Form 10-K
Table of Contents
Index to Financial Statements

 

 

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, 2010

Commission file number 1-5153

Marathon Oil Corporation

(Exact name of registrant as specified in its charter)

 

Delaware   25-0996816
(State or other jurisdiction of incorporation or organization)   (I.R.S. Employer Identification No.)

5555 San Felipe Road, Houston, TX 77056-2723

(Address of principal executive offices)

(713) 629-6600

(Registrant’s telephone number, including area code)

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

 

Title of Each Class

 

Name of Each Exchange on Which Registered

Common Stock, par value $1.00

  New York Stock Exchange

 

 

 

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

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

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

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  þ No  ¨

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

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

Large accelerated filer   þ    Accelerated filer  ¨    Non-accelerated filer  ¨    Smaller reporting company  ¨

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

The aggregate market value of Common Stock held by non-affiliates as of June 30, 2010: $22,006 million. This amount is based on the closing price of the registrant’s Common Stock on the New York Stock Exchange on that date. Shares of Common Stock held by executive officers and directors of the registrant are not included in the computation. The registrant, solely for the purpose of this required presentation, has deemed its directors and executive officers to be affiliates.

There were 710,280,842 shares of Marathon Oil Corporation Common Stock outstanding as of January 31, 2011.

Documents Incorporated By Reference:

Portions of the registrant’s proxy statement relating to its 2011 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.

 

 

 


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MARATHON OIL CORPORATION

Unless the context otherwise indicates, references to “Marathon,” “we,” “our,” or “us” in this Annual Report on Form 10-K are references to Marathon Oil Corporation, including its wholly-owned and majority-owned subsidiaries, and its ownership interests in equity method investees (corporate entities, partnerships, limited liability companies and other ventures over which Marathon exerts significant influence by virtue of its ownership interest).

Table of Contents

 

         Page  

PART I

       
 

Item 1.

  

Business

     1   
 

Item 1A.

  

Risk Factors

     24   
 

Item 1B.

  

Unresolved Staff Comments

     31   
 

Item 2.

  

Properties

     31   
 

Item 3.

  

Legal Proceedings

     31   

PART II

       
 

Item 5.

  

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

     34   
 

Item 6.

  

Selected Financial Data

     35   
 

Item 7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     36   
 

Item 7A.

  

Quantitative and Qualitative Disclosures about Market Risk

     58   
 

Item 8.

  

Financial Statements and Supplementary Data

     61   
 

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     122   
 

Item 9A.

  

Controls and Procedures

     122   
 

Item 9B.

  

Other Information

     122   

PART III

       
 

Item 10.

  

Directors, Executive Officers and Corporate Governance

     122   
 

Item 11.

  

Executive Compensation

     122   
 

Item 12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     123   
 

Item 13.

  

Certain Relationships and Related Transactions, and Director Independence

     124   
 

Item 14.

  

Principal Accounting Fees and Services

     124   

PART IV

       
 

Item 15.

  

Exhibits, Financial Statement Schedules

     124   
    

SIGNATURES

     131   


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Disclosures Regarding Forward-Looking Statements

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

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

PART I

Item 1. Business

Plan to Create Independent Downstream Company

On January 13, 2011, the Board of Directors of Marathon Oil Corporation (“Marathon”) announced that it has approved moving forward with plans to spin off our downstream (Refining, Marketing and Transportation) business, creating two independent energy companies: Marathon Petroleum Corporation (“MPC”) and Marathon Oil Corporation (“MRO”). To effect the spin-off, we intend to distribute one common share of MPC for every two common shares of Marathon held at a record date to be determined. The transaction is expected to be effective June 30, 2011, with distribution of MPC shares shortly thereafter. A tax ruling request was submitted to the U.S. Internal Revenue Service (“IRS”) regarding the tax-free nature of the spin-off and we anticipate a response during the second quarter of 2011.

The above discussion of the plans to create an independent downstream company includes forward looking statements. Factors which could affect the plans include board approval, receipt of a favorable private letter ruling from the IRS and a registration statement declared effective by the Securities and Exchange Commission (“SEC”).

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 “USX Separation”), USX Corporation changed its name to Marathon Oil Corporation.

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

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

Segment and Geographic Information

Our operations consist of four reportable operating segments: 1) Exploration and Production (“E&P”) – explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis; 2) Oil Sands Mining (“OSM”) – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and

 

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market synthetic crude oil; 3) Integrated Gas (“IG”) – markets and transports products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol, on a worldwide basis; and 4) Refining, Marketing and Transportation (“RM&T”) – refines, transports and markets crude oil and petroleum products, primarily in the Midwest, Gulf Coast and southeastern regions of the United States. For operating segment and geographic financial information, see Note 8 to the consolidated financial statements.

The E&P, OSM and IG segments comprise our upstream operations. The RM&T segment comprises our downstream operations.

Exploration and Production

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

At the end of 2010, we were conducting oil and gas exploration, development or production activities in ten countries: the United States, Angola, Canada, Equatorial Guinea, Indonesia, Libya, Norway, Poland, the Iraqi Kurdistan Region, and the United Kingdom.

Our 2010 worldwide net liquid hydrocarbon sales averaged 245 thousand barrels per day (“mbpd”). Our 2010 worldwide net natural gas sales, including natural gas acquired for injection and subsequent resale, averaged 878 million cubic feet per day (“mmcfd”). In total, our 2010 worldwide net sales averaged 391 thousand barrels of oil equivalent per day (“mboepd”). For purposes of determining barrels of oil equivalent (“boe”), natural gas volumes are converted to approximate liquid hydrocarbon barrels by dividing the natural gas volumes expressed in thousands of cubic feet (“mcf”) by six. The liquid hydrocarbon volume is added to the barrel equivalent of natural gas volume to obtain boe.

In the United States during 2010, we drilled 77 gross (36 net) exploratory wells of which 73 gross (32 net) wells encountered commercial quantities of hydrocarbons. Of these 73 wells, 35 were temporarily suspended or in the process of being completed at year end. Internationally, we drilled 10 gross (2 net) exploratory wells of which 7 gross (1 net) wells encountered commercial quantities of hydrocarbons. All 7 wells were temporarily suspended or were in the process of being completed at December 31, 2010.

North America

United States – Our U.S. operations accounted for 29 percent of our 2010 worldwide net liquid hydrocarbon sales volumes and 41 percent of our worldwide net natural gas sales volumes.

Offshore – The Gulf of Mexico continues to be a core area, with over 20 prospects. At year end 2010, we held material interests in seven producing fields, four of which are company operated. An eighth field is under development and anticipated to come on-line in 2011.

Gulf of Mexico Drilling Moratorium – On April 22, 2010, the Deepwater Horizon, a rig that was engaged in drilling operations in the deepwater Gulf of Mexico, sank after an explosion and fire. The incident resulted in a significant oil spill in the Gulf of Mexico. Marathon had no involvement in the incident.

As a result of the Deepwater Horizon incident, the U.S. Department of the Interior issued a drilling moratorium on May 30, 2010, to suspend the drilling of deepwater wells, and prohibit drilling any new deepwater wells (defined as greater than 500 foot water depth). Shortly after the moratorium was issued, we temporarily suspended drilling an exploratory well on the Innsbruck prospect, located on Mississippi Canyon Block 993. Although the drilling moratorium was lifted on October 12, 2010, it is not known when plans and permits will be approved for future deepwater drilling activity. We sent a Revised Development Operations Coordination Document for the Ozona completion and a Revised Exploration Plan for the Innsbruck well to the Bureau of Ocean Energy Management Regulation and Enforcement (“BOEMRE”). We continue to update our revised Oil Spill Response Plan as new and updated requirements come from the BOEMRE. We filed our first deepwater Exploration Plan since the Deepwater Horizon incident to the BOEMRE on October 15, 2010. We are continuing to engage the BOEMRE to provide them with all the requested information. The BOEMRE has not yet deemed our plan submitted. The effects of new or additional laws or regulations that may be adopted in response to this incident are not fully known at this time and may impact future project execution.

We operate the Ewing Bank 873 platform which is located 130 miles south of New Orleans, Louisiana. The platform started operations in 1994 and serves as a production hub for the Ewing Bank 873 (Lobster), Ewing Bank 917 (Oyster) and Ewing Bank 963 (Arnold) fields. The facility also processes third-party production via subsea tie-backs.

 

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We own a 50 percent interest in the outside-operated Petronius field on Viosca Knoll Blocks 786 and 830. The Petronius platform is capable of providing processing and transportation services to nearby third-party fields.

The Neptune development commenced production of liquid hydrocarbons and natural gas in July 2008. We hold a 30 percent working interest in this outside-operated development located on Atwater Valley 575, 120 miles off the coast of Louisiana. The completed Phase I development included six subsea wells tied back to a stand-alone platform. Phase II development activities have begun and the first well in this program was successfully drilled and completed in late 2009.

Our Droshky development in the Gulf of Mexico on Green Canyon Block 244 began production in mid-July of 2010 and reached peak net production of 45,000 boepd in the third quarter of 2010. Production declines have been steeper than anticipated due to reservoir compartmentalization and lack of aquifer support. This subsea project consists of four development wells tied back to a third-party platform. Three of the four wells are currently producing. We plan to re-enter the fourth well in the first quarter of 2011. We hold a 100 percent operated working interest and an 81 percent net revenue interest in Droshky.

Development of our operated Ozona prospect, located on Garden Banks Block 515, has also continued. We are in the process of securing a rig to complete the previously drilled appraisal well and tie back to the nearby third-party Auger platform. First production of liquid hydrocarbon is expected in 2011. We hold a 68 percent working interest in Ozona.

In 2008, we drilled a successful oil appraisal well on the Stones prospect located on Walker Ridge Block 508. We hold a 25 percent interest in the outside-operated Stones prospect. In the third quarter of 2008, we announced deepwater oil discovery on the Gunflint prospect located on Mississippi Canyon Block 948. We own a 13 percent interest in this outside-operated prospect. In the first quarter of 2009, we participated in a deepwater oil discovery on the Shenandoah prospect located on Walker Ridge Block 52. We own a 10 percent interest in the outside-operated prospect.

In December 2009, we began drilling an exploratory well on the Flying Dutchman prospect, located on Green Canyon Block 511 in the Gulf of Mexico. We have 63 percent ownership and are the operator of this liquid hydrocarbon prospect. The Flying Dutchman reached its targeted total depth in early May 2010. The well encountered hydrocarbon-bearing sands that require further technical evaluation. The results of the Flying Dutchman well will continue to be evaluated to determine overall commerciality.

In addition to the prospects listed above, we held interests in 103 blocks in the Gulf of Mexico at the end of 2010, including 97 in the deepwater area. Our plans call for exploration drilling on some of these leases in 2011 and 2012, presuming a favorable regulatory environment that will allow deep-water drilling to resume.

Onshore – We hold 391,000 net acres in the Bakken shale oil play in the Williston Basin of North Dakota with a working interest of approximately 80 percent. Approximately 275 company-operated locations will be drilled over the next 4 years. We are evaluating other potential horizons above and below the Middle Bakken. We currently have six operated drilling rigs running in our Bakken shale program, and will add a rig solely dedicated to completion operations in the first quarter of 2011.

In the Anadarko Woodford shale horizon, a liquids-rich play in Oklahoma, we continue to expand our acreage position and now hold approximately 88,000 net acres within the play. We have existing production operations in this geographical area which will facilitate early drilling, with initial wells currently in progress. We plan to increase from three to eight company operated rigs in 2011. We also have domestic natural gas operations in Oklahoma, East Texas, and North Louisiana with combined net gas sales of 103 mmcfd in 2010.

In December 2010, we entered into an agreement with an operator in the Eagle Ford shale, a liquids-rich play in Texas. We initially paid $10 million and will drill and complete four wells to earn approximately 17,000 net acres. We also have an option that expires October 31, 2011 to purchase the operator’s remaining 58,000 net acres at a total cost of approximately $209 million, including the initial payment, carried well interest and lease extensions. In the event that we do not exercise the purchase option, the operator has the option to put the remaining 58,000 acres to us at a total cost, including the initial payment, carried well interest and lease extensions, of approximately $92 million.

We hold leases with natural gas production in the Piceance Basin of Colorado, located in Garfield County in the Greater Grand Valley field complex. We acquired approximately 177,000 net acres within the Niobrara play in the DJ Basin of northern Colorado and southeast Wyoming. We expect to commence drilling in 2011 and will leverage our Bakken operating experience. Net liquid hydrocarbon and natural gas sales from our existing Wyoming fields averaged 24 mbpd and 106 mmcfd in 2010. We plan to drill approximately 20 company operated wells in 2011 in the Big Horn, Wind River and Powder River Basins.

 

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We hold acreage in two additional emerging shale resource plays in the U.S. In the Appalachian Basin we hold 80,000 net acres in the Marcellus shale natural gas play in Pennsylvania and West Virginia. In February 2011, we entered into a joint venture with a company on a large portion of our Marcellus shale acreage position. Under the agreement terms, the company will to earn 50 percent of approximately 60,000 acres under a drilling carry. The company also has an option to acquire our remaining acreage while we retain the rights to continue to market the acreage to others. We drilled three wells in 2010 and five in 2009. In Louisiana and east Texas, we hold 20,000 net acres in the Haynesville shale natural gas play, where we drilled two wells in 2010 and one in 2009.

We produce natural gas in the Cook Inlet and adjacent Kenai Peninsula of Alaska. We have operated and outside-operated interests in ten fields and hold a 51 to 100 percent working interest in each. Typically, our natural gas sales from Alaska are seasonal in nature, trending down during the second and third quarters of each year and increasing during the fourth and first quarters. To manage supplies to meet contractual demand we produce and store natural gas in a partially depleted reservoir in the Kenai natural gas field. In 2010, we drilled three operated wells in Alaska and plan to drill one to three company-operated wells per year during 2011 and 2012.

Canada – We hold interests in both operated and outside-operated exploration stage in-situ oil sand leases as a result of the acquisition of Western in 2007. The three potential in-situ developments are Namur, in which we hold a 60 percent operated interest, Birchwood, in which we hold a 100 percent operated interest, and Ells River, in which we hold a 20 percent outside-operated interest. Initial test drilling on the Birchwood prospect confirmed bitumen presence and an additional 70 test wells are planned in 2011 to assess reservoir quality. Sanction of the initial phase of the Birchwood development is anticipated in 2014, with resulting first production expected in 2016.

Africa

Equatorial Guinea – We own a 63 percent operated working interest in the Alba field which is offshore Equatorial Guinea. During 2010, Equatorial Guinea net liquid hydrocarbon sales were 15 percent of our worldwide net liquid hydrocarbon sales volumes, and net natural gas sales were 46 percent of our worldwide net natural gas sales.

We also own a 52 percent interest in Alba Plant LLC, an equity method investee that operates an onshore liquefied petroleum gas (“LPG”) processing plant. Alba field natural gas is processed by the LPG plant under a long-term contract at a fixed price for the British thermal units used in the operations of the LPG plant and for the hydrocarbons extracted from the natural gas stream in the form of secondary condensate and LPG. During 2010, a gross 753 mmcfd of natural gas was supplied to the LPG production facility and the resulting net liquid hydrocarbon sales volumes in 2010 included 3 mbpd of secondary condensate and 11 mbpd of LPG produced by Alba Plant LLC.

As part of our Integrated Gas segment, we own 45 percent of Atlantic Methanol Production Company LLC (“AMPCO”) and 60 percent of Equatorial Guinea LNG Holdings Limited (“EGHoldings”), both of which are accounted for as equity method investments. AMPCO operates a methanol plant and EGHoldings operates an LNG production facility, both located on Bioko Island. Dry natural gas from the Alba field, which remains after the condensate and LPG are removed, is supplied to both of these facilities under long-term contracts at fixed prices. Because of the location of and limited local demand for natural gas in Equatorial Guinea, we consider the prices under the contracts with Alba Plant LLC, AMPCO and EGHoldings to be comparable to the price that could be realized from transactions with unrelated parties in this market under the same or similar circumstances. Our share of the income ultimately generated by the subsequent export of secondary condensate and LPG produced by Alba Plant LLC is reflected in our E&P segment. Our share of the income ultimately generated by the subsequent export of methanol produced by AMPCO and LNG produced by EGHoldings is reflected in our Integrated Gas segment as discussed below. During 2010, a gross 108 mmcfd of dry natural gas was supplied to the methanol plant and a gross 623 mmcfd of dry gas was supplied to the LNG production facility. Any remaining dry gas is returned offshore and reinjected into the Alba field for later production.

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

AngolaOffshore Angola, we hold 10 percent interests in Block 31 and Block 32, both of which are outside-operated. The discoveries on Blocks 31 and 32 represent four potential development hubs. The Plutao, Saturno, Venus and Marte discoveries and one successful appraisal well form a planned development area in the northeastern portion of Block 31. In 2008, we received approval to proceed with this first deepwater development project, called the PSVM development. The PSVM development will utilize a floating, production, storage and offloading (“FPSO”) vessel. A total of 48 production and injection wells are planned with development drilling currently underway. First production is anticipated in 2012. Other discoveries on Block 31 comprise potential development areas in the southeast and middle portions of the block. A development area in the south eastern portion of Block 32 is currently being evaluated with the potential to include 6 fields for an anticipated first oil production in 2016.

