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  • 10-K (Feb 26, 2010)

 
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Marathon Oil 10-K 2010
FORM 10-K FOR THE FISCAL YEAR ENDED DECEMBER 31, 2009
Table of Contents

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2009

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Yes  ¨    No  þ

The aggregate market value of Common Stock held by non-affiliates as of June 30, 2009: $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 707,926,768 shares of Marathon Oil Corporation Common Stock outstanding as of January 29, 2010.

Documents Incorporated By Reference:

Portions of the registrant’s proxy statement relating to its 2010 annual meeting of stockholders, to be filed with the Securities and Exchange Commission pursuant to Regulation 14A under the Securities Exchange Act of 1934, are incorporated by reference to the extent set forth in Part III, Items 10-14 of this report.

 

 

 

 


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MARATHON OIL CORPORATION

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

Table of Contents

 

          Page

PART I

     

Item 1.

   Business    1

Item 1A.

   Risk Factors    27

Item 1B.

   Unresolved Staff Comments    34

Item 2.

   Properties    34

Item 3.

   Legal Proceeding    34

Item 4.

   Submission of Matters to a Vote of Security Holders    37

PART II

     

Item 5.

  

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

   38

Item 6.

   Selected Financial Data    39

Item 7.

  

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

   40

Item 7A.

   Quantitative and Qualitative Disclosures about Market Risk    67

Item 8.

   Financial Statements and Supplementary Data    71

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

   137

Item 9A.

   Control and Procedures    137

Item 9B.

   Other Information    137

PART III

     

Item 10.

   Directors, Executive Officers and Corporate Governance    137

Item 11.

   Executive Compensation    138

Item 12.

  

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

   138

Item 13.

   Certain Relationships and Related Transactions, and Director Independence    139

Item 14.

   Principal Accounting Fees and Services    139

PART IV

     

Item 15.

   Exhibits, Financial Statement Schedules    140
   SIGNATURES    147


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Disclosures Regarding Forward-Looking Statements

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

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

PART I

Item 1. Business

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 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

 

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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.

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 vacuum gas oil; 3) Integrated Gas (“IG”) – markets and transports products manufactured from natural gas, such as liquefied natural gas (“LNG”) and methanol, on a worldwide basis; and 4) Refining, Marketing and Transportation (“RM&T”) – refines, transports and markets crude oil and petroleum products, primarily in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the United States. For operating segment and geographic financial information, see Note 9 to the consolidated financial statements.

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

Exploration and Production

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

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

Our 2009 worldwide net liquid hydrocarbon sales averaged 243 thousand barrels per day (“mbpd”). Our 2009 worldwide net natural gas sales, including natural gas acquired for injection and subsequent resale, averaged 941 million cubic feet per day (“mmcfd”). In total, our 2009 worldwide net sales averaged 400 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. These volumes exclude 7 mboepd related to discontinued operations.

In the United States during 2009, we drilled 76 gross (50 net) exploratory wells of which 72 gross (48 net) wells encountered commercial quantities of hydrocarbons. Of these 72 wells, 6 were temporarily suspended or in the process of being completed at year end. Internationally, we drilled 9 gross (1 net) exploratory wells of which 6 gross (1 net) wells encountered commercial quantities of hydrocarbons. All 6 wells were temporarily suspended or were in the process of being completed at December 31, 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. During 2009, our net sales in the Gulf of Mexico averaged 24 mbpd of liquid hydrocarbons and 20 mmcfd of natural gas. At year end 2009, we held interests in seven producing fields and four platforms in the Gulf of Mexico, of which we operate one platform.

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

We own a 50 percent 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 is capable of providing processing and transportation services to nearby third-party fields.

 

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

Development of the Droshky discovery, located on Green Canyon Block 244, continued 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 the subsea facilities and topside modifications to the third-party Bullwinkle host platform. Expected net peak production is approximately 50 mboepd. We hold a 100 percent operated working interest in Droshky.

