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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 20082009

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)

 

 

 

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. Yes  þ    No  ¨

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 filerþ    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, 2008: $36,5592009: $21,272 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. However, the registrant has made no determination that such individuals are “affiliates” within the meaning of Rule 405 of the Securities Act of 1933.

There were 707,524,845707,926,768 shares of Marathon Oil Corporation Common Stock outstanding as of January 31, 2009.29, 2010.

Documents Incorporated By Reference:

Portions of the registrant’s proxy statement relating to its 20092010 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.

 

 

 


Index to Financial Statements

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 CONTENTSTable of Contents

 

      Page

PART I

    

Item 1.

  

Business

  21

Item 1A.

  

Risk Factors

  2527

Item 1B.

  

Unresolved Staff Comments

  3234

Item 2.

  

Properties

  3234

Item 3.

  

Legal Proceeding

  3234

Item 4.

  

Submission of Matters to a Vote of Security Holders

  3637

PART II

    

Item 5.

  

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

  3638

Item 6.

  Selected Financial Data  3839

Item 7.

  

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

  3940

Item 7A.

  Quantitative and Qualitative Disclosures about Market Risk  6967

Item 8.

  Financial Statements and Supplementary Data  7371

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

  132137

Item 9A.

  Control and Procedures  132137

Item 9B.

  Other Information  132137

PART III

    

Item 10.

  Directors, Executive Officers and Corporate Governance  132137

Item 11.

  Executive Compensation  133138

Item 12.

  

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

  133138

Item 13.

  Certain Relationships and Related Transactions, and Director Independence  134139

Item 14.

  Principal Accounting Fees and Services  134139

PART IV

    

Item 15.

  

Exhibits, Financial Statement Schedules

135

SIGNATURES

  140
SIGNATURES147

Index to Financial Statements

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, bitumensynthetic 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 bitumen;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

Item 1.Business

General

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

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

On October 18, 2007, we acquired all the outstanding shares of Western Oil Sands Inc. (“Western”). Western’s primary asset was a 20 percent outside-operated interest in the outside-operated Athabasca Oil Sands Project (“AOSP”), an oil sands mining joint venture located in the province of Alberta, Canada. The acquisition was accounted for under the purchase method of accounting and, as such, our results of operations include Western’s results from October 18, 2007. Western’s oil sands mining and bitumen upgrading operations are reported as a separate Oil Sands Mining

segment, while its ownership interests in leases where in-situ recovery techniques are expected to be utilized are included in the Exploration and Production segment.

Index to Financial Statements

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 market synthetic crude oil and by-products;vacuum gas oil; 3) Refining, Marketing and Transportation (“RM&T”) – refines, markets and transports crude oil and petroleum products, primarily in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the United States; and 4) Integrated Gas (“IG”) – markets and transports products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol, on a worldwide basis,basis; and is developing other projects to link stranded natural gas resources with key demand areas.4) Refining, Marketing and Transportation (“RM&T”) – refines, transports and markets crude oil and petroleum products, primarily in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the United States. For operating segment and geographic financial information, see Note 109 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.

We conductAt the end of 2009, we were conducting oil and gas exploration, development and production activities in teneight countries: the United States, Angola, Canada, Equatorial Guinea, Gabon, Indonesia, Ireland, Libya, Norway and the United Kingdom. During 2009, we exited Gabon and Ireland. We plan to begin exploration activities in Poland during 2010.

Our 20082009 worldwide net liquid hydrocarbon sales averaged 211243 thousand barrels per day (“mbpd”). Our 20082009 worldwide net natural gas sales, including natural gas acquired for injection and subsequent resale, averaged 1,016941 million cubic feet per day (“mmcfd”). In total, our 20082009 worldwide net sales averaged 381400 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.

Exploration These volumes exclude 7 mboepd related to discontinued operations.

In the United States during 2008,2009, we drilled 7176 gross (48(50 net) exploratory wells of which 6072 gross (42(48 net) wells encountered commercial quantities of hydrocarbons. Of these 6072 wells, 36 were temporarily suspended or in the process of being completed at year end. Internationally, we drilled 129 gross (3(1 net) exploratory wells of which 116 gross (3(1 net) wells encountered commercial quantities of hydrocarbons. Of these 11 wells, 5 gross (1 net)All 6 wells were temporarily suspended or were in the process of being completed at December 31, 2008.2009.

North America

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

Offshore – The Gulf of Mexico continues to be a core area. At the end of 2008, we had interests in 103 blocks in the Gulf of Mexico, including 97 in the deepwater area. We have been awarded 42 blocks on which we were the high bidder in the federal Outer Continental Shelf Lease Sales No. 205 and 206 conducted by the U.S. Minerals Management Service (“MMS”) in late 2007 and early 2008. Our initial net investment in these blocks was $343 million. We own 100 percent of fifteen of the blocks. We acquired the remaining blocks in conjunction with partners. Our plans call for initial drilling on some of these leases inDuring 2009, and 2010.

In 2008, a successful appraisal well was drilled on the Stones prospect located on Walker Ridge Block 508 after a 2005 discovery. We hold a 25 percent outside-operated interest in the Stones prospect. In the third quarter of 2008, we announced a Gulf of Mexico deepwater discovery on the Gunflint prospect located on Mississippi Canyon Block 948. We own a 13 percent outside-operated interest in the prospect. In the first quarter of 2009, we participated in a deepwater discovery on the Shenandoah prospect located on Walker Ridge Block 52. We own a 20 percent outside-operated interest in the prospect.

In 2008, we successfully completed our first horizontal well in the Woodford Shale resource play in the Anadarko Basin of Oklahoma. We are currently participating in additional horizontal wells in the area where we hold 30,000 net acres.

We hold acreage in two additional emerging shale resource plays in the U.S. In the Appalachian Basin we hold 65,000 net acres in the Marcellus Shale resource play in Pennsylvania and West Virginia. We hold 25,000 net acres, primarily in Texas, in the Haynesville Shale resource play located in north Louisiana and east Texas. Initial drilling on some of these leases is planned for 2009.

Angola – Offshore Angola, we hold a 10 percent outside-operated interest in Block 31 and a 30 percent outside-operated interest in Block 32. Through December 2008, 28 discoveries on these blocks have been announced, including the Portia and Dione discoveries on Angola Block 31 in 2008.

Index to Financial Statements

NorwayWe hold interests in over 510,000 gross acres offshore Norway, including production license 505 (“PL 505”) that was awarded in January 2009. In 2009, exploration drilling is expected to commence on additional prospects with the potential to be tied back to the Alvheim complex.

Indonesia – We are the operator and hold a 70 percent interest in the Pasangkayu Block offshore Indonesia. The 1.2 million acre block is located mostly in deep water, predominantly offshore of the island of Sulawesi in the Makassar Strait, directly east of the Kutei Basin production region. The production sharing contract with the Indonesian government was signed in 2006 and we completed 3D seismic acquisition in May 2008. We expect to begin exploratory drilling in early 2010. Additionally, in October 2008, we were granted a 49 percent interest and operatorship in the Bone Bay Block offshore Indonesia. The Bone Bay Block is 200 miles southeast of our Pasangkayu Block. Current exploration plans for Bone Bay call for the acquisition of seismic data starting in 2010, followed by drilling in 2011.

We are the operator of a drilling rig consortium that has secured a two-year contract for a deepwater exploration drilling rig. The rig will be used for deepwater exploration activities by us and by five other companies in Indonesia. The participants have the right to extend this rig commitment.

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

Equatorial Guinea – During 2004, we announced the Deep Luba and Gardenia discoveries on the Alba Block, in which we hold a 63 percent operated interest, and the Corona well on Block D, where we are the operator with a 90 percent interest. 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.

Libya – We hold a 16 percent outside-operated interest in the Waha concessions, which encompass almost 13 million acres located in the Sirte Basin. Our exploration program in 2008 included the drilling of three wells, all of which were successful. Most of these discoveries extended previously defined hydrocarbon accumulations.

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. Initial test drilling on the 100 percent interest Birchwood prospect positively confirmed bitumen presence with additional test drilling required to confirm reservoir quality.

United Kingdom – We have a 45 percent interest in five exploratory U.K. onshore coal seam gas (“CSG”) licenses. Drilling has been completed in five exploration wells in three of the licenses. One test well was completed in 2007 and three lateral wells for production testing were drilled in 2008. We and our partners were awarded 11 new blocks for CSG exploration and potential future development during the 13th Onshore Licensing Round in 2008. After the 2008 licensing our interest covers 520,000 acres. We are the operator of these new licenses and have a 55 percent working interest.

Production (including development activities)

United States –Our U.S. operations accounted for 30 percent of our 2008 worldwide net liquid hydrocarbon sales volumes and 44 percent of our worldwide net natural gas sales volumes.

During 2008, our net sales in the Gulf of Mexico averaged 2324 mbpd of liquid hydrocarbons representing 36 percent of our total U.S. net liquid hydrocarbon sales, and 20 mmcfd of natural gas, representing five percent of our total U.S. net natural gas sales.gas. At year end 2008,2009, we held interests in sixseven producing fields and fivefour platforms in the Gulf of Mexico, of which we operate one platform.

Hurricanes Gustav and Ike impacted GulfWe operate the Ewing Bank 873 platform which is located 130 miles south of MexicoNew Orleans, Louisiana. The platform started operations in 1994 and serves as a production hub for the latter part of the third quarter of 2008, resulting in approximately 9.5 net mboepd being shut-in during the quarter.Lobster, Oyster and Arnold fields. The Ewing Bank development resumedfacility also processes third-party production in October 2008, but the outside-operated Ursa and Troika fields were shut-in for repairs until November 2008 and January 2009, respectively, impacting fourth quarter sales by approximately 7 mboepd. We have a 65 percent working interest in Ewing Bank, a four percent overriding royalty interest in Ursa and a 50 percent working interest in Troika.via subsea tie-backs.

We own a 50 percent outside-operated interest in the outside-operated Petronius field on Viosca Knoll Blocks 786 and 830. An additional development well was successfully completed in 2009. The Petronius platform also providesis capable of providing processing and transportation services to adjacentnearby third-party fields. For example, Petronius processes liquid hydrocarbons from our Perseus field which commenced production in April 2005 and is located five miles from the platform.

Index to Financial Statements

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

In October 2008, developmentDevelopment of the Droshky discovery, located in the Gulf of Mexico on Green Canyon Block 244, was authorized by our boardcontinued in 2009. Droshky Phase I is a four well liquid hydrocarbon development with first production targeted for mid-year 2010. Ongoing development activities include running intelligent well completions, installation of directors. The initial Droshky discovery wellthe subsea facilities and two sidetracks were drilled in 2007, followed in 2008 by a second delineation and sidetrack well. The project will consist of development wells, which will be tied backtopside modifications to the nearby third-party owned and operated Bullwinkle host platform. We have secured a rig to begin drilling in 2009, and firstExpected net peak production is targeted for 2010. Net sales after royalties are expected to peak at about 45 mbpd of liquid hydrocarbons and 43 mmcfd of natural gas.approximately 50 mboepd. We hold a 100 percent operated working interest in Droshky.

Also in October 2008, developmentDevelopment of the Ozona prospect, located in the Gulf of Mexico on Garden Banks Block 515, was authorized by our board of directors.has also continued. We have secured a rig to complete the previously drilled appraisal well and tie back to the nearby outside-operatedthird-party Auger platform. First production is expected in 2011. We hold a 68 percent working interest in Ozona.

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

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

Onshore – We produce natural gas in the Cook Inlet and adjacent Kenai Peninsula of Alaska. We have operated and outside-operated interests in 10 fields and hold a 51 to 100 percent working interest in each. In 2008,2009, our net natural gas sales from Alaska averaged 126 mmcfd, representing 28 percent of87 mmcfd. Typically, our total U.S. net natural gas sales volumes. 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.

Net liquid hydrocarbon and natural gas sales from our Wyoming fields averaged 19 mbpd and 123 mmcfd in 2008. Our Wyoming net natural gas sales decreased from the prior year primarily as a result of natural field declines, partially offset by new In 2009, we drilled six wells in the Wamsutter FieldAlaska and Powder River Basin areas. Development of the Powder River Basin continued in 2008 with 100 operated wells drilled, which was down from the 170 wells drilled in 2007. Additional development of our southwest Wyoming interests continued in 2008 where we participated in the drilling of six wells.

We also have domestic natural gas operations in Oklahoma, east Texas and north Louisiana, with combined net sales of 137 mmcfd in 2008, and liquid hydrocarbon operations in the Permian Basin of southeast New Mexico and west Texas, with net sales of 11 mbpd in 2008.

We hold 320,000 acres in the Williston Basin (the Bakken Shale resource play). The majority of the acreage is located in North Dakota with the remainder in eastern Montana. This represents a substantial position in the Bakken Shale where approximately 225 locations will be drilled over the nextplan to drill four to five years. We currently have four operated drilling rigs running and ended 2008 with December average net sales of 8.2 mboepd.six wells per year during 2010 through 2012.

We hold leases with natural gas production in the Piceance Basin of Colorado, located in Garfield County in the Greater Grand Valley field complex. Our plans include drilling approximately 15065 wells over the next five years. Drilling and production commenced in late 2007. We currently have one operated drilling rig running and ended 2008averaged net sales of 15 mmcfd in 2009.

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

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

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

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

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

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

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

Africa

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

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

As part of our Integrated Gas segment, we own 45 percent of Atlantic Methanol Production Company LLC (“AMPCO”) and 60 percent of Equatorial Guinea LNG Holdings Limited (“EGHoldings”), both of which are accounted for as equity method investments. AMPCO operates a methanol plant and EGHoldings operates a liquefied natural gas (“LNG”) production facility, both located on Bioko Island. Dry natural gas from the Alba field, which remains after the condensate and LPG are removed, is supplied to both of these facilities under long-term contracts at fixed prices. Because of the location of and limited local demand for natural gas in Equatorial Guinea, we consider the prices under the contracts with Alba Plant LLC, AMPCO and EGHoldings to be comparable to the price that could be realized from transactions with unrelated parties in this market under the same or similar circumstances. Our share of the income ultimately generated by the subsequent export of secondary condensate and LPG produced by Alba Plant LLC is reflected in our E&P segment. Our share of the income ultimately generated by the subsequent export of methanol produced by AMPCO and LNG produced by EGHoldings is reflected in our Integrated Gas segment as discussed below. During 2009, a gross 115 mmcfd of dry natural gas was supplied to the methanol plant and a gross 647 mmcfd of dry gas was supplied to the LNG production facility. Any remaining dry gas is returned offshore and reinjected back into the Alba field for later production.

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

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 the drilling of the first three to four development wells planned in 2010. First production is anticipated in late 2011 to early 2012. Other discoveries on Block 31 comprise potential development areas in the southeast and middle portions of the block. Eight of the Block 32 discoveries form a potential development in the eastern area of that block. We expect first production on Block 32 in 2015 or 2016.

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

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

Europe

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

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

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

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

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

In addition, we hold a 28 percent interest in the outside-operated Gudrun field, located 120 miles off the coast of Norway. In January 2009, the operator announced a development concept that includes a fixed processing platform with seven production wells that would be tied to existing facilities on the Sleipner field, and one water disposal well.

United Kingdom – Our largest asset in the U.K. sector of the North Sea is the Brae area complex where we are the operator and have a 42 percent working interest in the South, Central, North and West Brae fields and a 38 percent working interest in the East Brae field. The Brae A platform and facilities host the underlying South Brae field and the adjacent Central and West Brae fields. A two well development program is scheduled in 2010 for West Brae. The North Brae field, which is produced via the Brae B platform, and the East Brae field, which is produced via the East Brae platform, are natural gas condensate fields. The East Brae platform hosts the nearby Braemar field in which we have a 2628 percent working interest. Net liquid hydrocarbon sales from the Brae area

averaged 1211 mbpd in 2008.2009. Net Brae natural gas sales averaged 119101 mmcfd, or 2111 percent of our internationalworldwide net natural gas sales volumes, in 2008.2009.

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 28 third-party fields have contracted to use the Brae system. In addition to generating processing and pipeline tariff revenue, this third-party business also has a favorable impact on Brae area operations by optimizing infrastructure usage and extending the economic life of the complex.

The Brae group owns a 50 percent interest in the outside-operated Scottish Area Gas Evacuation (“SAGE”) system. The SAGE pipeline transports natural gas from the Brae area, and the third-party Beryl area, and has a

Index to Financial Statements

total wet natural gas capacity of 1.1 billion cubic feet (“bcf”) per day. The SAGE terminal at St. Fergus in northeast Scotland processes natural gas from the SAGE pipeline and has the capacity for almostas well as approximately 1 bcf per day of third-party natural gas from the Britannia, Atlantic and Cromarty fields.gas.

In the U.K. Atlantic Margin west of the Shetland Islands, we own aan 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. Net sales from the Foinaven fields averaged 1213 mbpd of liquid hydrocarbons and 67 mmcfd of natural gas in 2008.2009. We are upgrading the FPSO which will extend the life of this project through 2021.

We have a 45 percent interest in five exploratory U.K. onshore coal seam gas licenses. Drilling has been completed in five exploration wells in three of the licenses. We also hold a 55 percent operated working interest in 11 blocks awarded in a 2008 bid round. Our interest covers 520,000 gross acres.

NorwayPolandNorway isWe have recently added a strategicnew opportunity to our portfolio, Poland shale gas. In November we were awarded the 296,000 acre Kwidzyn Block, followed by the 249,000 acre Orzechow Block in December. The five and growing core area, which complements our long-standing operations in the U.K. sector of the North Sea discussed above.a half year exploration phase for each block includes 2D seismic and at least one well. We were approved for our first operatorship onawarded the Norwegian continental shelf in 2002, where today we operate seven licenses, including the PL 505, which was awarded269,000 acre Brodnica Block in January 2009.

The operated Alvheim complex located on the Norwegian continental shelf commenced production2010, and we continue to look for additional opportunities in June 2008. The complex consists ofPoland. We hold a floating production, storage and offloading vessel (“FPSO”) with subsea infrastructure. Produced oil is transported by shuttle tanker and produced natural gas transported to the SAGE system using a new 14-inch diameter, 24-mile cross border pipeline. First production to the complex was from the Alvheim development which is comprised of the Kameleon and Kneler discoveries, in which we have a 65100 percent working interest and operatorship in all three blocks.

Other International

Indonesia – We are the Boa discovery, in which we have a 58 percent working interest. At the end of 2008, the Alvheim development included ten producing wellsoperator and two water disposal wells. The nearby Vilje discovery, in which we own a 47 percent outside-operated working interest, began producing through the Alvheim complex in August 2008. The two Vilje development wells were drilled and completed in 2007. Additionally, in 2007, the Norwegian government approved a plan for development and operation to develop the Volund field as a subsea tie-back to the Alvheim complex. The Volund development will consist of three production wells and one water disposal well, all to be drilled in the 2009 and 2010. The Volund development, in which we own a 65 percent working interest and serve as operator, is expected to begin production in late 2009.

In addition, we hold a 2870 percent outside-operated interest in the Gudrun field,Pasangkayu Block offshore Indonesia. The block is located 120mostly in deep water, predominantly offshore of the island of Sulawesi in the Makassar Strait, directly east of the Kutei Basin production region. The production sharing contract with the Indonesian government was signed in 2006 and we completed 3D seismic acquisition in May 2008. A mandatory 25 percent relinquishment was submitted to the Indonesian government in September 2009 and upon approval, the block size will be reduced from 1.2 million gross acres to 872,400 gross acres. We expect to drill two wells in 2010.

In October 2008, we were granted a 49 percent interest and operatorship in the Bone Bay Block offshore Sulawesi. An increase in ownership to 55 percent is pending Indonesian government approval. The Bone Bay Block covers an area of 1.23 million acres and is 200 miles offsoutheast of our Pasangkayu Block. Current exploration plans for Bone Bay call for the coastacquisition of Norway, whereseismic data starting in 2010, followed by drilling of one exploration well in 2011. In the second quarter of 2009, we were awarded a successful appraisal49 percent interest and operatorship in the Kumawa Block, our third Indonesia offshore exploration block, located offshore West Papua. An increase in ownership to 55 percent is pending Indonesian government approval. The Kumawa Block encompasses 1.24 million acres. A 2D seismic survey is planned in the first quarter of 2010 and we expect to drill one exploration well was drilled in 2006. In January 2009,2011-2012.

We are the operator announcedof a development conceptdrilling rig consortium, with five other operators, that includeshas secured a fixed processing platformdeepwater exploration drilling rig to drill exploratory wells in Indonesia over a two-year period commencing in the second quarter of 2010. The participants have the right to extend this rig contract for up to one additional year.

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

Divestitures

Angola –In February 2010, we closed the sale of an undivided 20 percent interest in the outside-operated production sharing contract and joint operating agreement on Block 32 offshore Angola for $1.3 billion, excluding any purchase price adjustments, with seven production wells that would be tied to existing facilities on the Sleipner field. A final investment decision is expectedan effective date of January 1, 2009. We retained a 10 percent interest in 2009.Block 32.

On October 31, 2008,

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

United States –In June 2009, we completed the sale of our operated and a portion of our outside-operated interests (24 percentPermian Basin producing assets in New Mexico and west Texas for net proceeds after closing adjustments of Heimdal field, 47 percent$293 million. A $196 million pretax gain on the sale was recorded. Net production from these sold properties averaged 8,150 boepd in the first quarter of Vale field and 20 percent of Skirne field) and associated undeveloped acreage in offshore Norway.2009.

Ireland– In December 2008,April 2009, we announced an agreement to sell our wholly-owned subsidiary which owns our producing properties in Ireland. Closing is subject to customary closing conditions. Properties included inclosed the sale areof our operated properties offshore Ireland, which consisted of our 100 percent working interest in the Kinsale Head, Ballycotton and Southwest Kinsale natural gas fields and our 87 percent operated working interest in the Seven Heads natural gas fieldfield. Net production from these operations averaged 5 mboepd in the Celtic Sea offshore Ireland. Also included is a 100 percent interest in our gas storage business which allows us to provide full third-party storage services from the Southwest Kinsale field.first quarter of 2009.

We own aIn July 2009 we closed the sale of our subsidiary holding our 19 percent working interest in the outside-operated Corrib natural gas development project, located 40 miles off Ireland’s northwest coast, where six of the seven wells necessary to develop the field have been drilled. Fouroffshore Ireland. As a result of these wells were completed and tested at the end of 2008. Terminal construction and offshore pipe installation are currently underway and onshore pipeline installation is planned to commence in 2009. The operator expects first production from the field in late 2010 or early 2011.

Equatorial Guinea – We own a 63 percent operated working interest in the Alba field offshore Equatorial Guinea During 2008, net liquid hydrocarbon sales average 41 mbpd or 28 percent ofdispositions, our international liquid hydrocarbon sales volumes, and net natural gas sales averaged 366 mmcfd, or 64 percent of our international natural gas sales. Net liquid hydrocarbon sales volumes in 2008 included 26 mbpd of condensate.

We also own a 52 percent interest in Alba Plant LLC, an equity method investee that operates an onshore liquefied petroleum gas (“LPG”) processing plant. Alba field natural gas is supplied to the LPG plant under a long-term contract at a fixed price. During 2008, a gross 883 mmcfd of natural gas was supplied to the LPG production facility and our net liquid hydrocarbon sales volumes in 2008 included 11 mbpd of LPG and 4 mbpd of secondary condensate produced by Alba Plant LLC.

Index to Financial Statements

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”). AMPCO operates a methanol plant and EGHoldings operates an LNG production facility, both located on Bioko Island. Alba field dry natural gas, 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 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 2008, a gross 94 mmcfd of dry natural gas was supplied to the methanol plant and a gross 565 mmcfd of dry gas was supplied to the LNG production facility. Any remaining dry gas is returned offshore and reinjected into the Alba reservoir for later production.

Angola – 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. Key contracts were awarded and construction work commenced in the second half of 2008. A total of 48 production and injection wells are planned for the PSVM development. Other discoveries on Block 31 comprise potential development areas in the southeast and middle portions of the block. Seven of the Block 32 discoveries form a potential development in the eastern area of that block.

Libya – We resumed operations in Libya in 2006, holding a 16 percent outside-operated interest in the Waha concessions. Net liquid hydrocarbon sales in Libya averaged 46 mbpd in 2008 compared to 45 mbpd in 2007. The 2008 net liquid hydrocarbon sales in Libya represented 31 percent of our international liquid hydrocarbon sales volumes. Net natural gas sales in Libya averaged 4 mmcfd in 2008.

Gabon – We are the operator of the Tchatamba South, Tchatamba West and Tchatamba Marin fields offshore Gabon with a 56 percent working interest. Net sales in Gabon averaged 6 mbpd of liquid hydrocarbons in 2008. Production from these three fields is processed on a single offshore facility at Tchatamba Marin, with the processed oil being transported through an offshore and onshore pipeline to an outside-operated storage facility.

Other Matters

During the first quarter of 2008, we relinquished our interest in anIrish exploration and production license in Sudan, andbusinesses have been reported as a result, we no longer have any interests in Sudan.

We ceased efforts to pursue exploration opportunities in Ukraine and closed our Kiev office in the third quarter of 2008.discontinued operations.

The above discussion of the E&P segment includes forward-looking statements with respect to anticipated future exploratory and development drilling, Blocks 31 and 32 offshore Angola, the Equatorial Guinea discoveries, the timing of production from the Woodford Shale resource play, the Droshky and Ozona developments in the Gulf of Mexico, the VolundFaregh Phase II Gas Plant, the PSVM development the sale of a subsidiary which owns producing properties in Irelandon Block 31 offshore Angola and the Corrib project.Block 32 and other possible developments. Some factors which could potentially affect these forward-looking statements include pricing, supply and demand for petroleum products, the amount of capital available for exploration and development, regulatory constraints, drilling rig availability, unforeseen hazards such as weather conditions, natural disasters, acts of war or terrorist acts and the governmental or military response, and other geological, operating and economic considerations. Except for the Volund development, theThe 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 possibleoffshore developments on Blocks 31 and 32 offshore Angola, and the Equatorial Guinea discoveries could further be affected by presently known data concerning size and character of reservoirs, economic recoverability, future drilling success and production experience. Factors that could affect the sale of the subsidiary include customary closing conditions. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Index to Financial Statements

ReservesProductive and Drilling Wells

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

Gross and Net Wells

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

2009

               

United States

  4,806  1,788  5,158  3,569    2,447  734  31  18
               

Equatorial Guinea

  -  -  13     5  3  -  -

Other Africa

  976  160  -  -   91  15  6  1
                        

Total Africa

  976  160  13     96  18  6  1

Total Europe

  67  27  44  18    27  10  -  -
                        

WORLDWIDE

  5,849  1,975  5,215  3,596    2,570  762  37  19
                        

2008

               

United States

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

Equatorial Guinea

  -  -  13     5  3    

Other Africa

  968  162  -  -   92  15    
                      

Total Africa

  968  162  13     97  18    

Total Europe

  64  26  67  40    26  10    
                      

WORLDWIDE

  6,888  2,328  5,491  3,895    2,826  850    
                      

2007

               

United States

  5,864  2,111  5,184  3,734    2,737  838    
               

Equatorial Guinea

  -  -  13     5  3    

Other Africa

  964  161  -  -   94  15    
                      

Total Africa

  964  161  13     99  18    

Total Europe

  54  20  76  41    29  11    
                      

WORLDWIDE

  6,882  2,292  5,273  3,784    2,865  867      
(a)

Of the gross productive wells, wells with multiple completions operated by Marathon totaled 170, 276 and 303 as of December 31, 2009, 2008 and 2007. Information on wells with multiple completions operated by others is unavailable to us.

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.

Net Productive and Dry Wells Completed

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

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

2007

                  

United States

  9  172  -  181  9  13  12  34  215

Total Africa

  4  -  -  4  3  -  1  4  8

Total Europe

  3  -  -  3  -  1  1  2  5
                           

WORLDWIDE

  16  172  -  188  12  14  14  40  228

Acreage

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

Gross and Net Acreage

   Developed  Undeveloped  Developed and
Undeveloped
(Thousands of acres)  Gross  Net  Gross  Net  Gross  Net

United States

  1,507  1,142  1,359  1,010  2,866  2,152

Canada

  -  -  143  55  143  55
                  

Total North America

  1,507  1,142  1,502  1,065  3,009  2,207

Equatorial Guinea

  45  29  173  122  218  151

Other Africa

  12,909  2,108  2,580  510  15,489  2,618
                  

Total Africa

  12,954  2,137  2,753  632  15,707  2,769

Total Europe

  131  68  1,765  1,050  1,896  1,118

Other International

  -  -  3,628  2,022  3,628  2,022
                  

WORLDWIDE

  14,592  3,347  9,648  4,769  24,240  8,116

Oil Sands Mining

Through our acquisition of Western in 2007, we hold a 20 percent outside-operated interest in the AOSP, an oil sands mining joint venture located in Alberta, Canada. The joint venture produces bitumen from oil sands deposits in the Athabasca region utilizing mining techniques and upgrades the bitumen to synthetic crude oils and vacuum gas oil. The AOSP’s mining and extractions assets are located near Fort McMurray, Alberta and include the Muskeg River mine which began bitumen production in 2003 and the Jackpine mine which is currently under construction and anticipated to commence bitumen production in the second half of 2010. The underlying developed leases are held for the duration of the project, with royalties payable to the province of Alberta. The upgrading assets are located at Fort Saskatchewan, northeast of Edmonton, Alberta. Additional upgrading capacity is being constructed with an anticipated startup in late 2010 or early 2011.

In the second quarter of 2009, the operator of AOSP offered three additional leases to the other joint venture partners for the Muskeg River mine. Terms of the transaction were as agreed in the original 1999 AOSP joint venture agreement. We elected to participate in these leases and our net proved bitumen reserves increased 168 million barrels. See Item 1. Business – Reserves for comprehensive discussion of reserves related to our oil sands mining and conventional exploration and production operations. As of December 31, 2009, we have rights to participate in developed and undeveloped leases totaling approximately 215,000 gross (45,000 net) acres.

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

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

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

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

The above discussion of the Oil Sands Mining segment includes forward-looking statements concerning the anticipated completion of AOSP Expansion 1 and the timing of production. Factors which could affect the expansion project include transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by necessary government and third-party approvals and other risks customarily associated with construction projects. The AOSP expansion could be further affected by commissioning and start-up risks associated with prototype equipment and new technology.

Reserves

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

Estimated Reserve Quantities

The following table sets forth estimated quantities of our net proved liquid hydrocarbon, and natural gas and synthetic crude oil reserves totaled 1,195 million boe,based upon an unweighted average of which 43closing prices for the first day of each month in the 12-month period ended December 31, 2009. Approximately 61 percent wereof our proved reserves are located in Organization for Economic Cooperation and Development (“OECD”) countries.

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

   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

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

   North America  Africa  Europe       
December 31, 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

   North America  Africa  Europe       
December 31, 2007  United
States
  Canada(a)  Total  EG  Other  Total  Total  Disc.
Ops.
(b)
  Grand
Total
 

Proved Developed Reserves

  

       

Liquid hydrocarbon(mmbbl)

  135  -   135  113  183  296  32     471 

Natural gas(bcf)

  761  -   761  1,405  110  1,515  127  46    2,449 

Total proved developed reserves(mmboe)

  262  -   262  347  202  549  52  16    879 

Total Proved Reserves

          

Liquid hydrocarbon(mmbbl)

  166  -   166  150  210  360  115     650 

Natural gas(bcf)

  1,007  -   1,007  1,951  110  2,061  238  144    3,450 

Total proved reserves(mmboe)

  334  -   334  475  228  703  155  33    1,225 

Developed reserves as a percent of total proved reserves

  78 -   78 73 89 78 34 48 72
(a)

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

(b)

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

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

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

Estimated QuantitiesPreparation of Net Proved Liquid Hydrocarbon and Natural Gas Reserves at December 31Reserve Estimates

   Developed  Developed and
Undeveloped
    2008  2007  2006  2008  2007  2006

Liquid Hydrocarbons(Millions of barrels)

         

United States

  137  135  150  178  166  172

Europe

  81  32  35  104  115  108

Africa

  296  304  381  354  369  397
                  

WORLDWIDE

  514  471  566  636  650  677
                  

Developed reserves as a percent of total net proved reserves

  81% 72% 84%     

Natural Gas(Billions of cubic feet)

         

United States

  839  761  857  1,085  1,007  1,069

Europe

  129  173  238  291  382  444

Africa

  1,382  1,515  648  1,975  2,061  1,997
                  

WORLDWIDE

  2,350  2,449  1,743  3,351  3,450  3,510
                  

Developed reserves as a percent of total net proved reserves

  70% 71% 50%     

Total BOE(Millions of barrels)

         

United States

  277  262  293  359  334  350

Europe

  103  61  75  153  179  182

Africa

  526  556  489  683  712  730
                  

WORLDWIDE

  906  879  857  1,195  1,225  1,262
                  

Developed reserves as a percent of total net proved reserves

  76% 72% 68%        

The following table sets forth changes in estimatedOur estimation of net recoverable quantities of proved liquid hydrocarbonhydrocarbons and natural gas reserves:

Changesis a highly technical process performed primarily by in-house teams of reservoir engineers and geoscience professionals. All estimates are made in Estimated Quantitiescompliance with SEC Rule 4-10 of Net Proved Liquid Hydrocarbon and Natural Gas Reserves

(Millions of barrels of oil equivalent)2008

Beginning of year

1,225

Revisions of previous estimates

23

Extensions, discoveries, additions and improved recovery(a)

87

Production

(137)

Sales of reserves in place(b)

(3)

End of year

1,195

(a)

Additions were principally in Norway, the Gulf of Mexico and Libya.

(b)

The sale of outside-operated properties in Norway was the most significant disposition.

During 2008, we transferred 126 million boe from proved undeveloped to proved developed reserves. Costs incurredRegulation S-X. Beginning December 31, 2009, reserve estimates are based upon the average of closing prices for the periodsfirst day of each month in the 12-month period ended December 31, 2009. In previous periods, reserve estimates were based on prices at December 31.

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

Our Director of Corporate Reserves, who reports to our Chief Financial Officer, has a bachelor of science degree in petroleum engineering and a master of business administration. Her 35 years of experience in the industry include 24 with Marathon. She is active in industry and professional groups, having served on the Society of Petroleum Engineers (“SPE”) Oil and Gas Reserves Committee (“OGRC”) since 2004, chairing in 2008 2007 and 2006 relating to2009. As a member of the OGRC, she participated in the development of the Petroleum Resource Management System (“PRMS”) and served on the Technical Program Committee for a 2007 SPE Reserves Estimation Workshop: Sharing the Vision focusing on PRMS. She chaired the development of the OGRC comments on the SEC’s proposed modernization of oil and gas reporting and was a member of the American Petroleum Institute’s Ad Hoc group that provided comments on the same topic.

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

Audits of Estimates

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

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

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

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

Changes in Proved Undeveloped Reserves

As of December 31, 2009, 492 mmboe of proved undeveloped liquid hydrocarbon and natural gas reserves were $1,189 million, $1,250 million and $1,010 million.reported, an increase of 203 mmboe from December 31, 2008, primarily due to the inclusion of synthetic crude oil. Of the 289 million boe492 mmboe of proved undeveloped reserves at year-end 2008, 64year end 2009, 31 percent of the volume is associated with projects that have been included in proved reserves for more than threefive years. The majority of this volume is related to a compression project in Equatorial Guinea that was sanctioned by the Board of Directors in 2004 and is expected to be completed in 2014. There are no other significant undeveloped reserves expected to be developed more than five years while 19 percentfrom now. Projects can remain in proved undeveloped reserves for extended periods in many situations such as behind-pipe zones where reserves will not be accessed until the primary producing zone depletes, large development projects which take more than five years to complete, and the timing of when additional gas compression is needed. During 2009, we added 290 mmboe to proved undeveloped reserves and transferred 38 mmboe from proved undeveloped to proved developed reserves. Costs incurred for the periods ended December 31, 2009, 2008 and 2007 relating to the development of proved undeveloped reserves, were added during 2008. $792 million, $1,189 million and $1,250 million.

As of December 31, 2008,2009, future development costs estimated to be required for the development of proved undeveloped liquid hydrocarbon, natural gas and synthetic crude oil reserves for the years 2010 through 2014 are projected to be $1,083 million, $565 million, $244 million, $331 million, and $123 million.

The above estimated future development costs relating to the development of proved undeveloped liquid hydrocarbon, and natural gas reserves for the years 2009 through 2011 are projected to be $1,244 million, $508 million and $262 million.

The above estimated quantities of net proved liquid hydrocarbon and natural gas reserves and estimated future development costs relating to the development of proved undeveloped liquid hydrocarbon and natural gas

Index to Financial Statements

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.

For a discussion of the proved liquid hydrocarbon and natural gas reserve estimation process, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates – Estimated Net Recoverable Reserve Quantities – Proved Liquid Hydrocarbon and Natural Gas Reserves, and 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 – Estimated Quantities of Proved Oil and Natural Gas Reserves. We filed reports with the U.S. Department of Energy (“DOE”) for 2007 disclosing our total year-end estimated liquid hydrocarbon and natural gas reserves. The year-end estimates reported to the DOE are the same estimates reported in the Supplementary Information on Oil and Gas Producing Activities.

Delivery CommitmentsProduction Sold

We sell liquid hydrocarbons and natural gas under a variety of contractual arrangements, some of which specify the delivery of a fixed and determinable quantity. Worldwide, we are contractually committed to deliver 126 bcf of natural gas in the future. These contracts have various expiration dates through the year 2018. Our proved reserves in Alaska, the United Kingdom and other locations, are sufficient to fulfill these delivery commitments.

Net Liquid Hydrocarbon and Natural Gas Sales

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

 

Net Liquid Hydrocarbon Sales(a)

      
(Thousands of barrels per day)  2008  2007  2006

United States(b)

  63  64  76

Europe(c)

  55  33  35

Africa(c)

  93  100  112
         

Worldwide Continuing Operations

  211  197  223

Discontinued Operations(d)

      12
         

WORLDWIDE

  211  197  235

Net Natural Gas Sales(e)

      
(Millions of cubic feet per day)  2008  2007  2006

United States(b)

  448  477  532

Europe(f)

  166  169  197

Africa

  370  232  72
         
WORLDWIDE  984  878  801
   North America  Africa  Europe  Disc.
Ops
(b)
   Total
    United
States
  Canada(a)  Total  EG  Other  Total  Total    

Year Ended December 31, 2009

                 

Liquid hydrocarbon(mbpd)(c)

  64  -   64  42  45  87  92      248

Natural gas(mmcfd)(d)(e)

  373  -   373  426  4  430  116  17     936

Total production sold(mboed)

  126  -   126  113  46  159  111      403

Year Ended December 31, 2008

                 

Liquid hydrocarbon(mbpd)(c)

  63  -   63  40  47  87  55      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

Year Ended December 31, 2007

                 

Liquid hydrocarbon(mbpd)(c)

  64  -   64  45  45  90  33  10     197

Natural gas(mmcfd)(d)(e)

  477  -   477  227  5  232  130  39     878

Total production sold(mboed)

  144  -   144  83  46  129  54  17     344

(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. All periods have been recast to reflect these businesses as discontinued operations.

(c)

Includes crude oil, condensate and natural gas liquids.

(b)

Represents net sales from leasehold ownership, after royalties and interests of others.

(c)

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

(d)

Represents the Russian oil exploration and production businessesU.S. natural gas volumes exclude volumes produced in Alaska that were soldare stored for later sale in June 2006.response to seasonal demand, although our reserves have been reduced by those volumes.

(e)(e)

Represents net sales after royalties, except for Ireland where amounts are before royalties.

(f)

Excludes volumes acquired from third parties for injection and subsequent resale of 32 mmcfd, 47 mmcfd and 46 mmcfd in 2008, 2007 and 2006.resale.

Index to Financial Statements

Productive and Drilling WellsAverage Sales Price per Unit

The following tables set forth productive wells and service wells as of December 31, 2008, 2007 and 2006 and drilling wells as of December 31, 2008.

 

Gross and Net Wells

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

2008

 

United States

  5,856  2,140  5,411  3,846  2,703  822  77  50 
 

Europe

  64  26  67  40  26  10  2  1 
 

Africa

  968  162  13  9  97  18  7  1 
                          
 

    WORLDWIDE

  6,888  2,328  5,491  3,895  2,826  850  86  52 
               

2007

 

United States

  5,864  2,111  5,184  3,734  2,737  838    
 

Europe

  54  20  76  41  29  11    
 

Africa

  964  161  13  9  99  18    
                       
 

    WORLDWIDE

  6,882  2,292  5,273  3,784  2,865  867    
               

2006

 

United States

  5,661  2,068  5,554  4,063  2,729  834    
 

Europe

  51  19  75  41  31  12    
 

Africa

  925  155  13  9  100  19    
                       
  

    WORLDWIDE

  6,637  2,242  5,642  4,113  2,860  865       
  North America Africa Europe Disc.
Ops
(b)
  Total
(Dollars per unit) United
States
 Canada(a)  Total EG Other Total Total  

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

Year Ended December 31, 2007

         

Liquid hydrocarbon(bbl)

  60.15 -    60.15  50.10  80.57  65.41  70.31  72.19     64.86

Natural gas(mcf)

  5.73 -    5.73  0.24  0.70  0.25  6.51  6.71     4.44

(a)

Includes active wells and wells temporarily shut-in. Of the gross productive wells, wells with multiple completions operated by Marathon totaled 276, 303 and 294 as ofBefore December 31, 2008, 20072009, oil sands mining was not included in the SEC’s definition of oil and 2006. Information on wells with multiple completions operated by others is unavailable to us.gas producing activities; therefore, synthetic crude oil prices are not reported.

(b)

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

Average Production Cost per Unit(a)

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

Years ended December 31:

                 

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

2007

   10.16  -    10.16   3.16   3.58   3.31   11.24   13.76      7.95

(a)

Production, severance and property taxes are excluded from the production costs used in calculation of injection, water supply and disposal wells.this metric.

(c)(b)

ConsistsBefore December 31, 2009, oil sands mining was not included in the SEC’s definition of exploratoryoil and development wells.

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.

Net Productive and Dry Wells Completed(a)

     Development(b)  Exploratory  Total
       Oil  Natural
Gas
  Dry  Total
  Oil  Natural
Gas
  Dry  Total    

2008

 

United States

  38  161    199  33  8  6  47  246
 

International

  8  1    9  1  2  1  4  13
                            
 

    WORLDWIDE

  46  162    208  34  10  7  51  259
                  

2007

 

United States

  9  172    181  9  13  12  34  215
 

International

  7      7  3  1  2  6  13
                            
 

    WORLDWIDE

  16  172    188  12  14  14  40  228
                  

2006

 

United States

  32  186  5  223  3  8  3  14  237
 

International

  51  1    52  19    6  25  77
                            
  

    WORLDWIDE

  83  187  5  275  22  8  9  39  314

(a)

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

(b)(c)

Indicates wells drilledOur businesses in the proved area of an oil or natural gas reservoir.Ireland and Gabon were sold in 2009. All periods have been recast to reflect these businesses as discontinued operations.

Index to Financial Statements

AcreageIntegrated 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. In May 2007, EGHoldings completed construction of a 3.7 million metric tonnes per annum (“mmtpa”) LNG production facility on Bioko Island. LNG from the production facility is sold under a 3.4 mmtpa, or 460 mmcfd, sales and purchase agreement with a 17-year term. The following tables set forth, by geographic area,purchaser under the developedagreement 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 3.9 million metric tonnes in 2009. In 2009, we continued discussions with the government of Equatorial Guinea and underdeveloped explorationour partners regarding a potential second LNG production facility on Bioko Island.

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

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

In addition to our expertise in utilizing existing gas technologies to manufacture and market products such as LNG and methanol, we continue to conduct research to develop new leading-edge natural gas technologies. While existing known natural gas resources are much more abundant than the world’s remaining oil resources, natural gas is more difficult to transport to global markets without the use of December 31, 2008.advanced gas technologies. Our Gas-to-Fuels (“GTF™”) technology is one such promising technology.

GrossOur GTFTM technology program is focused on converting natural gas into gasoline blendstocks and Net Acreage

   Developed  Undeveloped  Developed and
Undeveloped
(Thousands of acres)  Gross  Net  Gross  Net  Gross  Net

United States

  1,318  1,035  1,612  1,169  2,930  2,204

Europe

  493  393  1,555  617  2,048  1,010

Africa

  12,978  2,151  2,787  654  15,765  2,805

Other International

      2,535  1,471  2,535  1,471
                  

WORLDWIDE

  14,789  3,579  8,489  3,911  23,278  7,490

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

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

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

The GTFTM technology is protected by an oil sands mining joint venture located in Alberta, Canada.intellectual property protection program. The joint venture produces bitumen from oil sands deposits in the Athabasca region and upgrades the bitumen to synthetic crude oil. The AOSP’s asset is the mining and extraction operations of the Muskeg River mine located near Fort McMurray, Alberta, which began bitumen production in 2003, together with Scotford upgrading infrastructure located northeast of Edmonton, Alberta. The underlying developed leases are heldU.S. has granted 17 patents for the durationtechnology, with another 22 pending. Worldwide, there are over 300 patents issued or pending, covering over 100 countries including regional and direct foreign filings.

Another innovative technology that we are developing focuses on reducing the processing and transportation costs of the project, with royalties paidnatural gas by artificially creating natural gas hydrates, which are more easily transportable than natural gas in its gaseous form. Much like LNG, gas hydrates would then be regasified upon delivery to the province of Alberta. As of December 31, 2008, wereceiving market. We have rightsan active pilot program in place to participate in developedtest and undeveloped leases totaling approximately 215,000 gross (45,000 net) acres. Prior to December 6, 2009, we are entitled to participate in any new land acquisitions by either of the other AOSP owners withinfurther develop a defined area of mutual interest.

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. Bitumen production from the mine is taken by pipeline to the Scotford upgrader.

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 chunks are further reduced to smaller particles. The particles are combined with hot water to create slurry. The slurry moves through a pipeline where it separates into sand, clay and bitumen. Air is introduced to the slurry mixture, which creates a 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, referred to as “dilbit”, 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 hydro-treating and a hydro-conversion process to remove sulfur and break the heavy carbon molecules into lighter products. The three major products that the Scotford upgrader produces are Premium Albian synthetic crude oil, Albian Heavy synthetic crude oil and vacuumproprietary natural gas oil. The vacuum gas oil is sold to the operator under a long term contract at market-related prices, and the other products are sold in the marketplace.

The following table sets forth key operating statistics for the last two years.

OSM Operating Statistics

(Thousands of barrels per day)  2008  2007(a) 

Net bitumen production(b)

  25  4 

Net synthetic crude sales

  32  4 

(a)

The oil sands mining operations were acquired October 18, 2007. Daily volumes for 2007 represent total volumes since the acquisition date over total days in the period.

(b)

Bitumen production is before royalties.

Index to Financial Statements

Proved reserves can be added as expansions are permitted, funding is approved and certain stipulations of the joint venture agreement are satisfied. The following table sets forth changes in estimated quantities of net proved bitumen reserves for the year 2008.

Estimated Quantities of Proved Bitumen Reserves

(Millions of barrels)2008

Beginning of year

421

Revisions(a)

(30)

Extensions, discoveries and additions

6

Production

(9)

End of year

388

(a)

Revisions were driven primarily by price and the impact of the new royalty regime discussed below.

The above estimated quantity of net proved bitumen reserves is a forward-looking statement and is based on a number of assumptions, including (among others) commodity prices, volumes in-place, presently known physical data, recoverability of bitumen, industry economic conditions, levels of cash flow from operations, and other operating considerations. To the extent these assumptions prove inaccurate, actual recoveries could be different than current estimates. For a discussion of the proved bitumen reserves estimation process, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Estimates – Estimated Net Recoverable Reserve Quantities – Proved Bitumen Reserves. Operations at the AOSP are not within the scope of Statement of Financial Accounting Standards (“SFAS”) No. 25, “Suspension of Certain Accounting Requirements for Oil and Gas Producing Companies (an Amendment of Financial Accounting Standards Board (“FASB”) Statement No. 19),” SFAS No. 69, “Disclosures about Oil and Gas Producing Activities (an Amendment of FASB Statements 19, 25, 33 and 39),” and Securities and Exchange Commission (“SEC”) Rule 4-10 of Regulation S-X; therefore, bitumen production and reserves are not included in our Supplementary Information on Oil and Gas Producing Activities. The SEC has recently issued a release amending these disclosure requirements effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Accounting Standards Not Yet Adopted for additional information.

Prior to our acquisition of Western, the first fully-integrated expansion of the existing AOSP facilities was approved in 2006. Expansion 1, which includes construction of mining and extraction facilities at the Jackpine mine, expansion of treatment facilities at the existing Muskeg River mine, expansion of the Scotford upgrader and development of related infrastructure, is anticipated to begin operations in late 2010 or 2011. When Expansion 1 is complete, we will have more than 50,000 bpd of net production and upgrading capacity in the Canadian oil sands. The timing and scope of future expansions and debottlenecking opportunities on existing operations remain under review.

During 2008, the Alberta government accepted the project’s application to have a portion of the Expansion 1 capital costs form part of the Muskeg River mine’s allowable cost recovery pool. Due to commodity price declines in the year, royalties for 2008 were one percent of the gross mine revenue.

Commencing January 1, 2009, the Alberta Royalty regime has been amended such that royalty rates will be based on the Canadian dollar (“CAD”) equivalent monthly average West Texas Intermediate (“WTI”) price. Royalty rates will rise from a minimum of one percent to a maximum of nine percent under the gross revenue method and from a minimum of 25 percent to a maximum of 40 percent under the net revenue method. Under both methods, the minimum royalty is based on a WTI price of $55.00 CAD per barrel and below while the maximum royalty is reached at a WTI price of $120.00 CAD per barrel and above, with a linear increase in royalty between the aforementioned prices.hydrates manufacturing system.

The above discussion of the Oil Sands MiningIntegrated Gas segment includescontains forward-looking statements concerningwith respect to the anticipated completionpossible expansion of AOSP Expansion 1.the LNG production facility. Factors whichthat could potentially affect the possible expansion projectof the LNG production facility include transportation logistics, availability of materialspartner and labor, unforeseen hazards such as weather conditions, delaysgovernment 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 obtaining or conditions imposed by necessary government and third-party approvals and other risks customarily associated with construction projects.the forward-looking statements.

Refining, Marketing and Transportation

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

Refining

We own and operate seven refineries in the Gulf Coast, Midwest and upper Great Plains regions of the United States with an aggregate refining capacity of 1.0161.188 million barrels per day (“mmbpd”) of crude oil.oil as of December 31, 2009. During 2008,

Index to Financial Statements

2009, our refineries processed 944957 mbpd of crude oil and 207196 mbpd of other charge and blend stocks. The table below sets forth the location and daily crude oil refining capacity of each of our refineries as of December 31, 2008.2009.

Crude Oil Refining Capacity

 

(Thousands of barrels per day)  20082009

Garyville, Louisiana

  256436

Catlettsburg, Kentucky

  226212

Robinson, Illinois

  204206

Detroit, Michigan

  102106

Canton, Ohio

  78

Texas City, Texas

  76

St. Paul Park, Minnesota

  74
   

TOTAL

  1,0161,188

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

Our 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 intermediate products between refineries to optimize operations, produce higher margin products and utilize our processing capacity efficiently.

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

such as gasoline, distillates, sulfur, asphalt, propane, polymer grade propylene, isobutane and coke. In 2006, we approved an expansion of ourOur Garyville refinery by 180has earned designation as a U.S. Occupational Safety and Health Administration (OSHA) Voluntary Protection Program (VPP) STAR site.

The Garyville Major Expansion project, completed on schedule during the fourth quarter of 2009, is currently being fully integrated into the base Garyville refinery. As a result of the expansion, the refinery’s crude oil refining capacity has grown from 256 mbpd to 436 mbpd, with a currently projectedmaking it among the largest crude oil refineries in the country. The expansion also improves scale efficiencies, feedstock flexibility and refined product yields. The expansion project cost of $3.35approximately $3.9 billion (excluding capitalized interest). Construction commenced in early 2007 and is continuing on schedule. We estimate that, as of December 31, 2008, this project is approximately 75 percent complete. We expect to complete the expansion in late 2009.

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 the southeastern Illinois town of Robinson.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 our Detroit, Michigan,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 1510 percent. Construction began in the first half of 2008 and is presently expected to be complete in mid-2012.the second half of 2012. Our Detroit refinery is certified as a Michigan VPP site, receiving Rising Star status, and expects to satisfy the requirements for STAR status in the first quarter of 2010.

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

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

Our St. Paul Park, Minnesota, refinery is located in St. Paul Park, a suburbsoutheastern Minnesota where it is one of Minneapolis-St. Paul.only two refineries in the state. The St. Paul Park refinery processes predominantly Canadian crude oils into products such as gasoline, diesel, jet fuel, kerosene, asphalt, propane, propylene and sulfur.

Index Our St. Paul Park refinery is certified as a Minnesota VPP site, receiving Rising Star status, and expects to Financial Statements
satisfy the requirements for STAR status in 2010.

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

Planned maintenance activities requiring temporary shutdownOur 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 certain refinery operating units, or turnarounds, are periodically performed at each refinery. We performed major turnaround activities atcrude oil, feedstocks and intermediate products between refineries to optimize operations, produce higher margin products and utilize our Robinson, Catlettsburg, Garyville and Canton refineries in 2008, at our Catlettsburg, Robinson and St. Paul Park refineries in 2007 and at our Catlettsburg refinery in 2006.processing capacity efficiently.

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

Refined Product Yields

 

(Thousands of barrels per day)  2008  2007  2006  2009  2008  2007

Gasoline

  609  646  661  669  609  646

Distillates

  342  349  323  326  342  349

Propane

  22  23  23  23  22  23

Feedstocks and special products

  96  108  107  62  96  108

Heavy fuel oil

  24  27  26  24  24  27

Asphalt

  75  86  89  66  75  86
                  

TOTAL

  1,168  1,239  1,229  1,170  1,168  1,239

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

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. Of the U.S. and Canadian sourced crude processed at our refineries, 2733 mbpd, or 5four percent, was supplied by a combination of our E&P and OSM production operations for the year 2008.2009.

Sources of Crude Oil Refined

 

Sources of Crude Oil Refined

      
(Thousands of barrels per day)  2008  2007  2006  2009  2008  2007

United States

   466   527   470   613   466   527

Canada

   135   138   130   136   135   138

Middle East and Africa

   244   253   266   154   244   253

Other international

   99   92   114   54   99   92
                  

TOTAL

   944   1,010   980   957   944   1,010
                  

Average cost of crude oil throughput(Dollars per barrel)

  $98.34  $71.20  $61.15  $62.10  $98.34  $71.20

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 productproducts marketing and distribution –We are a supplier of refined products to resellers and consumers within our 23-state24-state market area in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the United States. Our market area includes approximately 4,600 Marathon branded-retail outlets concentrated in the Midwest and southeastern states. We currently own and distribute from 6564 light product and 22 asphalt terminals. In addition, we distribute through 6860 third-party terminals in our market area. Our marine transportation operations include 1516 towboats, and 196as well as 183 owned and 58 leased barges that transport refined products on the Ohio, Mississippi and Illinois rivers and their tributaries andas well as the Intercoastal Waterway. We lease or own 2,500approximately 2,400 railcars of various sizes and capacities for movement and storage of refined products andproducts. In addition, we own over 140120 transport trucks.trucks for the movement of light products.

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

 

Refined Product Sales by Customer Type  2008 2007 2006   2009 2008 2007 

Private-brand marketers, commercial and industrial consumers

  67% 69% 71%  67 67 69

Marathon-branded outlets

  18% 16% 14%  18 18 16

Speedway SuperAmerica LLC (“SSA”) retail outlets

  15% 15% 15%

Speedway SuperAmerica LLC retail outlets

  15 15 15

Index to Financial Statements

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

Refined Product Sales

      
(Thousands of barrels per day)  2008  2007  2006

Gasoline

   756   791   804

Distillates

   375   377   375

Propane

   22   23   23

Feedstocks and special products

   100   103   106

Heavy fuel oil

   23   29   26

Asphalt

   76   87   91
            

TOTAL(a)

   1,352   1,410   1,425
            

Average sales price(Dollars per barrel)

  $109.49  $86.53  $77.76

(Thousands of barrels per day)  2009  2008  2007

Gasoline

   830   756   791

Distillates

   357   375   377

Propane

   23   22   23

Feedstocks and special products

   75   100   103

Heavy fuel oil

   24   23   29

Asphalt

   69   76   87
            

TOTAL

   1,378   1,352   1,410
            

Average sales price (Dollars per barrel)

  $70.86  $109.49  $86.53

(a)

Includes matching buy/sell volumes of 24 mbpd in 2006. On April 1, 2006, we changed our accounting for matching buy/sell arrangements as a result of a new accounting standard. This change resulted in lower refined products sales volumes for 2008, 2007 and the remainder of 2006 than would have been reported under our previous accounting practices. See Note 2 to the consolidated financial statements.

Gasoline and distillates –We sell gasoline, gasoline blendstocks and No. 1 and No. 2 fuel oils (including kerosene, jet fuel and diesel fuel and home heating oil)fuel) to wholesale marketing customers in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the United States. We sold 4751 percent of our gasoline volumes and 8887 percent of our distillates volumes on a wholesale or spot market basis in 2008.2009. The demand for gasoline is seasonal in many of our markets, with demand typically being at its highest levels during the summer months.

We have blended fuel ethanol into gasoline for over 1520 years and began increasingexpanding our blending program in 2007, in part due to federal regulations that require us to use specified volumes of renewable fuels. WeEthanol volumes sold in blended 57gasoline were 60 mbpd of ethanol into gasolinein 2009, 54 mbpd in 2008 41and 40 mbpd in 2007 and 35 mbpd in 2006.2007. The future expansion or contraction of our ethanol blending program will be driven by the economics of the ethanol supply and by government regulations. We sell reformulated gasoline, which is also blended with ethanol, in parts of our marketing territory, including: Chicago, Illinois; Louisville, Kentucky; northern Kentucky; Milwaukee, Wisconsin, and Hartford, Illinois. We also sell biodiesel-blended diesel in Minnesota, Illinois and Kentucky.

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

Propane –We produce propane at all seven 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.

Feedstocks and special products –We are a producer and marketer of petrochemicals and specialty products. Product availability varies by refinery and includes benzene, cumene, dilute naphthalene oil, molten maleic anhydride, molten sulfur, propylene, toluene and xylene. We market propylene, cumene and sulfur domestically to customers in the chemical industry. We sell maleic anhydride throughout the United States and Canada. We also have the capacity to produce 1,400 tons per day of anode grade coke at our Robinson refinery, which is used to make carbon anodes for the aluminum smelting industry, and 2,7005,500 tons per day of fuel grade coke at the Garyville refinery, which is used for power generation and in miscellaneous industrial applications. In September 2008,early 2009, we shut down our lubes facility in Catlettsburg, Kentucky, and sold from inventory through December 31, 2008; therefore, base oils, aromatic extracts and slack wax are no longer being produced and marketed. In addition, we have recently discontinued production and sales of petroleum pitch and aliphatic solvents.solvents at our Catlettsburg refinery.

Heavy fuel oilWe produce and market heavy oil, also known asresidual fuel oil residual fuel or slurryrelated components at all seven of our refineries. Another product of crude oil, heavy residual fuel oil, is primarily used in the utility and ship bunkering (fuel) industries, though there are other more specialized uses of the product. We also sell heavy fuel oil at our terminals in Wellsville, Ohio, and Chattanooga, Tennessee.

AsphaltWe have refinery based asphalt production capacity of up to 102108 mbpd. We market asphalt through 33 owned or leased terminals throughout the Midwest and Southeast. We have a broad customer base, including

Index to Financial Statements

approximately 710675 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, polymerizedpolymer modified asphalt, emulsified asphalt emulsions and industrial asphalts.

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

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

Pipeline Barrels Handled

(Thousands of barrels per day)  2009  2008  2007

Crude oil trunk lines

  1,279  1,405  1,451

Refined products trunk lines

  953  960  1,049
         

TOTAL

  2,232  2,365  2,500

We also own 196 miles of private crude oil pipelines and 850 miles of private refined products pipelines, and we lease 217 miles of common carrier refined product pipelines. We have partial ownership interests in several pipeline companies that have approximately 780 miles of crude oil pipelines and 3,600 miles of refined products pipelines, including about 970 miles operated by MPL. In addition, MPL operates most of our 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, 2009, 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, 2009, 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; and

17 percent interest in Minnesota Pipe Line Company, LLC, which owns crude oil pipelines extending from Clearbrook, Minnesota, to Cottage Grove, Minnesota, which is in the vicinity of our St. Paul Park, Minnesota refinery.

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

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

Retail Marketing

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

As of December 31, 2008,2009, SSA had 1,6171,603 retail outlets in nine states. Sales of refined products through these retail outlets accounted for 15 percent of our refined product sales volumes in 2008.2009 and provide us with a base of ratable sales. Revenues from sales of non-petroleum merchandise through these retail outlets totaled $3,109 million in 2009, $2,838 million in 2008 and $2,796 million in 2007 and $2,706 million in 2006.2007. The demand for gasoline is seasonal in a majority of SSA markets, usually with the highest demand usually occurring during the summer driving season. Profit levelsMargins from the sale of merchandise and services tend to be less volatile than profit levelsmargins from the retail sale of gasoline and diesel fuel.

In October 2008, we sold our interest in Pilot Travel Centers LLC (“PTC”), an operator of travel centers in the United States.

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 and ORPL wholly-owned and undivided interest common carrier systems consist of 1,815 miles of crude oil lines and 1,826 miles of refined product lines comprising 34 systems located in 11 states. The MPL common carrier pipeline network is one of the largest petroleum pipeline systems in the United States, based on total barrels delivered. Our common carrier pipeline systems are subject to state and Federal Energy Regulatory Commission regulations and guidelines, including published tariffs for the transportation of crude oil and refined products. Third parties generated 11 percent of the crude oil and refined product shipments on our MPL and ORPL common carrier pipelines in 2008. 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

(Thousands of barrels per day)  2008  2007  2006

Crude oil trunk lines

  1,405  1,451  1,437

Refined products trunk lines

  960  1,049  1,101
         

TOTAL

  2,365  2,500  2,538

We also own 176 miles of private crude oil pipelines and 850 miles of private refined products pipelines, and we lease 217 miles of common carrier refined product pipelines. We have partial ownership interests in several pipeline companies that have approximately 780 miles of crude oil pipelines and 3,000 miles of refined products pipelines, including about 800 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 lines include the 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.

Index to Financial Statements

In addition, as of December 31, 2008, 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 crude oil lines run from: Patoka, Illinois, to Catlettsburg, Kentucky; Patoka, Illinois, to Robinson, Illinois; Patoka, Illinois, to Lima, Ohio; Samaria, Michigan, to Detroit, Michigan; and St. James, Louisiana, to Garyville, Louisiana.

In addition, as of December 31, 2008, 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;

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

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

17 percent interest in Minnesota Pipe Line Company, LLC, which owns crude oil pipelines extending from Clearbrook, Minnesota, to Cottage Grove, Minnesota, which is in the vicinity of our St. Paul Park, Minnesota refinery.

We plan to construct, by the year 2012, a new section of pipeline connecting with the existing crude line from Samaria, Michigan, to Detroit, Michigan. This new section will deliver additional supplies of Canadian crude to our Detroit refinery. The above discussion includes forward-looking statements concerning the construction of a new section of pipeline in Michigan. Some factors that could affect this project include transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by government or third-party approvals and other risks customarily associated with construction projects.

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.