 

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Libya – We hold a 16 percent interest in the Waha concessions, which encompass almost 13 million acres located in the Sirte Basin. Our exploration program in 2010 included the drilling of 10 wells, including 2 carry over wells from 2009: seven of these wells were discoveries, two were dry and abandoned, and one was drilling as of yearend. We drilled 28 development wells in Libya in 2010. Phase II of the Faregh project began commissioning during the third quarter of 2010, with production coming on line in November.

Europe

Norway – Norway continues to be a core area, which complements our long-standing operations in the U.K. sector of the North Sea discussed below. We were approved for our first operatorship on the offshore Norwegian continental shelf in 2002, where today we operate ten licenses and hold interests in over 240,000 net acres.

The operated Alvheim complex located on the Norwegian continental shelf commenced production in June 2008. The complex consists of a Floating Production, Storage and Offloading (“FPSO”) vessel with subsea infrastructure. Improved reliability, combined with optimization work, increased the throughput of the FPSO to 142 mbpd, up from the original design of 120 mbpd. Produced oil is transported by shuttle tanker and produced natural gas is transported to the existing U.K. Scottish Area Gas Evacuation (“SAGE”) system using a 14-inch diameter, 24-mile cross border pipeline. First production to the complex was from the Alvheim development which is comprised of the Kameleon, East Kameleon and Kneler fields, in which we have a 65 percent working interest, and the Boa field, in which we have a 58 percent working interest. At the end of 2010, the Alvheim development included 11 producing wells and 2 water disposal wells. A Phase 2 drilling program commenced in 2010, with 1 well on production since December 2010 and a further two production wells to be drilled in 2011. A Phase 2b drilling program consisting of 2 production wells is planned for 2011 and 2012.

The nearby outside-operated Vilje field, in which we own a 47 percent working interest, began producing through the Alvheim complex in August 2008.

In June 2009, we completed the drilling program for the Volund field as a subsea tieback to the Alvheim complex. The Volund development, in which we own a 65 percent operated interest, is located approximately five miles south of the Alvheim area and consists of three production wells and one water injection well. First production from Volund was announced in September 2009. In the second quarter of 2010, we commenced production at the Volund field which allows us to maintain full capacity on the Alvheim FPSO. Net sales from Alvheim, Vilje, and Volund for 2010 averaged 50 mbpd of liquid hydrocarbons and 30 mmcfd of natural gas.

Also offshore Norway, we and our partners announced the Marihone and Viper discoveries, both located within tie-back distance of the Alvheim FPSO. The Marihone oil discovery is located in license PL340 about 12 miles south of the Volund and Alvheim fields. We hold a 65 percent operated working interest in Marihone. The Viper oil discovery is located immediately next to Volund field in PL203, about 12 miles south of the Alvheim FPSO. We are the operator and hold a 65 percent interest in Viper. Conceptual development studies for both discoveries have begun. First production for both discoveries is anticipated in 2014.

In December 2010 a sales agreement was entered into for all of our interests in production licenses PL 025, PL 048E and PL 187. The transaction includes our outside-operated 20 percent interest in PL 025 (Gudrun field development) and PL 187 (Brynhild discovery), and 12.5 percent interest in PL 048E (Eirin discovery).

United Kingdom – Our largest asset in the U.K. sector of the North Sea is the Brae area complex where we are the operator and have a 42 percent working interest in the South, Central, North and West Brae fields and a 38 percent working interest in the East Brae field. The Brae A platform and facilities host the underlying South Brae field and the adjacent Central and West Brae fields. A two well development program commenced in 2010 for West Brae with one well on production in January 2011, and the second expected to produce by the end of March 2011. The North Brae field, which is produced via the Brae B platform, and the East Brae field, which is produced via the East Brae platform, are natural gas condensate fields. The East Brae platform hosts the nearby Braemar field in which we have a 28 percent working interest.

The strategic location of the Brae platforms along with pipeline and onshore infrastructure has generated third-party processing and transportation business since 1986. Currently, the operators of 30 third-party fields have contracted to use the Brae system. Most recently, in 2010, we agreed to commence construction and installation of a new module to accommodate the tie back of the third-party operated Devenick field. 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 SAGE system. The SAGE pipeline transports natural gas from the Brae area, and the third-party Beryl area, and has a total wet natural gas capacity of 1.1 billion

 

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cubic feet (“bcf”) per day. The SAGE terminal at St. Fergus in northeast Scotland processes natural gas from the SAGE pipeline as well as approximately 1 bcf per day of third-party natural gas.

In the U.K. Atlantic Margin west of the Shetland Islands, we own an average 30 percent working interest in the outside-operated Foinaven area complex, consisting of a 28 percent working interest in the main Foinaven field, 47 percent working interest in East Foinaven and 20 percent working interest in the T35 and T25 fields. The FPSO is being upgraded which is expected to extend the life of this asset through 2021.

Poland – In 2010, we added 10 licenses with shale gas potential in Poland, increasing our total acreage position to approximately 2.3 million net acres in 11 licenses. We have a 100 percent interest and operate all 11 blocks. In 2011 we plan to acquire 2D seismic over all concessions by the end of the third quarter and plan to initiate drilling in the fourth quarter. We have recently been successful in farming-out a portion of our interest in this play. Under the agreement, our partner will earn a 40 percent working interest in 10 licenses, as well as pay a promote on certain future seismic and well costs. This transaction is subject to the approval of the Polish Ministry of the Environment. We will remain operator of the 10 licenses included in the agreement.

Other International

Indonesia – We are the operator and hold a 70 percent interest in the Pasangkayu Block located both onshore & offshore Sulawesi in the Makassar Strait, Indonesia. The Pasangkayu Block covers an area of approximately 872,000 acres and is located directly east of the Kutei Basin production region. The production sharing contract with the Indonesian government was signed in 2006 and we completed 3D seismic acquisition in May 2008.

In November 2010, the Bravo-1 well in the northeastern portion of the Pasangkayu block was drilled in a water depth of approximately 3,200 feet and reached a total depth of 9,000 feet. No hydrocarbon accumulations were present.

The Romeo prospect, located on the north-central portion of the Pasangkayu block in a water depth of 6,200 feet, is being drilled and is expected to be completed during the first half of 2011.

In 2009, we were awarded a 49 percent interest and operatorship in the Kumawa Block, an Indonesia offshore exploration block, located offshore West Papua. An increase in ownership to 55 percent received Indonesian government approval in late 2010. The Kumawa Block encompasses 1.24 million acres. A seismic survey was acquired in 2010 and we expect to drill one exploration well in 2012.

In October 2008, we were granted a 49 percent interest and operatorship in the Bone Bay Block offshore Sulawesi. An increase in ownership to 55 percent received Indonesian government approval in late 2010. The Bone Bay Block covers an area of 1.23 million acres and is 200 miles southeast of our Pasangkayu Block. A 2D seismic survey was acquired in 2009 and we expect to drill one exploration well in early 2012.

We continue to pursue joint study agreements in Indonesia, which provide a right of first refusal in future bid rounds. We completed one joint study agreement in 2010 and continue to evaluate regional potential for other opportunities.

Iraqi Kurdistan Region – In October 2010, we acquired a position in four exploration blocks in the Kurdistan Region of Iraq. We have signed production sharing agreements for operatorship and an 80 percent ownership in two open blocks northeast of Erbil; Harir and Safen. The Kurdistan Regional Government (“KRG”) will hold a 20 percent carried interest. We were assigned working interests in two additional blocks located north-northwest of Erbil; Atrush, in which we have a 16 percent ownership (KRG holds a 4 percent carried interest), and Sarsang, in which we have a 20 ownership (KRG holds a 4 percent carried interest). These contracts provide us with access to approximately 368,000 net acres. We have committed to a seismic program and to drilling one well on each of the two open blocks during the initial three-year exploration period. The Atrush and Sarsang blocks each have one well currently drilling.

Divestitures

Angola – In February 2010, we closed the sale of an undivided 20 percent interest in the outside-operated production sharing contract and joint operating agreement on Block 32 offshore Angola effective January 1, 2009. We retained a 10 percent interest in Block 32.

The above discussion of the E&P segment includes forward-looking statements with respect to anticipated future exploratory and development drilling, the timing of production from the Ozona development in the Gulf of Mexico, the PSVM development on Block 31 offshore Angola and Block 32 and other possible developments. Some factors which could possible affect these forward-looking statements include pricing, supply and demand for petroleum products, the amount of capital available for exploration and development, regulatory constraints, drilling rig availability, unforeseen hazards such as weather conditions, natural disasters, acts of war or terrorist acts and the governmental or military response, and

 

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other geological, operating and economic considerations. The foregoing forward-looking statements may be further affected by the inability to obtain or delay in obtaining necessary government and third-party approvals and permits. The offshore developments could further be affected by presently known data concerning size and character of reservoirs, economic recoverability, future drilling success and production experience. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Productive and Drilling Wells

For our E&P segment, the following tables set forth gross and net productive wells and service wells as of December 31, 2010, 2009 and 2008 and drilling wells as of December 31, 2010.

 

     Productive Wells (a)                              
     Oil      Natural Gas        Service Wells          Drilling Wells    
      Gross      Net      Gross      Net      Gross      Net        Gross      Net    

2010

                       

United States

     4,818        1,860        3,145        1,905         2,466        746        26        16  

Equatorial Guinea

     -         -         13        9         5        3        -         -   

Other Africa

     1,022        168        3        -         94        16        11        -   
                                                                       

Total Africa

     1,022        168        16        9         99        19        11        -   

Total Europe

     67        28        40        16         29        11        1        -   

Total Other International

     -         -         -         -         -         -         3        1  
                                                                       

Worldwide

     5,907        2,056        3,201        1,930         2,594        776        41        17  
                                                                       

2009

                       

United States

     4,806        1,788        5,158        3,569         2,447        734        

Equatorial Guinea

     -         -         13        9         5        3        

Other Africa

     976        160        -         -         91        15        
                                                           

Total Africa

     976        160        13        9         96        18        

Total Europe

     67        27        44        18         27        10        
                                                           

Worldwide

     5,849        1,975        5,215        3,596         2,570        762        
                                                           

2008

                       

United States

     5,856        2,140        5,411        3,846         2,703        822        

Equatorial Guinea

     -         -         13        9         5        3        

Other Africa

     968        162        -         -         92        15        
                                                           

Total Africa

     968        162        13        9         97        18        

Total Europe

     64        26        67        40         26        10        
                                                           

Worldwide

         6,888            2,328            5,491            3,895           2,826            850                    
(a)

Of the gross productive wells, wells with multiple completions operated by us totaled 164, 170 and 276 as of December 31, 2010, 2009 and 2008. Information on wells with multiple completions operated by others is unavailable to us.

 

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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.

 

     Development      Exploratory      Total  
      Oil      Natural
Gas
     Dry      Total      Oil      Natural
Gas
     Dry      Total         

2010

                          

United States

             61                20                1                82                29                2                3                34                116  

Total Africa

     5        -         -         5        1        -         -         1        6  

Total Europe

     2        -         -         2        -         -         -         -         2  

Total Other International

     -         -         -         -         1        -         1        2        2  
                                                                                

Worldwide

     68        20        1        89        31        2        4        37        126  

2009

                          

United States

     11        54        2        67        37        9        2        48        115  

Total Africa

     5        1        -         6        1        -         -         1        7  

Total Europe

     1        -         -         1        1        -         -         1        2  
                                                                                

Worldwide

     17        55        2        74        39        9        2        50        124  

2008

                          

United States

     38        161        -         199        33        8        6        47        246  

Total Africa

     6        -         -         6        1        -         -         1        7  

Total Europe

     2        1        -         3        -         2        1        3        6  
                                                                                

Worldwide

     46        162        -         208        34        10        7        51        259  

Acreage

The following table sets forth, by geographic area, the gross and net developed and undeveloped exploration and production acreage held in our E&P segment as of December 31, 2010.

 

     Developed      Undeveloped      Developed and
Undeveloped
 
(In thousands)    Gross      Net      Gross      Net      Gross      Net  

United States

     1,500        1,100        1,265        1,046        2,765        2,146  

Canada

     -         -         143        55        143        55  
                                                     

Total North America

     1,500        1,100        1,408        1,101        2,908        2,201  

Equatorial Guinea

     45        29        173        122        218        151  

Other Africa

     12,909        2,108        2,580        258        15,489        2,366  
                                                     

Total Africa

     12,954        2,137        2,753        380        15,707        2,517  

Total Europe

     131        68        3,044        2,536        3,175        2,604  

Other International

     -         -         3,985        2,334        3,985        2,334  
                                                     

Worldwide

       14,585          3,305          11,190          6,351          25,775          9,656  

Of the 6.3 million net undeveloped acres held at December 31, 2010, 3 percent, 13 percent and 4 percent of those acres are under agreements scheduled to expire in the years 2011, 2012, and 2013.

Oil Sands Mining

We hold a 20 percent outside-operated interest in the Athabasca Oil Sands Project (“AOSP”), an oil sands mining joint venture located in Alberta, Canada. The joint venture produces bitumen from oil sands deposits in the Athabasca region utilizing mining techniques and upgrades the bitumen to synthetic crude oils. The AOSP’s mining and extractions assets are located near Fort McMurray, Alberta and include the Muskeg River mine which began bitumen production in 2003 and the Jackpine mine which commenced phased start-up in the third quarter of 2010. As of December 31, 2010, we have rights to participate in developed and undeveloped leases totaling approximately 215,000 gross (45,000 net) acres. The underlying developed leases are held for the duration of the project, with royalties payable to the province of Alberta. The upgrading assets are located at Fort Saskatchewan, northeast of Edmonton, Alberta.

The first fully integrated expansion of the existing AOSP facilities was approved in 2006. Expansion 1 includes construction of mining and extraction facilities at the Jackpine mine, new treatment facilities at the existing Muskeg River mine, addition of a new processing train at the Scotford upgrader and development of related infrastructure. A

 

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phased start-up of the Jackpine mine operations began in the third quarter of 2010. At full capacity, the Jackpine mine will add 100,000 gross bpd to our previously existing capacity. The expanded upgrader began the commissioning and start-up phase, which will continue into early 2011. Stage 1 debottlenecking activities are scheduled to begin in 2011. Potential future expansions and additional debottlenecking opportunities remain under review.

A planned turnaround at the Muskeg River mine and the upgrader occurred from March through May 2010. Our net share of turnaround costs was $99 million. Production as the AOSP was halted in April 2010 before a staged resumption of operations in mid-May 2010.

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

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

The above discussion of the Oil Sands Mining segment includes forward-looking statements concerning the start-up of the expanded upgrader. Factors which could affect this project include transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions and delays or other risks customarily associated with start-up projects.

 

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Reserves

Estimated Reserve Quantities

The following table sets forth estimated quantities of our net proved liquid hydrocarbon, natural gas and synthetic crude oil reserves based upon an unweighted average of closing prices for the first day of each month in the 12-month periods ended December 31, 2010 and 2009. Approximately 60 percent of our proved reserves are located in Organization for Economic Cooperation and Development (“OECD”) countries.

Reserves are disclosed by continent, by country, if the proved reserves related to any geographic area, on an oil-equivalent barrel basis represent 15 percent or more of our total proved reserves. A geographic area can be an individual country, group of countries within a continent, or a continent.

 

     North America      Africa        Europe           
December 31, 2010      United  
States
     Canada        Total        EG      Other      Total      Total        Grand  
Total
 

Proved Developed Reserves

                       

Liquid hydrocarbon (mmbbl)

     124        -         124        86        180        266        89        479  

Natural gas (bcf)

     591        -         591        1,186        104        1,290        43        1,924  

Synthetic crude oil (mmbbl)

     -         433        433        -         -         -         -         433  

Total proved developed reserves (mmboe)

     222        433        655        284        198        482        96        1,233  

Proved Undeveloped Reserves

                       

Liquid hydrocarbon (mmbbl)

     49        -         49        33        59        92        10        151  

Natural gas (bcf)

     154        -         154        465        1        466        73        693  

Synthetic crude oil (mmbbl)

     -         139        139        -         -         -         -         139  

Total proved undeveloped reserves (mmboe)

     75        139        214        110        59        169        22        405  

Total Proved Reserves

                       

Liquid hydrocarbon (mmbbl)

     173        -         173        119        239        358        99        630  

Natural gas (bcf)

     745        -         745        1,651        105        1,756        116        2,617  

Synthetic crude oil (mmbbl)

     -         572        572        -         -         -         -         572  

Total proved reserves (mmboe)

     297        572        869        394        257        651        118        1,638  

 

     North America      Africa        Europe           
December 31, 2009      United  
States
     Canada        Total        EG      Other        Total        Total        Grand  
Total
 

Proved Developed Reserves

                       

Liquid hydrocarbon (mmbbl)

     120        -         120        83        186        269        87        476  

Natural gas (bcf)

     652        -         652        1,102        107        1,209        50        1,911  

Synthetic crude oil (mmbbl)

     -         392        392        -         -         -         -         392  

Total proved developed reserves (mmboe)

     229        392        621        267        204        471        95        1,187  

Proved Undeveloped Reserves

                       

Liquid hydrocarbon (mmbbl)

     50        -         50        39        42        81        15        146  

Natural gas (bcf)

     168        -         168        586        -         586        59        813  

Synthetic crude oil (mmbbl)

     -         211        211        -         -         -         -         211  

Total proved undeveloped reserves (mmboe)

     78        211        289        136        42        178        25        492  

Total Proved Reserves

                       

Liquid hydrocarbon (mmbbl)

     170        -         170        122        228        350        102        622  

Natural gas (bcf)

     820        -         820        1,688        107        1,795        109        2,724  

Synthetic crude oil (mmbbl)

     -         603        603        -         -         -         -         603  

Total proved reserves (mmboe)

     307        603        910        403        246        649        120        1,679  

 

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

 

    North America     Africa       Europe                
December 31, 2008     United  
States
    Canada(a)       Total       EG     Other     Total     Total     Disc.
Ops.
(b)
      Grand  
Total
 

Proved Developed Reserves

                 

Liquid hydrocarbon (mmbbl)

    137               -        137       99       193       292       81              514  

Natural gas (bcf)

    839       -        839       1,273       109       1,382       95       34         2,350  

Total proved developed reserves (mmboe)

    277       -        277       312       211       523       96       10         906  

Total Proved Reserves

                 

Liquid hydrocarbon (mmbbl)

    178       -        178       139       211       350       104              636  

Natural gas (bcf)

    1,085       -        1,085       1,866       109       1,975       159       132         3,351  

Total proved reserves (mmboe)

    359       -        359       450       229       679       131       26         1,195  

Developed reserves as a percent of total proved reserves

    77%        -        77%        69%        92%        77%        73%        38%        76%   
(a)

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

(b)

Our businesses in Ireland and Gabon were sold in 2009 and were reported as discontinued operations.