Development of the Ozona prospect, located on Garden Banks Block 515, has also continued. We have secured a rig to complete the previously drilled appraisal well and tie back to the nearby third-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 2009, our net natural gas sales from Alaska averaged 87 mmcfd. Typically, our natural gas sales from Alaska are seasonal in nature, trending down during the second and third quarters of each year and increasing during the fourth and first quarters. To manage supplies to meet contractual demand we produce and store natural gas in a partially depleted reservoir in the Kenai natural gas field. In 2009, we drilled six wells in Alaska and plan to drill four to 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 65 wells over the next five years. We currently have one operated drilling rig running and averaged 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 a 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 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

 

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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.

 

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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 28 percent working interest. Net liquid hydrocarbon sales from the Brae area

 

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averaged 11 mbpd in 2009. Net Brae natural gas sales averaged 101 mmcfd, or 11 percent of our worldwide net natural gas sales volumes, in 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 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 as well as approximately 1 bcf per day of third-party natural gas.

In the U.K. Atlantic Margin west of the Shetland Islands, we own an average 30 percent working interest in the outside-operated Foinaven area complex, consisting of a 28 percent working interest in the main Foinaven field, 47 percent working interest in East Foinaven and 20 percent working interest in the T35 and T25 fields. Net sales from the Foinaven fields averaged 13 mbpd of liquid hydrocarbons and 7 mmcfd of natural gas in 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.

Poland – We have recently added a new 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 a half year exploration phase for each block includes 2D seismic and at least one well. We were awarded the 269,000 acre Brodnica Block in January 2010, and we continue to look for additional opportunities in Poland. We hold a 100 percent interest and operatorship in all three blocks.

Other International

Indonesia – We are the operator and hold a 70 percent interest in the Pasangkayu Block offshore Indonesia. The 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. 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 southeast of our Pasangkayu Block. Current exploration plans for Bone Bay call for the acquisition of seismic data starting in 2010, followed by drilling of one exploration well in 2011. In the second quarter of 2009, we were awarded a 49 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 in 2011-2012.

We are the operator of a drilling rig consortium, with five other operators, that has secured a deepwater 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 an effective date of January 1, 2009. We retained a 10 percent interest in Block 32.

 

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Gabon – In December 2009, we closed the sale of our 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 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. Net production from these sold properties averaged 8,150 boepd in the first quarter of 2009.

Ireland – In April 2009, we closed the sale of 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 working interest in the Seven Heads natural gas field. Net production from these operations averaged 5 mboepd in the first quarter of 2009.

In July 2009 we closed the sale of our subsidiary holding our 19 percent interest in the outside-operated Corrib natural gas development offshore Ireland. As a result of these dispositions, our Irish exploration and production businesses have been reported as discontinued operations.

The above discussion of the E&P segment includes forward-looking statements with respect to anticipated future exploratory and development drilling, the timing of production from the Droshky and Ozona developments in the Gulf of Mexico, the Faregh Phase II Gas Plant, the PSVM development on Block 31 offshore Angola and 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. The foregoing forward-looking statements may be further affected by the inability to obtain or delay in obtaining necessary government and third-party approvals and permits. The offshore developments could further be affected by presently known data concerning size and character of reservoirs, economic recoverability, future drilling success and production experience. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

 

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Productive and Drilling Wells

For 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.

 

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Drilling Activity

The following table sets forth, by geographic area, the number of net productive and dry development and exploratory wells completed in each of the last three years.

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.

 

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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, natural gas and synthetic crude oil reserves based upon an unweighted average of closing prices for the first day of each month in the 12-month period ended December 31, 2009. Approximately 61 percent of our proved reserves are located in Organization for Economic Cooperation and Development (“OECD”) countries.

 

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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

 

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     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, see Item 8. Financial Statements and Supplementary Data— Supplementary Information on Oil and Gas Producing Activities.

Preparation of Reserve Estimates

Our estimation of net recoverable quantities of liquid hydrocarbons and natural gas is a highly technical process performed primarily by in-house teams of reservoir engineers and geoscience professionals. All estimates are made in compliance with SEC Rule 4-10 of Regulation S-X. Beginning December 31, 2009, reserve estimates are based upon the average of closing prices for the first 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.

