan of development or awaiting project sanction by our Board of Directors, our co-venturers and the government entity having jurisdiction over the area under development. However, we continually monitor the progress being made towards the ultimate development of projects to ensure that continued capitalization is appropriate. At December 31, 2004, total costs capitalized attributable to suspended exploratory well costs were $339 million. Of the $339 million, $309 million relates to wells in areas where additional exploratory wells are underway or firmly planned. $23 million relates to wells in areas where additional wells are not firmly planned; however, less than a year has elapsed since the rig release for these wells. The remaining $7 million relates to single well projects that were drilling over year end and completion costs.

        Exploration expense was $202 million, $180 million and $192 million in 2004, 2003 and 2002. Costs incurred for exploration as reported on page F-42 was $291 million, $231 million and $258 million for 2004, 2003 and 2002. Exploration expense differs from exploration costs incurred due to timing differences between when costs are incurred and when those costs are ultimately recognized as expense. For example, costs may be incurred and suspended as exploratory well costs in one year and recorded in exploration expense in a subsequent year if it is ultimately determined that proved reserves cannot be recognized. Additionally, exploration costs incurred for wells that find proved reserves are transferred to proved property and remain capitalized, and therefore will not be recorded as exploration expense. Instead these costs will be expensed in depreciation, depletion and amortization on a units-of-production basis once production begins. Exploration expense also includes non-cash charges for unproved property impairments. For 2004, 2003 and 2002 exploration expense included $52 million, $31 million and $25 million

28

of unproved property impairment charges. Dry well expense included in exploration expense for 2004, 2003 and 2002 totaled $54 million, $55 million and $91 million. The remaining costs included in exploration expense of $96 million, $94 million and $76 million for 2004, 2003 and 2002 represent geological and geophysical costs, administrative expenses and other expenses.

        In February 2005, the Financial Accounting Standards Board ("FASB") proposed FASB Staff Position FAS 19-a, "Accounting for Suspended Well Costs" ("FSP FAS 19-a"), which would amend the guidance for suspended well costs in Statement of Financial Accounting Standard No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies" ("SFAS No. 19"). SFAS No. 19 requires costs of drilling exploratory wells to be capitalized pending determination of whether the well has found proved reserves. If classification of proved reserves cannot be made at the completion of the drilling in an area requiring a major capital expenditure, paragraph 31(a) of SFAS No. 19 provides that the cost should continue to be carried as an asset provided that (1) there have been sufficient reserves found to justify completion as a producing well if the required capital expenditure is made and (2) drilling of the additional exploratory well is underway or firmly planned for the near future. If either of those two criteria is not met, SFAS No. 19 indicates the entity should expense the exploratory well costs. For all other exploratory wells not addressed in paragraph 31(a), paragraph 31(b) provides that the capitalized costs should be charged to expense if the reserves cannot be classified as proved after a year following the completion of exploratory drilling. Questions have arisen in practice about the application of this guidance due to changes in oil and gas exploration processes and lifecycles. The issue is whether there are circumstances that would permit the continued capitalization of exploratory well costs beyond one year other than when additional exploration wells are necessary to justify major capital expenditures and those wells are underway or firmly planned for the near future. The proposed FSP FAS 19-a would allow exploratory well costs to continue to be capitalized when (a) the well has found a sufficient quantity of reserves to justify completion as a producing well and (b) the enterprise is making sufficient progress assessing the reserves and the economic and operating viability of the project. Our current policy as described above is in accordance with the proposed FSP FAS 19-a.

Depreciation, Depletion and Amortization of Property, Plant and Equipment

        Depreciation and depletion of producing oil and gas properties is determined by the units-of-production method and could change with revisions to estimated proved developed recoverable reserves. The change in the depreciation and depletion rate over the past three years due to revisions of previous reserve estimates has been immaterial. A five percent increase in the amount of oil and gas reserves would change the depreciation and depletion rate from $5.55 per barrel to $5.29 per barrel, which would increase pre-tax income by $32 million annually. A five percent decrease in the amount of oil and gas reserves would change the depreciation and depletion rate from $5.55 per barrel to $5.84 per barrel and would result in a decrease in pre-tax income of $35 million annually.

        Property, plant and equipment in our RM&T segment are depreciated using the straight-line method over their estimated useful lives, which range from 3 to 42 years. Useful lives are based on historical experience and the assumption that we will provide an appropriate level of annual expenditures to maintain the assets in good operating condition. Factors which could affect the estimated useful lives of our RM&T property, plant and equipment include changes in planned use, environmental regulations, competition and technological advances. There have been no significant changes in the useful lives of our RM&T property, plant and equipment during the 2002-2004 period.