LNG Operations

We hold a 60 percent interest in EGHoldings, which is accounted for under the equity method of accounting. In May 2007, EGHoldings completed construction of a 3.7 million metric tonnes per annum (“mmtpa”) LNG production facility on Bioko Island and delivered its first cargo of LNG. LNG from the production facility is sold

Index to Financial Statements

under a 3.4 mmtpa, or 460 mmcfd, sales and purchase agreement with a 17-year term. The purchaser under the agreement takes delivery of the LNG on Bioko Island, 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. Sales of LNG from this production facility totaled 3.4 metric tonnes in 2008. In 2008 we continued discussions with the government of Equatorial Guinea and partners regarding a potential second LNG production facility on Bioko Island.

We also own a 30 percent interest in a Kenai, Alaska, natural gas liquefaction plant, and lease two 87,500 cubic meter tankers used to transport LNG to customers in Japan. Feedstock for the plant is supplied from a portion of our natural gas production in the Cook Inlet. From the first production in 1969, we have sold our share of the LNG plant’s production under long-term contract with two of Japan’s largest utility companies, with 2008 LNG deliveries totaling 40 gross bcf. In June 2008 we, along with our partner, received approval from the DOE to extend the export license for this natural gas liquefaction plant through March 2011.

In April 2004, we began delivering LNG cargoes at the Elba Island, Georgia, LNG regasification terminal pursuant to an LNG sales and purchase agreement. Under the terms of the agreement, we have the right to deliver and sell up to 58 bcf of natural gas (as LNG) per year, through March 31, 2021, with a possible extension to November 30, 2023. In September 2004, we signed an agreement under which we will be supplied with 58 bcf of natural gas per year, as LNG, for a minimum period of five years. The agreement allows for delivery of LNG at the Elba Island LNG regasification terminal with pricing linked to the Henry Hub index. This supply agreement enables us to fully utilize our rights at Elba Island during the period of this agreement, while affording us the flexibility to commercialize other stranded natural gas resources beyond the term of this contract. The agreement commenced in 2005.

Methanol Operations

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. Sales of methanol from the plant totaled 792,794 metric tonnes in 2008. Production from the plant is used to supply customers in Europe and the United States.

Natural Gas Technology

We are developing a range of natural gas conversion technologies that can connect stranded natural gas to both conventional and transportation fuel markets. Our proprietary Gas-to-Fuels (“GTF”) process offers the ability to convert natural gas into premium fuels while bypassing conventional intermediate synthetic gasification technology. The base patent for this technology was awarded in 2007.

During 2008, we entered into agreements with GRT, Inc., a Delaware corporation, to cooperate on the advancement of gas-to-fuels-related technology. This transaction provides us with access to additional specialized technical and research personnel and lab facilities, and significantly expanded the portfolio of patents available to us via license and through a cooperative development program. In addition, we have acquired a 20 percent interest in GRT, Inc.

Also, during 2008, we completed construction of a facility to demonstrate operation of the fully integrated GTF process at a practical scale. We are evaluating the commercialization of this technology and have engaged an engineering contractor to provide engineering and design services for using the GTF technology on a commercial scale.

In addition to GTF, we continue to evaluate the application of other natural gas technologies, including LNG technology enhancements, gas hydrates and gas-to-liquids technology.

The above discussion of the Integrated Gas segment contains forward-looking statements with respect to the possible expansion of the LNG production facility and expectations for a GTF demonstration facility. Factors that could potentially affect the possible expansion of the LNG production facility include partner and government approvals, access to sufficient natural gas volumes through exploration or commercial negotiations with other resource owners and access to sufficient regasification capacity. Factors that could potentially affect the GTF demonstration facility include construction delays, start-up difficulties relating to scale-up in the process and unforeseen difficulties in our testing program related to moving from laboratory to practical scale. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Index to Financial Statements

Competition and Market Conditions

Strong competition exists in all sectors of the oil and gas industry and, in particular, in the exploration for and development of new reserves. We compete with major integrated and independent oil and gas companies, as well as national oil companies, for the acquisition of oil and natural gas leases and other properties. We compete with these companies for the equipment and labor required to develop and operate those properties and in the marketing of oil and natural gas to end-users. Many of our competitors have financial and other resources greater than those available to us. Acquiring the more attractive exploration opportunities frequently requires competitive bids involving front-end bonus payments or commitments-to-work programs. We also compete in attracting and retaining personnel, including geologists, geophysicists and other specialists. Based upon statistics compiled in the “2008“2009 Global Upstream Performance Review” published by IHS Herold Inc., we rank nintheighth among U.S.-based petroleum companies on the basis of 20072008 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. There are several additional synthetic crude oil projects being contemplated by various competitors and, if undertaken and completed, these projects may result in a significant increase in the supply of synthetic crude oil to the market. Since not all refineries are able to process or refine synthetic crude oil in significant volumes, there can be no assurance that sufficient market demand will exist at all times to absorb our share of the synthetic crude oil production from the AOSP at economically viable prices.

We must also compete with a large number of other companies to acquire crude oil for refinery processing and in the distribution and marketing of a full array of petroleum products. Based upon the “The Oil & Gas Journal 2009

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, 2008.2009. We compete in four distinct markets for the sale of refined products – wholesale, spot, branded and retail distribution. We believe we compete with about 4564 companies in the sale of refined products to wholesale marketing customers, including private-brand marketers and large commercial and industrial consumers; about 7075 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 280290 retailers in the retail sale of refined products. (A jobber is a business whothat does not carry out refining operations but who supplies refiner-branded products to gasoline stations or convenience stores. Dealers refer to a retail service station or convenience store operator,operators affiliated with a brand identity.) We compete in the convenience store industry through SSA’s retail outlets. The retail outlets offer consumers gasoline, diesel fuel (at selected locations) and a broad mix of other merchandise and services. In recent years, severalSeveral nontraditional fuel retailers, such as supermarkets, club stores and mass merchants, have affected the convenience store industry with their entrance intoand the retail transportation fuel business.National Petroleum News estimates such retailers had 11 percent of the U.S. gasoline market in 2009.

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

Environmental Matters

The Public Policy Committee of our Board of Directors is responsible for overseeing our position on public issues, including environmental matters. Our Corporate Health, Environment, Safety and SafetySecurity organization has the responsibility to ensure that our operating organizations maintain environmental compliance systems that are in accordancesupport 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 composed primarily of senior management, which oversees theour response to any major emergency, environmental or other emergency incident involving us or any of our properties.

LegislationState, 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 and greenhouse gas emissions have the potentialcould also affect our operations. The cost to impact us. The Kyoto Protocol, effective in 2005, has been ratified by countries in which we have or in the future may have operations. Canadian federal and provincialcomply with these laws the U.S. Energy Independence and Security Act of 2007, the European Union requirements and California laws contain provisions related to greenhouse gas emissions. Other climate change legislation and regulations in the United States, Canada and abroad are in various stages of development or implementation. These regulations are further along in development in Alberta, Canada, and in the European Union, where we have significant operations. Our industry and businesses

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throughout the United States are also awaiting the U.S. Environmental Protection Agency’s (“EPA”) actions upon the remand of the U.S. Supreme Court decision in Massachusetts v. USEPA, which could have impacts on a number of air permitting and environmental regulatory programs. In July 2008, the EPA issued an Advanced Notice of Proposed Rulemaking (“ANPR”) to address the Supreme Court decision and to seek public input on potential actions it may take to regulate greenhouse gas emissions. Action by EPA on the ANPR is expected in 2009. There also is other pending litigation which could affect whether EPA regulates greenhouse gas emissions. In addition, a new Administration in the U.S. may choose to address greenhouse gas emissions through regulation, permitting or other action in 2009. Our liquid hydrocarbon, natural gas and bitumen production and processing operations typically result in emissions of greenhouse gases. Likewise, emissions arise from our RM&T operations, including the refining of crude oil and the transportation of crude oil and refined products. 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, 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 theat this time, but could be significant. For 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.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

Of particular significance to our refining operations are EPA regulations that require reduced sulfur levels in diesel fuel for off-road use. We have spent approximately $120 million between 2006 and 2008, and plan to spend approximately $50 million in 2009 on refinery investments to produce ultra-low sulfur diesel fuel for off-road use, in compliance with EPA regulations. Further, we have estimated that we may spend approximately $1 billion over a five-year period beginning in 2008 to comply with Mobile Source Air Toxics II (“MSAT II”) regulations relating to benzene content in refined products. We have not finalized our strategy or cost estimates to comply with these requirements. Our actual MSAT II expenditures have totaled $76 million through December 31, 2008 and we expect to spend $200 million in 2009. The cost estimates are forward-looking statements and are subject to change as further work is completed in 2009.

The EPA is in the process of implementing regulations to address currentthe National Ambient Air Quality Standards (“NAAQS”) for fine particulate emissions and ozone. In connection with these standards, the EPA will designate certain areas as “nonattainment,” meaning that the air quality in such areas does not meet the NAAQS. To address these nonattainment areas, the EPA proposed a rule in 2004 called the Interstate Air Quality Rule (“IAQR”) that would require significant emissions reductions in numerous states. The final rule, promulgated in 2005, was renamed the Clean Air Interstate Rule (“CAIR”). While the EPA expects that states will meet their

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CAIR obligations by requiring emissions reductions from electric generating units, states were to have the final say on what sources they regulate to meet attainment criteria. Significant uncertainty in the final requirements of this rule resulted from litigation (State of North Carolina, et al. v. EPA). In July 2008, the U.S. Court of Appeals for the District of Columbia Circuit vacated the CAIR in its entirety and remanded it to EPA to promulgate a rule consistent with the Court’s opinion. In December 2008, the Court modified its July ruling to leave the CAIR in effect until EPA develops a new rule and control program. The EPA has announced that it plans to propose a new Clean Air Transport Rule in July of 2010. It is expected that the CAIR will be significantly altered, and it could result in changes in emissions control strategies. Our refinery operations are located in affected states, and some of these states may choose to propose more stringent fuels requirements on our refineries in order to meet the CAIR. In addition, the EPA promulgated a revised ozone standard in March 2008, and the EPA has commenced the multi-year process to develop the implementing rules required by the Clean Air Act. We cannot reasonably estimate the final financial impact of the state actions to implement the CAIR until the EPA has issued a revised rule and states have taken further action to implement that rule.

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

Water

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

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

Solid Waste

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

containing regulated substances. We have ongoing RCRA treatment and disposal operations at one of our RM&T facilities and primarily utilize offsite third-party treatment and disposal facilities. In 2011,2010, Canada will implement a ban on the land application of certain wastes, and we are developing options to treat or dispose of these wastes consistent with these new restrictions. Ongoingwastes. However, the ongoing waste handling and disposal-related costs however,associated with the Canadian land disposal restrictions are not expected to be material.material because we have identified alternative hazardous waste treatment options within the United States.

Remediation

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

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process which are placed in ponds. The AOSP is required to reclaim its tailing ponds as part of its on going reclamation work. The reclamation process uses developing technology and there is an inherent risk that the current process may not be as effective or perform as required in order to meet the approved closure and reclamation plan. The AOSP continues to develop its current reclamation technology and continues to investigate other alternate tailings management technologies. In February 2009, the Alberta Energy Resources Conservation Board (“ERCB”) issued a directive which more clearly defines criteria for managing oil sands tailings. TheIn September 2009, the AOSP Joint Venture Parties are reviewing this directiveOperator submitted a tailings management paper to determine the impact onERCB, that sets forth its plan to comply with the oil sands operations andDirective. This plan is currently under review by the timeline for the required compliance.ERCB. Increased compliance costs may result if tailing pond reclamation technologies prove unsuccessful or the directive requires additional measures.less effective than anticipated.

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 multiple-partsecond Renewable Fuel Standard (“RFS”RFS2”). The RFS was 9.0EPA announced the final RFS2 regulations on February 4, 2010. The RFS2 requires 12.95 billion gallons of renewable fuel usage in 2008, and is 11.1 billion gallons in 2009,2010, increasing to 36.0 billion gallons by 2022. In the near term, the RFSRFS2 will be satisfied primarily with fuel ethanol blended into gasoline. The RFSRFS2 presents production and logistic challenges for both the fuel ethanol and petroleum refining industries. The RFSRFS2 has required, and maywill 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 RFS,RFS2, EISA establishes an advanced biofuel RFSRFS2 that begins with 0.60.95 billion gallons in 20092010 and increases to 21.0 billion gallons by 2022. Subsets within the advanced biofuel RFSRFS2 include 0.51.15 billion gallons of biomass-based diesel in 2009,2010, increasing to 1.0 billion gallons 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.

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.

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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 the tenth anniversary of the USX Separation, 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. The agreement also obligates us to use commercially reasonable efforts to obtain and maintain letters of credit and other liquidity arrangements required under the assumed obligations.

United States Steel’s obligations to 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 significant exposures to United States Steel arising from the transaction discussed in Note 3 to the consolidated financial statements.

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 30,36028,855 active employees as of December 31, 2008.2009. Of that number, 19,79418,325 were employees of SSA, most of who 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. NegotiationsCertain employees at our Texas City refinery are currently underway withrepresented by the same union in Texas

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City withunder a contract expiration oflabor agreement that expires on March 31, 2009.2012. The International Brotherhood of Teamsters represents certain hourly employees under labor agreements that are scheduled to expire on May 31, 2012 at our St. Paul Park refinery and January 31, 2011, at our Detroit refinery.

Executive Officers of the Registrant

The executive officers of Marathon and their ages as of February 1, 2009,2010, are as follows:

 

Clarence P. Cazalot, Jr.

  5859  President and Chief Executive Officer

Janet F. Clark

  5455  Executive Vice President and Chief Financial Officer

Gary R. Heminger

  5556  Executive Vice President, Downstream

Steven B. Hinchman

50Executive Vice President, Technology and Services

Jerry Howard

  6061  Senior Vice President, Corporate Affairs

Sylvia J. Kerrigan

44Vice President, General Counsel and Secretary

Paul C. Reinbolt

  5354  Vice President, Finance and Treasurer

David E. Roberts, Jr.

  4849  Executive Vice President, Upstream

William F. Schwind, Jr.

64Vice President, General Counsel and Secretary

Michael K. Stewart

  5152  Vice President, Accounting and Controller

Howard J. Thill

  4950  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 and chief financial officer effective January 2005.2007. Ms. Clark joined Marathon in January 2004 as senior vice president and chief financial officer.

 

Mr. Heminger was appointed executive vice president, downstream effective JanuaryJuly 2005. Mr. Heminger has served as president of MPC since September 2001.

 

Mr. Hinchman was appointed senior vice president, worldwide production effective January 2002 and was appointed to his current position effective April 1, 2008.

Mr. Howard was appointed senior vice president, corporate affairs effective January 2002.

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. Schwind was appointed vice president, general counsel and secretary effective January 2002.

 

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.

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/Corporate_Governance/.

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 theour 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

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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.

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;

 

natural gas and electricity supply costs incurred by refineriesrefineries;

 

the ability of the members of the Organization of Petroleum Exporting Countries 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.

Estimates of liquid hydrocarbon, natural gas and bitumensynthetic 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 bitumensynthetic crude oil reserves.

The proved liquid hydrocarbon and natural gas reservesreserve information included in this report has been derived from engineering estimates. Those estimatesEstimates 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 we have retained.consultants. The synthetic crude oil reserves estimates were calculated using liquid hydrocarbon and natural gasprepared by GLJ Petroleum Consultants, a third-party consulting firm experienced in working with oil sands. Reserves were priced at the average of closing prices for the first day of each month in effect as ofthe 12-month period ended December 31, 2008,2009, as well as other conditions in existence as of thatat the date. Any significant future price

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changes will have a material effect on the quantity and present value of our proved liquid hydrocarbon and natural gas reserves. Future reserve revisions could also result from changes in governmental regulation, among other things, governmental regulation and severance and other production taxes.things.

Proved liquid hydrocarbon and natural gas reserveReserve estimation is a subjective process that involves estimating volumes to be recovered from underground accumulations of liquid hydrocarbonshydrocarbon, natural gas and natural gasbitumen that cannot be directly measured. (Bitumen is mined then upgraded into synthetic crude oil.) Estimates of economically recoverable liquid hydrocarbon and natural gasproducible 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; and

 

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

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

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

 

the amount and timing of liquid hydrocarbon and natural gas 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, and 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 liquid hydrocarbon and natural gas properties. As required by SEC Rule 4-10 of Regulation S-X, the estimated discounted future net revenues from our proved liquid hydrocarbon, and natural gas and synthetic crude oil reserves are based on an average of closing prices for the first day of each month in the 12-month period ended December 31, 2009, and costs as ofapplicable 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.

The proved bitumen reserves information included in this report has also been derived from engineering estimates. Reserves related to mining operations are defined as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proved reserves are measured by various testing and sampling methods. Bitumen reserves as of December 31, 2008 were estimated by third-party consultants, using volumetric estimation techniques similar to those used in estimating liquid hydrocarbon and natural gas reserves and are subject to many of the same uncertainties discussed above, except that estimates of bitumen reserves are based on average annual prices consistent with industry practice in Canada. The estimated quantity of net proved bitumen reserves is based on a number of assumptions, including (among others) commodity prices, volumes in-place, presently known physical data, recoverability of bitumen, industry economic conditions, levels of cash flow from operations and other operating considerations. To the extent these assumptions prove inaccurate, actual recoveries could be different than current estimates. Future proved bitumen reserve revisions could also result from changes in, among other things, governmental regulation and taxation.

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

Index to Financial Statements

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.

We will continue to 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 profitability could be materially reduced.

Our businesses are subject to numerous laws, regulations and regulationsother requirements relating to the protection of the environment, including those relating to the discharge of materials into the environment, waste management, pollution prevention, measures, 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 will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of these laws and regulations. To the extent these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. The specific impact of these laws and regulations on us and our competitors 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. 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 the United States, Canada and European Union. These include 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 costs to (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 program.programs. These costs and capital expenditures could be material. Although uncertain, these developments could increase our costs, reduce the demand for the products we sell and create delays in our obtaining air pollution permits for new or modified facilities.

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. Our liquid hydrocarbon, natural gas and synthetic crude oil production and processing operations typically result in emissions of greenhouse gases. Likewise, emissions arise from our RM&T operations, including the refining of crude oil, and from the use of our refined petroleum products by our customers. 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. Related to the endangerment finding, in September of 2009, the EPA proposed a greenhouse gas emission standard for mobile sources (cars and other light duty vehicles). This standard is expected to be finalized in the spring of 2010. The endangerment finding along with the mobile source standard are expected to lead to widespread regulation of stationary sources of greenhouse gas emissions, and in October of 2009 the EPA proposed 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.

In the U.S., the House of Representatives and the Senate each have their own form of cap and trade legislation to reduce carbon emissions (Waxman-Markey Bill and the Kerry-Boxer Bill). 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 Copenhagen Accord was reached in December 2009 with the United States pledging to reduce emissions 17 percent below 2005 levels by 2020.

The Canadian federal government has not enacted greenhouse gas emission reduction legislation although it has announced a commitment to reduce the country’s emissions 17 percent from 2005 levels by 2020, to be pursued through a cap and trade system.

The European Union (“EU”) Emissions Trading Scheme 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. Through 2009, we have complied with this program by using the allocated free allowances or by borrowing on our future year allowances.

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. 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 directed its responsible state agency to adopt mandatory reporting rules for significant sources of greenhouse gases. We have not conducted significant business in California in recent years, but other states where we have operations could adopt similar greenhouse gas legislation.

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.

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

Index to Financial Statements

substances. For example, we have been, and presently are, a defendant in various litigation and other proceedings involving products liability and other claims related to alleged contamination of groundwater with the oxygenate methyl tertiary butyltertiary-butyl ether or MTBE.(“MTBE’). We may become involved in further litigation or other proceedings, or we may be held responsible in existing or future litigation or proceedings, the costs of which could be material.

We have in the past operated retail marketing sites with underground storage tanks (“USTs”) in various jurisdictions and are currently operating retail marketing sites that have USTs in numerous states. Federal and state regulations and legislation govern the USTs, and compliance with those requirements can be costly. The operation of USTs also poses certain other risks, including damages associated with soil and groundwater contamination. Leaks from USTs which may occur at one or more of our retail marketing sites, or which may have occurred at our previously operated retail marketing sites, may impact soil or groundwater and could result in fines or civil liability for us.

Environmental laws are subject to frequent change and many of them have become more stringent. In some cases, they can impose liability for the entire cost of cleanup on any responsible party, without regard to negligence or fault, and impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them.

In 2007,If we are unable to complete capital projects at their expected costs and in a timely manner, or if the U.S. Congress passed the Energy Independencemarket conditions assumed in our project economics deteriorate, our business, financial condition, results of operations and Security Act (“EISA”),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 among other things, sets a targetare beyond our control, including:

denial of 35 miles per gallon for the combined fleet of carsor delay in receiving requisite regulatory approvals and light trucks/or permits;

unplanned increases in the United Statescost 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, model year 2020,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 contains a multiple-part Renewable Fuel Standard (“RFS”). The RFS was 9.0 billion gallonsadversely affect our business, financial conditions, results of renewable fuel in 2008,operations and is 11.1 billion gallons in 2009, increasingcash flows.

Many of our major projects and operations are conducted with partners, which may decrease our ability to 36.0 billion gallons by 2022. In the near term, the RFS will be satisfied primarily with fuel ethanol blended into gasoline. The RFS presents production and logistics challenges for both the fuel ethanol and petroleum refining industries. The RFS has required, and may in the future continue to require, additional capital expenditures or expenses by us to accommodate increased fuel ethanol use. The advanced biofuels programs will present specific challenges in that we may have tomanage 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 other partiespartners in order to meetshare risks associated with those operations. However, these arrangements also may decrease our obligationsability to use advanced biofuels, including biomass-based dieselmanage risks and cellulosic biofuel, with potentially uncertain suppliescosts, particularly where we are not the operator. We could have limited influence over and control of the behaviors and performance of these new fuels. There will be compliance costsoperations. This could affect our operational performance, financial position 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 per gallon or due to refined petroleum products being replaced by renewable fuels. In addition, tax incentives and other subsidies have made renewable fuels more competitive with refined products than they otherwise would have been which may have reduced and may further reduce refined product margins and refined products’ ability to compete with renewable fuels.reputation.

The recent distressUncertainty in the financial markets may impact our ability to obtain future financing and could adversely affect entities with which we do business.

In the future we may require financing to grow our business. Financial institutions participate in our revolving credit facility and provide us with businessservices including insurance, coverage, cash management, services, commercial letters of

credit, derivative instruments, and short-term investments. The recent distressUncertainty affecting the financial markets and the possibility that financial institutions may consolidate or go bankrupt has reducedaltered levels of activity in the creditfinancial markets. This could diminish the amountA deterioration of financing available to companies. In addition, such turmoil in the financial marketsmarket conditions could significantly increase our costs associated with borrowing. Our liquidity and our ability to access the credit and/or capital markets may also be adversely affected by changes in the financial markets and the global economy. Continuing turmoil in the financial markets could make it more difficult for us to access capital, sell assets, refinance our existing indebtedness, enter into agreements for new indebtedness or obtain funding through the issuance of our securities. In addition, there could be a number of follow-on effects from the credit crisiscontinued turmoil on us, including insolvency of customers, key suppliers, partners, and other counterparties to our commodity and foreign exchange derivative instruments.counterparties.

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

Local political and economic factors in internationalglobal markets could have a material adverse effect on us. A total of 6329 percent of our liquid hydrocarbon and natural gas sales volumes in 20082009 was derived from production outside the United States and 7071 percent of our proved liquid hydrocarbon and natural gas reserves as of December 31, 2008,2009, were located outside the United States. All of our bitumensynthetic 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 internationalglobal markets, including changes in foreign 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. These risks include:

 

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

 

the possibility that a foreign 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.

Index to Financial Statements

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.

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, and welosses. We do not insure against all potential losses and therefore we could be seriously harmed by unexpected liabilities.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. CertainVarious 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 orand 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.

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

In a bankruptcy case or lawsuit initiated by one or more creditors or a representative of creditors of Ashland, a court could review our 2005 transactions with Ashland under state fraudulent transfer or conveyance laws. Under those laws, the transactions would be deemed fraudulent if the court determined that the transactions were undertaken for the purpose of hindering, delaying or defrauding creditors or that the transactions were constructively fraudulent. If the transactions were found to be a fraudulent transfer or conveyance, we might be required to provide additional consideration to Ashland or to return all or a portion of the interest in MPC and the other assets we acquired from Ashland as a result of those transactions.

In connection with our transactions with Ashland completed in 2005, we delivered part of the overall consideration (specifically, shares of Marathon common stock having a value of $915 million) to Ashland’s shareholders. We obtained opinions from a nationally recognized appraisal firm that Ashland received reasonably equivalent value or fair consideration from us in the transactions and that Ashland was not insolvent either before or after giving effect to the closing of the transactions. Although we are confident in our conclusions regarding Ashland’s receipt of reasonably equivalent value or fair consideration and its solvency both before and after giving effect to the closing of our transactions, such determinations involve numerous assumptions and uncertainties, and it is possible that a court could disagree with our conclusions.

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.

Index to Financial Statements

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

As a result of the transactions in which we acquired the minority interest in MPC from Ashland in 2005, Marathon is severally liable for federal income taxes (and in some cases for certain state taxes) of Ashland for tax years still open as of the date we completed the transactions. We have entered into a tax matters agreement with Ashland, which provides that:

We will be responsible for the tax liabilities of the Marathon group of companies, including the tax liabilities of MPC and the other companies and businesses we acquired in the transactions (for periods after the completion of the transactions); and

Ashland will generally be responsible for the tax liabilities of the Ashland group of companies before the completion of the transactions, and the income taxes attributable to Ashland’s interest in MPC before the completion of the transactions. However, under certain circumstances we will have several liability for those tax liabilities owed by Ashland to various taxing authorities, including the Internal Revenue Service.

If Ashland fails to pay any tax obligation for which we are severally liable, we may be required to satisfy this tax obligation. That would leave us in the position of having to seek indemnification from Ashland. In that event, our indemnification claims against Ashland would constitute general unsecured claims, which would be effectively subordinate to the claims of secured creditors of Ashland, and we would be subject to collection risk associated with collecting unsecured debt from Ashland.

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

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

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

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

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

Index to Financial Statements

such compensation to Marathon. In the event we become entitled to any repayment, we would be subject to collection risks associated with collecting an unsecured claim from Ashland.

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

In a bankruptcy case or lawsuit initiated by one or more creditors or a representative of creditors of Ashland, a court may review our 2005 transactions with Ashland under state fraudulent transfer or conveyance laws. Under those laws, the transactions would be deemed fraudulent if the court determined that the transactions were undertaken for the purpose of hindering, delaying or defrauding creditors or that the transactions were constructively fraudulent. If the transactions were found to be a fraudulent transfer or conveyance, we might be required to provide additional consideration to Ashland or to return all or a portion of the interest in MPC and the other assets we acquired from Ashland.

Under the laws of most states, a transaction could be held to be constructively fraudulent if a court determined that:

the transferor received less than “reasonably equivalent value” or, in some jurisdictions, less than “fair consideration” or “valuable consideration”; and

the transferor:

was insolvent at the time of the transfer or was rendered insolvent by the transfer;

was engaged, or was about to engage, in a business or transaction for which its remaining property constituted unreasonably small capital; or

intended to incur, or believed it would incur, debts beyond its ability to pay as those debts matured.

In connection with our transactions with Ashland completed in 2005, we delivered part of the overall consideration (specifically, shares of Marathon common stock having a value of $915 million) to Ashland’s shareholders. In order to help establish that Ashland received reasonably equivalent value or fair consideration from us in the transactions, we obtained a written opinion from a nationally recognized appraisal firm to the effect that Ashland received amounts that were reasonably equivalent to the combined value of Ashland’s interest in MPC and the other assets we acquired. We also obtained a favorable opinion from that appraisal firm relating to various financial tests that supported our conclusion and Ashland’s representation to us that Ashland was not insolvent either before or after giving effect to the closing of the transactions. Those opinions were based on specific information provided to the appraisal firm and were subject to various assumptions, including assumptions relating to Ashland’s existing and contingent liabilities and insurance coverage. Although we are confident in our conclusions regarding (1) Ashland’s receipt of reasonably equivalent value or fair consideration and (2) Ashland’s solvency, it should be noted that the valuation of any business and a determination of the solvency of any entity involve numerous assumptions and uncertainties, and it is possible that a court could disagree with our conclusions.

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

In connection with the separation of United States Steel from Marathon, United States Steel agreed to hold Marathon harmless from and against various liabilities. While we cannot estimate some of these liabilities, the portion of these liabilities that we can estimate amounts to $513 million as of December 31, 2008, including accrued interest of $8 million. If United States Steel fails to satisfy any of those obligations, we would be required to satisfy them and seek indemnification from United States Steel. In that event, our indemnification claims against United States Steel would constitute general unsecured claims, effectively subordinate to the claims of secured creditors of United States Steel.

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

Index to Financial Statements

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 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 those 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.

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.

Item 1B. Unresolved Staff Comments

Item 1B.Unresolved Staff Comments

None.

Item 2. Properties

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, andincluding 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, and natural gas, and synthetic crude oil sales volumes, andwith net bitumen production volumes are set forth in Item 8. Financial Statements and Supplementary Data – Supplemental Statistics. Estimated net proved liquid hydrocarbon, and 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 and estimated net proved bitumen reserves are set forth in Item 1. Business – Oil Sands Mining.Reserves. The basis for estimating these reserves is discussed in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations1. BusinessCritical Accounting Estimates – Estimated Net Recoverable Reserve Quantities – Proved Liquid Hydrocarbon and Natural Gas Reserves and – Proved Bitumen Reserves.

Item 3. Legal Proceedings

Item 3.Legal Proceedings

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

MTBE Litigation

We, along with other refining companies, settled a number of lawsuits pertaining to methyl tertiary-butyl ether (“MTBE”) in 2008. Presently, we are a defendant, along with other refining companies, in 2027 cases arising in threefour states alleging damages for methyl tertiary-butyl ether (“MTBE”)MTBE contamination. We have also received seven Toxic Substances Control Act notice letters involving potential claims in two states. Such notice letters are often followed by litigation. Like the cases that werewe settled in 2008, 12 of the remaining MTBE cases are consolidated in a multidistrictmulti-district litigation (“MDL”) in the Southern District of New York for pretrial proceedings. NineteenThe other 15 cases are in New York state courts (Nassau and Suffolk Counties). Plaintiffs in 26 of the remaining27 cases allege damages to water

Index to Financial Statements

supply wells from contamination of groundwater by MTBE, similar to the damages claimed in the cases settled cases.in 2008. In the other remaining case, the State of New Jersey Department of Environmental Protection is seeking the cost of remediating MTBE contamination and natural resources damages allegedly resulting from contamination of groundwater by MTBE. This is the only MTBE contamination case in which we are a defendant and natural resources damages are sought. We are vigorously defending these cases. We along with a number of other defendants, have engaged in settlement discussions related to the majority of the cases in which we are a defendant.these cases. We do not expect our share of liability if any, for the remainingthese cases to significantly impact our consolidated results of operations, financial position or cash flows. We voluntarily discontinued producing MTBE in 2002.

Natural Gas Royalty Litigation

We are currently a party in twoto one qui tam cases,case, which allegealleges that federalMarathon and Indian lesseesother defendants violated the False Claims Act with respect to the reporting and payment of royalties on natural gas and natural gas liquids.liquids for federal and Indian leases. A qui tam action is an action in which the relator files suit on behalf of himself as well as the federal government. OneThe case currently pending is U.S. ex rel Harrold E. Wright v. Agip Petroleum Co. et al, whichal. It is primarily a gas valuation case. A tentativeMarathon has reached a settlement agreement has been reached.with the Relator and the DOJ which will be finalized after the Indian Tribes review and approve the settlement terms. Such settlement is not expected to significantly impact our consolidated results of operations, financial position or cash flows. The other case is U.S. ex rel Jack Grynberg v. Alaska Pipeline, et al. involving allegations of gas measurement. This case was dismissed by the trial court and is currently on appeal to the 10th Circuit Court of Appeals. The outcome of this case is not expected to significantly impact our consolidated results of operations, financial position or cash flows.

Product Contamination Litigation

A lawsuit filed in the United StatesU.S. District Court for the Southern District of West Virginia allegesalleged that our Catlettsburg, Kentucky, refinery distributed contaminated gasoline to wholesalers and retailers for a period prior to August 2003, causing permanent damage to storage tanks, dispensers and related equipment, resulting in lost profits, business disruption and personal and real property damages. Following the incident, we conducted remediation operations at affected facilities and we deny that anythere was no permanent damages resulted from the incident.damage to wholesaler and retailer equipment. Class action certification was granted in August 2007. We have entered into a tentativeA settlement agreement in this case. Notice of the proposed settlement has been sent to the class members. Approvalcase was approved by the court after a fairness hearing is required beforeon March 18, 2009, payment has been made and the case has been dismissed with prejudice. The settlement can be finalized. The fairness hearing is scheduled in the first quarter of 2009. The proposed settlement willdid not significantly impact our consolidated results of operations, financial position or cash flows.

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, 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. Mediation has been unsuccessful and the parties expectThe 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 setthe U.S. EPA with instructions for reconsideration. The federal government filed a briefing schedule for summary judgment motions.Notice of Appeal, but subsequently filed a voluntary Motion to dismiss which was granted by the District Court. In sum, the U.S. EPA must now decide whether to approve or disapprove Montana’s 2006 water quality standards consistent with the Court’s remand instructions.

Montana Litigation

In June 2006, we filed a complaint for declaratory judgment in Montana State District Court against the Montana Board of Environmental Review (“MBER”) and the Montana Department of Environmental Quality, seeking to set aside and declare invalid certain regulations of the MBER that single out the coal bed natural gas industry and a few streams in eastern Montana for excessively severe and unjustified restrictions for surface water discharges of produced water from coal bed methane operations. None of the streams affected by the regulations suffers impairment from coal bed natural gas discharges. The court, in deferring to the MBER’s discretion, upheld the MBER’s regulations. This decision was affirmed by the Montana Supreme Court; this decision in the meanwhile does not impact our operations due to pendinga decision in the litigation with U.S. EPA in Wyoming Federal District Court.Court, reversing U.S. EPA’s approval of the Montana regulations.

Index to Financial Statements

Colorado Litigation

In 2008, the State of Colorado, through its Department of Public Health and Environment, filed a state court suit against us and others alleging violations of storm water requirements in and around an upstream production facility. The State seeks penalties above $100,000. We continue to workmatter was resolved in the third quarter of 2009 with the state in an effort to resolve this matter.parties paying a penalty of $280,000 of which our share was $98,000.

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 state seeks penalties above $100,000.order requires a cash penalty of $610,560 plus plant compliance projects and supplemental environmental projects estimated to cost over $5 million. We continue to workwere the operator and part owner of the plant through June 2009. We are working with the state in an effortother plant owners to resolve the matter.obtain reimbursement for their share of these costs.

Powder River Basin Litigation

The U.S. Bureau of Land Management (“BLM”) completed multi-year reviews of potential environmental impacts from coal bed methane development on federal lands in the Powder River Basin, including those in Wyoming. The BLM signed a Record of Decision (“ROD”) on April 30, 2003, supporting increased coal bed methane development. Plaintiff environmental and other groups filed suit in May 2003 in federal court against the BLM to stop coal bed methane development on federal lands in the Powder River Basin until the BLM conducted additional environmental impact studies. Marathon intervened as a party in the ongoing litigation before the Wyoming Federal District Court. As these lawsuits to delay energy development in the Powder River Basin progressed through the courts, the Wyoming BLM continued to process permits to drill under the ROD. During the last quarter of 2008, the Court ruled in BLM’s favor, finding its environmental studies and stewardship were adequate and protective under federal law. The plaintiffs have appealed this ruling to the 10th Circuit Court of Appeals.Appeals and are currently awaiting oral arguments.

Other Environmental Proceedings

The following is a summary of proceedings involving us that were pending or contemplated as of December 31, 2008,2009, 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, 2008,2009, we had been identified as a PRP at a total of nine 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 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 $4 million per site. We are not far enough along in the process to determine the cost for the remaining three sites, but two of those sites may be a PRP at$1 million to $2 million or more each and the other site may be under $1 million. In addition, there are four additional sites wherefor which we have received information requests or other indications that we may be a PRP under CERCLA, but we do not havefor which sufficient information is not presently available to establishconfirm the existence of liability. We are at various stages of case development at the nine PRP sites with some site information being preliminary and incomplete and subject to change, but we currently estimate our liability will be under $200,000 at four sites, under $1 million at one site, under $2 million at two sites, and under $4 million at the remaining two sites.

There are also 119116 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

Index to Financial Statements

incomplete, we believe that liability for clean-up and remediation costs in connection with sixfive of these sites will be under $100,000 per site, that 5855 sites have potential costs between $100,000 and $1 million per site and that 29 sites may involve remediation costs between $1 million and $5 million per site. Ten sites have incurred remediation costs of more than $5 million per site. There are 16 of theseWith respect to the remaining 17 sites, for which 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 LLC in 2005. We estimate that we will be responsible for nearly $18 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.

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 2827 years, we anticipate spending approximately $4.8$4.6 million in remediation costs at this site. In 2009,2010, interim remediation measures will continue to occur and appropriate site characterization and risk-based assessments necessary 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 2009 and 2008 were $291,000 and 2007 were $434,000, and $524,000, respectively, with expenditures for remedial measures in 20092010 expected to be approximately $1.6 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 2008.2009.

During 2001, we entered into a New Source Review consent decree and settlement of alleged Clean Air Act (“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 of an enforcement action for alleged CAA violations 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”). Subject to entering a formal consent decree or further amendment of the New Source Review consent decree to memorialize our understanding, we have agreed with the U.S. Department of Justice and U.S. EPA to pay a civil penalty of $408,000 and conduct supplemental environmental projects of approximately $1.1$1 million, as part of a settlement of an enforcement action for alleged CAA violations relating to benzene waste NESHAPS. We hope to enteranticipate entering into a formal consent decree or amendment to resolve these matters in 2009.2010.

In May 2008, the Texas Commission on Environmental Quality (“TCEQ”) performed a benzene waste NESHAPS inspection at the Texas City Refinery. The TCEQ subsequently issued a notice of enforcement and a proposed penalty agreed order seeking $143,000 in penalties. We hopeorder. This matter was concluded whereby all parties agreed to resolve this matter with the TCEQ in 2009.a Supplemental Environmental Project (SEP) requiring Marathon to operate an on-site ambient air monitoring system for twelve months.

The U.S. Occupational Safety and Health Administration (“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 the Canton, Robinson, Catlettsburg, Detroit, and Texas City, and St. Paul Park refineries with agreed–to penalties of $321,500 and $135,000 imposed in Canton (2007) and Texas City, (2008), respectively. No penalties were imposed as a result of the other inspections. Inspections at St. Paul Park (2009) and Garyville (2010) may occur at Garyville in 2010 and further enforcement action by OSHA or equivalent state agency may resultresult.

In November 2008, the U.S. EPA issued a notice of violation for oil spills occurring at the Catlettsburg Refinery in 2004 and 2008. SubjectMarathon entered into two separate Consent Agreement/Final Orders (CAFOs) in 2009 resulting in civil penalties totaling $118,000.

Item 4. Submission of Matters to entering a formal consent decree to memorialize our understanding, we have agreed with the U.S. EPA to pay a civil penaltyVote of $118,000. We hope to enter into a formal consent decree to resolve these matters in 2009.

SEC Investigation Relating to Equatorial GuineaSecurity Holders

By letter dated July 15, 2004, the SEC notified us that it was conducting an inquiry into payments made to the government of Equatorial Guinea, or to officials and persons affiliated with officials of the government of Equatorial Guinea. By letter dated February 13, 2009, the SEC further notified us that they completed their investigation and did not intend to recommend any enforcement action in this matter.None.

Index to Financial Statements
Item 4.Submission of Matters to a Vote of Security Holders

None.

PART II

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

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. Marathon common stock is also traded on the Chicago Stock Exchange. As of January 29, 2010, there were 55,325 registered holders of Marathon common stock. The frequency and amount of dividends paid during the last two years is set forth in Item 8. Financial Statements and Supplementary Data – Selected Quarterly Financial Data.

As of January 31, 2009, there were 57,275 registered holders of Marathon common stock.

Information concerningThe following is the quarterly high and low sales prices for Marathon common stock follows:stock:

 

   2008  2007(a) 
    High  Low  High  Low 

Quarter 1

  $61.88  $45.23  $102.56  $83.43 

Quarter 2

   55.05   44.92   132.51   59.74 

Quarter 3

   52.78   37.48   65.04   49.24 

Quarter 4

   38.81   19.58   62.59   53.34 

(a)

Prices are as published each day; therefore, those before June 18, 2007 do not reflect the two-for-one stock split.

Recent Sales of Unregistered Securities

In October 2007, we issued 29,127,260 shares of Marathon common stock to Western shareholders in connection with our acquisition of Western. This issuance of Marathon common stock was exempt from the registration requirements of the Securities Act of 1933, as amended, by virtue of Section 3(a)(10).

   2009  2008
    High  Low  High  Low

Quarter 1

  $29.87  $20.92  $61.88  $45.23

Quarter 2

   33.41   27.08   55.05   44.92

Quarter 3

   33.88   28.03   52.78   37.48

Quarter 4

   35.27   30.48   38.81   19.58

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.

Index to Financial Statements

Issuer Purchases of Equity Securities

The following table provides information about purchases by Marathon and its affiliated purchaser during the quarter ended December 31, 2008,2009, 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)(b)
  Average
Price Paid
per Share
  Total Number of
Shares Purchased
as Part of
Publicly
Announced Plans
or Programs
(d)
  Approximate
Dollar Value of
Shares that May
Yet Be Purchased
Under the Plans
or Programs
(d)
 

10/01/08 – 10/31/08

  27,687  $38.24      –  $2,080,366,711 

11/01/08 – 11/30/08

  24,957  $29.22      –  $2,080,366,711 

12/01/08 – 12/31/08

  11,040(c) $24.26      –  $2,080,366,711 
          

Total

  63,684  $32.28      –     
   Column (a)  Column (b)  Column (c)  Column (d) 
Period  Total Number
of Shares
Purchased 
(a)(b)
  Average
Price Paid
per Share
  Total Number of
Shares
Purchased as
Part of Publicly
Announced
Plans or
Programs
(d)
  Approximate
Dollar Value of
Shares that May
Yet Be Purchased
Under the Plans
or Programs
(d)
 

10/01/09 – 10/31/09

  1,408  $31.45                      -  $2,080,366,711   

11/01/09 – 11/30/09

  29,476  $32.04  -  $2,080,366,711   

12/01/09 – 12/31/09

  48,807 (c)  $31.17  -  $2,080,366,711   
          

Total

  79,691  $31.50  -     

(a)

63,67231,849 shares of restricted stock were delivered by employees to Marathon, upon vesting, to satisfy tax withholding requirements.

(b)

Under the terms of the transactionstransaction whereby we acquired the minority interest in MPCMarathon Petroleum Company and other businesses from Ashland Marathon paidInc. (“Ashland”), Ashland shareholders have the right to receive 0.2364 shares of Marathon common stock for each share of Ashland common stock owned on June 30, 2005 and cash in lieu of issuing fractional shares based on a value of Marathon’s common stock to which such holders would otherwise be entitled. We$52.17 per share. In the fourth quarter of 2009, we acquired 127 shares due to acquisition share exchanges and Ashland share transfers pending at the closing of the transaction.

(c)

The47,835 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”) was temporarily suspended effective December 1, 2008, and remains suspended. No purchases of Marathon common stock to satisfy the requirements for dividend reinvestment were made by the administrator of the Dividend Reinvestment Plan after November 30, 2008. The determinationPlan. Shares needed to suspendmeet the requirements of the Dividend Reinvestment Plan was due toare either purchased in the evaluation of the separation of our businesses as described in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of–Evaluation of Separation of Marathon’s Businesses.open market or issued directly by Marathon.

(d)

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, 2008,2009, 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 share repurchases were made in the fourth quarter ofshares have been repurchased under this program since August 2008.

Index toItem 6. Selected Financial Statements

Data

(Dollars in millions, except as noted)  2009 (a)  2008 (a)(b)  2007 (a)(c)(d)  2006 (a)(e)  2005 (a)(f) 

Statement of Income Data

      

Revenues

  $    53,470   $    76,754   $    64,096   $    64,439   $    62,594  

Income from continuing operations

   1,184    3,384    3,766    4,787    2,853  

Net income

   1,463    3,528    3,956    5,234    3,032  

Per Share Data

      

Basic :

      

Income from continuing operations

  $1.67   $4.77   $5.46   $6.69   $4.01  

Net income

  $2.06   $4.97   $5.73   $7.31   $4.26  

Diluted :

      

Income from continuing operations

  $1.67   $4.75   $5.42   $6.63   $3.97  

Net income

  $2.06   $4.95   $5.69   $7.25   $4.22  

Statement of Cash Flows Data

      

Additions to property, plant and equipment

  $6,231   $6,989    $3,757   $3,325   $2,643  

Dividends paid

   679    681    637    547    436  

Dividends per share

  $0.96   $0.96   $0.92   $0.76   $0.60  

Balance Sheet Data as of December 31:

      

Total assets

  $47,052   $42,686   $42,746   $30,831   $28,498  

Total long-term debt, including capitalized leases

   8,436    7,087    6,084    3,061    3,698  
Item 6.Selected Financial Data

(Dollars in millions, except as noted)  2008(a)  2007(b)(c)  2006  2005(d)  2004

Statement of Income Data:

       

Revenues(e)

  $ 77,193  $64,552  $64,896  $62,986  $49,465

Income from continuing operations

   3,528   3,948   4,957   3,006   1,294

Net income

   3,528   3,956   5,234   3,032   1,261

Basic per share data:

       

Income from continuing operations

  $4.97  $5.72  $6.92  $4.22  $1.92

Net income

  $4.97  $5.73  $7.31  $4.26  $1.87

Diluted per share data:

       

Income from continuing operations

  $4.95  $5.68  $6.87  $4.19  $1.91

Net income

  $4.95  $5.69  $7.25  $4.22  $1.86

Statement of Cash Flows Data:

       

Capital expenditures from continuing operations

  $7,146  $4,466  $3,433  $2,796  $2,141

Dividends paid

   681   637   547   436   348

Dividends per share

  $0.96  $0.92  $0.76  $0.60  $0.51

Balance Sheet Data as of December 31:

       

Total assets

  $ 42,686  $42,746  $30,831  $28,498  $23,423

Total long-term debt, including capitalized leases

   7,087   6,084   3,061   3,698   4,057

(a)

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

(b)

Includes a $1,412 million impairment of goodwill related to the OSM reporting unit, (see Note 1615 to the consolidated financial statements) and a $25 million after-tax impairment ($40 million pretax) related to our investments in ethanol producing companies (see Note 1413 to the consolidated financial statements).

(b)(c)

On October 18, 2007, we completed the acquisition of all the outstanding shares of Western. See Note 6 to the consolidated financial statements.

(c)(d)

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’ capital expenditures subsequent to April 2007 are not included in our capital expenditures. See Note 4 to the consolidated financial statements.

(d)

On June 30, 2005, we acquired the 38 percent ownership interest in MPC previously held by Ashland, making it wholly-owned by Marathon.

(e)

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. See Note 2 to

(f)

On June 30, 2005, we acquired the consolidated financial statements.38 percent ownership interest in MPC previously held by Ashland, making it wholly-owned by Marathon.

Index to Financial Statements
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 the U.S., Canada,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 by-products.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, upper Great Plains, Gulf Coast and southeastern regions of the United States.

Integrated Gas (“IG”) which markets and transports products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol, on a worldwide basis, and is developing other projects to link stranded natural gas resources with key demand areas.

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.

We hold a 60 percent interest in Equatorial Guinea LNG Holdings Limited (“EGHoldings”). As discussed in Note 4 to the consolidated financial statements, effective May 1, 2007, we ceased consolidating EGHoldings. Our investment is accounted for using the equity method of accounting. Unless specifically noted, amounts presented for the Integrated Gas segment for periods prior to May 1, 2007, include amounts related to the minority interests.

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.

Evaluation of Separation of Marathon’s Businesses

On July 31, 2008, we announced that our board of directors would be evaluating the separation of Marathon into two independent, publicly-traded companies, each focused on its own set of business opportunities. On February 3, 2009, we further announced that our board concluded it is in the best interest of our shareholders to remain a fully integrated energy company.

Overview

Exploration and Production

Prevailing prices for the various qualitiesgrades of crude oil and natural gas that we produce significantly impact our revenues and cash flows. Prices were extremely volatile in 2008 with2009, but not as much as in the following table listing high and low spot prices duringprevious year. Prices in 2009 were also lower than in recent years as illustrated by the yearannual averages for key benchmarks.benchmark prices below.

 

Benchmark  High   Date  Low  Date  2009  2008  2007

WTI crude oil (Dollars per barrel)

  $ 145.29 July 3  $33.87  December 19  $62.09  $99.75  $72.41

Brent crude oil(Dollars per barrel)

  $ 144.22 July 3  $33.66  December 24

Dated Brent crude oil (Dollars per barrel)

  $61.67  $97.26  $72.39

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

  $   13.11 July 1  $6.47  November 1  $3.99  $9.04  $6.86

(a)

First-of-month price index.

On average, crude oil prices in 2008 were higher than in 2007. Crude oil prices climbed rapidlyrose sharply through the first half of 2008 based upon expectedas a result of strong global demand, a declining dollar, ongoing concerns about supplies of

Index to Financial Statements

crude oil, and political unrest in the Middle East and elsewhere.geopolitical risk. Later in 2008, crude oil prices dropped more rapidly than they had climbedsharply declined as the U.S. dollar rebounded and other countries entered recessions whichglobal demand decreased demand.

During 2008, the average spotas a result of economic recession. The price per barrel for WTI was $99.75, up from an average of $72.41decrease continued into 2009, but reversed after dropping below $33.98 in 2007, but endedFebruary, ending the year at $44.60. The average spot price per barrel for Brent was $97.26 in 2008, up from an average of $72.39 in 2007, but ended the year at $36.55. The differential between WTI and Brent average prices widened to $2.49 in 2008 from $0.02 in 2007. $79.36.

Our domestic crude oil production is on average heavier and higher inabout 62 percent sour, which means that it contains more sulfur content than light sweet WTI. Heavier and higher sulfurWTI does. Sour crude oil (commonly referredalso tends to as heavy sourbe heavier than light sweet crude oil)oil and sells at a discount to light sweet crude oil.oil because of higher refining costs and lower refined product values. Our international crude oil production is relatively sweet and is generally sold in relation to the Dated Brent crude oil benchmark. The differential between WTI and Dated Brent average prices narrowed to $0.42 in 2009 compared to $2.49 in 2008 and $0.02 in 2007.

Natural gas prices on average were higherlower in 2009 than in 2008 thanand in 2007.2007, with prices in 2008 hitting uniquely high levels. A significant portion of our U.S.natural gas production in the lower 48 states natural gas productionof the U.S. is sold at bid-week prices or first-of-month indices relative to our specific producing areas. The average Henry Hub first-of-month price index was $2.18 per thousand cubic feet (“mcf”) higher in 2008 than the 2007 average. NaturalA large portion of natural gas sales in Alaska are subject to term contracts. Our other major natural gas-producing regions are Europe and Equatorial Guinea, where large portions of our natural gas sales are also subject to term contracts, making realized prices in these areas less volatile. As we sell larger quantities of natural gas from these regions, to the extent that these fixed prices are lower than prevailing prices, our reported average natural gas prices realizations may decrease.

E&P segment income during 2008 was up 57 percent from 2007, with revenue increases tied to these increases in average commodity prices accounting for almost half of the income improvement. Liquid hydrocarbon andbe less than benchmark natural gas sales volumes were also higher in 2008 than 2007.prices.

Oil Sands Mining

Oil Sands Mining segment revenues correlate with prevailing market prices for the various qualities of synthetic crude oil and vacuum gas 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 upgrader. During 2008, our average realized price for synthetic crude oil and vacuum gas oil was $91.90 per barrel, up from 2007, but ended the year at $24.97 per barrel impacted by a heavier yield in December and a seasonal decrease in the value of our heavy output.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 unitPer-unit costs are sensitive to production rates. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian AECO natural gas sales index and crude prices respectively.

The table below shows average benchmark prices that impact both our revenues and variable costs, listing high and low spot prices during the year.costs.

 

Benchmark  High  Date  Low  Date  2009  2008  2007

WTI crude oil(Dollars per barrel)

  $145.29  July 3  $33.87  December 19  $62.09  $99.75  $72.41

Western Canadian Select (Dollars per barrel)(a)

  $114.95  July  $23.18  December  $52.13  $79.59  $49.60

AECO natural gas sales index (Canadian dollars per gigajoule)(b)

  $11.34  July 1  $5.42  September 19

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

  $3.49  $7.74  $6.06

(a)

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

(b)

Alberta Energy Company day ahead index.

Our OSM segment reported income of $258 million for 2008, reflecting synthetic crude oil and vacuum gas oil sales averaging 32 mboepd. Derivative instruments intended to hedge price risk on future sales have impacted revenues in the periods presented, with net gains of $48 million in 2008 and net losses of $53 million in 2007. In the first quarter of 2009, we entered into derivative instruments which effectively offset certain of our open derivative positions.

Refining, Marketing and Transportation

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

Index to Financial Statements

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 an indicator of the impact of price on 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. Posted Light Louisiana Sweet (“LLS”) 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. The following table lists calculated average crack spreads by quarter for the Midwest (Chicago) and Gulf Coast markets in 2008.

Crack spreads

 

(Dollars per barrel)

  1st Qtr  2nd Qtr  3rd Qtr  4th Qtr  2008

Chicago LLS 6-3-2-1

  $0.07  $2.71  $7.81  $2.31  $3.27

US Gulf Coast LLS 6-3-2-1

  $1.39  $1.99  $6.32  ($0.01) $2.45

In addition to the market changes indicated by the crack spreads, 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 mitigate price risk and the cost of purchased products for resale. We process significant amounts of sour crude oil which can enhance our profitability compared to certain of our competitors, as sour crude oil typically can be purchased at a discount to sweet crude oil. Finally, our refining and wholesale marketing gross margin is impacted by changes in manufacturing costs, which are primarily driven by the level of maintenance activities at the refineries and the price of purchased natural gas used for plant fuel.

Our 2008 refining and wholesale marketing gross margin was the key driver of the 43 percent decrease in RM&T segment income when compared to 2007. Our average refining and wholesale marketing gross margin per gallon decreased 37 percent, to 11.66 cents in 2008 from 18.48 cents in 2007, primarily due to the significant and rapid increases in crude oil prices early in 2008 and lagging wholesale price realizations.

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. While on average demand has been increasing for several years, 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. In 2008, demand began to drop due to the combination of significant increases in retail petroleum prices and a broad slowdown in general activity. The gross margin on merchandise sold at retail outlets has historically been more constant.

The profitability of our pipeline transportation operations is primarily dependent on the volumes shipped through our crude oil and refined products pipelines. The volume of crude oil that we transport is directly affected by the supply of, and refiner demand for, crude oil in the markets served directly by our crude oil pipelines. Key factors in this supply and demand balance are the production levels of crude oil by producers, the availability and cost of alternative modes of transportation, and refinery and transportation system maintenance levels. The volume of refined products that we transport is directly affected by the production levels of, and user demand for, refined products in the markets served by our refined product pipelines. In most of our markets, demand for gasoline peaks during the summer and declines during the fall and winter months, whereas distillate demand is more ratable throughout the year. As with crude oil, other transportation alternatives and system maintenance levels influence refined product movements.

Integrated Gas

Our integrated gas strategy is to link stranded natural gas resources with areas where a supply gap is emerging due to declining production and growing demand. 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., Europe and West Africa.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 2009, the gross sales from the plant were 3.9 million metric tonnes, while in 2008, its

Index to Financial Statements

first full year of operations, the plant sold 3.4 million metric tonnes. Our share of sales was 2.1 million tonnes. Industry estimates of 20082009 LNG trade are approximately 175185 million metric tonnes, which is about 25 percent of international natural gas trade.tonnes. More LNG production facilities and tankers are being constructed. The recentwere under construction in 2009. As a result of the sharp worldwide economic downturn isin 2008, continued weak economies are expected to lower natural gas consumption in various countries; therefore, affecting near-term demand for LNG. Long-term LNG supply 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. SalesGross sales of methanol from the plant totaled 960,374 metric tonnes in 2009 and 792,794 metric tonnes in 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. The 20082010 Chemical Markets Associates, Inc.’s World Methanol Analysis predicts estimates world demand for methanol in 2009 will be 43was 41 million metric tonnes. Our plant capacity is 1.1 million, or about 3 percent of total demand. Also included

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.

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 financial resultssame 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. Posted Light Louisiana Sweet (“LLS”) 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 Integrated Gas segmentcrack 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 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 50 percent, 52 percent and 54 percent of our crude oil processed in 2009, 2008 and 2007.

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)  2009  2008  2007

Chicago LLS 6-3-2-1

  $3.52  $3.27  $8.87

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

  $2.54  $2.45  $6.42

Sweet/Sour differential(a)

  $5.82  $11.99  $11.59
(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, associated with ongoing developmentwhich include depreciation.

Manufacturing costs are primarily driven by the cost of integrated gas projects, including natural gas technology research.

Integrated Gas segment incomeenergy used by our refineries and the level of maintenance costs. Planned turnaround and major maintenance activities were completed at our Catlettsburg, Garyville, and Robinson refineries in 2009. We performed turnaround and major maintenance activities at our Robinson, Catlettsburg, Garyville and Canton refineries in 2008 was up 129and at our Catlettsburg, Robinson and St. Paul Park refineries in 2007.

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. Refined product demand increased for several years until 2008 when it decreased due to the combination of significant increases in retail petroleum prices, a broad slowdown in general economic activity, and the impact of increased ethanol blending into gasoline. In 2009 refined product demand continued to decline. For our marketing area, we estimate a gasoline demand decline of about one percent and a distillate demand decline of about 12 percent from 2008 levels. Market demand declines for gasoline and distillates generally reduce the product margin we can realize. We also estimate gasoline and distillate demand in our marketing area decreased about three percent in 2008 compared to 2007 primarily because the LNG production facility in Equatorial Guinea, which commenced operations in May 2007, operated for the full year.levels. The gross margin on merchandise sold at retail outlets has been historically less volatile.

2008 Operating2009 Highlights

E&P Segment

 

We addedRealized exceptional utilization of the Alvheim floating production, storage and offloading (FPSO) vessel, with a record average monthly production rate of 90,000 net proved liquid hydrocarbon and natural gas reserves of 110 million barrels of oil equivalent (“boe”), excluding dispositions of 3 million boe, while producing 137 million boe during 2008. Over the past three years, we have added net proved reserves of 344 million boe, excluding dispositions of 48 million boe, while producing 396 million boe.boepd in October 2009.

 

We completedAchieved first oil from the operated Alvheim/Vilje development offshoreVolund field in Norway with first production from Alvheim in June 2008 and from Vilje in July 2008.ahead of schedule.

 

We completedAwarded 49 percent interest and will serve as operator in the outside-operated NeptuneKumawa block offshore Indonesia.

Announced the Marihone discovery south of the Volund and Alvheim fields offshore Norway.

Progressed Droshky development in deepwaterthe Gulf of Mexico which began producing in July 2008.– currently on schedule and under budget.

 

We drilled a second appraisal well onAnnounced Shenandoah deepwater discovery and leased 16 new blocks in the Droshky prospect in deepwater Gulf of Mexico and received Board approval to develop the prospect.

We announced a successful discovery well on the Gunflint prospect in deepwater Gulf of Mexico.

 

We were awarded 15 blocks at Outer Continental Shelf Lease Sale No. 206,Announced Leda, Oberon and a second Indonesian offshore exploration block.Tebe deepwater discoveries in Angola.

 

We announced the Portia and Dione discoveries on deepwater Angola Block 31, bringing our total discoveries in Angola to 28.Continued Bakken Shale production ramp-up, reaching a year-end rate over 11,000 net boepd.

 

We received government approval to proceedAdded three onshore exploration licenses in Poland with the first development project on Angola Block 31.

The Volund development offshore Norway continues to progress on schedule toward first productionshale gas potential (including one added in late 2009 and will be tied back to the Alvheim infrastructure.January 2010).

RM&TOSM Segment

 

We have completed approximately 75 percent of our Garyville, Louisiana, refinery expansion, which is scheduled to start-upAdded three additional leases in the fourth quarter of 2009.AOSP area in Canada, which increased net proved reserves by 168 mmbbl.

 

We commencedProgressed construction of the Detroit refinery heavy oil upgradingAOSP Phase 1 expansion, with mining operations anticipated in the second half of 2010, and expansion project, with start-up expectedthe upgrader operations anticipated in mid-2012.late 2010 or early 2011.

OSMReserves

 

Expansion 1Added net proved reserves of 674 mmboe, excluding dispositions, of which 603 mmbbl are proved synthetic crude reserves in Canada that were added under the new SEC regulations.

IG Segment

Achieved operational availability of better than 95 percent at the AthabascaEquatorial Guinea liquefied natural gas (“LNG”) facility during 2009.

Refining, Marketing and Transportation Segment

Completed Garyville Major Expansion project and began full integration with the base refinery.

Progressed construction of Detroit Heavy Oil SandsUpgrading Project, (“AOSP”) continueswith completion expected in the second half of 2012.

Increased Speedway SuperAmerica LLC same store gasoline sales volumes and merchandise sales 1.1 and 11.4 percent respectively, compared to proceed on schedule.2008.

Divestitures

 

We soldDisposed of our 50-percent ownershipexploration and production businesses in Ireland.

Sold our operated fields offshore Gabon.

Disposed of certain producing assets in the Permian Basin of New Mexico and Texas.

Announced the sale of an undivided 20 percent outside-operated interest in the Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola, which closed in February 2010.

Consolidated Results of Operations: 2009 compared to 2008

Revenues are summarized in the following table:

(In millions)  2009  2008 

E&P

  $        7,851  $        12,047 

OSM

   667   1,122 

IG

   50   93 

RM&T

   45,530   64,481 
         

Segment revenues

   54,098   77,743 

Elimination of intersegment revenues

   (700  (1,207

Gain on U.K. natural gas contracts

   72   218 
         

Total revenues

  $53,470  $76,754 
         

Items included in both revenues and costs:

   

Consumer excise taxes on petroleum products and merchandise

  $4,924  $5,065 

E&P segment revenues decreased $4,196 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

    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 $455 million from 2008 to 2009. Revenues were impacted by net gains of $12 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

Chicago Spot Unleaded regular gasoline

  $1.68  $2.50

Chicago Spot Ultra-low sulfur diesel

  $1.66  $2.95

U.S. Gulf Coast Spot Unleaded regular gasoline

  $1.64  $2.48

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

  $1.66  $2.93

Sales to related parties decreased in 2009 as a result of the sale of our interest in Pilot Travel Centers LLC (“PTC”) joint ventureduring the fourth quarter of 2008.

Income from equity method investments decreased $467 million in 2009 from 2008 primarily as the result of lower commodity prices on the earnings of many of our equity investees in 2009 and the sale of our equity method investment in PTC during the fourth quarter of 2008.

Net gain on disposal of assets in 2009 includes our gain on the sale of our operated and a $700 million transaction.

Weportion 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. In 2008, we sold our non-core outside-operated assetsinterests (24 percent of Heimdal field, 47 percent

of Vale field and 20 percent of Skirne field) and associated undeveloped acreage in the Heimdal area offshore Norway and our share of the PTC joint venture in 2008.

Cost of revenues decreased $19,117 million from 2008 to 2009. The largest decreases were in the RM&T segment and resulted from lower acquisition costs of crude oil. Acquisition costs for refinery charge and blendstocks and for purchased refined products also decreased. In our other segments, lower commodity prices and the related lower energy costs also contributed to the lower cost of revenues.