 

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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 and 2009. As a member of the OGRC, she participated in the development of the Petroleum Resource Management System (“PRMS”) and served on the Technical Program Committee for a 2007 SPE Reserves Estimation Workshop: Sharing the Vision focusing on PRMS. She chaired the development of the OGRC comments on the SEC’s proposed modernization of oil and gas reporting and was a member of the American Petroleum Institute’s Ad Hoc group that provided comments on the same topic.

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 reserves were reported, an increase of 203 mmboe from December 31, 2008, primarily due to the inclusion of synthetic crude oil. Of the 492 mmboe of proved undeveloped reserves at year end 2009, 31 percent of the volume is associated with projects that have been included in proved reserves for more than five years. The majority of this volume is related to a compression project in 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 from 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 $792 million, $1,189 million and $1,250 million.

 

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As of December 31, 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, natural gas and synthetic crude oil reserves are forward-looking statements and are based on a number of assumptions, including (among others) commodity prices, presently known physical data concerning size and character of the reservoirs, economic recoverability, technology developments, future drilling success, industry economic conditions, levels of cash flow from operations, production experience and other operating considerations. To the extent these assumptions prove inaccurate, actual recoveries and development costs could be different than current estimates.

Net Production Sold

 

     North America    Africa    Europe    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. The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.

(d)

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

(e)

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

Average Sales Price per Unit

 

    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)

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

(b)

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

 

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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 this metric.

(b)

Before December 31, 2009, oil sands mining was not included in the SEC’s definition of oil and gas producing activities; therefore, production costs are not reported.

(c)

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

Integrated Gas

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

We hold a 60 percent interest in EGHoldings, which is accounted for under the equity method of accounting. 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 purchaser under the agreement takes delivery of the LNG on Bioko Island, with pricing linked principally to the Henry Hub index, regardless of destination. This production facility allows us to monetize our natural gas reserves from the Alba field, as natural gas for the facility is purchased from the Alba field participants under a long-term natural gas supply agreement. Gross sales of LNG from this production facility totaled 3.9 million metric tonnes in 2009. In 2009, we continued discussions with the government of Equatorial Guinea and our 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 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 advanced gas technologies. Our Gas-to-Fuels (“GTF™”) technology is one such promising technology.

Our GTFTM technology program is focused on converting natural gas into gasoline blendstocks and petrochemicals. 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.

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

 

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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.

The GTFTM technology is protected by an intellectual property protection program. The U.S. has granted 17 patents for the technology, 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 natural 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 receiving market. We have an active pilot program in place to test and further develop a proprietary natural gas hydrates manufacturing system.

The above discussion of the Integrated Gas segment contains forward-looking statements with respect to the possible expansion of the LNG production 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. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Refining, Marketing and Transportation

We have refining, marketing and transportation operations concentrated primarily in the Midwest, 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 with an aggregate refining capacity of 1.188 million barrels per day (“mmbpd”) of crude oil as of December 31, 2009. During 2009, our refineries processed 957 mbpd of crude oil and 196 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, 2009.

Crude Oil Refining Capacity

 

(Thousands of barrels per day)    2009

Garyville, Louisiana

   436

Catlettsburg, Kentucky

   212

Robinson, Illinois

   206

Detroit, Michigan

   106

Canton, Ohio

   78

Texas City, Texas

   76

St. Paul Park, Minnesota

   74
    

TOTAL

   1,188

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

 

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such as gasoline, distillates, sulfur, asphalt, propane, polymer grade propylene, isobutane and coke. Our Garyville refinery has 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, making 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 approximately $3.9 billion (excluding capitalized interest).

