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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)

Delaware
(State of Incorporation)
      25-0996816
(I.R.S. Employer Identification No.)

5555 San Felipe Road, Houston, TX 77056-2723
(Address of principal executive offices)
Tel. No. (713) 629-6600

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



Title of Each Class

Common Stock, par value $1.00


Indicate by check mark 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

PART I    
  Item 1. and 2.   Business and Properties
  Item 3.   Legal Proceedings
  Item 4.   Submission of Matters to a Vote of Security Holders

PART II

 

 
 
Item 5.

 

Market for Registrant's Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities
  Item 6.   Selected Financial Data
  Item 7.   Management's Discussion and Analysis of Financial Condition and Results of Operations
  Item 7A.   Quantitative and Qualitative Disclosures about Market Risk
  Item 8.   Consolidated Financial Statements and Supplementary Data
  Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
  Item 9A.   Controls and Procedures
  Item 9B.   Other Information

PART III

 

 
 
Item 10.

 

Directors and Executive Officers of the Registrant
  Item 11.   Executive Compensation
  Item 12.   Security Ownership of Certain Beneficial Owners and Management
  Item 13.   Certain Relationships and Related Transactions
  Item 14.   Principal Accounting Fees and Services

PART IV

 

 
 
Item 15.

 

Exhibits and Financial Statement Schedules
      Schedule II – Valuation and Qualifying Accounts

SIGNATURES

GLOSSARY OF CERTAIN DEFINED TERMS

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.

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        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

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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

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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

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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

 
  Developed
  Developed and Undeveloped
 
  2004
  2003
  2002
  2004
  2003
  2002

Liquid Hydrocarbons (Millions of Barrels)                        
  United States   171   193   226   191   210   245
  Europe   41   47   63   107   59   76
  West Africa   147   120   113   223   218   203
  Other International   27   31   2   39   89   3
   
 
 
 
 
 
      Total Consolidated Continuing Operations   386   391   404   560   576   527
  Equity Investees(a)   -   2   177   -   2   183
   
 
 
 
 
 
Worldwide Continuing Operations   386   393   581   560   578   710
Discontinued Operations(b)   -   -   9   -   -   10
   
 
 
 
 
 
WORLDWIDE   386   393   590   560   578   720
   
 
 
 
 
 
Developed reserves as % of total net proved reserves   69 % 68 % 82 %          

Natural Gas
(Billions of Cubic Feet)

 

 

 

 

 

 

 

 

 

 

 

 
  United States   992   1,067   1,206   1,364   1,635   1,724
  Europe   376   421   408   544   484   562
  West Africa   570   528   552   1,564   665   653
   
 
 
 
 
 
      Total Consolidated Continuing Operations   1,938   2,016   2,166   3,472   2,784   2,939
  Equity Investee(c)   -   -   36   -   -   59
   
 
 
 
 
 
Worldwide Continuing Operations   1,938   2,016   2,202   3,472   2,784   2,998
Discontinued Operations(b)   -   -   290   -   -   379
   
 
 
 
 
 
WORLDWIDE   1,938   2,016   2,492   3,472   2,784   3,377
   
 
 
 
 
 
Developed reserves as % of total net proved reserves   56 % 72 % 74 %          

Total BOE
(Millions of Barrels)

 

 

 

 

 

 

 

 

 

 

 

 
  United States   336   371   427   418   483   532
  Europe   104   117   132   198   139   170
  West Africa   242   208   205   484   329   312
  Other International   27   31   2   39   89   3
   
 
 
 
 
 
      Total Consolidated Continuing Operations   709   727   766   1,139   1,040   1,017
  Equity Investees(a)   -   2   183   -   2   193
   
 
 
 
 
 
Worldwide Continuing Operations   709   729   949   1,139   1,042   1,210
Discontinued Operations(b)   -   -   57   -   -   73
   
 
 
 
 
 
WORLDWIDE   709   729   1,006   1,139   1,042   1,283
   
 
 
 
 
 
Developed reserves as % of total net proved reserves   62 % 70 % 78 %          

(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)

(Thousands of Barrels per Day)

  2004
  2003
  2002

United States(c)   81   107   117
Europe(d)   40   41   52
West Africa(d)   32   27   25
Other International(d)   16   10   1
   
 
 
  Total Consolidated Continuing Operations   169   185   195
Equity Investees(d)(e)   1   6   8
   
 
 
Worldwide Continuing Operations   170   191   203
Discontinued Operations(f)   -   3   4
   
 
 
WORLDWIDE   170   194   207
   
 
 

Net Natural Gas Production(b)(g)

(Millions of Cubic Feet per Day)

  2004
  2003
  2002

United States(c)   631   732   745
Europe   273   262   299
West Africa   76   66   53
   
 
 
  Total Consolidated Continuing Operations   980   1,060   1,097
Equity Investees(h)   -   13   25
   
 
 
Worldwide Continuing Operations   980   1,073   1,122
Discontinued Operations(f)   -   74   104
   
 
 
WORLDWIDE   980   1,147   1,226

(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

2004

   
   
   
   
   
   
   
   
  Productive Wells(a)
   
   
   
   
  Service
Wells
(b)
  Drilling
Wells
(c)
 
  Oil
  Gas
 
  Gross
  Net
  Gross
  Net
  Gross
  Net
  Gross
  Net

United States   5,604   2,022   4,860   3,702   2,749   845   34   17
Europe   54   20   66   35   28   10   2   1
West Africa   9   5   13   9   3   1   3   1
Other International   116   116   -   -   23   23   2   2
   
 
 
 
 
 
 
 
WORLDWIDE   5,783   2,163   4,939   3,746   2,803   879   41   21
   
 
 
 
 
 
 
 
2003

   
   
   
   
   
   
   
   
  Productive Wells(a)
   
   
   
   
  Service
Wells
(b)
   
   
 
  Oil
  Gas
   
   
 
  Gross
  Net
  Gross
  Net
  Gross
  Net
   
   
United States   5,580   2,040   4,649   3,555   2,726   834        
Europe   52   14   65   35   27   9        
West Africa   7   4   10   7   1   1        
Other International   109   109   -   -   21   21        
   
 
 
 
 
 
       
  Total Consolidated   5,748   2,167   4,724   3,597   2,775   865        
Equity Investees(d)   96   21   -   -   15   3        
   
 
 
 
 
 
       
WORLDWIDE   5,844   2,188   4,724   3,597   2,790   868        
   
 
 
 
 
 
       
2002

   
   
   
   
   
   
   
   
  Productive Wells(a)
   
   
   
   
  Service
Wells
(b)
   
   
 
  Oil
  Gas
   
   
 
  Gross
  Net
  Gross
  Net
  Gross
  Net
   
   
United States   6,495   2,715   4,577   2,876   2,752   807        
Europe   53   20   62   34   26   9        
West Africa   6   3   6   4   1   1        
Other International   485   226   1,529   1,032   47   16        
   
 
 
 
 
 
       
  Total Consolidated   7,039   2,964   6,174   3,946   2,826   833        
Equity Investees(d)   2,298   742   85   4   1,002   174        
   
 
 
 
 
 
       
WORLDWIDE   9,337   3,706   6,259   3,950   3,828   1,007        

(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)

 
 
  2004
  2003
  2002

United States(b)            
  Development(c) – Oil   13   4   8
  – Gas   167   231   174
  – Dry   –     –     1
     
 
 
  Total   180   235   183
  Exploratory – Oil   1   1   2
  – Gas   8   7   5
  – Dry   6   2   6
     
 
 
  Total   15   10   13
     
 
 
  Total United States   195   245   196
International(d)              
  Development(c) – Oil   27   31   2
  – Gas   3   14   28
  – Dry   1   1   3
     
 
 
  Total   31   46   33
  Exploratory – Oil   2   2   –  
  – Gas   –     21   20
  – Dry   7   5   3
     
 
 
  Total   9   28   23
  Total International   40   74   56
     
 
 
  Total Worldwide   235   319   252

(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

 
  Developed
  Undeveloped
  Developed and Undeveloped
(Thousands of Acres)

  Gross
  Net
  Gross
  Net
  Gross
  Net

United States   1,825   764   2,320   1,426   4,145   2,190
Europe   395   305   1,315   602   1,710   907
West Africa   68   42   2,973   799   3,041   841
Other International   599   599   2,541   1,997   3,140   2,596
   
 
 
 
 
 
  WORLDWIDE   2,887   1,710   9,149   4,824   12,036   6,534

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:

Crude Oil Refining Capacity
(Barrels per Day)
   

Garyville, LA

 

245,000
Catlettsburg, KY   222,000
Robinson, IL   192,000
Detroit, MI   74,000
Canton, OH   73,000
Texas City, TX   72,000
St. Paul Park, MN   70,000
   
TOTAL   948,000
   

        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

(Thousands of Barrels per Day)

  2004
  2003
  2002

Gasoline   608   567   581
Distillates   299   284   285
Propane   22   21   21
Feedstocks and Special Products   94   93   80
Heavy Fuel Oil   25   24   20
Asphalt   77   72   72
   
 
 
TOTAL   1,125   1,061   1,059

        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

(Thousands of Barrels per Day)

  2004
  2003
  2002

Gasoline   807   776   773
Distillates   373   365   346
Propane   22   21   22
Feedstocks and Special Products   92   97   82
Heavy Fuel Oil   27   24   20
Asphalt   79   74   75
   
 
 
TOTAL   1,400   1,357   1,318
   
 
 
Matching Buy/Sell Volumes included in above   71   64   71

        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:

        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:

        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:

        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:


        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:

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

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

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

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

        The prescribed actions and transactions include:

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

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

        Although the tax sharing agreement allocates tax liabilities relating to taxable periods ending on or prior to the Separation, each of Marathon and United States Steel, as members of the same consolidated tax reporting group during any portion of a taxable period ended on or prior to the date of the Separation, is jointly and severally liable under the Internal Revenue Code for the federal income tax liability of the entire consolidated tax reporting group for that year. To address the possibility that the taxing authorities may seek to collect all or part of a tax liability from one party where the tax sharing agreement allocates that liability to the other party, the agreement includes indemnification provisions that would entitle the party from whom the taxing authorities are seeking collection to obtain indemnification from the other party, to the extent the agreement allocates that liability to that other party. Marathon can provide no assurance, however, that United States Steel will be able to meet its indemnification obligations, if any, to Marathon that may arise under the tax sharing agreement.

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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.

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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.

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        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

 
  (a)

  (b)

  (c)

  (d)

Period

  Total Number
of Shares
Purchased
(1)(2)

  Average Price
Paid per Share

  Total Number
of Shares
Purchased as
Part of Publicly
Announced Plans
or Programs
(1)

  Maximum
Number of
Shares that
May Yet Be
Purchased Under
the Plans or
Programs


10/01/04 – 10/31/04   6,015   $40.51   N/A   N/A
11/01/04 – 11/30/04   5,145   $38.94   N/A   N/A
12/01/04 – 12/31/04   34,526   $37.07   N/A   N/A
   
 
 
 
Total:   45,686   $37.73   N/A   N/A

(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.

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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

26


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.

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        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.

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Pensions and Other Postretirement Benefit Obligations

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

        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.

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        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:

        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.