Depreciation, depletion and amortization (“DD&A”) increased $494 million in 2009 from 2008. The increase in 2009 primarily relates to higher sales volumes, particularly from the Alvheim/Vilje development offshore Norway and the Neptune development in the Gulf of Mexico, both of which commenced production mid-year 2008.

Goodwill impairment expense of $1,412 million in 2008 relates to our OSM reporting unit. There were no such impairments in 2009. See Note 15 to the consolidated financial statements for further information about the impairment.

Net interest and other financial costs increased $121 million from 2008 to 2009. Interest income decreased due to substantially lower interest rates, although average cash balances were higher in 2009. While interest expense increased due to the February 2009 issuance of $1.5 billion in senior notes, increased capitalized interest related to our capital projects offset the impact. We recorded a writeoff of a portion of the contingent proceeds from the sale of $301 million.the Corrib natural gas development (see Note 7 to the consolidated financial statements) in the fourth quarter of 2009 by $70 million on the basis of new public information regarding the pipeline that would transport gas from the Corrib development.

Provision for income taxes decreased $1,110 million from 2008 to 2009 primarily due to the reduction in pretax income. The effective rate, however, increased from 50 percent in 2008 to 66 percent in 2009. 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 2008. Also contributing to the increase in the effective tax rate is the remeasurement of foreign currency denominated tax balances to U.S. dollars. In 2009 the remeasurement provided a $319 million tax charge compared to a $249 million tax benefit in 2008. See Note 11 to the consolidated financial statements.

Discontinued operationsreflect the current year 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 Note 7 to the consolidated financial statements.

Segment Results: 2009 compared to 2008

Segment incomefor 2009 and 2008 is summarized and reconciled to net income in the following table.

 

(In millions)  2009  2008 

E&P

   

United States

  $55  $869 

International

   1,166   1,687 
         

E&P segment

   1,221   2,556 

OSM

   44   258 

IG

   90   302 

RM&T

   464   1,179 
         

Segment income

   1,819   4,295 

Items not allocated to segments, net of income taxes:

   

Corporate and other unallocated items

   (422  (75

Foreign currency effects on tax balances

   (319  249 

Impairments(a)

   (45  (1,437

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

   37   111 

Gain on disposal of assets

   114   241 

Discontinued operations

   279   144 
         

Net income

  $1,463  $3,528 
(a)

Impairments in 2009 reflect $45 million ($70 million pretax) writeoff of a portion of the contingent proceeds from the sale of the Corrib natural gas development (see Note 7 to the consolidated financial statements) that was recorded the fourth quarter of 2009 on the basis of new public information regarding the pipeline that would transport gas from the Corrib development. Impairments in 2008 include a $1,412 million impairment of goodwill related to the OSM reporting unit (see Note 15 to the consolidated financial statements) and a $25 million after-tax impairment ($40 million pretax) related to our investments in ethanol producing facilities (see Note 13 to the consolidated financial statements).

(b)

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

United States E&P income decreased $814 million, or 94 percent, from 2008 to 2009. The majority of the income decrease was due to liquid hydrocarbon and natural gas realizations averaging almost 40 percent lower than in 2008, as well as lower natural gas sales volumes and higher DD&A, partially offset by lower operating costs and exploration expenses. Exploration expenses were $153 million for the year 2009, compared to $238 million for 2008, reflecting decreased geological and geophysical spending and lower exploration dry well expense.

International E&P income decreased $521 million, or 31 percent, from 2008 to 2009. The majority of the income decrease is tied to lower liquid hydrocarbon and natural gas realizations and overall higher DD&A, primarily associated with a full year of Alvheim production. The revenue impact of lower realizations was partially offset by improved sales volumes from Norway and Equatorial Guinea. Additionally, operating costs and exploration expenses were lower. Exploration expenses were $154 million for the full year 2009, compared to $251 million for 2008, reflecting lower dry well expense and decreased geological and geophysical spending.

OSM segment income decreased $214 million, or 83 percent, from 2008 to 2009. The majority of the decrease in income for 2009 was due to synthetic crude oil realizations averaging almost 40 percent lower than in 2008, partially offset by lower blendstock and energy costs. Results for 2008 included after-tax gains on crude oil derivative instruments of $32 million, while the impact of derivatives on the 2009 periods was not significant. Those derivative instruments expired December 2009 (see Item 7A. Quantitative and Qualitative Disclosures about Market Risk).

IG segment income decreased $212 million, or 70 percent, from 2008 to 2009. The decrease in income was primarily the result of lower realizations for LNG and methanol. As evidenced by higher sales volumes, strong operational reliability at the EG LNG facility throughout 2009 partially offset the impact of lower prices. The LNG production facility averaged higher than 95 percent operational availability during 2009. We hold a 60 percent interest in the facility.

RM&T segment income decreased $715 million, or 61 percent, from 2008 to 2009, primarily as a result of the decrease in our refining and wholesale marketing gross margin per gallon from 11.66 cents in 2008 to 6.10 cents in 2009. The gross margin decline is a result of a 52 percent narrowing of the sweet/sour differential, thereby increasing the relative cost of crude processed by our refineries. The narrowing of the sweet/sour differential resulted from a variety of worldwide economic and petroleum industry related factors primarily related to lower hydrocarbon demand.

Included in the refining and wholesale marketing gross margins were pretax derivative losses of $83 million in 2009 and $87 million in 2008. 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.

We reached an agreementaveraged 957 mbpd of crude oil throughput in 2009 and 944 mbpd in 2008. Total refinery throughputs averaged 1,153 mbpd in 2009 compared to sell1,151 mbpd in 2008. Crude and total throughputs were lower in 2008 than in 2009 in part due to the impact that hurricanes and other weather related events had on our producing assetsoperations in Ireland.

2008.

Index to Financial Statements
The following table includes certain key operating statistics for the RM&T segment for 2009 and 2008.

RM&T Operating Statistics  2009  2008

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

  $0.0610    $0.1166

Refined products sales volumes(Thousands of barrels per day)

   1,378      1,352
(a)

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

Consolidated Results of Operations: 2008 compared to 2007

Revenuesare summarized in the following table.

 

(In millions)  2008 2007   2008 2007 

E&P

  $12,486  $9,155   $12,047  $8,699 

OSM

   1,122   221    1,122   221 

IG

   93   218 

RM&T

   64,481   56,075    64,481   56,075 

IG

   93   218 
              

Segment revenues

   78,182   65,669    77,743   65,213 
       

Elimination of intersegment revenues

   (1,207)  (885)   (1,207  (885

Gain (loss) on U.K. gas contracts

   218   (232)

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

   218   (232
              

Total revenues

  $77,193  $64,552   $76,754  $64,096 
              

Items included in both revenue and costs and expenses:

   

Items included in both revenues and costs:

   

Consumer excise taxes on petroleum products and merchandise

  $5,065  $5,163   $5,065  $5,163 

E&P segment revenues increased $3,331$3,348 million in 2008 from 2007.2007 to 2008. Higher average liquid hydrocarbon and natural gas realizations account for over 70 percent of the revenue increase. Liquid hydrocarbon and natural gas sales volumes were also higher in 2008 than 2007. Sales volumes also benefited from a full year of natural gas sales to the Equatorial Guinea LNG production facility, which we co-own. Beginning mid-year, both the Alvheim/Vilje development offshore Norway and the Neptune development in the Gulf of Mexico contributed particularly to the liquid hydrocarbon sales increase. 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. 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.

Index to Financial Statements
  2008  2007
E&P Operating Statistics  2008  2007    

Net Liquid Hydrocarbon Sales(Thousands of barrels per day)(a)

    

United States

   63   64

Europe(b)

   55   33

Africa(b)

   93   100
      

Total International(b)

   148   133
      

WORLDWIDE

   211   197

Net Natural Gas Sales(Millions of cubic feet per day)(c)(d)

    

Net Liquid Hydrocarbon Sales (mbpd)(a)

    

United States

   448   477  63  64

Europe

   198   216  55  33

Africa

   370   232  87  90
            

Total International

   568   448  142  123
            

WORLDWIDE

   1,016   925

Worldwide Continuing Operations

  205  187

Discontinued Operations(b)

  6  10
      

Total Worldwide Sales(Thousands of barrels of oil equivalent per day)

   381   351

Worldwide

  211  197

Natural Gas Sales (mmcfd)

    

United States

  448  477

Europe(c)

  161  177

Africa

  370  232
      

Average Realizations(e)

    

Liquid Hydrocarbons(Dollars per barrel)

    

United States

  $86.68  $60.15

Europe

   90.60   70.31

Africa

   90.29   66.09

Total International

   90.40   67.15  531  409

WORLDWIDE

  $89.29  $64.86

Natural Gas(Dollars per thousand cubic feet)

    

United States

  $7.01  $5.73

Europe

   8.03   6.53

Africa

   0.25   0.25

Total International

   2.97   3.28

WORLDWIDE

  $4.75  $4.54
      

Worldwide Continuing Operations

  979  886

Discontinued Operations(b)

  37  39
      

Worldwide

  1,016  925

Total Worldwide Sales (mboepd)

    

Continuing Operations

  369  334

Discontinued Operations(b)

  12  17
      

Worldwide

  381  351

    2008  2007

E&P Operating Statistics

    

Average Realizations(d)

    

Liquid Hydrocarbons (per bbl)

    

United States

  $86.68  $60.15

Europe

   90.60   70.31

Africa

   89.85   65.41

Total International

   90.14   66.74

Worldwide Continuing Operations

   89.07   64.47

Discontinued Operations(b)

   96.41   72.19

Worldwide

  $89.29  $64.86

Natural Gas (per mcf)

    

United States

  $7.01  $5.73

Europe

   7.67   6.49

Africa

   0.25   0.25

Total International

   2.50   2.96

Worldwide Continuing Operations

   4.56   4.45

Discontinued Operations(b)

   9.62   6.71

Worldwide

  $4.75  $4.54

(a)

Includes crude oil, condensate and natural gas liquids.

(b)

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

(c)(b)

Represents net sales after royalties, except forOur businesses in Ireland where amounts are before royalties.and Gabon were sold in 2009. All periods have been recast to reflect these businesses as discontinued operations.

(d)(c)

Includes natural gas acquired for injection and subsequent resale of 32 mmcfd and 47 mmcfd in 2008 and 2007.

(e)(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 $22 million in 2008 and losses of $15 million in 2007. Excluded from E&P segment revenues were gains of $218 million in 2008 and losses of $232 million in 2007 related to natural gas sales contracts in the United KingdomU.K. that arewere accounted for as derivative instruments.

OSM segment revenues totaled $1,122increased $901 million infrom 2007 to 2008, and $221 million in 2007, reflecting a full year of operations in 2008. Revenues were impacted by net gains in 2008 and net losses in 2007 on derivative instruments, which expire

December 2009, that were held by Western at the acquisition date and intended to mitigate price risk related to future sales of synthetic crude oil. The 2008 net gain of $48 million included realized losses of $72 million and unrealized gains of $120 million, while less than $1 million of the $53 million net loss in 2007 was realized. Additionally, revenues were negatively impacted by reliability issues and the implementation of a revised tailings management plan that impacted ore grade. Sales of synthetic crude oil averaged 32 mbpd at an average realized price of $91.90 per barrel compared to a $71.07 average realized price for the period from the October 18, 2007, acquisition date through December of 2007.

RM&T segment revenues increased $8,406 million in 2008 from 2007.2007 to 2008. Higher refined product selling prices were realized in 2008, but lower sales volumes partially offset the price impact.

Income from equity method investments increased $220 million in 2008 from 2007.2007 to 2008. The Equatorial Guinea LNG production facility operated for the full year of 2008, accounting for most of the increased income, with 54 cargoes delivered in 2008 compared to 24 in 2007. In addition, there was an $81 million increase in PTC income due to higher retail margins. Offsetting these increases was the $40 million pretax impairment of our equity investment in two ethanol production facilities, losses generated by one of those facilities and lower income from AMPCO. AMPCO sales volumes and realized prices were lower in 2008 due to temporary reductions in available feedstock gas and plant reliability problems.

Index to Financial Statements

Net gain on disposal of assets increased $387 million as a result of the review of our portfolio of assets that commenced in 2008. We sold our outside-operated interests (24 percent of Heimdal field, 47 percent of Vale field and 20 percent of Skirne field) and associated undeveloped acreage in offshore Norway and our share of the PTC joint venture in 2008. Property sales in 2007, primarily related to sales of individual producing properties and retail outlets were not significant.

Cost of revenues increased $10,713$10,548 million in 2008 from 2007.2007 to 2008. The increases were primarily in the RM&T segment and resulted from increases in acquisition costs of crude oil. Acquisition costs for refinery charge and blendstocks and for purchased refined products also increased, but the impact of this increase was partially offset by the impact of lower refinery throughput.

Depreciation, depletion and amortization (“DD&A”) increased $565 million in 2008 from 2007. The increase in 2008 primarily relates to new assets. Our oil sands assets operated for the full year of 2008 and two significant offshore developments, Alvheim/Vilje offshore Norway and Neptune in the Gulf of Mexico, began operating at mid-year.

Goodwill impairment expense of $1,412 million relates to our OSM reporting unit. During the fourth quarter of 2008, we tested our OSM reporting unit’s goodwill for impairment and upon allocating fair value among the reporting unit’s assets, there was no remaining implied fair value of goodwill as of December 31, 2008. See Note 1615 to the consolidated financial statements for further information about the impairment.

Net interest and other financial income or costs reflected $50$28 million in costs for 2008 and $41$33 million of income for 2007, an unfavorable change of $91 million from 2007. Interest income decreased due to lower interest rates and average cash balances during 2008. While interest expense also increased due to a higher level of short-term commercial paper borrowings throughout 2008 a similar increase in capitalized interest related to our capital projects offset the impact.

Gain on foreign currency derivative instruments in 2007 represented gains on foreign currency derivative instruments entered to limit our exposure to changes in the Canadian dollar exchange rate related to the cash portion of the purchase price for Western. These derivative instruments were settled on October 17, 2007.

Provision for income taxes increased $544$565 million in 2008 from 2007 to 2008, a 1920 percent increase, although income from continuing operations before income taxes increased only $124$183 million, or 23 percent. The effective tax rate in 2008 was impacted by the goodwill impairment which cannot be deducted for purposes of calculating income tax. The consolidated effective tax rate was also influenced by the geographical mix of income and related tax expense. Partially offsetting the effective tax rate increase caused by the goodwill impairment and income mix were benefits related to the reversal of the valuation allowance on the Norwegian net operating loss carryforwards and a $252$249 million benefit from the remeasurement of foreign currency denominated deferred taxes to U.S. dollars. The following is an analysis of the effective income tax rates for continuing operations for 2008 and 2007.balances. See Note 1211 to the consolidated financial statements.

Discontinued operations reflect the current year disposal of our E&P businesses in Ireland and Gabon (see Note 7) and the historical results of those operations, net of tax, for all periods presented.

    2008  2007 

Statutory U.S. income tax rate

  35.0% 35.0%

Effects of foreign operations, including foreign tax credits

  16.7  9.8 

Effects of nondeductible goodwill impairment

  7.1   

Adjustments to valuation allowances

  (9.6)  

State and local income taxes, net of federal income tax effects

  1.3  2.0 

Effects of enacted changes in tax laws

    (2.8)

Other tax effects

  (1.1) (1.6)
       

Effective income tax rate for continuing operations

  49.4% 42.4%

Index to Financial Statements

Segment Results: 2008 compared to 2007

Segment income or lossfor 2008 and 2007 is summarized and reconciled to net income in the following table.

 

(In millions)  2008 2007   2008 2007 

E&P

      

United States

  $869  $623   $869  $623 

International

   1,846   1,106    1,687   929 
              

E&P segment income

   2,715   1,729 

E&P segment

   2,556   1,552 

OSM

   258   (63)   258   (63

IG

   302   132 

RM&T

   1,179   2,077    1,179   2,077 

IG

   302   132 
              

Segment income

   4,454   3,875    4,295   3,698 

Items not allocated to segments, net of income taxes:

      

Corporate and other unallocated items

   (93)  (122)   (75  (128

Gain (loss) on U.K. natural gas contracts(a)

   111   (118)

Foreign currency gain on income taxes

   252   18 

Impairments(b)

   (1,437)   

Gain on dispositions

   241   8 

Foreign currency effects on tax balances

   249   19 

Impairments(a)

   (1,437  -    

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

   111   (118

Gain on disposal of assets

   241   -    

Gain on foreign currency derivative instruments

      112    -      112 

Deferred income taxes – tax legislation changes

      193 

Deferred income taxes-tax legislation changes

   -      193 

Loss on early extinguishment of debt

      (10)   -      (10

Discontinued operations

   144   190 
              

Net income

  $3,528  $3,956   $3,528  $3,956 

(a)

Amounts relate to natural gas contracts in the United Kingdom that are accounted for as derivative instruments and recorded at fair value. See Critical Accounting Estimates – Fair Value Estimates.

(b)

Impairments in 2008 include a $1,412 million impairment of goodwill related to the OSM reporting unit (see Note 1615 to the consolidated financial statements) and a $25 million after-tax impairment ($40 million pretax) related to our investments in ethanol producing facilities (see Note 1413 to the consolidated financial statements).

(b)

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

United States E&P incomeincreased $246 million, or 39 percent, in 2008 from 2007.2007 to 2008. The majority of the increase from year to year was due to overall higher average liquid hydrocarbon and natural gas realizations with relatively flat sales volumes. Partially offsetting the benefits of higher prices were increases in production taxes, operating expenses, DD&A and income taxes. Exploration expenses were $238 million for 2008, lower than $274 million in 2007.

International E&P income increased $740$758 million, or 6782 percent, in 2008 from 2007 to 2008 primarily due to higher average liquid hydrocarbon realizations and higher sales volumes for both liquid hydrocarbons and natural gas. Natural gas realizations were slightly lower because a significant portion of the natural gas sales volume increase related to that sold in Equatorial Guinea to the LNG production facility at a fixed price. Operating expenses and DD&A, associated with production from new developments, and income taxes also increased during 2008.

OSM segment income reported income of $258 million in 2008 as compared to a loss of $63 million in 2007. An after-tax gain on crude oil derivative instruments of $32 million was included in 2008 income while an after-tax loss of $40 million was recorded in 2007 (see Item 7A. Quantitative and Qualitative Disclosures about Market Risk). Results for 2008 include a full year of operations in comparison to two and one-half months of operation in 2007. Bitumen was produced at an average rate of 25 mbpd in 2008. Production and processing levels were adversely impacted by planned and unplanned maintenance, reliability issues and the implementation of a revised tailings management plan that impacted ore grade, which also increased operating costs.

RM&T segment income decreased $898 million in 2008 from 2007, primarily a result of a decrease in our refining and wholesale marketing gross margin per gallon from 18.48 cents in 2007 to 11.66 cents in 2008. The refining and wholesale marketing gross margin decline was consistent with the market indicators (crack spreads) in the Midwest and Gulf Coast regions. In addition, manufacturing expenses were higher in 2008 due primarily to higher energy costs and maintenance activities.

Included in the refining and wholesale marketing gross margins were pretax derivative losses of $87 million in 2008 and $899 million in 2007. The variance primarily reflects falling crude futures prices in the second half of 2008, as well as the fact that we no longer use derivatives to mitigate domestic crude oil acquisition price risk. For

Index to Financial Statements

a more complete explanation of our strategies to manage market risk related to commodity prices, see Quantitative and Qualitative Disclosures about Market Risk.

We averaged 944 mbpd of crude oil throughput in 2008 and 1,010 mbpd in 2007. Total refinery throughputs averaged 1,151 mbpd in 2008 compared to 1,224 mbpd in 2007. Crude and total throughputs were lower in 2008 than in 2007 in part due to the effect Hurricane Gustav and Ike had on U.S. Gulf Coast operations in 2008.

The following table includes certain key operating statistics for the RM&T segment for 2008 and 2007.

RM&T Operating Statistics  2008  2007

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

  $0.1166  $0.1848

Refined products sales volumes(Thousands of barrels per day)

   1,352   1,410

(a)

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

IG segment income increased $170 million, or 129 percent, in 2008 from 2007. The increase in income was primarily related to a full year of operation of the LNG production facility in Equatorial Guinea, which commenced operations in May 2007. We hold a 60 percent interest in the facility. Segment expenses increased slightly in 2008 as we continue to develop new technologies. In 2008, we spent $92 million on gas commercialization technologies, including completing construction of a gas-to-fuelsGas-To-Fuels™ demonstration plant. Such expense in 2007 was $42 million.

Consolidated Results of Operations: 2007 compared to 2006

Revenues are summarized in the following table.

(In millions)  2007  2006 

E&P

  $9,155  $9,010 

OSM

   221    

RM&T

   56,075   55,941 

IG

   218   179 
         

Segment revenues

   65,669   65,130 

Elimination of intersegment revenues

   (885)  (688)

Gain (loss) on long-term U.K. gas contracts

   (232)  454 
         

Total revenues

  $64,552  $64,896 
         

Items included in both revenue and costs and expenses:

   

Consumer excise taxes on petroleum products and merchandise

  $5,163  $4,979 

Matching crude oil and refined product buy/sell transactions settled in cash:

   

E&P

      16 

RM&T

   127   5,441 
         

Total buy/sell transactions included in revenues

  $127  $5,457 

E&P segment revenues increased $145 million in 2007 from 2006. The 2007 increase was primarily related to increased international crude oil marketing activities. Higher liquid hydrocarbon realized prices were not sufficient to offset the impact of sales volume declines as illustrated in the table below. Both liquid hydrocarbon and natural gas sales volumes from domestic operations decreased in 2007 primarily due to normal production declines in the Gulf of Mexico and Permian Basin, while international liquid hydrocarbon sales volumes were lower primarily because our Libya sales returned to normal levels compared to 2006, which included volumes owed to our account upon the resumption of our operations there. While international natural gas sales volumes increased, the majority of the increase was due sales to EGHoldings LNG production facility in Equatorial Guinea that began operations in the second quarter of 2007. This increase in fixed-price sales volumes also contributed to the decline in our average international natural gas realizations. 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.

Index to Financial Statements
E&P Operating Statistics  2007  2006

Net Liquid Hydrocarbon Sales(Thousands of barrels per day)(a)

    

United States

   64   76

Europe(b)

   33   35

Africa(b)

   100   112
        

Total International(b)

   133   147
        

Worldwide Continuing Operations

   197   223

Discontinued Operations(c)

      12
        

WORLDWIDE

   197   235

Net Natural Gas Sales(Millions of cubic feet per day)(d)(e)

    

United States

   477   532

Europe

   216   243

Africa

   232   72
        

Total International

   448   315
        

WORLDWIDE

   925   847

Total Worldwide Sales(Thousands of barrels of oil equivalent per day)

    

Continuing Operations

   351   365

Discontinued Operations

      12
        

WORLDWIDE

   351   377

Average Realizations(f)

    

Liquid Hydrocarbons(Dollars per barrel)

    

United States

  $60.15  $54.41

Europe

   70.31   64.02

Africa

   66.09   59.83

Total International

   67.15   60.81

Worldwide Continuing Operations

   64.86   58.63

Discontinued Operations

      38.38

WORLDWIDE

  $64.86  $57.58

Natural Gas(Dollars per thousand cubic feet)

    

United States

  $5.73  $5.76

Europe

   6.53   6.74

Africa

   0.25   0.27

Total International

   3.28   5.27

WORLDWIDE

  $4.54  $5.58

(a)

Includes crude oil, condensate and natural gas liquids.

(b)

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

(c)

Represents our Russian oil exploration and production businesses that were sold in June 2006.

(d)

Represents net sales after royalties, except for Ireland where amounts are before royalties.

(e)

Includes natural gas acquired for injection and subsequent resale of 47 mmcfd and 46 mmcfd in 2007 and 2006.

(f)

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 $15 million in 2007 and gains of $25 million in 2006. Excluded from E&P segment revenues were losses of $232 million in 2007 and gains of $454 million in 2006 related to natural gas sales contracts in the United Kingdom that are accounted for as derivative instruments. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

OSM segment revenues totaled $221 million in 2007, reflecting sales for the period subsequent to the October 18, 2007, Western acquisition date. Revenues during this period were reduced by $53 million of unrealized losses on derivative instruments held by Western at the acquisition date intended to mitigate price risk related to future sales of synthetic crude oil. Revenues were also negatively impacted by a mid-November fire and the subsequent curtailment of operations at the Scotford upgrader. Maintenance work originally scheduled for the first quarter of 2008 was performed in conjunction with the necessary repairs. The Scotford upgrader returned to operation in late December.

RM&T segment revenues increased $134 million in 2007 from 2006, while the portion related to matching buy/sell transactions decreased $5,314 million. Matching buy/sell transactions arise from arrangements in which we agree to buy a specified quantity and quality of crude oil or refined product to be delivered to a specified location

Index to Financial Statements

while simultaneously agreeing to sell a specified quantity and quality of the same commodity at a specified location to the same counterparty. Prior to April 1, 2006, all matching buy/sell transactions were recorded as separate sale and purchase transactions, or on a “gross” basis. For contracts entered into on or after April 1, 2006, the income effects of matching buy/sell transactions are reported in cost of revenues, or on a “net” basis. Transactions under contracts entered into before April 1, 2006 continued to be reported on a “gross” basis until their termination. This accounting change had no effect on net or segment income but the amounts of revenues and cost of revenues recognized after April 1, 2006 are less than the amounts that would have been recognized under previous accounting practices.

The decrease in revenues from matching buy/sell transactions was a result of the change in accounting for these transactions effective April 1, 2006, discussed above. Excluding matching buy/sell transactions, 2007 revenues increased primarily as a result of higher refined product prices.

Income from equity method investments increased $154 million in 2007 from 2006. Income from the LNG production facility in Equatorial Guinea accounts for most of the increase for 2007, as it began operations in May 2007 and delivered 24 cargoes during the year.

Cost of revenues increased $6,689 million in 2007 from 2006. The increase was primarily in the RM&T segment and resulted from increases in acquisition costs of crude oil, refinery charge and blendstocks and purchased refined products. The increase was also impacted by higher manufacturing expenses, primarily planned maintenance projects, or turnarounds, in 2007.

Purchases related to matching buy/sell transactions decreased $5,247 million in 2007 from 2006 as a result of the change in accounting for matching buy/sell transactions discussed above.

Depreciation, depletion and amortization increased $95 million in 2007 from 2006. The increase in 2007 primarily relates to the addition of the Oil Sands Mining assets recorded as a result of the Western acquisition, increased accretion of asset retirement obligations associated with international E&P properties and increased depreciation related to various refinery improvements in 2006 and 2007, such as our low-sulfur diesel projects.

Selling, general and administrative expenses increased $99 million in 2007 from 2006. The 2007 expense increases were primarily because personnel and staffing costs increased throughout the year as a result of variable compensation arrangements and increased business activity. Contingency accruals also contributed to the 2007 increase.

Exploration expenses increased $89 million in 2007 from 2006. Exploration expenses related to dry wells and other write-offs totaled $233 million and $166 million in 2007 and 2006.

Net interest and other financial income or costs reflected $41 million of income for 2007, a favorable change of $4 million from 2006. Included in net interest and other financial income or costs were foreign currency transaction gains of $2 million and $16 million for 2007 and 2006.

Gain on foreign currency derivative instruments in 2007 represents gains on foreign currency derivative instruments entered to limit our exposure to changes in the Canadian dollar exchange rate related to the cash portion of the purchase price for Western. These derivative instruments were settled on October 17, 2007.

Provision for income taxes decreased $1,121 million in 2007 from 2006 primarily due to the $2,130 million decrease in income from continuing operations before income taxes. The decrease in our effective income tax rate in 2007 was primarily a result of the $193 million benefit of applying the Canadian income tax rate reductions enacted subsequent to our acquisition of Western to the applicable net deferred tax liabilities. These tax rates will decrease from 32 percent to 25 percent by 2012. The following is an analysis of the effective income tax rates for continuing operations for 2007 and 2006. See Note 12 to the consolidated financial statements.

    2007  2006 

Statutory U.S. income tax rate

  35.0% 35.0%

Effects of foreign operations, including foreign tax credits

  9.8  10.1 

State and local income taxes, net of federal income tax effects

  2.0  1.9 

Effects of enacted changes in tax laws

  (2.8) (0.2)

Other tax effects

  (1.6) (2.0)
       

Effective income tax rate for continuing operations

  42.4% 44.8%

Index to Financial Statements

Discontinued operationsrelated to the exploration and production businesses which were sold in June 2006. After-tax gains on the disposal of $8 million and $243 million were also included in discontinued operations for 2007 and 2006. See Note 8 to the consolidated financial statements.

Segment Results: 2007 compared to 2006

As discussed in Note 8 to the consolidated financial statements, we sold our Russian oil exploration and production businesses during 2006. The activities of these operations have been reported as discontinued operations and therefore are excluded from segment results for all periods presented.

Segment income or lossfor 2007 and 2006 is summarized and reconciled to net income in the following table.

(In millions)  2007  2006 

E&P

   

United States

  $623  $873 

International

   1,106   1,130 
         

E&P segment income

   1,729   2,003 

OSM

   (63)   

RM&T

   2,077   2,795 

IG

   132   16 
         

Segment income

   3,875   4,814 

Items not allocated to segments, net of income taxes:

   

Corporate and other unallocated items

   (122)  (190)

Gain (loss) on U.K. natural gas contracts(a)

   (118)  232 

Foreign currency gain (loss) on income taxes

   18   (22)

Gain on dispositions

   8   274 

Gain on foreign currency derivative instruments

   112    

Deferred income taxes – tax legislation changes

   193   21 

                                              – other adjustments(b)

      93 

Loss on early extinguishment of debt

   (10)  (22)

Discontinued operations

      34 
         

Net income

  $3,956  $5,234 

(a)

Amounts relate to natural gas contracts in the United Kingdom that are accounted for as derivative instruments and recorded at fair value. See Critical Accounting Estimates – Fair Value Estimates.

(b)

Other deferred tax adjustments in 2006 represent a benefit recorded for cumulative income tax basis differences associated with prior periods.

United States E&P incomedecreased $250 million, or 29 percent, in 2007 from 2006. The decrease was primarily due to the revenue decline discussed above. In addition, exploration expenses were $105 million higher in 2007 than in 2006, primarily as a result of expensing non-commercial wells on the Flathead prospect in the Gulf of Mexico in 2007.

International E&P income decreased $24 million in 2007 from 2006. The revenue decrease associated with lower liquid hydrocarbon sales volumes discussed above had the most significant impact on pretax income.

OSM segment losstotaled $63 million in 2007, reflecting results for the period subsequent to the October 18, 2007, Western acquisition date. This loss includes a $40 million after-tax unrealized loss on derivative instruments held by Western at the acquisition date intended to mitigate price risk related to future sales of synthetic crude oil. Segment income was also impacted by a mid-November fire and subsequent curtailment of operations at the Scotford upgrader. Maintenance work originally scheduled for the first quarter of 2008 was performed in conjunction with the necessary repairs. The Scotford upgrader returned to operation in late December.

RM&T segment income decreased $718$898 million infrom 2007 from 2006,to 2008 primarily a result of a decrease in our refining and wholesale marketing gross margin per gallon from 22.88 cents in 2006 to 18.48 cents in 2007. Though the market-based crack spreads for 2007 were stronger thanto 11.66 cents in 2006, our 2008. The

refining and wholesale marketing gross margin declined primarily due todecline was consistent with the significantmarket indicators (crack spreads) in the Midwest and rapid increase in our crude oil costs during 2007, including the impact of derivatives, and lagging wholesale price realizations. Our refining and marketing wholesale gross margin was further reduced by higher manufacturing costs related to planned maintenance at several refineries.Gulf Coast regions. In addition, manufacturing expenses were higher in 2008 due primarily to the lower refininghigher energy costs and wholesale gross margin, segment income was impacted by higher operating and administrative expenses.maintenance activities.

Index to Financial Statements

Included in the refining and wholesale marketing gross margins were pretax derivative losses of $87 million in 2008 and $899 million in 2007 and gains2007. The variance primarily reflects falling crude futures prices in the second half of $400 million in 2006.2008, as well as the fact that we reduced our use of derivatives to manage domestic crude oil acquisition price risk. 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.

We averaged 1,010944 mbpd of crude oil throughput in 20072008 and 9801,010 mbpd in 2006. Our reported crude oil refining capacity increased to 1,0162007. Total refinery throughputs averaged 1,151 mbpd in 2007 from 9742008 compared to 1,224 mbpd in 20062007. Crude and total throughputs were lower in 2008 than in 2007 in part due to overall efficiency gains in the operation of the refining units, reflecting the cumulative effect of regular maintenance, capital improvementsimpact hurricanes and other process optimization efforts.weather related events had on our operations in 2008.

The following table includes certain key operating statistics for the RM&T segment for 20072008 and 2006.2007.

 

RM&T Operating Statistics  2007  2006  2008  2007

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

  $0.1848  $0.2288  $0.1166  $0.1848

Refined products sales volumes(Thousands of barrels per day)

   1,410   1,425   1,352   1,410

(a)

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

IG segment income increased $116 million in 2007 from 2006. During 2007, construction of the LNG production facility in Equatorial Guinea was completed ahead of schedule and on budget. The increase in 2007 segment income over the previous year was largely due to the facility beginning operations in May 2007 and delivering 24 cargoes during the year. Additionally, income from our equity method investment in AMPCO was higher in 2007 on increased methanol production due to plant downtime in 2006 and higher realized prices in 2007. In 2006, a $17 million pretax loss was recognized as a result of the renegotiation of a technology agreement and income from our equity method investment in AMPCO was lower due to plant downtime during a planned turnaround and subsequent compressor repair.

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

Cash Flows

Net cash provided from operating activitiestotaled $6,782$5,268 million in 2009 compared to $6,752 million in 2008 compared to $6,521and $5,900 million in 2007 and $5,4882007. The $1,484 million decrease in 2006.2009 reflects the impact of lower average realized prices in 2009. The $261$852 million increase in 2008 primarily reflects the impact of higher average realized prices. The $1,033 million increaseprices in 2007 primarily reflects working capital changes partially offset by lower net income.2008.

Net cash used in investing activities totaled $5,435$5,238 million in 2009, compared with $5,405 million in 2008 compared with $8,102and $7,481 million in 2007 and $2,955 million in 2006.2007. Significant investing activities include capital expenditures, acquisitionsadditions to property, plant and equipment, asset disposals and an acquisition of businessesa business in 2007.

The most significant additions to property, plant and asset disposals.

Capital expenditures by segment for continuing operations for each of the last three years are summarized in the following table.

(In millions)  2008  2007  2006

E&P

      

United States

  $2,036  $1,354  $1,302

International

   1,077   1,157   867
            

Total E&P

   3,113   2,511   2,169

OSM

   1,038   165   

RM&T

   2,954   1,640   916

IG

   4   93   307

Corporate

   37   57   41
            

Total

  $7,146  $4,466  $3,433

Capital expenditures for multiple years are impacted by the following projects.equipment relate to our long-term projects, which cross several years. In our E&P segment, exploration and development projects in Angola impacted all three years. Development and completion of the Alvheim/Vilje project affected our capital expenditures in 2006, 2007 and to a lesser extent2008, with other developments in 2008. Similarly, our Angolathe area in 2009. Beginning in 2008, spending on U.S. exploration and development projects impacted all three years.in the Gulf of Mexico and unconventional resource plays became a more significant portion of our additions to property, plant and equipment. In the OSM segment, the AOSP Expansion 1 began in 2008 and continued through 2009. In our RM&T segment, the expansion of our Garyville, Louisiana, refinery commenced with front-end engineering and design (“FEED”) in 2006 followed by construction in 2007 and 2008.affected all years. Also in RM&T, the expansion and upgrading

Index to Financial Statements

of our Detroit, Michigan refinery commenced with FEEDfront-end engineering and design work in 2007 and construction in 2008. Integrated gas spending2008 and 2009.

We have revised prior year amounts of capital expenditures in 2006 and through May 2007 reflects the completionconsolidated statement of the LNG production facility in Equatorial Guinea.

New capital spending in 2008 was primarily relatedcash flows. The consolidated statements of cash flows excludes changes to the ongoing AOSP Expansion 1 inconsolidated balance sheets that did not affect cash. A reconciliation of this amount to the OSM segment, and in U.S. exploration and development projects primarily in the Gulf of Mexico.reported capital expenditures follows for all years presented:

(in millions)  2009  2008  2007

Additions to property, plant and equipment

  $6,231  $6,989  $3,757

Change in capital accruals

   (343  30   621

Discontinued operations

   84   127   88
            

Capital expenditures

  $5,972  $7,146  $4,466

Acquisitions in 2007 consist primarily of the $3,907 million cash portion of the Western acquisition purchase price, net of the $44 million of cash acquired. See Note 6 to the consolidated financial statements for more information about the Western acquisition. In 2006, acquisitions primarily included cash payments of $718 million associated with our re-entry into Libya.

Disposal of assetstotaled $865 million, $999 million and $137 million in 2009, 2008 and $134 million2007. In 2009, we sold all of our operated and outside-operated interests in 2008, 2007Ireland and 2006.Gabon, reporting the disposals as discontinued operations. We also sold our operated and a portion of our outside-operated Permian Basin producing assets in New Mexico and west Texas. In 2008, disposal of assets included proceeds from the sale of our outside-operated interests and related undeveloped acreage in Norway and our share of PTC. Disposal of assets included proceeds from the sale ofIn 2007, we sold our interests in two LNG tankers in Alaska in 2007 and proceeds from the sale of 90 percent of our interest in Syrian natural gas fields in 2006.Alaska. Disposals for all years included proceeds from the sale of various domestic producing properties and SSA stores.

Disposal of discontinued operations of$832 million in 2006 related to the sale of our Russian exploration and production businesses in June 2006. See Note 87 to the consolidated financial statements.statements for more information about dispositions.

Net cash provided from financing activities totaled $724 million in 2009, compared with cash used in financing activities totaled of $1,193 million in 2008 compared with netand cash provided byfrom financing activities of $184 million in 2007 and cash used in financing activities of $2,581 million in 2006.2007. Sources of cash included the issuance of $1.5 billion in 2008 includedsenior notes in 2009, the issuance of $1.0 billion in senior notes. Sources of cashnotes in 2007 included2008 and the issuance of $1.5 billion in senior notes and borrowings of $578 million from the Norwegian export credit agency. Significant usesagency in 2007. Repayments of cash in financing activities in all years weredebt and common stock repurchases under our share repurchase plan were significant uses of cash in 2008 and 2007, while dividend payments and debt repayments.impacted every year.

Significant noncash transactions during 2007 included the issuance of $1.0 billion of 5.125 percent Fixed Rate Revenue Bonds (Marathon Oil Corporation Project) Series 2007A, with a maturity date of June 1, 2037. The proceeds from the bonds, along with interest income, arewere held in trust to beand were disbursed to us upon our request for reimbursement of expenditures related to our Garyville, Louisiana refinery expansion. Through December 31, 2008, such reimbursements have totaled $1,032 million. The $1.0 billion obligation is reflected as long-term debt andexpansion over the remaining $16 millioncourse of the construction project. Until all trusteed funds including interest income earned to date, is reflectedwere disbursed, the balance was reported as other noncurrent assets in theour consolidated balance sheet assheet. As of December 31, 2008.2009, we have received all funds from this financing.

Liquidity and Capital Resources

Our main sources of liquidity are cash and cash equivalents, internally generated cash flow from operations, the issuance of notes, and our $3.0 billion committed revolving credit facility. Because of the alternatives available to us, including internally generated cash flow and access to capital markets, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements including our capital spending programs, share repurchase program, dividend payments, defined benefit plan contributions, repayment of debt maturities and other amounts that may ultimately be paid in connection with contingencies.

Capital Resources

Credit Arrangements and Borrowings

At December 31, 2008,2009, we had $7,087$8,436 million in long term debt outstanding. Our senior unsecured debt is currently rated investment grade by Standard and Poor’s Corporation, Moody’s Investor Services, Inc. and Fitch Ratings with ratings of BBB+ (outlook stable), Baa1, (outlook stable), and BBB+ (outlook negative)., all with stable outlook. Should one or all of these agencies decide to downgrade our ratings, it could become more difficult and more costly for us to issue new debt or commercial paper. We do not have any ratings triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings.

At December 31, 2008,2009, we had no borrowings against our revolving credit facility and no commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.

Index to Financial Statements

Effective April 3, 2008, we amended our revolving credit facility, extending the termination date on $2,625 million from May 2012 to May 2013. The remaining $375 million continues to have a termination date of May 2012. No single lender holds more than 10 percent of the $3.0 billion revolving credit facility.

On March 12, 2008, we issued $1.0 billion aggregate principal amount of senior notes bearing interest at 5.9 percent with a maturity date of March 15, 2018. Interest on the senior notes is payable semi-annually beginning September 15, 2008.

Subsequent to year end 2008, on February 17, 2009, we issued $700 million aggregate principal amount of senior notes bearing interest at 6.5 percent with a maturity date of February 15, 2014 and $800 million aggregate principal amount of senior notes bearing interest at 7.5 percent with a maturity date of February 15, 2019. Interest on both issues is payable semi-annually beginning August 15, 2009.

Asset Sales

In 2008, we commenced a review of our portfolio of assets with the intent of monetizing those assets which are either mature or otherwise non-strategic. Through December 31, 2008, net proceeds of $999 million have been received from the sale of assets identified in this review.

Shelf Registration

On July 26, 2007, we filed a universal shelf registration statement with the Securities and Exchange Commission, under which we, as a well-known seasoned issuer, have the ability to issue and sell an indeterminate amount of various types of debt and equity securities.

Cash-Adjusted Debt-To-Capital Ratio

Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 23 percent and 22 percent at December 31, 20082009 and 2007.2008. This includes $485$340 million of debt at December 31, 2009 that is serviced by United States Steel.Steel Corporation (“United States Steel”).

 

(Dollars in millions)  2008 2007     2009 2008 

Long-term debt due within one year

  $98  $1,131    $96  $98 

Long-term debt

   7,087   6,084     8,436   7,087 
               

Total debt

  $7,185  $7,215    $8,532  $7,185 
               

Cash

  $1,285  $1,199    $2,057  $1,285 

Trusteed funds from revenue bonds(a)

  $16  $744    $-   $16 

Equity

  $21,409  $19,223    $21,910  $21,409 
       

Calculation:

       

Total debt

  $7,185  $7,215    $8,532  $7,185 

Minus cash

   1,285   1,199     2,057   1,285 

Minus trusteed funds from revenue bonds

   16   744     -    16 
               

Total debt minus cash

   5,884   5,272     6,475   5,884 
               

Total debt

   7,185   7,215     8,532   7,185 

Plus equity

   21,409   19,223     21,910   21,409 

Minus cash

   1,285   1,199     2,057   1,285 

Minus trusteed funds from revenue bonds

   16   744     -    16 
               

Total debt plus equity minus cash

  $27,293  $24,495    $    28,385  $    27,293 
               

Cash-adjusted debt-to-capital ratio

   22%  22%    23  22

(a)

Following the issuance of the $1.0 billion of revenue bonds by the Parish of St. John the Baptist, the proceeds were trusteed and will bewere disbursed to us upon our request for reimbursement of expenditures related to the Garyville refinery expansion. The trusteed funds arewere reflected as other noncurrent assets in the accompanying consolidated balance sheet as of December 31, 2008 and 2007.2008.

Capital Requirements

Capital Spending

We have approved a capital, investment and exploration budget of $5,738$5,148 million for 2009,2010, which represents a 2417 percent decrease from our 20082009 spending. Additional details related to the 20092010 budget are discussed in Outlook — Capital, Investment and Exploration Budget.Outlook.

Index to Financial Statements

Other Significant Expected Cash Outflows

We plan to make contributions of up to $439$17 million to ourfund pension plans during 2009.2010. As of December 31, 2008, $982009, $96 million of our long-term debt is due in the next twelve months.

Dividends of $0.96 per common share or $681$679 million were paid during 2008.2009. On February 2, 2009,1, 2010, we announced that our Board of Directors had declared a dividend of $0.24 cents per share on Marathon common stock, payable March 10, 2009,2010, to stockholders of record at the close of business on February 18, 2009.17, 2010.

Share Repurchase Program

Since January 2006, our Board of Directors has authorized a common share repurchase program totaling $5 billion. As of December 31, 2008,2009, we had repurchased 66 million common shares at a cost of $2,922 million. We have not made any purchases under the program since August 2008. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The program’s authorization does not include specific price targets or timetables. The timing of purchases under the program will be influenced by cash generated from operations, proceeds from potential asset sales and cash from available borrowings.

Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this

information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies. The discussion of liquidity above also contains forward-looking statements regarding expected capital, investment and exploration spending and a review of our portfolio of assets. The forward-looking statements about our capital, investment and exploration budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include prices of and demand for liquid hydrocarbons, natural gas and refined products, actions of competitors, disruptions or interruptions of our production, oil sands mining and bitumen upgrading or refining operations due to the shortage of skilled labor and unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other operating and economic considerations. Factors that could affect the review of our portfolio of assets include the identification of buyers and the negotiation of acceptable prices and other terms, as well as other customary closing conditions. The forward-looking statements about our common share repurchase program are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially are changes in prices of and demand for crude oil, natural gas and refined products, actions of competitors, disruptions or interruptions of our production or refining operations due to unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other operating and economic considerations.

Index to Financial Statements

Contractual Cash Obligations

The table below provides aggregated information on our consolidated obligations to make future payments under existing contracts as of December 31, 2008.2009.

 

(In millions)  Total  2009  

2010-

2011

  

2012-

2013

  Later
Years
  Total  2010  

2011-

2012

  

2013-

2014

  

Later

Years

Long-term debt (excludes interest)(a)(b)

  $6,880  $68  $279  $1,718  $4,815

Long-term debt (excludes interest)(a) (b)

  $8,184  $68  $1,664  $1,044  $5,408

Sale-leaseback financing(k)(a)

   297   14   55   44   184   33   11   22   -     -  

Capital lease obligations(k)(a)

   360   26   37   55   242   670   35   81   88   466

Operating lease obligations(a)

   967   176   233   180   378   909   160   251   186   312

Operating lease obligations under sublease(a)

   21   5   10   6      16   5   11   -     -  

Purchase obligations:

                    

Crude oil, feedstock, refined product and ethanol contracts(c)

   9,955   8,322   662   479   492   19,527   12,136   6,843   431   117

Transportation and related contracts

   1,657   430   401   223   603   2,354   395   417   260   1,282

Contracts to acquire property, plant and equipment

   4,070   1,949   1,242   389   490   2,938   1,466   1,380   73   19

LNG terminal operating costs(d)

   153   13   25   25   90   143   13   25   25   80

Service and materials contracts(e)

   1,567   379   442   205   541   2,261   429   537   433   862

Unconditional purchase obligations(f)

   50   8   14   14   14   47   8   16   16   7

Commitments for oil and gas exploration (non-capital)(g)

   21   19   2         43   29   7   1   6
                              

Total purchase obligations

   17,473   11,120   2,788   1,335   2,230   27,313   14,476   9,225   1,239   2,373

Other long-term liabilities reported in the consolidated balance sheet(h)

   3,562   500   704   871   1,487   2,308   80   643   560   1,025
                              

Total contractual cash obligations(i)(j)

  $29,560  $11,909  $4,106  $4,209  $9,336

Total contractual cash obligations(i) (j)

  $    39,433  $    14,835  $    11,897  $    3,117  $    9,584

(a)

Upon the USX Separation, United States Steel assumed certain debt and lease obligations, including $415$286 million of long-term debt obligations related to industrial revenue bonds. The Financial Matters Agreement provides that, on or before the tenth anniversary of the USX Separation, United States Steel will provide for Marathon’s discharge from any remaining liability under any of the assumed industrial revenue bonds. Such amounts are included in the above table because we remain primarily liable.

(b)

We anticipate cash payments for interest of $426$500 million for 2009, $8422010, $922 million for 2010-2011, $6462011-2012, $731 million for 2012-20132013-2014 and $3,603$3,474 million for the remaining years for a total of $5,517$5,627 million. Of these, we anticipate cash payments for interest of $23$16 million for 2009, $452010, $22 million for 2010-2011, $322011-2012, $16 million for 2012-20132013-2014 and $207$108 million for the later years to be made by United States Steel.

(c)

The majority of these contractual obligations as of December 31, 2008,2009 relate to contracts to be satisfied within the first 180 days of 2009.2010. These contracts include variable price arrangements.

(d)

We have acquired the right to deliver 58 bcf of natural gas per year to the Elba Island LNG re-gasification terminal. The agreement’s primary term ends in 2021. Pursuant to this agreement, we are also committed to pay for a portion of the operating costs of the terminal.

(e)

Service and materials contracts include contracts to purchase services such as utilities, supplies and various other maintenance and operating services.

(f)

We are a party to a long-term transportation services agreement with Alliance Pipeline. This agreement was used by Alliance Pipeline to secure its financing. This arrangement represents an indirect guarantee of indebtedness. Therefore, this amount has also been disclosed as a guarantee.

(g)

Commitments for oil and gas exploration (non-capital) include estimated costs related to contractually obligated exploratory work programs that are expensed immediately, such as geological and geophysical costs.

(h)

Primarily includes obligations for pension and other postretirement benefits including medical and life insurance. We have estimated projected funding requirements through 2018.2019. Also includes certainamounts for uncertain tax obligations recorded in accordance with FIN 48.positions.

(i)(i)

Includes $497$362 million of contractual cash obligations that have been assumed by United States Steel. See Item 7. Management’s Discussion and Analysis of Financial Condition, Cash Flows and Liquidity – Obligations Associated with the Separation of United States Steel.

(j)

This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of $ 965$1,102 million. See Note 2120 to the consolidated financial statements.

(k)

During the interim period between lease inception and effective date, long-term debt costs equal estimated or reported construction costs as of the end of the reporting period, not the minimum lease payment/rentals.

Off-Balance Sheet Arrangements

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

Index to Financial Statements

We have provided various guarantees related to equity method investees, United States Steel and others. These arrangements are described in Note 27 to the consolidated financial statements.

Transactions with Related Parties

We own a 63 percent working interest in the Alba field offshore Equatorial Guinea. Onshore Equatorial Guinea, we own a 52 percent interest in an LPG processing plant, a 60 percent interest in an LNG production facility and a 45 percent interest in a methanol production plant, each through equity method investees. We sell our natural gas from the Alba field to these equity method investees as the feedstock for their production processes. The methanol that is produced is then sold through another equity method investee.

Sales of refined petroleum products to our 50 percent equity method investee, PTC, which was sold in October 2008, accounted for 2.5 percent or less of our total sales revenue for 2008 2007 and 2006.2007. We believe that these transactions with related parties have been conducted under terms comparable to those with unrelated parties.parties

Off-Balance Sheet Arrangements

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

We have provided various guarantees related to equity method investees, United States Steel and others. These arrangements are described in Note 26 to the consolidated financial statements.

Obligations Associated with the Separation of United States Steel

We remain obligated (primarily or contingently) for certain debt and other financial arrangements for which United States Steel has assumed responsibility for repayment under the terms of the USX Separation. United States Steel’s obligations to us are general unsecured obligations that rank equal to United States Steel’s accounts payable and other general unsecured obligations. If United States Steel fails to satisfy these obligations, we would become responsible for repayment. Under the Financial Matters Agreement, United States Steel has all of the existing contractual rights under the leases assumed from 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 leases, other than extensions set forth in the terms of the assumed leases.

As of December 31, 2008,2009, we have identified the following obligations that have been assumed by United States Steel:

 

$415286 million of industrial revenue bonds related to environmental improvement projects for current and former United States Steel facilities, with maturities ranging from 2011 through 2033. Accrued interest payable on these bonds was $8$6 million at December 31, 2008.2009. We anticipate United States Steel will make future interest payments of $23$16 million for 2009, $452010, $22 million for 2010-2011, $322011-2012, $16 million for 2012-20132013-2014 and $207$108 million for the later years.

 

$3729 million of sale-leaseback financing under a lease for equipment at United States Steel’s Fairfield Works, with a term extending to 2012, subject to extensions. There was no accrued interest payable on this financing at December 31, 2008.2009.

 

$3225 million of obligations under a lease for equipment at United States Steel’s Clairton coke-making facility, with a term extending to 2012. There was no accrued interest payable on this financing at December 31, 2008.2009.

 

$2116 million of operating lease obligations, all of which was assumed by purchasers of major equipment used in plants and operations divested by United States Steel.

 

A guarantee with respect to all obligations of United States Steel to the limited partners of the Clairton 1314B Partnership, L.P., which was terminated on October 31, 2008. Upon termination of the partnership, we were not released from our obligations under guarantee. United States Steel has reported that it currently has no unpaid outstanding obligations to the limited partners. See Note 2726 to the consolidated financial statements.

Of the total $513$362 million, obligations of $492$346 million and corresponding receivables from United States Steel were recorded on our consolidated balance sheet as of December 31, 2008,2009, (current portion – $23portion—$22 million; long-term portion – $469portion—$324 million). The remaining $21$16 million was related to off-balance sheet arrangements and contingent liabilities of United States Steel.

United States Steel has restrictive covenants related to its indebtedness that could have an adverse effect on its financial position and liquidity.

In its Form 10-K for the year ended December 31, 2008,2009, United States Steel reportedmanagement stated that it was in compliance with all debt covenants, but thatbelieves its liquidity will be adequate to satisfy its obligations for the current global recession may affect its

Index to Financial Statements

ability to comply with those covenant and conditions in theforeseeable future. Such circumstances could trigger a need forDuring 2009, United States Steel undertook certain plans and actions designed to modify or replace credit agreements on less favorable termspreserve and enhance its liquidity and financial flexibility, including the sale of its common stock and issuance of senior convertible notes due 2014 for net proceeds of approximately $1,496 million. During the fourth quarter of 2009, United States Steel refinanced $129 million of certain debt for which we were liable; as a direct result of the refinancing, we are no longer liable for that could adversely affect its flexibility, cash flow$129 million. United States Steel’s senior unsecured debt ratings are BB by Standard and profitability.Poor’s Corporation, Ba3 by Moody’s Investment Service, Inc. and BB+ by Fitch Ratings. The ratings listed reflect a Fitch downgrade from BBB- to BB+ in January 2010.

Outlook

Capital, Investment and Exploration Budget

Our Board of Directors approved a capital, investment and exploration budget of $5,738$5,148 million for 2009,2010, which includes budgeted capital expenditures of $5,547$4,863 million. This represents a 2417 percent decrease from 20082009 spending. The focus of our 20092010 budget is to maintain solidon exploration and production performance, enhanceactivities, with an emphasis on ongoing development projects, certain potentially significant exploration wells and growing our downstream businesspresence in unconventional resource plays.

Exploration and provide necessary investments in mid- and long-term growth projects.Production

The budget includes worldwide exploration and production budget for 2010 is $2,868 million, of which $1,023 million is designated for our global exploration drilling program. A primary focus in 2010 is the deepwater Gulf of Mexico, where we plan to drill three or four significant wells. We have also targeted spending of $2,468 million. A significant amount of this budget, 45 percent, is targeted on projects that will sustainfor Indonesia, where we plan to drill two potentially high-reward, but also high-risk, deepwater wells in 2010. Additionally, we anticipate drilling or participating in approximately 20 to 30 wells in emerging North American resource plays – the Marcellus Shale in Pennsylvania/West Virginia, the Woodford Shale in Oklahoma and grow productionthe Haynesville/Bossier play in Texas – and approximately 10 to 15 onshore conventional wells in the short-term, including domestic assetsLower 48 in 2010.

This year’s production budget of $1,845 million is concentrated on three key oil projects: North Dakota’s Bakken Shale oil play, where we plan to drill or participate in approximately 75 wells; offshore Norway, where we plan further drilling or development on satellite fields surrounding the Alvheim/Vilje development, such as thosethe Gudrun field; and offshore Angola, where deepwater PSVM development on Block 31 is under way. A total of 48 production and injection wells are planned at the PSVM, with the first three to four development wells planned in 2010. First production is anticipated in late 2011 to early 2012. Other discoveries on Angola Block 31 comprise potential development areas in the Bakken Shalesoutheast and Piceance Basinmiddle portions of the block and internationaleight of the Block 32 discoveries form another potential development projects like Volund in Norway. Mid-termthe eastern area of that block. We expect first production growth projects such as Droshky and Ozonaon Block 32 in 2015-2016.

Additionally, in the Gulf of Mexico, we are winding down spending on the Droshky development, in which we own a 100 percent working interest while continuing work on the Ozona development. First production from Droshky is targeted for mid-2010. Initial production from Ozona, where we hold a 68 percent working interest, is expected in late 2011. We also plan to drill or participate in approximately 100 conventional development wells onshore U.S. in 2010.

The above discussion includes forward-looking statements with respect to anticipated future exploratory and emergingdevelopment drilling, investments in new resource plays inand development projects, the Marcellustiming of production from the Droshky and Woodford Shales account for 34 percent of the 2009 budget. Long-term projects will require about 20 percent of budgeted funds in 2009. The PSVM development on Angola Block 31, the Gudrun development in Norway, as well as explorationOzona developments in the Gulf of Mexico, the Faregh Phase II Gas Plant, the PVSM development on Block 31 offshore Angola, NorwayBlock 32 and Indonesia are our significant long-term projects.other possible developments. Some factors which could potentially affect these forward-looking statements include pricing, supply and demand for petroleum products, the amount of capital available for exploration and development, regulatory constraints, drilling rig availability, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other geological, operating and economic considerations. The foregoing forward-looking statements may be further affected by the inability to obtain or delay in obtaining necessary government and third-party approvals or 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.

Oil Sands Mining

The budget includes $887$668 million for the Oil Sands Mining segment in 2009, primarily2010, down 32 percent as AOSP Expansion 1 approaches completion. Expansion 1, which includes construction of mining and extraction facilities

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

Beginning late in the first quarter of 2010 and continuing into the second quarter, the existing AOSP mine and upgrader operations will undergo a scheduled turnaround. The last scheduled turnaround occurred in 2006. Production is planned to be curtailed for approximately 60 to 70 days, during which the continuationfacilities will be completely shutdown for approximately two-thirds of Expansion 1. This is slightly lower than 2008 spending due in partthe time. We expect our net cost of the turnaround to be approximately $85 to $120 million. Additional tie-ins and pipeline commissioning work related to the stronger U.S. dollarExpansion 1 will occur during this period, but such costs are included in the Expansion 1 capital budget.

Evaluation of the AOSP Quest Carbon Capture and Storage (“CCS”) project continues in 2010. A final investment decision on the Quest CCS project will be made at a later date, and is subject to the expected deferral of some nonessential projects.regulatory approvals, stakeholder engagement, detailed engineering studies, as well as a final joint venture partner agreement.

The above discussion includes forward-looking statements with respect to anticipated completion of the AOSP Expansion 1 and the planned turnaround at the AOSP mine and upgrader. Factors which could affect these projects 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.

Refining, Marketing and Transportation

The 2010 budget includes $1,944$1,114 million for RM&T projects, with about 52 percent budgeted forsegment projects. With the completion of the Garyville refinery expansion and 17 percentin 2009, budgeted spending is almost half what it was for 2009. As the new units comprising the Garyville refinery expansion reach full capacity utilization, we will have the capability to increase our relative distillate production capacity.

Continuation of the Detroit refinery heavy oil upgrading and expansion project. project accounts for about 36 percent of the budget. The Detroit project when finished will increase the refinery’s heavy oil upgrading capacity, including Canadian bitumen blends, by about 80 mbpd, and will increase its total crude oil refining capacity by 10 percent. Through the Garyville and Detroit refinery investments, we expect to more than double our coking capacity by 2012, which should lead to lower feedstock costs and increased margins.

In early January 2010, we began an extended turnaround at the 256 mbpd base refinery in Garyville (the new expansion refinery will be operating during the time of the turnaround at the base refinery). The entire facility (base plus expansion) is expected to reach full refining capacity of 436 mbpd by the second quarter of 2010. Total expense from turnarounds and major maintenance activities is expected to increase by approximately $100 million pretax in the first quarter of 2010 compared to first quarter 2009, primarily due to the extent of the Garyville turnaround and major maintenance activities.

The remainder of the budget is allocated to maintaining facilities and meeting regulatory requirements, notably the Mobile Source Air Toxics (“MSAT”MSAT II”) regulations that will be effective at the beginning of 2011.

The above discussion includes forward-looking statements concerning the Detroit refinery heavy oil upgrading and expansion project, expected turnaround expenditures and MSAT II regulations compliance costs. Some factors that could affect the Detroit and MSAT II projects include transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, other risks customarily associated with construction projects. These factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Integrated Gas

Although we have not budgeted for any capital spending for our Integrated Gas segment in 2010, we will continue non-capital spending in pursuit of the development of new technologies to supply new energy sources. We are evaluating the commercialization of our Gas-to-Fuels (“GTF™”) technology and are pursuing other technologies focused on reducing the processing and transportation costs of natural gas.

The above discussion contains forward looking statements with respect to the potential commercialization of our GTF™ technology. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Corporate and Other

The remaining $439$498 million of our 2010 budget relates to capitalized interest and corporate activities.

The net income tax liabilities of our OSM operations are denominated in Canadian dollars and must be remeasured to U.S. dollars each reporting period. At year end we took steps, as permitted under Canadian tax rules, which will enable us to convert these liabilities during the first half of 2010 to be denominated in U.S. dollars and thereby eliminate exposure to foreign currency exchange rate changes on our net deferred tax liability related to OSM operations from that point forward.

The forward-looking statements about our capital, investment and exploration budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include prices of and demand for crude oil, natural gas and refined products, actions of competitors, disruptions or interruptions of our production or refining operations due to the shortage of skilled labor and unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other operating and economic considerations.

Exploration

Major exploration activities are currently underway or under evaluation worldwide.

Angola – We hold a 10 percent outside-operated interest in offshore Block 31 and a 30 percent outside-operated interest in offshore Block 32. We plan to participate in four to six exploration or appraisal wells in these deepwater blocks in 2009. Four potential development hubs have been identified on these two blocks and we continue to evaluate our discoveries for future development.

Norway – We hold interests in over 510,000 acres offshore Norway and plan to continue our exploration efforts there. In 2009, exploration drilling is expected to commence on additional prospects with the potential to be tied back to the Alvheim complex.

Gulf of Mexico – We plan to participate in one to three exploration wells during 2009. The exploration success on the Shenandoah prospect was announced in February 2009 by the operator. We own a 10 percent outside-operated interest in this prospect. Additional prospects have been identified in the Gulf of Mexico deepwater leases acquired in 2007 and 2008. These projects make up the core of our 2009 through 2010 Gulf of Mexico exploration drilling plans.

Index to Financial Statements

Indonesia – We continue to evaluate seismic data on the Pasangkayu Block offshore Indonesia and plan to start exploratory drilling there in early 2010. We are the operator of this block and hold a 70 percent interest. Evaluation of the Bone Bay Block offshore Indonesia, which we were awarded in 2008, continues with plans to collect seismic data in 2010. Exploratory drilling on this block could begin in 2011. We have a 49 percent interest in the Bone Bay Block and are the operator.

U.S. onshore – We announced a discovery in the Woodford Shale in January 2009. We hold 30,000 net acres in the Woodford Shale resource play in the Anadarko Basin of Oklahoma and plan to participate in more horizontal wells in 2009. We also hold prospective acreage in two emerging shale resource plays in the U.S. In the Appalachian Basin we hold 65,000 net acres in the Marcellus Shale resource play in Pennsylvania and West Virginia. We also hold 25,000 net acres, primarily in Texas, in the Haynesville Shale resource play in North Louisiana and East Texas . Our plans call for initial drilling on some of these leases in 2009.

Equatorial Guinea – We are evaluating development scenarios for the Deep Luba and Gardenia discoveries on the Alba Block, one of which includes production through the Alba field infrastructure. We own a 63 percent interest in the Alba Block and serve as operator.