We previously reported OSM segment reserves as bitumen because oil sands mining was not considered an oil and gas producing activity by the SEC. Proved bitumen reserves reported as of December 31, 2008 were 388 mmboe.

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

Preparation of Reserve Estimates

Our estimation of economically producible volumes of liquid hydrocarbons and natural gas is a highly technical process performed primarily by in-house teams of reservoir engineers and geoscience professionals. All estimates of reserves are made in compliance with SEC Rule 4-10 of Regulation S-X. Beginning December 31, 2009, reserve estimates are based upon the unweighted average of closing prices for the first day of each month in the respective 12-month period ended December 31. In 2008, reserve estimates were based on prices at December 31.

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

        Our Director of Corporate Reserves, who reports to our Chief Financial Officer, has a Bachelor of Science degree in petroleum engineering and a master of business administration. Her 36 years of experience in the industry include 25 with Marathon. She is active in industry and professional groups, having served on the Society of Petroleum Engineers (“SPE”) Oil and Gas Reserves Committee (“OGRC”) since 2004, chairing in 2008 and 2009. As a member of the OGRC, she participated in the development of the Petroleum Resource Management System (“PRMS”) and served on the Technical Program Committee for a 2007 SPE Reserves Estimation Workshop: Sharing the Vision focusing on PRMS. She chaired the development of the OGRC comments on the SEC’s proposed modernization of oil and gas reporting and was a member of the American Petroleum Institute’s Ad Hoc group that provided comments on the same topic.

 

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        Estimates of synthetic crude oil reserves are prepared by GLJ Petroleum Consultants of Calgary, Canada, third-party consultants. A copy of their December 31, 2010 report is filed as Exhibit 99.1 to this Form 10-K. The engineer responsible for the estimates of our oil sands mining reserves has 32 years of experience in petroleum engineering and has conducted surface mineable oil sands evaluations since 1986. He is a member of SPE, having served as regional director 1998 through 2001 and is a registered Practicing Professional Engineer in the Province of Alberta.

Audits of Estimates

Third-party consultants are engaged to audit the in-house reserve estimates for fields that comprise 80 percent of our total proved reserves over a rolling four-year period. We met this goal for the four-year period ended December 31, 2010, without conducting any third party audits in 2010. We established a tolerance level of 10 percent for reserve audits such that initial estimates by the third-party consultants are accepted if they are within 10 percent of our internal estimates. Should the third-party consultants’ initial analysis fail to reach our tolerance level, both our team and the consultants re-examine the information provided, request additional data and refine their analysis if appropriate. This resolution process is continued until both estimates are within 10 percent. This process did not result in significant changes to our reserve estimates in 2009 or 2008.

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

Ryder Scott Company (“Ryder Scott”) performed audits of several of our fields in 2009. Their summary report on audits performed in 2009 is Exhibit 99.3 to this Form 10-K. The team lead for Ryder Scott has over 19 years of industry experience, having worked for a major international oil and gas company before joining Ryder Scott. He has a bachelor of science in mechanical engineering, is a member of SPE and is a registered Professional Engineer in the state of Texas.

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

Changes in Proved Undeveloped Reserves

As of December 31, 2010, 405 mmboe of proved undeveloped reserves were reported, a decrease of 87 mmboe from December 31, 2009. The following table shows of the changes in total proved undeveloped reserves for 2010:

 

Beginning of year

             492   

Revisions of previous estimates

     (30

Extensions, discoveries, and other additions

     71   

Transfer to developed

     (128
        

End of year

     405   

Significant additions to proved undeveloped reserves during 2010 include 28 mmboe for development drilling in our Libya properties and 19 mmboe additional for development drilling in the Bakken Shale play. Revisions include 26 mmboe of proved undeveloped reserves reclassified as proved developed in Equatorial Guinea because operating pressures can be reduced more than originally anticipated with the existing equipment. Transfers include the movement of 67 mmboe from proved undeveloped to proved developed due to start up for the Jackpine mine Expansion 1 in Canada and 26 mmboe related to the commencement of production at the Gulf of Mexico Droshky development in July 2010. Costs incurred in the periods ended December 31, 2010, 2009 and 2008 relating to the development of proved undeveloped reserves, were $1,463 million, $792 million and $1,189 million.

Projects can remain in proved undeveloped reserves for extended periods in certain situations such as behind-pipe zones where reserves will not be accessed until the primary producing zone depletes, large development projects which take more than five years to complete, and the timing of when additional gas compression is needed. Of the 405 mmboe of proved undeveloped reserves at year end 2010, 30 percent of the volume is associated with projects that have been included in proved reserves for more than five years. The majority of this volume is related to a compression project in

 

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Equatorial Guinea that was sanctioned by our Board of Directors in 2004 and is expected to be completed in 2015. The timing of the installation of compression is being deferred as a result of better than expected reservoir performance. In addition, the North Gialo project in Libya is being executed by the operator, encompassing a continuous drilling program and designing, fabricating, and installing extensive liquid handling and gas recycling facilities. In 2010, an engineering firm was awarded the bid for the front-end engineering and design activities. Long lead items are expected to be procured in 2011 and first production is expected in 2016. There are no other significant undeveloped reserves expected to be developed more than five years.

As of December 31, 2010, future development costs estimated to be required for the development of proved undeveloped liquid hydrocarbon, natural gas and synthetic crude oil reserves for the years 2011 through 2015 are projected to be $884 million, $315 million, $379 million, $433 million, and $224 million.

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

Net Production Sold

 

     North America      Africa        Europe                 
        United  
States
     Canada(a)       Total        EG      Other        Total        Total      Disc.
Ops
(b)
      Total    

Year Ended December 31, 2010

                        

Liquid hydrocarbon (mbpd)(c)

     70        -        70        38        45        83        92        -        245  

Natural gas (mmcfd)(d)(e)

     364        -        364        405        4        409        87        -        860  

Synthetic crude oil (mbpd)

     -         24        24        -         -         -         -         -        24  

Total production sold (mboed)

     131        24        155        106        45        151        106        -        412  

Year Ended December 31, 2009

                        

Liquid hydrocarbon (mbpd)(c)

     64        -        64        42        45        87        92        5        248  

Natural gas (mmcfd)(d)(e)

     373        -        373        426        4        430        116        17        936  

Total production sold (mboed)

     126        -        126        113        46        159        111        7        403  

Year Ended December 31, 2008

                        

Liquid hydrocarbon (mbpd)(c)

     63        -        63        40        47        87        55        6        211  

Natural gas (mmcfd)(d)(e)

     448        -        448        366        4        370        129        37        984  

Total production sold (mboed)

     138        -        138        101        48        149        77        12        376  
(a)

Before December 31, 2009, reserves related to oil sands mining were not included in the SEC’s definition of oil and gas producing activities; therefore, synthetic crude oil production of 27 mbpd is not reported for 2009.

(b)

Our businesses in Ireland and Gabon were sold in 2009 and were reported as discontinued operations.

(c)

Includes crude oil, condensate and natural gas liquids. The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.

(d)

U.S. natural gas volumes exclude volumes produced in Alaska that are stored for later sale in response to seasonal demand, although our reserves have been reduced by those volumes.

(e)

Excludes volumes acquired from third parties for injection and subsequent resale.

 

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Average Sales Price per Unit

 

    North America     Africa       Europe                
(Dollars per unit)     United  
States
    Canada(a)       Total       EG     Other     Total     Total     Disc.
Ops
(b)
      Total    

Year Ended December 31, 2010

                 

Liquid hydrocarbon (bbl)

  $ 72.30       -      $ 72.30     $ 50.57     $ 89.15     $ 71.71     $ 81.95     $ -      $ 75.73  

Natural gas (mcf)

    4.71       -        4.71       0.24       0.70       0.25       7.04       -        2.82  

Synthetic crude oil (bbl)

    -        71.06        71.06       -        -        -        -        -        71.06  

Year Ended December 31, 2009

                 

Liquid hydrocarbon (bbl)

    54.67       -        54.67       38.06       68.41       53.91       64.46       56.47        58.06  

Natural gas (mcf)

    4.14       -        4.14       0.24       0.70       0.25       4.84       8.54        2.52  

Year Ended December 31, 2008

                 

Liquid hydrocarbon (bbl)

      86.68       -          86.68         66.34       110.49         89.85         90.60         96.41          89.29  

Natural gas (mcf)

    7.01       -        7.01       0.24       0.70       0.25       7.80       9.62        4.67  
(a)

Before December 31, 2009, oil sands mining was not included in the SEC’s definition of oil and gas producing activities; therefore, synthetic crude oil prices are not reported for 2009 or 2008.

(b)

Our businesses in Ireland and Gabon were sold in 2009 and were reported as discontinued operations.

Average Production Cost per Unit(a)

 

     North America      Africa        Europe                 
(Dollars per boe)      United  
States
     Canada(b)     Total      EG      Other        Total        Total      Disc.
Ops
(c)
      Grand  
Total
 

Years ended December 31:

                        

2010

   $ 14.16      $   65.15      $   22.36      $   2.81      $   4.18      $   3.23      $ 7.49      $ -      $   11.54  

2009

       14.03        -        14.03        2.63        3.64        2.93        6.99        19.14        7.80  

2008

     12.82        -        12.82        2.57        2.39        2.51        11.72        15.24        8.61  
(a)

Production, severance and property taxes are excluded from the production costs used in calculation of this metric.

(b)

Before December 31, 2009, oil sands mining was not included in the SEC’s definition of oil and gas producing activities; therefore, production costs are not reported for 2009 or 2008. Production costs in 2010 include costs associated with a major turnaround.

(c)

Our businesses in Ireland and Gabon were sold in 2009 and were reported as discontinued operations.

Integrated Gas

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

We hold a 60 percent interest in EGHoldings, which is accounted for under the equity method of accounting. EGHoldings has a 3.7 million metric tonnes per annum (“mmtpa”) LNG production facility on Bioko Island in Equatorial Guinea. LNG from the production facility is sold under a 3.4 mmtpa, or 460 mmcfd, sales and purchase agreement with a 17-year term ending in 2024. The purchaser under the agreement takes delivery of the LNG on Bioko Island, with pricing linked principally to the Henry Hub index, regardless of destination. This production facility allows us to monetize our natural gas reserves from the Alba field, as natural gas for the facility is purchased from the Alba field participants under a long-term natural gas supply agreement. Gross sales of LNG from this production facility totaled 3.7 million metric tonnes in 2010. In 2010, we continued discussions with the government of Equatorial Guinea and our partners regarding a potential second LNG production facility on Bioko Island.

We own a 30 percent outside-operated interest in a natural gas liquefaction plant in Kenai Alaska. This facility began first production in 1969 and we currently lease one 87,500 cubic meter tankers to transport LNG to customers in Japan. In February 2011 we, along with the plant operator, announced that exports would cease in spring of 2011.

We own a 45 percent interest in AMPCO, which is accounted for under the equity method of accounting. AMPCO owns a methanol plant located in Malabo, Equatorial Guinea. Feedstock for the plant is supplied from our natural gas production from the Alba field. Gross sales of methanol from the plant totaled 850,605 metric tonnes in 2010. Production from the plant is used to supply customers in Europe and the U.S.

 

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

Refining, Marketing and Transportation

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

In December 2010, we sold our St. Paul Park, Minnesota, refinery (including associated terminal, tankage and pipeline investments and 166 SuperAmerica retail outlets (collectively, “Minnesota Assets”). Operations for the Minnesota Assets are included in all of the annual statistics reported.

Refining

We currently own and operate six refineries with an aggregate refining capacity of 1,142 thousand barrels per day (“mbpd”) of crude oil as detailed in the table below.

 

Crude Oil Refining Capacity       
(mbpd)       

Garyville, Louisiana

     464  

Catlettsburg, Kentucky

     212  

Robinson, Illinois

     206  

Detroit, Michigan

     106  

Canton, Ohio

     78  

Texas City, Texas

     76  
        

Total

         1,142  

During 2010, our refineries processed 1,173 mbpd of crude oil and 162 mbpd of other charge and blend stocks. Our refineries include crude oil atmospheric and vacuum distillation, fluid catalytic cracking, catalytic reforming, desulfurization and sulfur recovery units. The refineries process a wide variety of crude oils and produce numerous refined products, ranging from transportation fuels, such as reformulated gasolines, blend-grade gasolines intended for blending with fuel ethanol and ultra-low sulfur diesel fuel, to heavy fuel oil and asphalt. Additionally, we manufacture aromatics, cumene, propane, propylene, and sulfur.

Our Garyville, Louisiana, refinery is located along the Mississippi River in southeastern Louisiana between New Orleans and Baton Rouge. The Garyville refinery is configured to processes heavy sour crude oil into products such as gasoline, distillates, sulfur, asphalt, propane, polymer grade propylene, isobutane and coke. An expansion project was completed in the fourth quarter of 2009 that increased Garyville’s crude oil refining capacity, making it one of the largest refineries in the U.S. Our Garyville refinery has earned designation as a U.S. Occupational Safety and Health Administration (OSHA) Voluntary Protection Program (VPP) STAR site.

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

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

Our Detroit, Michigan, refinery is located near Interstate 75 in southwest Detroit. It is the only petroleum refinery currently operating in Michigan. The Detroit refinery processes light sweet and heavy sour crude oils, including Canadian crude oils, into products such as gasoline, diesel, asphalt, slurry, propane, chemical grade propylene and sulfur. In 2007, we approved a heavy oil upgrading and expansion project at this refinery, with a current projected cost of $2.2 billion (excluding capitalized interest). This project will enable the refinery to process an additional 80 mbpd of heavy sour crude oils, including Canadian bitumen blends, and will increase its crude oil refining capacity by about 15 mbpd. Construction

 

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began in the first half of 2008 and reached 50 percent completion at December 31, 2010. The project is expected to be complete in the second half of 2012. Our Detroit refinery is certified as a Michigan VPP STAR site.

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

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

The above discussion includes forward-looking statements concerning the Detroit refinery heavy oil upgrading and expansion project. Some factors that could affect this project include transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by necessary government and third-party approvals and other risks customarily associated with construction projects.

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

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

 

Refined Product Yields                     
(mbpd)    2010      2009      2008  

Gasoline

     726        669        609  

Distillates

     409        326        342  

Propane

     24        23        22  

Feedstocks and special products

     97        62        96  

Heavy fuel oil

     24        24        24  

Asphalt

     76        66        75  
                          

Total

       1,356          1,170          1,168  

Crude oil supply – We obtain most of the crude oil we refine through negotiated contracts and purchases or exchanges on the spot market. Our crude oil supply contracts are generally term contracts with market related pricing provisions. The following table provides information on our sources of crude oil for each of the last three years. The crude oil sourced outside of North America was acquired from various foreign national oil companies, producing companies and trading companies.

 

Sources of Crude Oil Refined                     
(mbpd)    2010      2009      2008  

United States

     720        613        466  

Canada

     115        136        135  

Middle East and Africa

     250        154        244  

Other international

     88        54        99  
                          

Total

         1,173            957            944  
                          

Average cost of crude oil throughput (Dollars per barrel)

     $78.57         $62.10         $98.34   

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

Refined products marketing and distribution – We are a supplier of refined products to resellers and consumers within our 20-state market area in the Midwest, Gulf Coast and southeastern regions of the United States. Our market area includes approximately 5,100 Marathon branded-retail outlets concentrated in the Midwest and southeastern states. We currently own and distribute from 63 light product and 21 asphalt terminals. In addition, we distribute light products through approximately 45 third-party terminals in our market area. Our marine transportation operations include 14 towboats, as well as 168 owned and 8 leased barges that transport refined products on the Ohio, Mississippi and Illinois rivers and their tributaries as well as the Intercoastal Waterway. We lease or own approximately 1,760 railcars of various sizes and capacities for movement and storage of refined products. In addition, we own 122 transport trucks for the movement of refined products.