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Management's Discussion and Analysis of Income and Operations

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

(In millions)

  2004
  2003
  2002
 

 
E&P   $ 4,897   $ 4,811   $ 4,477  
RM&T     43,630     34,514     26,399  
IG     1,739     2,248     1,217  
   
 
 
 
  Segment revenues     50,266     41,573     32,093  
Elimination of intersegment revenues     (668 )   (610 )   (798 )
   
 
 
 
  Total revenues   $ 49,598   $ 40,963   $ 31,295  
   
 
 
 
 
Items included in both revenues and costs and expenses:

 

 

 

 

 

 

 

 

 

 

Consumer excise taxes on petroleum products and merchandise

 

$

4,463

 

$

4,285

 

$

4,250

 
Matching crude oil and refined product buy/sell transactions settled in cash:                    
  E&P   $ 167   $ 222   $ 289  
  RM&T     8,997     6,936     4,191  
   
 
 
 
      Total buy/sell transactions   $ 9,164   $ 7,158   $ 4,480  

 

        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:

 
  2004
  2003
  2002
 

 
Statutory tax rate   35.0 % 35.0 % 35.0 %
Effects of foreign operations(a)   1.3   (0.4 ) 5.6  
State and local income taxes after federal income tax effects   1.6   2.2   3.9  
Other federal tax effects   (1.3 ) (0.2 ) (2.4 )
   
 
 
 
  Effective tax rate   36.6 % 36.6 % 42.1 %

 
(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:

(In millions)

  2004
  2003
  2002
 

 
E&P                    
    Domestic   $ 1,073   $ 1,155   $ 726  
    International     623     425     333  
   
 
 
 
        E&P segment income     1,696     1,580     1,059  
RM&T     1,406     819     372  
IG     48     (3 )   23  
   
 
 
 
        Segment income     3,150     2,396     1,454  
Items not allocated to segments:                    
  Administrative expenses     (307 )   (227 )   (194 )
  Gain (loss) on U.K. long-term gas contracts(a)     (99 )   (66 )   18  
  Impairment of certain oil and gas properties(b)     (44 )   –       –    
  Corporate insurance adjustment(c)     (32 )   –       –    
  Inventory market valuation adjustments(d)     –       –       71  
  Gain (loss) on ownership change in MAP     2     (1 )   12  
  Gain on asset dispositions(e)     –       106     24  
  Loss on dissolution of MKM Partners L.P.(f)     –       (124 )   –    
  Contract settlement(g)     –       –       (15 )
   
 
 
 
        Total income from operations   $ 2,670   $ 2,084   $ 1,370  

 
(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

 
  2004
  2003
  2002

OPERATING STATISTICS                  
Net Liquid Hydrocarbon Production (mbpd)(a)(b)                  
  United States     81.2     106.5     116.0
  Equity Investee (MKM)     –       4.4     8.5
   
 
 
    Total United States     81.2     110.9     124.5
  Europe     39.8     41.5     51.9
  Other International     15.6     10.0     1.0
  West Africa     32.5     27.1     25.3
  Equity Investee (Chernogorskoye)     1.0     1.2     –  
   
 
 
    Total International(c)     88.9     79.8     78.2
   
 
 
    Worldwide continuing operations     170.1     190.7     202.7
  Discontinued operations     –       3.1     4.4
   
 
 
    Worldwide     170.1     193.8     207.1
Net Natural Gas Production (mmcfd)(b)(d)                  
  United States     631.2     731.6     744.8
 
Europe

 

 

291.8

 

 

285.9

 

 

303.5
  West Africa     76.4     65.9     53.3
  Equity Investee (CLAM)     –       12.4     24.8
   
 
 
    Total International     368.2     364.2     381.6
   
 
 
    Worldwide continuing operations     999.4     1,095.8     1,126.4
  Discontinued operations     –       74.1     103.9
   
 
 
    Worldwide     999.4     1,169.9     1,230.3

Total production (mboepd)

 

 

336.7

 

 

388.8

 

 

412.2

Average Sales Prices (excluding derivative gains and losses)                  
  Liquid Hydrocarbons ($per bbl)(a)                  
    United States   $ 32.76   $ 26.92   $ 22.18
    Equity Investee (MKM)     –       29.45     24.65
      Total United States     32.76     27.02     22.35
   
Europe

 

 

37.16

 

 

28.50

 

 

24.40
    Other International     22.65     18.33     26.98
    West Africa     35.11     26.29     22.62
    Equity Investee (Chernogorskoye)     21.10     13.72     –  
      Total International     33.68     26.24     23.85
      Worldwide continuing operations     33.24     26.70     22.93
    Discontinued operations     –       28.96     23.29
     
Worldwide

 

$

33.24

 

$

26.73

 

$

22.94
  Natural Gas ($per mcf)                  
    United States   $ 4.89   $ 4.53   $ 2.87
   
Europe

 

 

4.13

 

 

3.35

 

 

2.67
    West Africa     .25     .25     .24
    Equity Investee (CLAM)     –       3.69     3.05
      Total International     3.33     2.80     2.35
      Worldwide continuing operations     4.31     3.95     2.70
    Discontinued operations     –       5.43     3.30
     
Worldwide

 

$

4.31

 

$

4.05

 

$

2.75

MAP:                  
Refined Products Sales Volumes (mbpd)(e)     1,400     1,357     1,318
Matching buy/sell volumes included in refined product sales volumes (mbpd)     71     64     71
Refining and Wholesale Marketing Margin(f)(g)   $ 0.0877   $ 0.0603   $ 0.0387

(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 are before royalties.
(c)
Represents equity tanker liftings and direct deliveries.
(d)
Includes gas acquired for injection and subsequent resale of 19.3, 23.4 and 4.4 mmcfd in 2004, 2003 and 2002, respectively.
(e)
Total average daily volumes of all refined product sales to MAP's wholesale, branded and retail (SSA) customers.
(f)
Per gallon.
(g)
Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation.

36


        Domestic E&P income decreased by $82 million in 2004 from 2003 following an increase of $429 million in 2003 from 2002. The decrease in 2004 was due to lower liquid hydrocarbon and natural gas volumes primarily resulting from natural declines in field production rates, weather-related downtime in the Gulf of Mexico and the sale of the Yates field, partially offset by higher liquid hydrocarbon and natural gas prices. The increase in 2003 was primarily due to higher natural gas and liquid hydrocarbon prices, lower dry well expense and a $25 million favorable contract settlement, partially offset by lower liquid hydrocarbon and natural gas volumes and derivative losses. Derivative losses totaled $118 million in 2004, compared to losses of $91 million in 2003 and gains of $32 million in 2002.

        In late September 2004, certain production platforms in the Gulf of Mexico were evacuated due to hurricane activity resulting in shut-in of approximately 40 thousand barrels per day ("mbpd") of liquid hydrocarbon and 95 million cubic feet per day ("mmcfd") of natural gas production. Restoration of production began following the hurricanes and all facilities were back on line by October 1, 2004 with the exception of the Petronius platform which is expected to be back on line by the end of the second quarter 2005. At the time of shut-in, the Petronius field was producing approximately 23.4 thousand barrels of oil equivalent per day ("mboepd") net to Marathon. As a result of the damage to the Petronius platform, we recorded expense of $11 million representing repair costs incurred, partially offset by the net effects of the property damage insurance recoveries and the related retrospective insurance premiums. We also recorded income of $34 million for business interruption insurance recoveries.

        Our domestic average liquid hydrocarbons price excluding derivative activity was $32.76 per barrel ("bbl") in 2004, compared to $27.02 per bbl in 2003 and $22.35 per bbl in 2002. Average gas prices were $4.89 per thousand cubic feet ("mcf") excluding derivative activity in 2004, compared with $4.53 per mcf in 2003 and $2.87 per mcf in 2002.

        Domestic net liquid hydrocarbons production decreased 27 percent to 81 mbpd in 2004, as a result of natural declines mainly in the Gulf of Mexico, hurricane damage to the Petronius platform and the sale of Yates field in November 2003. Net natural gas production averaged 631 mmcfd, down 14 percent from 2003, as a result of hurricane damage to the Petronius platform and natural declines in the Permian Basin and the Gulf of Mexico.

        Domestic net liquid hydrocarbons production decreased 11 percent to 111 mbpd in 2003, as a result of natural declines mainly in the Gulf of Mexico and dispositions. Net natural gas production averaged 732 mmcfd, down 2 percent from 2002.

        International E&P income increased by $198 million in 2004 from 2003 and by $92 million in 2003 from 2002. The increase in 2004 was primarily due to higher liquid hydrocarbon and natural gas prices and volumes partially offset by higher derivative losses. The increase in 2003 was due to higher natural gas and liquid hydrocarbon prices and higher liquid hydrocarbon volumes partially offset by lower natural gas volumes and derivative losses. Derivative losses totaled $51 million in 2004, compared to losses of $19 million in 2003 and gains of $2 million in 2002.

        Our international average liquid hydrocarbons price excluding derivative activity was $33.68 per bbl in 2004, compared with $26.24 per bbl in 2003 and $23.85 per bbl in 2002. Average gas prices were $3.33 per mcf excluding derivative activity in 2004, compared with $2.80 per mcf in 2003 and $2.35 per mcf in 2002.

        International net liquid hydrocarbons production increased 11 percent to 89 mbpd in 2004 primarily due to increased production in Equatorial Guinea and a full year of production from Khanty Mansiysk Oil Corporation ("KMOC") which was acquired in 2003. Net natural gas production averaged 368 mmcfd, up 1 percent from 2003 due to increased production from the condensate expansion project in Equatorial Guinea, offset by the disposition in 2003 of our interest in CLAM.

        International net liquid hydrocarbons production increased 2 percent to 80 mbpd in 2003 primarily due to the acquisition of KMOC, partially offset by lower production in the U.K. Net natural gas production averaged 364 mmcfd, down 5 percent from 2002, primarily from lower production in Ireland and the disposition of our interest in CLAM. This decrease was partially offset by increased production in Equatorial Guinea.

        RM&T segment income increased by $587 million in 2004 from 2003 and by $447 million in 2003 from 2002. The 2004 increase primarily results from a higher refining and wholesale marketing margin, which averaged 8.8 cents per gallon versus 6.0 cents in 2003. Margins improved initially due to the market's concerns about refiners' ability to supply the new Tier II low sulfur gasolines which were required effective January 1, 2004 and, more recently, due to concerns about the adequacy of distillate supplies heading into winter. In addition, the widening of price differentials between sweet and sour crude positively affected the 2004 results. For the full year 2004 MAP averaged 939,000 barrels of crude oil throughput per day or 99 percent of average system capacity. The 2003 increase was primarily due to an improved refining and wholesale marketing margin, as well as a higher gasoline and

37



distillate retail gross margin partially offset by higher administrative expenses. The refining and wholesale marketing margin in 2003 averaged 6.0 cents per gallon, versus 2002 level of 3.9 cents. The gasoline and distillate gross margin for its retail business was 12.3 cents per gallon in 2003, as compared to 10.1 cents per gallon in 2002. The higher administrative expenses were due primarily to higher employee related costs. Results for 2003 also included $34 million of gains from the sale of certain interests in refined product pipelines.

        Derivative losses, which are included in the refining and wholesale marketing margin, were $272 million in 2004 compared to $158 million in 2003 and $124 million in 2002. These derivative losses were generally incurred to mitigate the price risk of certain crude oil and other feedstock purchases, to protect carrying values of excess inventories and to protect crack spread values.

        Gains on the sale of SSA stores included in segment income were $17 million, $8 million and $37 million for 2004, 2003 and 2002.

        IG segment income increased by $51 million in 2004 from 2003, following a decrease of $26 million in 2003 from 2002. The increase in 2004 was primarily due to increased earnings from our investment in AMPCO and higher income from LNG operations, partially offset by costs associated with ongoing development of certain integrated gas projects and lower margins from gas marketing activities, including recognized changes in the fair value of derivatives used to support those activities. The AMPCO methanol plant in Equatorial Guinea operated at a 95 percent on-stream factor in 2004 and prices were strong, averaging nearly $227 per ton for the year. Additionally, the 2003 results included an impairment charge of $22 million on an equity method investment and a loss of $17 million on the termination of two tanker operating leases. The decrease in 2003 is due to the impairment charge of $22 million and the loss of $17 million on leases as discussed above and higher expenses related to the development of an integrated gas business, partially offset by higher AMPCO earnings.

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

Financial Condition

        Current assets increased $2.823 billion from year-end 2003, primarily due to an increase in cash and cash equivalents and receivables. The increase in cash and cash equivalents was mainly due to the issuance on March 31, 2004, of 34,500,000 shares of common stock resulting in net proceeds of $1.004 billion and the suspension of cash distributions to Ashland. The increase in receivables was mainly due to higher year-end commodity prices.

        Current liabilities increased $1.046 billion from year-end 2003, primarily due to an increase in accounts payable as a result of higher priced year-end crude oil purchases at MAP.

        Investments and long-term receivables increased $223 million from year-end 2003, primarily due to contributions to an equity investee to fund the LPG expansion project in Equatorial Guinea and restricted cash of $66 million at EGHoldings.

        Net property, plant and equipment increased $980 million from year-end 2003. Net property, plant and equipment for each of the last two years is summarized in the following table:

(In millions)

  2004
  2003

E&P            
  Domestic   $ 2,644   $ 2,636
  International     3,530     3,351
   
 
    Total E&P     6,174     5,987
RM&T     4,842     4,492
IG     621     153
Corporate     173     198
   
 
        Total   $ 11,810   $ 10,830

        The increase in international E&P is due to the construction of the Alba field condensate expansion project in Equatorial Guinea. The increase in RM&T is primarily due to refinery upgrade projects to enable the production of low sulfur gasoline and diesel fuel and the Detroit, Michigan refinery expansion project, partially offset by sales of SSA stores. The increase in IG is primarily due to costs associated with the LNG project in Equatorial Guinea.

        Long-term debt at December 31, 2004 was $4.057 billion, a decrease of $28 million from year-end 2003. See "Liquidity and Capital Resources" on page 40, for further discussion.

38



        Asset retirement obligations increased $87 million from year-end 2003 primarily due to revisions of previous estimates caused by the impact of a weakening U.S. dollar on foreign asset retirement obligations, as well as drilling activity during 2004.