Production

During 2008, several of our development projects were completed and began producing. We have approved new development projects, are evaluating others and will continue working on ongoing projects in 2009.

Angola – In 2008 we received approval to proceed with this first deepwater PSVM development project. The development is comprised of the Plutao, Saturno, Venus and Marte discoveries. Key contracts were awarded and construction work commenced in the second half of 2008. A total of 48 production and injection wells are planned for the PSVM development. First production is targeted for 2012 with a design capacity of about 150,000 gross bpd

Norway – Tie back of the Volund field offshore Norway to the Alvheim/Vilje production facility continues with first production expected in late 2009. We own a 65 percent interest in Volund and serve as operator. In addition, we hold a 28 percent outside-operated interest in the Gudrun field, located 120 miles off the coast of Norway, where a successful appraisal well was drilled in 2006. In January 2009, the operator announced a development concept that includes a fixed processing platform with seven production wells that would be tied to existing facilities on the Sleipner field. A final investment decision is expected in 2009.

Gulf of Mexico – The Droshky and Ozona developments in deepwater Gulf of Mexico were approved in 2008. Rig capacity has been secured for Droshky development drilling which is expected to begin in February 2009 with first production targeted for 2010. The project will consist of four development wells which will be tied back to the nearby third-party owned and operated Bullwinkle platform. We own a 100 percent working interest in Droshky. Ozona development on Garden Banks Block 515 will begin in 2009, with first production expected in 2011. We hold a 68 percent working interest in Ozona.

U.S. onshore – We continue drilling on resource plays in the Piceance Basin of Colorado and the Williston Basin of North Dakota and eastern Montana (the Bakken shale resource play). In the Piceance Basin, drilling and production commenced in late 2007. Plans are to drill 150 wells during the next five years. More than 100 operated wells have already been drilled with plans to drill approximately 225 additional wells during the next five years.

The above discussion includes forward-looking statements with respect to anticipated future exploratory and development drilling, the possibility of developing Blocks 31 and 32 offshore Angola and the Droshky discovery in the Gulf of Mexico, the timing of production from the Neptune development, the Droshky discovery, the Alvheim/Vilje development, the Volund field and the Corrib project. Some factors which could potentially affect these forward-looking statements include pricing, supply and demand for petroleum products, the amount of capital available for exploration and development, regulatory constraints, drilling rig availability, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other geological, operating and economic considerations. Except for the Neptune, Alvheim/Vilje and Volund developments, the foregoing forward-looking statements may be further affected by the inability to or delay in obtaining necessary government and third-party approvals and permits. The possible developments of the Droshky discovery and Blocks 31 and 32 offshore Angola 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.

Index to Financial Statements

Oil Sands Mining

The AOSP Expansion 1 continues in 2009 and is expected to begin operations in the 2010 to 2011 timeframe. The expansion includes construction of mining and extraction facilities at the Jackpine mine, expansion of treatment facilities at the existing Muskeg River mine and expansion of the Scotford upgrader, along with construction of common infrastructure sized to support future mining expansions.

The above discussion includes forward-looking statements with respect to anticipated completion of the AOSP expansion. Factors which could affect the expansion 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.

Refining, Marketing and Transportation

The Garyville refinery expansion is expected to be completed and ready for start up in the fourth quarter of 2009. Total projected costs are now estimated to be $3.35 billion (excluding capitalized interest). This expansion will increase the refinery’s crude oil throughput capacity by 180 mbpd and will enable the refinery to provide an additional 7.5 million gallons of clean transportation fuels to the market each day.

Permits were obtained and construction commenced for the heavy oil upgrading and expansion project at our Detroit, Michigan, refinery in 2008. Due to delays in the projected production from Canadian oil sands and current market conditions, we have reevaluated the project construction schedule and now plan to complete this project in mid-2012. We now forecast the project will cost $2.2 billion (excluding capitalized interest), or about 15 percent more than the original budget, due primarily to additional costs associated with the project deferral as well as a scope change that will allow the refinery to process heavier and more acidic crude oils.

Through these investment projects, we expect to more than double our coking capacity by 2012, which should lead to lower feedstock costs and increased margins. In addition, as the new units comprising the Garyville refinery expansion reach full capacity utilization, we anticipate the percentage of distillate produced to increase.

We estimate that we will spend approximately $200 million in 2009 to comply with MSAT II regulations.

The above discussion includes forward-looking statements concerning the planned expansion of the Garyville refinery, the Detroit refinery heavy oil upgrading and expansion project and MSAT II regulations compliance costs. Some factors that could affect the Garyville, Detroit and MSAT II projects include transportation logistics, availability of materials and labor, unforeseen hazards such as weather conditions, other risks customarily associated with construction projects. These factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Integrated Gas

Our net worldwide LNG sales volumes are expected to average 5,700 to 6,400 metric tonnes per day in 2009.

We continue to invest in the development of new technologies to supply new energy sources. In 2008, we completed construction of a facility to demonstrate operation of the fully integrated gas-to-fuels process at a practical scale. We are evaluating the commercialization of this technology and have engaged an engineering contractor to provide engineering and design services for using our proprietary GTF™ technology on a commercial scale.

The above discussion contains forward looking statements with respect to future LNG sales and the potential commercialization of our GTF™ technology. Projected LNG sales volumes are based upon a number of assumptions, including unforeseen hazards such as weather conditions, acts of war or terrorist acts and government or military response thereto and other operating and economic considerations. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

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

We have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. We

Index to Financial Statements

believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas, crude oil and feedstock sources, production processes and whether it is also engaged in the petrochemical business or the marine transportation of crude oil and refined products.

Legislation and regulations pertaining to climate change and greenhouse gas emissions have the potential to materially adversely impact our business, financial condition, results of operations and cash flow, including costs of compliance and permitting delays. The extent and magnitude of these adverse impacts cannot be reliably or accurately estimated at this time because specific regulatory and legislative requirements have not been finalized and uncertainty exists with respect to the measures being considered, the costs and the time frames for compliance, and our ability to pass compliance costs on to our customers. For additional information see Item 1A. Risk Factors.

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

(In millions)  2009  2008  2007

Capital

  $        399  $        421  $        199

Compliance

      

Operating and maintenance

   373   379   287

Remediation(b)

   29   26   25
            

Total

  $801  $826  $511
(a)

(In millions)  2008  2007  2006

Capital

  $421  $199  $176

Compliance

      

Operating and maintenance

   379   287   309

Remediation(b)

   26   25   20
            

Total

  $826  $511  $505

(a)

Amounts are determined based on American Petroleum Institute survey guidelines regarding the definition of environmental expenditures.

(b)

These amounts include spending charged against remediation reserves, where permissible, but exclude non-cash provisions recorded for environmental remediation.

Our environmental capital expenditures accounted for sixseven percent of capital expenditures for continuing operations in 2009, six percent in 2008 and four percent in 2007 and five percent in 2006.2007.

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

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

Our environmental capital expenditures are expected to be $373$304 million, or sevensix percent, of capital expenditures in 2009.2010. Predictions beyond 20092010 can only be broad-based estimates, which have varied, and will continue to vary, due to the ongoing evolution of specific regulatory requirements, the possible imposition of more stringent requirements and the availability of new technologies, among other matters. Based on currently identified projects, we anticipate that environmental capital expenditures will be approximately $426$331 million in 2010;2011; however, actual expenditures may vary as the number and scope of environmental projects are revised as a result of improved technology or changes in regulatory requirements and could increase if additional projects are identified or additional requirements are imposed.

Of particular significance to our refining operations are EPA regulations that require reduced sulfur levels in diesel fuel for off-road use. We have spent approximately $175 million between 2006 and 2009 on refinery investments to produce ultra-low sulfur diesel fuel for off-road use, in compliance with EPA regulations.

Further, we estimate that we may spend approximately $1 billion over a six-year period beginning in 2008 to comply with MSAT II regulations relating to benzene content in refined products. We have not finalized our strategy or cost estimates to comply with these requirements. Our actual MSAT II expenditures have totaled $283 million through December 31, 2009 and we expect to spend $325 million on MSAT II in 2010. The cost estimates are forward-looking statements and are subject to change as further work is completed in 2010.

For more information on environmental regulations that impact us, or could impact us, see Item 1. Business – Environmental Matters, and Item 3. Legal Proceedings.Proceedings and Item 1A. Risk Factors.

Critical Accounting Estimates

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

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

Index to Financial Statements

Estimated Net Recoverable Reserve QuantitiesProved Reserves

Proved Liquid Hydrocarbon and Natural Gas Reserves

We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved liquid hydrocarbon, and natural gas and synthetic crude oil reserves, both developed and undeveloped. The existence and the estimated amount of proved reserves affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depreciated, depleted or amortized into net income and the presentation of supplemental information on oil and gas producing activities. Both the expected future cash flows to be generated by oil and gas producing properties used in testing such properties for impairment and the expected future taxable income available to realize deferred tax assets also rely, in part, on estimates of net recoverable quantities of liquid hydrocarbons and natural gas.reserves.

Proved reserves are the estimatedthose quantities of liquid hydrocarbonsoil and natural gas, that geologic and engineeringwhich, by analysis of geoscience data, demonstratecan be estimated with reasonable certainty to be recoverable in future yearseconomically producible from a given date forward from known reservoirs, and

under existing economic conditions, operating methods, and operating conditions.government regulation before the time at which contracts providing the right to operate expire, unless evidence indicates that a renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, operational, economic and political conditions change. Beginning December 31, 2009, reserve estimates are based upon an average of prices in the prior 12-month period, using the closing prices on the first day of each month. In previous periods, reserve estimates were based upon prices at December 31. Neither of these prices should be expected to reflect future market conditions. During 2008,2009, net revisions of previous estimates increased total proved reserves by 23 million boe (less than 2596 mmboe (50 percent of the beginning of the year reserve estimate)., with 603 mmboe of the increase related to the presentation of reserves related to oil sand mining as synthetic crude oil effective December 31, 2009 under the SEC’s revised regulations.

OurThe estimation of net recoverable quantities of liquid hydrocarbons, and natural gas and synthetic crude oil is a highly technical process, performed by in-house teamswhich is based upon several underlying assumptions that are subject to change. For a discussion of reservoir engineers and geoscience professionals. All estimates prepared by these teams are made in compliance with SEC Rule 4-10(a)(2),(3) and (4) of Regulation S-X and SFAS No. 25, “Suspension of Certain Accounting Requirements for Oil and Gas Producing Companies (an Amendment of Financial Accounting Standards Board (“FASB”) Statement No. 19),” and disclosed in accordance with the requirements of SFAS No. 69, “Disclosures about Oil and Gas Producing Activities (an Amendment of FASB Statements 19, 25, 33 and 39).” The SEC has amended its disclosure requirements effective for annual reports on Form 10-K for fiscal years ending on or after December 31, 2009 – see Management’s Discussion and Analysis of Financial Condition and Results of Operations – Accounting Standards Not Yet Adopted for additional information. Estimates of liquid hydrocarbon and natural gas reserves are based on prices at December 31, 2008. Reserve estimates are reviewed and approved by our Corporate Reserves Group. Any change to proved reserves estimates in excess of 2.5 million boe on a total-field basis, within a single month, must be approved by the Director of Corporate Reserves, who reports to our Chief Financial Officer. 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.

Third-party consultants are engaged to prepare independent reserve estimates for fields that comprise the top 80 percent of our total reserves over a rolling four-year period. We met this goal for the four-year period ended December 31, 2008. For 2006 and thereafter, we established a tolerance level of 10 percent for third-party reserve estimates such that the third-party consultants discontinue their estimation activities once their results are within 10 percent of our internal estimates. Should the third-party consultants’ initial analysis fail to reach our tolerance level, the consultants re-examine the information provided, request additional data and refine their analysis if appropriate. If, after this re-examination, the third-party consultants cannot arrive at estimates within our tolerance, we adjust our reserve estimates as necessary to achieve estimates within our tolerance level. This independent third-party reserve estimation process, did not result in significant changes to our reserve estimates in 2008, 2007, or 2006.

The reservesincluding the use of the Alba field in Equatorial Guinea comprise approximately 38 percent of our total proved liquid hydrocarbon and natural gas reserves as of December 31, 2008. The reserves of the next five largest asset groups – the Waha concessions in Libya, the Alvheim/Vilje development offshore Norway, the Droshky development in Green Canyon Block 244 in the Gulf of Mexico, the Oregon Basin field in the Rocky Mountain area of the United States and the Foinaven development in the North Sea – comprise 32 percent of our total proved liquid hydrocarbon and natural gas reserves.third-party audits, see Item 1. Business.

Depreciation and depletion of producing liquid hydrocarbon, and natural gas and synthetic crude oil producing (including oil sands mining and upgrading assets) properties is determined by the units-of-production method and could change with revisions to estimated proved developed reserves. The change in the depreciation and depletion rate over the past three years due to revisions of previous reserve estimates has not been significant. Onsignificant to either our E&P or our OSM segments. For our E&P segment, on average, a five percent increase in the amount of liquid hydrocarbon and natural gas reserves would lower the depreciation and depletion rate by approximately $0.47$0.53 per barrel, which would increase pretax

Index to Financial Statements

income by approximately $66$78 million annually, based on 20082009 production. OnConversely, on average, a five percent decrease in the amount of liquid hydrocarbon and natural gas reserves would increase the depreciation and depletion rate by approximately $0.52$0.58 per barrel and would result in a decrease in pretax income of approximately $73$86 million annually, based on 20082009 production.

Proved Bitumen Reserves

We acquired a 20 percent outside-operated interest in the AOSP in Alberta, Canada with the acquisition of Western in October 2007. Oil sands mining operations at the AOSP are outside the scope of SFAS Nos. 25 and 69 and SEC Rule 4-10 of Regulation S-X; therefore, bitumen production and reserves are not included in For our Supplementary InformationOSM segment, on Oil and Gas Producing Activities. As discussed, the SEC has recently issued a release amending these disclosures – see Management’s Discussion and Analysis of Financial Condition and Results of Operations – Accounting Standards Not Yet Adopted for additional information.

The estimated amount of proved bitumen reserves affects the amount and timing of costs depreciated, depleted or amortized into net income. The expected future cash flows to be generated by oil sands mining and bitumen upgrading assets used in testing oil sands mining and bitumen upgrading assets for impairment also rely, in part, on estimates of proved bitumen reserves.

Reserves related to oil sands mining operations are defined as that part of a mineral deposit which could be economically and legally extracted or produced at the time of the reserve determination. Proved bitumen reserves as of December 31, 2008 were based on a third-party consultant’s estimate using volumetric estimation techniques similar to those used in estimating liquid hydrocarbon and natural gas reserves, except that estimates of bitumen reserves are based on annual average prices for 2008, which is believed to be consistent with industry practice in Canada.

Depreciation and depletion of most oil sands mining and bitumen upgrading assets is determined by the units-of-production method and could change with revisions to estimated proved bitumen reserves. On average, a five percent increase in estimated bitumensynthetic crude oil reserves would lower the depreciation and depletion rate by approximately $0.98$0.66 per barrel and would result in an increase in pretax income of approximately $9$8 million annually, based on 20082009 production. On average, a five percent decrease in estimated bitumensynthetic crude oil reserves would increase the depreciation and depletion rate by approximately $0.52$0.36 per barrel and would result in a decrease in pretax income of approximately $5$4 million annually, based on 20082009 production.

Fair Value Estimates

OnEffective January 1, 2008 and 2009, we adopted SFAS No. 157the new accounting standards for those financial assets and liabilities recognized or disclosed at fair value in the consolidated financial statements on a recurring and those recognized and disclosed on a nonrecurring basis. SFAS No. 157 definesThe standards define fair value, establishesestablish a framework for measuring fair value and expandsexpand disclosures about fair value measurements. It doesThe standards do not require us to make any new fair value measurements, but rather establishesestablish a fair value hierarchy that prioritizes the inputs to the valuation techniques used to measure fair value. Level 1 inputs are given the highest priority in the fair value hierarchy, as they represent observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date, while Level 3 inputs are given the lowest priority, as they represent unobservable inputs that are not corroborated by market data. Valuation techniques that maximize the use of observable inputs are favored. See Item 8. Financial Statements and Supplementary Data—Note 17 of16 to the consolidated financial statements for disclosures regarding our fair value measurements.

In February 2008, the FASB issued FASB Staff Position (“FSP”) FAS 157-2, “Effective Date of FASB Statement No. 157,” which deferred the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities. This includes impairments of goodwill, intangible assets and other long-lived assets, and initial measurement of asset retirement obligations, asset exchanges, pensions, business combinations and partial sales of proved properties.

The primary impact from the adoption of SFAS No. 157 at January 1, 2008, related to the fair value measurement of our derivative instruments. Additional information about derivatives and their valuation may be found in Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Index to Financial Statements

Significant uses of fair value measurements include:

assessment of impairment of long-lived assets,

assessment of impairment of goodwill,

 

allocation of the purchase price paid to acquire businesses to the assets acquired and liabilities assumed in those acquisitions,

assessment of impairment of long-lived assets,

assessment of impairment of goodwill, and

 

recorded value of derivative instruments.

Acquisitions

Under the purchase method of accounting for business combinations, the purchase price paid to acquire a business is allocated to its assets and liabilities based on the estimated fair values of the assets acquired and liabilities assumed as of the date of acquisition. The excess of the purchase price over the fair value of the net tangible and identifiable intangible assets acquired is recorded as goodwill. A significant amount of judgment is involved in estimating the individual fair values involving property, plant and equipment and identifiable intangible assets. We use all available information to make these fair value determinations and, for certain acquisitions, engage third-party consultants for assistance.

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

Impairment Assessments of GoodwillLong-Lived Assets and Long-Lived AssetsGoodwill

Fair value calculated for the purpose of testing for impairment of our long-lived assets and goodwill is estimated using the expected present value of future cash flows method and comparative market prices when

appropriate. A significant amount ofSignificant judgment is involved in performing these fair value estimates for goodwill and long-lived assets since the results are based on forecasted assumptions. Significant assumptions include:

 

  

Future liquid hydrocarbon, and natural gas and synthetic crude oil prices. Our estimates of future prices are based on our analysis of market supply and demand and consideration of market price indicators. Although liquid hydrocarbon and natural gasthese commodity prices may experience extreme volatility in any given year, we believe long-term industry prices are driven by global market supply and demand. To estimate supply, we consider numerous factors, including the world-wide resource base, depletion rates, and OPEC production policies. We believe demand is largely driven by global economic factors, such as population and income growth, governmental policies, and vehicle stocks. Such price estimates are consistent with those used in our planning and capital investment reviews. There has been significant volatility in the liquid hydrocarbon, and natural gas and synthetic crude oil prices and estimates of such price curves are inherently imprecise.

 

  

Estimated recoverable quantities of liquid hydrocarbons, natural gas and bitumensynthetic crude oil. This is based on a combination of proved and risk-adjustedweighted probable and possible reserves.reserves such that the combined volumes represent the mean (average) expectation. These estimates are based on work performed by our engineers and that of outside consultants. Because of their very nature, probable and possible reserves are less precise than those of proved reserves. We evaluate our probable and possible reserves using drilling results, reservoir performance, seismic interpretation and future plans to develop acreage. Reserves are adjusted as new information becomes available.

 

  

Expected timing of production. Production forecasts are based on a combination of proved and risk-adjustedweighted probable and possible reserves based on engineering studies. The actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money.

 

  

Future margins on refined products produced and sold. Our estimates of future product margins are based on our own analysis of various supply and demand factors, which includes,include, among other things, industry-wide capacity, our planned utilization rate, end-user demand, capital expenditures, and economic conditions. Such estimates are consistent with those used in our planning and capital investment reviews.

 

  

Discount rate commensurate with the risks involved. We apply a discount rate to our cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. This discount rate is also compared to recent observable market transactions, if possible. A higher discount rate decreases the net present value of cash flows.

 

  

Future capital requirements. This isThese are based on authorized spending and internal forecasts.

Index to Financial Statements

We base our fair value estimates on projected financial information which we believe to be reasonable. However, actual results may differ from thosethese projections.

The need to test for impairment can be based on several indicators, including a significant reduction in prices of liquid hydrocarbons, or natural gas or synthetic crude oil, unfavorable adjustments to reserves, significant changes in the expected timing of production, significant reduction in refining margins, other changes to contracts or changes in the regulatory environment in which the property is located.

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

Unlike long-lived assets, goodwill must be tested for impairment at least annually, or between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. Goodwill is tested for impairment at the reporting unit level.

An estimate as to the sensitivity to earnings resulting from impairment calculations is not practicable, given the numerous assumptions (e.g. reserves, pricing and discount rates) that can materially affect our estimates. That is, unfavorable adjustments to some of the above listed assumptions may be offset by favorable adjustments in other assumptions.

Acquisitions

Under the purchase method of accounting for business combinations, the purchase price paid to acquire a business is allocated to its assets and liabilities based on the estimated fair values of the assets acquired and liabilities assumed as of the date of acquisition. The excess of the purchase price over the fair value of the net tangible and identifiable intangible assets acquired is recorded as goodwill. A significant amount of judgment is involved in estimating the individual fair values involving property, plant and equipment and identifiable intangible assets. We use all available information to make these fair value determinations and, for certain acquisitions, engage third-party consultants for assistance.

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

Derivatives

We record all derivative instruments at fair value. A large volume of our commodity derivatives are exchange-traded and require few assumptions in arriving at fair value.

In our E&P segment, we havehad two long-term contracts for the sale of natural gas in the United Kingdom that arewere accounted for as derivative instruments. These contracts, which expireexpired in September 2009, were entered into in the early 1990s in support of our investments in the East Brae field and the SAGE pipeline. The contract price isprices reset annually in October and iswere indexed to a basket of costs of living and energy commodity indices for the previous twelve months. Consequently, the prices under these contracts dodid not track forward natural gas prices. The fair value of these contracts iswas determined by applying the difference between the contract price and the U.K. forward natural gas strip price to the expected sales volumes under these contracts for the shorter of the remaining contract terms or 18 months. Adjustments to the fair value of these contracts result inwere recorded as non-cash charges or credits to income from operations. The difference between the contract price and the U.K. forward natural gas strip price may fluctuate widely from time to time and may significantly affect income from operations. A 10 percent increase in natural gas prices would decrease the fair value of these derivatives by $21 million, while a 10 percent decrease in natural gas prices would increase the fair value of these derivatives by $21 million in 2008.

Our OSM segment holdsheld crude oil options expiringwhich expired in December 2009, which2009. These options were designed to protect against price decreases on portions of future synthetic crude oil sales. Thesales and their fair value of these options iswas measured using a Black-Scholes option pricing model that usesused prices from the active commodity market and a market volatility calculated by a third-party service. A 10 percent increase

Additional information about derivatives and their valuation may be found in crude oil prices would decrease the fair value of these options by $4 million, while a 10 percent decrease in crude oil prices would increase the fair value of these options by $13 million in 2008.Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Expected Future Taxable Income

We must estimate our expected future taxable income to assess the realizability of our deferred income tax assets.

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

Index to Financial Statements

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

Additionally, we must consider any prudent and feasible tax planning strategies that might minimize the amount of deferred tax liabilities recognized or the amount of any valuation allowance recognized against deferred tax assets, if we can implement these strategies and if we expect to implement these strategies in the event the

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

Pension and Other Postretirement Benefit Obligations

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

 

the discount rate for measuring the present value of future plan obligations;

 

the expected long-term return on plan assets;

 

the rate of future increases in compensation levels; and

 

health care cost projections.

We develop our demographics and utilize the work of third-party actuaries to assist in the measurement of these obligations. We have selected different discount rates for our funded U.S. pension plans and our unfunded U.S. retiree health care plan due to the different projected liability durations of 8 years and 1312 years. The selected rates are compared to various similar bond indexes for reasonableness. In determining the assumed discount rates, our methods include a review of market yields on high-quality corporate debt and use of our third-party actuary’s discount rate modeling tool. This tool applies a yield curve to the projected benefit plan cash flows using a hypothetical Aa yield curve. The yield curve represents a series of annualized individual discount rates from 1.5 to 30 years. The bonds used are rated Aa or higher by a recognized rating agency and only non-callable bonds are included. Each issue is required to have at least $150 million par value outstanding. The top quartile bonds are selected within each maturity group to construct the yield curve.

Of the assumptions used to measure the December 31, 20082009 obligations and estimated 20092010 net periodic benefit cost, the discount rate has the most significant effect on the periodic benefit cost reported for the plans. A 0.25 percent decrease in the discount rates of 6.95.50 percent for our U.S. pension plans and 6.855.95 percent for our other U.S. postretirement benefit plans would increase pension obligations and other postretirement benefit plan obligations by $66$129 million and $21 million and would increase defined benefit pension expense and other postretirement benefit plan expense by $9$13 million and $3$2 million.

The asset rate of return assumption considers the asset mix of the plans (currently targeted at approximately 75 percent equity securities and 25 percent debt securities for the U.S. funded pension plans and 70 percent equity securities and 30 percent debt securities for the international funded pension plans), past performance and other factors. Certain components of the asset mix are modeled with various assumptions regarding inflation, debt returns and stock yields. Our assumptions arelong term asset rate of return assumption is compared to those of peerother companies and to our historical returns for reasonableness and appropriateness.reasonableness. A 0.25 percent decrease in the asset rate of return assumption would not have a significant impact on our defined benefit pension expense.

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

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

Index to Financial Statements

Note 2322 to the consolidated financial statements includes detailed information about the assumptions used to calculate the components of our defined benefit pension and other postretirement plan expense for 2009, 2008 2007 and 2006,2007, as well as the obligations and accumulated other comprehensive income reported on the balance sheets as of December 31, 2008,2009, and 2007.

In 2006, we made certain plan design changes which included an update of the mortality table used in the plans’ definition of actuarial equivalence and lump sum calculations and a 20 percent retiree cost of living adjustment for annuitants. This change increased our benefit obligations by $117 million. There were no plan design changes in 2008 or 2007.2008.

Contingent Liabilities

We accrue contingent liabilities for environmental remediation, tax deficiencies unrelatedrelated to incomeoperating taxes, product liability claims and litigation claims when such contingencies are probable and estimable. Actual costs can differ from estimates for many reasons. For instance, settlement costs for claims and litigation can vary from estimates based on differing interpretations of laws, opinions on responsibility and assessments of the amount of

damages. Similarly, liabilities for environmental remediation may vary from estimates because of changes in laws, regulations and their interpretation; additional information on the extent and nature of site contamination; and improvements in technology. Our in-house legal counsel regularly assesses these contingent liabilities. In certain circumstances, outside legal counsel is utilized.

We generally record losses related to these types of contingencies as cost of revenues or selling, general and administrative expenses in the consolidated statements of income, except for tax contingencies unrelated to income taxes, which are recorded as other taxes. For additional information on contingent liabilities, see Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies.

An estimate of the sensitivity to net income if other assumptions had been used in recording these liabilities is not practical because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, in terms of both the probability of loss and the estimates of such loss.

Accounting Standards Not Yet Adopted

In December 2008, the SEC announced that it had approved revisions to its oil and gas reporting disclosures. The new disclosure requirements include provisions that:

Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end prices. The SEC indicated that they will continue to communicate withVariable interest accounting standards were amended by the FASB staff to align their accounting standards with these rules. The FASB currently requires a single-day, year-end price for accounting purposes.

Permit companies to disclose their probable and possible reserves on a voluntary basis. In the past, proved reserves were the only reserves allowed in the disclosures.

Require companies to provide additional disclosure regarding the aging of proved undeveloped reserves.

Permit the use of reliable technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

Replace the existing “certainty” test for areas beyond one offsetting drilling unit from a productive well with a “reasonable certainty” test.

Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures regarding internal controls surrounding reserve estimation, as well as a report addressing the independence and qualifications of its reserves preparer or auditor will be mandatory.

Require separate disclosure of reserves in foreign countries if they represent more than 15 percent of total proved reserves, based on barrels of oil equivalents.

Index to Financial Statements

If finalized, we will apply the new disclosure requirements in our annual report on Form 10-K for the year ending December 31,June 2009. The new rules may not be appliedaccounting standards replace the existing quantitative-based risks and rewards calculation for determining which enterprise has a controlling financial interest in a variable interest entity with an approach focused on identifying which enterprise has the power to disclosures in quarterly reports prior todirect the first annual report in which the revised disclosures are required. We are currently in the process of evaluating the new requirements.

Also in December 2008, the FASB issued FSP FAS 132(R)-1, “Employers Disclosures about Postretirement Benefit Plan Assets” which provides guidance on an employer’s disclosures about plan assetsactivities of a defined benefit pension or other postretirement plans. This would require additional disclosures about investment policiesvariable interest entity. In addition, the concept of qualifying special-purpose entities has been eliminated and strategies, the reporting of fair value by asset category and other information about fair value measurements. The FSP is effective January 1, 2009 and early application is permitted. Upon initial application, the provisions of FSP FAS 132(R)-1 are not requiredtherefore, will now be evaluated for earlier periods that are presented for comparative purposes. We will expand our disclosuresconsolidation in accordance with FSP FAS 132(R)-1the applicable consolidation guidance. Ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity are also required. The amended variable interest accounting standard requires reconsideration for determining whether an entity is a variable interest entity when changes in ourfacts and circumstances occur such that the holders of the equity investment at risk, as a group, lack the power from voting rights or similar rights to direct the activities of the entity. Enhanced disclosures are required for any enterprise that holds a variable interest in a variable interest entity. Application will be prospective beginning in the first quarter of 2010, and for all interim and annual report on Form 10-K for the year ending December 31, 2009; however, the adoption of this standardperiods thereafter. Earlier application is prohibited. Adoption is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.

In November 2008, the FASB ratified EITF 08-6, “Equity Method Investment Accounting Considerations” (“EITF 08-6”) which clarifies howA standard to account for certain transactions involving equity method investments. The initial measurement, decreases in value and changes in the level of ownership of the equity method investment are addressed. EITF 08-6 is effective on a prospective basis for our fiscal year beginning January 1, 2009 and interim periods within the years. Early application by an entity that has previously adopted an alternative accounting policy is not permitted. Since this standard will be applied prospectively, adoption is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.

In June 2008, the FASB issued FSP on Emerging Issues Task Force (“EITF”) 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”) which provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings allocation in computing earnings per share (“EPS”) under the two-class method. FSP EITF 03-6-1 is effective January 1, 2009, and all prior-period EPS data (including any amounts related to interim periods, summaries of earnings and selected financial data) will be adjusted retrospectively to conform to its provisions. Early application of FSP EITF 03-6-1 is not permitted. Although restricted stock awards meet this definition of participating securities, we do not expect application of FSP EITF 03-6-1 to have a significant impact on our reported EPS.

In April 2008, the FASB issued FSP on FAS 142-3 (“FSP FAS 142-3”) which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under Statement of Financial Accounting Standards (“SFAS”) No. 142, “Goodwill and Other Intangible Assets.” The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset. FSP FAS 142-3 is effective on January 1, 2009, early adoption is prohibited. The provisions of FSP FAS 142-3 are to be applied prospectively to intangible assets acquired after the effective date, except for the disclosure requirements which must be applied prospectively to all intangible assets recognized as of, and subsequent to, the effective date. Since this standard will be applied prospectively, adoption is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.” This statement expands the disclosure requirements for derivative instruments to provide information regarding (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. To meet these objectives, the statement requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts and gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. This standard is effective January 1, 2009. The statement encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption. We will expand our disclosures in accordance with SFAS No. 161 beginning in the first quarter of 2009; however, the adoption of this standard is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.

In December 2007,measurements was issued by the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (“SFAS No. 141 (R)”). This statement significantly changesin January 2010. The additional disclosures required include: (1) the accounting for business combinations. Under SFAS No.141(R), an acquiring entity will be required to recognize all thedifferent classes of assets acquired,and liabilities assumed and any non-controlling

Index to Financial Statements

interest in the acquireemeasured at their acquisition-date fair value, with limited exceptions. The statement expands(2) the definition of a businesssignificant inputs and is expectedtechniques used to be applicable to more transactions than the previous business combinations standard. The statement also changes the accounting treatment for changes in control, step acquisitions, transaction costs, acquired contingent liabilities, in-process researchmeasure Level 2 and development, restructuring costs, changes in deferred tax asset valuation allowances as a result of a business combination and changes in income tax uncertainties after the acquisition date. Accounting for changes in valuation allowances for acquired deferred taxLevel 3 assets and liabilities for both recurring and nonrecurring fair value measurements, (3) the resolutiongross presentation of uncertain tax positionspurchases, sales, issuances and settlements for prior business combinations will impact tax expense insteadthe rollforward of impacting recorded goodwill. AdditionalLevel 3 activity, and (4) the transfers in and out of Levels 1 and 2. The new disclosures are also required. SFAS No. 141(R) is effective on January 1,for interim and annual reporting periods beginning after December 15, 2009, for all new business combinations. The adoption of this standard is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.

Also in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements – An Amendment of ARB No. 51.” This statement establishes new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Specifically, this statement clarifies that a noncontrolling interest in a subsidiary (sometimes called a minority interest) is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements, but separate from the parent’s equity. It requires that the amount of consolidated net income attributable to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement. SFAS No. 160 clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, this statement requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated, based on the fair value of the noncontrolling equity investment on the deconsolidation date. Additional disclosures are required that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS No. 160 is effective January 1, 2009, and early adoption is prohibited. The statement must be applied prospectively, except for the gross presentation of purchases, sales, issuances, and disclosure requirements which must be applied retrospectivelysettlements for allthe rollforward of Level 3 activity. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods presented in consolidated financial statements. We do not have significant noncontrolling interests in consolidated subsidiaries, and therefore, adoption of this standard is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.thereafter.

Index to Financial Statements

Item 7A.Quantitative and Qualitative Disclosures about Market Risk
Item 7A. Quantitative and Qualitative Disclosures about Market Risk

We are exposed to market risks related to the volatility of liquid hydrocarbon, natural gas, synthetic crude oil natural gas and refined product prices. We employ various strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations. We are also exposed to market risks related to changes in interest rates and foreign currency exchange rates. We employ various strategies, including the use of financial derivative instruments, to manage the risks related to these fluctuations. We are at risk for changes in the fair value of all of our derivative instruments; however, such risk should be mitigated by price or rate changes related to the underlying commodity or financial transaction.

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

See Notes 16 and 17 to the consolidated financial statement for more information about the fair value measurement of our derivatives, as well as the amounts recorded in our consolidated balance sheets and statements of income for those which qualify as hedges and those not designated as hedges.

Commodity Price Risk

Our strategy is to obtain competitive prices for our products and allow operating results to reflect market price movements dictated by supply and demand. However, management has the authority, within board-approved levels, to protect prices on forecasted sales, as deemed appropriate. We use a variety of commodity derivative instruments, including futures, forwards, swaps and combinations of options, as part of an overall program to manage commodity price risk in our different businesses. We also may utilize the market knowledge gained from these activities to do a limited amount of trading not directly related to our physical transactions.

OurWe regularly use commodity derivative instruments in the E&P segment primarily uses commodity derivative instruments to mitigate themanage natural gas price risk during the time that the natural gas is held in storage before it is sold or on natural gas that is purchased to be marketed with our own natural gas production. We also may use commodity derivative instruments selectivelyact opportunistically to protect against price decreasesprices on portions of our futureforecasted sales of liquid hydrocarbons orhydrocarbon, natural gas when it is deemed advantageous to do so. The majority of these derivatives are measured at fair value with a market approach using broker quotes or third-party pricing services, which have been corroborated with data from active markets, making them a Level 2 in the fair value hierarchy described by SFAS No. 157.

Unrealized gains and losses on certain natural gas contracts in the U.K. that are accounted for as derivative instruments are excluded from E&P segment income. These contracts originated in the early 1990s and expire in September 2009. The contract prices are reset annually in October based on the previous twelve-month changes in a basket of energy and other indices. Consequently, the prices under these contracts do not track forward natural gas prices. The reported fair value of the U.K. natural gas contracts is measured with an income approach by applying the difference between the contract price and the U.K. forward natural gas strip price to the expected sales volumes for the shorter of the remaining contract term or 18 months. Such an internally generated model is classified as Level 3 in the fair value hierarchy.

Our OSM segment may use commodity derivative instruments to protect against price decreases on portions of our future sales of synthetic crude oil when it is deemed advantageous to do so. The reported fair value of these crude oil options, which expirein our E&P or OSM segments. In late December 2009 is measured usingand early January 2010, we saw an opportunity to protect a Black-Scholes option pricing model, which is an income approach that utilizes prices fromportion of our 2010 forecasted sales against the active commodity market and market volatility calculated by a third-party service. Because a third-party service is used, and their inputs represent unobservable market data, these are classified as Level 3 in the fair value hierarchy.risk of declining prices.

Our RM&T segment primarily uses commodity derivative instruments on a selective basis to mitigatemanage price risk on crude oil price risk during the time that crude oil inventories are held before they are actuallyand refined into salable petroleum products.product inventories. We also use derivative instruments in our RM&T segment to manage price risk related to refined petroleum products, feedstocks used in the refining processacquisition of foreign-sourced crude oil and ethanol blended with refined petroleum products and fixed price sales contracts. Weproducts. In addition, we may use commodity derivative instruments to mitigate crude oilmanage risk on fixed price risk betweencontracts for the time that crude oil purchases are priced and when they are actuallysale of refined into salable petroleum products, but we have decreased our use of derivatives in this manner as described further below.products. The majority of these derivatives are exchange-traded contracts for crude oil, natural gas, refined products, ethanol and ethanolnatural gas measured at fair value with a market approach using the close-of-day settlement prices for the market making them a Level 1 in the fair value hierarchy. When broker accounts are covered by master netting agreements the broker deposits are netted against the value to arrive at the fair values of Level 1

Open Commodity Derivative Positions and Level 2 commodity derivatives.Sensitivity Analysis

Generally, commodityAt December 31, 2009, we held open derivative instruments usedcontracts in our E&P segment qualify for hedge accounting. Asto manage the price risk on natural gas held in storage or purchased to be marketed with our own natural gas production. These hedges were in amounts in line with normal levels of activity.

Beginning in December 2009 and into January 2010, we entered swaps on a result, we do not recognizeportion of our forecast 2010 sales of liquid hydrocarbon, natural gas and synthetic crude oil as follows:

40 percent of natural gas sales from the lower 48 states of the U.S.

80 percent of synthetic crude oil sales in net income any changesCanada, and

20 percent of liquid hydrocarbon sales in the fair value of those derivative instruments until theU.S. and Norway.

Index to Financial Statements

underlying physical transaction occurs. We have not qualified commodity derivative instruments used in our OSM or RM&T segmentsthese swaps for hedge accounting. As a result, we recognize in net income all changes in the fair value of derivative instruments used in those operations. The majority of these derivatives are measured at fair value with a market approach using broker quotes or third-party pricing services, which have been

Open Commodity Derivative Positions as

corroborated with data from active markets, making them a Level 2 in the fair value hierarchy described in the fair value accounting standards. The largest portion of December 31, 2008 and Sensitivity Analysis

At December 31, 2008,open derivative contracts in our E&P segment held open derivative contractsand OSM segments are those related to mitigate2010 forecasted sales, as listed on the price risk on natural gas held in storage or purchased to be marketed with our own natural gas production in amounts that were in line with normal levels of activity. At December 31, 2008, we had notable below:

    Term  Bbls per Day   Weighted Average
Swap Price
  Benchmark

Crude Oil

        

U.S.

  January - June 2010  35,000     $80.77  West Texas Intermediate

Norway

  January - June 2010  30,000     $80.42  Dated Brent

Canada

  January - December 2010  25,000     $82.56  West Texas Intermediate

    .

              
    Term  Mmbtu per Day(a)   Weighted Average
Swap Price
  Benchmark

Natural Gas

        

U.S. Lower 48

  January - December 2010  80,000     $5.39  CIG Rocky Mountains(b)

U.S. Lower 48

  January - December 2010  30,000     $5.59  NGPL Mid Continent(c)
(a)

Million British thermal units

(b)

Colorado Interstate Gas Co. (“CIG”)

(c)

Natural Gas Pipeline Co. of America (“NGPL”)

In the table below are the significant open derivative contracts related to our future sales of liquid hydrocarbons and natural gas and therefore remained substantially exposed to market prices of these commodities.

The OSM segment holds crude oil options which were purchased by Western for a three year period (January 2007 to December 2009). The premiums for the purchased put options had been partially offset through the sale of call options for the same three-year period, resulting in a net premium liability. Payment of the net premium liability is deferred until the settlement of the option contracts. As of December 31, 2008, the following put and call options were outstanding:

Option Expiration Date2009

Option Contract Volumes(Barrels per day):

Put options purchased

20,000

Call options sold

15,000

Average Exercise Price(Dollars per barrel):

Put options

$50.50

Call options

$90.50

In the first quarter of 2009, we sold derivative instruments at an average exercise price of $50.50 which effectively offset the open put options for the remainder of 2009.

At December 31, 2008, the number of open derivative contracts held by our RM&T segment was lower than in previous periods. Starting inat December 31, 2009. These contracts enable us to effectively correlate our commodity price exposure to the second quarter of 2008, we decreased our use of derivatives to mitigate crude oilrelevant market indicators, thereby mitigating fixed price risk between the time that domestic spot crude oil purchases are priced and when they are actually refined into salable petroleum products. Instead, we are addressing this price risk through other means, including changes in contractual terms and crude oil acquisition practices.risk.

Additionally, in previous periods, certain contracts in our RM&T segment for the purchase or sale of commodities were not qualified or designated as normal purchase or normal sales under generally accepted accounting principles and therefore were accounted for as derivative instruments. During the second quarter of 2008, as we decreased our use of derivatives, we began to designate such contracts for the normal purchase and normal sale exclusion.

    Position  Bbls per Day  Weighted Average Price  Benchmark

Crude Oil

      

Exchange-traded

  Long(a)  61,677  $76.67  NYMEX Crude

Exchange-traded

  Short(a)  (54,395 $76.85  NYMEX Crude

    .

      
    Term  Bbls per Day  Weighted Average
Swap Price
  Benchmark

Refined Products

      

Exchange-traded

  Long(b)  11,773  $2.00  NYEX Heating Oil and
RBOB

Exchange-traded

  Short(b)  (17,030 $2.00  NYEX Heating Oil and
RBOB
(a)

75 percent of these contracts expire in the first quarter of 2010.

(b)

90 percent of these contracts expire in the first quarter of 2010.

Index to Financial Statements

Sensitivity analysis of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent changesincreases and decreases in commodity prices for open commodity derivative instruments as of December 31, 2008,2009, is provided in the following table. The direction of the price change used in calculating the sensitivity amount

   Incremental Change in IFO
from a Hypothetical Price
Increase of
  Incremental Change in IFO
from a Hypothetical Price
Decrease of
 
(In millions)  10%  25%  10%  25% 

E&P Segment

     

Crude oil

  $(67 $(167 $67  $167 

Natural gas

   (22  (56  22   56 

OSM Segment

     

Crude oil

  $(75 $(188 $75  $188 

RM&T Segment

     

Crude oil

  $24  $61  $(20 $(50

Refined products

   (12  (37  12   29 

We remain at risk for each commodity reflects that which would resultpossible changes in the largest incremental decreasemarket value of commodity derivative instruments; however, such risk should be mitigated by price changes in IFO when applied to the underlying physical commodity. Effects of these offsets are not reflected in the above sensitivity analysis.

We evaluate our portfolio of commodity derivative instruments usedon an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles. Changes to hedge that commodity.

   Incremental
Decrease in IFO

Assuming a
Hypothetical
Price Change of
(a)
 
(In millions)          10%                  25%         

Commodity Derivative Instruments(b)

   

Crude oil

  $16(d) $15(d)

Natural gas

       21(c)      53(c)

Refined products

   6(d)  15(d)

(a)

We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risk should be mitigated by price changes in the underlying physical commodity. Effects of these offsets are not reflected in the sensitivity analysis. Amounts reflect hypothetical 10 percent and 25 percent changes in closing commodity prices for each open contract position at December 31, 2008. Included in the natural gas impacts above were $21 million and $53 million for hypothetical price changes of 10 percent and 25 percent related to the U.K. natural gas contracts accounted for as derivative instruments. We evaluate our portfolio of commodity derivative instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles. Changes to the portfolio after December 31, 2008,the portfolio after December 31, 2009, would cause future IFO effects to differ from those presented above.

(b)

The number of net open contracts for the E&P segment varied throughout 2008, from a low of 3 contracts on October 1, 2008, to a high of 472 contracts on January 29, 2008, and averaged 181 for the year. The number of net open contracts for the RM&T segment varied throughout 2008, from a low of 13 contracts on May 16, 2008, to a high of 15,599 contracts on March 17, 2008, and averaged 3,019 for the year. The number of net open contracts for the OSM segment varied throughout 2008, from a low of 12,775 contracts on December 31, 2008, to a high of 24,500 contracts on January 1, 2008, and averaged 18,646 for the year. The commodity derivative instruments used and positions taken will vary and, because of these variations in the composition of the portfolio over time, the number of open contracts by itself cannot be used to predict future income effects.

(c)

Price increase.

(d)

Price decrease.

Interest Rate Risk

We are impacted by interest rate fluctuations which affect the fair value of certain financial instruments. We manage our exposure to interest rate movements by utilizing financial derivative instruments. The primary objective of this program is to reduce our overall cost of borrowing by managing the mix of fixed and floating interest rate debt in our portfolio. As of December 31, 2008,2009, we had multiple interest rate swap agreements with a total notional amount of $450 million,$1.35 billion at a weighted-average, LIBOR-based, floating rate of 4.37 percent. These interest rate swaps are designated as a fair value hedge,hedges, which effectively resultedresults in an exchange of existing obligations to pay fixed interest rates for obligations to pay floating rates. The weighted average floating rate on these swap agreements is LIBOR plus 2.060 percent.

Sensitivity analysis of the projected incremental effect of a hypothetical 10 percent change in interest rates on financial assets and liabilities as of December 31, 2008,2009, is provided in the following table.

 

(In millions)  Fair
Value
  Incremental
Change in
Fair Value
 

Financial assets (liabilities)(a)

   

Receivable from United States Steel

  $438  $11 (c)

Interest rate swap agreements

  $29 (b) $(c)

Long-term debt, including amounts due within one year

  $(5,683)(b) $(358)(c)
(In millions)Fair
Value
Incremental
Change in
Fair Value

Financial assets (liabilities)(a)

Receivable from United States Steel

$360 $(c)

Interest rate swap agreements

$(b)$(c)

Long-term debt, including amounts due within one year

$(8,754)(b)$(348)(c)
(a)

Fair values of cash and cash equivalents, receivables, notes payable, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.

(b)

Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.

(c)

For receivables from United States Steel and long-term debt, this assumes a 10 percent decrease in the weighted average yield-to-maturity of our receivables and long-term debt at December 31, 2008.2009. For interest rate swap agreements, this assumes a 10 percent decrease in the effective swap rate at December 31, 2008.2009.

At December 31, 2008,2009, our portfolio of long-term debt was substantially comprised of fixed rate instruments. Therefore, the fair value of the portfolio is relatively sensitive to interest rate fluctuations. Our sensitivity to interest rate declines and corresponding increases in the fair value of our debt portfolio unfavorably affects our results of operations and cash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices above carrying value.

Index to Financial Statements

Foreign Currency Exchange Rate Risk

We manage our exposure to foreign currency exchange rates by utilizing forward and option contracts, although we had no option contracts open at December 31, 2008.contracts. The primary objective of this program is to reduce our exposure to movements in foreign currency exchange rates by locking in such rates. The following table summarizestables summarize our derivative foreign currency derivative instruments as of December 31, 2008.2009.

 

(In millions)  Period  Notional
Amount
  

Average

Forward

Rate(a)

 

Fair

Value(b)

   Settlement Period  Notional
Amount
  Weighted Average
Forward Rate
(a)
 

Foreign Currency Forwards

             

Dollar (Canada)

  January 2009 – February 2010  $564  1.063(d) $(68)  January 2010 - February 2010  $24  1.062 (b) 

Euro

  January 2009 – April 2010  $27  1.358(d) $1   March 2010 - June 2010  $3  1.278 (c) 

Kroner (Norway)

  January 2009 – November 2009  $500  6.263(c) $(8)

(a)

Rates shown are weighted average forward rates for the period.

(b)

Fair value was based on market rates.

(c)

U.S. dollar to foreign currency.

(d)(c)

Foreign currency to U.S. dollar.

The aggregate cash flow effect

(In millions)  Period  Notional
Amount
  Weighted Average
Exercise Price
(a)
 

Foreign Currency Options

      

Dollar (Canada)

  January 2010 - September 2010  $144  1.042 (b) 
(a)

Rates shown are weighted average exercise prices for the period.

(b)

U.S. dollar to foreign currency.

Sensitivity analysis of the incremental effects on foreign currency contractsIFO of a hypothetical 10 percent change toincreases and decreases in exchange rates atfor open foreign currency derivative instruments as of December 31, 2008, would be $52 million.2009, is provided in the following table:

   Incremental Change in IFO from a
         Hypothetical Exchange Rate         
(In millions)  

Increase of

10%

   

Decrease of

10%

Forwards

  $            (3  $                3

Options

   (3   9
         

Total

  $(6  $12

Counterparty Risk

We are also exposed to creditfinancial risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is reviewed and master netting agreements are used when appropriate.

Safe Harbor

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

Index toItem 8. Financial Statements

Item 8.Financial Statements and Supplementary Data
and Supplementary Data

Index

 

   Page

Management’s Responsibilities for Financial Statements

  7472

Management’s Report on Internal Control Over Financial Reporting

  7472

Report of Independent Registered Public Accounting Firm

  7573

Audited Consolidated Financial Statements

  

Consolidated Statements of Income

  7674

Consolidated Balance Sheets

  7775

Consolidated Statements of Cash Flows

  7876

Consolidated Statements of Stockholders’ Equity

  7977

Consolidated Statements of Comprehensive Income

78

Notes to Consolidated Financial Statements

  8079

Select Quarterly Financial Data (Unaudited)

  121125

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

  122126

Supplemental Statistics (Unaudited)

  129134

Index to Financial Statements

Management’s Responsibilities for Financial Statements

To the Stockholders of Marathon Oil Corporation:

The accompanying consolidated financial statements of Marathon Oil Corporation and its consolidated subsidiaries (“Marathon”) are the responsibility of management and have been prepared in conformity with accounting principles generally accepted in the United States of America. They necessarily include some amounts that are based on best judgments and estimates. The financial information displayed in other sections of this Annual Report on Form 10-K is consistent with these consolidated financial statements.

Marathon seeks to assure the objectivity and integrity of its financial records by careful selection of its managers, by organizational arrangements that provide an appropriate division of responsibility and by communications programs aimed at assuring that its policies and methods are understood throughout the organization.

The Board of Directors pursues its oversight role in the area of financial reporting and internal control over financial reporting through its Audit and Finance Committee. This Committee, composed solely of independent directors, regularly meets (jointly and separately) with the independent registered public accounting firm, management and internal auditors to monitor the proper discharge by each of their responsibilities relative to internal accounting controls and the consolidated financial statements.

 

/s/ Clarence P. Cazalot, Jr.

 /s/ Janet F. Clark /s/ Michael K. Stewart

President and

Chief Executive Officer

 

Executive Vice President

and Chief Financial

Officer

 

Vice President, Accounting

Chief Executive Officerand Chief Financial Officer

and Controller

Management’s Report on Internal Control over Financial Reporting

To the Stockholders of Marathon Oil Corporation:

Marathon’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a – 15(f) under the Securities Exchange Act of 1934). An evaluation of the design and effectiveness of our internal control over financial reporting, based on the framework inInternal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer. Based on the results of this evaluation, Marathon’s management concluded that its internal control over financial reporting was effective as of December 31, 2008.2009.

The effectiveness of Marathon’s internal control over financial reporting as of December 31, 20082009 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

 

/s/ Clarence P. Cazalot, Jr.

 /s/ Janet F. Clark

President and

Chief Executive Officer

 

Executive Vice President

Chief Executive Officer

and Chief Financial

Officer

Index to Financial Statements

Report of Independent Registered Public Accounting Firm

To the Stockholders of Marathon Oil Corporation:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Marathon Oil Corporation and its subsidiaries (the “Company”) at December 31, 2008,2009, and 2007,2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008,2009, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008,2009, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for purchases and sales of inventory with the same counterparty and defined benefit pension and other postretirement plans in 2006.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
Houston, Texas
February 27, 2009

Index to Financial Statements
Houston, Texas

February 26, 2010

MARATHON OIL CORPORATION

Consolidated Statements of Income

 

(In millions, except per share data)  2008 2007 2006   2009 2008 2007 

Revenues and other income:

        

Sales and other operating revenues (including consumer excise taxes)

  $75,314  $62,800  $57,973   $    53,373  $    74,875  $    62,471 

Revenue from matching buy/sell transactions

      127   5,457 

Sales to related parties

   1,879   1,625   1,466    97   1,879   1,625 

Income from equity method investments

   765   545   391    298   765   545 

Net gain on disposal of assets

   423   36   77    205   423   36 

Other income

   188   74   85    166   188   74 
                    

Total revenues and other income

   78,569   65,207   65,449    54,139   78,130   64,751 

Costs and expenses:

        

Cost of revenues (excludes items below)

   59,817   49,104   42,415    40,560   59,677   49,129 

Purchases related to matching buy/sell transactions

      149   5,396 

Purchases from related parties

   715   363   210    485   715   363 

Consumer excise taxes

   5,065   5,163   4,979    4,924   5,065   5,163 

Depreciation, depletion and amortization

   2,178   1,613   1,518    2,623   2,129   1,564 

Goodwill impairment

   1,412          -    1,412   -  

Selling, general and administrative expenses

   1,387   1,327   1,228    1,263   1,382   1,315 

Other taxes

   482   394   371    387   482   393 

Exploration expenses

   490   454   365    307   489   454 
                    

Total costs and expenses

   71,546   58,567   56,482    50,549   71,351   58,381 
          

Income from operations

   3,590   6,779   6,370 

Income from operations

   7,023   6,640   8,967 

Net interest and other financing income (costs)

   (50)  41   37    (149  (28  33 

Gain on foreign currency derivative instruments

      182       -    -    182 

Loss on early extinguishment of debt

      (17)  (35)   -    -    (17

Minority interests in loss of Equatorial Guinea LNG Holdings Limited

      3   10 
          
          

Income from continuing operations before income taxes

   6,973   6,849   8,979    3,441   6,751   6,568 

Provision for income taxes

   3,445   2,901   4,022    2,257   3,367   2,802 
          
          

Income from continuing operations

   3,528   3,948   4,957    1,184   3,384   3,766 

Discontinued operations

      8   277    279   144   190 
                    

Net income

  $3,528  $3,956  $5,234   $1,463  $3,528  $3,956 

Per Share Data

        

Basic:

        

Income from continuing operations

  $4.97  $5.72  $6.92   $1.67  $4.77  $5.46 

Discontinued operations

  $  $0.01  $0.39   $0.39  $0.20  $0.27 

Net income

  $4.97  $5.73  $7.31   $2.06  $4.97  $5.73 

Diluted:

        

Income from continuing operations

  $4.95  $5.68  $6.87   $1.67  $4.75  $5.42 

Discontinued operations

  $  $0.01  $0.38   $0.39  $0.20  $0.27 

Net income

  $4.95  $5.69  $7.25   $2.06  $4.95  $5.69 

Dividends paid

  $0.96  $0.96  $0.92 

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

Index to Financial Statements

MARATHON OIL CORPORATION

Consolidated Balance Sheets

 

  December 31,   December 31, 
(In millions, except per share data)  2008 2007   2009 2008 

Assets

      

Current assets:

      

Cash and cash equivalents

  $1,285  $1,199   $        2,057  $        1,285 

Receivables, less allowance for doubtful accounts of $6 and $3

   3,094   5,672 

Receivables, less allowance for doubtful accounts of $14 and $6

   4,677   3,094 

Receivables from United States Steel

   23   22    22   23 

Receivables from related parties

   33   79    60   33 

Inventories

   3,507   3,277    3,622   3,507 

Other current assets

   461   338    199   461 
              

Total current assets

   8,403   10,587    10,637   8,403 

Equity method investments

   2,080   2,630    1,970   2,080 

Receivables from United States Steel

   469   485    324   469 

Property, plant and equipment, less accumulated depreciation, depletion and amortization of $15,581 and $14,857

   29,414   24,675 

Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $17,185 and $15,581

   32,121   29,414 

Goodwill

   1,447   2,899    1,422   1,447 

Other noncurrent assets

   873   1,470    578   873 
              

Total assets

  $42,686  $42,746   $47,052  $42,686 
 

Liabilities

      

Current liabilities:

      

Accounts payable

  $4,712  $7,567   $6,982  $4,712 

Payables to related parties

   21   44    64   21 

Payroll and benefits payable

   400   417    399   400 

Accrued taxes

   1,133   712    547   1,133 

Deferred income taxes

   561   547    403   561 

Other current liabilities

   828   842    566   828 

Long-term debt due within one year

   98   1,131    96   98 
              

Total current liabilities

   7,753   11,260    9,057   7,753 

Long-term debt

   7,087   6,084    8,436   7,087 

Deferred income taxes

   3,330   3,389    4,104   3,330 

Defined benefit postretirement plan obligations

   1,609   1,092    2,056   1,609 

Asset retirement obligations

   963   1,131    1,099   963 

Payable to United States Steel

   4   5    5   4 

Deferred credits and other liabilities

   531   562    385   531 
              

Total liabilities

   21,277   23,523    25,142   21,277 

Commitments and contingencies

      

Stockholders’ Equity

      

Preferred stock – 5 million shares issued, 3 million and 5 million shares outstanding (no par value, 6 million shares authorized)

       

Preferred stock – 5 million shares issued, 1 million and 3 million shares
outstanding (no par value, 6 million shares authorized)

   -    -  

Common stock:

      

Issued – 767 million and 765 million shares (par value $1 per share, 1.1 billion shares authorized)

   767   765 

Securities exchangeable into common stock – 5 million shares issued, 3 million and 5 million shares outstanding (no par value, unlimited shares authorized)

       

Held in treasury, at cost – 61 million and 55 million shares

   (2,720)  (2,384)

Issued – 769 million and 767 million shares (par value $1 per share,
1.1 billion shares authorized)

   769   767 

Securities exchangeable into common stock – 5 million shares issued,
1 million and 3 million shares outstanding (no par value, unlimited
shares authorized)

   -    -  

Held in treasury, at cost – 61 million and 61 million shares

   (2,706  (2,720

Additional paid-in capital

   6,696   6,679    6,738   6,696 

Retained earnings

   17,259   14,412    18,043   17,259 

Accumulated other comprehensive loss

   (593)  (249)   (934  (593
              

Total stockholders’ equity

   21,409   19,223    21,910   21,409 
              

Total liabilities and stockholders’ equity

  $42,686  $42,746   $47,052  $42,686 
 

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

Index to Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows

 

(In millions)  2008 2007 2006   2009 2008 2007 

Increase (decrease) in cash and cash equivalents

        

Operating activities:

        

Net income

  $3,528  $3,956  $5,234   $      1,463  $      3,528  $      3,956 

Adjustments to reconcile net income to net cash provided by operating activities:

        

Loss on early extinguishment of debt

      17   35    -    -    17 

Income from discontinued operations

      (8)  (277)

Discontinued operations

   (279  (144  (190

Deferred income taxes

   93   (347)  268    1,072   94   (352

Minority interests in loss of Equatorial Guinea LNG Holdings Limited

      (3)  (10)

Goodwill impairment

   1,412          -    1,412   -  

Depreciation, depletion and amortization

   2,178   1,613   1,518    2,623   2,129   1,564 

Pension and other postretirement benefits, net

   130   32   (426)   (116  133   33 

Exploratory dry well costs and unproved property impairments

   170   233   166    81   170   233 

Net gain on disposal of assets

   (423)  (36)  (77)   (205  (423  (36

Equity method investments, net

   62   (43)  (200)   42   62   (43

Changes in the fair value of U.K. natural gas contracts

   (219)  232   (454)

Changes in the fair value of derivative instruments

   (43  (312  206 

Changes in:

        

Current receivables

   2,619   (1,338)  (525)   (1,632  2,612   (1,329

Inventories

   (274)  (90)  (133)   (126  (246  (89

Current accounts payable and accrued liabilities

   (2,465)  2,312   244    2,169   (2,532  1,677 

All other, net

   (29)  (9)  55 

All other operating, net

   161   50   24 
                    

Net cash provided by continuing operations

   6,782   6,521   5,418    5,210   6,533   5,671 

Net cash provided by discontinued operations

         70    58   219   229 
                    

Net cash provided by operating activities

   6,782   6,521   5,488    5,268   6,752   5,900 
                    

Investing activities:

        

Capital expenditures

   (7,146)  (4,466)  (3,433)

Additions to property, plant and equipment

   (6,231  (6,989  (3,757

Acquisitions

      (3,926)  (741)   -    -    (3,926

Disposal of assets

   999   137   134    865   999   137 

Disposal of discontinued operations

         832 

Trusteed funds – withdrawals

   752   280    

Investments – loans and advances

   (117)  (114)  (17)

Investments – repayments of loans and return of capital

   93   59   298 

Trusteed funds—withdrawals

   16   752   280 

Investments—loans and advances

   (23  (117  (114

Investments—repayments of loans and return of capital

   94   93   59 

Deconsolidation of Equatorial Guinea LNG Holdings Limited

      (37)      -    -    (37

Investing activities of discontinued operations

         (45)   (84  (127  (88

All other, net

   (16)  (35)  17 

All other investing, net

   125   (16  (35
                    

Net cash used in investing activities

   (5,435)  (8,102)  (2,955)   (5,238  (5,405  (7,481
                    

Financing activities:

        

Borrowings

   1,247   2,261       1,491   1,247   2,261 

Debt issuance costs

   (7)  (20)      (11  (7  (20

Debt repayments

   (1,366)  (694)  (501)   (81  (1,366  (694

Issuance of common stock

   9   27   50    4   9   27 

Purchases of common stock

   (402)  (822)  (1,698)   -    (402  (822

Excess tax benefits from stock-based compensation arrangements

   7   30   35    -    7   30 

Dividends paid

   (681)  (637)  (547)   (679  (681  (637

Contributions from minority shareholders of Equatorial Guinea LNG Holdings Limited

      39   80    -    -    39 
                    

Net cash provided by (used in) financing activities

   (1,193)  184   (2,581)   724   (1,193  184 
                    

Effect of exchange rate changes on cash

   (68)  11   16 
          

Effect of exchange rate changes on cash:

    

Continuing operations

   19   (44  9 

Discontinued operations

   (1  (24  2 

Net increase (decrease) in cash and cash equivalents

   86   (1,386)  (32)   772   86   (1,386

Cash and cash equivalents at beginning of period

   1,199   2,585   2,617    1,285   1,199   2,585 
                    

Cash and cash equivalents at end of period

  $1,285  $1,199  $2,585   $2,057  $1,285  $1,199 

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

Index to Financial Statements

MARATHON OIL CORPORATION

Consolidated Statements of Stockholders’ Equity

 

  Stockholders’ Equity  Shares 
(In millions, except per share data) 2008  2007  2006  2008  2007  2006 

Preferred stock issued

      

Balance at beginning of year

 $  $  $   5       

Issuances

              5    

Exchanges

           (2)      
                        

Balance at end of year

 $  $  $   3   5    

Common stock

      

Issued

      

Balance at beginning of year

 $765  $736  $734   765   736   734 

Issuances

  2   29   2   2   29   2 
                        

Balance at end of year

 $767  $765  $736   767   765   736 

Securities exchangeable for common stock

      

Balance at beginning of year

 $  $  $   5       

Issuances

              5    

Exchanges

           (2)      
                        

Balance at end of year

 $  $  $   3   5    

Held in treasury

      

Balance at beginning of year

 $(2,384) $(1,638) $(8)  (55)  (40) 

Repurchases

  (412)  (845)  (1,712)  (8)  (17)  (42)

Reissuances for employee stock plans

  76   99   82   2   2   2 
                        

Balance at end of year

 $(2,720) $(2,384) $(1,638)  (61)  (55)  (40)
           Comprehensive Income 
               2008  2007  2006 

Additional paid-in capital

      

Balance at beginning of year

 $6,679  $4,784  $4,744    

Stock issuances

  (61)  1,844   (8)   

Stock-based compensation

  78   51   48    
               

Balance at end of year

 $6,696  $6,679  $4,784    

Unearned compensation

      

Balance at beginning of year

 $  $  $(20)   

Change in accounting principle

        20    
               

Balance at end of year

 $  $  $    

Retained earnings

      

Balance at beginning of year

 $14,412  $11,093  $6,406    

Net income

  3,528   3,956   5,234  $3,528  $3,956  $5,234 

Dividends paid ($0.96 , $0.92 and $0.76 per share)

  (681)  (637)  (547)   
               

Balance at end of year

 $17,259  $14,412  $11,093    

Accumulated other comprehensive loss

      

Minimum pension liability adjustments

      

Balance at beginning of year

 $  $  $(141)   

Changes during year, net of tax of $–, $–, and $74

 

  114     114 

Reclassification to defined benefit postretirement plans

        27    
               

Balance at end of year

 $  $  $    

Defined benefit postretirement plans

      

Balance at beginning of year

 $(263) $(375) $    

Actuarial gain (loss), net of tax of $146, $87

  (248)  110      (248)  110    

Prior service costs, net of tax of $2, $1

  2   2      2   2    

Reclassification from minimum pension liability adjustments

        (27)   

Change in accounting principle, net of tax of $289

        (348)   
               

Balance at end of year

 $(509) $(263) $(375)   

Other

      

Balance at beginning of year

 $14  $7  $(10)   

Changes during year, net of tax of $43, $4, and $9

  (98)  7   17   (98)  7   12 
               

Balance at end of year

 $(84) $14  $7    
               

Total at end of year

 $(593) $(249) $(368)            

Comprehensive income

             $3,184  $4,075  $5,360 

Total stockholders’ equity

 $21,409  $19,223  $14,607             
(In millions) Preferred
Stock
  Common
Stock
 

Securities
Exchangeable

for Common

Stock

  Treasury
Stock
  Additional
Paid-in
Capital
  Retained
Earnings
  Accumulated
Other
Comprehensive
Income (Loss)
  Total
Stockholders’
Equity
 

Balance as of January 1, 2007

 $            -   $      736 $                    -   $(1,638 $    4,784  $ 11,093  $(368 $      14,607 

Shares issued - acquisition

  -    29  -    -    1,844   -                        -    1,873 

Shares issued - stock based
    compensation

  -    -  -             99   -    -    -    99 

Shares repurchased

  -    -  -    (845  -    -    -    (845

Stock-based compensation

  -    -  -    -    51   -    -    51 

Net income

  -    -  -    -    -    3,956   -    3,956 

Other comprehensive income(loss)

  -    -  -    -     -    119   119 

Dividends paid

  -    -  -    -    -    (637  -    (637
                               

Balance as of December 31, 2007

 $-   $765 $-   $(2,384 $6,679  $14,412  $(249 $19,223 

Shares issued - stock based
    compensation

  -    -  -    76   (63  -    -    13 

Shares exchanged

  -    2  -    -    2   -    -    4 

Shares repurchased

  -    -  -    (412  -    -    -    (412

Stock-based compensation

  -    -  -    -    78   -    -    78 

Net income

  -    -  -    -    -    3,528   -    3,528 

Other comprehensive income(loss)

  -    -  -    -    -    -    (344  (344

Dividends paid

  -    -  -    -    -    (681  -    (681
                               

Balance as of December 31, 2008

 $-   $767 $-   $(2,720 $6,696  $17,259  $(593 $21,409 

Shares issued - stock based
    compensation

  -    -  -    20   (9  -    -    11 

Shares exchanged

  -    2  -    -    (2  -    -    -  

Shares repurchased

  -    -  -    (6  -    -    -    (6

Stock-based compensation

  -    -  -    -    53   -    -    53 

Net income

  -    -  -    -    -    1,463   -    1,463 

Other comprehensive income(loss)

  -    -  -    -    -    -    (341  (341

Dividends paid

  -    -  -    -    -    (679  -    (679
                               

Balance as of December 31, 2009

 $-   $769 $-   $(2,706 $6,738  $18,043  $(934 $21,910 
  

(Shares in millions)

  
 
Preferred
Stock
  
  
  
 
Common
Stock
  
 
 
 
Securities
Exchangeable
for Common
Stock
  
  
  
  
  
 
Treasury
Stock
  
  
    
      

Balance as of January 1, 2007

  -    736  -    (40    

Shares issued - acquisition

  5   29  5   -      

Shares issued - stock based
    compensation

  -    -  -    2     

Shares repurchased

  -    -  -    (17    
                   

Balance as of December 31, 2007

  5   765  5   (55    

Shares issued - stock based
    compensation

  -    -  -    2     

Shares exchanged

  (2  2  (2  -      

Shares repurchased

  -    -  -    (8    
                   

Balance as of December 31, 2008

  3   767  3   (61    

Shares issued - stock based
    compensation

  -    -  -    -      

Shares exchanged

  (2  2  (2  -      
                   

Balance as of December 31, 2009

  1   769  1   (61    
  

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

MARATHON OIL CORPORATION

Index to FinancialConsolidated Statements

of Comprehensive Income

(In millions)  2009  2008  2007 

Net income

  $    1,463  $    3,528  $    3,956 

Other comprehensive income (loss)

    

Post-retirement and post-employment plans

    

Change in actuarial gain (loss)

   (564  (397  194 

Income tax benefit (provision) on post-retirement and post-employment plans

   208   147   (87
             

Post-retirement and post-employment plans, net of tax

   (356  (250  107 

Derivative hedges

    

Net unrecognized gain (loss)

   24   (91  13 

Income tax benefit (provision) on derivatives

   (12  24   (4
             

Derivative hedges, net of tax

   12   (67  9 

Foreign currency translation and other

    

Unrealized gain (loss)

   4   (43  5 

Income tax benefit (provision) on foreign currency translation and other

   (1  16   (2
             

Foreign currency translation and other, net of tax

   3   (27  3 

Other comprehensive income (loss)

   (341  (344  119 
             
Comprehensive income  $    1,122  $    3,184  $    4,075 

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

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

1.    Summary of Principal Accounting Policies

We are engaged in worldwide exploration, production and marketing of liquid hydrocarbons and natural gas; oil sands mining and bitumen upgrading in Canada; domestic refining, marketing and transportation of crude oil and petroleum products; and worldwide marketing and transportation of products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol.