 

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

 

Refined Product Sales by Customer Type    2010      2009      2008  

Private-brand marketers, commercial and industrial consumers

     70%         67%         67%   

Marathon-branded outlets

     17%         18%         18%   

Speedway retail outlets

     13%         15%         15%   

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

 

Refined Product Sales                     
(mbpd)    2010      2009      2008  

Gasoline

     923        830        756  

Distillates

     435        357        375  

Propane

     24        23        22  

Feedstocks and special products

     103        75        100  

Heavy fuel oil

     23        24        23  

Asphalt

     77        69        76  
                          

Total

     1,585        1,378        1,352  
                          

Average sales price (Dollars per barrel)

         $  87.87             $  70.86             $  109.49   

We sell gasoline, gasoline blendstocks and No. 1 and No. 2 fuel oils (including kerosene, jet fuel and diesel fuel) to wholesale marketing customers in the Midwest, Gulf Coast and southeastern regions of the U.S. We sold 54 percent of our gasoline volumes and 88 percent of our distillates volumes on a wholesale or spot market basis in 2010. The demand for gasoline is seasonal in many of our markets, with demand typically being at its highest levels during the summer months.

We have blended ethanol into gasoline for over 20 years and expanded our blending program in 2007, in part due to federal regulations that require us to use specified volumes of renewable fuels. Ethanol volumes sold in blended gasoline averaged 68 mbpd in 2010, 60 mbpd in 2009 and 54 mbpd in 2008. The future expansion or contraction of our ethanol blending program will be driven by the economics of the ethanol supply and by government regulations. We sell reformulated gasoline, which is also blended with ethanol, in parts of our marketing territory, including: Chicago, Illinois; Louisville, Kentucky; northern Kentucky; and Milwaukee, Wisconsin. We also sell biodiesel-blended diesel in Illinois, Kentucky and Pennsylvania.

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

We are a producer and marketer of petrochemicals and specialty products. Product availability varies by refinery and includes benzene, cumene, dilute naphthalene oil, molten sulfur, propylene, toluene and xylene. We market propylene, cumene and sulfur domestically to customers in the chemical industry. We also have the capacity to produce 1,400 tons per day of anode grade coke at our Robinson refinery, which is used to make carbon anodes for the aluminum smelting industry, and 5,600 tons per day of fuel grade coke at the Garyville refinery, which is used for power generation and in miscellaneous industrial applications.

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

We have refinery based asphalt production capacity of up to 92 mbpd. We market asphalt through 33 owned or leased terminals throughout the Midwest and Southeast. We have a broad customer base, including approximately 641 asphalt-paving contractors, government entities (states, counties, cities and townships) and asphalt roofing shingle manufacturers. We sell asphalt in the wholesale and cargo markets via rail and barge. We also produce asphalt cements, polymer modified asphalt, emulsified asphalt and industrial asphalts.

We hold a 35 percent interest in an entity which owns and operates a 110-million-gallon-per-year ethanol production facility in Clymers, Indiana. We also own a 50 percent interest in an entity which owns a 110-million-gallon-per-year ethanol production facility in Greenville, Ohio. Both of these facilities are managed by a co-owner.

Pipeline transportation – We own a system of pipelines through Marathon Pipe Line LLC (“MPL”) and Ohio River Pipe Line LLC (“ORPL”), our wholly-owned subsidiaries. Our pipeline systems transport crude oil and refined products primarily in the Midwest and Gulf Coast regions to our refineries, our terminals and other pipeline systems. Our MPL

 

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and ORPL wholly-owned and undivided interest common carrier systems consist of 1,707 miles of crude oil lines and 1,825 miles of refined product lines comprising 31 systems located in 11 states. The MPL common carrier pipeline network is one of the largest petroleum pipeline systems in the U.S., based on total barrels delivered. Our common carrier pipeline systems are subject to state and Federal Energy Regulatory Commission regulations and guidelines, including published tariffs for the transportation of crude oil and refined products. Third parties generated 11 percent of the crude oil and refined product shipments on our MPL and ORPL common carrier pipelines in 2010. Our MPL and ORPL common carrier pipelines transported the volumes shown in the following table for each of the last three years.

 

Pipeline Barrels Handled                     
(mbpd)    2010      2009      2008  

Crude oil trunk lines

     1,204        1,279        1,405  

Refined products trunk lines

     968        953        960  
                          

Total

     2,172        2,232        2,365  

We also own 175 miles of private crude oil pipelines and 846 miles of private refined products pipelines, and we lease 217 miles of common carrier refined product pipelines. We have partial ownership interests in several pipeline companies that have approximately 110 miles of crude oil pipelines and 3,600 miles of refined products pipelines, including about 970 miles operated by MPL. In addition, MPL operates most of our private pipelines and 985 miles of crude oil and 160 miles of natural gas pipelines owned by our E&P segment.

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

In addition, as of December 31, 2010, we had interests in the following refined product pipelines:

 

   

65 percent undivided ownership interest in the Louisville-Lexington system, a petroleum products pipeline system extending from Louisville to Lexington, Kentucky;

 

   

60 percent interest in Muskegon Pipeline LLC, which owns a refined products pipeline extending from Griffith, Indiana, to North Muskegon, Michigan;

 

   

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

 

   

17 percent interest in Explorer Pipeline Company, a refined products pipeline system extending from the Gulf Coast to the Midwest; and

 

   

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

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

As of December 31, 2010, we had interests in the following crude oil pipelines:

 

   

51 percent interest in LOOP LLC, the owner and operator of LOOP, which is the only U.S. deepwater oil port, located 18 miles off the coast of Louisiana, and a crude oil pipeline connecting the port facility to storage caverns and tanks at Clovelly, Louisiana;

 

   

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

 

   

33 percent undivided joint interest in the Capline system, a large-diameter crude oil pipeline extending from St. James, Louisiana, to Patoka, Illinois;

 

   

26 percent undivided joint interest in the Maumee Pipeline System, a large diameter crude oil pipeline extending from Lima, Ohio, to Samaria, Michigan.

We plan to construct, by the end of 2012, a new section of pipeline connecting an existing pipeline to our Detroit refinery which will allow us to deliver additional supplies of Canadian crude.

The above discussion contains forward looking statements with respect to the plans to construct a new section of pipeline. Factors which could affect these plans include transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by necessary government and third-party approvals, and other risks customarily associated with construction projects.

 

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Retail Marketing

Speedway, our wholly-owned subsidiary headquartered in Enon, Ohio, sells gasoline and merchandise through owned and operated retail outlets primarily under the Speedway® brand. Diesel fuel is also sold at a number of these outlets. Speedway retail outlets offer a wide variety of merchandise, such as prepared foods, beverages, and non-food items, as well as a significant number of proprietary items. For eleven consecutive quarters ending September 30, 2010, Speedway has been rated as the best convenience store chain in terms of overall customer satisfaction in a national consumer perception survey conducted by Corporate Research International®. In 2010, Harris Interactive’s EquiTrend® annual brand equity study named Speedway® the number one gasoline brand with consumers for the second year in a row. Speedway’s Speedy Rewards™, an industry-leading customer loyalty program, has built active membership to 3.5 million customers.

As of December 31, 2010, Speedway had 1,358 retail outlets in seven states. Sales of refined products through these retail outlets accounted for 13 percent of our refined product sales volumes in 2010 and provide us with a base of ratable sales. Revenues from sales of non-petroleum merchandise through these retail outlets totaled $3,195 million in 2010, $3,109 million in 2009 and $2,838 million in 2008. The demand for gasoline is seasonal in a majority of Speedway markets, with the highest demand usually occurring during the summer driving season. Margins from the sale of merchandise and services tend to be less volatile than margins from the retail sale of gasoline and diesel fuel.

Competition and Market Conditions

Strong competition exists in all sectors of the oil and gas industry and, in particular, in the exploration for and development of new reserves. We compete with major integrated and independent oil and gas companies, as well as national oil companies, for the acquisition of oil and natural gas leases and other properties. We compete with these companies for the equipment and labor required to develop and operate those properties and in the marketing of oil and natural gas to end-users. Many of our competitors have financial and other resources greater than those available to us. Acquiring exploration opportunities frequently requires competitive bids involving front-end bonus payments or commitments-to-work programs. We also compete in attracting and retaining personnel, including geologists, geophysicists and other specialists. Based upon statistics compiled in the “2010 Global Upstream Performance Review” published by IHS Herold Inc., we rank ninth among U.S.-based petroleum companies on the basis of 2009 worldwide liquid hydrocarbon and natural gas production.

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

We must also compete with a large number of other companies to acquire crude oil for refinery processing and in the distribution and marketing of a full array of petroleum products. Based upon the “The Oil & Gas Journal 2010 Worldwide Refinery Survey”, we rank fifth among U.S. petroleum companies on the basis of U.S. crude oil refining capacity as of December 31, 2010. We compete in four distinct markets for the sale of refined products – wholesale, spot, branded and retail distribution. We believe we compete with about 56 companies in the sale of refined products to wholesale marketing customers, including private-brand marketers and large commercial and industrial consumers; about 91 companies in the sale of refined products in the spot market; ten refiners or marketers in the supply of refined products to refiner branded jobbers and dealers; and approximately 252 retailers in the retail sale of refined products. (A jobber is a business that does not carry out refining operations but supplies refiner-branded products to gasoline stations or convenience stores. Dealers refer to retail service station or convenience store operators affiliated with a brand identity.) We compete in the convenience store industry through Speedway’s retail outlets. The retail outlets offer consumers gasoline, diesel fuel (at selected locations) and a broad mix of other merchandise and services. Several nontraditional fuel retailers, such as supermarkets, club stores and mass merchants, have affected the convenience store industry and Energy Analysts International, Inc. estimates such retailers had 12 percent of the U.S. gasoline market in 2010.

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

 

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Environmental Matters

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

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

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

For a discussion of environmental capital expenditures and costs of compliance for air, water, solid waste and remediation, see Item 3. Legal Proceedings and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies.

Air

The U.S. Environmental Protection Agency (“EPA”) is in the process of implementing regulations to address the National Ambient Air Quality Standards (“NAAQS”) for fine particulate emissions and ozone. In connection with these standards, the EPA will designate certain areas as “nonattainment,” meaning that the air quality in such areas does not meet the NAAQS. The proposed rule is directed at electric generating units, not refineries, and is expected to be finalized in 2011. However, we cannot reasonably estimate any final financial impact of the state actions to implement the CATR until the EPA has issued a final rule and states have taken further action to implement that rule.

The EPA is reviewing and is proposing to revise, all NAAQS for criteria air pollutants. In January, 2010, the EPA issued the final nitrogen dioxide standard. In addition, in June 2010, the EPA published the final standard for sulfur dioxide. In December 2010, the EPA announced that the final ozone rule will be completed by July 29, 2011. We cannot reasonably estimate the final financial impact of these revised NAAQS standards until the implementing rules are established and judicial challenges over the revised NAAQS standards are resolved.

Water

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

 

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

Solid Waste

We continue to seek methods to minimize the generation of hazardous wastes in our operations. The RCRA establishes standards for the management of solid and hazardous wastes. Besides affecting waste disposal practices, RCRA also addresses the environmental effects of certain past waste disposal operations, the recycling of wastes and the regulation of underground storage tanks (“USTs”) containing regulated substances. We have ongoing RCRA treatment and disposal operations at one of our RM&T facilities and primarily utilize offsite third-party treatment and disposal facilities.

Remediation

We own or operate certain retail outlets where, during the normal course of operations, releases of refined products from USTs have occurred. Federal and state laws require that contamination caused by such releases at these sites be assessed and remediated to meet applicable standards. The enforcement of the UST regulations under RCRA has been delegated to the states, which administer their own UST programs. Our obligation to remediate such contamination varies, depending on the extent of the releases and the stringency of the laws and regulations of the states in which we operate. A portion of these remediation costs may be recoverable from the appropriate state UST reimbursement funds once the applicable deductibles have been satisfied. We also have other facilities which are subject to remediation under federal or state law. See Item 3. Legal Proceedings – Environmental Proceedings – Other Proceedings for a discussion of these sites.

The AOSP operations use established processes to mine deposits of bitumen from an open-pit mine, extract the bitumen and upgrade it into synthetic crude oils. Tailings are waste products created from the oil sands extraction process which are placed in ponds. The AOSP is required to reclaim its tailing ponds as part of its ongoing reclamation work. The reclamation process uses developing technology and there is an inherent risk that the current process may not be as effective or perform as required in order to meet the approved closure and reclamation plan. The AOSP continues to develop its current reclamation technology and continues to investigate other alternate tailings management technologies. In February 2009, the Alberta Energy Resources Conservation Board (“ERCB”) issued a directive which more clearly defines criteria for managing oil sands tailings. The AOSP Joint Venture Operator submitted tailings management papers to the ERCB (for both mines), that sets forth plans to comply with the Directive and received approval (with conditions) in the second half of 2010. Further new regulations or failure to comply (in a timely manner) could result in additional cost to us.

Other Matters

In 2007, the U.S. Congress passed the Energy Independence and Security Act (“EISA”), which, among other things, sets a target of 35 miles per gallon for the combined fleet of cars and light trucks in the United States by model year 2020, and contains a second Renewable Fuel Standard (“RFS2”). The EPA announced the final RFS2 regulations on February 4, 2010. The RFS2 requires 12.95 billion gallons of renewable fuel usage in 2010, increasing to 36.0 billion gallons by 2022. In the near term, the RFS2 will be satisfied primarily with fuel ethanol blended into gasoline. The RFS2 presents production and logistic challenges for both the fuel ethanol and petroleum refining industries. The RFS2 has required, and will likely in the future continue to require, additional capital expenditures or expenses by us to accommodate increased fuel ethanol use. Within the overall 36.0 billion gallon RFS2, EISA establishes an advanced biofuel RFS2 that begins with 0.95 billion gallons in 2010 and increases to 21.0 billion gallons by 2022. Subsets within the advanced biofuel RFS2 include 1.15 billion gallons of biomass-based diesel in 2010 (due to combining the 2009 and 2010 volumes), which is capped at 1.0 billion gallons starting in 2012, and 0.1 billion gallons of cellulosic biofuel in 2010, increasing to 16.0 billion gallons by 2022. The EPA has determined that 0.1 billion gallons of cellulosic biofuel will not be produced in 2010 and has lowered the requirement to 5.0 million gallons. The advanced biofuels programs will present specific challenges in that we may have to enter into arrangements with other parties to meet our obligations to use advanced biofuels, including biomass-based diesel and cellulosic biofuel, with potentially uncertain supplies of these new fuels. There will be compliance costs and uncertainties regarding how we will comply with the various requirements contained in this law and related regulations. We may experience a decrease in demand for refined petroleum products due to an increase in combined fleet mileage or due to refined petroleum products being replaced by renewable fuels.

 

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On October 13, 2010, the EPA issued a partial waiver decision under the CAA to allow for an increase in the amount of ethanol permitted to be blended into gasoline from 10 percent (“E10”) to 15 percent (“E15”) for 2007 and newer light-duty motor vehicles. There are numerous state and federal regulatory issues that would need to be addressed before E15 can be marketed for use in any traditional gasoline engines.

The USX Separation

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

 

   

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

 

   

USX Corporation changed its name to Marathon Oil Corporation.

As a result of the USX Separation, Marathon and United States Steel are separate companies and neither has any ownership interest in the other.

In connection with the USX 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 USX Separation and providing for the allocation of tax and certain other liabilities and obligations arising from periods before the USX Separation. The following is a description of the material terms of one of those agreements.

Financial Matters Agreement

Under the financial matters agreement, United States Steel has assumed and agreed to discharge all of our 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 us:

 

   

obligations under industrial revenue bonds related to environmental projects for current and former U.S. Steel Group facilities, with maturities ranging from 2011 through 2033;

 

   

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

 

   

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

 

   

certain other guarantees.

The financial matters agreement also provides that, on or before December 31, 2011, United States Steel will provide for our 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 us an amount equal to the remaining principal amount of all accrued and unpaid debt service outstanding on, and any premium required to immediately retire, the then outstanding industrial revenue bonds.

Under the financial matters agreement, United States Steel has all of the existing contractual rights under the leases assumed from us, 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 lease obligations without our prior consent other than extensions set forth in the terms of the assumed leases.

The financial matters agreement requires us to use commercially reasonable efforts to assure compliance with all covenants and other obligations to avoid the occurrence of a default or the acceleration of the payments on the assumed obligations.

United States Steel’s obligations to us 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.

Concentrations of Credit Risk

We are exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy-related industries. The creditworthiness of customers and other counterparties is subject to continuing review, including the use of master netting agreements, where appropriate. While no single customer accounts for more than 10 percent of annual revenues, we have exposures to United States Steel arising from the transaction discussed in Note 3 to the consolidated financial statements.

 

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Trademarks, Patents and Licenses

We currently hold a number of U.S. and foreign patents and have various pending patent applications. Although in the aggregate our trademarks, patents and licenses are important to us, we do not regard any single trademark, patent, license or group of related trademarks, patents or licenses as critical or essential to our business as a whole.

Employees

We had 29,677 active employees as of December 31, 2010. Of that number, 19,147 were employees of Speedway, most of whom were employed at our retail marketing outlets.

Certain hourly employees at our Catlettsburg and Canton refineries are represented by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers Union under labor agreements that expire on January 31, 2012. Certain employees at our Texas City refinery are represented by the same union under a labor agreement that expires on March 31, 2012.