Cash Flows

        Net cash provided from operating activities (for continuing operations) totaled $3.730 billion in 2004, compared with $2.665 billion in 2003 and $2.331 billion in 2002. The increases mainly resulted from the effects of higher worldwide natural gas and liquid hydrocarbons prices and a higher refining and wholesale marketing margin.

        Net cash provided from operating activities (for discontinued operations) totaled $83 million in 2003, compared with $69 million in 2002 related to our E&P operations in western Canada sold in 2003.

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

(In millions)

  2004
  2003
  2002

E&P(a)                  
  Domestic   $ 402   $ 344   $ 417
  International     542     629     403
   
 
 
    Total E&P     944     973     820
  RM&T     784     772     621
  IG     490     131     48
  Corporate     19     16     31
   
 
 
      Total   $ 2,237   $ 1,892   $ 1,520

(a)
Amounts exclude the acquisitions of KMOC in 2003 and the Equatorial Guinea interests in 2002.

        Capital expenditures in 2004 totaled $2.237 billion compared with $1.892 billion and $1.520 billion in 2003 and 2002, excluding the acquisitions of KMOC in 2003 and Equatorial Guinea interests in 2002. The $345 million increase in 2004 mainly resulted from increased spending in the IG segment associated with the LNG project in Equatorial Guinea. The $372 million increase in 2003 mainly resulted from increased spending in the RM&T segment at the Catlettsburg refinery and on the Cardinal Products Pipeline and in the E&P segment in West Africa and Norway. The increase in IG in 2003 was due to the purchase of a 30 percent interest in two LNG tankers which we previously leased and project development costs associated with the LNG project in Equatorial Guinea. The decrease in corporate capital expenditures in 2003 was primarily due to the implementation of SAP financial and operations software in prior years.

        Acquisitions included cash payments of $252 million in 2003 for the acquisition of KMOC and $1.160 billion in 2002 for the acquisition of the interests in Equatorial Guinea. For further discussion of acquisitions, see Note 5 to the Consolidated Financial Statements.

        Cash from disposal of assets was $76 million in 2004, compared with $1.256 billion including the disposal of discontinued operations, in 2003 and $146 million in 2002. In 2004, proceeds were primarily from the sale of certain SSA stores and various domestic producing properties. In 2003, proceeds were primarily from the disposition of our E&P properties in western Canada, the Yates field and gathering system, our interest in CLAM, various SSA stores, our interest in several pipeline companies and certain fields in the Big Horn Basin of Wyoming. In 2002, proceeds were primarily from the disposition of various SSA stores and the sale of our San Juan Basin assets.

        Net cash provided from financing activities totaled $527 million in 2004, compared with net cash used of $888 million in 2003 and net cash provided of $88 million in 2002. The increase in 2004 was due to $1.004 billion in net proceeds from the March 31, 2004, issuance of 34,500,000 shares of common stock as well as the suspension of distributions to the minority shareholder of MAP. This was partially offset by an increase in dividends paid to stockholders. The decrease in 2003 was due to activity in 2002 primarily associated with financing the acquisitions of Equatorial Guinea interests of $1.160 billion. This was partially offset by the $295 million repayment of preferred securities in 2002 that became redeemable or were converted to a right to receive cash upon the Separation. In early January 2002, we paid $185 million to retire the 6.75% Convertible Quarterly Income Preferred Securities and $110 million to retire the 6.50% Cumulative Convertible Preferred Stock.

39


Derivative Instruments

        See "Quantitative and Qualitative Disclosures About Market Risk" on page 50, for a discussion of derivative instruments and associated market risk.

Dividends to Stockholders

        On January 23, 2005, our Board of Directors declared a dividend of 28 cents per share on our common stock, payable March 10, 2005, to stockholders of record at the close of business on February 16, 2005.

Liquidity and Capital Resources

        Our main sources of liquidity and capital resources are internally generated cash flow from operations, committed and uncommitted credit facilities, and access to both the debt and equity capital markets. Our ability to access the debt capital market is supported by our investment grade credit ratings. Because of the liquidity and capital resource alternatives available to us, including internally generated cash flow, we believe that our short-term and long-term liquidity is adequate to fund operations, including our capital spending program, repayment of debt maturities for the years 2005, 2006 and 2007, and any amounts that may ultimately be paid in connection with contingencies.

        Our senior unsecured debt is currently rated investment grade by Standard and Poor's Corporation, Moody's Investor Services, Inc. and Fitch Ratings with ratings of BBB+, Baa1, and BBB+, respectively. Our investment-grade credit ratings were affirmed by these agencies following the announcement of the proposed acquisition of Ashland's 38 percent ownership interest in MAP.

        We have a committed $1.5 billion five-year revolving credit facility that terminates in May 2009. At December 31, 2004, there were no borrowings against this facility. At December 31, 2004, we had no commercial paper outstanding under the U.S. commercial paper program that is backed by the five-year revolving credit facility. Additionally, we have other uncommitted short-term lines of credit totaling $200 million, of which no amounts were drawn at December 31, 2004.

        MAP has a committed $500 million five-year revolving credit facility with third-party financial institutions that terminates in May 2009. MAP also has a $190 million revolving credit agreement with Ashland that expires in March 2005. At December 31, 2004, there were no borrowings against these facilities. Pursuant to the terms of our agreement to acquire the 38 percent ownership interest in MAP currently held by Ashland (see Note 29 to the Consolidated Financial Statements), MAP's use of its credit agreement with Ashland was restricted after September 30, 2004 and we anticipate the credit agreement will be terminated if the transaction is completed.

        The Marathon and MAP revolving credit facilities each require a representation at an initial borrowing that there has been no change in the respective borrower's consolidated financial position or operations, considered as a whole, that would materially and adversely affect such borrower's ability to perform its obligations under its revolving credit facility.

        On March 31, 2004, we completed the sale of 34,500,000 shares of common stock at the offering price of $30 per share from the $2.7 billion universal shelf registration statement filed with the Securities and Exchange Commission in 2002. We recorded net proceeds of $1.004 billion related to this issuance. As of December 31, 2004 there was $1.7 billion aggregate amount of common stock, preferred stock and other equity securities, debt securities, trust preferred securities and/or other securities, including securities convertible into or exchangeable for other equity or debt securities available to be issued under this shelf registration statement.

        Cash and cash equivalents totaled $3.369 billion at December 31, 2004, as compared to $1.396 billion at December 31, 2003. We expect to utilize a substantial portion of this cash to repay debt assumed in connection with the proposed acquisition of Ashland's interest in MAP and related businesses, to retire other outstanding long-term debt or for other general corporate purposes.

        Cash distributions from MAP have been suspended pending consummation of the agreement to acquire the 38 percent ownership interest in MAP currently held by Ashland. If the proposed transaction closes, Ashland would receive additional proceeds equal to 38 percent of MAP's distributable cash at the time of closing. If the transaction does not close, Ashland would receive its share of these funds as part of MAP's normal distributions. Ashland's share on December 31, 2004 was $574 million.

40



        Our cash-adjusted debt-to-capital ratio (total-debt-minus-cash to total-debt-plus-equity-minus-cash) was 8 percent at December 31, 2004, compared to 33 percent at year-end 2003 as shown below. This includes approximately $594 million of debt that is serviced by United States Steel Corporation ("United States Steel") and the above suspended distributions to Ashland. We continually monitor our spending levels, market conditions and related interest rates to maintain what we perceive to be reasonable debt levels.

(Dollars in millions)

  December 31
2004

  December 31
2003

 

 
Long-term debt due within one year   $ 16   $ 272  
Long-term debt     4,057     4,085  
   
 
 
  Total debt   $ 4,073   $ 4,357  
Cash (includes $574 million in suspended distributions to Ashland for 2004)   $ 3,369   $ 1,396  
Equity   $ 8,111   $ 6,075  

 

Calculation

 

 

 

 

 

 

 
Total debt   $ 4,073   $ 4,357  
Minus cash     3,369     1,396  
   
 
 
  Total debt minus cash     704     2,961  
   
 
 
Total debt     4,073     4,357  
Plus equity     8,111     6,075  
Minus cash     3,369     1,396  
   
 
 
  Total debt plus equity minus cash   $ 8,815   $ 9,036  
   
 
 
Cash-adjusted debt-to-capital ratio     8 %   33 %

 

        The table below provides aggregated information on our obligations to make future payments under existing contracts as of December 31, 2004:


Summary of Contractual Cash Obligations

(Dollars in millions)

  Total
  2005
  2006-
2007

  2008-
2009

  Later
Years


Short and long-term debt (excludes interest)(a)(b)   $ 3,925   $ 7   $ 752   $ 402   $ 2,764
Sale-leaseback financing (includes imputed interest)(a)     96     11     30     22     33
Capital lease obligations(a)     137     9     30     30     68
Operating lease obligations(a)     363     83     118     58     104
Operating lease obligations under sublease(a)     54     12     15     11     16
Purchase obligations:                              
  Crude, refinery feedstock and refined products contracts(c)     11,482     10,094     1,388     –       –  
  Transportation and related contracts     852     142     207     106     397
  Contracts to acquire property, plant and equipment     1,094     906     186     2     –  
  LNG facility operating costs(d)     217     13     27     27     150
  Service and materials contracts(e)     156     78     40     20     18
  Unconditional purchase obligations(f)     67     5     11     11     40
  Commitments for oil and gas exploration (non-capital)(g)     23     23     –       –       –  
   
 
 
 
 
      Total purchase obligations     13,891     11,261     1,859     166     605
Other long-term liabilities reported in the Consolidated Balance Sheet:                              
  Accrued LNG facility operating costs(d)     22     3     5     5     9
  Employee benefit obligations(h)     1,609     204     195     323     887
   
 
 
 
 
      Total other long-term liabilities     1,631     207     200     328     896
   
 
 
 
 
Total contractual cash obligations(i)   $ 20,097   $ 11,590   $ 3,004   $ 1,017   $ 4,486

(a)
Upon the Separation, United States Steel assumed certain debt and lease obligations. Such amounts have been included in the above table because Marathon remains primarily liable.
(b)
We anticipate cash payments for interest of $251 million for 2005, $453 million for 2006-2007, $383 million for 2008-2009 and $1.596 billion for the remaining years for a total of $2.683 billion.
(c)
The majority of 2005's contractual obligations to purchase crude oil, refinery feedstock and refined products relate to contracts to be satisfied within the first 180 days of the year.
(d)
We have acquired the right to deliver to the Elba Island LNG re-gasification terminal 58 bcf of natural gas per year. The agreement's primary term ends in 2021. Pursuant to this agreement, we are also committed to pay for a portion of the operating costs of the LNG re-gasification terminal.

41


(e)
Services and materials contracts include contracts to purchase services such as utilities, supplies and various other maintenance and operating services.
(f)
We are a party to a long-term transportation services agreement with Alliance Pipeline. This agreement is used by Alliance Pipeline to secure its financing. This arrangement represents an indirect guarantee of indebtedness. Therefore, this amount has also been disclosed as a guarantee. See Note 28 to the Consolidated Financial Statements for a complete discussion of our guarantee.
(g)
Commitments for oil and gas exploration (non-capital) include estimated costs related to contractually obligated exploratory work programs that are expensed immediately, such as geological and geophysical costs.
(h)
We have employee benefit obligations consisting of pensions and other postretirement benefits including medical and life insurance. We have estimated projected funding requirements through 2014.
(i)
Includes $694 million of contractual cash obligations that have been assumed by United States Steel. For additional information, see "Management's Discussion and Analysis of Financial Condition, Cash Flows and Liquidity – Obligations Associated with the Separation of United States Steel – Summary of Contractual Cash Obligations Assumed by United States Steel" on page 43.

        Contractual cash obligations for which the ultimate settlement amounts are not fixed and determinable have been excluded from the above table. These include derivative contracts that are sensitive to future changes in commodity prices and other factors.

        Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies.

Off-Balance Sheet Arrangements

        Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under generally accepted accounting principles. Although off-balance sheet arrangements serve a variety of our business purposes, we are not dependent on these arrangements to maintain our liquidity and capital resources; and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources.

        We have provided various forms of guarantees to unconsolidated affiliates, United States Steel and certain lease contracts. These arrangements are described in Note 28 to the Consolidated Financial Statements.

        We are a party to agreements that would require us to purchase, under certain circumstances, the interests in MAP and in Pilot Travel Centers LLC ("PTC") not currently owned. These put/call agreements are described in Note 28 to the Consolidated Financial Statements.

        We are party to an agreement that would require us to sell, under certain circumstances, a 13 percent interest in EGHoldings to GEPetrol at historical cost plus an additional specified rate of return for a period of one year from the date of project sanction. This agreement is described in Note 28 to the Consolidated Financial Statements.