Principles applied in consolidation – These consolidated financial statements include the accounts of our majority-owned, controlled subsidiaries and variable interest entities for which we are the primary beneficiary.

Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting and are carried at our share of net assets plus loans and advances. This includes entities in which we hold majority ownership but the minority shareholders have substantive participating rights in the investee. Income from equity method investments represents our proportionate share of net income generated by the equity method investees. Differences in the basis of the investments and the separate net asset value of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets, except for the excess related to goodwill.

Equity method investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net income.

Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis.

CertainReclassifications – We have revised prior years amounts of capital expenditures in the consolidated statement of cash flows. The presentation within the consolidated statement of cash flows for additions to property, plant and equipment reflects capital expenditures on a cash basis. The following reflects the reclassifications of prior years’ datamade:

(in millions)  2008  2007 

Capital expenditures, previously reported

  $(7,146 $(4,466

Reclassification of capital accruals

                30               621 
         

Additions to property, plant and equipment, including discontinued operations

  $(7,116 $(3,845

The corresponding offsets to the amounts above have been made to conform to 2008 classifications.reflected within cash provided by operating activities through change in current accounts payable and accrued liabilities.

(in millions)  2008  2007 

Cash flow from operations, previously reported

  $        6,782  $         6,521 

Reclassification of capital accruals

   (30  (621
         

Cash flow from operations

  $6,752  $5,900 

Use of estimates – The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods.

Foreign currency transactions– The U.S. dollar is the functional currency of our foreign operating subsidiaries. Foreign currency transaction gains and losses are included in net income.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Revenue recognition – Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. Costs associated with revenues are recorded in cost of revenues.

In the continental United States, production volumes of liquid hydrocarbons and natural gas are sold immediately and transported via pipeline. In Alaska and international locations, liquid hydrocarbon and natural gas production volumes may be stored as inventory and sold at a later time. In Canada, mined bitumen is first processed through the Scotford upgrader and then sold as synthetic crude oil. Both bitumen and synthetic crude oil may be stored as inventory.

We follow the sales method of accounting for crude oil and natural gas production imbalances and would recognize a liability if the existing proved reserves were not adequate to cover an imbalance. Imbalances have not been significant in the periods presented.

Rebates from vendors are recognized as a reduction of cost of revenues when the initiating transaction occurs. Incentives that are derived from contractual provisions are accrued based on past experience and recognized in cost of revenues.

Matching buy/sell transactions – In a typical matching buy/sell transaction, we enter into a contract to sell a particular quantity and quality of crude oil or refined product at a specified location and date to a particular

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

counterparty, and simultaneously agrees to buy a particular quantity and quality of the same commodity at a specified location on the same or another specified date from the same counterparty. Prior to April 1, 2006, we recorded all matching buy/sell transactions in both revenues and cost of revenues as separate sale and purchase transactions. Effective April 1, 2006, upon adoption of the provisions of Emerging Issues Task Force (“EITF”) Issue No. 04-13, we account for matching buy/sell arrangements entered into or modified as exchanges of inventory, except for those arrangements accounted for as derivative instruments.

See Note 2 for further information regarding adoption of EITF Issue No. 04-13.

Consumer excise taxes – We are required by various governmental authorities, including countries, states and municipalities, to collect and remit taxes on certain consumer products. Such taxes are presented on a gross basis in revenues and costs and expenses in the consolidated statements of income.

Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with original maturities of three months or less.

Accounts receivable and allowance for doubtful accounts – Our receivables primarily consist of customer accounts receivable, including proprietary credit card receivables. The allowance for doubtful accounts is the best estimate of the amount of probable credit losses in our proprietary credit card receivables. We determine the allowance based on historical write-off experience and the volume of proprietary credit card sales. We review the allowance quarterly and past-due balances over 180 days are reviewed individually for collectability. All other customer receivables are recorded at the invoiced amounts and generally do not bear interest. Account balances for these customer receivables are charged directly to bad debt expense when it becomes probable the receivable will not be collected.

Inventories – Inventories are carried at the lower of cost or market value. Cost of inventories is determined primarily under the last-in, first-out (“LIFO”) method.

We may enter into a contract to sell a particular quantity and quality of crude oil or refined product at a specified location and date to a particular counterparty, and simultaneously agree to buy a particular quantity and quality of the same commodity at a specified location on the same or another specified date from the same counterparty. We account for such matching buy/sell arrangements entered into or modified as exchanges of inventory, except for those arrangements accounted for as derivative instruments.

Derivative instruments – We may use derivatives to manage a portion of our exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk. Changes in theWe also have limited authority to use selective derivative instruments that assume market risk. All derivative instruments are recorded at fair value ofvalue. Commodity derivatives are recognized immediately inreflected on our consolidated balance sheet on a net income unless the derivative qualifiesbasis by brokerage firm, as a hedge of future cash flows or certain foreign currency exposures.they are governed by master netting agreements. Cash flows related to derivatives used to manage commodity price risk, interest rate risk and foreign currency exchange rate risk related to operating expenditures are classified in operating activities with the underlying hedged transactions. Cash flows related to derivatives used to manage exchange rate risk related to capital expenditures denominated in foreign currencies are classified in investing activities with the underlying hedged transactions.

For derivatives qualifying asCash flow hedges of future cash flows or certain – We may use foreign currency exposures, theforwards and options to manage foreign currency risk associated with anticipated transactions, primarily expenditures for capital projects denominated in certain foreign

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

currencies, and designate them as cash flow hedges. The effective portion of any changes in fair value is recognized in other comprehensive income (“OCI”) and is reclassified to net income when the underlying forecasted transaction is recognized in net income. Any ineffective portion of such hedges is recognized in net incomeinterest and financing costs as it occurs. For a discontinued cash flow hedges,hedge, prospective changes in the fair value of the derivative are recognized in net income. The accumulated gain or loss recognized in other comprehensive incomeOCI at the time a hedge is discontinued continues to be deferred until the original forecasted transaction occurs. However, if it is determined that the likelihood of the original forecasted transaction occurring is no longer probable, the entire accumulated gain or loss recognized in other comprehensive incomeOCI is immediately reclassified into net income.

ForWe may use interest rate derivative instruments to manage the risk of interest rate changes during the period prior to anticipated borrowings and designate them as cash flow hedges. No such derivatives designated aswere outstanding at December 31, 2009.

Fair value hedges of – We may use interest rate swaps to manage our exposure to interest rate risk associated with fixed interest rate debt in our portfolio and we may use commodity derivative instruments to manage the fair value of recognized assets, liabilities or firm commitments, changesprice risk on natural gas that we purchase to be marketed with our natural gas production. Changes in the fair values of both the hedged item and the related derivative are recognized immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect is to report in net income the extent to which the hedge is not effective in achieving offsetting changes in fair value.

In the E&P segment, two natural gas delivery commitment contracts in the United Kingdom are classifiedDerivatives not designated as derivative instruments. These contracts contain pricing provisionshedges – Derivatives that are not clearlydesignated as hedges primarily include commodity derivatives used to manage price risk on: (1) the forecast sale of crude oil, natural gas and closely related tosynthetic crude oil that we produce, (2) inventories, (3) fixed price sales of refined products, (4) the underlying commodityacquisition of foreign-sourced crude oil, and therefore must be accounted(5) the acquisition of ethanol for as derivative instruments.

As market conditions change, we may use selective derivative instruments that assume market risk. For derivative instruments that are classified as trading, changesblending with refined products. Changes in the fair value of derivatives not designated as hedges are recognized immediately in net

Index to Financial Statements

MARATHON OIL CORPORATION income.

NotesContingent credit featuresOur derivative instruments contain no significant contingent credit features.

Concentrations of credit risk –All of our financial instruments, including derivatives, involve elements of credit and market risk. The most significant portion of our credit risk relates to Consolidated Financial Statements

incomenonperformance by counterparties. The counterparties to our financial instruments consist primarily of major financial institutions and are classified as other income. Any premium received is amortized into net incomecompanies within the energy industry. To manage counterparty risk associated with financial instruments, we select and monitor counterparties based on our assessment of their financial strength and on credit ratings, if available. Additionally, we limit the underlying settlement termslevel of the derivative position. All related effects of a trading strategy, including physical settlement of the derivative position, are recognized in net income and classified as other income.exposure with any single counterparty.

Property, plant and equipment – We use the successful efforts method of accounting for oil and gas producing activities.

Property acquisition costs – Costs to acquire mineral interests in oil and natural gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves thatbut cannot yet be classified as proved are capitalized if (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (2) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended well costs is monitored continuously and reviewed not less than quarterly.

Capitalized costs related to oil sands mining are those specifically related to the acquisition, exploration, development and construction of mining projects. Development costs to expand the capacity of existing mines are also capitalized.

Depreciation, Depletiondepletion and Amortizationamortization – Capitalized costs of producing oil and natural gas properties are depreciated and depleted on a units-of-production basis based on estimated proved oil and gas reserves.

Oil sands mining properties and the related bitumen upgrading facility are depreciated and depleted on a units-of-production basis. Mobile equipment used in mining operations is depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 10 to 20 years.

Support equipment and other property, plant and equipment related to oil and gas producing and oil sands mining activities are depreciated on a straight-line basis over their estimated useful lives which range from 5 to 39 years.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Property, plant and equipment unrelated to oil and gas producing or oil sands mining activities is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 42 years.

Impairments – We evaluate our oil and gas producing properties for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure. Impairment of proved properties is required when the carrying value exceeds the related undiscounted future net cash flows based on total proved and risk-adjusted probable and possible reserves. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows based on total proved and risk-adjusted probable and possible reserves or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors in addition to the use of an undiscounted future net cash flow approach. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage are also considered. Unproved property investments deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows. Impairment expense for unproved oil and natural gas properties is reported in exploration expenses.

Assets related to oil sands mining are reviewed for impairment whenever events or changes in circumstances indicate that the carrying value may not be recoverable from estimated undiscounted future net cash flows based on total bitumen reserves. Assets deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Refining, marketing and transportation assets are reviewed for impairment whenever events or changes in the circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset.

Dispositions – When property, plant and equipment depreciated on an individual basis are sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale. Proceeds from the disposal of property, plant and equipment depreciated on a group basis are credited to accumulated depreciation, depletion and amortization with no immediate effect on net income.

Goodwill – Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Such goodwill is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to operating expense.

Major maintenance activities – Costs are incurred for planned major refinery maintenance (“turnarounds”).maintenance. These types of costs include contractor repair services, materials and supplies, equipment rentals and our labor costs. Such costs are expensed in the period incurred.

Environmental costs – Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. We provide for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed and

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

determinable. If recoveries of remediation costs from third parties are probable, a receivable is recorded and is discounted when the estimated amount is reasonably fixed and determinable.

Asset retirement obligations – The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Our asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities. Asset retirement obligations for such facilities include costs to dismantle and relocate or dispose of production platforms, gathering systems, wells and related structures and restoration costs of land and seabed, including those leased. Estimates of these costs are developed for each property based on the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering professionals. Asset retirement obligations have not been recognized for certain of our international oil and gas producing facilities as we currently do not have a legal obligation associated with the retirement of those facilities.

To a lesser extent, asset retirement obligations related to dismantlement, site restoration of oil sands mining facilities and, conditional asset retirement obligations for removal and disposal of fire-retardant material from certain refining facilities have also been recognized. The amounts recorded for such obligations are based on the most probable current cost projections. Asset retirement obligations have not been recognized for the removal of materials and equipment from or the closure of certain refinery, pipeline, marketing and bitumen upgrading assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate.

Current inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for oil and gas production and oil sands mining facilities and on a straight-line basis for refining facilities, while accretion escalates over the lives of the assets.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Deferred taxes – Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several interrelated factors. These factors include our expectation to generate sufficient future taxable income including future foreign source income, tax credits, operating loss carryforwards and management’s intent regarding the permanent reinvestment of the income from certain foreign subsidiaries.

Stock-based compensation arrangements – The fair value of stock options, stock options with tandem stock appreciation rights (“SARs”) and stock-settled SARs (“stock option awards”) is estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value calculated and ultimately, the amount of expense that is recognized over the life of the stock option award. Of the required assumptions, the expected life of the stock option award and the expected volatility of our stock price have the most significant impact on the fair value calculation. We have utilized historical data and analyzed current information which reasonably support these assumptions.

The fair value of our restricted stock awards and common stock units is determined based on the fair market value of Marathon common stock on the date of grant.

Our stock-based compensation expense is recognized based on management’s best estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods. Unearned stock-based compensation is charged to stockholders’ equity when restricted stock awards are granted. Compensation expense is recognized over the vesting period and is adjusted if conditions of the restricted stock award are not met. Options with tandem SARs are classified as a liability and are remeasured at fair value each reporting period until settlement.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

2. New    Accounting Standards

FSP FIN 39-1Recently Adopted– In April 2007,

Oil and Gas Reserve Estimation and Disclosure standards were issued by the Financial Accounting Standards Board (“FASB”) in January 2010, which aligns the FASB’s reporting requirements with the below requirements of the Securities and Exchange Commission (“SEC”). The FASB also addresses the impact of changes in the SEC’s rules and definitions on accounting for oil and gas producing activities. Similar to the SEC requirements, the FASB requirements were effective for periods ending on or after December 31, 2009. Initial adoption did not have an impact on our consolidated results of operations, financial position or cash flows; however, there will be an impact on the amount of depreciation, depletion and amortization expense recognized in future periods. We expect this effect as compared to prior periods will not be significant. The required disclosures are presented in Supplementary Information on Oil and Gas Producing Activities (Unaudited).

In December 2008, the SEC announced that it had approved revisions to its oil and gas reporting disclosures. The new disclosure requirements include provisions that:

Introduce a new definition of oil and gas producing activities. This new definition allows companies to include volumes in their reserve base from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end prices.

Permit companies to disclose their probable and possible reserves on a voluntary basis.

Require companies to provide additional disclosure regarding the aging of proved undeveloped reserves.

Permit the use of reliable technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

Replace the existing “certainty” test for areas beyond one offsetting drilling unit from a productive well with a “reasonable certainty” test.

Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures regarding internal controls surrounding reserve estimation, as well as a report addressing the independence and qualifications of its reserves preparer or auditor are required.

Require separate disclosure of reserves in foreign countries if they represent 15 percent or more of total proved reserves, based on barrels of oil equivalents.

As with the FASB standard described above, adoption did not have an impact on our consolidated results of operations, financial position or cash flows. The additional disclosures required by the SEC can be found in Item 1. Business – Reserves.

Measuring liabilities at fair value, a FASB accounting standards update, was issued FASB Staff Position (“FSP”) FASB Interpretation No. 39 (“FSP FIN 39-1”), “Offsettingin August 2009. This update provides clarification for circumstances in which a quoted price in an active market for an identical liability is not available. In such circumstances, an entity is required to measure fair value using (1) the quoted price of Amounts Related to Certain Contracts”, which allows a party to a master netting agreement to offsetthe identical liability when traded as an asset, or (2) quoted prices for similar liabilities or similar liabilities when traded as assets, or (3) another valuation technique consistent with the fair value measurement principles such as an income approach or a market approach. The new update for measuring liabilities at fair value was effective for the third quarter of 2009. Adoption did not have an impact on our consolidated results of operations, financial position or cash flows.

Subsequent events accounting standards were issued in May 2009 by the FASB, establishing the of accounting and disclosure standards for events that occur after the balance sheet date but before financial statements are issued or available to be issued. This codifies into the accounting standards guidance that existed in the auditing standards and should not significantly change the subsequent events that we report. We began applying these standards prospectively in the second quarter of 2009. The disclosures required appear in Note 1.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Interim disclosures about fair value of financial instruments were expanded by the FASB in April 2009. Disclosures about fair value of financial instruments are now required in interim reporting periods for publicly traded companies. This change was effective for the second quarter of 2009 and did not require disclosures for earlier periods presented for comparative purposes. Adoption did not have an impact on our consolidated results of operations, financial position or cash flows. The required disclosures are presented in Note 16.

Guidance for determining fair value when the volume and level of activity for the asset or liability have significantly decreased and guidance on identifying circumstances that indicate a transaction is not orderly was also issued in April 2009 by the FASB. It was effective for the second quarter of 2009 and did not require disclosures for earlier periods presented for comparative purposes. Adoption did not have a significant impact on our consolidated results of operations, financial position or cash flows.

Accounting considerations for equity method investments were ratified by the FASB in November 2008, which address the initial measurement, decreases in value and changes in the level of ownership of the equity method investment. These were effective on a prospective basis on January 1, 2009 and for interim periods. Early application by an entity that has previously adopted an alternative accounting policy is not permitted. Since these were applied prospectively, adoption did not have a significant impact on our consolidated results of operations, financial position or cash flows.

Guidance for determining whether instruments granted in share-based payment transactions are participating securities was issued by the FASB in June 2008. It provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings allocation in computing earnings per share (“EPS”) under the two-class method. It was effective January 1, 2009 and all prior-period EPS data (including any amounts related to interim periods, summaries of earnings and selected financial data) were adjusted retrospectively to conform to its provisions. While our restricted stock awards meet this definition of participating securities, this application did not have a significant impact on our reported EPS.

Guidance for determining the rightuseful life of intangible assets was issued in April 2008 by the FASB. This guidance amends the factors that should be considered in developing renewal or extension assumptions used to reclaim collateral againstdetermine the useful life of a recognized intangible asset. The intent is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value amounts recognized for derivative instruments. Such treatmentof the asset. It was consistent with our accounting policy; therefore, adoption of FSP FIN No. 39-1 effective on January 1, 2008,2009 and was applied prospectively to intangible assets acquired after the effective date, except for the disclosure requirements which must be applied prospectively to all intangible assets recognized as of, and subsequent to, the effective date. Since this is applied prospectively, adoption did not have any effecta significant impact on our consolidated results of operations, financial position.position or cash flows.

SFAS No. 159 – In February 2007,Disclosures requirements for derivative instruments and hedging activities were expanded by the FASB issued Statement of Financial Accounting Standards (“SFAS”) No. 159, “The Fair Value Optionin March 2008 to provide information regarding (1) how and why an entity uses derivative instruments, (2) how derivative instruments and related hedged items are accounted for Financial Assets and Financial Liabilities.” This statement permits entities to choose to measure at(3) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. Requirements include qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value many financial instrumentsamounts and certain other items that are not currently required to be measured at fair value. It requires that unrealized gains and losses on itemsderivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. The amendments were effective January 1, 2009 and encouraged, but did not require, disclosures for whichearlier periods presented for comparative purposes at initial adoption. The required disclosures appear in Note 17.

Accounting for business combinations was revised by the FASB in December 2007. This significantly changes the accounting for business combinations. An acquiring entity will be required to recognize all the assets acquired, liabilities assumed and any noncontrolling interest in the acquiree at their acquisition-date fair value with limited exceptions. The definition of a business is expanded and is expected to be applicable to more transactions. In addition, there are changes in the accounting treatment for changes in control, step acquisitions, transaction costs, acquired contingent liabilities, in-process research and development, restructuring costs, changes in deferred tax asset valuation allowances as a result of a business combination and changes in income tax uncertainties after the acquisition date. Accounting for changes in valuation allowances for acquired deferred tax assets and the

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

resolution of uncertain tax positions for prior business combinations will impact tax expense instead of impacting recorded goodwill. Additional disclosures are also required. In April 2009, the FASB issued guidance for accounting for assets acquired and liabilities assumed in a business combination that arise from contingencies. Both the December 2007 revision and the April 2009 guidance were effective on January 1, 2009 for all new business combinations. Because we had no business combinations in progress at January 1, 2009, adoption did not have a significant impact on our consolidated results of operations, financial position or cash flows.

Accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary were issued in December 2007 by the FASB. Specifically, the standards clarified that a noncontrolling interest in a subsidiary (sometimes called a minority interest) is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements, but separate from the parent’s equity. It requires that the amount of consolidated net income attributable to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement. It also clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, a parent must recognize a gain or loss in net income when a subsidiary is deconsolidated, based on the fair value option has been electedof the noncontrolling equity investment on the deconsolidation date. Additional disclosures are required that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. In January 2009, the FASB ratified implementation questions regarding the new accounting standards for noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Both the new accounting standards and the implementation questions were effective January 1, 2009 and must be recorded in net income. The statement also establishesapplied prospectively, except for the presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributeswhich must be applied retrospectively for similar types of assets and liabilities. Weall periods presented in consolidated financial statements. Adoption did not elect thehave a significant impact on our consolidated results of operations, financial position or cash flows.

Accounting and reporting standards for fair value option when this standard became effective on January 1, 2008, nor have we chosenmeasurements were issued in September 2006 by the FASB. The standards define fair value, option for any assets or liabilities subsequent to that date.

SFAS No. 157 – In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements.” This statement defines fair value, establishesestablish a framework for measuring fair value in generally accepted accounting principles and expandsexpand disclosures about fair value measurements. SFAS No. 157 doesThe standards do not require any new fair value measurements but may require some entities to change their measurement practices. EffectiveWe adopted these standards effective January 1, 2008 we adopted SFAS No. 157, except for measurements of thosewith respect to financial assets and liabilities and effective January 1, 2009 with respect to nonfinancial assets and liabilities subject to the one-year deferral, which for us includes impairments of goodwill, intangible assets and other long-lived assets, and initial measurement of asset retirement obligations, asset exchanges, business combinations and partial sales of proved properties.liabilities. Adoption did not have a significant effectimpact on our consolidated results of operations, financial position or financial position.cash flows.

InApplication guidance to address fair value measurements for purposes of lease classification or measurement in accounting for leases was issued in February 2008 by the FASB issued FSP FAS 157-1, “Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Lease Classification or Measurement under Statement 13,” whichFASB. This guidance removes certain leasing transactions from the scope of SFAS No. 157, and FSP FAS 157-2, “Effective Date of FASB Statement No. 157,” which defers the effective date of SFAS No. 157 for one year for certain nonfinancial assets and nonfinancial liabilities, except those that are recognized or disclosed at fair value inaccounting and adoption did not have a significant impact on our consolidated results of operations, financial position or cash flows.

Guidance for determining the fair value of a financial statements on a recurring basis.

In October 2008,asset when the market for that asset is not active was issued by the FASB issued FSP FAS 157-3, “Determining the Fair Value of a Financial Asset When the Market for That Asset Is Not Active,” whichin October 2008. It clarifies the application of SFAS No. 157fair value measurements in a market that is not active and provides an example to illustrate key considerations in determining the fair value of a financial asset when the market for that financial asset is not active. FSP FAS 157-3This guidance was effective upon issuance, including prior periods for which financial statements havehad not been issued, and any revisions resulting from a change in the valuation technique or its application shallwere required to be accounted for as a change in accounting estimate. Application of FSP FAS 157-3this new guidance did not cause us to change our valuation techniques for assets and liabilities measured under SFAS No. 157.liabilities.

The additional disclosures regarding assets and liabilities recorded at fair value and measured under SFAS No. 157disclosures are presented in Note 17.16.

SFAS No. 158 – In September 2006, the FASB issued SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of FASB Statements No. 87, 88, 106, and 132 (R).” This standard requires an employer to: (1) recognize in its statement of financial position an asset for a plan’s overfunded status or a liability for a plan’s underfunded status; (2) measure a plan’s assets and its obligations that determine its funded status as of the end of the employer’s fiscal year (with limited exceptions); and (3) recognize changes in the funded status of a plan in the year in which the changes occur through comprehensive income. The funded status of a plan is measured as the difference betweendisclosures about plan assets at fair value and theof defined benefit obligation. For a pension plan, the benefit obligation is the projected benefit obligation and for any other postretirement plan it is the accumulated postretirement benefit obligation. We adopted SFAS No. 158 prospectively as of December 31, 2006 and recognized the funded status of our plans in the consolidated balance sheets, with a cumulative effect of a change in accounting principle of $348 million in stockholders’ equity. The adoption of SFAS No. 158 had no impact on our measurement date as we have historically measured the plan assets and benefit obligations of our pension andor other postretirement plans aswere expanded in December 2008 by the FASB. Additional disclosures about investment policies and strategies, the reporting of December 31. See Note 23fair value by asset category and other information about fair value measurements is required. This was effective January 1, 2009 and early application is permitted. Upon initial application, these new disclosures are not required for earlier periods that are presented for comparative purposes. These additional disclosures regarding defined benefit pension and other postretirement plans required by SFAS No. 158.

EITF Issue No. 04-13– In September 2005, the FASB ratified the consensus reached by the EITF on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty.” The consensus establishes the circumstances under which two or more inventory purchase and sale transactions with the same counterparty should be recognized at fair value or viewed as a single exchange transaction subject to APB Opinion No. 29, “Accounting for Nonmonetary Transactions.” In general, two or more transactions with the same counterparty must be combined for purposes of applying APB Opinion No. 29 if they are entered intopresented in contemplation of each other. The purchase and sale transactions may be pursuant to a single contractual arrangement or separate contractual arrangements and the inventory purchased or sold may be in the form of raw materials, work-in-process or finished goods.

Effective April 1, 2006, we adopted the provisions of EITF Issue No. 04-13 prospectively. EITF Issue No. 04-13 changes the accounting for matching buy/sell arrangements that are entered into or modified on or after April 1, 2006 (except for those accounted for as derivative instruments). In a typical matching buy/sell transaction, we enter into a contract to sell a particular quantity and quality of crude oil or refined product at a specified location and date to a particular counterparty and simultaneously agrees to buy a particular quantity and quality of the same commodity at a specified location on the same or another specified date from the same counterparty. Prior to adoption of EITF Issue No. 04-13, we recorded such matching buy/sell transactions in both revenues and cost of revenues as separate sale and purchase transactions. Upon adoption, we accounted for such transactions as exchanges of inventory.

Transactions arising from matching buy/sell arrangements entered into before April 1, 2006 were reported as separate sale and purchase transactions, until all such contracts ceased.

The adoption of EITF Issue No. 04-13 no effect on net income. The amounts of revenues and cost of revenues recognized after April 1, 2006 are less than the amounts that would have been recognized under previous accounting practices.Note 22.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

 

Not Yet Adopted

Variable interest accounting standards were amended by the FASB in June 2009. The new accounting standards replace the existing quantitative-based risks and rewards calculation for determining which enterprise has a controlling financial interest in a variable interest entity with an approach focused on identifying which enterprise has the power to direct the activities of a variable interest entity. In addition, the concept of qualifying special-purpose entities has been eliminated and therefore, will now be evaluated for consolidation in accordance with the applicable consolidation guidance. Ongoing assessments of whether an enterprise is the primary beneficiary of a variable interest entity are also required. The amended variable interest accounting standard requires reconsideration for determining whether an entity is a variable interest entity when changes in facts and circumstances occur such that the holders of the equity investment at risk, as a group, lack the power from voting rights or similar rights to direct the activities of the entity. Enhanced disclosures are required for any enterprise that holds a variable interest in a variable interest entity. Application will be prospective beginning in the first quarter of 2010, and for all interim and annual periods thereafter. Earlier application is prohibited. Adoption is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.

A standard to improve disclosures about fair value measurements was issued by the FASB in January 2010. The additional disclosures required include: (1) the different classes of assets and liabilities measured at fair value, (2) the significant inputs and techniques used to measure Level 2 and Level 3 assets and liabilities for both recurring and nonrecurring fair value measurements, (3) the gross presentation of purchases, sales, issuances and settlements for the rollforward of Level 3 activity, and (4) the transfers in and out of Levels 1 and 2. The new disclosures are effective for interim and annual reporting periods beginning after December 15, 2009, except for the gross presentation of purchases, sales, issuances, and settlements for the rollforward of Level 3 activity. Those disclosures are effective for fiscal years beginning after December 15, 2010, and for interim periods thereafter.

3.    Information about United States Steel

The USX Separation– Prior to December 31, 2001, Marathon had two outstanding classes of common stock: USX – USX—Marathon Group common stock, which was intended to reflect the performance of our energy business, and USX – USX—U.S. Steel Group common stock (“Steel Stock”), which was intended to reflect the performance of our steel business. On December 31, 2001, in a tax-free distribution to holders of Steel Stock, we exchanged the common stock of United States Steel for all outstanding shares of Steel Stock on a one-for-one basis (the “USX Separation”). In connection with the USX Separation, Marathon and United States Steel entered into a number of agreements, including:

Financial Matters Agreement– Marathon and United States Steel entered into a Financial Matters Agreement that provides for United States Steel’s assumption of certain industrial revenue bonds and certain other financial obligations of Marathon. The Financial Matters Agreement also provides that, on or before the tenth anniversary of the USX Separation, United States Steel will provide for our discharge from any remaining liability under any of the assumed industrial revenue bonds.

Under the Financial Matters Agreement, United States Steel has all of the existing contractual rights under the leases assumed, including all rights related to purchase options, prepayments or the grant or release of security interests. However, United States Steel has no right to increase amounts due under or lengthen the term of any of the assumed leases, other than extensions set forth in the terms of any of the assumed leases.

United States Steel was the sole general partner of Clairton 1314B Partnership, L.P., which owned certain cokemaking facilities at United States Steel Clairton Works. We guaranteed to the limited partners all obligations of United States Steel under the partnership documents (“the Clairton 1314B Guarantee”). The Financial Matters Agreement requires United States Steel to use commercially reasonable efforts to have Marathon released from its obligations under this guarantee. The Clairton 1314B Partnership was terminated on October 31, 2008. We were not released from our obligations under the Clairton 1314B Guarantee upon termination of the partnership. As a result, we continue to guarantee the United States Steel indemnification of the former limited partners for certain income tax exposures.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

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 payments on the assumed obligations.

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

Tax Sharing Agreement– Marathon and United States Steel entered into a Tax Sharing Agreement that reflects each party’s rights and obligations relating to payments and refunds of income, sales, transfer and other taxes that are attributable to periods beginning prior to and including the USX Separation date and taxes resulting from transactions effected in connection with the USX Separation.

In 2006, in accordance with the terms of the Tax Sharing Agreement, Marathon paid $35 million to United States Steel in connection with the settlement with the Internal Revenue Service of the consolidated federal income tax returns of USX Corporation for the years 1995 through 2001. The final payment of $13 million to United States Steel related to income tax returns under the Tax Sharing Agreement was made in January 2007.

4.    Deconsolidation of Equatorial Guinea LNG Holdings LimitedVariable Interest Entities

Equatorial Guinea LNG Holdings Limited (“EGHoldings”), in which we hold a 60 percent interest, was formed for the purpose of constructing and operating an LNG production facility. During facility construction, EGHoldings was a variable interest entity (“VIE”) that was consolidated because we were its primary beneficiary. Once the LNG production facility commenced its primary operations and began to generate revenue in May 2007,

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

EGHoldings was no longer a VIE. Effective May 1, 2007, we no longer consolidateconsolidated EGHoldings, despite the fact that we hold majority ownership, because the minority shareholders have rights limiting our ability to exercise control over the entity. We account for our investment in EGHoldings, using the equity method of accounting, at our share of net assets plus loans and advances.advances, if any. Our investment is included in the equity method investments line of our consolidated balance sheet (see Note 1413 to the consolidated financial statements).

The owners of the Athabasca Oil Sands Project (“AOSP”), in which we own 20 percent, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership (“Corridor Pipeline”) to provide materials transportation capabilities among the Muskeg River mine, the Scotford Upgrader and markets in Edmonton. The contract, originally signed in 1999, by Marathon’s predecessor, allows each owner to ship materials in accordance with its AOSP ownership. Currently, no third-party shippers use the pipeline. Under this agreement, the AOSP owners collectively are absorbing all of the operating and capital costs of the pipeline. Should shipments be suspended, by choice or due to force majeure, the AOSP owners remain responsible for the payments. This contract therefore qualifies as a variable interest contractual arrangement in a VIE. We hold a significant variable interest but are not the primary beneficiary; therefore, the Corridor Pipeline is not consolidated by Marathon. Our maximum exposure to loss as a result of our involvement with this VIE is the maximum amount we will be required to pay over the contract term, which was $928 million as of December 31, 2009. The contract expires in 2029; however, the shippers can perpetually extend its term.

5.    Related Party Transactions

During 2009, 2008 2007 and 20062007 only our equity method investees were considered related parties including:

 

Alba Plant LLC, in which we have a 52 percent noncontrolling interest. Alba Plant LLC processes liquefied petroleum gas.

The Andersons Clymers Ethanol LLC, in which we have a 35 percent interest, and The Andersons Marathon Ethanol LLC, in which we have a 50 percent interest (“Ethanol investments”). These companies each own an ethanol production facility.

Atlantic Methanol Production Company LLC (“AMPCO”), in which we have a 45 percent interest. AMPCO is engaged in methanol production activity.

 

Centennial Pipeline LLC (“Centennial”), in which we have a 50 percent interest. Centennial operates a refined products pipeline and storage facility.

 

EGHoldings, in which we have a 60 percent noncontrolling interest. EGHoldings processes liquefied natural gas.

 

The Andersons Clymers Ethanol LLC, in which we have a 35 percent interest, and The Andersons Marathon Ethanol LLC, in which we have a 50 percent interest (“Ethanol investments”). These companies each own an ethanol production facility.

LOOP LLC, in which we have a 51 percent noncontrolling interest. LOOP LLC operates an offshore oil port.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

 

Pilot Travel Centers LLC (“PTC”), in which we sold our 50 percent interest in October 2008. PTC owns and operates travel centers primarily in the United States.

 

Poseidon Oil Pipeline Company, L.L.C.LLC (“Poseidon”), in which we have a 28 percent interest. Poseidon transports crude oil.

We believe that transactions with related parties were conducted under terms comparable to those with unrelated parties.

Related party sales to PTC consisted primarily of petroleum products. In the fourth quarter of 2008, we completed the sale of our 50 percent ownership interest in PTC.

IndexRevenues from related parties were as follows:

(In millions)  2009  2008  2007

EGHoldings

  $          44  $39  $19

Centennial

   34   31   27

Other equity method investees

   19   20   23

PTC

   -   1,789   1,556
            

Total

  $97  $    1,879  $    1,625

Purchases from related parties were as follows:

(In millions)  2009  2008  2007

Alba Plant LLC

  $        143  $        235  $        131

Ethanol investments

   143   188   9

Poseidon

   53   154   16

Centennial

   58   61   57

LOOP LLC

   40   35   43

Other equity method investees

   48   42   107
            

Total

  $485  $715  $363

Current receivables from related parties were as follows:

   December 31,
(In millions)  2009  2008

EGHoldings

  $         36  $         19

Poseidon

   11   1

Alba Plant LLC

   10   6

AMPCO

   2   5

Other equity method investees

   1   2
        

Total

  $        60  $        33

Payables to Financial Statements

related parties were as follows:

   December 31,
(In millions)  2009  2008

Poseidon

  $          20  $          3

LOOP

   17   2

Ethanol investments

   9   6

Alba Plant LLC

   9   5

Other equity method investees

   9   5
        

Total

  $64  $21

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

 

Related party sales to PTC consist primarily of petroleum products. Revenues from related parties were as follows:

(In millions)  2008  2007  2006

PTC

  $1,789  $1,556  $1,420

EGHoldings

   39   19   

Centennial

   31   27   28

Other equity method investees

   20   23   18
            

Total

  $1,879  $1,625  $1,466

Purchases from related parties were as follows:

(In millions)  2008  2007  2006

Alba Plant LLC

  $235  $131  $

Ethanol investments

   188   9   

Poseidon

   154   16   8

Centennial

   61   57   53

LOOP LLC

   35   43   54

Other equity method investees

   42   107   95
            

Total

  $715  $363  $210

6.    Acquisitions

Western Oil Sands Inc.– On October 18, 2007, we completed the acquisition of all the outstanding shares of Western Oil Sands Inc. (“Western”) for cash and securities of $5,833 million. Subsequent to the transaction, Western’s name was changed to Marathon Oil Canada Corporation. The acquisition was accounted for under the purchase method of accounting and, as such, our results of operations include Western’s results from October 18, 2007. Western’s oil sands mining and bitumen upgrading operations are reported as a separate Oil Sands Mining segment, while its ownership interests in leases where in-situ recovery techniques are expected to be utilized are included in the E&P segment.

The final purchase price for the Western acquisition was as follows:

 

(In millions)    

Cash(a)

  $        3,907

Marathon common stock and securities exchangeable for Marathon common stock(b)

   1,910

Transaction-related costs

   16
    

Purchase price

   5,833

Fair value of debt acquired

   1,063
    

Total consideration including debt acquired

  $6,896
(In millions)

Cash(a)

$ 3,907

Marathon common stock and securities exchangeable for Marathon common stock(b)

1,910

Transaction-related costs

16

Purchase price

5,833

Fair value of debt acquired

1,063

Total consideration including debt acquired

$ 6,896

(a)

Western shareholders received cash of 3,808 million Canadian dollars.

(b)

Western shareholders received 29 million shares of Marathon common stock and 5 million securities exchangeable for Marathon common stock valued at $55.70 per share, which was the average common stock price over the trading days between July 26 and August 1, 2007 (the days surrounding the announcement of the transaction).

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

The primary reasons for the acquisition and the principal factors contributing to a purchase price resulting in goodwill are: access to the long-life Athabasca Oil Sands Project (“AOSP”)AOSP of northern Alberta, Canada; the opportunity to realize a fully-integrated oil strategy, capitalizing on the ownership of this asset by aligning production from the AOSP developments, including planned expansions of the current mining operations, with our refining system; potential for expanded growth opportunities in the Athabasca region; and access to a trained workforce with expertise in bitumen production and upgrading and in synthetic crude oil marketing. The goodwill arising from the purchase price allocation was $1,508 million, of which $1,437 million was assigned to the Oil Sands Mining segment and $71 million was assigned to the E&P segment. Reductions of $25 million were made to Oil Sands Mining segment goodwill upon resolution of tax and royalty issues in 2008. None of the goodwill is deductible for tax purposes.

The following table summarizes the fair values of the assets and liabilities acquired as of October 18, 2007.

(In millions)    

Current assets:

  

Cash and cash equivalents

  $44

Receivables

   359

Inventories

   26

Other current assets

   40
    

Total current assets acquired

   469

Property, plant and equipment

   6,842

Goodwill

   1,483

Intangible assets

   113

Other noncurrent assets

   10
    

Total assets acquired

  $8,917
    

Current liabilities:

  

Accounts payable

  $339

Current portion of long-term debt

   50

Deferred income taxes

   48

Other current liabilities

   20
    

Total current liabilities assumed

   457

Long-term debt

   1,013

Deferred income taxes

   1,494

Asset retirement obligations

   31

Other liabilities

   89
    

Total liabilities assumed

   3,084
    

Net assets acquired

  $5,833

The following unaudited pro forma data was prepared as if the acquisition of Western had been consummated at the beginning of each period presented. The pro forma data is based on historical information and does not reflect the actual results that would have occurred nor is it indicative of future results of operations.

 

(In millions, except per share amounts)  2007  2006  2007

Revenues and other income

  $66,089  $66,283  $        65,633

Income from continuing operations

   3,495   4,765   3,313

Net income

   3,503   5,042   3,503

Per share data:

      

Income from continuing operations basic

  $5.07  $6.35  $4.80

Income from continuing operations diluted

  $5.03  $6.30  $4.77

Net income basic

  $5.08  $6.72  $5.08

Net income diluted

  $5.04  $6.67  $5.04

7.    Dispositions

IndexDuring 2009, we have disposed of our exploration and production businesses in Ireland, Gabon and certain producing assets in the Permian Basin of New Mexico and Texas. At December 31, 2009, agreements were pending to Financial Statements
dispose of certain assets under development in Angola (see discussion below). These dispositions all relate to our Exploration and Production (“E&P”) segment. Our Irish and Gabonese exploration and production businesses have

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

 

been reported as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented.

7. DispositionsDiscontinued operations—Revenues and pretax income associated with our discontinued Irish and Gabonese operations are shown in the following table:

(In millions)  2009  2008  2007

Revenues applicable to discontinued operations

  $        188  $        439  $        456

Pretax income from discontinued operations

  $80  $221  $281

Angola disposition – In July 2009, we entered into an agreement to sell an undivided 20 percent outside-operated interest in the Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola for $1.3 billion, excluding any purchase price adjustments at closing, with an effective date of January 1, 2009. The sale closed and we received net proceeds of $1.3 billion in February 2010. The pretax gain on the sale will be approximately $800 million. We retained a 10 percent outside-operated interest in Block 32.

Outside-operated Gabon disposition – In December 2009, we closed the sale of our operated fields offshore Gabon, receiving net proceeds of $269 million, after closing adjustments. A $232 million pretax gain on this disposition was reported in discontinued operations for 2009.

Permian Basin disposition – In June 2009, we closed the sale of our operated and a portion of our outside-operated Permian Basin producing assets in New Mexico and west Texas for net proceeds after closing adjustments of $293 million. A $196 million pretax gain on the sale was recorded.

Ireland dispositions – In April 2009, we closed the sale of our operated properties in Ireland for net proceeds of $84 million, after adjusting for cash held by the sold subsidiary. A $158 million pretax gain on the sale was recorded. As a result of this sale, we terminated our pension plan in Ireland, incurring a charge of $18 million.

In June 2009, we entered into an agreement to sell the subsidiary holding our 19 percent outside-operated interest in the Corrib natural gas development offshore Ireland. Total proceeds were estimated to range between $235 million and $400 million, subject to the timing of first commercial gas at Corrib and closing adjustments. At closing on July 30, 2009, the initial $100 million payment plus closing adjustments was received. The fair value of the proceeds was estimated to be $311 million. Fair value of anticipated sale proceeds includes (i) $100 million received at closing, (ii) $135 million minimum amount due at the earlier of first gas or December 31, 2012, and (iii) a range of zero to $165 million of contingent proceeds subject to the timing of first commercial gas. A $154 million impairment of the held for sale asset was recognized in discontinued operations in the second quarter of 2009 (see Note 16) since the fair value of the disposal group was less than the net book value. Final proceeds will range between $135 million (minimum amount) to $300 million and are due on the earlier of first commercial gas or December 31, 2012. The fair value of the expected final proceeds was recorded as an asset at closing. As a result of new public information in the fourth quarter of 2009, a writeoff was recorded on the contingent portion of the proceeds (see Note 10).

Existing guarantees of our subsidiaries’ performance issued to Irish government entities will remain in place after the sales until the purchasers issue similar guarantees to replace them. The guarantees, related to asset retirement obligations and natural gas production levels, have been indemnified by the purchasers. The fair value of these guarantees is not significant.

Norwegian propertiesdisposition– On October 31, 2008, we closed the sale of our Norwegian outside-operated E&P properties and undeveloped offshore acreage in the Heimdal area of the Norwegian North Sea for net proceeds of $301 million, with a pretax gain of $254 million as of December 31, 2008.

Pilot Travel Centers disposition– On October 8, 2008, we completed the sale of our 50 percent ownership interest in PTC. Sale proceeds were $625 million, with a pretax gain on the sale of $126 million. Immediately preceding the sale, we received a $75 million partial redemption of our ownership interest from PTC that was accounted for as a return of investment. This was an investment of our RM&T segment.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Operated Irish propertiesRussia dispositionOn December 17, 2008, we agreed to sell our operated properties located in Ireland for proceeds of $180 million, before post-closing adjustments and cash on hand at closing. Closing is subject to completion of the necessary administrative processes.

As of December 31, 2008, operating assets and liabilities were classified as held for sale, as disclosed by major class in the following table:

(In millions)  2008

Current assets

  $164

Noncurrent assets

   103
    

Total assets

   267

Current liabilities

   62

Noncurrent liabilities

   199
    

Total liabilities

   261
    

Net assets held for sale

  $6

8. Discontinued Operations

On June 2, 2006, we sold our Russian oil exploration and production businesses in the Khanty-Mansiysk region of western Siberia. Under the terms of the agreement, we received $787 million for these businesses, plus preliminary working capital and other closing adjustments of $56 million, for a total transaction value of $843 million. Proceeds net of transaction costs and cash held by the Russian businesses at the transaction date totaled $832 million. A gain on the sale of $243 million ($342 million before income taxes) was reported in discontinued operations for 2006. Income taxes on this gain were reduced by the utilization of a capital loss carryforward. Exploration and Production segment goodwill of $21 million was allocated to the Russian assets and reduced the reported gain. Adjustments to the sales price were completed in 2007 and an additional pretax gain on the sale of $8$13 million ($138 million beforeafter income taxes) was recognized.

The activities of the Russian businesses have been reported asin discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for 2006. Revenues applicable to discontinued operations were $173 million and pretax income from discontinued operations was $45 million for 2006.

Index to Financial Statements

MARATHON OIL CORPORATIONoperations.

Notes to Consolidated Financial Statements

9.8.    Income per Common Share

Basic income per share is based on the weighted average number of common shares outstanding, including securities exchangeable into common shares. Diluted income per share assumes exercise of stock options and stock appreciation rights, and restricted stock, provided the effect is not antidilutive.

 

 2008 2007 2006  2009  2008  2007
(In millions except per share data) Basic Diluted Basic Diluted Basic Diluted  Basic  Diluted  Basic  Diluted  Basic  Diluted

Income from continuing operations

 $3,528 $3,528 $3,948 $3,948 $4,957 $4,957  $        1,184  $        1,184  $        3,384  $        3,384  $        3,766  $        3,766

Discontinued operations

      8  8  277  277   279   279   144   144   190   190
                              

Net income

 $3,528 $3,528 $3,956 $3,956 $5,234 $5,234  $1,463  $1,463  $3,528  $3,528  $3,956  $3,956
                              

Weighted average common shares outstanding

  709  709  690  690  716  716   709   709   709   709   690   690

Effect of dilutive securities

    4    5    6   -     2   -     4   -     5
                              

Weighted average common shares, including dilutive effect

  709  713  690  695  716  722   709   711   709   713   690   695
                              

Per share:

                  

Income from continuing operations

 $4.97 $4.95 $5.72 $5.68 $6.92 $6.87  $1.67  $1.67  $4.77  $4.75  $5.46  $5.42
            

Discontinued operations

 $ $ $0.01 $0.01 $0.39 $0.38  $0.39  $0.39  $0.20  $0.20  $0.27  $0.27
            

Net income

 $4.97 $4.95 $5.73 $5.69 $7.31 $7.25  $2.06  $2.06  $4.97  $4.95  $5.73  $5.69

The per share calculations above exclude 5.410 million, 5 million and 3.23 million stock options and stock appreciation rights in 2009, 2008 and 2007 that were antidilutive. There were no antidilutive stock options or stock appreciation rights in 2006. Restricted stock was not antidilutive in 2008, 2007 or 2006.

10.9.    Segment Information

We have four reportable operating segments: Exploration and Production; Oil Sands Mining; Integrated Gas and Refining, Marketing and Transportation; and Integrated Gas.Transportation. Each of these segments is organized and managed based upon the nature of the products and services they offer.

 

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

 

Oil Sands Mining (“OSM”) – mines, extracts and transports bitumen from oil sands deposits in Alberta, Canada, and upgrades the bitumen to produce and market synthetic crude oil and by-products;

Refining, Marketing and Transportation (“RM&T”) – refines, markets and transports crude oil and petroleum products, primarily in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the U.S.; andvacuum gas oil;

 

Integrated Gas (“IG”) – markets and transports products manufactured from natural gas, such as LNG and methanol, on a worldwide basis, and is developing other projects to link stranded natural gas resources with key demand areas.areas; and

Refining, Marketing and Transportation (“RM&T”) – refines, markets and transports crude oil and petroleum products, primarily in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the U.S.

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”). Segment income represents income from continuing operations, net of minority interests and income taxes, attributable to the operating segments. Our corporate general and administrative costs are not allocated to the operating segments. These costs primarily consist of employment costs (including pension effects), professional

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

services, facilities and other costs associated with corporate activities, net of associated income tax effects. All foreignForeign currency remeasurement and transaction gains or losses are not allocated to operating segments. Non-cash gains and losses on two natural gas sales contracts in the United Kingdom that arewere accounted for as derivative instruments, impairments or infrequently occurringother items that affect comparability (as determined by the CODM) also are not allocated to operating segments.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Revenues from external customers are attributed to geographic areas based on selling location. No single customer accounts for more than 10 percent of annual revenues.

 

(In millions)  E&P  OSM  RM&T  IG  Total 

2008

       

Revenues:

       

Customer

  $11,636  $922  $62,445  $93  $75,096 

Intersegment(a)

   798   200   209      1,207 

Related parties

   52      1,827      1,879 
                     

Segment revenues

   12,486   1,122   64,481   93   78,182 

Elimination of intersegment revenues

   (798)  (200)  (209)     (1,207)

Gain on U.K. natural gas contracts

   218            218 
                     

Total revenues

  $11,906  $922  $64,272  $93  $77,193 
                     

Segment income

  $2,715  $258  $1,179  $302  $4,454 

Income from equity method investments(b)

   225      178   402   805 

Depreciation, depletion and amortization(b)

   1,386   143   606   3   2,138 

Income tax provision(b)

   2,912   93   684   131   3,820 

Capital expenditures(c)(d)

   3,113   1,038   2,954   4   7,109 

2007

       

Revenues:

       

Customer

  $8,623  $181  $54,137  $218  $63,159 

Intersegment(a)

   497   40   348      885 

Related parties

   35      1,590      1,625 
                     

Segment revenues

   9,155   221   56,075   218   65,669 

Elimination of intersegment revenues

   (497)  (40)  (348)     (885)

Loss on U.K. natural gas contracts

   (232)           (232)
                     

Total revenues

  $8,426  $181  $55,727  $218  $64,552 
                     

Segment income (loss)

  $1,729  $(63) $2,077  $132  $3,875 

Income from equity method investments

   238      139   168   545 

Depreciation, depletion and amortization(b)

   963   22   587   6   1,578 

Minority interest in loss of subsidiary

            3   3 

Income tax provision (benefit)(b)

   2,172   (21)  1,183   24   3,358 

Capital expenditures(c)(d)

   2,511   165    1,640   93   4,409 

2006 

       

Revenues:

       

Customer

  $8,326  $  $54,471  $179  $62,976 

Intersegment(a)

   672      16      688 

Related parties

   12      1,454      1,466 
                     

Segment revenues

   9,010      55,941   179   65,130 

Elimination of intersegment revenues

   (672)     (16)     (688)

Gain on U.K. natural gas contracts

   454            454 
                     

Total revenues

  $8,792  $  $55,925  $179  $64,896 
                     

Segment income

  $2,003  $  $2,795  $16  $4,814 

Income from equity method investments

   206      145   40   391 

Depreciation, depletion and amortization(b)

   919      558   9   1,486 

Minority interest in loss of subsidiary

            10   10 

Income tax provision(b)

   2,371      1,642   8   4,021 

Capital expenditures(c)(d)

   2,169      916   307   3,392 
(In millions)  E&P(a)  OSM  IG  RM&T  Total 

2009 

       

Revenues:

       

Customer

  $            7,241   $            549  $              50  $        45,461  $        53,301 

Intersegment(b)

   551    118   -     31   700 

Related parties

   59    -      -     38   97 
                     

Segment revenues

   7,851    667   50   45,530   54,098 

Elimination of intersegment revenues

   (551)    (118  -     (31  (700

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

   72    -      -     -      72 
                     

Total revenues

  $7,372   $549  $50  $45,499  $53,470 
                     

Segment income

  $1,221   $44  $90  $464  $1,819 

Income from equity method investments(d)

   125    -      144   29   298 

Depreciation, depletion and amortization(e)

   1,795    124   3   670   2,592 

Income tax provision(e)

   1,563    6   39   234   1,842 

Capital expenditures(f)(g)

   2,162    1,115   2   2,570   5,849 

(In millions)  E&P(a)  OSM  IG  RM&T  Total 

2008 

       

Revenues:

       

Customer

  $        11,197   $            922  $                93  $        62,445  $        74,657 

Intersegment(b)

   798    200   -     209   1,207 

Related parties

   52    -      -     1,827   1,879 
                     

Segment revenues

   12,047    1,122   93   64,481   77,743 

Elimination of intersegment revenues

   (798)    (200  -     (209  (1,207

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

   218    -      -     -      218 
                     

Total revenues

  $11,467   $922  $93  $64,272  $76,754 
                     

Segment income

  $2,556   $258  $302  $1,179  $4,295 

Income from equity method investments(d)

   225    -      402   178   805 

Depreciation, depletion and amortization(e)

   1,337    143   3   606   2,089 

Income tax provision(e)

   2,827    93   131   684   3,735 

Capital expenditures(f)(g)

   2,971    1,038   4   2,954   6,967 

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

(In millions)  E&P(a)  OSM(h)  IG  RM&T  Total 

2007 

       

Revenues:

       

Customer

  $        8,167   $          181   $          218  $        54,137  $        62,703 

Intersegment(b)

   497    40    -   348   885 

Related parties

   35    -    -   1,590   1,625 
                     

Segment revenues

   8,699    221    218   56,075   65,213 

Elimination of intersegment revenues

   (497)    (40)    -   (348  (885

Loss on U.K. natural gas contracts(c)

   (232)    -    -   -    (232
                     

Total revenues

  $7,970   $181   $218  $55,727  $64,096 
                     

Segment income (loss)

  $1,552   $(63 $132  $2,077  $3,698 

Income from equity method investments(d)

   238    -    168   139   545 

Depreciation, depletion and amortization(e)

   914    22     6   587   1,529 

Income tax provision (benefit)(e)

   2,076    (21)    24   1,183   3,262 

Capital expenditures(f)(g)(i)

   2,426    165    93   1,640   4,324 

(a)

As discussed in Note 7, discontinued operations for our Irish and Gabonese businesses in all periods presented and our Russian business in 2007 have been excluded from segment results.

(b)

Management believes intersegment transactions were conducted under terms comparable to those with unrelated parties.

(b)(c)

The U.K. natural gas contracts expired in September 2009.

(d)

Our investment in Pilot Travel Centers LLC, which was reported in our RM&T segment, was sold in the fourth quarter of 2008.

(e)

Differences between segment totals and our totals represent amounts related to corporate administrative activities and other unallocated items and are included in “Items not allocated to segments, net of income taxes” in reconciliation below.

(c)(f)

Differences between segment totals and our totals represent amounts related to corporate administrative activities.

(d)(g)

Includes accruals.

(h)

As discussed in Note 6, we acquired Western in October 18, 2007.

(i)

Through April 2007, Integrated Gas segment capital expenditures include EGHoldings at 100 percent. 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’ capital expenditures subsequent to April 2007 are not included in our capital expenditures.

(e)

As discussed in Note 8, the Russian businesses that were sold on June 2, 2006 have been accounted for as discontinued operations. Segment information for all presented periods excludes the amounts for these Russian operations.

(f)

As discussed in Note 6, we acquired Western in October 18, 2007.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

The following reconciles segment income to net income as reported in the consolidated statements of income:

 

(In millions)  2008 2007 2006   2009 2008 2007 

Segment income

  $4,454  $3,875  $4,814   $        1,819  $        4,295  $    3,698 

Items not allocated to segments, net of income taxes:

        

Corporate and other unallocated items

   (93)  (122)  (190)   (422  (75  (128

Foreign currency remeasurement of taxes

   (319  249   19 

Impairments(a)

   (45  (1,437  -  

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

   111   (118)  232    37   111   (118

Foreign currency gain (loss) on income taxes

   252   18   (22)

Impairments(a)

   (1,437)      

Gain on dispositions

   241   8   274    114   241   -  

Gain on foreign currency derivative instruments

      112       -    -    112 

Deferred income taxes – tax legislation changes

      193   21 

– other adjustments(b)

         93 

Deferred income taxes—tax legislation changes

   -    -    193 

Loss on early extinguishment of debt

      (10)  (22)   -    -    (10

Discontinued operations

         34    279   144   190 
                    

Net income

  $3,528  $3,956  $5,234   $1,463  $3,528  $3,956 

(a)

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 Note 7) that was recorded in the fourth quarter of 2009 on the basis of new public information regarding the pipeline that would transport gas from the Corrib development. Impairments in 2008 include the $1,412 million impairment of goodwill related to the OSM reporting unit see(see Note 1615 to the consolidated financial statementsstatements) and the $25 million after-tax impairment ($40 million pretax) related to our investments in ethanol producing companies see(see Note 1413 to the consolidated financial statements.statements).

(b)

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Other deferred tax adjustments in 2006 represent a benefit recorded for cumulative income tax basis differences associated with prior periods.

The following reconciles total revenues to sales and other operating revenues (including consumer excise taxes) as reported in the consolidated statements of income.

 

(In millions)  2008  2007  2006  2009  2008  2007

Total revenues

  $77,193  $64,552  $64,896  $        53,470  $        76,754  $        64,096

Less: Sales to related parties

   1,879   1,625   1,466   97   1,879   1,625

Revenues from matching buy/sell transactions

      127   5,457
                  

Sales and other operating revenues (including consumer excise taxes)

  $75,314  $62,800  $57,973  $53,373  $74,875  $62,471

The following summarizes revenues from external customers by geographic area.

 

(In millions)  2008  2007  2006  2009  2008  2007

United States

  $69,034  $59,302  $59,723  $        47,293  $        69,034  $        59,302

International

   8,159   5,250   5,173   6,177   7,720   4,794
                  

Total

  $77,193  $64,552  $64,896

Total revenues

  $53,470  $76,754  $64,096

The following summarizes certain long-lived assets by geographic area, including property, plant and equipment and investments.