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, 2004, we reported net deferred tax assets of $1.360 billion, which represented gross assets of $1.853 billion net of valuation allowances of $493 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 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 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.

29

        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 if the forecasted conditions actually occurred. The principal tax planning strategy available to us relates to the permanent reinvestment of the earnings of foreign subsidiaries. Assumptions related to the permanent reinvestment of the earnings of foreign subsidiaries are reconsidered quarterly to give effect to changes in our portfolio of producing properties and in our tax profile.

Net Realizable Value of Receivables from United States Steel

        As described further in "Management's Discussion and Analysis of Financial Condition, Cash Flows and Liquidity – Obligations Associated with the Separation of United States Steel" on page 42, we remain obligated (primarily or contingently) for certain debt and other financial arrangements for which United States Steel has assumed responsibility for repayment under the terms of the Separation. As of December 31, 2004, we have reported receivables from United States Steel of $602 million, representing the amount of principal and accrued interest on Marathon debt for which United States Steel has assumed responsibility for repayment. We must assess the realizability of these receivables, based on our expectations of United States Steel's ability to satisfy its obligations. To make this assessment, we must rely on public information about United States Steel. As of December 31, 2004, we have judged the entire receivable to be realizable.

        We may continue to be exposed to the risk of nonpayment by United States Steel on a significant portion of this receivable until December 31, 2011. Of the $602 million, $472 million, or 78 percent, relates to industrial revenue bonds that are due in 2011 or later. The Financial Matters Agreement between Marathon and United States Steel provides that, on or before the tenth anniversary of the Separation, which is December 31, 2011, United States Steel will provide for our discharge from any remaining liability under any of the assumed industrial revenue bonds.

        As of December 31, 2004, our cash-adjusted debt-to-capital ratio (which includes debt for which United States Steel has assumed responsibility for repayment and suspended cash distributions to Ashland) was 8 percent. The assessment of our liquidity and capital resources may be impacted by expectations concerning United States Steel's ability to satisfy its obligations.

        If the debt for which United States Steel has assumed responsibility for repayment were excluded from the computation, our cash-adjusted debt-to-capital ratio as of December 31, 2004 would have been approximately 1 percent. On the other hand, if the receivable from United States Steel had been written off as unrealizable, the cash-adjusted debt-to-capital ratio as of December 31, 2004 would have been approximately 8 percent. (If United States Steel were unable to satisfy its obligations, other adjustments in addition to the write-off of the receivable may be necessary.)

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 multiple 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 on the amount of damages. Similarly, liabilities for environmental remediation may change 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.

        Under the accounting rules, 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 "Costs of revenues" or "Selling, general and administrative expenses" on the Consolidated Statement 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" on page 44.

        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.

30

Pensions and Other Postretirement Benefit Obligations

        Accounting for pension and other postretirement benefit obligations involves assumptions related to:

•

discount rate for measuring the present value of future plan obligations



•

expected long-term rates of return on plan assets



•

rate of future increases in compensation levels



•

health care cost projections

        We develop our demographics and utilize the work of outside actuaries to assist in the measurement of these obligations. In determining the discount rate, we review market yields on high-quality corporate debt and perform an in-depth analysis of projected pension plan cash flows relating to the duration of pension plan liabilities.

        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), past performance and other factors. Certain components of the asset mix are modeled with various assumptions regarding inflation, debt returns and stock yields. Peer data and historical returns are reviewed to check 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, beginning on page F-30, includes detailed information for the three years ended December 31, 2004, on the components of pension and other postretirement expense and the underlying assumptions as well as the funded status for the company's pension plans for the years ended 2004 and 2003.

        Of the assumptions used to measure the December 31, 2004 obligations and estimated 2005 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 rate of 5.75 percent for domestic and 5.30 percent for international would increase pension and other postretirement plan expense by approximately $13 million and $2 million, respectively.

Estimated Fair Value of Derivative Contracts

        We record all derivative instruments at fair value. Derivative instruments are used to manage risk throughout our different businesses. These risks relate to commodities, interest rates and our exposure to foreign currency fluctuations. We use derivative instruments that are exchange traded and non-exchange traded. Non-exchange traded instruments are referred to as over-the-counter ("OTC") instruments.

        For commodities, the fair value of exchange traded instruments is based on existing market quotes. Fair value for OTC instruments such as options and swap agreements is developed through the use of option-pricing models or third party market quotes. Forward contracts are valued based on quotes from the counterparties of the forward contracts.