Nonrecourse Indebtedness of Investees

        Certain of our equity investees have incurred indebtedness that we do not support through guarantees or otherwise. If we were obligated to share in this debt on a pro rata ownership basis, our share would have been approximately $299 million as of December 31, 2004. Of this amount, $170 million relates to PTC. If any of these equity investees default, we have no obligation to support the debt. Our partner in PTC has guaranteed $157 million of the total PTC debt.

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Obligations Associated with the Separation of United States Steel

        On December 31, 2001, we disposed of our steel business through a tax-free distribution of the common stock of our wholly owned subsidiary, United States Steel, to holders of its USX – U. S. Steel Group class of common stock ("Steel Stock") in exchange for all outstanding shares of Steel Stock on a one-for-one basis (the "Separation").

        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. United States Steel's obligations to Marathon are general unsecured obligations that rank equal to United States Steel's accounts payable and other general unsecured obligations. If United States Steel fails to satisfy these obligations, we would become responsible for repayment. Under the Financial Matters Agreement, United States Steel has all of the existing contractual rights under the leases assumed from Marathon, including all rights related to purchase options, prepayments or the grant or release of security interests. However, United States Steel has no right to increase amounts due under or lengthen the term of any of the assumed leases, other than extensions set forth in the terms of the assumed leases.

        As of December 31, 2004, we have identified the following obligations totaling $671 million that have been assumed by United States Steel:

        Of the total $671 million, obligations of $602 million and corresponding receivables from United States Steel were recorded on our consolidated balance sheet (current portion – $15 million; long-term portion – $587 million). The remaining $69 million was related to off-balance sheet arrangements and contingent liabilities of United States Steel.

        The table below provides aggregated information on the portion of our obligations to make future payments under existing contracts that have been assumed by United States Steel as of December 31, 2004:


Summary of Contractual Cash Obligations Assumed by United States Steel

(Dollars in millions)

  Total
  2005
  2006-
2007

  2008-
2009

  Later
Years


Contractual obligations assumed by United States Steel                              
  Long-term debt(a)   $ 472   $ –     $ –     $ –     $ 472
  Sale-leaseback financing (includes imputed interest)     96     11     30     22     33
  Capital lease obligations     71     4     19     19     29
  Operating lease obligations     13     5     8     –       –  
  Operating lease obligations under sublease     42     5     10     11     16
   
 
 
 
 
Total contractual obligations assumed by United States Steel   $ 694   $ 25   $ 67   $ 52   $ 550

(a)
We anticipate cash payments for interest of $27 million for 2005, $53 million for 2006-2007, $53 million for 2008-2009 and $53 million for the later years to be assumed by United States Steel.

        Each of Marathon and United States Steel, as members of the same consolidated tax reporting group during taxable periods ended on or before December 31, 2001, is jointly and severally liable for the federal income tax liability of the entire consolidated tax reporting group for those periods. Marathon and United States Steel have entered into a tax sharing agreement that allocates tax liabilities relating to taxable periods ended on or before December 31, 2001.

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The agreement includes indemnification provisions to address the possibility that the taxing authorities may seek to collect a tax liability from one party where the tax sharing agreement allocates that liability to the other party. In 2003, in accordance with the terms of the tax sharing agreement, we paid $16 million to United States Steel in connection with the settlement with the Internal Revenue Service of the consolidated federal income tax returns of USX Corporation for the years 1992 through 1994.

        United States Steel reported in its Form 10-K for the year ended December 31, 2004, that it has significant restrictive covenants related to its indebtedness including cross-default and cross-acceleration clauses on selected debt that could have an adverse effect on its financial position and liquidity. However, United States Steel management believes that its liquidity will be adequate to satisfy its obligations for the foreseeable future. During periods of weakness in the manufacturing sector of the U.S. economy, United States Steel believes that it can maintain adequate liquidity through a combination of deferral of nonessential capital spending, sale of non-strategic assets and other cash conservation measures.

Transactions with Related Parties

        We own a combined 63 percent working interest in the Alba field. We own a net 52 percent interest in an onshore LPG processing plant through an equity method investee, Alba Plant LLC. Additionally, we own a 45 percent interest in an onshore methanol production plant through AMPCO, an equity method investee. We sell our marketed natural gas from the Alba field to Alba Plant LLC and AMPCO. AMPCO uses the natural gas to manufacture methanol and sells the methanol through another equity method investee, AMPCO Marketing LLC.

        MAP's related party sales to its 50 percent equity method investee, PTC, consists primarily of refined petroleum products which accounted for approximately 2 percent of its total sales revenue for 2004 and 2003. PTC is the largest travel center network in the United States and operates approximately 250 travel centers nationwide. MAP also sells refined petroleum products consisting mainly of petrochemicals, base lube oils, and asphalt to Ashland which owns a 38 percent interest in MAP. MAP's sales to Ashland accounted for approximately 1 percent of its total sales revenue for 2004 and 2003. We believe that these transactions were conducted under terms comparable to those with unrelated parties.

        In 2004, Marathon and GEPetrol announced that all of the necessary agreements had been finalized for a LNG plant, including the formation of the jointly-owned holding company EGHoldings. Marathon holds a 75 percent economic interest and GEPetrol holds a 25 percent economic interest in EGHoldings. As of December 31, 2004, total expenditures of $551 million, including $524 million of capital expenditures, related to the LNG project have been incurred. Cash held in escrow of $66 million to fund future contributions from GEPetrol is classified as restricted cash and is included in investments and long-term receivables. Payables to related parties include $23 million payable to GEPetrol.

Management's Discussion and Analysis of Environmental Matters, Litigation and Contingencies

        We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately recovered in the prices of our products and services, operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas, production processes and whether it is also engaged in the petrochemical business or the marine transportation of crude oil and refined products.

        Our environmental expenditures for each of the last three years were(a):

(In millions)

  2004
  2003
  2002

Capital   $ 433   $ 331   $ 128
Compliance                  
  Operating & maintenance     215     243     205
  Remediation(b)     32     44     45
   
 
 
      Total   $ 680   $ 618   $ 378

(a)
Amounts are determined based on American Petroleum Institute survey guidelines and include 100 percent of MAP.
(b)
These amounts include spending charged against remediation reserves, where permissible, but exclude noncash provisions recorded for environmental remediation.

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        Our environmental capital expenditures accounted for 19 percent of total capital expenditures in 2004, 17 percent in 2003, and eight percent in 2002.

        We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. As environmental remediation matters proceed toward ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required.

        We have been notified that we are a potentially responsible party ("PRP") at six waste sites under the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA") as of December 31, 2004. In addition, there is one site where we have received information requests or other indications that we may be a PRP under CERCLA but where sufficient information is presently unavailable to confirm the existence of liability. At many of these sites, we are one of a number of parties involved and the total cost of remediation, as well as our share thereof, is frequently dependent on the outcome of investigations and remedial studies.

        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 for which Ashland has retained liability for all costs associated with remediation.

        New or expanded environmental requirements, which could increase our environmental costs, may arise in the future. We comply with all legal requirements regarding the environment, but since not all of them are fixed or presently determinable (even under existing legislation) and may be affected by future legislation or regulations, it is not possible to predict all of the ultimate costs of compliance, including remediation costs that may be incurred and penalties that may be imposed.

        Our environmental capital expenditures are expected to be approximately $438 million or 15 percent of capital expenditures in 2005. Predictions beyond 2005 can only be broad-based estimates, which have varied, and will continue to vary, due to the ongoing evolution of specific regulatory requirements, the possible imposition of more stringent requirements and the availability of new technologies, among other matters. Based on currently identified projects, we anticipate that environmental capital expenditures will be approximately $200 million in 2006; however, actual expenditures may vary as the number and scope of environmental projects are revised as a result of improved technology or changes in regulatory requirements and could increase if additional projects are identified or additional requirements are imposed.

        New Tier II gasoline and on-road diesel fuel rules require substantially reduced sulfur levels for gasoline and diesel starting in 2004 and 2006, respectively. The combined capital costs to achieve compliance with the gasoline and diesel regulations could amount to approximately $900 million over the period between 2002 and 2006 and includes costs that could be incurred as part of other refinery upgrade projects. This is a forward-looking statement. Costs incurred through December 31, 2004, were approximately $520 million. Some factors (among others) that could potentially affect gasoline and diesel fuel compliance costs include completion of project detailed engineering, construction and start-up activities.

        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.

        During 2001, MAP entered into a New Source Review consent decree and settlement of alleged Clean Air Act ("CAA") and other violations with the U. S. Environmental Protection Agency covering all of MAP's refineries. The settlement committed MAP to specific control technologies and implementation schedules for environmental expenditures and improvements to MAP's refineries over approximately an eight-year period. The total one-time expenditures for these environmental projects is approximately $370 million over the eight-year period, with about $240 million incurred through December 31, 2004. The impact of the settlement on ongoing operating expenses is expected to be immaterial. In addition, MAP has nearly completed certain agreed upon supplemental environmental projects as part of this settlement of an enforcement action for alleged CAA violations, at a cost of $9 million. We believe this settlement will provide MAP with increased permitting and operating flexibility while achieving significant emission reductions.

45


Other Contingencies

        We are a defendant along with many other refining companies in over forty cases in eleven states alleging methyl tertiary-butyl ether ("MTBE") contamination in groundwater. The plaintiffs generally are water providers or governmental authorities and they allege that refiners, manufacturers and sellers of gasoline containing MTBE are liable for manufacturing a defective product and that owners and operators of retail gasoline sites have allowed MTBE to be discharged into the groundwater. Several of these lawsuits allege contamination that is outside of our marketing area. A few of the cases seek approval as class actions. Many of the cases seek punitive damages or treble damages under a variety of statutes and theories. We stopped producing MTBE at our refineries in October 2002. The potential impact of these recent cases and future potential similar cases is uncertain. We will defend these cases vigorously.

        We are 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. The ultimate resolution of these contingencies could, individually or in the aggregate, be material to us. However, we believe that we will remain a viable and competitive enterprise even though it is possible that these contingencies could be resolved unfavorably to us. See "Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources."

SEC Inquiry Relating to Equatorial Guinea

        By letter dated July 15, 2004, the United States Securities and Exchange Commission ("SEC") notified Marathon that it was conducting an inquiry into payments made to the government of Equatorial Guinea, or to officials and persons affiliated with officials of the government of Equatorial Guinea. This inquiry follows an investigation and public hearing conducted by the United States Senate Permanent Subcommittee on Investigations, which reviewed the transactions of various foreign governments, including that of Equatorial Guinea, with Riggs Bank. The investigation and hearing also reviewed the operations of U.S. oil companies, including Marathon, in Equatorial Guinea. There was no finding in the Subcommittee's report that Marathon violated the U.S. Foreign Corrupt Practices Act or any other applicable laws or regulations. The investigation is ongoing and Marathon is cooperating fully with the SEC inquiry.

Outlook

Capital, Investment and Exploration Budget

        We approved a capital, investment and exploration budget of $2.98 billion for 2005. The primary focus of the 2005 budget is to find additional oil and gas reserves, develop existing fields, strengthen RM&T assets and continue implementation of the integrated gas strategy. The budget includes worldwide production capital spending of $1.219 billion primarily in U.S, Norway, Russia, Equatorial Guinea, Ireland, and the U.K. The worldwide exploration budget of $364 million includes plans to drill 15 significant exploration wells in the Gulf of Mexico, Angola, Norway and other areas. Other activities will focus on projects primarily in the United States. The budget includes $804 million for RM&T projects, primarily for refinery expansion and upgrading projects, as well as investments necessary to meet required low sulfur (Tier II) gasoline and ultra-low sulfur diesel fuel specifications. The integrated gas budget of $481 million is primarily for the ongoing construction of the LNG plant in Equatorial Guinea. The remaining $111 million balance is designated for corporate activities and capitalized interest.

Exploration and Production

        Our six discoveries in 2004 result from our balanced exploration strategy which places greater emphasis on near-term production and lower risk opportunities, while retaining an appropriate exposure to longer-term options. Major exploration activities, which are currently underway or under evaluation, include those in:

46


        During 2004, we continued to make progress in advancing key development projects that will help serve as the basis for our production growth profile in the coming years. Major development and production activities currently underway or under evaluation include those in:

        The above discussion includes forward-looking statements with respect to the timing and levels of our worldwide liquid hydrocarbon and natural gas production, future exploration and drilling activity, the Alvheim/Vilje developments, the LPG expansion project and the Corrib gas project. Some factors that could potentially affect worldwide liquid hydrocarbon and natural gas and condensate production, the exploration and drilling activities and the Alvheim development include pricing, supply and demand for petroleum products, amount of capital available for exploration and development, occurrence of acquisitions/dispositions of oil and gas properties, regulatory constraints, timing of commencing production from new wells, drilling rig availability, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto, and other geological, operating and economic considerations. In addition to the foregoing factors, the plan for development and operation of the Vilje Field may be affected by delays in obtaining Norwegian regulatory approval. Some factors that could affect the LPG expansion project and the Corrib gas project include unforeseen problems arising from construction and unforeseen hazards such as weather conditions. The forward-looking information related to production is based on certain assumptions, including, among others, presently known physical data concerning size and character of reservoirs, economic recoverability, technology development, future drilling success, production experience, industry economic conditions, levels of cash flow from operations and operating conditions. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

47


Refining, Marketing and Transportation

        Throughout 2004, MAP remained focused on its strategy of leveraging refining and marketing investments in core markets, as well as expanding and enhancing its asset base while controlling costs. The record refinery throughput performance was achieved even though the company had undertaken a significant number of planned turnarounds during the first quarter of 2004 at the Garyville, Louisiana; Catlettsburg, Kentucky; and Canton, Ohio, refineries. Assuming refining margins remain strong in 2005, we expect MAP's 2005 average crude oil throughput to exceed that achieved in 2004.