The International Brotherhood of Teamsters represents certain hourly employees at our Detroit refinery under a labor agreement that is scheduled to expire on January 31, 2014. They also represent employees at the St. Paul Park refinery under a labor agreement that is scheduled to expire on May 31, 2012. The St. Paul Park Refinery was sold effective December 1, 2010, however there is a transition services agreement in place. Due to this agreement, we remain subject to the labor contracts until the employee transfer date. See Item 8. Financial Statements and Supplementary Data—Note 6 for transaction details.

Executive Officers of the Registrant

The executive officers of Marathon and their ages as of February 1, 2011, are as follows:

 

Clarence P. Cazalot, Jr.

     60         President and Chief Executive Officer

Janet F. Clark

     56         Executive Vice President and Chief Financial Officer

Eileen M. Campbell

     53         Vice President, Public Policy

Gary R. Heminger

     57         Executive Vice President, Downstream

Sylvia J. Kerrigan

     45         Vice President, General Counsel and Secretary

Paul C. Reinbolt

     55         Vice President, Finance and Treasurer

David E. Roberts, Jr.

     50         Executive Vice President, Upstream

Michael K. Stewart

     53         Vice President, Accounting and Controller

Howard J. Thill

     51         Vice President, Investor Relations and Public Affairs

With the exception of Mr. Roberts, all of the executive officers have held responsible management or professional positions with Marathon or its subsidiaries for more than the past five years.

 

   

Mr. Cazalot was appointed president and chief executive officer effective January 2002.

 

   

Ms. Clark was appointed executive vice president effective January 2007. Ms. Clark joined Marathon in January 2004 as senior vice president and chief financial officer.

 

   

Ms. Campbell was appointed vice president, public policy effective June 2010. Prior to this appointment, Ms. Campbell was Vice President, Human Resources since October 2000.

 

   

Mr. Heminger was appointed executive vice president, downstream effective July 2005. Mr. Heminger has served as president of Marathon Petroleum Company LP since September 2001.

 

   

Ms. Kerrigan was appointed vice president, general counsel and secretary effective November 1, 2009. Prior to this appointment, Ms. Kerrigan was assistant general counsel since January 1, 2003.

 

   

Mr. Reinbolt was appointed vice president, finance and treasurer effective January 2002.

 

   

Mr. Roberts joined Marathon in June 2006 as senior vice president, business development and was appointed executive vice president, upstream in April 2008. Prior to joining Marathon, he was employed by BG Group from 2003 as executive vice president/managing director responsible for Asia and the Middle East.

 

   

Mr. Stewart was appointed vice president, accounting and controller effective May 2006. Mr. Stewart previously served as controller from July 2005 to April 2006. Prior to his appointment as controller, Mr. Stewart was director of internal audit from January 2002 to June 2005.

 

   

Mr. Thill was appointed vice president, investor relations and public affairs effective January 2008. Mr. Thill was previously director of investor relations from April 2003 to December 2007.

 

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Available Information

General information about Marathon, including the Corporate Governance Principles and Charters for the Audit and Finance Committee, Compensation Committee, Corporate Governance and Nominating Committee and Public Policy Committee, can be found at www.marathon.com. In addition, our Code of Business Conduct and Code of Ethics for Senior Financial Officers are available at http://www.marathon.com/Investor_Center/.

Our 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 our website as soon as reasonably practicable after the reports are filed or furnished with the SEC. These documents are also available in hard copy, free of charge, by contacting our Investor Relations office. Information contained on our website is not incorporated into this Annual Report on Form 10-K or other securities filings.

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. The following summarizes significant risks and uncertainties that may adversely affect our business, financial condition or results of operations.

The proposed spin-off of MPC is contingent upon the satisfaction of a number of conditions, which may not be consummated on the terms or timeline currently contemplated or may not achieve the intended results.

We expect that the spin-off will be effective June 30, 2011. Our ability to timely effect the spin-off is subject to several conditions, including among others, the receipt of a favorable private letter ruling from the IRS, an independent tax opinion that the distribution of one share of MPC common stock for every two shares of Marathon will qualify as tax-free and the SEC declaring effective the registration statement. We cannot assure that we will be able to complete the spin-off in a timely fashion, if at all. For these and other reasons, the spin-off may not be completed on the terms or timeline contemplated. Further, if the spin-off is completed, it may not achieve the intended results. Any such difficulties could adversely affect our business, results of operations or financial condition.

The spin-off could result in substantial tax liability.

We have requested a private letter ruling from the Internal Revenue Service (“IRS”) substantially to the effect that, for U.S. federal income tax purposes, the spin-off and certain related transactions will qualify under Sections 355 and/or 368 of the U.S. Internal Revenue Code of 1986, as amended (the “Code”). If the factual assumptions or representations made in the request for the private letter ruling prove to have been inaccurate or incomplete in any material respect, then we will not be able to rely on the ruling. Furthermore, the IRS does not rule on whether a distribution such as the spin-off satisfies certain requirements necessary to obtain tax-free treatment under section 355 of the Code. The private letter ruling will be based on representations by us that those requirements were satisfied, and any inaccuracy in those representations could invalidate the ruling. In connection with the spin-off, we also intend to obtain an opinion of outside counsel, substantially to the effect that, for U.S. federal income tax purposes, the spin-off and certain related transactions will qualify under Sections 355 and 368 of the Code. The opinion will rely on, among other things, the continuing validity of the private letter ruling and various assumptions and representations as to factual matters made by us which, if inaccurate or incomplete in any material respect, would jeopardize the conclusions reached by such counsel in its opinion. The opinion will not be binding on the IRS or the courts, and there can be no assurance that the IRS or the courts would not challenge the conclusions stated in the opinion or that any such challenge would not prevail.

A substantial or extended decline in liquid hydrocarbon or natural gas prices, or in refining and wholesale marketing gross margins, would reduce our operating results and cash flows and could adversely impact our future rate of growth and the carrying value of our assets.

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

 

   

worldwide and domestic supplies of and demand for liquid hydrocarbons, natural gas and refined products;

 

   

the cost of exploring for, developing and producing liquid hydrocarbons and natural gas;

 

   

the cost of crude oil to be manufactured into refined products;

 

   

utilization rates of refineries;

 

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natural gas and electricity supply costs incurred by refineries;

 

   

the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) to agree to and maintain production controls;

 

   

political instability or armed conflict in oil and natural gas producing regions;

 

   

changes in weather patterns and climate;

 

   

natural disasters such as hurricanes and tornados;

 

   

the price and availability of alternative and competing forms of energy;

 

   

domestic and foreign governmental regulations and taxes; and

 

   

general economic conditions worldwide.

The long-term effects of these and other factors on the prices of liquid hydrocarbons and natural gas, as well as on refining and wholesale marketing gross margins, are uncertain.

Lower liquid hydrocarbon and natural gas prices, may cause us to reduce the amount of these commodities that we produce, which may reduce our revenues, operating income and cash flows. Significant reductions in liquid hydrocarbon and natural gas prices or refining and wholesale marketing gross margins could require us to reduce our capital expenditures or impair the carrying value of our assets.

Our offshore operations involve special risks that could negatively impact us.

Offshore exploration and development operations present technological challenges and operating risks because of the marine environment. Activities in deepwater areas may pose incrementally greater risks because of water depths that limit intervention capability and the physical distance to oilfield service infrastructure and service providers. Environmental remediation and other costs resulting from spills or releases may result in substantial liabilities and could materially and adversely affect our business, financial condition, results of operations, cash flow and market value of our securities.

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

The proved reserve information included in this report has been derived from engineering estimates. Estimates of liquid hydrocarbon and natural gas reserves were prepared by our in-house teams of reservoir engineers and geoscience professionals and were reviewed, on a selected basis, by our Corporate Reserves Group or third-party consultants. The synthetic crude oil reserves estimates were prepared by GLJ Petroleum Consultants, a third-party consulting firm experienced in working with oil sands. Reserves were priced at the unweighted average of closing prices for the first day of each month in the 12-month period ended December 31, 2010, as well as other conditions in existence at the date. Any significant future price changes will have a material effect on the quantity and present value of our proved reserves. Future reserve revisions could also result from changes in governmental regulation, among other things.

Reserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of liquid hydrocarbons, natural gas and bitumen that cannot be directly measured. (Bitumen is mined then upgraded into synthetic crude oil.) Estimates of economically producible reserves and of future net cash flows depend upon a number of variable factors and assumptions, including:

 

   

location, size and shape of the accumulation as well as fluid, rock and producing characteristics of the accumulation;

 

   

historical production from the area, compared with production from other comparable producing areas;

 

   

volumes of bitumen in-place and various factors affecting the recoverability of bitumen and its conversion into synthetic crude oil such as historical upgrader performance;

 

   

the assumed effects of regulation by governmental agencies;

 

   

assumptions concerning future operating costs, severance and excise taxes, development costs and workover and repair costs, and

 

   

industry economic conditions, levels of cash flows from operations and other operating considerations.

 

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As a result, different petroleum engineers, each using industry-accepted geologic and engineering practices and scientific methods, may produce different estimates of proved reserves and future net cash flows based on the same available data. Because of the subjective nature of such reserve estimates, each of the following items may differ materially from the amounts or other factors estimated:

 

   

the amount and timing of production;

 

   

the revenues and costs associated with that production; and

 

   

the amount and timing of future development expenditures.

The discounted future net revenues from our proved liquid hydrocarbon, natural gas and synthetic crude oil reserves reflected in this report should not be considered as the market value of the reserves attributable to our properties. As required by SEC Rule 4-10 of Regulation S-X, the estimated discounted future net revenues from our proved liquid hydrocarbon, natural gas and synthetic crude oil reserves are based on an unweighted average of closing prices for the first day of each month in the 12-month period ended December 31, 2009, and costs applicable at the date of the estimate, while actual future prices and costs may be materially higher or lower.

In addition, the 10 percent discount factor required by the applicable rules of the SEC to be used to calculate discounted future net revenues for reporting purposes is not necessarily the most appropriate discount factor based on our cost of capital and the risks associated with our business and the oil and natural gas industry in general.

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

The rate of production from liquid hydrocarbon and natural gas properties generally declines as reserves are depleted. Except to the extent we acquire interests in additional properties containing proved reserves, conduct successful exploration and development activities or, through engineering studies, optimize production performance, identify additional reservoirs not currently producing or secondary recovery reserves, our proved reserves will decline materially as liquid hydrocarbons and natural gas are produced. Accordingly, to the extent we are not successful in replacing the liquid hydrocarbons and natural gas we produce, our future revenues will decline. Creating and maintaining an inventory of prospects for future production depends on many factors, including:

 

   

obtaining rights to explore for, develop and produce liquid hydrocarbons and natural gas in promising areas;

 

   

drilling success;

 

   

the ability to complete long lead-time, capital-intensive projects timely and on budget;

 

   

the ability to find or acquire additional proved reserves at acceptable costs; and

 

   

the ability to fund such activity.

The availability of crude oil and increases in crude oil prices may reduce our refining, marketing and transportation profitability and refining and wholesale marketing gross margins.

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

Restrictions on U.S. Gulf of Mexico deepwater operations and similar action by countries where we do business could have a significant impact on our operations.

Although the deepwater drilling moratorium imposed by the U.S. Department of the Interior suspending outer continental shelf subsea and floating facility operations was lifted on October 12, 2010, we cannot predict when necessary plans and permits will be approved for renewed offshore drilling activity other than completions, interventions and workovers. An extended regulatory delay on other deepwater drilling activities in the Gulf of Mexico or changes in laws or

 

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regulations affecting our operations in these areas could have a material adverse effect on our business, financial condition, results of operations, cash flow and market value of our securities. In addition, other countries where we do business may make changes to their laws or regulations governing offshore operations, including deepwater areas that could have a similar material adverse effect.

We may incur substantial capital expenditures and operating costs as a result of compliance with, and changes in environmental health, safety and security laws and regulations, and, as a result, our business, financial condition, results of operation and cash flow could be materially and adversely affected.

Our businesses are subject to numerous laws, regulations and other requirements relating to the protection of the environment, including those relating to the discharge of materials into the environment, waste management, pollution prevention, greenhouse gas emissions, and characteristics and composition of gasoline and diesel fuels, as well as laws and regulations relating to public and employee safety and health and to facility security. We have incurred and may continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. The specific impact of these laws and regulations may vary depending on a number of factors, including the age and location of operating facilities, marketing areas, crude oil and feedstock sources, and production processes. We may also be required to make material expenditures to modify operations, install pollution control equipment, perform site cleanups or curtail operations that could materially and adversely affect business, financial condition, results of operation and cash flows. We may become subject to liabilities that we currently do not anticipate in connection with new, amended or more stringent requirements, stricter interpretations of existing requirements or the future discovery of contamination. In addition, any failure by us to comply with existing or future laws or regulations could result in civil penalties or criminal fines and other enforcement actions against us.

We believe it is likely that the scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations that could affect our operations. Currently, various legislative and regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides) are in various phases of review, discussion or implementation in countries where we operate: the United States, Canada, European Union (“EU”) and Norway. Our operations result in these greenhouse gas emissions and emissions also arise from the use of our refined petroleum products by our customers. Through 2010, these included proposed federal legislation and state actions to develop statewide or regional programs, each of which could impose reductions in greenhouse gas emissions. These actions could result in increased: (1) costs to operate and maintain our facilities, (2) capital expenditures to install new emission controls at our refineries and other facilities, and (3) costs to administer and manage any potential greenhouse gas emissions or carbon trading or tax programs or to produce fuels to meet low-carbon fuel standards. These costs and capital expenditures could be material. Although uncertain, these developments could increase our costs, reduce the demand for the products we sell, reduce the supply of crude oils which can be used and create delays in our obtaining air pollution permits for new or modified facilities. Legislation or regulatory activity that impacts or could impact our operations includes:

 

   

EPA issued a finding that greenhouse gases contribute to air pollution that endangers public health and welfare. In April of 2010, the EPA finalized a greenhouse gas emission standard for mobile sources (cars and light duty vehicles). The endangerment finding, along with the mobile source standard, and EPA’s determination that greenhouse gases are subject to regulation under the CAA, will lead to widespread regulation of stationary sources of greenhouse gas emissions. As a result, the EPA has issued a so-called tailoring rule to limit the applicability of the EPA’s major permitting programs to larger sources of greenhouse gas emissions, such as our refineries and a few large production facilities. Although legal challenges have been filed against these EPA actions, no court decisions are expected for another year or more and the EPA permitting requirements will apply to our larger facilities starting in January 2011. EPA has also announced its plan to develop refining sector new source performance standards for greenhouse gas emissions with standards to be proposed in December 2011 and final standards to be adopted in December 2012.

 

   

In the U.S., the House of Representatives and the Senate each had their own form of cap-and-trade legislation to reduce carbon emissions in the Congressional session ending in 2010. The House approved the Waxman-Markey Bill in 2009 and the Senate considered but did not approve any such legislation. Similar legislation may be introduced in 2011 in the new Congressional session or the legislation may seek to limit or delay implementation of the EPA greenhouse gas emission requirements. Among other actions, cap and trade systems require businesses that emit greenhouse gases to buy emission credits from the government, other businesses, or through an auction process.

 

   

Although not ratified in the United States, the Kyoto Protocol, effective in 2005, has been ratified by countries in which we have or in the future may have operations.

 

   

The non-binding Copenhagen Accord was reached in 2009 with the United States pledging to reduce emissions 17 percent below 2005 levels by 2020.

 

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The Canadian federal government has not enacted greenhouse gas emission reduction legislation although in signing the Copenhagen Accord, reaffirmed its commitment to reduce the country’s emissions 17 percent from 2005 levels by 2020. Alberta enacted legislation effective in 2007 which requires large emission sources such as oil sands facilities to reduce their net emissions intensity by 12 percent as measured against their baseline emissions. Sources may also comply by making a compliance obligation payment or by purchasing verifiable offsets.

 

   

The European Union Emissions Trading Scheme (“EU ETS”) is in its second phase which runs from 2008 to 2012, in which EU member governments provide a certain number of free allowances to facilities and a facility may purchase additional EU allowances from other facilities, traders and the government. For, 2010, our EU facilities have complied with the EU ETS by using the allocated free allowances. Norway, as a member of the European Economic Area, while not in the European Union, has a carbon tax and also participates in the EU ETS. For 2010, our Norway facilities complied with the EU ETS by purchasing carbon allowances in the market.

 

   

The Canadian federal government and province of Alberta jointly announced their intent to partially fund the AOSP’s Quest Carbon Capture and Storage (“Quest CCS”) project. Under the terms of their letters of intent, Alberta would contribute 745 million Canadian dollars and the Government of Canada would provide 120 million Canadian dollars toward the project’s development. The Quest project would store approximately 1.1 million tons of carbon dioxide annually and should allow the AOSP to meet Canadian and Alberta emission reduction requirements for the foreseeable future. The operator intends to finalize the government funding agreements in the first quarter of 2011. A final investment decision on the Quest CCS project will be made at a later date, and is subject to regulatory approvals, stakeholder engagement, detailed engineering studies, as well as the agreement of joint venture partners.

 

   

The State of California enacted legislation effective in 2007 capping California’s greenhouse gas emissions at 1990 levels by 2020 and is implementing this legislation through a low-carbon fuel standard and a cap-and-trade program. The low-carbon fuel standard is being challenged in court. New Mexico has adopted a regulation which would reduce greenhouse gas emissions from current levels by three percent annually starting in 2012. We have not conducted significant business in California in recent years and discontinued operations in New Mexico in 2009, but other states where we have operations could adopt similar greenhouse gas limitations.