        We also have two long-term contracts for the sale of natural gas in the United Kingdom ("U.K."). 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 gas prices.

        These U.K. gas contracts are accounted for as derivative instruments. The fair value of these contracts is determined by applying the difference between the contract price and the U.K. forward 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 noncash charges or credits to income from operations. The difference between the contract price and the U.K. forward gas strip price may fluctuate widely from time to time and may significantly affect income from operations.

        The noncash change in fair value recognized in earnings was a loss of $99 million in 2004, a loss of $66 million in 2003 and a gain of $18 million in 2002. These effects are primarily due to the U.K. 18-month forward gas price curve strengthening 36 and 26 percent during 2004 and 2003 and weakening 12 percent during 2002.

31

        For additional information on market risk sensitivity, see "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" on page 50.

Matching buy/sell transactions

        Matching buy/sell transactions are arrangements in which we agree to buy a specific quantity and quality of crude oil or refined petroleum products to be delivered at a specific location while simultaneously agreeing to sell a specified quantity and quality of crude oil or refined petroleum products at a different location, usually with the same counterparty. All matching buy/sell transactions are settled in cash and are recorded in both revenues and costs of revenues as separate sales and purchase transactions, or on a "gross" basis.

        In a typical buy/sell transaction, we enter into a contract to sell a particular grade of crude oil or refined product at a specified location and date to a particular counterparty, and simultaneously agree to buy a particular grade of crude oil or refined product at a different location on the same or another specified date, typically from the same counterparty. The value of the purchased volumes rarely equals the sales value of the sold volumes. The value difference between purchases and sales are primarily due to 1) grade/quality differentials, 2) location differentials or 3) timing differences, in those instances when the purchase and sale do not occur in the same month.

        For the E&P segment, we enter into matching buy/sell transactions to reposition crude oil from one market center to another in order to maximize the value received for our crude oil production. For the RM&T segment, we enter into crude oil matching buy/sell transactions to secure the most profitable refinery supply and refined product matching buy/sell transactions to meet projected customer demands and to secure the required volumes in the most cost-effective manner.

        The characteristics of our matching buy/sell transactions include gross invoicing between Marathon and its counterparties and cash settlement of the transactions. Nonperformance by one party to deliver generally does not relieve the other party's obligation to perform. Both transactions require physical delivery of the product. The risks and rewards of ownership are evidenced by title transfer, assumption of environmental risk, transportation scheduling, credit risk, counterparty nonperformance risk and the fact that we have the primary obligation to perform.

        We believe matching buy/sell transactions are monetary in nature and thus outside the scope of APB Opinion No. 29, "Accounting for Nonmonetary Transactions" ("APB No. 29"). Additionally, we have evaluated EITF No. 99-19, "Reporting Revenue Gross as a Principal versus Net as an Agent" ("EITF No. 99-19") and, based on that evaluation, management believes that the recording these transactions on a gross basis is appropriate.

        The Emerging Issues Task Force ("EITF") is currently considering Issue No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty," ("EITF No. 04-13"), which relates to transactions in which an entity sells inventory to another entity in the same line of business from which it also purchases inventory. The following questions have been raised regarding the accounting for these types of transactions and are expected to be addressed by the EITF:

(a)

Under what circumstances should two or more transactions with the same counterparty (counterparties) be viewed as a single nonmonetary transaction within the scope of APB No. 29?



(b)

If nonmonetary transactions within the scope of APB No. 29 involve inventory, are there any circumstances under which the transactions should be recognized at fair value?

        The EITF has not yet addressed the first question. The EITF discussed the second question at its November 2004 meeting without reaching any consensus. If the EITF were to determine that these transactions should be accounted for as monetary transactions on a gross basis, no change in our accounting policy for matching buy/sell transactions would be necessary. If the EITF were to determine that these transactions should be accounted for as nonmonetary transactions qualifying for fair value recognition and require a net presentation of such transactions, the amounts of revenues and cost of revenues associated with matching buy/sell transactions would be netted in our consolidated statement of income, but there would be no effect on income from operations, net income or cash flows from operations. If the EITF were to determine that these transactions should be accounted for as nonmonetary transactions not qualifying for fair value recognition, these amounts of revenues and cost of revenues would be netted in our consolidated statement of income and there could be an impact on income from operations and net income related to the timing of the ultimate sale of product purchased in the "buy" side of the matching buy/sell transaction. However, management does not believe any impact would be material. There would be no impact on cash flows from operations as a result of this accounting treatment.