        The Detroit refinery expansion project remains on schedule for completion in late 2005. This project will increase the refinery's crude processing capacity from 74,000 bpd to 100,000 bpd as well as enable the refinery to produce new clean fuels and further control regulated air emissions. Marathon is loaning MAP the funds necessary for these upgrade and expansion projects.

        On March 18, 2004, we entered into an agreement with Ashland Inc. to acquire its 38 percent interest in MAP, along with a portion of its Valvoline Instant Oil Change business and its maleic anhydride business. The proposed transaction is subject to a number of conditions, including favorable private letter rulings from the Internal Revenue Service ("IRS"), opinions of outside tax counsel, Ashland shareholder approval, Ashland public debt holder consents, and updated Ashland solvency opinions. With respect to the tax treatment of the transaction, Marathon and Ashland are discussing with the IRS possible modifications of the transaction that would allow a tax efficient transfer of the MAP interest. Any such modifications would require Marathon and Ashland to amend the Master Agreement executed by the parties on March 18, 2004. However, there can be no assurance that an agreement on a modified transaction will be reached. If an agreement is reached on a modified transaction, it is likely the transaction would close in the second quarter of 2005. For additional information, see Note 29 to the Consolidated Financial Statements.

        The above discussion includes forward-looking statements with respect to projections of crude oil throughput, the Detroit refinery expansion project, the proposed acquisition of Ashland's 38 percent interest in MAP and other related businesses and the anticipated effects of private letter rulings from the IRS with respect to the tax treatment of the MAP transaction. Some factors that could affect crude oil throughput include planned and unplanned refinery maintenance projects, the level of refining margins, and other operating considerations. The Detroit refinery expansion project may be affected by the availability of materials and labor, unforeseen hazards such as weather conditions, and other risks customarily associated with construction projects. Some factors that could affect the completion of the acquisition of Ashland's 38 percent interest in MAP and other related businesses include modifications to the transaction, an adverse ruling from the IRS regarding certain tax basis issues, opinions of outside tax counsel, Ashland shareholder approval, Ashland public debt holder consents and updated Ashland solvency opinions. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Integrated Gas

        We continued to progress our integrated gas strategy throughout the year. This strategy is designed to complement our exploration and production operations focusing on accessing low cost stranded natural gas resources and adding value by applying technology and commercial skills to connect those resources to the major consuming markets.

        Construction of the Equatorial Guinea LNG project is on schedule for shipment of first cargoes of LNG in late 2007. This project is expected to be one of the lowest cost LNG operations in the Atlantic basin with an all-in LNG operating, capital and feedstock cost of approximately $1 per million British thermal units ("mmbtu") at the loading flange of the LNG plant. Efforts are underway to acquire additional gas supply and expand the utilization of this LNG facility above and beyond the contract to supply 3.4 million metric tons per year to BG Gas Marketing Ltd. for 17 years. We also are seeking additional natural gas supplies in the area to expand the capacity and life of this plant and that could lead to the development of a second LNG train.

        Under the five year BP supply agreement, we will begin taking delivery of LNG at the Elba Island, Georgia, LNG regasification terminal during the second half of 2005. At the Elba Island terminal, we hold rights to deliver and sell up to 58 bcf of natural gas per year through 2021, with an option to extend for five years. 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 LNG cargoes before the start of deliveries from BP.

48



        In 2005, we plan to continue exploring and investing in gas technology research, including GTL technology, which was successfully applied in the Catoosa GTL demonstration plant in 2004. In addition to GTL, we are researching and developing expertise in methanol to power, gas to gasoline and compressed natural gas technologies.

        The above discussion contains forward-looking statements with respect to the estimated construction of a LNG project. Factors that could affect the proposed LNG project and related facilities include unforeseen problems arising from construction, inability or delay in obtaining necessary government and third-party approvals, unanticipated changes in market demand or supply, environmental issues, availability or construction of sufficient LNG vessels, and unforeseen hazards such as weather conditions. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Corporate Matters

        In 2004, as part of ongoing business transformation programs, we implemented two outsourcing agreements to achieve further business process improvements and cost reductions. It is anticipated that these programs will result in total pretax charges of approximately $70 million. Of these charges, $24 million was recorded in 2003 and $43 million was recorded in 2004, including net settlement and curtailment gains of $10 million in 2003 and losses of $20 million in 2004, on employee benefit plans. Projected savings from the business transformation programs are expected to benefit all business segments.

Accounting Standards Not Yet Adopted

        During December 2004, the FASB issued Statement of Financial Accounting Standard No. 123 (revised 2004) "Share-Based Payment" ("SFAS No. 123R") as a revision of Statement of Financial Accounting Standard No. 123 "Accounting for Stock Based Compensation". This statement requires entities to measure the cost of employee services received in exchange for an award of equity instruments based on the fair value of the award on the grant date. That cost will be recognized over the period during which an employee is required to provide service in exchange for the award, usually the vesting period. In addition, liability awards will be remeasured each reporting period. In 2003, Marathon adopted the fair value method for grants made, modified or settled on or after January 1, 2003. Accordingly, management does not expect the adoption of SFAS No. 123R to have a material affect on results of operations, financial position or cash flows. This statement is effective for Marathon on July 1, 2005. Marathon has not yet determined whether to adopt this standard earlier than the effective date.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Management Opinion Concerning Derivative Instruments

        Management has authorized the use of futures, forwards, swaps and options to manage exposure to market fluctuations in commodity prices, interest rates, and foreign currency exchange rates.

        We use commodity-based derivatives to manage price risk related to the purchase, production or sale of crude oil, natural gas, and refined products. To a lesser extent, we are exposed to the risk of price fluctuations on natural gas liquids and on petroleum feedstocks used as raw materials.

        Our strategy has generally been to obtain competitive prices for our products and allow operating results to reflect market price movements dictated by supply and demand. We will use a variety of derivative instruments, including option combinations, as part of the overall risk management program to manage commodity price risk in our different businesses. As market conditions change, we evaluate our risk management program and could enter into strategies that assume market risk whereby cash settlement of commodity-based derivatives will be based on market prices.

        Our E&P segment primarily uses commodity derivative instruments selectively to protect against price decreases on portions of our future production when deemed advantageous to do so. We also use financial derivative instruments to manage foreign currency exchange rate exposure on foreign currency denominated capital investment expenditures, operating expenses and foreign tax payments.

        Our RM&T segment uses commodity derivative instruments:

        Our IG segment is exposed to market risk associated with the purchase and subsequent resale of natural gas. We use commodity derivative instruments to mitigate the price risk on purchased volumes and anticipated sales volumes.

        We use financial derivative instruments to manage interest rate and foreign currency exchange rate exposures. As we enter into these derivatives, assessments are made as to the qualification of each transaction for hedge accounting.

        We believe that use of derivative instruments along with risk assessment procedures and internal controls does not expose us to material risk. However, the use of derivative instruments could materially affect our results of operations in particular quarterly or annual periods. We believe that use of these instruments will not have a material adverse effect on financial position or liquidity.

50


Commodity Price Risk

        Sensitivity analyses of the incremental effects on income from operations ("IFO") of hypothetical 10 percent and 25 percent changes in commodity prices for open derivative commodity instruments as of December 31, 2004 and December 31, 2003, are provided in the following table:(a)

(In millions)

   
   
   
   
 

 
Derivative Commodity Instruments(b)(c)     10%     25%     10%     25%  

 
Crude oil(d)   $ 1.3 (e) $ –     $ 28.3 (e) $ 87.9 (e)
Natural gas(e)     36.3 (e)   90.7 (e)   29.1 (e)   73.5 (e)
Refined products(e)     2.6 (f)   7.4 (f)   3.6 (e)   9.1 (e)

 
(a)
We remain at risk for future changes in the market value of derivative instruments; however, such risk should be mitigated by price changes in the underlying hedged item. Effects of these offsets are not reported in the sensitivity analyses. Amounts assume hypothetical 10 percent and 25 percent changes in closing commodity prices, excluding basis swaps, for each open contract position at December 31, 2004 and 2003. We evaluate our portfolio of derivative commodity instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles. We are also exposed to credit risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is reviewed continuously and master netting agreements are used when practical. Changes to the portfolio after December 31, 2004, would cause future IFO effects to differ from those presented in the table.
(b)
Net open contracts for the combined E&P and IG segments varied throughout 2004, from a low of 1 contract at December 15 to a high of 39,683 contracts at January 1, and averaged 19,344 for the year. The number of net open contracts for the RM&T segment varied throughout 2004, from a low of 253 contracts at July 7 to a high of 23,138 contracts at October 13, and averaged 11,437 for the year. The derivative commodity instruments used and hedging positions taken will vary and, because of these variations in the composition of the portfolio over time, the number of open contracts by itself cannot be used to predict future income effects.
(c)
The calculation of sensitivity amounts for basis swaps assumes that the physical and paper indices are perfectly correlated. Gains and losses on options are based on changes in intrinsic value only.
(d)
The direction of the price change used in calculating the sensitivity amount for each commodity is based on the largest incremental decrease in IFO when applied to the derivative commodity instruments used to hedge that commodity.
(e)
Price increase.
(f)
Price decrease.

E&P Segment

        Derivative losses included in the E&P segment were $169 million in 2004 compared to losses of $110 million in 2003 and gains of $34 million in 2002. Additionally, losses from discontinued cash flow hedges of $3 million are included in 2004 segment results, compared to losses of $8 million in 2003 and gains of $23 million in 2002. The discontinued cash flow hedge amounts were reclassified from accumulated other comprehensive income (loss) as it was no longer probable that the original forecasted transactions would occur.

        Excluded from the E&P segment results were losses of $99 million in 2004, losses of $66 million in 2003 and gains of $18 million in 2002 on long-term gas contracts in the United Kingdom that are accounted for as derivative instruments. For additional information on U.K. gas contracts, see "Estimated Fair Value of Derivative Contracts" on page 31.

        At December 31, 2004, we had no open equity production derivative contracts. We evaluate the commodity price risk of our equity production on an ongoing basis and may enter into commodity derivative instruments when it is deemed advantageous.

51


RM&T Segment

        We do not attempt to qualify commodity derivative instruments used in our RM&T operations for hedge accounting. As a result, we recognize all changes in the fair value of derivatives used in our RM&T operations in income, although most of these derivatives have an underlying physical commodity transaction. Generally, derivative losses occur when market prices increase, which are offset by gains on the underlying physical commodity transactions. Conversely, derivative gains occur when market prices decrease, which are offset by losses on the underlying physical commodity transactions. Derivative gains or losses included in RM&T segment income for each of the last three years are summarized in the following table:

Strategy (In Millions)

  2004

  2003

  2002

 

 
Mitigate price risk   $ (106 ) $ (112 ) $ (95 )
Protect carrying values of excess inventories     (98 )   (57 )   (41 )
Protect margin on fixed price sales     8     5     11  
Protect crack spread values     (76 )   6     1  
Trading activities     8     (4 )   –    
   
 
 
 
  Total net derivative losses   $ (264 ) $ (162 ) $ (124 )

 

        During 2004, using derivative instruments MAP sold crack spreads forward through the fourth quarter 2005 at values higher than the company thought sustainable in the actual months these contracts expire. Included in the $76 million derivative loss for 2004 noted in the above table for the "Protect crack spread values" strategy was approximately an $8 million gain due to changes in the fair value of crack-spread derivatives that will expire throughout 2005.

        In addition, natural gas options are in place to manage the price risk associated with approximately 41 percent of the first quarter 2005 anticipated natural gas purchases for refinery use.