 

  December 31,  December 31,
(In millions)  2008  2007  2009  2008

United States

  $16,298  $13,133  $        18,794  $        16,298

Canada

   7,775   6,980   8,558   7,775

Equatorial Guinea

   2,732   2,842   2,577   2,732

Other international

   4,719   4,393   4,182   4,719
            

Total

  $31,524  $27,348  $34,111  $31,524

Revenues by product line were:

Index to Financial Statements

(In millions)  2009  2008  2007

Refined products

  $        40,518  $        59,299  $        49,718

Merchandise

   3,308   3,028   2,975

Liquid hydrocarbons

   8,253   10,983   8,463

Natural gas

   1,265   3,085   2,629

Other products or services

   126   359   311
            

Total revenues

  $53,470  $76,754  $64,096

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

 

Revenues by product line were:

(In millions)  2008  2007  2006

Refined products

  $59,299  $49,718  $45,511

Merchandise

   3,028   2,975   2,871

Liquid hydrocarbons

   11,422   8,919   12,531

Natural gas

   3,085   2,629   3,742

Transportation and other

   359   311   241
            

Total

  $77,193  $64,552  $64,896

11.10.    Other Items

Net interest and other financing income (costs)

 

(In millions)  2008  2007  2006 

Interest and other financial income:

    

Interest income

  $60  $144  $129 

Net foreign currency gains

   14   2   16 
             

Total

   74   146   145 

Interest and other financing costs:

    

Interest incurred(a)

   440   290   245 

Loss (income) on interest rate swaps

   (1)  15   16 

Interest capitalized

   (326)  (214)  (152)
             

Net interest expense

   113   91   109 

Other

   11   14   (1)
             

Total

   124   105   108 
             

Net interest and other financial income (costs)

  $(50) $41  $37 
(In millions)  2009  2008  2007 

Interest:

    

Interest income

  $11  $55  $139 

Interest expense(a)

   (510  (418  (275

Income (loss) on interest rate swaps

   17   1   (15

Interest capitalized

           441           305           198 
             

Total interest

   (41  (57  47 

Other:

    

Net foreign currency gains (losses)

   (36  40   -    

Writeoff off contingent proceeds(b)

   (70  -      -    

Other

   (2  (11  (14
             

Total other

   (108  29   (14
             

Net interest and other financing income (costs)

  $(149 $(28 $33 

(a)

Excludes $27 million, $29 million $30 million and $33$30 million paid by United States Steel in 2009, 2008 2007 and 20062007 on assumed debt.

(b)

A portion of he contingent proceeds from the sale of the Corrib natural gas development (see Note 7) was written off in the fourth quarter of 2009 on the basis of new public information regarding the pipeline that would transport gas from the Corrib development. Should further delays occur with respect to commercial first gas, the remaining carrying value of this contingent asset of $15 million may be reduced.

Foreign currency transactions - Aggregate foreign currency gains (losses) were included in the consolidated statements of income as follows:

 

(In millions)  2008  2007  2006   2009 2008  2007

Net interest and other financing costs

  $14  $2  $16   $(36 $40  $-  

Provision for income taxes

   252   18   (22)           (319          249           19
                   

Aggregate foreign currency gains (losses)

  $266  $20  $(6)  $(355 $289  $19

11.    Income Taxes

Index to Financial Statements
Income tax provisions (benefits) were:

   2009  2008  2007
(In millions)  Current  Deferred  Total  Current  Deferred  Total  Current  Deferred  Total

Federal

  $(224 $162  $(62 $921  $  192  $  1,113  $  1,289  $(8 $1,281

State and local

   (75  40   (35  146   12   158   184   22   206

Foreign

   1,484   870   2,354   2,206   (110  2,096   1,681   (366  1,315
                                    

Total

  $  1,185  $  1,072  $  2,257  $  3,273  $94  $3,367  $3,154  $  (352 $  2,802

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

 

12. Income Taxes

Income tax provisions (benefits) were:

   2008  2007  2006
(In millions)  Current  Deferred  Total  Current  Deferred  Total  Current  Deferred  Total

Federal

  $923  $193  $1,116  $1,290  $(2) $1,288  $1,579  $72  $1,651

State and local

   146   12   158   184   22   206   230   30   260

Foreign

   2,283   (112)  2,171   1,774   (367)  1,407   1,945   166   2,111
                                    

    Total

  $3,352  $93  $3,445  $3,248  $(347) $2,901  $3,754  $268  $4,022

A reconciliation of the federal statutory income tax rate (35 percent) applied to income from continuing operations before income taxes to the provision for income taxes follows:

 

(In millions)  2008 2007 2006 
  2009 2008 2007 

Statutory rate applied to income from continuing operations before income taxes

  $2,440  $2,397  $3,143       35      35      35 

Effects of foreign operations, including foreign tax credits(a)

   1,168   671   909   12  21  11 

Foreign currency remeasurement (gain) loss

  10  (4 -    

Effects of nondeductible goodwill impairment

   494         -     7  -    

Adjustments to valuation allowances(b)

   (671)        8  (10 -    

State and local income taxes, net of federal income tax effects

   92   134   170   (1 2  2 

Credits other than foreign tax credits

   (7)  (3)  (2)

Domestic manufacturing deduction

   (44)  (64)  (47)

Effects of partially-owned companies

   (4)  (5)  (6)

Effects of enacted changes in tax laws(c)

      (193)  (21)

Adjustment of prior years federal income taxes(d)

   (30)  (27)  (119)

Other

   7   (9)  (5)  2  (1 (5
                    

Provision for income taxes

  $3,445  $2,901  $4,022   66  50  43 

(a)

In 2006, we resumed operations in Libya whereIncludes foreign tax credits but excludes the statutoryeffects of remeasuring income tax rate isassets and liabilities denominated in excess of 90 percent.foreign currencies. 2009 includes foreign tax credit benefits related to crediting certain foreign taxes that were previously considered deductible for U.S. tax purposes.

(b)

The adjustmentsIn 2009, it was determined that we may not be able to therealize all recorded foreign tax credit benefits and therefore a valuation allowance related primarily to the release of the Norwegian valuation allowance.was recorded against these benefits. In 2008, we released the valuation allowance on the Norwegian deferred tax asset associated with operating loss carryforwards upon completion of the operated Alvheim/Vilje development offshore Norway, with first production from Alvheim in June 2008 and from Vilje in July 2008.

(c)

The amounts in all periods represent the income tax benefits of applying income tax rate changes to the applicable net deferred tax asset or liability balances. In 2007, subsequent to the Western acquisition, decreases to the Canadian income tax rates were enacted. In 2006, the U.K. supplemental corporation tax rate (“SCT”) was increased, which resulted in a benefit due to the net deferred tax asset position related to the SCT.

(d)

The 2006 adjustment of prior years’ federal income taxes was primarily related to a $93 million credit as a result of an analysis of the tax consequences attributable to prior years’ differences between the financial statement carrying amounts of assets and liabilities and their tax bases for U.S. federal income tax purposes.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Deferred tax assets and liabilities resulted from the following:

 

  December 31,   December 31, 
(In millions)  2008 2007 
  2009 2008 

Deferred tax assets:

      

Employee benefits

  $918  $703   $  1,163  $918 

Operating loss carryforwards(a)

   1,150   1,596    625     1,150 

Derivative instruments

   86   284    -      86 

Foreign tax credits(b)

   1,088   838    1,934   1,088 

Other

   160   169    177   160 

Valuation allowances

      

Federal(c)(b)

      (29)   (280  -    

State

   (50)  (55)   (45  (50

Foreign(d)(c)

   (212)  (917)   (157  (212
              

Total deferred tax assets

   3,140   2,589    3,417   3,140 
              

Deferred tax liabilities:

   

Deferred tax liabilities

   

Property, plant and equipment

   4,679   4,610    5,862   4,679 

Inventories

   649   652    615   649 

Investments in subsidiaries and affiliates

   1,361   987    1,330   1,361 

Derivative instruments

   33   63 

Other

   63   89    75   -    
              

Total deferred tax liabilities

   6,752   6,338    7,915   6,752 
              

Net deferred tax liabilities

  $3,612  $3,749   $4,498  $3,612 

(a)

At December 31, 2008,2009, foreign operating loss carryforwards primarily include $562 million for Norway regular income tax, $1,044$118 million for Norway special petroleum tax and $585$847 million for Angola income tax. The Norway and Angola operating loss carryforwards have no expiration dates. The remainder of foreign carryforwards were in several other foreign jurisdictions, the majority of which expire in 20092010 through 2020. State operating loss carryforwards of $719$1,196 million expire in 20092010 through 2028. The state operating loss carryforwards primarily relate to net operating losses generated during 2009 and the periodperiods prior to the USX Separation. Loss carryforward amounts related to the USX Separation and wereare offset by valuation allowances.

(b)

Our expectation regarding our ability to realize the benefit of foreign tax credits is based on certain assumptions concerning future operating conditions (particularly as related to prevailing commodity prices), and income generated from foreign sources and our tax profile in the years that such credits may be claimed.

(c)

sources. Federal valuation allowances increased $280 million in 2009, decreased $29 million in 2008 and increased $10 million in 2007 due to changes in the expected realizability of foreign tax credits.

(c)

Foreign valuation allowances decreased $55 million in 2009, primarily due to the realizibilityreduction of foreign tax credits. In 2006, federal valuation allowances decreased $101 million primarily due to $79 millionnet operating loss carryforwards as a result of carryforward losses utilized in conjunction with the saledispositon of our Russian oil exploration and production businesses.

(d)

businesses in Ireland. Foreign valuation allowances decreased $705 million in 2008, primarily due to the release of the Norwegian valuation allowance. Foreign valuation allowances increased $306 million and $176 million in 2007 and 2006 primarily as a result of net operating loss carryforwards generated in those years in Norway, Angola and several other jurisdictions.

Net deferred tax liabilities were classified in the consolidated balance sheet as follows:

 

   December 31,
(In millions)  2008  2007

Assets:

    

Other current assets

  $36  $2

Other noncurrent assets

   243   185

Liabilities:

    

Current deferred income taxes

   561   547

Noncurrent deferred income taxes

   3,330   3,389
        

Net deferred tax liabilities

  $3,612  $3,749

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

   December 31,
(In millions)  2009  2008

Assets:

    

Other current assets

  $3  $36

Other noncurrent assets

   6   243

Liabilities:

    

Current deferred income taxes

   403   561

Noncurrent deferred income taxes

   4,104   3,330
        

Net deferred tax liabilities

  $  4,498  $  3,612

We are continuously undergoing examination of our U.S. federal income tax returns by the Internal Revenue Service. Such audits have been completed through the 2005 tax year. We believe adequate provision has been made for federal income taxes and interest which may become payable for years not yet settled. Further, we are routinely involved in U.S. state income tax audits and foreign jurisdiction tax audits. We believe all other audits will be resolved within the amounts paid and/or provided for these liabilities. As of December 31, 2008,2009, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated.indicated:

United States(a)

  2001 – 2007- 2008

Canada(b)

  2000 – 20072002 - 2008

Equatorial Guinea

  2006 – 2007- 2008

Libya

  2006 – 2007- 2008

Norway

  20072008

United Kingdom

  2007 - 2008

(a)

Includes federal and state jurisdictions.

(b)

Tax years to 2001 have been audited, but remain subject to reexamination due to the existence of net operating losses.

We adopted FIN No 48the revised accounting standard for uncertainty in income taxes as of January 1, 2007. Total unrecognized tax benefits were $75 million, $39 million and $40 million as of December 31, 2009, 2008 and 2007. If the unrecognized tax benefits as of December 31, 20082009 were recognized, $29$68 million would affect our effective income tax rate. There were $10$7 million of uncertain tax positions as of that dateDecember 31, 2009 for which it is reasonably possible that the amount of unrecognized tax benefits would significantly decrease during 2009.2010.

The following table summarizes the activity in unrecognized tax benefits:

 

(In millions)  2008 2007   2009 2008 2007 

January 1 balance

  $40  $48   $39  $40  $48 

Additions based on tax positions related to the current year

      11    30   -      11 

Reductions based on tax positions related to the current year

   (2  -      -    

Additions for tax positions of prior years

   24   30    30   24   30 

Reductions for tax positions of prior years

   (26)  (30)   (15  (26  (30

Settlements

   1   (19)   (7  1   (19
                 

December 31 balance

  $39  $40   $    75  $    39  $    40 

In connection with2007, also under the adoption of FIN No. 48,revised accounting standard, we changed the presentation of interest and penalties related to income taxes in the consolidated statement of income. Effective January 1, 2007, such interest and penalties are prospectively recorded as part of the provision for income taxes. Prior to January 1, 2007, such interest was recorded as part of net interest and other financing costs and such penalties as selling, general and administrative expenses. Interest and penalties were expenses of less than $1 million in the year ended

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

December 31, 2009 and were a net $14 million credit to income in the year ended December 31, 2008 and were a net $8 million credit to income for the yearyears ended December 31, 2008 and 2007. As of December 31, 2009, 2008 and 2007, $7 million, $8 million and $15 million of interest and penalties were accrued related to income taxes.

Pretax income from continuing operations included amounts attributable to foreign sources of $4,962$2,947 million in 2009, $4,029 million in 2008, $2,900and $2,619 million in 2007, and $3,570 million in 2006.2007.

Undistributed income of certain consolidated foreign subsidiaries at December 31, 20082009 amounted to $1,626$1,903 million for which no deferred U.S. income tax provision has been recorded because we intend to permanently reinvest such income in those foreign operations. If such income was not permanently reinvested, income tax expense of $569up to $666 million would have been incurred.be recorded.

13.12.    Inventories

 

  December 31,  December 31,

(In millions)

   2008   2007  2009  2008

Liquid hydrocarbons, natural gas and bitumen

  $1,376  $1,203  $1,393  $1,376

Refined products and merchandise

   1,797   1,792   1,790   1,797

Supplies and sundry items

   334   282   439   334
            

Total, at cost

  $3,507  $3,277  $3,622  $3,507

The LIFO method accounted for 85 percent and 90 percent of total inventory value at December 31, 2009 and 2008. Current acquisition costs were estimated to exceed the LIFO inventory value at December 31, 2009 and 2008 by $3,115 million and $777 million.

Index to Financial Statements
13.    Equity Method Investments

   Ownership as of
December 31, 2009
   December 31,
(In millions)    2009  2008

EGHoldings

  60  $986  $1,053

Alba Plant LLC

  52   317   315

Atlantic Methanol Production Company LLC

  45   224   235

LOOP LLC

  51   149   143

Ethanol investments

  (a   62   70

Other

     232   264
          

Total

      $1,970  $2,080
(a)

As discussed in Note 5, Ethanol investments represent our 35 percent ownership in The Andersons Clymers Ethanol LLC and our 50 percent ownership in The Anderson Marathon Ethanol LLC. Our Ethanol investments were impaired by $40 million ($25 million, net of tax), in 2008, due to an other-than-temporary loss in value as a result of declining demand and prices for ethanol, a poor outlook for short-term future profitability and, in the case of one production facility, recurring operating losses.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

 

The LIFO method accounted for 90 percent and 89 percent of total inventory value at December 31, 2008 and 2007. Current acquisition costs were estimated to exceed the LIFO inventory value at December 31, 2008 and 2007 by $777 million and $4,034 million.

14. Equity Method Investments

   

Ownership as of

December 31, 2008

 

  December 31,
(In millions)    2008  2007

EGHoldings(a)

  60%  $1,053  $1,014

Alba Plant LLC

  52%   315   395

Atlantic Methanol Production Company LLC(b)

  45%   235   245

LOOP LLC

  51%   143   183

Ethanol investments(c)

  35% / 50%   70   97

PTC(d)

  0%      493

Other

     264   203
          

Total

     $2,080  $2,630

(a)

As discussed in Note 4, we ceased consolidating EGHoldings effective May 1, 2007; thereafter, our investments has been accounted for using the equity method of accounting. EGHoldings’ results are included in the income data below after May 1, 2007.

(b)

Atlantic Methanol Production Company LLC is engaged in methanol production activity.

(c)

As discussed in Note 5, Ethanol investments represent our ownership in The Andersons Clymers Ethanol LLC and The Anderson Marathon Ethanol LLC.

(d)

On October 8, 2008, we completed the sale of our 50 percent ownership interest in Pilot Travel Centers LLC, as discussed in Note 7 to the consolidated financial statements.

Our Ethanol investments were impaired by $40 million ($25 million, net of tax), in the fourth quarter of 2008, due to an other-than-temporary loss in value as a result of declining demand and prices for ethanol, a poor outlook for short-term future profitability and, in the case of one production facility, recurring operating losses.

Summarized financial information for equity method investees is as follows:

 

(In millions)  2008  2007  2006  2009  2008  2007

Income data – year:

              

Revenues and other income

  $15,766  $14,133  $11,873  $1,916  $15,766    $14,133

Income from operations

   1,608   1,098   746   677   1,608     1,098

Net income

   1,436   1,038   710   576   1,436      1,038

Balance sheet data – December 31:

              

Current assets

  $837  $1,279    $802  $837    

Noncurrent assets

   4,692   5,998     4,266   4,692    

Current liabilities

   993   1,512     767   993    

Noncurrent liabilities

   821   1,378      807   821      

As of December 31, 2008,2009, the carrying value of our equity method investments was $361$301 million higher than the underlying net assets of investees. This basis difference is being amortized into net income over the remaining estimated useful lives of the underlying net assets, except for $49 million of the excess related to goodwill.

Dividends and partnership distributions received from equity method investees (excluding distributions that represented a return of capital previously contributed) were $340 million in 2009, $827 million in 2008 and $502 million in 2007 and $191 million in 2006.2007. In 2008 we received a $75 million partial redemption of our partnership interest from Pilot Travel Centers that was accounted for as a return of our investment.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

15.14.    Property, Plant and Equipment

 

  December 31,  December 31,
(In millions, except per share data)  2008  2007
(In millions)  2009  2008

Exploration and production

  $22,497  $21,232  $23,436  $22,497

Oil sands mining and bitumen upgrading

   7,935   6,691   8,595   7,935

Refining

   9,026   6,462   11,522   9,026

Marketing

   2,144   2,123   2,098   2,144

Transportation

   2,592   2,331   2,703   2,592

Gas Liquefaction

   26   26

Other

   775   667   952   801
            

Total

  $44,995  $39,532  $49,306  $44,995
      

Less accumulated depreciation, depletion and amortization

   15,581   14,857   17,185   15,581
            

Net property, plant and equipment

  $29,414  $24,675  $32,121  $29,414

Property, plant and equipment includes gross assets acquired under capital leases of $82$247 million and $74$82 million at December 31, 20082009 and 2007,2008, with related amounts in accumulated depreciation, depletion and amortization of $18$26 million and $13$18 million at December 31, 20082009 and 2007.2008.

Property impairments were $19 million, $21 million and $19 million in 2009, 2008 and $25 million in 2008, 2007 and 2006.2007. The economic and commodity price declines in the latter part of 2008 and weak natural gas prices in 2009 caused us to assess the carrying value of our assets. No significant impairments resulted due to the cash flows these assets are expected to generate. Should market conditions continue to deteriorate or commodity prices continue to decline, further assessment of the carrying value of assets may be necessary.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Deferred exploratory well costs were as follows:

 

  December 31,  December 31,
(In millions, except per share data)  2008  2007  2006
(In millions)  2009  2008  2007

Amounts capitalized less than one year after completion of drilling

  $863  $683  $377  $679  $863  $683

Amounts capitalized greater than one year after completion of drilling

   54   100   93   150   54   100
                  

Total deferred exploratory well costs

  $917  $783  $470  $829  $917  $783
         

Number of projects with costs capitalized greater than one year after completion of drilling

   2   3   3   3   2   3

Exploratory well costs capitalized greater than one year after completion of drilling as of December 31, 2009 included $84 million for the Stones appraisal well incurred in 2008, included$36 million for the Gunflint/Freedom appraisal well incurred in 2008 and $30 million related to wells in Equatorial Guinea (primarily Corona and Gardenia) that was primarily incurred in 2004 and $24 million2004.

The Minerals Management Service (MMS) has approved a plan for the GudrunStones prospect. Engineering and data-gathering efforts continue to progress according to the approved plan. Various development alternatives are being evaluated and optimization efforts continue.

Appraisal drilling for the Gunflint/Freedom prospect will commence in 2010 and continue into 2011. The results of the appraisal well offshore Norway that was primarily incurred in 2006.program will be used to evaluate the commercial viability of the project.

The Equatorial Guinea discovery wells are part of our long-term LNG strategy. These discoveries will be developed when the natural gas supply from the nearby Alba Field starts to decline.

Development plans are underway for the North Sea Gudrun field, which contains both oil and natural gas. The development concept was announced by the operator in January 2009. We hold a 28 percent working interest in Gudrun. A final investment decision is expected in 2009.

The net changes in deferred exploratory well costs were as follows:

 

(In millions)  2008  2007  2006 

Beginning Balance

  $783  $470  $363 

Additions

   413   394   174 

Dry well expense

   (63)  (39)  (27)

Transfers to development

   (216)  (42)  (21)

Dispositions

         (19)
             

Ending Balance

  $917  $783  $470 

Index to Financial Statements
(In millions)  2009  2008  2007 

Beginning Balance

  $917  $783  $470 

Additions

   155   413   394 

Dry well expense

   (32  (63  (39

Transfers to development

   (211  (216  (42
             

Ending Balance

  $829  $917  $783 

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

16.15.    Goodwill

Goodwill is tested for impairment on an annual basis, or when events or changes in circumstances indicate the fair value of a reporting unit with goodwill has been reduced below the carrying value. We performed our annual impairment test during 2009 and no impairment was required. The fair value of our reporting units exceeded the book value appreciably for each of our reporting units.

We performed our 2008 annual goodwill impairment test during the second quarter for our E&P reporting unit, during the third quarter for our OSM reporting unit and during the fourth quarter for our reporting units comprising the RM&T segment, at which time no impairment to the carrying value of goodwill was identified.

The disruption in the credit and equity markets and the significant change in commodity prices that transpired during the latter part of 2008 impacts several of the significant assumptions used in our determination of fair value. As a result, we We tested goodwill for impairment again in the fourth quarter of 2008 for our E&P and OSM reporting units.units because of the late 2008 disruption in the credit and equity markets and the significant change in commodity prices impacted several of the significant assumptions used in our determination of fair value.

As there wasSince limited market-based data was available, we principally used an income based discounted cash flow model to compute the fair value of our reporting units. In applying this valuation method, there was a significant amount of judgment required, involving estimates regarding amount and timing of future production, commodity prices and the discount rate appropriate for each reporting unit. We used our planning and capital investment projections, which considersconsider factors such as a combination of proved and risk adjustedrisk-adjusted probable and possible reserves, expected future commodity prices and operating costs. An appropriate discount rate was selected for the each of the reporting units. We also compared our significant assumptions used to determine the fair value amounts against other market-based information, if available. In addition, we considered several fair value determination scenarios using key assumption sensitivities to corroborate our fair value estimates.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Testing goodwill for impairment is a two step process. The first step of the goodwill impairment test, used to identify potential impairment, compares the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to be impaired, thus the second step of the impairment test is unnecessary. If the carrying amount of a reporting unit exceeds its fair value, the second step of the goodwill impairment test is performed to measure the amount of impairment, if any. Our fourth quarter 2008 fair value estimate for the OSM reporting unit was less than the carrying amount.

The second step of the goodwill impairment test, used to measure the amount of impairment loss, compares the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. The implied fair value of goodwill shall be determined in the same manner as the amount of goodwill recognized in a business combination. This requires a hypothetical purchase price to be established as if the fair value of the reporting unit was the current price paid to acquire the reporting unit. To determine what the implied fair value of the recorded goodwill would be, the fair value for that reporting unit is hypothetically allocated to all assets and liabilities within that reporting unit. If the carrying amount of reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is required to be recognized in an amount equal to that excess.

The second step in the goodwill impairment process indicated there was no remaining implied fair value of goodwill as of December 31, 2008, for the OSM reporting unit. This was largely due to the recent disruption in the credit and equity markets, which impacts discount rate assumptions, a change in the timing of expected production and the decline in commodity prices. As a result, a $1,412 million impairment of goodwill for the OSM reporting unit was recorded and is reported on a separate line of our consolidated statement of income for 2008.

While the fair values of our other reporting units exceed the carrying value at the present time, should market conditions continue to deteriorate or commodity prices continue to decline, the goodwill of our other reporting units could require impairment.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

The changes in the carrying amount of goodwill for the years ended December 31, 2007,2009, and 2008, were as follows:

 

(In millions)  E&P  OSM  RM&T  Total 

Balance as of December 31, 2006

  $519  $  $879  $1,398 

Acquired

   71   1,437      1,508 

Adjusted(a)

         (7)  (7)
                 

Balance as of December 31, 2007

   590   1,437   872   2,899 

Adjusted(a)

   (17)  (25)  7   (35)

Impaired

      (1,412)     (1,412)

Disposed(b)

   (5)      (5)
                 

Balance as of December 31, 2008

  $568  $  $879  $1,447 

(a)

Adjustments related to prior period income tax and royalty adjustments.

(b)

Goodwill was allocated to the Norwegian outside-operated properties sold in 2008.

(In millions)  E&P  OSM  RM&T  Total 

2008

     

Beginning balance

  $590  $1,437  $872  $2,899 

Impairment

   -    (1,412  -    (1,412

Deferred tax adjustments

   (17  (9  -    (26

Purchase price adjustments

   -    (16  -    (16

Contingent consideration adjustment

   -    -    7   7 

Dispositions

   (5  -    -    (5
                 

Ending balance

   568   -    879   1,447 

2009 

     

Beginning balance, gross

   568   1,412   879   2,859 

Less: accumulated impairments

   -    (1,412  -    (1,412
                 

Beginning balance, net

   568   -    879   1,447 

Deferred tax adjustments

   -    -    9   9 

Contingent consideration adjustment

   -    -    (1)  (1)

Dispositions

   (31  -    (2  (33
                 

Ending balance, net

  $537  $-   $885  $1,422 

17.16.    Fair Value Measurements

As defined in SFAS No. 157, fairFair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. SFAS No. 157 describesThere are three approaches tofor measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

SFAS No. 157 doesThe fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. SFAS No. 157 establishesThese standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows.

 

Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

 

Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

 

Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

We use a market or income approach for recurring fair value measurements and endeavor to use the best information available. Accordingly, valuationValuation techniques that maximize the use of observable inputs are favored. Financial assetsAssets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Index We use a market or income approach for recurring fair value measurements and endeavor to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

use the best information available.

The following table presentstables present net financial assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2009 and 2008:

 

  December 31, 2009
(In millions)  Level 1  Level 2 Level 3 Total   Level 1  Level 2  Level 3  Total

Derivative instruments:

              

Commodity

  $107  $6  $(55) $58   $16  $55  $1  $72

Interest rate

         29   29    -     -     5   5

Foreign currency

      (75)     (75)   -     1   2   3
                         

Total derivative instruments

   107   (69)  (26)  12    16   56   8   80

Other assets

   2         2    3   -     -     3
                         

Total at fair value

  $109  $(69) $(26) $14   $19  $56  $8  $83

   December 31, 2008 
(In millions)  Level 1  Level 2  Level 3  Total 

Derivative instruments:

      

Commodity

  $107  $6  $(55 $58 

Interest rate

   -     -      29   29 

Foreign currency

   -     (75  -      (75
                 

Total derivative instruments

   107   (69  (26  12 

Other assets

   2   -      -      2 
                 

Total at fair value

  $109  $(69 $(26 $14 

Deposits of $63 million and $121 million in broker accounts covered by master netting agreements are included in the Level 1 and Level 2 fair values of commodity derivatives.derivatives as of December 31, 2009 and 2008. Derivatives in Level 1 are exchange-traded contracts for crude oil, natural gas, refined products and ethanol measured at fair value with a market approach using the close-of-day settlement prices for the market. Derivatives in Level 2 are measured at fair value with a market approach using broker quotes or third-party pricing services,

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

which have been corroborated with data from active markets. Level 3 derivatives are measured at fair value using either a market or income approach. Generally at least one input is unobservable, such as the use of an internally generated model or an external data source.

Derivatives in Level 3 at December 31, 2009 include interest rate derivatives which are measured at fair value using quotes from a reporting service. In addition, the fair value of the foreign currency options is measured using an option pricing model for which the inputs come from a reporting service. Because we are unable to independently verify those inputs obtained from a service directly to an active market, such inputs are considered Level 3.

Commodity derivatives in Level 3 includeat December 31, 2008 included a $72 million liability related to two U.K. natural gas sales contracts that arewere accounted for as derivative instruments and a $52 million asset for crude oil options related to sales of Canadian synthetic crude oil. The fair value of the U.K. natural gas contracts iswas measured with an income approach by applying the difference between the contract price and the U.K. forward natural gas strip price to the expected sales volumes for the shorter of the remaining contract term or 18 months.term. These contracts originated in the early 1990s and expireexpired in September 2009. The contract prices arewere reset annually in October based on the previous twelve-month changes in a basket of energy and other indices. Consequently, the prices under these contracts dodid not track forward natural gas prices. The crude oil options, which expireexpired December 2009, arewere measured at fair value using a Black-Scholes option pricing model, an income approach that utilizesused prices from an active market and market volatility calculated by a third-party service.

The interest rate derivatives are measured at fair value using quotes from our counterparties which are compared to internal calculations made using rates posted by a pricing service. Because we are unable to independently verify those rates directly to the market, such inputs are considered Level 3.

The following is a reconciliation of the net beginning and ending balances recorded for derivative instruments classified as Level 3 in the fair value hierarchy.

 

(In millions)December 31, 2008

Beginning balance

                        $(355)

Total realized and unrealized losses:

Included in net income

210

Included in other comprehensive income

1

Purchases, sales, issuances and settlements, net

   118

Ending balance

$  (26)
   December 31, 
(In millions)  2009  2008 

Beginning balance

  $(26 $(355

Total realized and unrealized losses (gains):

   

Included in net income

   68   210 

Included in other comprehensive income

   (1  1 

Purchases, sales, issuances and settlements, net

   (33  118 
         

Ending balance

  $8  $(26

The change inNet income for the years ended December 31, 2009 and 2008 included unrealized losses included in net incomeof $7 million and an unrealized gain of $299 million related to instruments held on those dates. See Note 17 for the impacts of our derivative instruments on our consolidated statements of income.

Fair Values – Nonrecurring

The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.

   Year Ended December 31, 2009
(In millions)  Fair Value  Impairment

Long-lived assets held for use

  $5  $15

Long-lived assets held for sale

   311   154

Several long-lived assets held for use were evaluated for impairment during 2009 due to reductions in estimated reserves and declining natural gas prices. The fair values of the assets were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, which are Level 3 inputs. An impairment was recorded for one natural gas field in east Texas.

The $154 million impairment charge recorded on assets held for sale in the second quarter of 2009 related to the sale of the Corrib natural gas development offshore Ireland and was based on a $311 million fair value of anticipated sale proceeds (see Note 7). Fair value of anticipated sale proceeds includes (1) $100 million received at closing, (2) $135 million minimum amount due at the earlier of first gas or December 31, 2008, was an addition2012, and (3) a range of $299zero to $165 million for 2008. Amounts reported in net income are classified as sales and other operating revenues or cost of revenues for commodity derivative instruments, as net interest and other financing income for interest rate derivative instruments and as costcontingent proceeds subject to the timing of revenues for foreign currency derivatives, except those designated as hedges of future capital expenditures. Amounts related to foreign currency derivatives designated as hedges of future capital expenditures accumulate in other comprehensive income and are amortized to depletion, depreciation and amortization over the lifefirst commercial gas. The fair value of the capital asset.total

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

 

proceeds was measured using an income method that incorporated a probability-weighted approach with respect to timing of first commercial gas and an associated sliding scale on the amount of corresponding consideration specified in the sales agreement: the longer it takes to achieve first gas, the lower the amount of the consideration. Because a portion of the proceeds is variable in timing and amount depending upon timing of first commercial gas, the inputs to the fair value calculation were classified as Level 3 inputs.

The following table summarizes financial instruments, excluding the derivative financial instruments reported above, by individual balance sheet line item at December 31, 20082009 and 2007.2008.

 

  December 31,  December 31,
  2008  2007  2009  2008
(In millions)  Fair
Value
  Carrying
Amount
  Fair
Value
  Carrying
Amount
  Fair
Value
  Carrying
Amount
  Fair
Value
  Carrying
Amount

Financial assets

                

Receivables from United States Steel, including current portion

  $438  $492  $500  $507  $360  $346  $438  $492

Other noncurrent assets(a)

   286   113   1,140   899   334   178   260   91
                        

Total financial assets

   724   605   1,640   1,406   694   524   698   583

Financial liabilities

                

Long-term debt, including current portion(b)

   5,683   6,880   7,176   6,947   8,754   8,190   5,683   6,907

Deferred credits and other liabilities(c)

   49   49   55   55
                        

Total financial liabilities

  $5,683  $6,880  $7,176  $6,947  $8,803  $8,239  $5,738  $6,962

(a)

Includes restricted cash, cost method investments, and miscellaneous long-term receivables or deposits.deposits and restricted cash.

(b)

Excludes capital leases.

(c)

Includes long-term liabilities related to contract terminations.

Our current assets and liabilities accounts contain financial instruments, the most significant of which are trade accounts receivables and payables. We believe the carrying values of our current assets and liabilities approximate fair value, with the exception of the current portion of receivables from United States Steel and the current portion of our long-term debt which isare reported above. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments (e.g., less than 1 percent of our trade receivables and payables are outstanding for greater than 90 days), (2) our investment-grade credit rating, and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.

The fair value of the receivables from United States Steel is measured using an income approach that discounts the future expected payments over the remaining term of the obligations. Because this asset is not publicly-traded and not easily transferable, a hypothetical market based upon United States Steel’s borrowing rate curve is assumed and the majority of inputs to the calculation are Level 3. The industrial revenue bonds are to be redeemed on or before the tenth anniversary of the USX Separation per the Financial Matters Agreement.

The majority of our restricted cash represent cash accounts that earn interest; therefore, the balance approximates fair value. Other financial assets included in our other noncurrent assets line include cost method investments and miscellaneous long-term receivables or deposits. Fair value for the cost method investments is measured using an income approach. Estimated future cash flows, obtained from our internal forecasts or forecasts from the partially owned companies, are discounted to obtain the fair value. Long-term receivables and deposits are also measured using an income approach. The expected timing of payments is scheduled and then discounted using a rate deemed appropriate.

Over 90 percent of our long-term debt instruments are publicly-traded. A market approach, based upon quotes from major financial institutions is used to measure the fair value of such debt. Because these quotes cannot be independently verified to the market they are considered Level 3 inputs. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.

Long-term receivables and deposits are also measured using an income approach. The expected timing of payments are scheduled and then discounted using a rate deemed appropriate.

MARATHON OIL CORPORATION

18. Derivative InstrumentsNotes to Consolidated Financial Statements

Derivative instruments are recorded at fair value. Derivative instruments on our consolidated balance sheet are reported on a net basis by brokerage firm, as permitted by master netting agreements.

17.    Derivatives

For further information regarding the fair value measurement of derivative instruments see Note 17.16. See our Note 1 for discussion of the types of derivatives we use and the reasons for them. The following table presents the gross fair values of derivative instruments, excluding cash collateral, and where they appear on the consolidated balance sheet as of December 31, 2009:

(In millions)  Asset  Liability  Net Asset  Balance Sheet Location

Cash Flow Hedges

       

Foreign currency

  $2  $        -   $2  Other current assets

Fair Value Hedges

       

Interest rate

   8   (3  5  Other noncurrent assets
              

Total Designated Hedges

   10   (3  7  

Not Designated as Hedges

       

Foreign currency

   1   -    1  Other current assets

Commodity

           116   (104          12  Other current assets
              

Total Not Designated as Hedges

   117   (104  13  
              

Total

  $127  $(107 $20   

(In millions)  Asset  Liability  Net
Liability
  Balance Sheet Location

Cash Flow Hedges

      

Foreign currency

  $-    $-     $-     Other current liabilities

Fair Value Hedges

      

Commodity

   -     (1  (1 Other current liabilities
              

Total Designated Hedges

   -     (1  (1 

Not Designated as Hedges

      

Commodity

   13   (15  (2 Other current liabilities
              

Total Not Designated as Hedges

   13   (15  (2 
              

Total

  $13  $(16 $(3  

Derivatives Designated as Cash Flow Hedges

As of December 31, 2009, the following foreign currency forwards and options were designated as cash flow hedges:

(In millions)Settlement Period

Notional

Amount

Weighted
Average
Forward
Rate

Foreign Currency Forwards Dollar (Canada)

January 2010 - February 2010$        241.062 (a)
(a)

U.S. dollar to foreign currency.

(In millions)Period

Notional

Amount

Weighted Average
Exercise Price

Foreign Currency Options Dollar (Canada)

January 2010 - September 2010$    1441.042 (a)
(a)

U.S. dollar to foreign currency.

Approximately $2 million in losses are expected to be reclassified from accumulated other comprehensive income (“AOCI”) over the next 12 months. Ineffectiveness related to cash flow hedges was a $1 million loss in 2009.

Index

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

The following table summarizes the pretax effect of derivative instruments designated as hedges of cash flows in other comprehensive income:

(In millions)  Gain (Loss) in OCI
2009
 

Foreign currency

  $39 

Interest rate

  $(15

The following table summarizes the pretax effect of AOCI reclassifications related to derivative instruments designated as hedges of cash flows in our consolidated statement of income:

(In millions)  Income Statement Location  Gain (Loss) Reclassified
from AOCI into Net
Income 2009
 

Foreign currency

  Discontinued operations  $            1 

Foreign currency

  Depreciation, depletion and amortization  $1 

Interest rate

  Net interest and other financing income (costs)  $(3

Derivatives Designated as Fair Value Hedges

As of December 31, 2009, we had multiple interest rate swap agreements with a total notional amount of $1.35 billion at a weighted-average, LIBOR-based, floating rate of 4.37 percent. As of December 31, 2009, we also had commodity derivative instruments for a weighted average 5,000 mcfd (“thousand cubic feet per day”) outstanding for the period January through March 2010

The following table summarizes the pretax effect of derivative instruments designated as hedges of fair value in our consolidated statement of income for 2009:

(In millions)  Income Statement Location  Gain (Loss)
2009
 

Derivative

    

Commodity

  Sales and other operating revenues  $(16

Interest rate

  Net interest and other financing income (costs)   -  
       
     (16
       

Hedged Item

    

Commodity

  Sales and other operating revenues           16 

Long-term debt

  Net interest and other financing income (costs)   -  

The interest rate swaps have no hedge ineffectiveness. Hedge ineffectiveness related to the commodity derivatives was less than $1 million in 2009.

Derivatives not Designated as Hedges

The two U.K. natural gas sales contracts that were accounted for as derivative instruments and the crude oil options related to the acquisition of Western Oil Sands Inc. expired in 2009.

During 2009, hedge accounting was discontinued prospectively for Kroner (Norway) and Euro foreign currency forwards when it was determined that they were no longer highly effective hedges. The Kroner contracts expired in 2009. The Euro contracts remain in place and prospective changes in the fair value of the derivative contracts will be recognized in net interest and other financing income (costs). Ineffectiveness on these hedges of $3 million was recorded as a gain to net interest and other financing income (costs) in 2009.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

As of December 31, 2009, the following foreign currency forwards not designated as hedges were outstanding:

(In millions)Settlement PeriodNotional
Amount
Weighted Average
Forward Rate

Foreign Currency Forwards

Euro

March 2010 - June 2010$            31.278(a)
(a)

Foreign currency to U.S. dollar.

The following table summarizes volumes related to our net open commodity derivatives that are not designated as hedges as of December 31, 2009:

Buy/(Sell)

Crude oil (million barrels)

(14.6

Refined products (million barrels)

(1.5

Natural gas (billion cubic feet)

Price

(41.7

Basis

(41.8

The following table summarizes the effect of all derivative instruments not designated as hedges in our consolidated statement of income for 2009:

(In millions)  Income Statement Location  Gain (Loss)
2009
 

Commodity

  Sales and other operating revenues  $76  

Commodity

  Cost of revenues   (70

Commodity

  Other income               12  

Foreign currency

  Net interest and other financing income (costs)   3  
       
      $21  

Derivative instruments reported in previous years

Accounting standards expanding the disclosure requirements for derivative instruments and hedging activities were effective January 1, 2009, and encouraged, but did not require, disclosures for earlier periods presented for comparative purposes at initial adoption. Reporting for prior-year derivatives is therefore carried forward. For more information regarding the expanded requirements, see Note 2.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

 

The following table sets forth quantitative information by category of derivative instrument at December 31, 2008 and 2007.2008. These amounts are reported on a gross basis by individual derivative instrument.

 

  2008 2007   2008 
(In millions)  Assets  (Liabilities) Assets  (Liabilities)   Assets  (Liabilities) 

Commodity Instruments

           

Fair value hedges:(a)

           

OTC commodity swaps

  $  $(12) $10  $(5)

Commodity swaps

  $-  $(12

Non-hedge designation:

           

Exchange-traded commodity futures

   279   (277)  423   (506)               279   (277

Exchange-traded commodity options

   16   (18)  312   (287)   16   (18

OTC commodity swaps

   25   (55)  17   (26)

OTC commodity options

   65   (14)     (136)

Commodity swaps

   25   (55

Commodity options

   65   (14

U.K. natural gas contracts(b)

      (72)     (291)   -   (72

Physical commodity contracts(c)

         271   (198)

Financial Instruments

           

Fair value hedges:

           

OTC interest rate swaps(d)

   29         (3)

Cash flow hedges:(e)

       

OTC foreign currency forwards

  $2  $(77) $12  $ 

Interest rate swaps(c)

   29   -  

Cash flow hedges:(d)

    

Foreign currency forwards

  $2  $(77

(a)

There was no ineffectiveness associated with fair value hedges for 2008 or 2007 because the hedging instruments and the existing firm commitment contracts were priced on the same underlying index. Derivative instruments used in the fair value hedges mature in 2009.

(b)

The contract price under the U.K. natural gas contracts iswas reset annually and iswas indexed to a basket of costs of living and energy commodity indices for the previous 12 months. The fair value of these contracts iswas determined by applying the difference between the contract price and the U.K. forward natural gas strip price to the expected sales volumes under these contracts. The U.K. natural gas contracts expireexpired September 2009.

(c)

Certain physical commodity contracts were classified as derivative instruments in 2007 because certain volumes covered by these contracts were physically netted at particular delivery locations. The netting process caused all contracts at such delivery locations to be considered derivative instruments. Other physical contracts that we chose not to designate as normal purchases or normal sales in that period were also been accounted for as derivative instruments. Beginning in the second quarter of 2008, we ceased netting volumes and elected the normal purchase and normal sale designation for our physical commodity contracts; therefore reducing substantially our number of derivative instruments.

(d)

The fair value of OTC interest rate swaps excludes accrued interest amounts not yet settled. As of December 31, 2008, and 2007, accrued interest was a receivable of $1 million and a payable of $3 million. The net fair value of the OTC interest rate swaps as of December 31, 2008 and 2007 is included in long-term debt. See Note 20.19.

(e)(d)

The changes in fair value of cash flow hedges included less than $1 million ineffectiveness during 2008 and no ineffectiveness during 2007.2008.

Pretax derivative gains and losses included in net income for 2008 and 2007 are summarized in the following table:

(In millions)  2008  2007 

Derivative gains (losses):

   

E&P segment revenues

  $22  $(15

OSM segment revenues

   48   (54

RM&T segment revenues

   (89  (900

U.K. natural gas contracts not allocated to the segments

   218   (232
         

Total net derivative gains (losses)

  $199  $(1,201

19.18.    Short Term Debt

We have a commercial paper program that is supported by the unused and available credit on our revolving credit facility discussed in Note 20.19. At December 31, 20082009 and 2007,2008, there were no commercial paper borrowings outstanding.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

 

20.19.    Long Term Debt

Our long term debt agreements do not contain restrictive financial covenants.

 

  December 31,   December 31, 
(In millions)  2008 2007   2009 2008 

Marathon Oil Corporation:

      

Revolving credit facility(a)

  $  $ 

6.850% notes due 2008

      400 

Revolving credit facility due 2012(a)

  $-   $-  

6.125% notes due 2012(b)

   450   450    450   450 

6.000% notes due 2012(b)

   400   400    400   400 

5.900% notes due 2018(c)

   1,000       1,000   1,000 

6.800% notes due 2032(b)

   550   550    550   550 

9.375% debentures due 2012

   87   87    87   87 

9.125% debentures due 2013

   174   174    174   174 

6.500% debentures due 2014(d)

   700   -  

7.500% debentures due 2019(d)

   800   -  

6.000% debentures due 2017(b)

   750   750    750   750 

9.375% debentures due 2022

   65   65    65   65 

8.500% debentures due 2023

   116   116    116   116 

8.125% debentures due 2023

   172   172    172   172 

6.600% debentures due 2037(b)

   750   750    750   750 

4.550% promissory note, semi-annual payments due 2009 – 2015

   476   544 

4.550% promissory note, semi-annual payments due 2010 - 2015

   408   476 

Series A medium term notes due 2022

   3   3    3   3 

4.750% – 6.875% obligations relating to industrial development and environmental improvement bonds and notes due 2009 – 2033(d)

   439   439 

5.125% obligation relating to revenue bonds due 2037(e)

   1,000   1,000 

Sale-leaseback financing due 2009 – 2012(f)

   37   45 

Capital lease obligation due 2009 – 2012(g)

   32   38 

4.750% - 6.875% obligations relating to industrial development and
environmental improvement bonds and notes due 2013 - 2033
(e)

   310   439 

5.125% obligation relating to revenue bonds due 2037

   1,000   1,000 

Sale-leaseback financing due 2010 - 2012(f)

   29   37 

Capital lease obligation due 2010 - 2012(g)

   25   32 

Consolidated subsidiaries

      

Revolving credit facility due 2012(h)

      599 

8.375% secured notes due 2012(b)(i)

   448   448 

Sale-leaseback financing due 2009 – 2024(j)

   103   45 

Capital lease obligations due 2009 – 2020(j)

   80   108 

8.375% secured notes due 2012(b) (h)

   448   448 

Capital lease obligations due 2010 - 2020(i)

   265   183 
              

Total(k)(l)

   7,132   7,183 

Total(j) (k)

   8,502   7,132 

Unamortized fair value differential for debt assumed in acquisitions

   37   47    27   37 

Unamortized discount

   (13)  (12)   (20  (13

Fair value adjustments on notes subject to hedging(m)

   29   (3)

Fair value adjustments(l)

   23   29 

Amounts due within one year

   (98)  (1,131)   (96  (98
              

Total long-term debt due after one year

  $7,087  $6,084   $8,436  $7,087 

(a)

During 2008, we entered into an amendment of our $3.0 billion revolving credit facility, extending the termination date on $2,625 million from May 2012 to May 2013. The remaining $375 million continues to have a termination date of May 2012. The facility requires a representation at an initial borrowing that there has been no change in our consolidated financial position or operations, considered as a whole which would materially and adversely affect our ability to perform our obligations under the revolving credit facility. Interest on the facility is based on defined short-term market rates. During the term of the agreement, we are obligated to pay a variable facility fee on the total commitment, which at December 31, 20082009 was 0.08 percent.

(b)

These notes contain a make-whole provision allowing us the right to repay the debt at a premium to market price.

(c)

On March 12,In 2008, we issued $1.0 billion aggregate principal amount of senior notes bearing interest at 5.9 percent with a maturity date of March 15, 2018. Interest on the senior notes is payable semi-annually beginning September 15, 2008.

(d)

In 2009, we issued $700 million aggregate principal amount of senior notes bearing interest at 6.5 percent with a maturity date of February 15, 2014 and $800 million aggregate principal amount of senior notes bearing interest at 7.5 percent with a maturity date of February 15, 2019. Interest on both is payable semi-annually beginning August 15, 2009.

(e)United States Steel has assumed responsibility for repayment of $415$286 million of these obligations. The Financial Matters Agreement provides that, on or before the tenth anniversary of the USX Separation, United States Steel will provide for our discharge from any remaining liability under any of the assumed industrial revenue bonds.

In 2009, US Steel refinanced and paid off $129 million face value of these bonds.

(e)

(f)

During 2007, the Parish of St. John the Baptist, where our Garyville, Louisiana, refinery is located, issued these revenue bonds associated with our Garyville refinery expansion. We are solely obligated to service the principal and interest payments associated with the bonds. The proceeds from the bonds, including interest income, were trusteed to be disbursed to us upon request for reimbursement of expenditures related to the expansion. Through December 31, 2008, such reimbursements have totaled $1,032 million. The remaining $16 million of trusteed funds, including interest income earned to date, is reflected as other noncurrent assets in the consolidated balance sheet as of December 31, 2008.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

(f)

This sale-leaseback financing arrangement relates to a lease of a slab caster at United States Steel’s Fairfield Works facility in Alabama. We are the primary obligor under this lease. Under the Financial Matters Agreement, United States Steel has assumed responsibility for all obligations under this lease. This lease is an amortizing financing with a final maturity of 2012, subject to additional extensions.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

(g)

This obligation relates to a lease of equipment at United States Steel’s Clairton Works cokemaking facility in Pennsylvania. We are the primary obligor under this lease. Under the Financial Matters Agreement, United States Steel has assumed responsibility for all obligations under this lease. This lease is an amortizing financing with a final maturity of 2012.

(h)

Marathon Oil Canada Corporation had an 805 million Canadian dollar revolving term credit facility which was secured by substantially all of Marathon Oil Canada Corporation’s assets and included certain financial covenants, including leverage and interest coverage ratios. In February 2008, the outstanding balance was repaid and the facility was terminated.

(i)

These notes are senior secured notes of Marathon Oil Canada Corporation. The notes wereare secured by substantially all of Marathon Oil Canada Corporation’s assets. In January 2008, we provided a full and unconditional guarantee covering the payment of all principal and interest due under the senior notes.

(j)

(i)

These obligations as of December 31, 20082009 include $126$36 million related to assets under construction at that date for which a capital leases or sale-leaseback financingslease will commence upon completion of construction. The amounts currently reported are based upon the percent of construction completed as of December 31, 20082009 and therefore do not reflect future minimum lease obligations of $209 million.

$164 million related to the asset.

(k)

(j)

Payments of long-term debt for the years 2009 – 20132010 - 2014 are $99$102 million, $98$246 million, $257$1,492 million, $1,487$287 million and $279$802 million. Of these amounts, payments assumed by United States Steel are $15 million,is due to pay $17 million in 2010, $161 million in 2011, $19 million in 2012, and zero.

$11 for year 2014.

(l)

(k)

In the event of a change in control, as defined in the related agreements, debt obligations totaling $669$662 million at December 31, 2008,2009, may be declared immediately due and payable.

(m)

(l)

See Note 1716 for information on interest rate swaps.

On February 17, 2009, we issued $700 million aggregate principal amount of senior notes bearing interest at 6.5 percent with a maturity date of February 15, 2014 and $800 million aggregate principal amount of senior notes bearing interest at 7.5 percent with a maturity date of February 15, 2019. Interest on both issues is payable semi-annually beginning August 15, 2009.

21.20. Asset Retirement Obligations

The following summarizes the changes in asset retirement obligations:

 

(In millions)  2008 2007   2009 2008 

Asset retirement obligations as of January 1

  $1,134  $1,044   $965  $    1,134 

Liabilities incurred, including acquisitions

   30   60    14   30 

Liabilities settled

   (94)  (10)   (65  (94

Accretion expense (included in depreciation, depletion and amortization)

   66   61    64   66 

Revisions to previous estimates

   24   (17)   124   24 

Held for sale(a)

   (195)      -    (195

Deconsolidation of EGHoldings

      (4)
              

Asset retirement obligations as of December 31(b)

  $965  $1,134 

Asset retirement obligations as of December 31(a)

  $    1,102  $965 

(a)

See Note 7 for information related to our assets held for sale.

(b)

Includes asset retirement obligation of $2$3 and $3$2 million classified as short-term at December 31, 2008,2009, and 2007.2008.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

 

22.21.    Supplemental Cash Flow Information

 

(In millions)  2008 2007 2006   2009 2008 2007 

Net cash provided from operating activities from continuing operations included:

        

Interest paid (net of amounts capitalized)

  $92  $66  $96   $19  $92  $66 

Income taxes paid to taxing authorities

   2,921   3,283   4,149        1,663   2,921   3,283 

Income tax settlements paid to United States Steel

      13   35    -    -    13 

Commercial paper and revolving credit arrangements, net:

        

Commercial paper – issuances

  $46,706  $12,751  $1,321 

– repayments

   (46,706)  (12,751)  (1,321)

Credit agreements – borrowings

   404       

– repayments

   (404)      

Commercial paper - issuances

  $897  $46,706  $12,751 

- repayments

   (897      (46,706      (12,751

Credit agreements - borrowings

   -    404   -  

- repayments

   -    (404  -  

Noncash investing and financing activities:

        

Additions to property, plant and equipment

    

Asset retirement costs capitalized, excluding acquisitions

  $26  $8  $286   $135  $26  $8 

Debt payments assumed by United States Steel

   14   21   24 

Capital lease and sale-leaseback financing obligations

   84   49   1 

Change in capital expenditure accrual

   (343  30   621 

Debt payments made by United States Steel

   144   14   21 

Capital lease and sale-leaseback financing obligations increase

   86   84   49 

Bond obligation assumed for trusteed funds

      1,000       -    -    1,000 

Acquisitions:

        

Debt and other liabilities assumed

      1,541   26    -    -    1,541 

Common stock or securities exchangeable for common stock issued to seller

      1,910    

Noncash effect of deconsolidation of EGHoldings:

    

Common stock or securities exchangeable for common stock issued

   -    -    1,910 

Deconsolidation of EGHoldings:

    

Decrease in non-cash assets

  $  $1,759  $    -    -    1,759 

Equity method investment recorded

      942       -    -    942 

Decrease in liabilities

      310       -    -    310 

Elimination of minority interests

      544       -    -    544 

23.22.    Defined Benefit and Other Postretirement Plans

We have noncontributory defined benefit pension plans covering substantially all domestic employees as well as international employees located in Ireland, Norway and the United Kingdom. BenefitsThrough 2009, benefits under these plans arehave been based primarily on years of service and final average pensionable earnings.

We also have defined benefit plans for other postretirement benefits covering most employees. Health care benefits are provided through comprehensive hospital, surgical and major medical benefit provisions subject to various cost sharingcost-sharing features. Life insurance benefits are provided to certain nonunion and union-represented retiree beneficiaries. Other postretirement benefits haveare not been funded in advance.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

 

Obligations and funded status The following summarizes the obligations and funded status for our defined benefit pension and other postretirement plans:plans.

 

  Pension Benefits Other Benefits  Pension Benefits Other Benefits 
  2008 2007 2008 2007  2009 2008 2009 2008  
(In millions)  U.S. Int’l U.S. Int’l        U.S. Int’l U.S. Int’l       

Change in benefit obligations:

             

Benefit obligations at January 1

  $2,143  $426  $2,077  $381  $736  $821  $2,164  $288  $2,143  $426  $694  $736   

Service cost

   127   19   126   14   18   22   130   14   127   19   17   18   

Interest cost

   135   25   124   18   44   45   146   22   135   25   41   44   

Actuarial loss (gain)

   (58)  (72)  (8)  9   (75)  (122)  703   85   (58  (72  (35  (75)  

Plan amendment

      1               -    -    -    1   -    -  

Foreign currency exchange rate changes

      (99)     13         -    26   -    (99  -    -  

Divestiture(a)

  -    (30  -    -    -   

Benefits paid

   (183)  (12)  (176)  (9)  (29)  (30)  (154  (10  (183  (12  (32  (29)  
                                     

Benefit obligations at December 31

  $2,164  $288  $2,143  $426  $694  $736  $2,989  $395  $2,164  $288  $685  $694  

Change in plan assets:

             

Fair value of plan assets at January 1

  $1,790  $381  $1,688  $301  $  $  $1,203  $    288  $1,790  $381  $-   $-  

Actual return on plan assets

   (448)  (28)  148   28         257   52   (448  (28  -    -  

Employer contributions

   44   41   130   55         311   34   44   41   -    -  

Foreign currency exchange rate changes

      (94)     6         -    28   -    (94  -    -  

Benefits paid to plan assets

   (183)  (12)  (176)  (9)      

Divestiture(a)

  -    (44  -    -    -    -  

Other

  6   -    -    -    -    -  

Benefits paid

  (154  (10  (183  (12  -    -  
                                     

Fair value of plan assets at December 31

  $1,203  $288  $1,790  $381  $  $  $1,623  $348  $    1,203  $    288  $-   $-  

Funded status of plans at December 31

  $(961) $  $(353) $(45) $(694) $(736) $(1,366 $(47 $(961 $-   $    (685 $    (694

Amounts recognized in the consolidated balance sheet:

             

Current liabilities

   (11)     (7)     (35)  (35)  (18  -    (11  -    (34  (35)  

Noncurrent liabilities

   (950)     (346)  (45)  (659)  (701)  (1,348  (47  (950  -    (651  (659
                                     

Accrued benefit cost

  $(961) $  $(353) $(45) $(694) $(736) $    (1,366 $(47 $(961 $-   $(685 $(694

Pretax amounts in accumulated other comprehensive income:(a)

       

Pretax amounts in accumulated other comprehensive income:(b)

      

Net loss (gain)

  $785  $26  $281  $62  $(23) $54   $1,338  $71  $785  $26  $(53 $(23

Prior service cost (credit)

   106   1   119      (36)  (44)  93   -    106   1   (30  (36)  

(a)

Excludes amountsThe divestiture is related to our discontinued operations in Ireland, as discussed in Note 7

(b)

Amount excludes those related to LOOP LLC, an equity method investee with defined benefit pension and postretirement plans for which net losses of $8 million and $10 million and $7 million were reflectedrecorded in accumulated other comprehensive income, reflecting our 51 percent share.

The accumulated benefit obligation for all defined benefit pension plans was $1,975$2,659 million and $2,028$1,975 million as of December 31, 20082009 and 2007.2008.

The following summarizes all of our defined benefit pension plans that have accumulated benefit obligations in excess of plan assetsassets.

 

  December 31,   December 31,
  2008  2007   2009 2008
(In millions)  U.S. Int’l  U.S. Int’l   U.S. Int’l U.S. Int’l

Projected benefit obligation

  $(2,164) $  –  $(100) $(397)  $(2,989 $(395 $(2,164 $-

Accumulated benefit obligation

   (1,711)     (81)  (366)   (2,300  (359  (1,711  -

Fair value of plan assets

   1,203         352        1,623         348       1,203               -

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

 

Components of net periodic benefit cost and other comprehensive income – The following summarizes the net periodic benefit costs and the amounts recognized as other comprehensive income for our defined benefit pension and other postretirement plans.

 

  Pension Benefits        Pension Benefits Other Benefits 
  2008 2007 2006 Other Benefits  2009 2008 2007 
(In millions)  U.S. Int’l U.S. Int’l U.S. Int’l 2008 2007 2006  U.S. Int’l U.S. Int’l U.S. Int’l 2009 2008 2007 

Components of net periodic benefit cost:

                   

Service cost

  $127  $19  $126  $14  $117  $17  $18  $22  $23  $130  $14  $127  $19  $126  $14  $17  $18  $22 

Interest cost

   135   25   124   18   113   17   44   45   42   146   22   135   25   124   18   41   44   45 

Expected return on plan assets

   (142)  (26)  (135)  (19)  (103)  (15)               (141      (21      (142      (26      (135      (19  -    -    -  

Amortization – prior service cost (credit)

   13      13      8      (8)  (10)  (11)

– actuarial loss

   29   3   36   3   34   7   1   8   9 

Amortization

         

- prior service cost (credit)

  13   1   13   -    13   -    (5  (8  (10

- actuarial loss

  29   2   29   3   36   3   (5  1   8 

Net settlement/curtailment loss(a) (b)

  4   18   -    -    -    -    -    -    -  
                                                       

Net periodic benefit cost(a)

  $162  $21  $164  $16  $169  $26  $55  $65  $63 

Net periodic benefit cost(c)

 $181  $36  $162  $21  $164  $16  $48  $55  $65 
                           

Other changes in plan assets and benefit obligations recognized in other comprehensive income (pretax):

         

Actuarial loss (gain)

 $587  $52  $532  $(32 $(21 $7  $    (34 $    (76 $    (122

Amortization of actuarial loss

  (33  (7  (29  (3  (36  (3  5   (1  (8

Prior service cost

  -    -    -    1   -    -    5   -    -  

Amortization of prior service credit (cost)

  (13  (1  (13  -    (13  -    -    8   10 
                           

Total recognized in other comprehensive income

 $541  $44  $490  $(34 $(70 $4  $(24 $(69 $(120
                           

Total recognized in net periodic benefit cost and other comprehensive income

 $722  $80  $652  $(13 $94  $20  $24  $(14 $(55

(a)

UsesA settlement was recorded for one U.S. plan due to lump sum payments exceeding the plan’s total service and interest cost expensed in 2009.

(b)

A curtailment and settlement were recorded related to our discontinued operations in Ireland, as discussed in Note 7.

(c)

Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over 3three years.

   Pension Benefits  

Other
Benefits

 

 
(In millions)      U.S.          Int’l      

2008

    

Other changes in plan assets and benefit obligations recognized in other comprehensive income (pretax):

    

Actuarial loss (gain)

  $532  $(32) $(76)

Amortization of actuarial loss

   (29)  (3)  (1)

Prior service cost

      1    

Amortization of prior service credit (cost)

   (13)     8 
             

Total recognized in other comprehensive income

  $490  $(34) $(69)
             

Total recognized in net periodic benefit cost and other comprehensive income

  $652  $(13) $(14)

2007

    

Other changes in plan assets and benefit obligations recognized in other comprehensive income (pretax):

    

Actuarial loss (gain)

  $(21) $7  $(122)

Amortization of actuarial loss

   (36)  (3)  (8)

Amortization of prior service credit (cost)

   (13)     10 
             

Total recognized in other comprehensive income

  $(70) $4  $(120)
             

Total recognized in net periodic benefit cost and other comprehensive income

  $94  $20  $(55)

The estimated net loss and prior service cost for theour defined benefit pension plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 20092010 are $25$102 million and $13 million. The 2010 net loss amortization is expected to be higher than the 2009 actual amortization primarily as a result of the decrease in the discount rate as shown in the table below. The estimated net gain and prior service credit for theour other defined benefit postretirement plans that will be amortized from accumulated other comprehensive income into net periodic benefit cost in 20092010 are $1$2 million and $5$6 million.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

��

Plan assumptions – The following summarizes the assumptions used to determine the benefit obligations at December 31, and net periodic benefit cost for the defined benefit pension and other postretirement plans for the 2009, 2008 2007 and 2006.2007.

 

   Pension Benefits  Other Benefits
   2008  2007  2006  
(In millions)  U.S.  Int’l  U.S.  Int’l  U.S.  Int’l  2008  2007  2006

Weighted average assumptions used to determine benefit obligation:

          

Discount rate

  6.90% 6.70% 6.30% 5.80% 5.80% 5.20% 6.85% 6.60% 5.90%

Rate of compensation increase

  4.50% 4.75% 4.50% 5.15% 4.50% 4.75% 4.50% 4.50% 4.50%

Weighted average actuarial assumptions used to determine net periodic benefit cost:

          

Discount rate(a)

  6.30% 5.80% 5.81% 5.20% 5.70% 4.70% 6.60% 5.90% 5.75%

Expected long-term return on plan assets

  8.50% 6.48% 8.50% 6.45% 8.50% 6.07%     –   

Rate of compensation increase

  4.50% 5.15% 4.50% 4.75% 4.50% 4.55% 4.50% 4.50% 4.50%

(a)

On December 15, 2007, due to an interim remeasurement, the discount rate for the U.S. pension plans was increased to 5.93 percent from 5.80 percent. On July 31, 2006, due to an interim remeasurement, the discount rate for the U.S. pension plans was increased to 6.00 percent from 5.50 percent.