32

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 $86 million in 2004 from 2003 and by $334 million in 2003 from 2002. The 2004 increase was primarily due to higher worldwide liquid hydrocarbon and natural gas prices. This increase was partially offset by lower liquid hydrocarbon and natural gas volumes and decreased crude oil marketing activities. The 2003 increase was primarily due to higher worldwide natural gas and liquid hydrocarbon prices and increased crude oil marketing activities. This increase was partially offset by lower liquid hydrocarbon and natural gas volumes. Derivative losses totaled $268 million in 2004, compared to losses of $176 million in 2003 and gains of $52 million in 2002. These results included losses of $99 million in 2004 compared to losses of $66 million in 2003 and gains of $18 million in 2002 related to long-term natural gas contracts in the United Kingdom that are accounted for as derivative instruments. See "Quantitative and Qualitative Disclosures About Market Risk" on page 50 for discussion of derivative instruments and associated market risk. Matching buy/sell transactions decreased by $55 million in 2004 from 2003 and by $67 million in 2003 from 2002. The 2004 and 2003 decreases were primarily due to decreased crude oil buy/sell transactions, partially offset by higher domestic liquid hydrocarbon prices.

        RM&T segment revenues increased by $9.116 billion in 2004 from 2003 and by $8.115 billion in 2003 from 2002. The increases primarily resulted from higher refined product selling prices and volumes and increased crude oil sales volumes and prices. Matching buy/sell transactions increased by $2.061 billion in 2004 from 2003 and by $2.745 billion in 2003 from 2002. The 2004 increase was primarily due to higher liquid hydrocarbon and refined product prices and increased crude oil and refined products buy/sell transaction volumes. The 2003 increase was primarily due to increased crude oil buy/sell transactions and higher liquid hydrocarbon and refined product prices, partially offset by lower refined product buy/sell transaction volumes.

        IG segment revenues decreased by $509 million in 2004 from 2003 and increased by $1.031 billion in 2003 from 2002. The decrease in 2004 is due to a decrease in natural gas marketing activities, partially offset by higher natural gas prices. The increase in 2003 is a result of higher natural gas prices and increased natural gas marketing activity. Derivative gains totaled $17 million in 2004, compared to gains of $19 million in 2003 and losses of $8 million in 2002.

        For additional information on segment results, see the discussion on income from operations on page 35.

        Income from equity method investments increased by $141 million in 2004 from 2003 and decreased by $108 million in 2003 from 2002. The increase in 2004 and decrease in 2003 is due to a $124 million loss on the dissolution of MKM Partners L.P. ("MKM") recorded in 2003. Results for 2004 also include increased earnings of other equity method investments, primarily Atlantic Methanol Production Company ("AMPCO"). The loss on the dissolution of MKM in 2003 was partially offset by increased earnings of other equity method investments due to higher natural gas and liquid hydrocarbons prices. For further discussion of the dissolution of MKM, see Note 13 to the Consolidated Financial Statements.

        Net gains on disposal of assets decreased by $130 million in 2004 from 2003 and increased by $99 million in 2003 from 2002. Results from 2004 include the sale of various SSA stores. During 2003, we sold our interest in CLAM Petroleum B.V. ("CLAM"), interests in several pipeline companies, Yates field and gathering system, SSA stores primarily in Florida, South Carolina, North Carolina and Georgia, and certain fields in the Big Horn Basin of Wyoming. Results from 2002 include the sale of various SSA stores and the sale of San Juan Basin assets.

33

        Gain or loss on ownership change in MAP results from contributions to MAP of certain environmental capital expenditures and leased property acquisitions funded by Marathon and Ashland. In accordance with MAP's limited liability company agreement, in certain instances, environmental capital expenditures and acquisitions of leased properties are funded by the original contributor of the assets, but no change in ownership interest may result from these contributions. An excess of Ashland funded improvements over Marathon funded improvements results in a net gain and an excess of Marathon funded improvements over Ashland funded improvements results in a net loss.

        Cost of revenues increased by $5.822 billion in 2004 from 2003 and by $6.040 billion in 2003 from 2002. The increases are primarily in the RM&T segment and result from higher acquisition costs for crude oil, refined products, refinery charge and blend feedstocks and increased manufacturing expenses.

        Selling, general and administrative expenses increased by $105 million in 2004 from 2003 and by $97 million in 2003 from 2002. 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 start-up costs associated with the LNG project in Equatorial Guinea and the increased cost of complying with governmental regulations. The increase in 2003 was primarily due to increased employee benefit expenses (caused by increased pension expense resulting from changes in actuarial assumptions and a decrease in realized returns on plan assets) and other employee related costs. Additionally, during 2003, we recorded a charge of $24 million related to organizational and business process changes.