IG Segment

        We have used derivative instruments to convert the fixed price of a long-term gas sales contract to market prices. The underlying physical contract is for a specified annual quantity of gas and matures in 2008. Similarly, we will use derivative instruments to convert shorter term (typically less than a year) fixed price contracts to market prices in our ongoing purchase for resale activity; and to hedge purchased gas injected into storage for subsequent resale. Derivative gains included in IG segment income were $17 million in 2004, compared to gains of $19 million in 2003 and losses of $8 million in 2002. Trading activity in the IG segment resulted in losses of $2 million in 2004, compared to losses of $7 million in 2003 and gains of $4 million in 2002 and have been included in the aforementioned amounts.

Other Commodity Risk

        We are impacted by basis risk, caused by factors that affect the relationship between commodity futures prices reflected in derivative commodity instruments and the cash market price of the underlying commodity. Natural gas transaction prices are frequently based on industry reference prices that may vary from prices experienced in local markets. For example, New York Mercantile Exchange ("NYMEX") contracts for natural gas are priced at Louisiana's Henry Hub, while the underlying quantities of natural gas may be produced and sold in the western United States at prices that do not move in strict correlation with NYMEX prices. If commodity price changes in one region are not reflected in other regions, derivative commodity instruments may no longer provide the expected hedge, resulting in increased exposure to basis risk. These regional price differences could yield favorable or unfavorable results. OTC transactions are being used to manage exposure to a portion of basis risk.

        We are impacted by liquidity risk, caused by timing delays in liquidating contract positions due to a potential inability to identify a counterparty willing to accept an offsetting position. Due to the large number of active participants, liquidity risk exposure is relatively low for exchange-traded transactions.

52


Interest Rate Risk

        We are impacted by interest rate fluctuations which affect the fair value of certain financial instruments. A sensitivity analysis of the projected incremental effect of a hypothetical 10 percent decrease in interest rates is provided in the following table:

(In millions)

   
   
   
   
 

 
Financial Instruments(a)     Fair
Value(b)
    Incremental
Increase in
Fair Value(c)
    Fair
Value(b)
    Incremental
Increase in
Fair Value(c)
 

 
Financial assets (liabilities):                          
  Investments and long-term receivables   $ 266   $ –     $ 186   $ –    
  Interest rate swap agreements   $ (10 ) $ 14   $ 4   $ 16  
  Long-term debt(d)(e)   $ (4,480 ) $ (164 ) $ (4,740 ) $ (176 )

 
(a)
Fair values of cash and cash equivalents, receivables, notes payable, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.
(b)
See Note 17 and 18 to the Consolidated Financial Statements for carrying value of instruments.
(c)
For long-term debt, this assumes a 10 percent decrease in the weighted average yield to maturity of our long-term debt at December 31, 2004 and 2003. For interest rate swap agreements, this assumes a 10 percent decrease in the effective swap rate at December 31, 2004 and 2003.
(d)
Includes amounts due within one year.
(e)
Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.

        At December 31, 2004 and 2003, our portfolio of long-term debt was substantially comprised of fixed rate instruments. Therefore, the fair value of the portfolio is relatively sensitive to effects of interest rate fluctuations. This sensitivity is illustrated by the $164 million increase in the fair value of long-term debt assuming a hypothetical 10 percent decrease in interest rates. However, our sensitivity to interest rate declines and corresponding increases in the fair value of our debt portfolio would unfavorably affect our results and cash flows only if we would elect to repurchase or otherwise retire all or a portion of its fixed-rate debt portfolio at prices above carrying value.

        We have initiated a program to manage our exposure to interest rate movements by utilizing financial derivative instruments. The primary objective of this program is to reduce our overall cost of borrowing by managing the fixed and floating interest rate mix of the debt portfolio. We have entered into several interest rate swap agreements, designated as fair value hedges, which effectively resulted in an exchange of existing obligations to pay fixed interest rates for obligations to pay floating rates. The following table summarizes, by individual debt instrument, the interest rate swap activity as of December 31, 2004:

Floating Rate to be Paid

  Fixed Rate
to be
Received

  Notional
Amount

  Swap
Maturity

  Fair Value


Six Month LIBOR +4.226%   6.650 % $300 million   2006   $(2) million
Six Month LIBOR +1.935%   5.375 % $450 million   2007   $(1) million
Six Month LIBOR +3.285%   6.850 % $400 million   2008   $(2) million
Six Month LIBOR +2.142%   6.125 % $200 million   2012   $(5) million

53


Foreign Currency Exchange Rate Risk

        We manage our exposure to foreign currency exchange rates by utilizing forward contracts, generally with terms of 365 days or less. The primary objective of this program is to reduce our exposure to movements in the foreign currency markets by locking in foreign currency rates. At December 31, 2004, the following commodity derivatives were outstanding. All contracts currently qualify for hedge accounting unless noted.

Financial Instruments

  Period

  Notional Amount

  All-in-Rate(a)

  Fair Value


Foreign Currency Rate Swaps                
  Euro   January 2005 – July 2005   $89 million   1.257 (c) $7 million
  Norwegian kroner   January 2005 – December 2005   $49 million (b) 6.213 (d) $1 million
  British pound sterling   January 2005 – September 2005   $6 million   1.759 (c) $1 million

(a)
The rate at which the derivative instruments will be settled.
(b)
On December 31, 2004, $18 million was discontinued and no longer qualified for hedge accounting. On January 31, 2005, this amount was re-qualified for hedge accounting.
(c)
U.S. dollar to foreign currency.
(d)
Foreign currency to U.S. dollar.

        The aggregate effect on foreign exchange contracts of a hypothetical 10 percent change to year-end exchange rates would be approximately $15 million.

Credit Risk

        We are exposed to significant credit risk from United States Steel arising from the Separation. That exposure is discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations – Obligations Associated with the Separation of United States Steel" on page 42.

Safe Harbor

        These quantitative and qualitative disclosures about market risk include forward-looking statements with respect to management's opinion about risks associated with the use of derivative instruments. These statements are based on certain assumptions with respect to market prices and industry supply of and demand for crude oil, natural gas, refined products and other feedstocks. If these assumptions prove to be inaccurate, future outcomes with respect to our hedging programs may differ materially from those discussed in the forward-looking statements.

54


Item 8. Consolidated Financial Statements and Supplementary Data

    MARATHON OIL CORPORATION

 
Management's Responsibilities for Financial Statements

Management's Report on Internal Control over Financial Reporting

Report of Independent Registered Public Accounting Firm

Audited Consolidated Financial Statements:
 
Consolidated Statement of Income
 
Consolidated Balance Sheet
 
Consolidated Statement of Cash Flows
 
Consolidated Statement of Stockholders' Equity
 
Notes to Consolidated Financial Statements

Selected Quarterly Financial Data (Unaudited)

Principal Unconsolidated Investees (Unaudited)

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Five-Year Operating Summary

Five-Year Selected Financial Data

F-1



                   Management's Responsibilities for Financial Statements

SIGNATURE   SIGNATURE   SIGNATURE
Clarence P. Cazalot, Jr.   Janet F. Clark   Albert G. Adkins
President and   Senior Vice President   Vice President –
Chief Executive Officer   and Chief Financial Officer   Accounting and Controller


                   Management's Report on Internal Control over Financial Reporting

SIGNATURE   SIGNATURE    
Clarence P. Cazalot, Jr.   Janet F. Clark    
President and   Senior Vice President    
Chief Executive Officer   and Chief Financial Officer    

F-2



                   Report of Independent Registered Public Accounting Firm

                   Consolidated financial statements

                   Internal control over financial reporting

F-3



                   
Consolidated Statement of Income

(Dollars in millions except per share data)

  2004
  2003
  2002
 

 
Revenues and other income:                    
  Sales and other operating revenues (including consumer excise taxes)   $ 39,383   $ 32,884   $ 25,946  
  Revenues from matching buy/sell transactions     9,164     7,158     4,480  
  Sales to related parties     1,051     921     869  
  Income from equity method investments     170     29     137  
  Net gains on disposal of assets     36     166     67  
  Gain (loss) on ownership changes in Marathon Ashland Petroleum LLC     2     (1 )   12  
  Other income     101     77     44  
   
 
 
 
      Total revenues and other income     49,907     41,234     31,555  
   
 
 
 
Costs and expenses:                    
  Cost of revenues (excludes items shown below)     30,740     24,918     18,878  
  Purchases related to matching buy/sell transactions     9,050     7,195     4,514  
  Purchases from related parties     202     209     193  
  Consumer excise taxes     4,463     4,285     4,250  
  Depreciation, depletion and amortization     1,217     1,144     1,151  
  Selling, general and administrative expenses     1,025     920     823  
  Other taxes     338     299     255  
  Exploration expenses     202     180     192  
  Inventory market valuation credit     –       –       (71 )
   
 
 
 
      Total costs and expenses     47,237     39,150     30,185  
   
 
 
 
Income from operations     2,670     2,084     1,370  
Net interest and other financing costs     161     186     268  
Loss from early extinguishment of debt     –       –       53  
Minority interest in income (loss) of:                    
  Marathon Ashland Petroleum LLC     532     302     173  
  Equatorial Guinea LNG Holdings Limited     (7 )   –       –    
   
 
 
 
Income from continuing operations before income taxes     1,984     1,596     876  
Provision for income taxes     727     584     369  
   
 
 
 
Income from continuing operations     1,257     1,012     507  

Discontinued operations

 

 

4

 

 

305

 

 

(4

)
   
 
 
 
Income before cumulative effect of changes in accounting principles     1,261     1,317     503  
Cumulative effect of changes in accounting principles     –       4     13  
   
 
 
 
Net income   $ 1,261   $ 1,321   $ 516  

 

Per Share Data

 

 

 

 

 

 

 

 

 

 
  Basic                    
    Income from continuing operations   $ 3.74   $ 3.26   $ 1.63  
   
 
 
 
    Net income   $ 3.75   $ 4.26   $ 1.66  
 
Diluted

 

 

 

 

 

 

 

 

 

 
    Income from continuing operations   $ 3.72   $ 3.26   $ 1.63  
   
 
 
 
    Net income   $ 3.73   $ 4.26   $ 1.66  

 

F-4



                   
Consolidated Balance Sheet

(Dollars in millions)

  December 31
  2004
  2003
 

 
Assets                  
Current assets:                  
  Cash and cash equivalents       $ 3,369   $ 1,396  
  Receivables, less allowance for doubtful accounts of $6 and $5         3,146     2,389  
  Receivables from United States Steel         15     20  
  Receivables from related parties         74     121  
  Inventories         1,995     1,955  
  Other current assets         268     163  
       
 
 
      Total current assets         8,867     6,044  
Investments and long-term receivables, less allowance for doubtful accounts of $10 and $10         1,546     1,323  
Receivables from United States Steel         587     593  
Property, plant and equipment – net         11,810     10,830  
Prepaid pensions         128     181  
Goodwill         252     252  
Intangibles         108     118  
Other noncurrent assets         125     141  
       
 
 
      Total assets       $ 23,423   $ 19,482  

 
Liabilities                  
Current liabilities:                  
  Accounts payable       $ 4,430   $ 3,352  
  Payables to United States Steel         –       4  
  Payables to related parties         44     17  
  Payroll and benefits payable         274     230  
  Accrued taxes         397     247  
  Accrued interest         92     85  
  Long-term debt due within one year         16     272  
       
 
 
      Total current liabilities         5,253     4,207  
Long-term debt         4,057     4,085  
Deferred income taxes         1,553     1,489  
Employee benefit obligations         989     990  
Asset retirement obligations         477     390  
Payables to United States Steel         5     8  
Deferred credits and other liabilities         288     227  
       
 
 
      Total liabilities         12,622     11,396  
Minority interest in Marathon Ashland Petroleum LLC         2,559     2,011  
Minority interest in Equatorial Guinea LNG Holdings Limited         131     –    
Commitments and contingencies         –       –    

Stockholders' Equity

 

 

 

 

 

 

 

 

 
Common Stock issued – 346,727,029 shares at December 31, 2004 and 312,165,978 shares at December 31, 2003 (par value $1 per share, authorized 550,000,000 shares)         347     312  
Common Stock held in treasury – 29,569 shares at December 31, 2004 and 1,744,370 shares at December 31, 2003         (1 )   (46 )
Additional paid-in capital         4,028     3,033  
Retained earnings         3,810     2,897  
Accumulated other comprehensive loss         (64 )   (112 )
Unearned compensation         (9 )   (9 )
       
 
 
      Total stockholders' equity         8,111     6,075  
       
 
 
      Total liabilities and stockholders' equity       $ 23,423   $ 19,482  

 

                     The accompanying notes are an integral part of these consolidated financial statements.