Although there may be adverse financial impact (including compliance costs, potential permitting delays and potential reduced demand for crude oil or certain refined products) associated with any legislation, regulation, the EPA or other action, the extent and magnitude of that impact cannot be reliably or accurately estimated due to the fact that requirements have only recently been adopted and the present uncertainty regarding the additional measures and how they will be implemented. Private party litigation has also been brought against emitters of greenhouse gas emissions, but we have not been named in those cases.

If we are unable to complete capital projects at their expected costs and in a timely manner, or if the market conditions assumed in our project economics deteriorate, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

Delays or cost increases related to capital spending programs involving engineering, procurement and construction of facilities (including improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted internal rates of return and operating results. Delays in making required changes or upgrades to our facilities could subject us to fines or penalties as well as affect our ability to supply certain products we produce. Such delays or cost increases may arise as a result of unpredictable factors, many of which are beyond our control, including:

 

   

denial of or delay in receiving requisite regulatory approvals and /or permits;

 

   

unplanned increases in the cost of construction materials or labor;

 

   

disruptions in transportation of components or construction materials;

 

   

adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of vendors or suppliers;

 

   

shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

 

   

market-related increases in a project’s debt or equity financing costs; and

 

   

nonperformance by, or disputes with, vendors, suppliers, contractors or subcontractors.

Any one or more of these factors could have a significant impact on our ongoing capital projects. If we were unable to make up the delays associated with such factors or to recover the related costs, or if market conditions change, it could materially and adversely affect our business, financial conditions, results of operations and cash flows.

 

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Many of our major projects and operations are conducted with partners, which may decrease our ability to manage risk.

We often enter into arrangements to conduct certain business operations, such oil and gas exploration and production, oil sands mining or pipeline transportation, with partners in order to share risks associated with those operations. However, these arrangements also may decrease our ability to manage risks and costs, particularly where we are not the operator. We could have limited influence over and control of the behaviors and performance of these operations. This could affect our operational performance, financial position and reputation.

Financial market uncertainty could impact our ability to obtain future financing.

In the future we may require financing to grow our business. Financial institutions participate in our revolving credit facility and provide us with services including insurance, cash management, commercial letters of credit, derivative instruments, and short-term investments. A deterioration of the financial market conditions could significantly increase our costs associated with borrowing. Our liquidity and our ability to access the credit and/or capital markets could also be adversely affected by changes in the financial markets and the global economy.

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

Local political and economic factors in global markets could have a material adverse effect on us. A total of 67 percent of our liquid hydrocarbon and natural gas sales volumes in 2010 was derived from production outside the United States and 72 percent of our proved liquid hydrocarbon and natural gas reserves as of December 31, 2010, were located outside the United States. All of our synthetic crude oil production and proved reserves are located in Canada. In addition, a significant portion of the feedstock requirements for our refineries is satisfied through supplies originating in Saudi Arabia, Kuwait, Canada, Mexico and various other foreign countries. We are, therefore, subject to the political, geographic and economic risks and possible terrorist activities attendant to doing business with suppliers located in, and supplies originating from, those areas. There are many risks associated with operations in countries and in global markets, such as Equatorial Guinea, Indonesia, Libya and the Iraqi Kurdistan Region, including

 

   

changes in governmental policies relating to liquid hydrocarbon, natural gas, bitumen, synthetic crude oil or refined product pricing and taxation;

 

   

other political, economic or diplomatic developments and international monetary fluctuations;

 

   

political and economic instability, war, acts of terrorism and civil disturbances;

 

   

the possibility that a government may seize our property with or without compensation, may attempt to renegotiate or revoke existing contractual arrangements or may impose additional taxes or royalty burdens; and

 

   

fluctuating currency values, hard currency shortages and currency controls.

In recent weeks, civil unrest, which began in Tunisia, has spread to other parts of North Africa and the Middle East. There have been demonstrations by protestors demanding regime changes in countries such as Egypt, Libya, Yemen and Bahrain. Some of these demonstrations have been violent particularly in Libya where we have operations. If such unrest continues to spread, conflicts could result in civil wars, regional conflicts, and regime changes resulting in governments that are hostile to the United States. These may have the following results, among others:

 

   

Volatility in global crude oil prices which could negatively impact the global economy, resulting in slower economic growth rates and reduced demand for our products;

 

   

Negative impact on the world crude oil supply if transportation avenues are disrupted;

 

   

Security concerns leading to the prolonged evacuation of our personnel;

 

   

Damage to, or the inability to access, production facilities or other operating assets;

 

   

Inability of our service and equipment providers to deliver items necessary for us to conduct our operations; and

 

   

Imposition of trade sanctions by the U.S. government on Libya.

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

 

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

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

Our exploration and production operations are subject to unplanned occurrences, including blowouts, explosions, fires, loss of well control, spills, hurricanes and other adverse weather, labor disputes and accidents. Our oil sands mining operations are subject to business interruptions due to breakdown or failure of equipment or processes and unplanned events such as fires, earthquakes, explosions or other interruptions. In addition, our refining, marketing and transportation operations are subject to business interruptions due to scheduled refinery turnarounds and unplanned events such as explosions, fires, pipeline ruptures or other interruptions, crude oil or refined product spills, severe weather and labor disputes. These same risks can be applied to the third-parties which transport crude oil and refined products to, from and among facilities. A prolonged disruption in the ability of any pipeline or vessels to transport crude oil or refined products could contribute to a business interruption or increase costs.

Our operations are also subject to the additional hazards of pollution, releases of toxic gas and other environmental hazards and risks, as well as hazards of marine operations, such as capsizing, collision, acts of piracy and damage or loss from severe weather conditions. These hazards could result in serious personal injury or loss of human life, significant damage to property and equipment, environmental pollution, impairment of operations and substantial losses to us. Various hazards have adversely affected us in the past, and damages resulting from a catastrophic occurrence in the future involving us or any of our assets or operations may result in our being named as a defendant in one or more lawsuits asserting potentially large claims or in our being assessed potentially substantial fines by governmental authorities. We maintain insurance against many, but not all, potential losses or liabilities arising from operating hazards in amounts that we believe to be prudent. Uninsured losses and liabilities arising from operating hazards could reduce the funds available to us for capital, exploration and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Historically, we have maintained insurance coverage for physical damage and resulting business interruption to our major onshore and offshore facilities, with significant self-insured retentions. In the future, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies have increased substantially and could escalate further. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, due to hurricane activity in recent years, the availability of insurance coverage for our offshore facilities for windstorms in the Gulf of Mexico region has been reduced or, in many instances, it is prohibitively expensive. As a result, our exposure to losses from future windstorm activity in the Gulf of Mexico region has increased.

Litigation by private plaintiffs or government officials could adversely affect our performance.

We currently are defending litigation and anticipate that we will be required to defend new litigation in the future. The subject matter of such litigation may include releases of hazardous substances from our facilities, products liability, consumer credit or privacy laws, product pricing or antitrust laws or any other laws or regulations that apply to our operations. While an adverse outcome in most litigation matters would not be expected to be material to us, in some cases the plaintiff or plaintiffs seek alleged damages involving large classes of potential litigants, and may allege damages relating to extended periods of time or other alleged facts and circumstances. If we are not able to successfully defend such claims, they may result in substantial liability. We do not have insurance covering all of these potential liabilities. There has been a trend in recent years of litigation by attorneys general and other government officials seeking to recover civil damages from companies. We are defending litigation of that type and anticipate that we will be required to defend new litigation of that type in the future. In addition to substantial liability, litigation may also seek injunctive relief which could have an adverse effect on our future operations.

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

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

 

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Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The location and general character of our principal liquid hydrocarbon and natural gas properties, oil sands mining properties and facilities, refineries, pipeline systems and other important physical properties have been described by segment under Item 1. Business. Except for oil and gas producing properties, including oil sands mines, 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.

Net liquid hydrocarbon, natural gas, and synthetic crude oil sales volumes, with net bitumen production volumes are set forth in Item 8. Financial Statements and Supplementary Data – Supplemental Statistics. Estimated net proved liquid hydrocarbon, natural gas and synthetic crude oil reserves are set forth in Item 8. Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities – Estimated Quantities of Proved Oil and Gas Reserves. The basis for estimating these reserves is discussed in Item 1. Business – Reserves.

Item 3. Legal Proceedings

We are defendant in a number of lawsuits arising in the ordinary course of business, including, but not limited to, royalty claims, contract claims and environmental claims. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that the resolution of these proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. Certain of these matters are discussed below.

Environmental Proceedings

U.S. EPA Litigation

In 2006, we and other oil and gas companies joined the State of Wyoming in filing a petition for review against the U.S. EPA in the U.S. District Court for the District of Wyoming. These actions seek a court order mandating the U.S. EPA to disapprove Montana’s 2006 amended water quality standards, on grounds that the standards lack sound scientific justification, they are arbitrary and capricious, and were adopted contrary to law. The water quality amendments at issue could require more stringent discharge limits and have the potential to require certain Wyoming coal bed methane operations to perform more costly water treatment or inject produced water. Approval of these standards could delay or prevent obtaining permits needed to discharge produced water to streams flowing from Wyoming into Montana. In February 2008, the U.S. EPA approved Montana’s 2006 regulations, and we amended our petition for review. The court stayed this case while the U.S. EPA mediated the matter between Montana, Wyoming and the Northern Cheyenne tribe. The mediation was unsuccessful; however the Court ultimately vacated the U.S. EPA’s approval of the 2003 and 2006 Montana standards and remanded the matter to the U.S. EPA with instructions for reconsideration. The federal government filed a Notice of Appeal, but subsequently filed a voluntary Motion to dismiss which was granted by the District Court.

New Mexico Litigation

In December 2008, the State of New Mexico filed a state court suit against us alleging violations of the New Mexico Air Quality Control Act. The lawsuit arose out of a February 2008 notice of violation issued to our Indian Basin Natural Gas Plant. We believe there has been no adverse impact to public health or the environment, having implemented voluntary emission reduction measures over the years. We have finalized a consent order and the court has approved it. The order required a cash penalty of $610,560 plus plant compliance projects and supplemental environmental projects estimated to cost over $5 million. We paid the cash penalty of $610,560 and entered into a Supplemental Consent Decree, approved by the court on July 30, 2010, pursuant to which we would pay $2.7 million as a civil penalty in lieu of one of the proposed supplemental environmental projects. All of these payments were made on August 11, 2010. Installation of the plant compliance projects was completed on November 15, 2010, by the current operator of the plant. We were the operator and part owner of the plant through June 2009. We are working with the other plant owners to obtain reimbursement for their share of these costs. The State of New Mexico has agreed the case should be dismissed and the consent decree terminated. A draft joint motion to the court has been prepared and was submitted to NMED for approval.

Powder River Basin Litigation

The U.S. Bureau of Land Management (“U.S. BLM”) completed multi-year reviews of potential environmental impacts from coal bed methane development on federal lands in the Powder River Basin, including those in Wyoming. The U.S. BLM signed a Record of Decision (“ROD”) on April 30, 2003, supporting increased coal bed methane development.

 

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Plaintiff environmental and other groups filed suit in May 2003 in federal court against the U.S. BLM to stop coal bed methane development on federal lands in the Powder River Basin until the U.S. BLM conducted additional environmental impact studies. We intervened as a party in the ongoing litigation before the Wyoming Federal District Court. As these lawsuits to delay energy development in the Powder River Basin progressed through the courts, the U.S. BLM continued to process permits to drill under the ROD. During the last quarter of 2008, the Court ruled in U.S. BLM’s favor, finding its environmental studies and stewardship were adequate and protective under federal law. Plaintiffs appealed this ruling to the 10th Circuit Court of Appeals, which affirmed the district court’s decision on June 18, 2010. Plaintiffs did not seek certiorari from the Supreme Court of the United States in this matter. Thus, this matter is concluded.

Pipeline Enforcement Matters

The U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (“PHMSA”) issued a Notice of Probable Violation (“NOPV”), Proposed Civil Penalty, and Proposed Compliance Order to Marathon Pipe Line LLC (“MPL”) related to the March 10, 2009 incident at St. James, Louisiana. PHMSA has proposed a civil penalty in the amount of approximately $1 million. PHMSA granted MPL extensions in which to respond to the Notice of Probable Violation. On January 25, 2011, MPL filed its request for a hearing in response to the NOPV.

Other Environmental Proceedings

The following is a summary of proceedings involving us that were pending or contemplated as of December 31, 2010, 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 Legal Proceedings above takes such matters into account.

Claims under CERCLA and related state acts have been raised with respect to the clean-up of various waste disposal and other sites. CERCLA is intended to facilitate the clean-up 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 clean-up costs and the time period during which such costs may be incurred, we are unable to reasonably estimate our ultimate cost of compliance with CERCLA.

The projections of spending for and/or timing of completion of specific projects provided in the following paragraphs 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 and/or timing of completion of environmental projects may differ materially from those stated in the forward-looking statements.

As of December 31, 2010, we had been identified as a PRP at a total of eight CERCLA waste sites. Based on currently available information, which is in many cases preliminary and incomplete, we believe that our liability for clean-up and remediation costs in connection with three of these sites will be under $100,000 and with one site will be under $200,000. As to two sites, we believe that our liability for clean-up and remediation costs will be under $1 million per site. As to the remaining two sites, we believe that our liability for clean-up and remediation costs will be under $4 million for one of the sites and over $5 million for the other site. In addition, there are four sites for which we have received information requests or other indications that we may be a PRP under CERCLA, but for which sufficient information is not presently available to confirm the existence of liability.

There are also 116 sites, excluding retail marketing outlets, where remediation is being sought under other environmental statutes, both federal and state, or where private parties are seeking remediation through discussions or litigation. Based on currently available information, which is in many cases preliminary and incomplete, we believe that liability for clean-up and remediation costs in connection with five of these sites will be under $100,000 per site, that 57 sites have potential costs between $100,000 and $1 million per site and that 28 sites may involve remediation costs between $1 million and $5 million per site. Twelve sites have incurred remediation costs equal to or greater than $5 million per site. With respect to the remaining 14 sites, Ashland Inc (“Ashland”) retains responsibility to us for remediation, subject to caps and other requirements contained in the agreements with Ashland related to the acquisition of Ashland’s minority interest in Marathon Petroleum Company LP in 2005. We estimate that we will be responsible for $11.4 million in remediation costs at these sites which will not be reimbursed by Ashland, and we have included this amount in our accrued environmental remediation liabilities as of December 31, 2010.

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 26 years, we anticipate spending approximately $5 million in remediation costs at this site. In 2011, interim remediation measures will continue to occur and appropriate site characterization and risk-based assessments nec

 

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essary for closure will be refined and may change the estimated future expenditures for this site. The closure strategy being developed for this site and ongoing work at the site are subject to approval by the MDEQ. Expenditures for remedial measures in 2010 and 2009 were $221,000 and $291,000, respectively, with expenditures for remedial measures in 2011 expected to be approximately $1.5 million.

We are subject to a pending enforcement matter with the Illinois Environmental Protection Agency and the Illinois Attorney General’s Office since 2002 concerning self-reporting of possible emission exceedences and permitting issues related to storage tanks at the Robinson, Illinois refinery. There were no developments in this matter in 2010.

During 2001, we entered into a New Source Review consent decree and settlement of alleged CAA and other violations with the U.S. EPA covering all of our refineries. The settlement committed us to specific control technologies and implementation schedules for environmental expenditures and improvements to our refineries over approximately an eight-year period, which are now substantially complete. In addition, we have been working on certain agreed-upon supplemental environmental projects as part of this settlement and these have been completed. As part of this consent decree, we were required to conduct evaluations of refinery benzene waste air pollution programs (benzene waste “NESHAPS”). Pursuant to a modification to our New Source Review consent decree, we have agreed with the U.S. Department of Justice and the U.S. EPA to pay a civil penalty of $408,000 and conduct supplemental environmental projects of approximately $1 million, as part of a settlement of an enforcement action for alleged Clean Air Act violations relating to benzene waste NESHAPS. This modification was finalized as of June 30, 2010, and the civil penalty has been paid.

OSHA previously announced a National Emphasis Program to inspect most domestic oil refineries. The inspections began in 2007 and focused on compliance with the OSHA Process Safety Management requirements. OSHA or state-equivalent agencies have conducted inspections at our Canton, Robinson, Catlettsburg, Detroit and Texas City refineries with agreed–to penalties of $321,500 and $135,000 imposed in Canton and Texas City, respectively. No penalties were imposed as a result of the other inspections. An inspection occurred at Garyville in 2010, however no enforcement action by OSHA or equivalent state agency has resulted.

In January 2011, the U.S. EPA notified us of 18 alleged violations of various statutory and regulatory provisions related to motor fuels, some of which we had previously self-reported to the U.S. EPA. No formal enforcement action has been commenced and no demand for penalties has been asserted by the U.S. EPA in connection with these alleged violations. However, it is possible that U.S. EPA could seek penalties in excess of $100,000 in connection with one or more of the alleged violations.

 

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PART II

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

The principal market on which Marathon common stock is traded is the New York Stock Exchange. As of January 31, 2011, there were 52,216 registered holders of Marathon common stock.