        Inventory market valuation reserve ("IMV") is established to reduce the cost basis of inventories to current market value. Generally, we will establish an IMV reserve when crude oil prices fall below $22 per barrel. The 2002 results of operations include credits to income from operations of $71 million, reversing the IMV reserve at December 31, 2001.

        Net interest and other financial costs decreased by $25 million in 2004 from 2003 and by $82 million in 2003 from 2002. The decrease in 2004 is primarily due to an increase in interest income. The decrease in 2003 is primarily due to an increase in capitalized interest related to increased long-term construction projects, the favorable effect of interest rate swaps, the favorable effect of a reduction in interest on tax deficiencies and increased interest income on investments. Additionally, included in net interest and other financing costs are foreign currency gains of $9 million, $13 million and $8 million for 2004, 2003 and 2002.

        Loss from early extinguishment of debt in 2002 was attributable to the retirement of $337 million aggregate principal amount of debt, resulting in a loss of $53 million.

        Minority interest in income of MAP, which represents Ashland's 38 percent ownership interest, increased by $230 million in 2004 from 2003 and by $129 million in 2003 from 2002. MAP income was higher in 2004 compared to 2003 and in 2003 compared to 2002 as discussed below in the RM&T segment.

        Minority interest in loss of Equatorial Guinea LNG Holdings Limited, which represents GEPetrol's 25 percent ownership interest, was $7 million in 2004, primarily resulting from GEPetrol's share of start-up costs associated with the LNG project in Equatorial Guinea.

        Provision for income taxes increased by $143 million in 2004 from 2003 and by $215 million in 2003 from 2002, primarily due to $388 million and $720 million increases in income before income taxes. The effective tax rate for 2004 was 36.6 percent compared to 36.6 percent and 42.1 percent for 2003 and 2002. The higher rate in 2002 was due to the United Kingdom enactment of a supplementary 10 percent tax on profits from the North Sea oil and gas production, retroactively effective to April 17, 2002. In 2002, we recognized a one-time noncash deferred tax adjustment of $61 million as a result of the rate increase.

        The following is an analysis of the effective tax rate for the periods presented:

^(a)

The deferred tax effect related to the enactment of a supplemental tax in the U.K. increased the effective tax rate 7.0 percent in 2002.

34

        Discontinued operations in 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. Results for 2002 report the western Canadian operations as discontinued.

        Cumulative effect of changes in accounting principles of $4 million, net of a tax provision of $4 million, in 2003 represents the adoption of Statement of Financial Accounting Standards No. 143 "Accounting for Asset Retirement Obligations" ("SFAS No. 143"), in which we recognized in income the cumulative effect of recording the fair value of asset retirement obligations. The $13 million gain, net of a tax provision of $7 million, in 2002 represents the adoption of subsequently issued interpretations by the Financial Accounting Standards Board ("FASB") of Statement of Financial Accounting Standards No. 133 "Accounting for Derivative Instruments and Hedging Activities" ("SFAS No. 133") in which we must recognize in income the effect of changes in the fair value of two long-term natural gas sales contracts in the United Kingdom.

        Net income decreased by $60 million in 2004 from 2003 and increased by $805 million in 2003 from 2002, primarily due to the factors discussed above.

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

^(a)

Amounts relate to long-term gas contracts in the United Kingdom that are accounted for as derivative instruments and recorded at fair value. See "Estimated Fair Value of Derivative Contracts" on page 31 for further discussion.

^(b)

Amount includes $32 million related to unproved properties and $12 million related to producing properties primarily due to unsuccessful developmental drilling activity in Russia.

^(c)

Insurance expense related to estimated future obligations to make certain insurance premium payments related to past loss experience.

^(d)

The IMV reserve results when the recorded LIFO cost basis of inventories of liquid hydrocarbons and refined petroleum products exceeds net realizable value.

^(e)

The net gain in 2003 represents a gain on the disposition of interest in CLAM and certain fields in the Big Horn Basin of Wyoming and SSA stores in Florida, North Carolina, South Carolina and Georgia. The 2002 amount represents gain on exchange of certain oil and gas properties with XTO Energy, Inc.

^(f)

See Note 13 to the Consolidated Financial Statements for a discussion of the dissolution of MKM.

^(g)

Represents a settlement arising from the cancellation of the Cajun Express rig contract on July 5, 2001.

35

Average Volumes and Selling Prices