   Pension Benefits          
   2009  2008  2007  Other Benefits 
(In millions)  U.S.  Int’l  U.S.  Int’l  U.S.  Int’l  2009  2008  2007 

Weighted average assumptions used to determine benefit obligation:

          

Discount rate

  5.50 5.70 6.90 6.70 6.30 5.80 5.95 6.85 6.60

Rate of compensation increase

  4.50 5.55 4.50 4.75 4.50 5.15 4.50 4.50 4.50

Weighted average assumptions used to determine net periodic benefit cost:

          

Discount rate

  6.90 6.70 6.30 5.80 5.81 5.20 6.85 6.60 5.90

Expected long-term return on plan assets

  8.50 6.10 8.50 6.48 8.50 6.45 -   -   -  

Rate of compensation increase

  4.50 4.75 4.50 5.15 4.50 4.75 4.50 4.50 4.50

Expected long-term return on plan assets

U.S. Plans – Historical markets are studied and long-term historical relationships between equities and fixed income securities are preserved consistent with the widely accepted capital market principle that assets with higher volatility generate a greater return over the long term. Certain components of the asset mix are modeled with various assumptions regarding inflation, debt returns and stock yields. The assumptions are compared to those of peer companies and to historical returns for reasonableness and appropriateness.

International Plansplans – The overall expected long-term return on plan assets assumption for our U.S. plans is derived using thedetermined based on an asset rate-of-return modeling tool developed by a third-party investment group. The tool utilizes underlying assumptions based on actual returns by asset category and inflation and takes into account our U.S. pension plans’ asset allocation to derive an expected returns on the individual asset classes, weighted by holdings as of year end. The long-term rate of return on those assets. Capital market assumptions reflect the long-term capital market outlook. The assumptions for equity and fixed income investments is assumed to be 2.5 percent greater thanare developed using a building-block approach, reflecting observable inflation information and interest rate information available in the yieldfixed income markets. Long-term assumptions for other asset categories are based on local government bonds. Expectedhistorical results, current market characteristics and the professional judgment of our internal and external investment teams.

International plans – To determine the overall expected long-term return on plan assets assumption for our international plans, we consider the current level of expected returns on debt securities are estimated directly at market yieldsrisk-free investments (primarily government bonds), the historical levels of the risk premiums associated with the other applicable asset categories and the expectations for future returns of each asset class. The expected return for each asset category is then weighted based on cash are estimated at the local currency base rate.actual asset allocation in our international pension plans to develop the overall expected long-term return on plan assets assumption.

Assumed health care cost trend

The following summarizes the assumed health care cost trend rates.

 

  2008 2007 2006  2009 2008 2007 

Health care cost trend rate assumed for the following year:

        

Medical

  7.0% 7.5% 8.0%    

Pre-65

  7.00 7.00 7.50

Post-65

  6.75 7.00 7.50

Prescription drugs

  10.0% 10.5% 11.0%  7.50 10.00 10.50

Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):

        

Medical

  5.0% 5.0% 5.0%    

Pre-65

  5.00 5.00 5.00

Post-65

  5.00 5.00 5.00

Prescription drugs

  6.0% 6.0% 6.0%  5.00 6.00 6.00

Year that the rate reaches the ultimate trend rate:

        

Medical

  2012  2012  2012       

Pre-65

  2014  2012  2012 

Post-65

  2015  2012  2012 

Prescription drugs

  2016  2016  2016     2015  2016  2016 

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

 

Assumed health care cost trend rates have a significant effect on the amounts reported for defined benefit retiree health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

 

(In millions)  1-Percentage-
Point Increase
  1-Percentage-
Point Decrease
   1-Percentage-
Point Increase
  1-Percentage-
Point Decrease

Effect on total of service and interest cost components

  $10  $(8)  $        9  $        7

Effect on other postretirement benefit obligations

   89   (74)   88   72

Plan assets – The following summarizes the defined benefit pension plans’ weighted-average asset allocations by asset category as of December 31, 2008, and 2007.

   2008  2007
    U.S.  Int’l  U.S.  Int’l    

Equity securities

  74% 61% 74% 68% 

Debt securities

  21% 38% 20% 32% 

Real estate

  4% 0% 3% 0% 

Other

  1% 1% 3% 0% 
               

Total

  100% 100% 100% 100%  

Plan investment policies and strategies

U.S. PlansThe investment policy reflectspolicies for our U.S. and international pension plan assets reflect the funded status of the plans and expectations regarding our future ability to make further contributions. Long-term investment goals are to: (1) manage the assets in accordance with the legal requirements of all applicable laws; (2) produce investment returns which meet or exceed the rates of return achievable in the capital markets while maintaining the risk parameters set by the plans’ investment committees and protecting the assets from any erosion of purchasing power; and (3) position the portfolios with a long-term risk/return orientation.

U.S. plans Historical performance and future expectations suggest that common stocks will provide higher total investment returns than fixed-incomefixed income securities over a long-term investment horizon. As a result, equity investments will likely continue to exceed 50 percent of the value of the fund. Accordingly, bond and other fixed- income investments will comprise the remainder of the fund. Short-term investments shallonly reflect the liquidity requirements for making pension payments. TheAs such, the plans’ targeted asset allocation is comprised of 75 percent equity securities and 25 percent fixed-income, real estate-relatedfixed income securities. In the second quarter of 2009, we exchanged the majority of our publicly-traded stocks and bonds for interests in pooled equity and fixed income investment funds from our outside manager, representing 58 percent and 20 percent of U.S. plan assets, respectively, as of December 31, 2009. These funds are managed with the same style and strategy as when the securities were held separately. Each fund’s main objective is to provide investors with exposure to either a publicly-traded equity or fixed income portfolio comprised of both U.S. and non-U.S. securities. The equity fund holdings primarily consist of publicly-traded individually-held securities in various sectors of many industries. The fixed income fund holdings primarily consist of publicly-traded investment-grade bonds.

The plans’ assets are managed by a third-party investment manager. The investment manager has limited discretion to move away from the target allocations based upon the manager’s judgment as to current confidence or concern forregarding the capital markets. Investments are diversified by industry and type, limited by grade and maturity. The plans’ investment policy prohibits investments in any securities in the steel industry and allows derivatives subject to strict guidelines, such that derivatives may only be written against equity securities in the portfolio. Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies.

International PlansplansThe objective of the investment policy is to achieve a long-term return which is consistent with assumptions made by the actuary in determining the funding requirements of the plans. TheOur international plans’ target asset allocation is comprised of 70 percent equity securities and 30 percent debtfixed income securities. The day-to-day management of the plans’plan assets is delegated toare invested in six separate portfolios, mainly pooled fund vehicles, managed by several professional investment managers. The spread of assetsInvestments are diversified by industry and type, limited by grade and the investment managers’ policies on investing in individual securities within each type provide adequate diversification of investments.maturity. The use of derivatives by the investment managers is permitted, and plan specific, subject to strict guidelines. InvestmentThe investment managers’ performance is measured independently by a third-party asset servicing consulting firm. Overall, investment performance and risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews and periodic asset and liability studies.

Fair value measurements

Plan assets are measured at fair value. The definition and approaches to measuring fair value and the three levels of the fair value hierarchy are described in Note 16. The following provides a description of the valuation techniques employed for each major plan asset category at December 31, 2009 and 2008.

Cash flowsand cash equivalents –Cash and cash equivalents include cash on deposit and an investment in a money market mutual fund that invests mainly in short-term instruments and cash, both of which are valued using a

MARATHON OIL CORPORATION

Plan Notes to Consolidated Financial Statements

market approach and are considered Level 1 in the fair value hierarchy. The money market mutual fund is valued at the net asset value (“NAV”) of shares held.

Equity securities – Investments in public investment trusts and S&P 500 exchange-traded funds are valued using a market approach at the closing price reported in an active market and are therefore considered Level 1. Non-public investment trusts are valued using a market approach based on the underlying investments in the trust, which are publicly-traded securities, and are considered Level 2. Private equity investments include interests in limited partnerships which are valued based on the sum of the estimated fair values of the investments held by each partnership, determined using a combination of market, income and cost approaches, plus working capital, adjusted for liabilities, currency translation and estimated performance incentives. These private equity investments are considered Level 3.

Mutual funds – Investments in mutual funds are valued using a market approach at the NAV of shares or units held. The NAV is generally based on prices from a public exchange, which is normally the principal market on which a significant portion of the underlying investments are traded, and is considered Level 1.

Pooled funds – Investments in pooled funds are valued using a market approach at the NAV of units held, but investment opportunities in such funds are limited to institutional investors on the behalf of defined benefit plans. The various funds consist of either an equity or fixed income investment portfolio with underlying investments held in U.S. and non-U.S. securities. A significant portion of the underlying investments are publicly-traded. The majority of the pooled funds held by our international pension plans are benchmarked against a relative public index as defined under the plans’ investment policies. These investments are considered Level 2.

Real estate – Real estate investments are valued based on discounted cash flows, comparable sales, outside appraisals, price per square foot or some combination thereof and therefore are considered Level 3.

Other – Other investments are composed of an investment in an unallocated annuity contract and investments in two limited liability companies (“LLCs”) with no public market. The LLCs were formed to acquire acres of timberland in the southwest and other properties. The investment in an unallocated annuity contract is valued using a market approach based on the experience of the assets held in an insurer’s general account and is considered Level 2. The majority of the general account is invested in a well-diversified portfolio of high-quality fixed income securities, primarily consisting of investment-grade bonds. Investment income is allocated among pension plans participating in the general account based on the investment year method. Under this method, a record of the book value of assets held is maintained in subdivisions according to the calendar year in which the funds are invested. The earnings rate for each of these calendar year subdivisions varies from year to year, reflecting the actual earnings on the assets attributed to that year. The values of the LLCs are determined using an income approach based on discounted cash flows and are considered Level 3.

The following table presents the fair values of our defined benefit pension plans’ assets, by level within the fair value hierarchy, as of December 31, 2009.

(In millions)  Level 1  Level 2  Level 3  Total
   U.S.  Int’l  U.S.  Int’l  U.S.  Int’l  U.S.  Int’l

Cash and cash equivalents

  $        12  $1  $-  $-  $-  $-  $12  $1

Equity securities:

                

Investment trusts

   21   -   114   -   -   -   135   -

Exchange traded funds

   26   -   -   -   -   -   26   -

Private equity

   -   -   -   -   42   -   42   -

Investment funds

                

Mutual funds—equity

   -         145   -   -   -   -   -   145

Pooled funds—equity

   -   -   930   103   -   -   930   103

Pooled funds—fixed income

       327   99       327   99

Real estate

   -   -   -   -   36   -   36   -

Other(a)

   -   -   92   -   23   -   115   -
                                

Total investments, at fair value

  $59  $146  $  1,463  $      202  $      101  $          -  $  1,623  $      348
(a)

Includes an $86 million receivable for the sale of an investment that closed as of December 31, 2009 but did not cash settle until the next business day.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

The following is a reconciliation of the beginning and ending balances recorded for plan assets classified as Level 3 in the fair value hierarchy.

(In millions)  

Private

Equity

  

Real

Estate

  Other  Total 

Balance as of December 31, 2008

  $        35  $        51  $7  $93 

Actual Return on plan assets held at December 31, 2009

   2   (21  1   (18

Purchases, sales and settlements, net

   5   6   15   26 
                 

Balance as of December 31, 2009

  $42  $36  $        23  $        101 

Cash flows

Contributions to defined benefit plans – We expect to make contributions to the funded pension plans of up to $439$17 million in 2009.2010. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are expected to be approximately $11$18 million and $40$39 million in 2009.2010.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Estimated Future Benefit Paymentsfuture benefit payments – The following gross benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated.

 

  Pension
Benefits
  Other
Benefits
(a)
   Pension Benefits  Other
Benefits
(a)
 
(In millions)  U.S.  Int’l    U.S.  Int’l  

2009

  $178  $10  $40 

2010

   195   12   43   $        208  $        10  $        39   

2011

   214   13   46    225   11   42   

2012

   239   15   49    247   12   44   

2013

   253   15   52    260   12   47   

2014 through 2018

   1,410   117   307 

2014

   272   15   50   

2015 through 2019

   1,489   102   288   

(a)

Expected Medicare reimbursements for 20092010 through 20182019 total $57$54 million.

Other Plan Contributions to defined contribution plans – We also contribute to several defined contribution plans for eligible employees. Contributions to these plans totaled $59 million in 2009, $49 million in 2008 and $55 million in 2007 and $47 million in 2006.2007.

24.23.    Stock-Based Compensation Plans

Description of the Plans

The Marathon Oil Corporation 2007 Incentive Compensation Plan (the “2007 Plan”) was approved by our stockholders in April 2007 and authorizes the Compensation Committee of the Board of Directors to grant stock options, stock appreciation rights, stock awards (including restricted stock and restricted stock unit awards) and performance awards to employees. The 2007 Plan also allows us to provide equity compensation to our non-employee directors. No more than 34 million shares of Marathon common stock may be issued under the 2007 Plan and no more than 12 million of those shares may be used for awards other than stock options or stock appreciation rights.

Shares subject to awards under the 2007 Plan that are forfeited, are terminated or expire unexercised become available for future grants. If a stock appreciation right is settled upon exercise by delivery of shares of common stock, the full number of shares with respect to which the stock appreciation right was exercised will count against the number of shares of Marathon common stock reserved for issuance under the 2007 Plan and will not again become available under the 2007 Plan. In addition, the number of shares of Marathon common stock reserved for issuance under the 2007 Plan will not be increased by shares tendered to satisfy the purchase price of an award, exchanged for other awards or withheld to satisfy tax withholding obligations. Shares issued as a result of awards granted under the 2007 Plan are generally funded out of common stock held in treasury, except to the extent there are insufficient treasury shares, in which case new common shares are issued.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

After approval of the 2007 Plan, no new grants were or will be made from the 2003 Incentive Compensation Plan (the “2003 Plan”). The 2003 Plan replaced the 1990 Stock Plan, the Non-Officer Restricted Stock Plan, the Non-Employee Director Stock Plan, the deferred stock benefit provision of the Deferred Compensation Plan for Non-Employee Directors, the Senior Executive Officer Annual Incentive Compensation Plan and the Annual Incentive Compensation Plan (the “Prior Plans”). No new grants will be made from the Prior Plans. Any awards previously granted under the 2003 Plan or the Prior Plans shall continue to vest or be exercisable in accordance with their original terms and conditions.

Stock-based awards under the Plan

Stock options – We grant stock options under the 2007 Plan. Our stock options represent the right to purchase shares of Marathon common stock at its fair market value on the date of grant. Through 2004, certain stock options were granted under the 2003 Plan with a tandem stock appreciation right, which allows the recipient to instead elect to receive cash or Marathon common stock equal to the excess of the fair market value of shares of common stock, as determined in accordance with the 2003 Plan, over the option price of the shares. In general, stock options granted under the 2007 Plan and the 2003 Plan vest ratably over a three-year period and have a maximum term of ten years from the date they are granted.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Stock appreciation rights – Prior to 2005, we granted SARs under the 2003 Plan. No stock appreciation rights have been granted under the 2007 Plan. Similar to stock options, stock appreciation rights represent the right to receive a payment equal to the excess of the fair market value of shares of common stock on the date the right is exercised over the grant price. Under the 2003 Plan, certain SARs were granted as stock-settled SARs and others were granted in tandem with stock options. In general, SARs granted under the 2003 Plan vest ratably over a three-year period and have a maximum term of ten years from the date they are granted.

Stock-based performance awards – Prior to 2005, we granted stock-based performance awards under the 2003 Plan. No stock-based performance awards have been granted under the 2007 Plan. Beginning in 2005, we discontinued granting stock-based performance awards and instead now grant cash-settled performance units to officers. All stock-based performance awards granted under the 2003 Plan have either vested or been forfeited. As a result, there are no outstanding stock-based performance awards.

Restricted stock – We grant restricted stock and restricted stock units under the 2007 Plan and previously granted such awards under the 2003 Plan. In 2005, the Compensation Committee began granting time-based restricted stock to certain U.S.-based officers of Marathon and its consolidated subsidiaries as part of their annual long-term incentive package. The restricted stock awards to officers vest three years from the date of grant, contingent on the recipient’s continued employment. We also grant restricted stock to certain non-officer employees and restricted stock units to certain international employees (“restricted stock awards”), based on their performance within certain guidelines and for retention purposes. The restricted stock awards to non-officers generally vest in one-third increments over a three-year period, contingent on the recipient’s continued employment, however, certain restricted stock awards granted in 2008 will vest over a four-year period, contingent on the recipient’s continued employment. Prior to vesting, all restricted stock recipients have the right to vote such stock and receive dividends thereon. The non-vested shares are not transferable and are held by our transfer agent.

Common stock units – We maintain an equity compensation program for our non-employee directors under the 2007 Plan and previously maintained such a program under the 2003 Plan. All non-employee directors other than the Chairman receive annual grants of common stock units, and they are required to hold those units until they leave the Board of Directors. When dividends are paid on Marathon common stock, directors receive dividend equivalents in the form of additional common stock units.

Total Stock-based Compensation Expensestock-based compensation expense

Total employee stock-based compensation expense was $76 million, $43 million and $66 million in 2009, 2008 and $78 million in 2008, 2007, and 2006. Thewhile the total related income tax benefits were $29 million, $16 million and $24 million and $29 million.in the same years. In 2009, 2008 and 2007 cash received upon exercise of stock option awards was $4 million, $9 million and $27 million. Tax benefits realized for deductions for stock awards exercised during 2009, 2008 and 2007 that were in excess of the stock-based compensation expense recorded for options exercised and other stock-based awards vested during the

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

period totaled $7$1 million, $4 million and $30$24 million. Cash settlements of stock option awards totaled $1 million in 2007. There were no cash settlements in 2009 or 2008.

Stock Option Awardsoption awards

During 2009, 2008 2007 and 2006,2007, we granted stock option awards to both officer and non-officer employees. The weighted average grant date fair value of these awards was based on the following Black-Scholes assumptions:

 

    2008  2007  2006

Weighted average exercise price per share

  $51.74  $60.94  $37.84   

Expected annual dividends per share

  $0.96  $0.96  $0.80   

Expected life in years

   4.8   5.0   5.1   

Expected volatility

   30%  27%  28%

Risk-free interest rate

   3.1%  4.1%  5.0%

Weighted average grant date fair value of stock option awards granted

  $13.03  $17.24  $10.19   

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

    2009  2008  2007

Weighted average exercise price per share

  $        27.62  $51.74  $        60.94

Expected annual dividends per share

   0.96   0.96   0.96

Expected life in years

   4.9   4.8   5.0

Expected volatility

   41%   30%   27%

Risk-free interest rate

   2.3%   3.1%   4.1%

Weighted average grant date fair value of stock option awards granted

  $7.67  $        13.03  $17.24

The following is a summary of stock option award activity in 2008.2009.

 

  Number of
Shares
 Weighted-
Average
Exercise
price
  

Number

of Shares

 

Weighted -

Average
Exercise price

Outstanding at December 31, 2007

  12,214,853  $34.58

Outstanding at December 31, 2008

  13,841,748  $        37.59

Granted

  2,558,409   51.74  4,970,500   27.62

Exercised

  (491,248)  18.07  (273,382  15.89

Cancelled

  (440,266)  51.75  (308,792  45.27
          

Outstanding at December 31, 2008

  13,841,748   37.59

Outstanding at December 31, 2009

  18,230,074  $35.01

The intrinsic value of stock option awards exercised during 2009, 2008 and 2007 and 2006 was $3 million, $12 million $64 million and $107$64 million. Of those amounts, $0,$1 million in 2009 and $10 million and $32 million relatein 2007 related to stock options with tandem SARs. No stock options with tandem SARs were exercised in 2008.

The following table presents information related to stock option awards at December 31, 2008.2009.

 

  

Outstanding

  

Exercisable

  

Outstanding

  

Exercisable

Range of
Exercise Prices
  Number
of Shares
Under Option
  Weighted-
Average
Remaining
Contractual
Life
  Weighted-
Average
Exercise Price
  Number
of Shares
Under Option
  Weighted-
Average
Exercise Price
  

Number of
Shares Under
Option

  

Weighted - -
Average
Remaining
Contractual
Life

  

Weighted-
Average
Exercise Price

  

Number

of Shares Under
Option

  

Weighted-
Average
Exercise Price

$ 12.75-17.00

    3,353,046  5  $15.56         3,353,046  $15.56      

23.21-29.10

    2,443,668  6  24.97         2,440,477  24.96      

$ 12.75-16.81

  3,179,480  4  $        15.56  3,179,480  $        15.56

23.21-29.24

  7,242,984  8            26.77  2,445,856            24.90

37.82-47.91

    2,711,108  8  38.11         1,682,455  37.84        2,646,100  6            38.12  2,581,774            37.94

51.17-61.33

    5,333,926  9  56.95         1,021,896  60.95        5,161,510  7            56.98  2,764,456            58.38
                        

Total

  13,841,748  7  37.59         8,497,874  28.13        18,230,074  7            35.01  10,971,566            33.70

As of December 31, 2008,2009, the aggregate intrinsic value of stock option awards outstanding was $45$82 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable were $45$65 million and 65 years.

As of December 31, 2008,2009, the number of fully-vested stock option awards and stock option awards expected to vest was 13,697,959.18,047,400. The weighted average exercise price and weighted average remaining contractual life of these stock option awards were $37.45$35.02 and 7 years and the aggregate intrinsic value was $45$82 million. As of December 31, 2008,2009, unrecognized compensation cost related to stock option awards was $45$42 million, which is expected to be recognized over a weighted average period of 2 years.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Restricted Stock Awardsstock awards

The following is a summary of restricted stock award activity.

 

  Awards Weighted-
Average
Grant Date
Fair Value
  Awards Weighted-Average
Grant Date
Fair Value

Unvested at December 31, 2007

  1,527,831  $39.87

Unvested at December 31, 2008

  2,049,255  $47.72

Granted

  1,510,378   46.85  251,335   24.74

Vested

  (851,545)  32.77  (762,466  46.03

Forfeited

  (137,409)  43.52  (96,625  43.56
          

Unvested at December 31, 2008

  2,049,255   47.72

Unvested at December 31, 2009

  1,441,499   44.89

The vesting date fair value of restricted stock awards which vested during 2009, 2008 and 2007 and 2006 was $24 million, $38 million and $29 millionmillion. The weighted average grant date fair value of restricted stock awards was $44.89, $47.72, and $32 million.$39.87 for awards unvested at December 31, 2009, 2008 and 2007.

As of December 31, 2008,2009, there was $75$43 million of unrecognized compensation cost related to restricted stock awards which is expected to be recognized over a weighted average period of 2.11.6 years.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Stock-Based Performance AwardsStock-based performance awards

All stock-based performance awards have either vested or been forfeited. The vesting date fair value of stock-based performance awards which vested during 2007 and 2006 was $38 million and $21 million.$38.

25.24.    Stockholders’ Equity

Common stock – On April 25, 2007, our stockholders approved an increaseIn each year, 2009 and 2008, we issued 2 million in the number of authorized shares of Marathon common stock from 550 million to 1.1 billion shares, and the Board of Directors subsequently declared a two-for-one split of Marathon common stock. The stock split was effected in the form of a stock dividend distributed on June 18, 2007, to stockholders of record at the close of business on May 23, 2007. Stockholders received one additional share of Marathon common stock for each share of common stock held as of the close of business on the record date. In addition, shares of Marathon common stock issued or issuable for stock-based awards under our incentive compensation plans were proportionately increased in accordance with the terms of the plans. Common stock and per share (except par value) information for all periods presented has been restated in the consolidated financial statements and notes to reflect the stock split.

During 2008 and 2007, we had the following common stock issuances in addition to shares issued for employee stock-based awards:

In 2008, 2 million common shares were issued upon the redemption of the Exchangeable Shares described below.

On October 18, 2007,below in connection with the acquisition of Western discussed in Note 6, we distributed 29 millionaddition to treasury shares of Marathon common stock valued at $55.70 per share to Western’s shareholders.issued for employee stock-based awards.

The Board of Directors has authorized the repurchase of up to $5 billion of Marathon common stock. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions. We will use cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The repurchase program does not include specific price targets or timetables. As of December 31, 2008,2009, we have acquired 66 million common shares at a cost of $2,922 million under the program, including 8 million common shares acquired during 2008 at a cost of $402 million.program. No shares have been acquired since August 2008.

Securities exchangeable into Marathon common stock – As discussed in Note 6, we acquired all of the outstanding shares of Western on October 18, 2007. The Western shareholders who were Canadian residents received, at their election, cash, Marathon common stock, securities exchangeable into Marathon common stock (the “Exchangeable Shares”) or a combination thereof. The Western shareholders elected to receive 5 million Exchangeable Shares as part of the acquisition consideration. The Exchangeable Shares are shares of an indirect Canadian subsidiary of Marathon and, at the acquisition date, were exchangeable on a one-for-one basis into Marathon common stock. Subsequent to the acquisition, the exchange ratio is adjusted to reflect cash dividends, if any, paid on Marathon common stock and cash dividends, if any, paid on the Exchangeable Shares. The exchange ratio at December 31, 2008,2009, was 1.028111.06109 common shares for each Exchangeable Share. The Exchangeable Shares are exchangeable at the option of the holder at any time and are automatically redeemable on October 18, 2011.

Holders of Exchangeable Shares are entitled to instruct a trustee to vote (or obtain a proxy from the trustee to vote directly) on all matters submitted to the holders of Marathon common stock. The number of votes to which each holder is entitled is equal to the whole number of shares of Marathon common stock into which such holder’s Exchangeable Shares would be exchangeable based on the exchange ratio in effect on the record date for the vote. The voting right is attached to voting preferred shares of Marathon that were issued to a trustee in an amount

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

equivalent to the Exchangeable Shares at the acquisition date as discussed below. Additional shares of voting preferred stock will be issued as necessary to adjust the number of votes to account for changes in the exchange ratio.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Preferred shares – In connection with the acquisition of Western discussed in Note 6, the Board of Directors authorized a class of voting preferred stock consisting of 6 million shares. Upon completion of the acquisition, we issued 5 million shares of this voting preferred stock to a trustee, who holds the shares for the benefit of the holders of the Exchangeable Shares discussed above. Each share of voting preferred stock is entitled to one vote on all matters submitted to the holders of Marathon common stock. Each holder of Exchangeable Shares may direct the trustee to vote the number of shares of voting preferred stock equal to the number of shares of Marathon common stock issuable upon the exchange of the Exchangeable Shares held by that holder. In no event will the aggregate number of votes entitled to be cast by the trustee with respect to the outstanding shares of voting preferred stock exceed the number of votes entitled to be cast with respect to the outstanding Exchangeable Shares. Except as otherwise provided in our restated certificate of incorporation or by applicable law, the common stock and the voting preferred stock will vote together as a single class in the election of directors of Marathon and on all other matters submitted to a vote of stockholders of Marathon generally. The voting preferred stock will have no other voting rights except as required by law. Other than dividends payable solely in shares of voting preferred stock, no dividend or other distribution, will be paid or payable to the holder of the voting preferred stock. In the event of any liquidation, dissolution or winding up of Marathon, the holder of shares of the voting preferred stock will not be entitled to receive any assets of Marathon available for distribution to its stockholders. The voting preferred stock is not convertible into any other class or series of the capital stock of Marathon or into cash, property or other rights, and may not be redeemed.

26.25.    Leases

We lease a wide variety of facilities and equipment under operating leases, including land and building space, office equipment, production facilities and transportation equipment. Most long-term leases include renewal options and, in certain leases, purchase options. Future minimum commitments for capital lease obligations (including sale-leasebacks accounted for as financings) and for operating lease obligations having initial or remaining noncancelable lease terms in excess of one year are as follows:

 

(In millions)  Capital
Lease
Obligations
(a)
 Operating
Lease
Obligations
   Capital Lease
Obligations
(a)
 Operating
Lease
Obligations
 

2009

  $40  $181 

2010

   45   133   $46    $165 

2011

   47   110    45     140 

2012

   60   100    58     121 

2013

   39   85    44     102 

2014

   44     84 

Later years

   426   379    466     313 

Sublease rentals

      (21)   -    (16
              

Total minimum lease payments

  $657  $967   $        703    $        909 

Less imputed interest costs

   (198)    (257)   
          

Present value of net minimum lease payments

  $459    $446    

(a)

Capital lease obligations includes $335include $164 million related to assets under construction as of December 31, 2008.2009. These leases are currently reported in long-term debt based on percentage of construction completed at $126$36 million.

In connection with past sales of various plants and operations, we assigned and the purchasers assumed certain leases of major equipment used in the divested plants and operations of United States Steel. In the event of a default by any of the purchasers, United States Steel has assumed these obligations; however, we remain primarily obligated for payments under these leases. Minimum lease payments under these operating lease obligations of $21$16 million have been included above and an equal amount has been reported as sublease rentals.

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Of the $459$446 million present value of net minimum capital lease payments, $69$53 million was related to obligations assumed by United States Steel under the Financial Matters Agreement.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Operating lease rental expense was:

 

(In millions)  2008  2007  2006   2009  2008  2007

Minimum rental(a)

  $245  $209  $172   $        238  $        245    $        209

Contingent rental

   22   33   28    19   22     33

Sublease rentals

         (7)
                      

Net rental expense

  $267  $242  $193   $257  $267   �� $242

(a)

Excludes $3 million, $5 million $8 million and $9$8 million paid by United States Steel in 2009, 2008 2007 and 20062007 on assumed leases.

27.26. Commitments and Contingencies and Commitments

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

Environmental matters – We are subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance. At December 31, 20082009 and 2007,2008, accrued liabilities for remediation totaled $111$116 million and $108$111 million. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties that may be imposed. Receivables for recoverable costs from certain states, under programs to assist companies in clean-up efforts related to underground storage tanks at retail marketing outlets, were $60$59 and $66$60 million at December 31, 20082009 and 2007.2008.

Legal casesWe, along with other refining companies, settled a number of lawsuits pertaining to methyl tertiary-butyl ether (“MTBE”) in 2008. Presently, we are a defendant, along with other refining companies, in 2027 cases arising in threefour states alleging damages for methyl tertiary-butyl ether (“MTBE”)MTBE contamination. We have also received seven Toxic Substances Control Act notice letters involving potential claims in two states. Such notice letters are often followed by litigation. Like the cases that werewe settled in 2008, 12 of the remaining MTBE cases are consolidated in a multidistrictmulti-district litigation (“MDL”) in the Southern District of New York for pretrial proceedings. NineteenThe other 15 cases are in New York state courts (Nassau and Suffolk Counties). Plaintiffs in 26 of the remaining27 cases allege damages to water supply wells from contamination of groundwater by MTBE, similar to the damages claimed in the cases settled cases.in 2008. In the other remaining case, the State of New Jersey Department of Environmental Protection is seeking the cost of remediating MTBE contamination and natural resources damages allegedly resulting from contamination of groundwater by MTBE. This is the only MTBE contamination case in which we are a defendant and natural resources damages are sought. We are vigorously defending these cases. We along with a number of other defendants, have engaged in settlement discussions related to the majority of the cases in which we are a defendant.these cases. We do not expect our share of liability if any, for the remainingthese cases to significantly impact our consolidated results of operations, financial position or cash flows. We voluntarily discontinued producing MTBE in 2002.

A lawsuit filed in the United States District Court for the Southern District of West VirginiaWe are currently a party to one qui tam case, which alleges that our Catlettsburg, Kentucky, refinery distributed contaminated gasoline to wholesalersMarathon and retailers for a period prior to August, 2003, causing permanent damage to storage tanks, dispensers and related equipment, resulting in lost profits, business disruption and personal and real property damages. Followingother defendants violated the incident, we conducted remediation operations at affected facilities, and we deny that any permanent damages resulted from the incident. Class action certification was granted in August 2007. We have entered into a tentative settlement agreement in this case. Notice of the proposed settlement has been sentFalse Claims Act with respect to the class members. Approval byreporting and payment of royalties on natural gas and natural gas liquids for federal and Indian leases. A qui tam action is an action in which the courtrelator files suit on behalf of himself as well as the federal government. The case currently pending is U.S. ex rel Harrold E. Wright v. Agip Petroleum Co. et al. It is primarily a gas valuation case. Marathon has reached a settlement with the Relator and the DOJ which will be finalized after a fairness hearing is required beforethe Indian Tribes review and approve the settlement can be finalized. The fairness hearingterms. Such settlement is scheduled in the first quarter of 2009. The proposed settlement will not expected to significantly impact our consolidated results of operations, financial position or cash flows.

Guarantees – We have provided certain guarantees, direct and indirect, of the indebtedness of other companies. Under the terms of most of these guarantee arrangements, we would be required to perform should the guaranteed party fail to fulfill its obligations under the specified arrangements. In addition to these financial guarantees, we also have various performance guarantees related to specific agreements.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

 

Guarantees Relatedrelated to Indebtednessindebtedness of Equity Method Investeesequity method investees – We hold interests in an offshore oil port, LOOP LLC, and a crude oil pipeline system, LOCAP LLC. Both LOOP LLC and LOCAP LLC have secured various project financings with throughput and deficiency agreements. Under the agreements, we are required to advance funds if the investees are unable to service their debt. Any such advances are considered prepayments of future transportation charges. The terms of the agreements vary but tend to follow the terms of the underlying debt. Our maximum potential undiscounted payments under these agreements totaled $172 million as of December 31, 2008.2009.

We hold an interest in a refined products pipeline through our investment in Centennial, and have guaranteed the repayment of Centennial’s outstanding balance under a Master Shelf Agreement which expires in 2024. The guarantee arose in order for Centennial to obtain adequate financing. Our maximum potential undiscounted payments under this agreement totaled $65$60 million as of December 31, 2008.2009.

Other Guaranteesguarantees – We have entered into other guarantees with maximum potential undiscounted payments totaling $266$190 million as of December 31, 2008,2009, which consist primarily of leases of corporate assets containing general lease indemnities and guaranteed residual values, commitmentsa commitment to contribute cash to an equity method investeesinvestee for certain catastrophic events in lieu of procuring insurance coverage, a legal indemnification, a performance guarantee and a long-term transportation services agreement.

United States Steel was the sole general partner of Clairton 1314B Partnership, L.P., which owned certain cokemaking facilities formerly owned by United States Steel. We have agreed, under certain circumstances, to indemnify the limited partners if the partnership’s product sales fail to qualify for the credit under Section 29 of the Internal Revenue Code. The Clairton 1314B Partnership was terminated on October 31, 2008, but we were not released from our obligations. United States Steel has estimated the maximum potential amount of this indemnity obligation, including interest and tax gross-up, was approximately $650$100 million as of December 31, 2008.2009.

General Guarantees Associatedguarantees associated with Asset Disposalsdispositions Over the years, we have sold various assets in the normal course of our business. Certain of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require us to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling assets. We are typically not able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the underlying triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based.

Existing guarantees of our subsidiaries’ performance issued to Irish government entities will remain in place after the 2009 sales until the purchasers issue similar guarantees to replace them. The guarantees, related to asset retirement obligations and natural gas production levels, have been indemnified by the purchasers. Our maximum potential undiscounted payments under these guarantees as of December 31, 2009 are $157 million.

Contract commitments – At December 31, 20082009 and 2007,2008, our contract commitments to acquire property, plant and equipment totaled $4,070$ 2,938 million and $3,893$4,070 million.

Other contingencies – In November 2006, the government of Equatorial Guinea enacted a new hydrocarbon law governing petroleum operations in Equatorial Guinea. The transitional provision of the law provides that all contractors and the terms of any contract to which they are a party will be subject to the law. The governmental agency responsible for the energy industry was given the authority to renegotiate any contract for the purpose of adapting any terms and conditions that are inconsistent with the new law. We are in the process of determining what impact this law may have on our existing operations in Equatorial Guinea.

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

 

28. Accounting Standards Not Yet Adopted

In December 2008, the SEC announced that it had approved revisions to its oil and gas reporting disclosures. The new disclosure requirements include provisions that:

Introduce a new definition of oil and gas producing activities. This new definition allows companies to include in their reserve base volumes from unconventional resources. Such unconventional resources include bitumen extracted from oil sands and oil and gas extracted from coal beds and shale formations.

Report oil and gas reserves using an unweighted average price using the prior 12-month period, based on the closing prices on the first day of each month, rather than year-end prices. The SEC indicated that they will continue to communicate with the FASB staff to align their accounting standards with these rules. The FASB currently requires a single-day, year-end price for accounting purposes.

Permit companies to disclose their probable and possible reserves on a voluntary basis. In the past, proved reserves were the only reserves allowed in the disclosures.

Require companies to provide additional disclosure regarding the aging of proved undeveloped reserves.

Permit the use of reliable technologies to determine proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes.

Replace the existing “certainty” test for areas beyond one offsetting drilling unit from a productive well with a “reasonable certainty” test.

Require additional disclosures regarding the qualifications of the chief technical person who oversees the company’s overall reserve estimation process. Additionally, disclosures regarding internal controls surrounding reserve estimation, as well as a report addressing the independence and qualifications of its reserves preparer or auditor will be mandatory.

Require separate disclosure of reserves in foreign countries if they represent more than 15 percent of total proved reserves, based on barrels of oil equivalents.

If finalized, we will begin complying with the disclosure requirements in our annual report on Form 10-K for the year ending December 31, 2009. The new rules may not be applied to disclosures in quarterly reports prior to the first annual report in which the revised disclosures are required. We are currently in the process of evaluating the new requirements.

Also in December 2008, the FASB issued FSP FAS 132(R)-1, “Employers Disclosures about Postretirement Benefit Plan Assets” which provides guidance on an employer’s disclosures about plan assets of a defined benefit pension or other postretirement plans. This would require additional disclosures about investment policies and strategies, the reporting of fair value by asset category and other information about fair value measurements. The FSP is effective January 1, 2009 and early application is permitted. Upon initial application, the provisions of FSP FAS 132(R)-1 are not required for earlier periods that are presented for comparative purposes. We will expand our disclosures in accordance with FSP FAS 132(R)-1 in our annual report on Form 10-K for the year ending December 31, 2009; however, the adoption of this standard is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.

In November 2008, the FASB ratified EITF 08-6, “Equity Method Investment Accounting Considerations” (“EITF 08-6”) which clarifies how to account for certain transactions involving equity method investments. The initial measurement, decreases in value and changes in the level of ownership of the equity method investment are addressed. EITF 08-6 is effective on a prospective basis for our fiscal year beginning January 1, 2009 and interim periods within the years. Early application by an entity that has previously adopted an alternative accounting policy is not permitted. Since this standard will be applied prospectively, adoption is not expected to have a significant impact on our consolidated results of operations financial position or cash flows.

In June 2008, the FASB issued FSP on EITF 03-6-1, “Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating Securities” (“FSP EITF 03-6-1”) which provides that unvested share-based payment awards that contain nonforfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and, therefore, need to be included in the earnings allocation in computing earnings per share (“EPS”) under the two-class method. FSP EITF 03-6-1 is effective January 1, 2009 and all prior-period EPS data (including any amounts related to interim periods, summaries of earnings and selected financial data) will be adjusted retrospectively to conform to its provisions. Early application of FSP EITF 03-6-1 is not

Index to Financial Statements

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

permitted. Although restricted stock awards meet this definition of participating securities, we do not expect application of FSP EITF 03-6-1 to have a significant impact on our reported EPS.

In April 2008, the FASB issued FSP on FAS 142-3 (“FSP FAS 142-3”) which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of a recognized intangible asset under SFAS No. 142, “Goodwill and Other Intangible Assets.” The intent of this FSP is to improve the consistency between the useful life of a recognized intangible asset and the period of expected cash flows used to measure the fair value of the asset. FSP FAS 142-3 is effective on January 1, 2009, early adoption is prohibited. The provisions of FSP FAS 142-3 are to be applied prospectively to intangible assets acquired after the effective date, except for the disclosure requirements which must be applied prospectively to all intangible assets recognized as of, and subsequent to, the effective date. Since this standard will be applied prospectively, adoption is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.

In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities – an amendment of FASB Statement No. 133.” This statement expands the disclosure requirements for derivative instruments to provide information regarding (i) how and why an entity uses derivative instruments, (ii) how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations and (iii) how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. To meet these objectives, the statement requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts and gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. This standard is effective January 1, 2009. The statement encourages but does not require disclosures for earlier periods presented for comparative purposes at initial adoption. We will expand our disclosures in accordance with SFAS No. 161 beginning in the first quarter of 2009; however, the adoption of this standard is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.

In December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (“SFAS No. 141 (R)”). This statement significantly changes the accounting for business combinations. Under SFAS No. 141(R), an acquiring entity will be required to recognize all the assets acquired, liabilities assumed and any non-controlling interest in the acquiree at their acquisition-date fair value with limited exceptions. The statement expands the definition of a business and is expected to be applicable to more transactions than the previous business combinations standard. The statement also changes the accounting treatment for changes in control, step acquisitions, transaction costs, acquired contingent liabilities, in-process research and development, restructuring costs, changes in deferred tax asset valuation allowances as a result of a business combination and changes in income tax uncertainties after the acquisition date. Accounting for changes in valuation allowances for acquired deferred tax assets and the resolution of uncertain tax positions for prior business combinations will impact tax expense instead of impacting recorded goodwill. Additional disclosures are also required. SFAS No. 141(R) is effective on January 1, 2009 for all new business combinations. The adoption of this standard is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.

Also in December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements—An Amendment of ARB No. 51.” This statement establishes new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. Specifically, this statement clarifies that a noncontrolling interest in a subsidiary (sometimes called a minority interest) is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements, but separate from the parent’s equity. It requires that the amount of consolidated net income attributable to the noncontrolling interest be clearly identified and presented on the face of the consolidated income statement. SFAS No. 160 clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, this statement requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated, based on the fair value of the noncontrolling equity investment on the deconsolidation date. Additional disclosures are required that clearly identify and distinguish between the interests of the parent and the interests of the noncontrolling owners. SFAS No. 160 is effective January 1, 2009 and early adoption is prohibited. The statement must be applied prospectively, except for the presentation and disclosure requirements which must be applied retrospectively for all periods presented in consolidated financial statements. We do not have significant noncontrolling interests in consolidated subsidiaries, and therefore, adoption of this standard is not expected to have a significant impact on our consolidated results of operations, financial position or cash flows.

Index to Financial Statements

Selected Quarterly Financial Data (Unaudited)

 

  2008  2007 2009 2008  
(In millions, except per share data)  

1st

Qtr.

  2nd
Qtr.
  3rd
Qtr.
  

4th

Qtr.

 

1st

Qtr.

  2nd
Qtr.
  3rd
Qtr.
  4th
Qtr.
(In millions, except per share
data)(a)
 1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr. 1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr.(b) 

Revenues

  $17,822  $21,912  $23,114  $14,345   $12,869  $16,736  $16,762  $18,185 $  10,176 $  13,039 $  14,362 $  15,893 $  17,648 $  21,889 $  22,969 $  14,248  

Income from operations

   1,290   1,594   3,754   385   1,316   2,756   1,619   949  538  1,042  1,017  993  1,198  1,593  3,639  349 

Income (loss) from continuing operations

   731   774   2,064   (41)(a)  717   1,542   1,021   668  265  328  392  199  680  761  1,992  (49)  

Discontinued operations

                  8        17  85  21  156  51  13  72  8  

Net income (loss)

   731   774   2,064   (41)(a)  717   1,550   1,021   668  282  413  413  355  731  774  2,064  (41)  

Common stock data

               

Net income (loss) per share:

                       

– Basic

  $1.03  $1.09  $2.92  $(0.06) $1.04  $2.27  $1.50  $0.95

– Diluted

  $1.02  $1.08  $2.90  $(0.06)(b) $1.03  $2.25  $1.49  $0.94

- Basic

 $0.40 $0.58 $0.58 $0.50 $1.03 $1.09 $2.92 $(0.06)  

- Diluted

 $0.40 $0.58 $0.58 $0.50 $1.02 $1.08 $2.90 $(0.06)  

Dividends paid per share

  $0.24  $0.24  $0.24  $0.24   $0.20  $0.24  $0.24  $0.24 $0.24 $0.24 $0.24 $0.24 $0.24 $0.24 $0.24 $0.24  

(a)

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

(b)

Reflects a $1,412 million impairment of goodwill related to the OSM segment. See Note 1615 to the consolidated financial statements.

(b)

Because a loss was reported for the quarter, all outstanding awards were antidilutive. See Note 9 to the consolidated financial statements for the calculation of annual earnings per share.

Index to Financial Statements

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

The supplementary information is disclosed by the following geographic areas: the United States; Europe, which primarily includes activities in the United Kingdom Ireland and Norway; Equatorial Guinea (“EG”); Other Africa, which primarily includes activities in Angola Equatorial Guinea, Gabon and Libya; Canada; and Other International (“Other Int’l”), which primarily includes activities in Canada and Indonesia, and other international locations outside of Europe and Africa.Indonesia. Discontinued operations (“Disc Ops”) represent Marathon’s RussianIrish and Gabonese oil exploration and production businesses that were sold in 2006.2009.

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization

   December 31,
(In millions)  United
States
  Europe  Africa  Other
Int’l
  Total
2008 

Capitalized costs:

          
 

Proved properties

  $10,008  $8,460  $2,257  $1  $20,726
 

Unproved properties

   1,170   53   549   326   2,098
 

Suspended exploratory wells

   373   56   480   8   917
                     
 

Total

   11,551   8,569   3,286   335   23,741
                     
 

Accumulated depreciation, depletion and amortization:

          
 

Proved properties

   5,927   4,995   627   1   11,550
 

Unproved properties

   69   1   9   8   87
                     
 

Total

   5,996   4,996   636   9   11,637
                     
  

Net capitalized costs

  $5,555  $3,573  $2,650  $326  $12,104
2007 

Capitalized costs:

          
 

Proved properties

  $8,325  $8,191  $2,108  $60  $18,684
 

Unproved properties

   1,133   64   474   261   1,932
 

Suspended exploratory wells

   312   76   395      783
                     
 

Total

   9,770   8,331   2,977   321   21,399
                     
 

Accumulated depreciation, depletion amortization:

          
 

Proved properties

   5,478   5,070   482   1   11,031
 

Unproved properties

   67   6   9      82
                     
 

Total

   5,545   5,076   491   1   11,113
                     
  

Net capitalized costs

  $4,225  $3,255  $2,486  $320  $10,286

Costs Incurred for Property Acquisition, Exploration and Development(a)

(In millions)  United
States
  Europe  Africa  Other
Int’l
  Continuing
Operations
  Disc
Ops
  Total
2008  

Property acquisition:

           
  

Proved

  $5  $  $  $  $5  $  $5
  

Unproved

   395      8   65   468      468
  

Exploration

   738   57   156   58   1,009      1,009
  

Development

   1,019   683   196      1,898      1,898
  

Capitalized asset retirement costs

   53   (6)  (21)     26      26
                              
   

Total

  $2,210  $734  $339  $123  $3,406  $  $3,406
2007  

Property acquisition:

           
  

Proved

  $4  $  $  $  $4  $  $4
  

Unproved

   142   1   1   315   459      459
  

Exploration

   523   68   219   44   854      854
  

Development

   759   806   85      1,650      1,650
  

Capitalized asset retirement costs

   (62)  61   9      8      8
                              
   

Total

  $1,366  $936  $314  $359  $2,975  $  $2,975
2006  

Property acquisition:

           
  

Proved

  $4  $  $19  $  $23  $  $23
  

Unproved

   526   3   3   4   536      536
  

Exploration

   224   36   169   70   499   2   501
  

Development

   603   607   40      1,250   43   1,293
  

Capitalized asset retirement costs

   78   201   13   2   294   1   295
                              
   

Total

  $1,435  $847  $244  $76  $2,602  $46  $2,648

(a)

Includes costs incurred whether capitalized or expensed.

Index to Financial Statements

Supplementary Information on Oil and Gas Producing Activities (Unaudited) C O N T I N U E D

Results of Operations for Oil and Gas Producing Activities

(In millions)  United
States
  Europe  Africa  Other
Int’l
  Total 
2008 

Revenues and other income:

      
 

Sales(a)

  $2,619  $1,283  $1,930  $  $5,832 
 

Transfers

   547   1,062   1,170      2,779 
 

Other income(b)

   1   254         255 
                      
 

Total revenues

   3,167   2,599   3,100      8,866 
 

Expenses:

      
 

Production costs

   (692)  (319)  (145)     (1,156)
 

Transportation costs

   (153)  (59)  (36)     (248)
 

Exploration expenses

   (238)  (88)  (47)  (117)  (490)
 

Depreciation, depletion and amortization

   (671)  (512)  (144)  (1)  (1,328)
 

Administrative expenses

   (49)  (15)  (5)  (37)  (106)
                      
 

Total expenses

   (1,803)  (993)  (377)  (155)  (3,328)
 

Other production-related income (loss)(c)

   (1)  35   1      35 
                      
 

Results before income taxes

   1,363   1,641   2,724   (155)  5,573 
 

Income tax (provision) benefit

   (516)  (598)  (1,892)  58   (2,948)
                      
  Results of continuing operations  $847  $1,043  $832  $(97) $2,625 
2007 

Revenues and other income:

      
 

Sales(a)

  $2,110  $1,198  $1,380  $  $4,688 
 

Transfers

   299   60   1,031      1,390 
 

Other income(b)

   3      2   7   12 
                      
 

Total revenues

   2,412   1,258   2,413   7   6,090 
 

Expenses:

      
 

Production costs

   (550)  (234)  (164)     (948)
 

Transportation costs

   (122)  (39)  (28)     (189)
 

Exploration expenses

   (274)  (23)  (118)  (37)  (452)
 

Depreciation, depletion and amortization

   (486)  (278)  (130)     (894)
 

Administrative expenses

   (56)  (11)  (6)  (34)  (107)
                      
 

Total expenses

   (1,488)  (585)  (446)  (71)  (2,590)
 

Other production-related income(c)

      103   6      109 
                      
 

Results before income taxes

   924   776   1,973   (64)  3,609 
 

Income tax (provision) benefit

   (343)  (377)  (1,368)  24   (2,064)
                      
 

Results of continuing operations

  $581  $399  $605  $(40) $1,545 
  Results of discontinued operations  $  $  $  $8  $8 
2006 

Revenues and other income:

      
 

Sales(a)

  $2,329  $1,240  $1,300  $  $4,869 
 

Transfers

   307   58   1,168      1,533 
 

Other income(b)

   3         46   49 
                      
 

Total revenues

   2,639   1,298   2,468   46   6,451 
 

Expenses:

      
 

Production costs

   (512)  (207)  (126)     (845)
 

Transportation costs

   (124)  (44)  (33)     (201)
 

Exploration expenses

   (169)  (29)  (91)  (73)  (362)
 

Depreciation, depletion and amortization

   (458)  (281)  (127)     (866)
 

Administrative expenses

   (41)  (10)  (6)  (36)  (93)
                      
 

Total expenses

   (1,304)  (571)  (383)  (109)  (2,367)
 

Other production-related income(c)

      73   1      74 
                      
 

Results before income taxes

   1,335   800   2,086   (63)  4,158 
 

Income tax (provision) benefit

   (489)  (358)  (1,457)  4   (2,300)
                      
 

Results of continuing operations

  $846  $442  $629  $(59) $1,858 
  Results of discontinued operations  $  $  $  $273  $273 

(a)

Excludes noncash effects of changes in the fair value of certain natural gas sales contracts in the United Kingdom.

(b)

Includes net gain on disposal of assets.

(c)

Includes revenues, net of associated costs, from activities that are an integral part of our production operations which may include processing or transportation of third-party production, the purchase and subsequent resale of natural gas utilized for reservoir management and providing storage capacity.

Index to Financial Statements

Supplementary Information on Oil and Gas Producing Activities (Unaudited) C O N T I N U E D

Results of Operations for Oil and Gas Producing Activities

The following reconciles results of continuing operations for oil and gas producing activities to E&P segment income:

(In millions)  2008  2007  2006 

Results of continuing operations

  $2,625  $1,545  $1,858 

Items not included in results of continuing oil and gas operations, net of tax:

    

Marketing income and technology costs

   58   36   40 

Income from equity method investments

   201   154   135 

Other

   (6)  (6)  1 

Items not allocated to E&P segment income:

    

Gain on asset disposition

   (163)     (31)
             

E&P segment income

  $2,715  $1,729  $2,003 

Average Production Costs(a)

(Per barrel of oil equivalent)  United
States
  Europe  Africa  Continuing
Operations

2008

  $13.71  $10.56  $2.56  $8.42

2007

   10.46   10.41   3.26   7.56

2006

   8.51   8.36   2.78   6.48

(a)

Computed using production costs, which excludes transportation costs, as disclosed in the Results of Operations for Oil and Gas Producing Activities and as defined by the Securities and Exchange Commission. Natural gas volumes were converted to barrels of oil equivalent using a conversion factor of six mcf of natural gas to one barrel of oil.

Average Realizations

    United
States
  Europe  Africa  Continuing
Operations
  Disc
Ops
(Excluding derivative gains and losses)          

2008

  Liquid hydrocarbons (per bbl)  $86.68  $90.60  $90.29  $89.29  $
  Natural gas (per mcf)(a)(b)   7.01   8.20   0.25   4.67   

2007

  Liquid hydrocarbons (per bbl)  $60.15  $70.31  $66.09  $64.86  $
  Natural gas (per mcf)(a)(b)   5.73   6.55   0.25   4.44   

2006

  Liquid hydrocarbons (per bbl)  $54.41  $64.02  $59.83  $58.63  $38.38
   Natural gas (per mcf)(a)(b)   5.76   6.78   0.27   5.52   

(a)

The Europe realizations exclude the resale of purchased natural gas utilized for reservoir management.

(b)

The Africa realizations primarily represent fixed prices under long-term contracts with Alba Plants LLC, AMPCO and EGHoldings, equity method investees. We include our share of Alba Plant LLC’s income in our E&P segment, and we include our share of AMPCO’s and EGHoldings income in our Integrated Gas segment.

Index to Financial Statements

Supplementary Information on Oil and Gas Producing Activities (Unaudited) C O N T I N U E D

Estimated Quantities of Proved Oil and Gas Reserves

Estimates of proved reserves have been prepared by in-house teams of reservoir engineers and geoscience professionals. Reserve estimates are periodically reviewed by our Corporate Reserves Group to assure that rigorous professional standards andIn December 2008, the reserves definitions prescribed by the U.S. Securities and Exchange Commission (“SEC”) are consistently applied throughout the Company.

Proved reserves are the estimated quantities of oil and natural gas that geologic and engineering data demonstrate with reasonable certaintyannounced revisions to be recoverable in future years from known reservoirs under existing economic and operating conditions. Estimates of proved reserves may change, either positively or negatively, as additional information becomes available and as contractual, economic and political conditions change.

Our net proved reserve estimates have been adjusted as necessary to reflect all contractual agreements, royalty obligations and interests owned by others at the time of the estimate. Only reserves that are estimated to be recovered during the term of the current contract have been included in the proved reserve estimate unless there is a clear and consistent history of contract extension. Reserves from properties governed by production sharing contracts have been calculated using the “economic interest” method prescribed by the SEC. Reserves that are not currently considered proved, such as those that may result from extensions of currently proved areas or that may result from applying secondary or tertiary recovery processes not yet tested and determined to be economic are excluded. Purchased natural gas utilized in reservoir management and subsequently resold is also excluded. We do not have any quantities ofits regulations on oil and gas reporting. In January 2010, the Financial Accounting Standards Board issued an accounting standards update which was intended to harmonize the accounting literature with the SEC’s new regulations. See Item 8. Financial Statements and Supplementary Data – Note 2 for a summary of the changes. The revised regulations were applied in estimating and reporting our reserves as of December 31, 2009.

The estimation of net recoverable quantities of liquid hydrocarbons, natural gas and synthetic crude oil is a highly technical process, which is based upon several underlying assumptions that are subject to long-term supply agreements with foreign governments or authorities in which we act as producer.

Proved developed reserves arechange. For a discussion of our reserve estimation process, including the quantitiesuse of oil and gas expected to be recovered through existing wells with existing equipment and operating methods. In some cases, proved undeveloped reserves may require substantial new investments in additional wells and related facilities.third-party audits, see Item 1 – Business.

 

(Millions of barrels)  United
States
 Europe Africa(a) Continuing
Operations
 Disc Ops   United
States
 Canada(a) EG(b) Other
Africa
 Europe Continuing
Operations
 Disc
Ops
 

Liquid Hydrocarbons

              

Proved developed and undeveloped reserves:

              

Beginning of year – 2006

  189  98  373  660  44 

Beginning of year - 2007

          172              -       177       210      108          667          10 

Revisions of previous estimates

  2  -   (10)   -   7  (1 2 

Improved recovery

  8  -   -   -   -   8  -  

Purchase of reserves in place

      1  1     2  -   -   -   -   2  -  

Extensions, discoveries and other additions

  5  -   -   16  13  34  -  

Production(b)

  (23 -   (17 (16 (13 (69 (3
                      

End of year - 2007

  166  -   150   210  115  641  9 

Revisions of previous estimates

  2  8  49  59  1   3  -   4   7  (1 13  (3

Improved recovery

  3      3     1  -   -   -   -   1  -  

Extensions, discoveries and other additions

  6  15  15  36  4   31  -   -   11  11  53  -  

Production(b)

  (28) (13) (41) (82) (4)  (23 -   (15)   (17 (20 (75 (2

Sales of reserves in place

          (45)  -   -   -   -   (1 (1 -  
                                      

End of year – 2006

  172  108  397  677   

Purchase of reserves in place

  2      2   

End of year - 2008

  178  -   139   211  104  632  4 

Revisions of previous estimates

  2  7  (8) 1     -   -   (2)   3  19  20  2 

Improved recovery

  8      8   

Extensions, discoveries and other additions

  5  13  16  34   

Production(b)

  (23) (13) (36) (72)  
                

End of year – 2007

  166  115  369  650   

Revisions of previous estimates

  3  (1) 8  10   

Improved recovery

  1      1   

Extensions, discoveries and other additions

  31  11  11  53     21  -   -   31  12  64  -  

Production(b)

  (23) (20) (34) (77)    (23 -   (15)   (17 (33 (88 (2

Sales of reserves in place

    (1)   (1)    (6 -   -   -   -   (6 (4
                                      

End of year – 2008

  178  104  354  636   

End of year - 2009

  170  -   122   228  102  622  -  
 

Proved developed reserves:

              

Beginning of year – 2006

  165  39  368  572  31 

End of year – 2006

  150  35  381  566   

End of year – 2007

  135  32  304  471   

End of year – 2008

  137  81  296  514   

Beginning of year - 2007

  150  -   176   196  35  557  9 

End of year - 2007

  135  -   113   183  32  463  8 

End of year - 2008

  137  -   99   193  81  510  4 

End of year - 2009

  120  -   83   186  87  476  -  
 

Proved undeveloped reserves:

        

Beginning of year - 2007

  22  -   1   14  73  110  1 

End of year - 2007

  31  -   37   27  83  178  1 

End of year - 2008

  41  -   40   18  23  122  -  

End of year - 2009

  50  -   39   42  15  146  -  
 

Index to Financial Statements

Supplementary Information on Oil and Gas Producing Activities (Unaudited) C O N T I N U E D

Estimated Quantities of Proved Oil and Gas Reserves (continued)

 

(Billions of cubic feet)  United
States
  Europe  Africa(a)  Continuing
Operations
  Disc Ops

Natural Gas

      

Proved developed and undeveloped reserves:

      

Beginning of year – 2006

  1,209  486  1,852  3,547  

Purchase of reserves in place

    4  8  12  

Revisions of previous estimates

  (5) 4  139  138  

Extensions, discoveries and other additions

  59  20  24  103  

Production(b)

  (194) (70) (26) (290)         –
               

End of year – 2006

  1,069  444  1,997  3,510  

Purchase of reserves in place

  1      1  

Revisions of previous estimates

  (36) (5) 60  19  

Extensions, discoveries and other additions

  148  4  88  240  

Production(b)

  (174) (61) (84) (319) 

Sales of reserves in place

  (1)     (1) 
               

End of year – 2007

  1,007  382  2,061  3,450  

Revisions of previous estimates

  79  (51) 49  77  

Extensions, discoveries and other additions

  165  30    195  

Production(b)

  (164) (60) (135) (359) 

Sales of reserves in place

  (2) (10)   (12) 
               

End of year – 2008

  1,085  291  1,975  3,351  

Proved developed reserves:

      

Beginning of year – 2006

  943  326  638  1,907  

End of year – 2006

  857  238  648  1,743  

End of year – 2007

  761  173  1,515  2,449  

End of year – 2008

  839  129  1,382  2,350  
    United
States
  Canada(a)  EG(b)  Other
Africa
  Europe  Continuing
Operations
  Disc
Ops
 

Natural Gas(billions of cubic feet)

        

Proved developed and undeveloped reserves:

        

Beginning of year - 2007

  1,069              -       1,974           23      293      3,359      151 

Revisions of previous estimates

  (36 -   60   -   (11 13  6 

Purchase of reserves in place

  1  -   -   -   -   1  -  

Extensions, discoveries and other additions

  148  -   -   88  4  240  -  

Production(c)

  (174 -   (83)   (1 (48 (306 (13

Sales of reserves in place

  (1 -   -   -   -   (1 -  
                      

End of year - 2007

  1,007  -   1,951   110  238  3,306  144 

Revisions of previous estimates

  79  -   49   -   (51 77  -  

Extensions, discoveries and other additions

  165  -   -   -   30  195  -  

Production(c)

  (164 -   (134)   (1 (48 (347 (12

Sales of reserves in place

  (2 -   -   -   (10 (12 -  
                      

End of year - 2008

  1,085  -   1,866   109  159  3,219  132 

Revisions of previous estimates

  (139 -   (23)   -   (10 (172 -  

Extensions, discoveries and other additions

  80  -   -   -   2  82  -  

Production(c)

  (146 -   (155)   (2 (42 (345 (6

Sales of reserves in place

  (60 -   -   -   -   (60 (126
                      

End of year - 2009

  820  -   1,688   107  109  2,724  -  

Proved developed reserves:

        

Beginning of year - 2007

  857  -   625   23  185  1,690  53 

End of year - 2007

  761  -   1,405   110  127  2,403  46 

End of year - 2008

  839  -   1,273   109  95  2,316  34 

End of year - 2009

  652  -   1,102   107  50  1,911  -  

Proved undeveloped reserves:

        

Beginning of year - 2007

  212  -   1,349   -   108  1,669  98 

End of year - 2007

  246  -   546   -   111  903  98 

End of year - 2008

  246  -   593   -   64  903  98 

End of year - 2009

  168  -   586   -   59  813  -  

Synthetic crude oil(millions of barrels)

        

Proved developed and undeveloped reserves:

        

Beginning of year - 2009

  -   -   -   -   -   -   -  

Revisions of previous estimates

  -   603   -   -   -   603  -  
                      

End of year - 2009

  -   603   -   -   -   603  -  

Proved developed reserves:

        

Beginning of year - 2009

  -   -   -   -   -   -   -  

End of year - 2009

  -   392   -   -   -   392  -  

Proved undeveloped reserves:

        

Beginning of year - 2009

  -   -   -   -   -   -   -  

End of year - 2009

  -   211   -   -   -   211  -  

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Estimated Quantities of Proved Oil and Gas Reserves (continued)

(millions of barrels of oil equivalent)  United
States
  Canada(a)  EG(b)  Other
Africa
  Europe  Continuing
Operations
  Disc
Ops
 

Total Proved Reserves

        

Proved developed and undeveloped reserves:

        

Beginning of year - 2007

  350  -     506   214  157  1,227  35 

Revisions of previous estimates

  (4 -     -     -     5  1  3 

Improved recovery

  8  -     -     -     -     8  -    

Purchase of reserves in place

  2  -     -     -     -     2  -    

Extensions, discoveries and other additions

  30  -     -     31  13  74  -    

Production(c)

  (52 -     (31 (17 (20 (120 (5
                      

End of year - 2007

  334  -     475   228  155  1,192  33 

Revisions of previous estimates

  15  -     12   7  (9 25  (2

Improved recovery

  1  -     -     -     -     1  -    

Extensions, discoveries and other additions

  59  -     -     11  16  86  -    

Production(c)

  (50 -     (37 (17 (28 (132 (5

Sales of reserves in place

  -     -     -     -     (3 (3 -    
                      

End of year - 2008

  359  -     450   229  131  1,169  26 

Revisions of previous estimates(d)

  (22 603   (6)   3  17  595  1 

Extensions, discoveries and other additions

  34  -     -     31  13  78  -    

Production(c)

  (48 -     (41 (17 (41 (147 (2

Sales of reserves in place

  (16 -     -     -     -     (16 (25
                      

End of year-2009

  307  603   403   246  120  1,679  -    

Proved developed reserves:

        

Beginning of year - 2007

  293  -     280   200  66  839  18 

End of year - 2007

  262  -     347   202  52  863  16 

End of year - 2008

  277  -     312   211  96  896  10 

End of year - 2009

  229  392   267   204  95  1,187  -    

Proved undeveloped reserves:

        

Beginning of year-2007

  57  -     226   14  91  388  17 

End of year - 2007

  72  -     128   26  103  329  17 

End of year - 2008

  82  -     138   18  35  273  16 

End of year - 2009

  78  211   136   42  25  492  -    

(a)

Synthetic crude oil proved reserves were added as of December 31, 2009.