F-5



                   
Consolidated Statement of Cash Flows

(Dollars in millions)

  2004
  2003
  2002
 

 
Increase (decrease) in cash and cash equivalents                    
Operating activities:                    
Net income   $ 1,261   $ 1,321   $ 516  
Adjustments to reconcile to net cash provided from operating activities:                    
  Cumulative effect of changes in accounting principles     –       (4 )   (13 )
  Loss (income) from discontinued operations     (4 )   (305 )   4  
  Deferred income taxes     (73 )   71     77  
  Minority interest in income of subsidiaries     525     302     173  
  Loss from early extinguishment of debt     –       –       53  
  Depreciation, depletion and amortization     1,217     1,144     1,151  
  Pension and other postretirement benefits – net     82     68     87  
  Inventory market valuation credit     –       –       (71 )
  Exploratory dry well costs and unproved property impairments     106     86     116  
  Net gains on disposal of assets     (36 )   (166 )   (67 )
  Impairment of investments     –       129     –    
  Changes in the fair value of long-term natural gas contracts in the United Kingdom     99     66     (18 )
  Changes in: Current receivables     (709 )   (671 )   (103 )
                          Inventories     (41 )   33     (53 )
                          Accounts payable and other current liabilities     1,224     496     614  
  All other – net     79     95     (135 )
   
 
 
 
    Net cash provided from continuing operations     3,730     2,665     2,331  
    Net cash provided from discontinued operations     –       83     69  
   
 
 
 
    Net cash provided from operating activities     3,730     2,748     2,400  
   
 
 
 
Investing activities:                    
Capital expenditures     (2,237 )   (1,892 )   (1,520 )
Acquisitions     –       (252 )   (1,160 )
Disposal of discontinued operations     –       612     54  
Disposal of assets     76     644     146  
Restricted cash – withdrawals     34     146     91  
                              – deposits     (42 )   (108 )   (123 )
Investments – contributions     (4 )   (34 )   (111 )
                        – loans and advances     (156 )   (91 )   –    
                        – returns and repayments     40     55     10  
All other – net     1     (19 )   –    
Investing activities of discontinued operations     –       (29 )   (48 )
   
 
 
 
    Net cash used in investing activities     (2,288 )   (968 )   (2,661 )
   
 
 
 
Financing activities:                    
Commercial paper and revolving credit arrangements – net     –       (131 )   (375 )
Debt issuance costs     (4 )   –       –    
Other debt – borrowings     –       –       1,828  
                      – repayments     (259 )   (208 )   (604 )
Net proceeds from sale of common stock     1,004     –       –    
Redemption of preferred stock of subsidiary     –       –       (185 )
Preferred stock repurchased     –       –       (110 )
Treasury common stock – proceeds from issuances     43     17     2  
                                               – purchases     (4 )   (6 )   (7 )
Dividends paid     (348 )   (298 )   (285 )
Contributions from minority shareholder of Equatorial Guinea LNG Holdings Limited     95     –       –    
Distributions to minority shareholder of Marathon Ashland Petroleum LLC     –       (262 )   (176 )
   
 
 
 
        Net cash provided from (used in) financing activities     527     (888 )   88  
   
 
 
 
Effect of exchange rate changes on cash:                    
  Continuing operations     4     8     4  
  Discontinued operations     –       8     –    
   
 
 
 
Net increase (decrease) in cash and cash equivalents     1,973     908     (169 )
Cash and cash equivalents at beginning of year     1,396     488     657  
   
 
 
 
Cash and cash equivalents at end of year   $ 3,369   $ 1,396   $ 488  

 

                     The accompanying notes are an integral part of these consolidated financial statements.

F-6



                   
Consolidated Statement of Stockholders' Equity

 
  Stockholder's Equity
  Shares in thousands
 
(Dollars in millions)

  2004
  2003
  2002
  2004
  2003
  2002
 

 
Common stock:                                      
  Balance at beginning of year   $ 312   $ 312   $ 312     312,166     312,166     312,166  
  Issuance(a)     35     –       –       34,552     –       –    
   
 
 
 
 
 
 
  Balance at end of year   $ 347   $ 312   $ 312     346,718     312,166     312,166  

 
Treasury common stock, at cost:                                      
  Balance at beginning of year   $ (46 ) $ (60 ) $ (74 )   (1,744 )   (2,293 )   (2,771 )
  Repurchased     (4 )   (6 )   (7 )   (124 )   (219 )   (297 )
  Reissued for:                                      
    Employee stock plans     49     20     19     1,838     768     727  
    Non-employee directors deferred compensation plan     –       –       2     –       –       48  
   
 
 
 
 
 
 
  Balance at end of year   $ (1 ) $ (46 ) $ (60 )   (30 )   (1,744 )   (2,293 )

 
 
   
   
   
  Comprehensive Income
 

 


 

 


 

 


 

 


 

2004

 

2003

 

2002

 

 
Additional paid-in capital:                                      
  Balance at beginning of year   $ 3,033   $ 3,032   $ 3,035                    
  Common stock issuance(a)     970     –       –                      
  Treasury common stock reissued     25     1     (3 )                  
   
 
 
                   
  Balance at end of year   $ 4,028   $ 3,033   $ 3,032                    

                   
Unearned compensation:                                      
  Balance at beginning of year   $ (9 ) $ (7 ) $ (10 )                  
  Change during year     –       (2 )   3                    
   
 
 
                   
  Balance at end of year   $ (9 ) $ (9 ) $ (7 )                  

                   
Retained earnings:                                      
  Balance at beginning of year   $ 2,897   $ 1,874   $ 1,643                    
  Net income     1,261     1,321     516   $ 1,261   $ 1,321   $ 516  
  Dividends paid: (per share: $1.03 in 2004, $.96 in 2003 and $.92 in 2002)     (348 )   (298 )   (285 )                  
   
 
 
                   
  Balance at end of year   $ 3,810   $ 2,897   $ 1,874                    

                   
Accumulated other comprehensive income (loss)(b):                                      
  Minimum pension liability adjustments:                                      
    Balance at beginning of year   $ (93 ) $ (47 ) $ (14 )                  
    Changes during year     22     (46 )   (33 )   22     (46 )   (33 )
   
 
 
                   
    Balance at end of year   $ (71 ) $ (93 ) $ (47 )                  
   
 
 
                   
  Foreign currency translation adjustments:                                      
    Balance at beginning of year   $ (4 ) $ (1 ) $ (3 )                  
    Changes during year     (1 )   (3 )   2     (1 )   (3 )   2  
   
 
 
                   
    Balance at end of year   $ (5 ) $ (4 ) $ (1 )                  
 
Deferred gains (losses) on derivative instruments:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 
    Balance at beginning of year   $ (15 ) $ (21 ) $ 51                    
    Reclassification of the cumulative effect adjustment into income     (3 )   (3 )   (1 )   (3 )   (3 )   (1 )
    Changes in fair value     (82 )   (50 )   (36 )   (82 )   (50 )   (36 )
    Reclassification to income     112     59     (35 )   112     59     (35 )
   
 
 
                   
    Balance at end of year   $ 12   $ (15 ) $ (21 )                  
   
 
 
                   
      Total balances at end of year   $ (64 ) $ (112 ) $ (69 )                  

 
        Total comprehensive income                     $ 1,309   $ 1,278   $ 413  

 
Total stockholders' equity   $ 8,111   $ 6,075   $ 5,082                    

                   
(a) On March 31, 2004, Marathon issued 34,500,000 shares of its common stock at the offering price of $30 per share
    and recorded net proceeds of $1.004 billion.
 
(b) Related income tax provision (credit) on changes
    and reclassifications during the year:
  2004
  2003
  2002
                   
    Minimum pension liability adjustments   $ 3   $ (25 ) $ (18 )                  
    Foreign currency translation adjustments     –       (2 )   2                    
    Net deferred gains (losses) on derivative instruments     9     3     (39 )                  

F-7


                   Notes to Consolidated Financial Statements

1. Summary of Principal Accounting Policies


F-8


F-9


(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?

F-10


F-11


F-12


F-13


(In millions, except per share data)

  2004
  2003
  2002
 

 
Net income applicable to Common Stock                    
  As reported   $ 1,261   $ 1,321   $ 516  
  Add: Stock-based employee compensation expense included in reported net income, net of related tax effects     39     23     5  
  Deduct: Total stock-based employee compensation expense determined under fair value method for all awards, net of related tax effects     (32 )   (17 )   (16 )
   
 
 
 
Pro forma net income applicable to Common Stock   $ 1,268   $ 1,327   $ 505  
   
 
 
 
Basic net income per share                    
  – As reported   $ 3.75   $ 4.26   $ 1.66  
  – Pro forma   $ 3.77   $ 4.28   $ 1.63  
Diluted net income per share                    
  – As reported   $ 3.73   $ 4.26   $ 1.66  
  – Pro forma   $ 3.75   $ 4.28   $ 1.63  

 
(In millions, except per share data)

  2004
  2003
  2002
 

 
Weighted-average grant-date exercise price per share   $ 33.61   $ 25.58   $ 28.12  
Expected annual dividends per share   $ 1.00   $ .97   $ .92  
Expected life in years     5.5     5     5  
Expected volatility     32 %   34 %   35 %
Risk free interest rate     3.9 %   3.0 %   4.5 %

 
Weighted-average grant-date fair value of options granted during the year, as calculated from above   $ 8.83   $ 5.37   $ 7.79  

 

2. New Accounting Standards

F-14


3. Information about United States Steel

F-15


(In millions)                  December 31

  2004
  2003

Receivables:            
  Current:            
    Receivables related to debt and other obligations for which United States Steel has assumed responsibility for repayment   $ 15   $ 20
   
 
  Noncurrent:            
    Receivables related to debt and other obligations for which United States Steel has assumed responsibility for repayment   $ 587   $ 593
   
 
Payables:            
  Current:            
    Income tax settlement and related interest payable   $ –     $ 4
   
 
  Noncurrent:            
    Reimbursements payable under nonqualified employee benefit plans   $ 5   $ 8

F-16


4. Related Party Transactions

(In millions)

  2004
  2003
  2002

Ashland   $ 274   $ 258   $ 218
Equity investees:                  
  Pilot Travel Centers LLC ("PTC")     715     635     645
  Centennial Pipeline LLC ("Centennial")     49     16     –  
  Other     13     12     6
   
 
 
    Total   $ 1,051   $ 921   $ 869

(In millions)

  2004
  2003
  2002

Ashland   $ 22   $ 24   $ 33
Equity investees                  
  Centennial     56     49     16
  Other     124     136     144
   
 
 
    Total   $ 202   $ 209   $ 193

(In millions)            December 31

  2004
  2003

Ashland   $ 18   $ 22
Equity investees:            
  PTC     19     16
  Alba Plant LLC and related companies(a)     17     73
  Centennial     16     7
  Other     4     3
   
 
    Total   $ 74   $ 121

(a)
Receivables relate to invoices paid by Marathon on behalf of Alba Plant LLC.
(In millions)            December 31

  2004
  2003

Ashland   $ –     $ 1
GEPetrol     23     –  
Equity investees            
  Centennial     12     10
  Other     9     6
   
 
    Total   $ 44   $ 17

F-17


5. Business Combinations

(In millions)

   

Cash   $ 2
Receivables     10
Inventories     3
Investments and long-term receivables     19
Property, plant and equipment     325
Other assets     5
   
  Total assets acquired   $ 364
   
Current liabilities   $ 20
Long-term debt     31
Asset retirement obligations     12
Deferred income taxes     45
Other liabilities     2
   
  Total liabilities assumed   $ 110
   
Net assets acquired   $ 254

(In millions, except per share amounts)

  2003

Revenues and other income   $ 41,257
Income from continuing operations     1,005
Net income     1,314
Per share amounts applicable to Common Stock      
  Income from continuing operations – basic and diluted     3.24
  Net income – basic and diluted     4.23

F-18


6. Discontinued Operations

7. Income Per Common Share

 
  2004
  2003
  2002
 
(Dollars in millions, except per share data)

  Basic
  Diluted
  Basic
  Diluted
  Basic
  Diluted
 

 
Income from continuing operations   $ 1,257   $ 1,257   $ 1,012   $ 1,012   $ 507   $ 507  
Income (loss) from discontinued operations     4     4     305     305     (4 )   (4 )
Cumulative effect of change in accounting principle     –       –       4     4     13     13  
   
 
 
 
 
 
 
Net income   $ 1,261   $ 1,261   $ 1,321   $ 1,321   $ 516   $ 516  
   
 
 
 
 
 
 
Shares of common stock outstanding (thousands):                                      
  Average number of common shares outstanding     336,485     336,485     310,129     310,129     309,792     309,792  
  Effect of dilutive securities – stock options     –       1,768     –       197     –       159  
   
 
 
 
 
 
 
  Average common shares including dilutive effect     336,485     338,253     310,129     310,326     309,792     309,951  
   
 
 
 
 
 
 
Per share:                                      
  Income from continuing operations   $ 3.74   $ 3.72   $ 3.26   $ 3.26   $ 1.63   $ 1.63  
   
 
 
 
 
 
 