The following table reflects high and low sales prices for Marathon common stock and the related dividend per share by quarter for the past two years:

 

     2010      2009  
Dollars per share      High Price        Low Price        Dividends          High Price        Low Price        Dividends    

Quarter 1

   $ 32.85      $ 28.04      $ 0.24      $ 29.87      $ 20.92      $ 0.24  

Quarter 2

     34.11        30.19        0.25        33.41        27.08        0.24  

Quarter 3

     34.98        30.21        0.25        33.88        28.03        0.24  

Quarter 4

     37.03        33.07        0.25        35.27        30.48        0.24  

Full Year

             37.03                28.04                0.99                35.27                20.92                0.96  

Dividends

Our 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 the dividend policy with respect to Marathon common stock, the Board will rely on our consolidated financial statements of Marathon. Dividends on Marathon common stock are limited to our legally available funds.

Issuer Purchases of Equity Securities

The following table provides information about purchases by Marathon and its affiliated purchaser during the quarter ended December 31, 2010, of equity securities that are registered by Marathon pursuant to Section 12 of the Securities Exchange Act of 1934:

 

     Column (a)       Column (b)        Column (c)      Column (d)  
Period    Total Number of
Shares
Purchased
(a)
    Average
Price Paid
per Share
     Total Number of
Shares Purchased
as Part of
Publicly
Announced Plans
or Programs
(c)
     Approximate
Dollar Value of
Shares that May
Yet Be Purchased
Under the Plans
or Programs
(c)
 

10/01/10 – 10/31/10

     1,530     $ 33.62                         -       $       2,080,366,711   

11/01/10 – 11/30/10

     23,382     $ 35.68         -       $ 2,080,366,711   

12/01/10 – 12/31/10

             43,505  (b)    $ 35.11         -       $ 2,080,366,711   

Total

     68,417     $ 35.27         -            
(a)

25,884 shares of restricted stock were delivered by employees to Marathon, upon vesting, to satisfy tax withholding requirements.

 

(b)

42,533 shares were repurchased in open-market transactions to satisfy the requirements for dividend reinvestment under the Marathon Oil Corporation Dividend Reinvestment and Direct Stock Purchase Plan (the “Dividend Reinvestment Plan”) by the administrator of the Dividend Reinvestment Plan. Shares needed to meet the requirements of the Dividend Reinvestment Plan are either purchased in the open market or issued directly by Marathon.

 

(c)

We announced a share repurchase program in January 2006, and amended it several times in 2007 for a total authorized program of $5 billion. As of December 31, 2010, 66 million split adjusted common shares had been acquired at a cost of $2,922 million, which includes transaction fees and commissions that are not reported in the table above. No shares have been repurchased under this program since August 2008.

 

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Item 6. Selected Financial Data

 

(Dollars in millions, except as noted)    2010(a)     2009(b)(c)     2008(b)(c)(d)     2007(b)(c)(e)(f)     2006(b)(c)(g)  

Statement of Income Data

          

Revenues

   $     72,321      $     53,287      $     76,589      $     63,845      $     64,246   

Income from continuing operations

     2,568        1,184        3,384        3,766        4,787   

Net income

     2,568        1,463        3,528        3,956        5,234   

Per Share Data

          

Basic :

          

Income from continuing operations

   $ 3.62      $ 1.67      $ 4.77      $ 5.46      $ 6.69   

Net income

   $ 3.62      $ 2.06      $ 4.97      $ 5.73      $ 7.31   

Diluted :

          

Income from continuing operations

   $ 3.61      $ 1.67      $ 4.75      $ 5.42      $ 6.63   

Net income

   $ 3.61      $ 2.06      $ 4.95      $ 5.69      $ 7.25   

Statement of Cash Flows Data

          

Additions to property, plant and equipment

   $ 4,762      $ 6,231      $ 6,989      $ 3,757      $ 3,325   

Dividends paid

     704        679        681        637        547   

Dividends per share

   $ 0.99      $ 0.96      $ 0.96      $ 0.92      $ 0.76   

Balance Sheet Data as of December 31:

          

Total assets

   $ 50,014      $ 47,052      $ 42,686      $ 42,746      $ 30,831   

Total long-term debt, including capitalized leases

     7,601        8,436        7,087        6,084        3,061   
(a)

Includes long-lived asset impairments of $479 million primarily related to E&P segment assets (see Item 8. Financial Statements and Supplementary Data—Note 15 to the consolidated financial statements).

 

(b)

We have revised prior year amounts as discussed in Item 8. Financial Statements and Supplementary Data—Note 1 to the consolidated financial statements. Revenues were reduced by $183 million in 2009, $165 million in the 2008, $251 million in 2007 and $193 million in 2006; however, consolidated income did not change because an offsetting amount is in cost of revenues.

 

(c)

Our businesses in Ireland and Gabon were sold in 2009. Previous periods have been recast to reflect these businesses in discontinued operations.

 

(d)

Includes a $1,412 million impairment of goodwill related to the OSM reporting unit, (see Note 14 to the consolidated financial statements) and a $25 million after-tax impairment ($40 million pretax) related to our investments in ethanol producing companies.

 

(e)

On October 18, 2007, we completed the acquisition of all the outstanding shares of Western Oil Sands Inc.

 

(f)

Effective May 1, 2007, we no longer consolidate EGHoldings and our investment in EGHoldings is accounted for under the equity method of accounting; therefore, EGHoldings’ additions to property, plant and equipment subsequent to April 2007 are not included in our capital expenditures.

 

(g)

Effective April 1, 2006, we changed our accounting for matching buy/sell transactions. This change had no effect on income from continuing operations or net income, but the revenues and cost of revenues recognized after April 1, 2006, are less than the amounts that would have been recognized under previous accounting practices.

 

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

We are a global integrated energy company with significant operations in North America, Africa and Europe. Our operations are organized into four reportable segments:

 

   

Exploration and Production (“E&P”) which explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis.

 

   

Oil Sands Mining (“OSM”) which mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and vacuum gas oil.

 

   

Integrated Gas (“IG”) which markets and transports products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol, on a worldwide basis.

 

   

Refining, Marketing & Transportation (“RM&T”) which refines, markets and transports crude oil and petroleum products, primarily in the Midwest, Gulf Coast and southeastern regions of the United States.

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the information under Item 1. Business, Item 1A. Risk Factors, Item 6. Selected Financial Data and Item 8. Financial Statements and Supplementary Data.

Plan to Create Independent Downstream Company

On January 13, 2011, the Board of Directors of Marathon Oil Corporation (“Marathon”) announced that it has approved moving forward with plans to spin off Marathon’s downstream (Refining, Marketing and Transportation) business, creating two independent energy companies: Marathon Petroleum Corporation (“MPC”) and Marathon Oil Corporation (“MRO”). To effect the spin-off, Marathon intends to distribute one share of MPC for every two shares of Marathon held at a record date to be determined. The transaction is expected to be effective June 30, 2011, with distribution of MPC shares shortly thereafter. A tax ruling request was submitted to the U.S. Internal Revenue Service (“IRS”) regarding the tax-free nature of the spin-off and Marathon anticipates a response during the second quarter of 2011.

Overview – Market Conditions

Exploration and Production

Prevailing prices for the various grades of crude oil and natural gas that we produce significantly impact our revenues and cash flows. Prices have been volatile in recent years, but both West Texas Intermediate crude oil and Dated Brent crude oil monthly average prices remained in the $75 to $85 per barrel range during much of 2010. Crude oil prices rose sharply through the first half of 2008 as a result of strong global demand, a declining dollar, ongoing concerns about supplies of crude oil, and geopolitical risk. Later in 2008, crude oil prices sharply declined as the U.S. dollar rebounded and global demand decreased as a result of economic recession. The price decrease continued into 2009, but reversed after dropping below $33.98 in February, ending the year 2009 at $79.36. The following table lists benchmark crude oil and natural gas price annual averages for the past three years.

 

Benchmark    2010      2009      2008  

WTI crude oil (Dollars per barrel)

   $   79.61      $   62.09      $   99.75  

Dated Brent crude oil (Dollars per barrel)

   $ 79.50      $ 61.67      $ 97.26  

Henry Hub natural gas (Dollars per mcf)(a)

   $ 4.39      $ 3.99      $ 9.04  
(a)

First-of-month price index.

Our domestic crude oil production is about 73 percent sour. Sour crude contains more sulfur than light sweet WTI does. Sour crude oil also tends to be heavier than light sweet crude oil and sells at a discount to light sweet crude oil because of higher refining costs and lower refined product values. Our international crude oil production is relatively

 

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sweet and is generally sold in relation to the Dated Brent crude benchmark. The differential between WTI and Dated Brent average prices narrowed to $0.11 in 2010 compared to $0.42 in 2009 and $2.49 in 2008.

Natural gas prices on average were higher in 2010 than in 2009, although below the high levels experienced in 2008. A significant portion of our natural gas production in the lower 48 states of the U.S. is sold at bid-week prices or first-of-month indices relative to our specific producing areas. Our other major natural gas-producing regions are Europe and Equatorial Guinea, where our natural gas sales have been and, in the case of Equatorial Guinea primarily, still are subject to term contracts, making realized prices in these areas less volatile. The natural gas being sold from these regions, primarily Equatorial Guinea, are at fixed prices; therefore, our reported average natural gas realized prices may not fully track market price movements.

Oil Sands Mining

Oil Sands Mining segment revenues correlate with prevailing market prices for the various qualities of synthetic crude oil we produce. Roughly two-thirds of the normal output mix will track movements in WTI and one-third will track movements in the Canadian heavy sour crude oil marker, primarily Western Canadian Select. Output mix can be impacted by operational problems or planned unit outages at the mine or the upgrader.

The operating cost structure of the oil sands mining operations is predominantly fixed and therefore many of the costs incurred in times of full operation continue during production downtime. Per-unit costs are sensitive to production rates. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company (“AECO”) natural gas sales index and crude prices respectively.

The table below shows average benchmark prices that impact both our revenues and variable costs.

 

Benchmark    2010      2009      2008  

WTI crude oil (Dollars per barrel)

   $     79.61      $     62.09      $     99.75  

Western Canadian Select (Dollars per barrel)(a)

   $ 65.31      $ 52.13      $ 79.59  

AECO natural gas sales index (Dollars per mmbtu)(b)

   $ 3.89      $ 3.49      $ 7.74  
(a)

Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.

(b)

Monthly average Alberta Energy Company day ahead index.

Integrated Gas

Our integrated gas operations include marketing and transportation of products manufactured from natural gas, such as LNG and methanol, primarily in west Africa, the U.S. and Europe.

Our most significant LNG investment is our 60 percent ownership in a production facility in Equatorial Guinea, which sells LNG under a long-term contract at prices tied to Henry Hub natural gas prices. In 2010 and 2009, the gross sales from the plant were 3.7 million and 3.9 million metric tonnes, while in 2008, its first full year of operations, the plant sold 3.4 million metric tonnes. World LNG trade in 2010 has been estimated to be 219 million metric tonnes, while worldwide capacity increased approximately 31 million metric tonnes in 2010 as new LNG supply projects began operation. LNG demand also increased as global economics bounced back from the economic crisis. Long-term LNG continues to be in demand as markets seek the benefits of clean burning natural gas. Market prices for LNG are not reported or posted. In general, LNG delivered to the U.S. is tied to Henry Hub prices and will track with changes in U.S. natural gas prices, while LNG sold in Europe and Asia is indexed to crude oil prices and will track the movement of those prices.

We own a 45 percent interest in a methanol plant located in Equatorial Guinea through our investment in AMPCO. Gross sales of methanol from the plant totaled 850,605, 960,374 and 792,794 metric tonnes in 2010, 2009 and 2008. Methanol demand has a direct impact on AMPCO’s earnings. Because global demand for methanol is rather limited, changes in the supply-demand balance can have a significant impact on sales prices. World demand for methanol in 2010 has been estimated to be 45 million metric tonnes. Our plant capacity of 1.1 million metric tonnes is about 3 percent of total demand.

Refining, Marketing and Transportation

RM&T segment income depends largely on our refining and wholesale marketing gross margin, refinery throughputs and retail marketing gross margins for gasoline, distillates and merchandise.

 

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Our refining and wholesale marketing gross margin is the difference between the prices of refined products sold and the costs of crude oil and other charge and blendstocks refined, including the costs to transport these inputs to our refineries, the costs of purchased products and manufacturing expenses, including depreciation. The crack spread is a measure of the difference between market prices for refined products and crude oil, commonly used by the industry as a proxy for the refining margin. Crack spreads can fluctuate significantly, particularly when prices of refined products do not move in the same relationship as the cost of crude oil. As a performance benchmark and a comparison with other industry participants, we calculate Midwest (Chicago) and U.S. Gulf Coast crack spreads that we feel most closely track our operations and slate of products. Light Louisiana Sweet (“LLS”) crude oil prices and a 6-3-2-1 ratio of products (6 barrels of crude oil producing 3 barrels of gasoline, 2 barrels of distillate and 1 barrel of residual fuel) are used for the crack spread calculation.

Our refineries can process significant amounts of sour crude oil which typically can be purchased at a discount to sweet crude oil. The amount of this discount, the sweet/sour differential, can vary significantly causing our refining and wholesale marketing gross margin to differ from the crack spreads which are based upon sweet crude. In general, a larger sweet/sour differential will enhance our refining and wholesale marketing gross margin. In 2010, the sweet/sour differential widened, due to a variety of worldwide economic and petroleum industry related factors, including higher hydrocarbon demand. The sweet/sour differential widening contributed to the increase in our 2010 refining and wholesale marketing gross margin compared to 2009. In 2009, the sweet/sour differential narrowed, due to a variety of worldwide economic and petroleum industry related factors, primarily related to lower hydrocarbon demand. Sour crude accounted for 54 percent, 50 percent and 52 percent of our crude oil processed in 2010, 2009 and 2008.

The following table lists calculated average crack spreads for the Midwest (Chicago) and Gulf Coast markets and the sweet/sour differential for the past three years.

 

(Dollars per barrel)    2010      2009      2008  

Chicago LLS 6-3-2-1

   $       3.04      $       3.52      $ 3.27  

U.S. Gulf Coast LLS 6-3-2-1

   $ 2.14      $ 2.54      $ 2.45  

Sweet/Sour differential(a)

   $ 7.71      $ 5.82      $         11.99  
(a)

Calculated using the following mix of crude types as compared to LLS: 15% Arab Light, 20% Kuwait, 10% Maya, 15% Western Canadian Select, 40% Mars.

In addition to the market changes indicated by the crack spreads and sweet/sour differential, our refining and wholesale marketing gross margin is impacted by factors such as:

 

   

the types of crude oil and other charge and blendstocks processed,

 

   

the selling prices realized for refined products,

 

   

the impact of commodity derivative instruments used to manage price risk,

 

   

the cost of products purchased for resale, and

 

   

changes in manufacturing costs, which include depreciation.

Manufacturing costs are primarily driven by the cost of energy used by our refineries and the level of maintenance costs. Planned major maintenance activities, or turnarounds, requiring temporary shutdown of certain refinery operating units, are periodically performed at each refinery. Planned turnaround and major maintenance activities were completed at our Garyville, Louisiana; Catlettsburg, Kentucky; Detroit, Michigan; Texas City, Texas and Robinson, Illinois refineries in 2010. This compares turnarounds and major maintenance activities that were completed at our Catlettsburg, Robinson and Garyville refineries in 2009 and at our Catlettsburg, Garyville, Robinson and Canton, Ohio, refineries in 2008.

Our retail marketing gross margin for gasoline and distillates, which is the difference between the ultimate price paid by consumers and the cost of refined products, including secondary transportation and consumer excise taxes, also impacts RM&T segment profitability. There are numerous factors including local competition, seasonal demand fluctuations, the available wholesale supply, the level of economic activity in our marketing areas and weather conditions that impact gasoline and distillate demand throughout the year. After decreasing in 2008 and 2009, refined product demand for the U.S. increased in 2010 associated with the slow economic recovery. For our marketing area, we estimate a distillate demand increase of eight percent in 2010 while gasoline demand remained constant from 2009 levels. For 2009, gasoline demand declined about one percent and distillate demand declined about 12 percent from 2008 levels. The product margin that we can realize generally increases or decrease along with market demand for gasoline and distillates. The gross margin on merchandise sold at retail outlets has been historically less volatile.

 

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2010 Highlights

E&P Segment

 

   

Expanded opportunities in unconventional, liquids-rich U.S. resource plays: the Niobrara in southeast Wyoming and northern Colorado, Oklahoma’s Anadarko Woodford Shale, the Eagle Ford Shale in south Texas and the Bakken Shale in western North Dakota.

 

   

Acquired positions in four exploration blocks in the Iraqi Kurdistan Region.

 

   

Continued Bakken Shale production ramp-up, added a sixth rig in the third quarter.

 

   

Added ten onshore exploration licenses with shale gas potential in Poland for a total of 11 licenses.

 

   

Continued successful exploration program in Libya with seven discoveries.

 

   

Commenced production from the deepwater Gulf of Mexico Droshky development in Green Canyon Block 244.

OSM Segment

 

   

Commenced start-up of the Canadian Jackpine Mine operations in the third quarter, with an ongoing phased start-up of the expanded upgrader operations.

Reserves

 

   

Added net proved reserves, for the E&P and OSM segments combined, of 112 mmboe, excluding dispositions.