(b)

Consists of estimated reserves from properties governed by production sharing contracts.

(b)(c)

Excludes the resale of purchased natural gas utilized in reservoir management.

(d)

Volumes for Canada are after 10 million barrels of synthetic crude oil production in 2009.

The most significant impact of adopting the SEC’s new regulations on oil and gas producing activities was the addition of 603 mmbbl of synthetic crude oil to our reserves in 2009. Other changes resulting from the new regulations did not have a significant impact.

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Information on Proved Bitumen Reserves Not Included Above

In additionWe previously reported reserves related to the liquid hydrocarbon and natural gas provedour oil sands mining operations in Alberta, Canada, as bitumen, which were reported separately from other reserves above, we have interests in provedsince bitumen reserves in Canada associated with the AOSP. Under SEC regulations, these reserves arewere not considered mining-related and not part ofrelated to oil and gas producing activities by the SEC. Reserve quantities under the new regulations include synthetic crude oil (bitumen after upgrading) reserves and therefore are not included in our tabular presentation of oil and gas reserves. The bitumen reserves are also not included in the standardized measureEstimated Quantities of discounted future net cash flows relatingProved Oil and Gas Reserves for 2009. During 2009, activity related to proved oilour bitumen reserves included purchase of reserves of 168 million barrels (“mmbbl”) of bitumen and gas reserves on the following page.production of 9 mmbbl of bitumen.

 

(Millions of barrels)  Continuing
Operations
 

Proved Bitumen Reserves:

  

Beginning of year - 2007

  -    

Purchase of reserves in place

  420 

Revisions

  2 

Production

  (1)
    

End of year - 2007

  421 

Revisions

  (30)

Extensions, discoveries and other additions

  6 

Production

  (9)
    

End of year - 2008

  388 

Index to Financial Statements

Supplementary Information on Oil and Gas Producing Activities (Unaudited) C O N T I N U E D

Standardized Measure of Discounted Future Net Cash FlowsCapitalized Costs and Changes Therein Relating to Proved OilAccumulated Depreciation, Depletion and Gas Reserves

Future cash inflows are computed by applying year-end prices of oil and natural gas relating to our proved reserves to the year-end quantities of those reserves. Future price changes are considered only to the extent provided by contractual arrangements in existence at year-end.

The assumptions used to compute the proved reserve valuation do not necessarily reflect our expectations of actual revenues to be derived from those reserves or their present worth. Assigning monetary values to the estimated quantities of reserves, described on the preceding page, does not reduce the subjective and ever-changing nature of such reserve estimates.

Additional subjectivity occurs when determining present values because the rate of producing the reserves must be estimated. In addition to uncertainties inherent in predicting the future, variations from the expected production rate also could result directly or indirectly from factors outside of our control, such as unintentional delays in development, environmental concerns, changes in prices or regulatory controls.

The reserve valuation assumes that all reserves will be disposed of by production. However, if reserves are sold in place or subjected to participation by foreign governments, additional economic considerations could also affect the amount of cash eventually realized.

Future production, transportation and administrative costs and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to our proved oil and gas reserves. Oil and gas related tax credits and allowances are recognized.

Discount was derived by using a discount rate of 10 percent annually.Amortization

 

      December 31, 
(In millions)      United
States
  Europe  Africa  Total 

2008

     
 Future cash inflows  $11,295  $6,802  $13,044  $31,141 
 Future production, transportation and administrative costs   (6,045)  (2,386)  (2,294)  (10,725)
 Future development costs   (2,673)  (2,101)  (638)  (5,412)
 Future income tax expenses   (443)  (192)  (7,871)  (8,506)
                    
 Future net cash flows  $2,134  $2,123  $2,241  $6,498 
 10 percent annual discount for estimated timing of cash flows   (703)  (191)  (1,000)  (1,894)
                    
  

Standardized measure of discounted future net cash flows relating to proved oil and gas reserves

  $1,431  $1,932  $1,241  $4,604 

2007

     
 Future cash inflows  $19,432  $14,795  $32,312  $66,539 
 Future production, transportation and administrative costs   (5,769)  (3,358)  (2,199)  (11,326)
 Future development costs   (1,299)  (2,397)  (705)  (4,401)
 Future income tax expenses   (4,047)  (3,961)  (22,378)  (30,386)
                    
 Future net cash flows  $8,317  $5,079  $7,030  $20,426 
 10 percent annual discount for estimated timing of cash flows   (3,297)  (777)  (2,857)  (6,931)
                    
  

Standardized measure of discounted future net cash flows relating to proved oil and gas reserves

  $5,020  $4,302  $4,173  $13,495 

2006

     
 Future cash inflows  $13,435  $8,713  $22,799  $44,947 
 Future production, transportation and administrative costs   (5,512)  (2,564)  (1,877)  (9,953)
 Future development costs   (762)  (1,781)  (495)  (3,038)
 Future income tax expenses   (2,217)  (1,709)  (14,847)  (18,773)
                    
 Future net cash flows  $4,944  $2,659  $5,580  $13,183 
 10 percent annual discount for estimated timing of cash flows   (1,818)  (408)  (2,439)  (4,665)
                    
  

Standardized measure of discounted future net cash flows relating to proved oil and gas reserves

  $3,126  $2,251  $3,141  $8,518 
   December 31,
(In millions)  United
States
  Canada(a)  EG  Other
Africa
  Europe  Other
Int’l
  Total

2009    Capitalized costs:

             

Proved properties

  $    10,927  $    7,510   $    1,521  $    1,505  $  7,790  $3  $  29,256

Unproved properties

   1,258   1,544    24   404   68           19   3,317
                            

Total

   12,185   9,054    1,545   1,909   7,858   22   32,573
                            

Accumulated depreciation,
depletion and amortization:

             

Proved properties

   6,128   280    516   85   5,230   1   12,240

Unproved properties

   60   -    -   9   1   8   78
                            

Total

   6,188   280    516   94   5,231   9   12,318

Net capitalized costs

  $5,997  $8,774   $1,029  $1,815  $2,627  $13  $20,255

2008    Capitalized costs:

             

Proved properties

  $10,008  $-   $1,455  $802  $8,460  $1  $20,726

Unproved properties

   1,543   315    53   976   109   19   3,015
                            

Total

   11,551   315    1,508   1,778   8,569   20   23,741
                            

Accumulated depreciation, depletion and amortization:

             

Proved properties

   5,927   -    401   226   4,995   1   11,550

Unproved properties

   69   -    -   9   1   8   87
                            

Total

   5,996   -    401   235   4,996   9   11,637

Net capitalized costs

  $5,555  $315   $1,107  $1,543  $3,573  $11  $12,104
(a)

2009 includes amounts related to our oil sands mining operations.

Costs Incurred for Property Acquisition, Exploration and Development (a)

Index to Financial Statements

(In millions)  United
States
  Canada(b)  EG  Other
Africa
  Europe  Other
Int’l
  Continuing
Operations
  Disc
Ops
  Total

2009    Property acquisition:

                 

Proved

  $-  $11   $-  $-  $-  $-  $11  $15  $26

Unproved

   127   1    -   6   -   2   136   -   136

Exploration

   271   11    -   127   81   29   519   -   519

Development

   1,150   976    23   266   354   -   2,769   64   2,833
                                    

Total

  $1,548  $999   $23  $399  $435  $31  $3,435  $79  $3,514

2008    Property acquisition:

                 

Proved

  $3  $-   $-  $-  $-  $-  $3  $-  $3

Unproved

   397   -    -   8   -   7   412   -   412

Exploration

   738   31    1   155   56   85   1,066   1   1,067

Development

   1,072   -    30   141   516   -   1,759   165   1,924
                                    

Total

  $2,210  $31   $31  $304  $572  $92  $3,240  $166  $3,406

2007    Property acquisition:

                 

Proved

  $4  $-   $-  $-  $-  $-  $4  $-  $4

Unproved

   142   309    -   1   1   6   459   -   459

Exploration

   523   4    1   218   68   40   854   -   854

Development

   697   -    21   72   754   -   1,544   114   1,658
                                    

Total

  $1,366  $313   $22  $291  $823  $46  $2,861  $114  $2,975
(a)

Includes costs incurred whether capitalized or expensed.

(b)

2009 includes amounts related to our oil sands mining operations.

Supplementary Information on Oil and Gas Producing Activities (Unaudited) C O N T I N U E D

SummaryResults of ChangesOperations for Oil and Gas Producing Activities

(In millions)  United
States
  Canada(a)  EG  Other
Africa
  Europe  Other
Int’l
  Total 

2009    Revenues and other income:

        

Sales(b)

  $    1,426  $      499   $23  $    1,146  $      699  $    -     $    3,793 

Transfers

   437   100    587   -      1,678   -      2,802 

Other income(c)

   185   -      -      -      13   -      198 
                             

Total revenues and other income

   2,048   599    610   1,146   2,390   -      6,793 

Expenses:

        

Production costs

   (763  (371  (108  (62  (289  -      (1,593

Exploration expenses

   (153  (16)    -      (73  (37  (28  (307

Depreciation, depletion and amortization

   (846  (126  (115  (37  (736  -      (1,860

Administrative expenses

   (53  (9)    (1  (3  (13  (22  (101
                             

Total expenses

   (1,815  (522  (224  (175  (1,075  (50  (3,861

Results before income taxes

   233   77    386   971   1,315   (50  2,932 

Income tax (provision) benefit

   (76  (17)    (112  (770  (678  14   (1,639
                             

Results of continuing operations

  $157  $60   $      274  $201  $637  $(36 $1,293 

Results of discontinued operations

  $-     $-     $-     $194  $79  $-     $273 

2008    Revenues and other income:

        

Sales(b)

  $2,619  $-     $28  $1,858  $1,164  $-     $5,669 

Transfers

   547   -      995   -      1,062   -      2,604 

Other income(c)

   1   -      -      -      254   -      255 
                             

Total revenues and other income

   3,167   -      1,023   1,858   2,480   -      8,528 

Expenses:

        

Production costs

   (845  -      (96  (41  (340  -      (1,322

Exploration expenses

   (238  (25)    (2  (45  (87  (92  (489

Depreciation, depletion and amortization

   (671  -      (102  (35  (475  (1  (1,284

Administrative expenses

   (49  (1)    (1  (15  (16  (36  (118
                             

Total expenses

   (1,803  (26)    (201  (136  (918  (129  (3,213

Results before income taxes

   1,364   (26)    822   1,722   1,562   (129  5,315 

Income tax (provision) benefit

   (513  6    (280  (1,550  (551  44   (2,844
                             

Results of continuing operations

  $851  $(20 $542  $172  $1,011  $(85 $2,471 

Results of discontinued operations

  $-     $-     $-     $117  $28  $-     $145 

2007    Revenues and other income:

        

Sales(b)

  $2,110  $-     $10  $1,319  $1,111  $-     $4,550 

Transfers

   299   -      821   -      60   -      1,180 

Other income(c)

   3   -      2   -      -      7   12 
                             

Total revenues and other income

   2,412   -      833   1,319   1,171   7   5,742 

Expenses:

        

Production costs

   (672  -      (95  (60  (228  -      (1,055

Exploration expenses

   (274  (3)    (1  (117  (23  (34  (452

Depreciation, depletion and amortization

   (486  -      (87  (31  (243  -      (847

Administrative expenses

   (56  -      (3  (2  (10  (34  (105
                             

Total expenses

   (1,488  (3)    (186  (210  (504  (68  (2,459

Results before income taxes

   924   (3)    647   1,109   667   (61  3,283 

Income tax (provision) benefit

   (343  -      (228  (1,061  (330  22   (1,940
                             

Results of continuing operations

  $581  $(3)   $419  $48  $337  $(39 $1,343 

Results of discontinued operations

  $-     $-     $-     $114  $4  $8  $126 
(a)

2009 includes amounts related to our oil sands mining operations.

(b)

Excludes noncash effects of changes in the fair value of certain natural gas sales contracts in the United Kingdom.

(c)

Includes net gain on disposal of assets.

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Results of Operations for Oil and Gas Producing Activities

The following reconciles results of continuing operations for oil and gas producing activities to segment income:

(In millions)  2009  2008  2007 

Results of continuing operations

  $    1,293  $    2,471  $    1,343 

Items not included in results of continuing oil and gas operations, net of tax:

    

Marketing income and technology costs

   (21  27   31 

Income from equity method investments

   110   201   154 

Other third-party income(a)

   9   26   30 

Other

   (4  (6  (6

Items not allocated to segment income:

    

Gain on asset disposition

   (122  (163  -    

Segment income (loss) not included in results of continuing oil and gas operations:

    

Oil Sands Mining(b)

   N/A    258   (63

Refining, Marketing and Transportation

   464   1,179   2,077 

Integrated Gas

   90   302   132 
             

Segment income

  $1,819  $4,295  $3,698 
(a)

Includes revenues, net of associated costs and income taxes, from activities that support our production operations, which may include processing or transportation of third-party production and the purchase and subsequent resale of natural gas utilized for reservoir management.

(b)

2009 Oil Sands Mining segment income is included in the Results of Operations for Oil and Gas Producing Activities.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved

  December 31, 
(In millions) United
States
  Canada  EG  Other
Africa
  Europe  Total 

2009

      

Future cash inflows

 $  12,094  $  32,207  $    4,620  $  14,974  $    6,901  $ 70,796 

Future production and administrative costs

  (6,796  (21,044  (1,514  (876  (2,373  (32,603

Future development costs

  (1,362  (6,715  (462  (677  (1,119  (10,335

Future income tax expenses

  (923  (60  (935  (12,419  (1,768  (16,105
                        

Future net cash flows

 $3,013  $4,388  $1,709  $1,002  $1,641  $11,753 

10 percent annual discount for estimated timing of cash flows

  (1,041  (3,658  (625  (571  (167  (6,062
                        

Standardized measure of discounted future net cash flows relating to proved oil and gas reserves

 $1,972  $730  $1,084  $431  $1,474  $5,691 

2008

      

Future cash inflows

 $11,295  $-     $3,316  $8,952  $5,578  $29,141 

Future production and administrative costs

  (6,045  -      (1,525  (666  (2,130  (10,366

Future development costs

  (2,673  -      (436  (172  (1,690  (4,971

Future income tax expenses

  (443  -      (429  (7,422  (64  (8,358
                        

Future net cash flows

 $2,134  $-     $926  $692  $1,694  $5,446 

10 percent annual discount for estimated timing of cash flows

  (703  -      (352  (330  (26  (1,411
                        

Standardized measure of discounted future net cash flows relating to proved oil and gas reserves

 $1,431  $-     $574  $362  $1,668  $4,035 

Standardized measure of discounted future net cash flows relating to discontinued operations

 $-     $-     $-     $20  $264  $284 

2007

      

Future cash inflows

 $19,432  $-     $9,787  $21,732  $13,449  $64,400 

Future production and administrative costs

  (5,769  -      (1,314  (671  (2,982  (10,736

Future development costs

  (1,299  -      (552  (124  (2,002  (3,977

Future income tax expenses

  (4,047  -      (2,715  (19,445  (3,816  (30,023
                        

Future net cash flows

 $8,317  $-     $5,206  $1,492  $4,649  $19,664 

10 percent annual discount for estimated timing of cash flows

  (3,297  -      (2,094  (713  (593  (6,697
                        

Standardized measure of discounted future net cash flows relating to proved oil and gas reserves

 $5,020  $-     $3,112  $779  $4,056  $12,967 

Standardized measure of discounted future net cash flows relating to discontinued operations

 $-     $-     $-     $282  $246  $528 

Supplementary Information on Oil and Gas ReservesProducing Activities (Unaudited)

 

(In millions)  2008  2007  2006 

Sales and transfers of oil and gas produced, net of production, transportation and administrative costs

  $(7,141) $(4,887) $(5,312)

Net changes in prices and production, transportation and administrative costs related to future production

   (18,290)  12,845   (1,342)

Extensions, discoveries and improved recovery, less related costs

   663   1,816   1,290 

Development costs incurred during the period

   1,916   1,654   1,251 

Changes in estimated future development costs

   (1,584)  (1,727)  (527)

Revisions of previous quantity estimates

   53   290   1,319 

Net changes in purchases and sales of minerals in place

   (13)  23   30 

Accretion of discount

   2,796   1,726   1,882 

Net change in income taxes

   12,805   (6,751)  (660)

Timing and other

   (96)  (12)  (14)
             

Net change for the year

   (8,891)  4,977   (2,083)

Beginning of the year

   13,495   8,518   10,601 
             

End of year

  $4,604  $13,495  $8,518 

Net change for the year from discontinued operations

  $  $  $(216)

Changes in the Standardized Measure of Discounted Future Net Cash Flows

Index to Financial Statements

(In millions)  2009  2008  2007 

Sales and transfers of oil and gas produced, net of production and
administrative costs

  $(4,876 $(6,863 $(4,613

Net changes in prices and production and administrative costs related to
future production

   4,840   (18,683  12,344 

Extensions, discoveries and improved recovery, less related costs

   1,399   663   1,816 

Development costs incurred during the period

   2,786   1,774   1,569 

Changes in estimated future development costs

   (3,641  (1,436  (1,706

Revisions of previous quantity estimates

   5,110   85   166 

Net changes in purchases and sales of minerals in place

   (159  (13  23 

Accretion of discount

   787   2,724   1,696 

Net change in income taxes

   (4,441  12,633   (6,647

Timing and other

   (149  184   (31
             

Net change for the year

   1,656   (8,932  4,617 

Beginning of the year

   4,035   12,967   8,350 
             

End of year

  $      5,691  $      4,035  $    12,967 

Net change for the year from discontinued operations

  $-     $284  $528 

MARATHON OIL CORPORATION

SupplementalSupplementary Statistics (Unaudited)(Unaudited)

 

  December 31,   December 31, 
(In millions, except as noted)  2008 2007 2006 
(In millions)  2009 2008 2007 

Segment Income (Loss)

        

Exploration and Production

        

United States

  $869  $623  $873   $55  $869  $623 

International

   1,846   1,106   1,130    1,166   1,687   929 
                    

E&P segment

   2,715   1,729   2,003    1,221   2,556   1,552 

Oil Sands Mining

   258   (63)      44   258   (63

Integrated Gas

   90   302   132 

Refining, Marketing and Transportation

   1,179   2,077   2,795    464   1,179   2,077 

Integrated Gas

   302   132   16 
                    

Segment income

   4,454   3,875   4,814    1,819   4,295   3,698 

Items not allocated to segments, net of income taxes:

    

Corporate and other unallocated items

   (93)  (122)  (190)

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

   111   (118)  232 

Foreign currency gain (loss) on income taxes

   252   18   (22)

Impairments

   (1,437)      

Gain on dispositions

   241   8   274 

Gain on foreign currency derivative instruments

      112    

Deferred income taxes – tax legislation

      193   21 

– other adjustments(a)

         93 

Loss on early extinguishment of debt

      (10)  (22)

Discontinued operations

         34 

Items not allocated to segments, net of income taxes

   (356  (767  258 
                    

Net income

  $3,528  $3,956  $5,234   $    1,463  $    3,528  $    3,956 

Capital Expenditures

    
          

Capital Expenditures(a)

    

Exploration and Production

  $3,113  $2,511  $2,169     

United States

  $1,420  $2,036  $1,353 

International

   742   935   1,073 
          

E&P segment

   2,162   2,971   2,426 

Oil Sands Mining

   1,038   165       1,115   1,038   165 

Integrated Gas(b)

   2   4   93 

Refining, Marketing and Transportation

   2,954   1,640   916    2,570   2,954   1,640 

Integrated Gas(b)

   4   93   307 

Discontinued Operations

         45 

Discontinued Operations(c)

   81   142   85 

Corporate

   37   57   41    42   37   57 
                    

Total

  $7,146  $4,466  $3,478   $5,972  $7,146  $4,466 

Exploration Expenses

        

United States

  $238  $274  $169   $153  $238  $274 

International

   252   180   196    154   251   180 
                    

Total

  $490  $454  $365   $307  $489  $454 

(a)

Other deferred tax adjustmentsCapital expenditures include changes in 2006 represent a benefit recorded for cumulative income tax basis differences associated with prior periods.accruals.

(b)

Through April 2007, includes EGHoldings at 100 percent. Effective May 1, 2007, we no longer consolidate EGHoldings and our investment in EGHoldings is accounted for prospectively using the equity method of accounting; therefore, EGHoldings’ capital expenditures subsequent to April 2007 are not included in our capital expenditures.

(c)

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

Index to Financial Statements

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

 

(In millions, except as noted)  2008 2007 2006   
  2009  2008  2007
E&P Operating Statistics           

Net Liquid Hydrocarbon Sales (mbpd)(c)

           

United States

   63   64   76     64   63   64

Europe

   55   33   35     92   55   33

Africa

   93   100   112     87   87   90
                    

Total International

   148   133   147     179   142   123
                    

Worldwide Continuing Operations

   211   197   223     243   205   187

Discontinued Operations

         12     5   6   10
                    

Worldwide

   211   197   235     248   211   197

Natural gas liquids included in above

   20   22   23     19   20   22

Natural Gas Sales (mmcfd)(d)(c)

           

United States

   448   477   532     373   448   477

Europe

   198   216   243     138   161   177

Africa

   370   232   72     430   370   232
                    

Total International

   568   448   315     568   531   409
                    

Worldwide Continuing Operations

   941   979   886

Discontinued Operations

   17   37   39
         

Worldwide

   1,016   925   847     958   1,016   925

Total Worldwide Sales (mboepd)

           

Continuing Operations

   381   351   365     400   369   334

Discontinued Operations

         12     7   12   17
                    

Worldwide

   381   351   377     407   381   351

Average Realizations(e)

     

Average Realizations(d)

      

Liquid Hydrocarbons (per bbl)

           

United States

  $86.68  $60.15  $54.41    $      54.67  $      86.68  $      60.15

Europe

   90.60   70.31   64.02     64.46   90.60   70.31

Africa

   90.29   66.09   59.83     53.91   89.85   65.41

Total International

   90.40   67.15   60.81     59.31   90.14   66.74

Worldwide Continuing Operations

   89.29   64.86   58.63     58.09   89.07   64.47

Discontinued Operations

         38.38     56.47   96.41   72.19

Worldwide

  $89.29  $64.86  $57.58    $58.06  $89.29  $64.86

Natural Gas (per mcf)

           

United States

  $7.01  $5.73  $5.76    $4.14  $7.01  $5.73

Europe

   8.03   6.53   6.74     4.90   7.67   6.49

Africa(f)

   0.25   0.25   0.27  

Africa(e)

   0.25   0.25   0.25

Total International

   2.97   3.28   5.27     1.38   2.50   2.96

Worldwide Continuing Operations

   2.47   4.56   4.45

Discontinued Operations

   8.54   9.62   6.71

Worldwide

  $4.75  $4.54  $5.58    $2.58  $4.75  $4.54

Net Proved Reserves at year-end (developed and undeveloped)

     

Liquid Hydrocarbons (mmbbl)

     

United States

   178   166   172  

International

   458   484   505  
           

Total

   636   650   677  

Developed reserves as a percentage of total net reserves

   81%  72%  84% 

Natural Gas (bcf)

     

United States

   1,085   1,007   1,069  

International

   2,266   2,443   2,441  
           

Total

   3,351   3,450   3,510  

Developed reserves as a percentage of total net reserves

   70%  71%  50% 

OSM Operating Statistics(f)

      

Net Synthetic Crude Sales (mbpd)(g)

   32   32   4

Synthetic Crude Average Realization (per bbl)(d)

  $56.44  $91.90  $71.07

Net Proved Bitumen Reserves at year-end (mmbbl)(h)

   N/A   388   421

(c)

Amounts represent net sales after royalties, except for Ireland where amounts are before royalties.

(d)

Includes natural gas acquired for injection and subsequent resale of 22 mmcfd, 32 mmcfd 47 mmcfd and 4647 mmcfd for the years 2009, 2008 2007 and 2006.2007.

(e)(d)

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

(f)(e)

Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and EGHoldings, equity method investees. We include our share of Alba Plant LLC’s income in our E&P segment and we include our share of AMPCO’s and EGHoldings’ income in our Integrated Gas segment.

Index to Financial Statements

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

(In millions, except as noted)  2008  2007  2006
OSM Operating Statistics(g)     

Net Bitumen Production (mbpd)(h)

   25   4   

Net Synthetic Crude Sales (mbpd)(h)

   32   4   

Synthetic Crude Average Realization (per bbl)(i)

  $91.90  $71.07  $

Net Proved Bitumen Reserves at year-end (mmbbl)

   388   421   
RM&T Operating Statistics     

Refinery Runs (mbpd)

     

Crude oil refined

   944   1,010   980

Other charge and blend stocks

   207   214   234
            

Total

   1,151   1,224   1,214

Refined Product Yields (mbpd)

     

Gasoline

   609   646   661

Distillates

   342   349   323

Propane

   22   23   23

Feedstocks and special products

   96   108   107

Heavy fuel oil

   24   27   26

Asphalt

   75   86   89
            

Total

   1,168   1,239   1,229

Refined Products Sales Volumes (mbpd)(j)

   1,352   1,410   1,425

Matching buy/sell volumes included above

         24

Refining and Wholesale Marketing Gross

     

Margin (per gallon)(k)

  $0.1166  $0.1848  $0.2288

Speedway SuperAmerica

     

Retail outlets

   1,617   1,636   1,636

Gasoline and distillate sales (millions of gallons)

   3,215   3,356   3,301

Gasoline and distillate gross margin (per gallon)

  $0.1387  $0.1119  $0.1156

Merchandise sales

  $2,838  $2,796  $2,706

Merchandise gross margin

  $716  $705  $667
IG Operating Statistics     

Net Sales (mtpd)(l)

     

LNG

   6,285   3,310   1,026

Methanol

   975   1,308   905

(g)(f)

The oil sands mining operations were acquired October 18, 2007. Daily volumes reported in 2007 represent activity after the acquisition date over by the total number of days in the period.

(h)(g)

Amounts are before royalties.Includes blendstocks.

(h)

Prior to December 31, 2009, reserves related to oil sand mining were not included in the SEC’s definition of oil and gas producing activities; therefore, bitumen reserves were reported separately for the OSM segment. See the Proved Reserves section of the supplemental statistics for 2009 information.

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

(In millions, except as noted)  2009  2008  2007

Proved Reserves

      

Net Proved Reserves at year-end (developed and undeveloped)

      

Liquid Hydrocarbons (mmbbl)

      

United States

   170   178   166

International

   452   454   475
            

Worldwide Continuing Operations

   622   632   641

Discontinued Operations

   -     4   9
            

Worldwide

   622   636   650

Natural Gas (bcf)

      

United States

   820   1,085   1,007

International

   1,904   2,134   2,299
            

Worldwide Continuing Operations

   2,724   3,219   3,306

Discontinued Operations

   -     132   144
            

Worldwide

   2,724   3,351   3,450

Synthetic Crude Oil (mmbbls)(i)

      

Canada

   603   N/A   N/A

Total Proved Reserves (mmboe)

   1,679   1,195   1,225

IG Operating Statistics

      

Net Sales (mtpd)(j)

      

LNG

   6,642   6,285   3,310

Methanol

   1,192   975   1,308

RM&T Operating Statistics

      

Refinery Runs (mbpd)

      

Crude oil refined

   957   944   1,010

Other charge and blend stocks

   196   207   214
            

Total

   1,153   1,151   1,224

Refined Product Yields (mbpd)

      

Gasoline

   669   609   646

Distillates

   326   342   349

Propane

   23   22   23

Feedstocks and special products

   62   96   108

Heavy fuel oil

   24   24   27

Asphalt

   66   75   86
            

Total

   1,170   1,168   1,239

Refined Products Sales Volumes (mbpd)(k)

   1,378   1,352   1,410

Refining and Wholesale Marketing Gross

      

Margin (per gallon)(l)

  $        0.0610  $        0.1166  $        0.1848

Speedway SuperAmerica

      

Retail outlets

   1,603   1,617   1,636

Gasoline and distillate sales (millions of gallons)

   3,232   3,215   3,356

Gasoline and distillate gross margin (per gallon)

  $0.1141  $0.1387  $0.1119

Merchandise sales

  $3,109  $2,838  $2,796

Merchandise gross margin

  $775  $716  $705
(i)

Excludes gainsBeginning December 31, 2009, under revised SEC regulations, reserves related to oil sands mining are reported as synthetic crude oil (bitumen after upgrading), in combination with oil and losses on derivative instruments.gas producing activities.

(j)

Total average daily volumes of all refined product sales to wholesale, branded and retail (SSA) customers.

(k)

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

(l)

Includes both consolidated sales volumes and our share of the sales volumes of equity method investees. LNG sales from Alaska are conducted through a consolidated subsidiary. LNG and methanol sales from Equatorial Guinea are conducted through equity method investees.

(k)

Total average daily volumes of all refined product sales to wholesale, branded and retail (SSA) customers.

(l)

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

Index to Financial Statements
Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

 

Item 9A.Controls and Procedures

Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective.

Internal Control Over Financial Reporting

See Financial Statements and Supplementary Data – Management’s Report on Internal Control over Financial Reporting and – Report of Independent Registered Public Accounting Firm. During the fourth quarter of 2008,2009, there were no changes in our internal control over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal control over financial reporting.

 

Item 9B.Other Information

None.

PART III

 

Item 10.Directors, Executive Officers and Corporate Governance

Information concerning our directors required by this item is incorporated by reference to the material appearing under the heading “Election of Directors” in our Proxy Statement for the 20092010 Annual Meeting of stockholders.

Our Board of Directors has established the Audit and Finance Committee and determined our “Audit Committee Financial Expert.” The related information required by this item is incorporated by reference to the material appearing under the sub-heading “Audit and Finance Committee” located under the heading “The Board of Directors and Governance Matters” in our Proxy Statement for the 20092010 Annual Meeting of Stockholders.

We have adopted a Code of Ethics for Senior Financial Officers. It is available on our website at http://www.marathon.com/Investor_Center/Corporate_Governance/Code_of_Ethics_for_Senior_Financial_Officers/.

Executive Officers of the Registrant

See Item 1. Business – Executive Officers of the Registrant for the names, ages and titles of our executive officers.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires that our directors and executive officers, and persons who own more than ten percent of a registered class of our equity securities, file reports of beneficial ownership on Form 3 and changes in beneficial ownership on Form 4 or Form 5 with the SEC. Based solely on our review of the reporting forms and written representations provided to us by the individuals required to file reports, we believe that each of our executive officers and directors has complied with the applicable reporting requirements for transactions in our securities during the fiscal year ended December 31, 2008.2009.

Index to Financial Statements
Item 11.Executive Compensation

Information required by this item is incorporated by reference to the material appearing under the heading “Executive Compensation Tables and Other Information;” under the sub-headings “Compensation Committee” and “Compensation Committee Interlocks and Insider Participation” under the heading “The Board of Directors and Governance Matters;” and under the heading “Compensation Committee Report” in our Proxy Statement for the 20092010 Annual Meeting of stockholders.

 

Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information concerning security ownership of certain beneficial owners and management required by this item is incorporated by reference to the material appearing under the headings “Security Ownership of Certain Beneficial Owners” and “Security Ownership of Directors and Executive Officers” in our Proxy Statement for the 20092010 Annual Meeting of stockholders.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 20082009 with respect to shares of Marathon common stock that may be issued under our existing equity compensation plans:

 

2007 Incentive Compensation Plan (the “2007 Plan”)

2003 Incentive Compensation Plan (the “2003 Plan”) – No additional awards will be granted under this plan.

1990 Stock Plan – No additional awards will be granted under this plan.

Deferred Compensation Plan for Non-Employee Directors – No additional awards will be granted under this plan.

Index to Financial Statements
  Column (a) Column (b) Column (c)   Column (a) Column (b) Column (c) 
Plan category  Number of
securities
to be issued
upon
exercise of
outstanding
options,
warrants
and rights
 Weighted-
average
exercise
price of
outstanding
options,
warrants
and rights
(c)
 Number of
securities
remaining
available for
future
issuance
under equity
compensation
plans
(d)
   Number of
securities to be
issued upon
exercise of
outstanding
options,
warrants and
rights
 Weighted-
average
exercise
price of
outstanding
options,
warrants
and rights
(c)
 Number of
securities
remaining
available for
future issuance
under equity
compensation
plans
(a)
 

Equity compensation plans approved by stockholders

  13,010,970(a) $37.59  26,716,689(e)  17,537,150 (a)  $35.01   21,726,933 (d) 

Equity compensation plans not approved by stockholders

  94,133(b)  N/A     91,457 (b)   N/A   -    
                

Total

  13,105,103   N/A  26,716,689   17,628,607     N/A   21,726,933   

(a)

Includes the following:

5,433,60010,178,384 stock options outstanding under the 2007 Plan;

6,664,8096,584,742 stock options outstanding under the 2003 Plan and the net number of stock-settled SARs that could be issued from this Plan. The number of stock-settled SARs is based on the closing price of Marathon common stock on December 31, 2008,2009 of $27.36$31.22 per share;

492,780403,100 stock options and SARs outstanding under the 1990 Stock Plan;

178,457211,479 common stock units that have been credited to non-employee directors pursuant to the non-employee director deferred compensation program and the annual director stock award program established under the 2007 Plan and the 2003 Plan; common stock units credited under the 2007 Plan and the 2003 Plan were 30,39980,054 and 148,058;131,425;

213,670152,765 restricted stock units granted to non-officers under the 2007 Plan and outstanding as of December 31, 2008;2009; and

27,6546,680 restricted stock units granted to non-officers under the 2003 Plan and outstanding as of December 31, 2008.2009.

In addition to the awards reported above, 1,536,829 shares and 271,102 shares of restricted stock were issued and outstanding as of December 31, 2008, but subject to forfeiture restrictions under the 2007 Plan and the 2003 Plan.

In addition to the awards reported above 1,239,720 shares and 42,334 shares of restricted stock were issued and outstanding as of December 31, 2009, but subject to forfeiture restrictions under the 2007 Plan and the 2003 Plan.
(b)

Reflects awards of common stock units made to non-employee directors under the Deferred Compensation Plan for Non-Employee Directors prior to April 30, 2003. When a non-employee director leaves the Board, he or she will be issued actual shares of Marathon common stock in place of the common stock units.

(c)

Weighted-average exercise prices do not take the restricted stock units or common stock units into account as these awards have no exercise price.

(d)

Excludes securities reflected in column (a).

(e)

Reflects the shares available for issuance under the 2007 Plan. No more than 10,150,2899,905,317 of these shares may be issued for awards other than stock options or stock appreciation rights. In addition, shares related to grants that are forfeited, terminated, cancelled or expire unexercised shall again immediately become available for issuance.

The Deferred Compensation Plan for Non-Employee Directors is our only equity compensation plan that has not been approved by our stockholders. Our authority to make equity grants under this plan was terminated effective April 30, 2003. Under the Deferred Compensation Plan for Non-Employee Directors, all of our non-employee directors were required to defer half of their annual retainers in the form of common stock units. On the date the retainer would have otherwise been payable to the non-employee director, we credited an unfunded bookkeeping account for each non-employee director with a number of common stock units equal to half of his or her annual retainer divided by the fair market value of Marathon our

common stock on that date. The ongoing value of each common stock unit equals the market price of a share of Marathonour common stock. When the non-employee director leaves the Board, he or she is issued actual shares of Marathonour common stock equal to the number of common stock units in his or her account at that time.

 

Item 13.Certain Relationships and Related Transactions, and Director Independence

Information required by this item is incorporated by reference to the material appearing under the heading “Certain Relationships and Related Person Transactions,” and under the sub-heading “Board and Committee Independence” under the heading “The Board of Directors and Governance Matters” in our Proxy Statement for the 20092010 Annual Meeting of stockholders.

 

Item 14.Principal Accounting Fees and Services

Information required by this item is incorporated by reference to the material appearing under the heading “Information Regarding the Independent Registered Public Accounting Firm’s Fees, Services and Independence” in our Proxy Statement for the 20092010 Annual Meeting of stockholders.

Index to Financial Statements

PART IV

 

Item 15.Exhibits, Financial Statement Schedules

 

A.Documents Filed as Part of the Report

1. Financial Statements (see Part II, Item 8. of this report regarding financial statements)

1.Financial Statements (see Part II, Item 8. of this report regarding financial statements)

2. Financial Statement Schedules

2.Financial Statement Schedules

Financial statement schedules required under SEC rules but not included in this report are omitted because they are not applicable or the required information is contained in the consolidated financial statements or notes thereto.

3. Exhibits:

3.Exhibits:

Any reference made to USX Corporation in the exhibit listing that follows is a reference to the former name of Marathon Oil Corporation, a Delaware corporation and the registrant, and is made because the exhibit being listed and incorporated by reference was originally filed before July 2001, the date of the change in the registrant’s name. References to Marathon Ashland Petroleum LLC or MAP are references to the entity now known as Marathon Petroleum Company LLC.

 

Exhibit
Number

  

Exhibit Description

 Incorporated by Reference Filed
Herewith
 Furnished
Herewith
   Form Exhibit Filing Date SEC File No.  
2      Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession 
2.1  Holding Company Reorganization Agreement, dated as of July 1, 2001, by and among USX Corporation, USX Holdco, Inc. and United States Steel LLC 10-K 2.1 3/1/2007   
2.2  Agreement and Plan of Reorganization, dated as of July 31, 2001, by and between USX Corporation and United States Steel LLC 10-K 2.2 3/1/2007   
2.3++  Master Agreement, among Ashland Inc., ATB Holdings Inc., EXM LLC, New EXM Inc., Marathon Oil Corporation, Marathon Oil Company, Marathon Domestic LLC and Marathon Ashland Petroleum LLC, dated as of March 18, 2004 and Amendment No. 1 dated as of April 27, 2005 S-4/A 2.1 5/19/2005 333-119694  
2.4++  Amended and Restated Arrangement Agreement among Marathon Oil Corporation, 1339971 Alberta Ltd., Western Oil Sands Inc. and WesternZagros Resources Inc., dated as of September 14, 2007 S-

3ASR

 2.7 10/17/2007 333-146772  
2.5++  Amending Agreement among Marathon Oil Corporation, 1339971 Alberta Ltd, Western Oil Sands Inc. and WesternZagros Resources Inc., dated as of October 15, 2007 S-

3ASR

 2.8 10/17/2007 333-146772  

Exhibit
Number

  

Exhibit Description

 Incorporated by Reference Filed
Herewith
 Furnished
Herewith
   Form Exhibit Filing Date SEC File No.  
2.6++  Plan of Arrangement under Section 193 of the Business Corporations Act (Alberta) S-

3ASR

 2.9 10/17/2007 333-146772  
3      Articles of Incorporation and Bylaws 
3.1  Restated Certificate of Incorporation of Marathon Oil Corporation 8-K 3.1 4/25/2007   
3.2  By-Laws of Marathon Oil Corporation 8-K 3.1 11/4/2008   
3.3  Specimen of Common Stock Certificate 8-K 3.3 5/14/2007   
3.4  Certificate of Designations of Special Voting Stock of Marathon Oil Corporation 10-Q 3.3 9/30/2007   
4      Instruments Defining the Rights of Security Holders, Including Indentures 
4.1  Five Year Credit Agreement dated as of May 20, 2004 among Marathon Oil Corporation, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, ABN Ambro Bank N.V., Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents and JPMorgan Chase Bank, as Administrative Agent     X 
4.2  Amendment No. 1 dated as of May 4, 2006 to Five-Year Credit Agreement dated as of May 20, 2004 among Marathon Oil Corporation, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents and JPMorgan Chase Bank, as Administrative Agent 10-Q 4.1 3/31/2006   
4.3  Amendment No. 2 dated as of May 7, 2007 to Five-Year Credit Agreement dated as of May 20, 2004 among Marathon Oil Corporation, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents and JPMorgan Chase Bank, as Administrative Agent 10-Q 4.1 6/30/2007   

Exhibit
Number

  

Exhibit Description

 Incorporated by Reference Filed
Herewith
 Furnished
Herewith
   Form Exhibit Filing Date SEC File No.  
4.4  Amendment No. 3 dated as of October 4, 2007 to Five-Year Credit Agreement dated as of May 20, 2004 among Marathon Oil Corporation, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents and JPMorgan Chase Bank, as Administrative Agent 10-Q 4.1 9/30/2007   
4.5  Amendment No. 4 dated as of April 3, 2008 to Five-Year Credit Agreement dated as of May 20, 2004 among Marathon Oil Corporation, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents and JPMorgan Chase Bank, as Administrative Agent 10-Q 4.2 3/31/2008   
4.6  Indenture dated February 26, 2002 between Marathon and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon S-3 4.4 7/26/2007 333-144874  
  Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon. Marathon hereby agrees to furnish a copy of any such instrument to the Commission upon its request.      
10  Material Contracts 
10.1  Financial Matters Agreement between USX Corporation and United States Steel LLC (converted into United States Steel Corporation) dated as of December 31, 2001 10-K 10.2 12/31/2007   
10.2  Exchangeable Share Provisions of 1339971 Alberta Ltd S-

3ASR

 10.1 10/17/2007 333-146772  
10.3  Form of Support Agreement among Marathon Oil Corporation, 1339971 Alberta Ltd. and Marathon Canadian Oil Sands Holding Limited, dated as of October 18, 2007 S-

3ASR

 10.2 10/17/2007 333-146772  

Exhibit
Number

  

Exhibit Description

 Incorporated by Reference Filed
Herewith
 Furnished
Herewith
   Form Exhibit Filing Date SEC File No.  
10.4  Form of Voting and Exchange Trust Agreement among Marathon Oil Corporation, 1339971 Alberta Ltd., Marathon Canadian Oil Sands Holding Limited and Valiant Trust Company, dated as of October 18, 2007 S-

3ASR

 10.3 10/17/2007 333-146772  
10.5  Marathon Oil Corporation 2007 Incentive Compensation Plan (incorporated by reference to Appendix I to Marathon Oil Corporation’s Definitive Proxy Statement on Schedule 14A filed on March 14, 2007). 14A App. I 3/14/2007   
10.6  Form of Non-Qualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective May 30, 2007 10-Q 10.2 6/30/2007   
10.7  Form of Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective May 30, 2007 (incorporated by reference to Exhibit 10.3 to Marathon Oil Corporation’s Form 10-Q for the quarter ended June 30, 2007). 10-Q 10.3 6/30/2007   
10.8  Form of Performance Unit Award Agreement (2007-2009 Performance Cycle) for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective May 30, 2007 10-Q 10.4 6/30/2007   
10.9  Marathon Oil Corporation 2003 Incentive Compensation Plan, Effective January 1, 2003     X 
10.10  Marathon Oil Corporation 1990 Stock Plan, as Amended and Restated, Effective January 1, 2002 10-Q 10.1 9/30/2008   
10.11  First Amendment to Marathon Oil Corporation 1990 Stock Plan (as Amended and Restated) Effective January 1, 2002 10-Q 10.2 9/30/2008   
10.12  Marathon Oil Corporation Deferred Compensation Plan for Non-Employee Directors (Amended and Restated as of January 1, 2009). 10-K 10.14 2/27/2009   
10.13  Form of Non-Qualified Stock Option Grant for Executive Officers granted under Marathon Oil Corporation’s 1990 Stock Plan, as amended and restated effective January 1, 2002 10-Q 10.3 9/30/2004   

Exhibit
Number

  

Exhibit Description

 Incorporated by Reference Filed
Herewith
 Furnished
Herewith
   Form Exhibit Filing Date SEC File No.  
10.14  Form of Non-Qualified Stock Option Grant for MAP officers granted under Marathon Oil Corporation’s 1990 Stock Plan, as amended and restated effective January 1, 2002 10-K 10.14 12/31/2005   
10.15  Form of Non-Qualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Chief Executive Officer granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003     X 
10.16  Form of Non-Qualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Executive Committee members granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003     X 
10.17  Form of Non-Qualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003     X 
10.18  Form of Non-Qualified Stock Option Award Agreement for MAP officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003     X 
10.19  Form of Stock Appreciation Right Award Agreement for Chief Executive Officer granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003     X 
10.20  Form of Stock Appreciation Right Award Agreement for Executive Committee members granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003     X 
10.21  Form of Stock Appreciation Right Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003     X 

Exhibit
Number

  

Exhibit Description

 Incorporated by Reference Filed
Herewith
 Furnished
Herewith
   Form Exhibit Filing Date SEC File No.  
10.22  Form of Non-Qualified Stock Option Award Agreement granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan     X 
10.23  Form of Officer Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan     X 
10.24  Form of Performance Unit Award Agreement (2005-2007 Performance Cycle) granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan     X 
10.25  Form of Performance Unit Award Agreement (2010-2012 Performance Cycle) granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan     X 
10.26  Form of Non-Qualified Stock Option Award Agreement granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan     X 
10.27  Form of Officer Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan     X 
10.28  Marathon Oil Company Excess Benefit Plan (Amended and Restated as of January 1, 2009). 10-K 10.27 2/27/2009   
10.29  Marathon Oil Company Deferred Compensation Plan. 10-K 10.28 2/27/2009   
10.30  Marathon Petroleum Company LLC Excess Benefit Plan 10-K 10.29 2/27/2009   
10.31  Marathon Petroleum Company LLC Deferred Compensation Plan. 10-K 10.30 2/27/2009   
10.32  Speedway SuperAmerica LLC Excess Benefit Plan 10-K 10.31 2/27/2009   
10.33  Executive Tax, Estate, and Financial Planning Program 10-K 10.32 2/27/2009   
10.34  EMRO Marketing Company Deferred Compensation Plan 10-K 10.33 2/27/2009   
10.35  Speedway SuperAmerica LLC Deferred Compensation Plan. 10-K 10.34 2/27/2009   
10.36  Executive Change in Control Severance Benefits Plan. 10-K 10.35 2/27/2009   
12.1  Computation of Ratio of Earnings to Fixed Charges.     X 
14.1  Code of Ethics for Senior Financial Officers     X 

Exhibit No.
Number

  

Exhibit Description

2.

 Plan of Acquisition, Reorganization, Arrangement, Liquidation or SuccessionIncorporated by ReferenceFiled
Herewith
Furnished
Herewith
FormExhibitFiling DateSEC File No.
2.1Holding Company Reorganization Agreement, dated as of July 1, 2001, by and among USX Corporation, USX Holdco, Inc. and United States Steel LLC (incorporated by reference to Exhibit 2.1 to Marathon Oil Corporation’s Form 10-K filed on March 1, 2007).
2.2Agreement and Plan of Reorganization, dated as of July 31, 2001, by and between USX Corporation and United States Steel LLC (incorporated by reference to Exhibit 2.2 to Marathon Oil Corporation’s Form 10-K filed on March 1, 2007).
2.3++Master Agreement, among Ashland Inc., ATB Holdings Inc., EXM LLC, New EXM Inc., Marathon Oil Corporation, Marathon Oil Company, Marathon Domestic LLC and Marathon Ashland Petroleum LLC, dated as of March 18, 2004 and Amendment No. 1 dated as of April 27, 2005 (incorporated by reference to Exhibit 2.1 on Amendment NO. 3 to the Registration Statement on Form S-4/A (File No. 333-119694) of Marathon Oil Corporation filed on May 19, 2005).
2.4++Amended and Restated Tax Matters Agreement among Ashland Inc., ATB Holdings Inc., EXM LLC, New EXM Inc., Marathon Oil Corporation, Marathon Oil Company, Marathon Domestic LLC and Marathon Ashland Petroleum LLC, dated as of April 27, 2005 (incorporated by reference to Exhibit 2.2 on Amendment No. 3 to the Registration Statement on Form S-4/A (File No. 333-119694) of Marathon Oil Corporation filed on May 19, 2005).
2.5++Assignment and Assumption Agreement (VIOC Centers) between Ashland Inc. and ATB Holdings Inc., dated as of March 18, 2004 (incorporated by reference to Exhibit 2.3 to Marathon Oil Corporation’s Amendment No. 1 to Form 8-K/A, filed on November 29, 2004).
2.6++Assignment and Assumption Agreement (Maleic Business) between Ashland Inc. and ATB Holdings Inc., dated as of March 18, 2004 (incorporated by reference to Exhibit 2.4 to Marathon Oil Corporation’s Amendment No. 1 to Form 8-K/A, filed on November 29, 2004).
2.7++Amended and Restated Arrangement Agreement among Marathon Oil Corporation, 1339971 Alberta Ltd., Western Oil Sands Inc. and WesternZagros Resources Inc., dated as of September 14, 2007 (incorporated by reference to Exhibit 2.7 to the Registration Statement on Form S-3ASR (File No. 333-146772) of Marathon Oil Corporation filed on October 17, 2007).
2.8++Amending Agreement among Marathon Oil Corporation, 1339971 Alberta Ltd, Western Oil Sands Inc. and WesternZagros Resources Inc., dated as of October 15, 2007 (incorporated by reference to Exhibit 2.8 to the Registration Statement on Form S-3ASR (File No. 333-146772) of Marathon Oil Corporation filed on October 17, 2007).

Index to Financial Statements
Exhibit No.Description
2.9++Plan of Arrangement under Section 193 of theBusiness Corporations Act (Alberta) (incorporated by reference to Exhibit 2.9 to the Registration Statement on Form S-3ASR (File No. 333-146772) of Marathon Oil Corporation filed on October 17, 2007).
3.Articles of Incorporation and Bylaws
3.1Restated Certificate of Incorporation of Marathon Oil Corporation (incorporated by reference to Exhibit 3.1 to Marathon Oil Corporation’s Form 8-K, filed on April 25, 2007).
3.2By-Laws of Marathon Oil Corporation (incorporated by reference to Exhibit 3.1 to Marathon Oil Corporation’s Form 8-K, filed on November 4, 2008).
3.3Specimen of Common Stock Certificate (incorporated by reference to Exhibit 3.3 to Marathon Oil Corporation’s Form 8-K filed on May 14, 2007).
3.4Certificate of Designations of Special Voting Stock of Marathon Oil Corporation (incorporated by reference to Exhibit 3.3 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2007).
4.Instruments Defining the Rights of Security Holders, Including Indentures
4.1Five Year Credit Agreement dated as of May 20, 2004 among Marathon Oil Corporation, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, ABN Ambro Bank N.V., Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents and JPMorgan Chase Bank, as Administrative Agent (incorporated by reference to Exhibit 4.1 to Marathon Oil Corporation’s Form 10-Q for the quarter ended June 30, 2004).
4.2Amendment No. 1 dated as of May 4, 2006 to Five-Year Credit Agreement dated as of May 20, 2004 among Marathon Oil Corporation, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents and JPMorgan Chase Bank, as Administrative Agent (incorporated by reference to Exhibit 4.1 to Marathon Oil Corporation’s Form 10-Q for the quarter ended March 31, 2006).
4.3Amendment No. 2 dated as of May 7, 2007 to Five-Year Credit Agreement dated as of May 20, 2004 among Marathon Oil Corporation, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents and JPMorgan Chase Bank, as Administrative Agent (incorporated by reference to Exhibit 4.1 to Marathon Oil Corporation’s Form 10-Q for the quarter ended June 30, 2007).
4.4Amendment No. 3 dated as of October 4, 2007 to Five-Year Credit Agreement dated as of May 20, 2004 among Marathon Oil Corporation, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents and JPMorgan Chase Bank, as Administrative Agent (incorporated by reference to Exhibit 4.1 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2007).
4.5Amendment No. 4 dated as of April 3, 2008 to Five-Year Credit Agreement dated as of May 20, 2004 among Marathon Oil Corporation, the Co-Agents and other Lenders party thereto, Bank of America, N.A., as Syndication Agent, Citibank, N.A. and Morgan Stanley Bank, as Documentation Agents and JPMorgan Chase Bank, as Administrative Agent (incorporated by reference to Exhibit 4.2 to Marathon Oil Corporation’s Form 10-Q for the quarter ended March 31, 2008).
4.6Indenture dated February 26, 2002 between Marathon and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon (incorporated by reference to Exhibit 4.4 to Marathon’s Registration Statement on Form S-3 filed with the SEC on July 26, 2007 (Reg. No 333-144874)).
Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10% of the total consolidated assets of Marathon. Marathon hereby agrees to furnish a copy of any such instrument to the Commission upon its request.

Index to Financial Statements
Exhibit No.Description
10.Material Contracts
10.1Tax Sharing Agreement between USX Corporation and United States Steel LLC (converted into United States Steel Corporation) dated as of December 31, 2001 (incorporated by reference to Exhibit 10.1 to Marathon Oil Corporation’s Annual Report on Form 10-K for the year ended December 31, 2007).
10.2Financial Matters Agreement between USX Corporation and United States Steel LLC (converted into United States Steel Corporation) dated as of December 31, 2001 (incorporated by reference to Exhibit 10.2 to Marathon Oil Corporation’s Annual Report on Form 10-K for the year ended December 31, 2007).
10.3Insurance Assistance Agreement between USX Corporation and United States Steel LLC (converted into United States Steel Corporation) dated as of December 31, 2001 (incorporated by reference to Exhibit 10.3 to Marathon Oil Corporation’s Annual Report on Form 10-K for the year ended December 31, 2007).
10.4Exchangeable Share Provisions of 1339971 Alberta Ltd (incorporated by reference to Exhibit 10.1 to the Registration Statement on Form S-3ASR (File No. 333-146772) of Marathon Oil Corporation filed on October 17, 2007).
10.5Form of Support Agreement among Marathon Oil Corporation, 1339971 Alberta Ltd. and Marathon Canadian Oil Sands Holding Limited, dated as of October 18, 2007 (incorporated by reference to Exhibit 10.2 to the Registration Statement on Form S-3ASR (File No. 333-146772) of Marathon Oil Corporation filed on October 17, 2007).
10.6Form of Voting and Exchange Trust Agreement among Marathon Oil Corporation, 1339971 Alberta Ltd., Marathon Canadian Oil Sands Holding Limited and Valiant Trust Company, dated as of October 18, 2007 (incorporated by reference to Exhibit 10.3 to the Registration Statement on Form S-3ASR (File No. 333-146772) of Marathon Oil Corporation filed on October 17, 2007)
10.7Marathon Oil Corporation 2007 Incentive Compensation Plan (incorporated by reference to Appendix I to Marathon Oil Corporation’s Definitive Proxy Statement on Schedule 14A filed on March 14, 2007).
10.8Form of Non-Qualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective May 30, 2007 (incorporated by reference to Exhibit 10.2 to Marathon Oil Corporation’s Form 10-Q for the quarter ended June 30, 2007).
10.9Form of Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective May 30, 2007 (incorporated by reference to Exhibit 10.3 to Marathon Oil Corporation’s Form 10-Q for the quarter ended June 30, 2007).
10.10Form of Performance Unit Award Agreement (2007-2009 Performance Cycle) for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective May 30, 2007 (incorporated by reference to Exhibit 10.4 to Marathon Oil Corporation’s Form 10-Q for the quarter ended June 30, 2007).
10.11Marathon Oil Corporation 2003 Incentive Compensation Plan, Effective January 1, 2003 (incorporated by reference to Appendix C to Marathon Oil Corporation’s Definitive Proxy Statement on Schedule 14A filed on March 10, 2003).
10.12Marathon Oil Corporation 1990 Stock Plan, as Amended and Restated Effective January 1, 2002 (incorporated by reference to Exhibit 10.1 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2008).
10.13First Amendment to Marathon Oil Corporation 1990 Stock Plan (as Amended and Restated Effective January 1, 2002 (incorporated by reference to Exhibit 10.2 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2008).
10.14*Marathon Oil Corporation Deferred Compensation Plan for Non-Employee Directors (Amended and Restated as of January 1, 2009).
10.15Form of Non-Qualified Stock Option Grant for Executive Officers granted under Marathon Oil Corporation’s 1990 Stock Plan, as amended and restated effective January 1, 2002 (incorporated by reference to Exhibit 10.3 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).

Index to Financial Statements
Exhibit No.Description
10.16Form of Non-Qualified Stock Option Grant for MAP officers granted under Marathon Oil Corporation’s 1990 Stock Plan, as amended and restated effective January 1, 2002 (incorporated by reference to Exhibit 10.14 to Marathon Oil Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005).
10.17Form of Non-Qualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Chief Executive Officer granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 (incorporated by reference to Exhibit 10.4 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).
10.18Form of Non-Qualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Executive Committee members granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 (incorporated by reference to Exhibit 10.5 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).
10.19Form of Non-Qualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 (incorporated by reference to Exhibit 10.6 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).
10.20Form of Non-Qualified Stock Option Award Agreement for MAP officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 (incorporated by reference to Exhibit 10.18 to Marathon Oil Corporation’s Annual Report on Form 10-K for the year ended December 31, 2005).
10.21Form of Stock Appreciation Right Award Agreement for Chief Executive Officer granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 (incorporated by reference to Exhibit 10.7 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).
10.22Form of Stock Appreciation Right Award Agreement for Executive Committee members granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 (incorporated by reference to Exhibit 10.8 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).
10.23Form of Stock Appreciation Right Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003 (incorporated by reference to Exhibit 10.9 to Marathon Oil Corporation’s Form 10-Q for the quarter ended September 30, 2004).
10.24Form of Non-Qualified Stock Option Award Agreement granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan (incorporated by reference to Exhibit 99.1 to Marathon Oil Corporation’s Form 8-K, filed on May 27, 2005).
10.25Form of Officer Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan (incorporated by reference to Exhibit 99.2 to Marathon Oil Corporation’s Form 8-K, filed on May 27, 2005).
10.26Form of Performance Unit Award Agreement (2005-2007 Performance Cycle) granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan (incorporated by reference to Exhibit 99.3 to Marathon Oil Corporation’s Form 8-K filed on May 27, 2005).
10.27*Marathon Oil Company Excess Benefit Plan (Amended and Restated as of January 1, 2009).
10.28*Marathon Oil Company Deferred Compensation Plan.
10.29*Marathon Petroleum Company LLC Excess Benefit Plan (Amended and Restated as of January 1, 2009).
10.30*Marathon Petroleum Company LLC Deferred Compensation Plan.
10.31*Speedway SuperAmerica LLC Excess Benefit Plan (Amended and Restated as of January 1, 2009).
10.32*Executive Tax, Estate, and Financial Planning Program (Amended and Restated as of January 1, 2009).

Index to Financial Statements
Exhibit No.Description
10.33*EMRO Marketing Company Deferred Compensation Plan (Amended and Restated as of January 1, 2009).
10.34*Speedway SuperAmerica LLC Deferred Compensation Plan.
10.35*Executive Change in Control Severance Benefits Plan.
12.1*Computation of Ratio of Earnings to Combined Fixed Charges.
14.1Code of Ethics for Senior Financial Officers (incorporated by reference to Exhibit 14.1 to Marathon Oil Corporation’s Form 10-K for the year ended December 31, 2004).
21.1*21.1  List of Significant Subsidiaries.X
23.1*23.1  Consent of Independent Registered Public Accounting Firm.X
31.1*23.2Consent of GLJ Petroleum Consultants, independent petroleum engineers and geologistsX
23.3Consent of Ryder Scott, independent petroleum engineers and geologistsX
23.4Consent of Netherland, Sewell & Associates, independent petroleum engineers and geologistsX
31.1  Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.X
31.2*31.2  Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934.X
32.1*32.1  Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350.X
32.2*32.2  Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.X

*Filed herewith
99.1Report of GLJ Petroleum Consultants, independent petroleum engineers and geologistsX
99.2Summary report of audits performed by Netherland, Sewell & Associates, independent petroleum engineers and geologistsX
99.3Summary report of audits performed by Ryder Scott, independent petroleum engineers and geologistsX
101.INSXBRL Instance Document.X
101.SCHXBRL Taxonomy Extension Schema.X
101.CALXBRL Taxonomy Extension Calculation Linkbase.X
101.PREXBRL Taxonomy Extension Presentation Linkbase.X
101.LABXBRL Taxonomy Extension Label Linkbase.X
101.DEFXBRL Taxonomy Extension Definition Linkbase.X
++Marathon agrees to furnish supplementally a copy of any omitted schedule to the United States Securities and Exchange Commission upon request.request

Index to Financial Statements

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

 

February 27, 200926, 2010  MARATHON OIL CORPORATION
  By:

/S/    MICHAEL /s/ MICHAEL K. STEWART        

STEWART
   

Michael K. Stewart

Vice President, Accounting and Controller

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on February 27, 200926, 2010 on behalf of the registrant and in the capacities indicated.

 

Signature

  

Title

/S/    THOMASs/ THOMAS J. USHER        USHER

Thomas J. Usher

  Chairman of the Board and Director

/S/    CLARENCEs/ CLARENCE P. CAZALOT, JR.        CAZALOT, JR.

Clarence P. Cazalot, Jr.

  President and Chief Executive Officer and Director

/S/    JANETs/ JANET F. CLARK        CLARK

Janet F. Clark

  Executive Vice President and Chief Financial Officer

/S/    MICHAELs/ MICHAEL K. STEWART        STEWART

Michael K. Stewart

  Vice President, Accounting and Controller

/S/    CHARLES F. BOLDEN, JR.        

Charles F. Bolden, Jr.

Director

/S/    GREGORYs/ GREGORY H. BOYCE        BOYCE

Gregory H. Boyce

  Director

/S/    DAVIDs/ DAVID A. DABERKO        DABERKO

David A. Daberko

  Director

/S/    WILLIAMs/ WILLIAM L. DAVIS        DAVIS

William L. Davis

  Director

/S/    SHIRLEY ANN JACKSON        s/ SHIRLEY ANN JACKSON

Shirley Ann Jackson

  Director

/S/    PHILIP LADER        s/ PHILIP LADER

Philip Lader

  Director

/S/    CHARLESs/ CHARLES R. LEE        LEE

Charles R. Lee

  Director

/S/    MICHAELs/ MICHAEL E. J. PHELPS        PHELPS

Michael E. J. Phelps

  Director

/S/    DENNISs/ DENNIS H. REILLEY        REILLEY

Dennis H. Reilley

  Director

/S/    SETHs/ SETH E. SCHOFIELD        SCHOFIELD

Seth E. Schofield

  Director

/S/    JOHNs/ JOHN W. SNOW        SNOW

John W. Snow

  Director

 

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