  Income (loss) from discontinued operations   $ .01   $ .01   $ .99   $ .99   $ (.01 ) $ (.01 )
   
 
 
 
 
 
 
  Cumulative effect of change in accounting principle   $ –     $ –     $ .01   $ .01   $ .04   $ .04  
   
 
 
 
 
 
 
  Net income   $ 3.75   $ 3.73   $ 4.26   $ 4.26   $ 1.66   $ 1.66  

 

8. Segment Information

(In millions)

  2004
  2003
  2002

Refined products   $ 29,780   $ 24,092   $ 19,729
Merchandise     2,489     2,395     2,521
Liquid hydrocarbons     13,860     10,500     6,517
Natural gas     3,266     3,796     2,362
Transportation and other products     203     180     166
   
 
 
  Total   $ 49,598   $ 40,963   $ 31,295

(In millions)

  2004
  2003
  2002

Refined products   $ 1,226   $ 826   $ 771
Liquid hydrocarbons     7,938     6,332     3,709
   
 
 
  Total   $ 9,164   $ 7,158   $ 4,480

F-19


(In millions)

  Exploration
and
Production

  Refining,
Marketing and
Transportation

  Integrated
Gas

  Total

2004                        
Revenues:                        
  Customer   $ 4,519   $ 42,435   $ 1,593   $ 48,547
  Intersegment(a)     370     152     146     668
  Related parties     8     1,043     –       1,051
   
 
 
 
    Total revenues   $ 4,897   $ 43,630   $ 1,739   $ 50,266
   
 
 
 
Segment income   $ 1,696   $ 1,406   $ 48   $ 3,150
Income from equity method investments     20     81     69     170
Depreciation, depletion and amortization(b)     750     416     8     1,174
Impairments(c)     –       –       –       –  
Capital expenditures(d)     944     784     490     2,218

2003                        
Revenues:                        
  Customer   $ 4,394   $ 33,508   $ 2,140   $ 40,042
  Intersegment(a)     405     97     108     610
  Related parties     12     909     –       921
   
 
 
 
    Total revenues   $ 4,811   $ 34,514   $ 2,248   $ 41,573
   
 
 
 
Segment income   $ 1,580   $ 819   $ (3 ) $ 2,396
Income from equity method investments(e)     50     82     21     153
Depreciation, depletion and amortization(b)     724     375     12     1,111
Impairments(c)     3     –       –       3
Capital expenditures(d)     973     772     131     1,876

2002                        
Revenues:                        
  Customer   $ 3,894   $ 25,384   $ 1,148   $ 30,426
  Intersegment(a)     583     146     69     798
  Related parties     –       869     –       869
   
 
 
 
    Total revenues   $ 4,477   $ 26,399   $ 1,217   $ 32,093
   
 
 
 
Segment income   $ 1,059   $ 372   $ 23   $ 1,454
Income from equity method investments     75     48     14     137
Depreciation, depletion and amortization(b)     744     364     3     1,111
Impairments(c)     13     –       –       13
Capital expenditures(d)     820     621     48     1,489

(a)
Management believes intersegment transactions were conducted under terms comparable to those with unrelated parties.
(b)
Differences between segment totals and Marathon totals represent impairments and amounts related to corporate administrative activities.
(c)
Excludes impairments of unproved oil and gas properties and $12 million of proved property impairments not allocated to the E&P segment in 2004.
(d)
Differences between segment totals and Marathon totals represent amounts related to corporate administrative activities.
(e)
Excludes a $124 million loss on the dissolution of MKM Partners L.P., which was not allocated to segments. See Note 13.

The following reconciles segment income to income from operations as reported in Marathon's consolidated statement of income:

(In millions)

  2004
  2003
  2002
 

 
Segment income   $ 3,150   $ 2,396   $ 1,454  
Items not allocated to segments:                    
  Administrative expenses     (307 )   (227 )   (194 )
  Gains (losses) on U.K. long-term gas contracts     (99 )   (66 )   18  
  Impairment of certain oil and gas properties     (44 )   –       –    
  Corporate insurance adjustment     (32 )   –       –    
  Gain on asset disposition     –       106     24  
  Loss on dissolution of MKM Partners L.P.     –       (124 )   –    
  Gain (loss) on ownership changes in subsidiaries     2     (1 )   12  
  Contract settlement     –       –       (15 )
  Inventory market valuation adjustments     –       –       71  
   
 
 
 
    Total income from operations   $ 2,670   $ 2,084   $ 1,370  

 

F-20


 
   
  Revenues
   
(In millions)

  Year
  Within Geographic
Areas

  Between
Geographic Areas

  Total
  Assets(a)

United States   2004   $ 47,284   $ –     $ 47,284   $ 8,396
    2003     39,377     –       39,377     8,061
    2002     29,930     –       29,930     7,904
Canada   2004     698     1,678     2,376     23
    2003     413     1,218     1,631     24
    2002     265     917     1,182     485
United Kingdom   2004     995     –       995     1,076
    2003     849     –       849     1,215
    2002     916     –       916     1,316
Equatorial Guinea   2004     312     –       312     2,444
    2003     119     –       119     1,656
    2002     82     –       82     1,018
Other Foreign Countries   2004     309     190     499     1,208
    2003     205     134     339     1,049
    2002     102     153     255     1,144
Eliminations   2004     –       (1,868 )   (1,868 )   –  
    2003     –       (1,352 )   (1,352 )   –  
    2002     –       (1,070 )   (1,070 )   –  
Total   2004   $ 49,598     –     $ 49,598   $ 13,147
    2003     40,963     –       40,963     12,005
    2002     31,295     –       31,295     11,867

(a)
Includes property, plant and equipment and investments.

9. Other Items

(In millions)

  2004
  2003
  2002

Interest and other financial income:                  
  Interest income   $ 45   $ 16   $ 10
  Income from interest rate swaps     24     23     2
  Foreign currency adjustments     9     13     8
   
 
 
    Total     78     52     20
   
 
 
Interest and other financing costs:                  
  Interest incurred(a)     262     282     288
  Less interest capitalized     48     41     16
   
 
 
    Net interest expense     214     241     272
  Interest on tax issues     12     (13 )   9
  Other     13     10     7
   
 
 
    Total     239     238     288
   
 
 
Net interest and other financing costs   $ 161   $ 186   $ 268

(a)
Excludes $40 million, $34 million and $28 million paid by United States Steel in 2004, 2003 and 2002 on assumed debt.

(In millions)

  2004
  2003
  2002
 

 
Net interest and other financing costs   $ 9   $ 13   $ 8  
Provision for income taxes     (15 )   (15 )   (10 )
   
 
 
 
  Aggregate foreign currency gains (losses)   $ (6 ) $ (2 ) $ (2 )

 

F-21


10. Income Taxes

 
  2004
  2003
  2002
(In millions)

  Current
  Deferred
  Total
  Current
  Deferred
  Total
  Current
  Deferred
  Total

Federal   $ 473   $ (22 ) $ 451   $ 280   $ 95   $ 375   $ 105   $ (26 ) $ 79
State and local     47     1     48     56     (4 )   52     21     33     54
Foreign     280     (52 )   228     177     (20 )   157     166     70     236
   
 
 
 
 
 
 
 
 
  Total   $ 800   $ (73 ) $ 727   $ 513   $ 71   $ 584   $ 292   $ 77   $ 369

(In millions)

  2004
  2003
  2002
 

 
Statutory rate applied to income before income taxes   $ 694   $ 559   $ 307  
Effects of foreign operations:                    
  Remeasurement of deferred taxes due to legislated changes(a)     –       –       61  
  All other, including foreign tax credits     26     (7 )   (12 )
State and local income taxes after federal income tax effects     32     35     34  
Credits other than foreign tax credits     (2 )   (6 )   (11 )
Effects of partially owned companies     (3 )   (6 )   (6 )
Adjustment of prior years' federal income taxes     (11 )   17     (1 )
Other     (9 )   (8 )   (3 )
   
 
 
 
    Total provisions   $ 727   $ 584   $ 369  

 
(a)
Represents a one-time deferred tax charge as a result of the enactment of a supplemental tax in the United Kingdom.
(In millions)

  December 31
  2004
  2003
 

 
Deferred tax assets:                  
  Net operating loss carryforwards (expiring in 2023)       $ 2   $ –    
  Capital loss carryforwards (expiring in 2008)         57     67  
  State tax loss carryforwards (expiring in 2005 through 2021)         122     131  
  Foreign tax loss carryforwards(a)         581     479  
  Expected federal benefit for:                  
    Crediting certain foreign deferred income taxes         292     331  
    Deducting state and foreign deferred income taxes         36     45  
  Employee benefits         341     301  
  Contingencies and other accruals         201     180  
  Investments in subsidiaries and equity investees         65     68  
  Other         156     130  
  Valuation allowances(b):                  
    Federal         (57 )   (67 )
    State         (71 )   (73 )
    Foreign(c)         (365 )   (283 )
       
 
 
      Total deferred tax assets(d)         1,360     1,309  
       
 
 
Deferred tax liabilities:                  
  Property, plant and equipment(c)         2,192     2,168  
  Inventory         315     317  
  Prepaid pensions         72     96  
  Other         147     145  
       
 
 
    Total deferred tax liabilities         2,726     2,726  
       
 
 
      Net deferred tax liabilities       $ 1,366   $ 1,417  

 
(a)
For 2004, includes $534 million for Norway which has no expiration date. The remainder expire 2005 through 2019.
(b)
Valuation allowances related to deferred federal tax assets are associated with capital loss carryforwards. The remaining valuation allowances are primarily associated with net operating loss carryforwards in several state jurisdictions, Norway, and several other foreign jurisdictions.
(c)
A revision was made to the deferred tax liability for property, plant and equipment and valuation allowance for Norway at December 31, 2003. The revision increased the deferred tax liability by $153 million and decreased the valuation allowance by the same amount. The revision had no impact on income, financial position or cash flow.
(d)
Marathon expects to generate sufficient future taxable income to realize the benefit of the deferred tax assets. In addition, the ability to realize the benefit of foreign tax credits is based on certain assumptions concerning future operating conditions (particularly as related to prevailing oil prices), income generated from foreign sources and Marathon's tax profile in the years that such credits may be claimed.

F-22


(In millions)

  December 31
  2004
  2003

Assets:                
  Other current assets       $ 127   $ 37
  Other noncurrent assets         60     35
Liabilities:                
  Deferred income taxes         1,553     1,489
       
 
    Net deferred tax liabilities       $ 1,366   $ 1,417

11. Business Transformation

(In millions)

  Accrued
January 1

  Expense
  Noncash
Charges (Gains)

  Cash
Payments

  Accrued
December 31


2004                              
Employee severance and termination benefits   $ 12   $ 15   $ –     $ 24   $ 3
Net benefit plans settlement and curtailment losses     –       20     20     –       –  
Relocation costs     5     8     –       11     2
Fixed asset related costs     1     –       –       1     –  
   
 
 
 
 
  Total   $ 18   $ 43   $ 20   $ 36   $ 5

2003                              
Employee severance and termination benefits   $ –     $ 25   $ –     $ 13   $ 12
Net benefit plans settlement and curtailment gains     –       (10 )   (10 )   –       –  
Relocation costs     –       5     –       –       5
Fixed asset related costs     –       4     2     1     1
   
 
 
 
 
  Total   $ –     $ 24   $ (8 ) $ 14   $ 18

12. Inventories

(In millions)

  December 31
  2004
  2003

Liquid hydrocarbons and natural gas       $ 676   $ 674
Refined products and merchandise         1,192     1,151
Supplies and sundry items         127     130
       
 
  Total       $ 1,995   $ 1,955

F-23


13. Investments and Long-Term Receivables

(In millions)

  December 31
  2004
  2003

Equity method investments:                
  Alba Plant LLC       $ 432   $ 277
  Atlantic Methanol Production Company, LLC         265     263
  Pilot Travel Centers LLC         372     373
  Other         265     259
Other investments         3     3
Recoverable environmental costs receivable         52     81
Value-added tax refunds receivable         32     13
Fair value of derivative assets         24     34
Deposits of restricted cash         89     5
Other receivables         12     15
       
 
    Total       $ 1,546   $ 1,323

(In millions)

  2004
  2003
  2002

Income data – year:                  
  Revenues and other income   $ 7,419   $ 7,036   $ 5,541
  Operating income     434     435     329
  Net income     330     319     264

Balance sheet data – December 31:                  
  Current assets   $ 583   $ 619      
  Noncurrent assets     3,990     3,727      
  Current liabilities     569     641      
  Noncurrent liabilities     1,511     1,172      

14. Property, Plant and Equipment

<
(In millions)

  December 31
  2004
  2003

Production       $ 15,162   $ 14,267
Refining         4,398     3,822
Marketing         1,954     1,926
Transportation         1,816     1,760
Gas processing