IG Segment

 

   

Achieved operational availability of better than 97 percent at the Equatorial Guinea LNG facility during the year.

Refining, Marketing and Transportation Segment

 

   

Completed full integration of refinery units added as part of the Garyville Major Expansion project and realized increased refining capacity.

 

   

Progressed construction of the Detroit Heavy Oil Upgrading Project to approximately 50 percent as of year-end, with completion expected in the second half of 2012.

 

   

Increased Speedway same store gasoline sales volumes and merchandise sales 3 percent and 4 percent respectively, compared to 2009.

 

   

Speedway® named best gasoline brand in the nation in its category, by the 2010 EquiTrend® Brand Study, for the second consecutive year.

Divestitures

 

   

Sold an undivided 20 percent outside-operated interest in the Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola in February 2010.

 

   

Sold our St. Paul Park, Minnesota, refinery (including associated terminal, tankage and pipeline investments) and 166 SuperAmerica retail outlets, plus related inventories in December 2010.

 

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Consolidated Results of Operations: 2010 compared to 2009

Revenues are summarized in the following table:

 

(In millions)    2010     2009  

E&P

   $ 11,019     $ 7,949  

OSM

     920       723  

IG

     150       50  

RM&T

     62,487       45,530  
                

Segment revenues

         74,576           54,252  

Elimination of intersegment revenues

     (2,255     (1,037

Gain on U.K. natural gas contracts

     -        72  
                

Total revenues

   $ 72,321     $ 53,287  
                

Items included in both revenues and costs:

    

Consumer excise taxes on petroleum products and merchandise

   $ 5,208     $ 4,924  

E&P segment revenues increased $3,070 million from 2009 to 2010, primarily due to higher average liquid hydrocarbon and natural gas realizations, slightly offset by lower liquid hydrocarbon and natural gas sales volumes. On average, our net worldwide liquid hydrocarbon realizations were 30 percent higher in 2010 than in 2009 and our net worldwide natural gas realizations were 13 percent higher. While liquid hydrocarbon sales volumes in 2010 benefited from the Droshky development in the Gulf of Mexico, which commenced production mid-year 2010, sales volumes were lower overall. The lower sales volumes in 2010 were primarily the result of a turnaround that was completed in the second quarter of 2010 at the production facilities in Equatorial Guinea, natural field declines and 2009 asset dispositions.

 

      2010      2009  

E&P Operating Statistics

     

Net Liquid Hydrocarbon Sales (mbpd)(a)

     

United States

     70        64  

Europe

     92        92  

Africa

     83        87  
                 

Total International

             175                179  
                 

Worldwide Continuing Operations

     245        243  

Discontinued Operations(b)

     -         5  
                 

Worldwide

     245        248  

Natural Gas Sales (mmcfd)

     

United States

     364        373  

Europe(c)

     105        138  

Africa

     409        430  
                 

Total International

     514        568  
                 

Worldwide Continuing Operations

     878        941  

Discontinued Operations(b)

     -         17  
                 

Worldwide

     878        958  

Total Worldwide Sales (mboepd)

     

Continuing Operations

     391        400  

Discontinued Operations(b)

     -         7  
                 

Worldwide

     391        407  

 

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      2010      2009  

E&P Operating Statistics

     

Average Realizations(d)

     

Liquid Hydrocarbons (per bbl)

     

United States

   $ 72.30      $ 54.67  

Europe

     81.95        64.46  

Africa

     71.71        53.91  

Total International

     77.11        59.31  

Worldwide Continuing Operations

     75.73        58.09  

Discontinued Operations(b)

     -         56.47  

Worldwide

   $       75.73      $       58.06  

Natural Gas (per mcf)

     

United States

   $ 4.71      $ 4.14  

Europe

     7.10        4.90  

Africa

     0.25        0.25  

Total International

     1.65        1.38  

Worldwide Continuing Operations

     2.91        2.47  

Discontinued Operations(b)

     -         8.54  

Worldwide

   $ 2.91      $ 2.58  
(a)

Includes crude oil, condensate and natural gas liquids. The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.

(b)

Our businesses in Ireland and Gabon were sold in 2009 and were reported as discontinued operations.

(c)

Includes natural gas acquired for injection and subsequent resale of 18 mmcfd and 22 mmcfd in 2010 and 2009.

(d)

Excludes gains and losses on derivative instruments and the unrealized effects of U.K. natural gas contracts that are accounted for as derivatives.

E&P segment revenues included derivative gains of $95 million and losses of $13 million in 2010 and 2009. Excluded from E&P segment revenues were gains of $72 million in 2009 related to natural gas sales contracts in the U.K. that were accounted for as derivative instruments. These U.K contracts expired in September 2009.

OSM segment revenues increased $197 million from 2009 to 2010. Revenues were impacted by net gains of $25 million and $13 million in 2010 and 2009 on derivative instruments. Excluding the derivatives impact, the increase in revenue reflects the 26 percent increase in synthetic crude oil realizations. Synthetic crude oil sales volumes were lower in 2010 due to the impact of the planned turnaround at the Muskeg River mine and upgrader that began March 22, 2010 and halted production in April before a staged resumption of operations in May.

RM&T segment revenues increased $16,957 million from 2009 to 2010 due to relative price level changes and increased refined product sales volumes. The increase in sales volumes is primarily related to production from the Garyville, Louisiana refinery expansion. The table below shows the average annual refined product benchmark prices for our marketing area:

 

(Dollars per gallon)    2010      2009  

Chicago Spot Unleaded regular gasoline

   $ 2.09       $ 1.68   

Chicago Spot Ultra-low sulfur diesel

   $ 2.17       $ 1.66   

U.S. Gulf Coast Spot Unleaded regular gasoline

   $ 2.05       $ 1.64   

U.S. Gulf Coast Spot Ultra-low sulfur diesel

   $ 2.16       $ 1.66   

Income from equity method investments increased $116 million in 2010 from 2009 primarily as the result of higher commodity prices on the earnings of many of our equity investees in 2010.

Net gain on disposal of assets in 2010 is related the pretax gain of $811 million on the sale of a 20 percent outside-operated interest in our E&P segment’s Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola. In 2009, we sold our operated and a portion of our outside-operated Permian Basin producing assets in New Mexico and west Texas, plus sales of other oil and gas properties and retail stores.

Cost of revenues increased $16,357 million from 2009 to 2010. The increase was primarily in the RM&T segment resulting from higher acquisition costs of crude oil and increased crude oil volume, primarily associated with increased production from our Garyville refinery.

 

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Depreciation, depletion and amortization increased $361 million in 2010 from 2009. The DD&A increase in the RM&T segment was related to the Garyville expansion being put into service at the end of 2009. In the E&P segment, the DD&A increase was primarily related to the higher sales volumes at a higher rate of DD&A per barrel on our domestic E&P assets.

Long-lived asset impairment in 2010 includes $423 million related to our Powder River Basin field in the first quarter, as well as smaller impairments to other E&P segment fields due to reductions in estimated reserves, reduced drilling expectations and declining natural gas prices. See Item 8. Financial Statements and Supplementary Data—Note 15 to the consolidated financial statements for further information about the impairments.

Provision for income taxes increased $297 million from 2009 to 2010 primarily due to the increase in pretax income. The effective rate, however, decreased from 66 percent in 2009 to 50 percent in 2010. The effective tax rate is influenced by the geographical mix of income and related tax expense. In 2009 more income was generated in high tax jurisdictions than in 2010. In addition, in 2009, it was determined that we may not be able to realize all recorded foreign tax benefits and therefore a valuation allowance was recorded against these benefits. See Item 8. Financial Statements and Supplementary Data—Note 10 to the consolidated financial statements.

Discontinued operations reflect the 2009 disposal of our E&P businesses in Ireland and Gabon and the historical results of those operations, net of tax, for all periods presented. See Item 8. Financial Statements and Supplementary Data—Note 6 to the consolidated financial statements.

Segment Results: 2010 compared to 2009

Segment income for 2010 and 2009 is summarized and reconciled to net income in the following table.

 

(In millions)    2010     2009  

E&P

    

United States

   $ 250     $ 55  

International

     1,690       1,166  
                

E&P segment

     1,940       1,221  

OSM

     (50     44  

IG

     142       90  

RM&T

     682       464  
                

Segment income

           2,714             1,819  

Items not allocated to segments, net of income taxes:

    

Corporate and other unallocated items

     (180     (422

Foreign currency effects on tax balances

     32       (319

Gain on disposal of assets

     407       114  

Impairments(a)

     (303     (45

Gain on U.K. natural gas contracts(b)

     -        37  

Deferred income taxes -tax legislation changes

     (45     -   

Loss on early extinguishment of debt

     (57     -   

Discontinued operations

     -        279  
                

Net income

   $ 2,568     $ 1,463  
(a)

Impairments in 2010 include a $262 million impairment ($423 million pretax) of our Powder River Basin field, a $9 million ($15 million pretax) writeoff of the remaining contingent proceeds from the sale of the Corrib natural gas development, a $15 million after-tax impairment ($25 million pretax) related to our investments in gas technology, and a $17 million impairment ($28 million pretax) related to a plant that manufactures maleic anhydride. (See Item 8. Financial Statements and Supplementary Data—Note 15 to the consolidated financial statements.) Impairments in 2009 reflect a $45 million ($70 million pretax) writeoff of a portion of the contingent proceeds from the sale of the Corrib natural gas development. (See Item 8. Financial Statements and Supplementary Data—Note 9 to the consolidated financial statements). Impairments in 2008 include the $1,412 million impairment of goodwill related to the OSM reporting unit (See Item 8. Financial Statements and Supplementary Data—Note 14 to the consolidated financial statements) and the $25 million impairment ($40 million pretax) related to our investments in ethanol producing companies.

 

(b)

Amounts relate to natural gas contracts in the U. K. that are accounted for as derivative instruments and recorded at fair value.

 

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United States E&P income increased $195 million from 2009 to 2010. The majority of the income increase was primarily due to higher liquid hydrocarbon and natural gas realizations in 2009, along with higher liquid hydrocarbon sales volumes, partially offset by higher DD&A and higher exploration and operating costs. Exploration expenses were $275 million for the year 2010, compared to $153 million for 2009, reflecting increased geological and geophysical spending focused on shale plays and exploration dry well expense, primarily in the Flying Dutchman well in the Gulf of Mexico.

International E&P income increased $524 million from 2009 to 2010. This increase was primarily related to higher liquid hydrocarbon and natural gas realizations, partially offset by higher exploration expenses and income taxes. Exploration expenses were $223 million for the full year 2010, compared to $154 million for 2009, reflecting higher dry well expense with dry wells in Indonesia, Norway and Equatorial Guinea.

OSM segment income decreased $94 million from 2009 to 2010. Cost increases in 2010 associated with the planned turnaround at the AOSP and the Jackpine Mine start-up were in excess of the revenue increase previously discussed. Results for 2010 included after-tax gains on crude oil derivative instruments of $19 million, while the impact of derivatives on the 2009 periods was not significant.

IG segment income increased $52 million from 2009 to 2010. The increase in income was primarily the result of higher realizations for LNG and methanol.

RM&T segment income increased $218 million from 2009 to 2010, as a result of the increase in our refining and wholesale marketing gross margin per gallon from 6.10 cents in 2009 to 7.06 cents in 2010. The gross margin increase is primarily a result of a 32 percent widening of the sweet/sour differential, thereby decreasing the relative cost of crude processed by our refineries. The widening of the sweet/sour differential resulted from a variety of worldwide economic and petroleum industry related factors.

Also contributing to the increase in segment income were increases in our crude throughputs. We averaged 1,173 mbpd of crude oil throughput in 2010 compared to 957 mbpd in 2009 and increased our sour crude throughput by approximately 4 percent. Total refinery throughputs averaged 1,335 mbpd in 2010 compared to 1,153 mbpd in 2009. These throughputs were higher in 2010 than in 2009 primarily due to the Garyville refinery expansion, slightly offset by the reduction caused by the sale of the St. Paul Park refinery effective December 1, 2010 These favorable impacts to segment income were partially offset by increased manufacturing costs incurred related to the additional units at the Garyville refinery.

Included in the refining and wholesale marketing gross margins were pretax derivative losses of $29 million in 2010 and $83 million in 2009. For a more complete explanation of our strategies to manage market risk related to commodity prices, see Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

The following table includes certain key operating statistics for the RM&T segment for 2010 and 2009.

 

RM&T Operating Statistics    2010      2009  

Refining and wholesale marketing gross margin (Dollars per gallon)(a)

   $       0.0706      $       0.0610  

Refined products sales volumes (Thousands of barrels per day)

     1,585        1,378  
(a)

Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation.

 

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Consolidated Results of Operations: 2009 compared to 2008

Revenues are summarized in the following table:

 

(In millions)    2009     2008  

E&P

   $ 7,949     $ 12,246  

OSM

     723       1,213  

IG

     50       93  

RM&T

         45,530           64,481  
                

Segment revenues

     54,252       78,033  

Elimination of intersegment revenues

     (1,037     (1,662

Gain on U.K. natural gas contracts

     72       218  
                

Total revenues

   $ 53,287     $ 76,589  
                

Items included in both revenues and costs:

    

Consumer excise taxes on petroleum products and merchandise

   $ 4,924     $ 5,065  

E&P segment revenues decreased $4,297 million from 2008 to 2009, primarily due to lower average liquid hydrocarbon and natural gas realizations, partially offset by higher liquid hydrocarbon and natural gas sales volumes. On average, our net worldwide liquid hydrocarbon realizations were 35 percent lower in 2009 than in 2008 and our net worldwide natural gas realizations were 46 percent lower. Liquid hydrocarbon sales volumes in 2009 benefited from a full year production from both the Alvheim/Vilje development offshore Norway and the Neptune development in the Gulf of Mexico, which commenced production mid-year 2008. Natural gas sales volumes from Equatorial Guinea increased almost 16 percent from 2008 to 2009, more than making up for decreased sales as a result of our property divestitures in the Permian Basin of the U.S., Ireland and Norway. Because the majority of the natural gas sales increase was fixed-price sales to the LNG production facility in Equatorial Guinea, our average international natural gas realizations decreased by more than the market in general. Our share of the income ultimately generated by the subsequent export of LNG produced by EGHoldings, as well as methanol produced by AMPCO, is reflected in our Integrated Gas segment as discussed below.

 

      2009      2008  

E&P Operating Statistics

     

Net Liquid Hydrocarbon Sales (mbpd)(a)

     

United States

     64        63  

Europe

     92        55  

Africa

     87        87  
                 

Total International

             179                142  
                 

Worldwide Continuing Operations

     243        205  

Discontinued Operations(b)

     5        6  
                 

Worldwide

     248        211  

Natural Gas Sales (mmcfd)

     

United States

     373        448  

Europe(c)

     138        161  

Africa

     430        370  
                 

Total International

     568        531  
                 

Worldwide Continuing Operations

     941        979  

Discontinued Operations(b)

     17        37  
                 

Worldwide

     958        1,016  

Total Worldwide Sales (mboepd)

     

Continuing Operations

     400        369  

Discontinued Operations(b)

     7        12  
                 

Worldwide

     407        381  

 

44


Table of Contents
Index to Financial Statements
      2009      2008  

E&P Operating Statistics

     

Average Realizations(d)

     

Liquid Hydrocarbons (per bbl)

     

United States

   $ 54.67      $ 86.68  

Europe

             64.46                90.60  

Africa

     53.91        89.85  

Total International

     59.31        90.14  

Worldwide Continuing Operations

     58.09        89.07  

Discontinued Operations(b)

     56.47        96.41  

Worldwide

   $ 58.06      $ 89.29  

Natural Gas (per mcf)

     

United States

   $ 4.14      $ 7.01  

Europe

     4.90        7.67  

Africa

     0.25        0.25  

Total International

     1.38        2.50  

Worldwide Continuing Operations

     2.47        4.56  

Discontinued Operations(b)

     8.54        9.62  

Worldwide

   $ 2.58      $ 4.75  
(a)

Includes crude oil, condensate and natural gas liquids. The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.

 

(b)

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

 

(c)

Includes natural gas acquired for injection and subsequent resale of 22 mmcfd and 32 mmcfd in 2009 and 2008.

 

(d)

Excludes gains and losses on derivative instruments and the unrealized effects of U.K. natural gas contracts that are accounted for as derivatives.

E&P segment revenues included derivative losses of $13 million in 2009 and gains of $22 million in 2008. Excluded from E&P segment revenues were gains of $72 million in 2009 and $218 million in 2008 related to natural gas sales contracts in the U.K. that were accounted for as derivative instruments. These U.K contracts expired in September 2009.

OSM segment revenues decreased $490 million from 2008 to 2009. Revenues were impacted by net gains of $13 million in 2009 and $48 million in 2008 on derivative instruments, which expired December 2009. Excluding the derivatives, the decrease in revenue reflects the almost 40 percent decline in synthetic crude oil realizations. Synthetic crude oil sales volumes were consistent between the years.

RM&T segment revenues decreased $18,951 million from 2008 to 2009 matching relative price level changes. While our overall refined product sales volumes in 2009 were relatively unchanged compared to 2008, the level of average petroleum prices declined significantly as shown in Item 1. Business—Refining, Marketing and Transportation. The level of crude oil prices has a direct influence on our refined product prices. The table below shows the average annual refined product benchmark prices for our marketing area.

 

(Dollars per gallon)    2009      2008