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

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

Our Detroit, Michigan, refinery is located near Interstate 75 in southwest Detroit. It is the only petroleum refinery currently operating in Michigan. The Detroit refinery processes light sweet and heavy sour crude oils, including Canadian crude oils, into products such as gasoline, diesel, asphalt, slurry, propane, chemical grade propylene and sulfur. In 2007, we approved a heavy oil upgrading and expansion project at this refinery, with a current projected cost of $2.2 billion (excluding capitalized interest). This project will enable the refinery to process an additional 80 mbpd of heavy sour crude oils, including Canadian bitumen blends, and will increase its crude oil refining capacity by about 10 percent. Construction began in the first half of 2008 and is presently expected to be complete in 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 southeastern Minnesota where it is one of 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. Our St. Paul Park refinery is certified as a Minnesota VPP site, receiving Rising Star status, and expects to satisfy the requirements for STAR status in 2010.

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

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

 

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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)    2009    2008    2007

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

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, 33 mbpd, or four percent, was supplied by a combination of our E&P and OSM production operations for the year 2009.

Sources of Crude Oil Refined

 

(Thousands of barrels per day)    2009    2008    2007

United States

     613      466      527

Canada

     136      135      138

Middle East and Africa

     154      244      253

Other international

     54      99      92
                    

TOTAL

     957      944      1,010
                    

Average cost of crude oil throughput (Dollars per barrel)

   $ 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 products marketing and distribution – We are a supplier of refined products to resellers and consumers within our 24-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 64 light product and 22 asphalt terminals. In addition, we distribute through 60 third-party terminals in our market area. Our marine transportation operations include 16 towboats, as well as 183 owned and 8 leased barges that transport refined products on the Ohio, Mississippi and Illinois rivers and their tributaries as well as the Intercoastal Waterway. We lease or own approximately 2,400 railcars of various sizes and capacities for movement and storage of refined products. In addition, we own over 120 transport 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    2009     2008     2007  

Private-brand marketers, commercial and industrial consumers

   67   67   69

Marathon-branded outlets

   18   18   16

Speedway SuperAmerica LLC retail outlets

   15   15   15

 

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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

 

(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

We sell gasoline, gasoline blendstocks and No. 1 and No. 2 fuel oils (including kerosene, jet fuel and diesel fuel) to wholesale marketing customers in the Midwest, upper Great Plains, Gulf Coast and southeastern regions of the United States. We sold 51 percent of our gasoline volumes and 87 percent of our distillates volumes on a wholesale or spot market basis in 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 ethanol into gasoline for over 20 years and began expanding our blending program in 2007, in part due to federal regulations that require us to use specified volumes of renewable fuels. Ethanol volumes sold in blended gasoline were 60 mbpd in 2009, 54 mbpd in 2008 and 40 mbpd in 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.

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.

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 5,500 tons per day of fuel grade coke at the Garyville refinery, which is used for power generation and in miscellaneous industrial applications. In early 2009, we discontinued production and sales of petroleum pitch and aliphatic solvents at our Catlettsburg refinery.

We produce and market heavy residual fuel oil or related 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 have refinery based asphalt production capacity of up to 108 mbpd. We market asphalt through 33 owned or leased terminals throughout the Midwest and Southeast. We have a broad customer base, including approximately 675 asphalt-paving contractors, government entities (states, counties, cities and townships) and asphalt roofing shingle manufacturers. We sell asphalt in the wholesale and cargo markets via rail and barge. We also produce asphalt cements, polymer modified asphalt, emulsified asphalt and industrial asphalts.

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.

 

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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;

 

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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, 2009, SSA had 1,603 retail outlets in nine states. Sales of refined products through these retail outlets accounted for 15 percent of our refined product sales volumes in 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. The demand for gasoline is seasonal in a majority of SSA markets, with the highest demand usually occurring during the summer driving season. Margins from the sale of merchandise and services tend to be less volatile than margins from the retail sale of gasoline and diesel fuel.

Competition and Market Conditions

Strong competition exists in all sectors of the oil and gas industry and, in particular, in the exploration for and development of new reserves. We compete with major integrated and independent oil and gas companies, as well as national oil companies, for the acquisition of oil and natural gas leases and other properties. We compete with these companies for the equipment and labor required to develop and operate those properties and in the marketing of oil and natural gas to end-users. Many of our competitors have financial and other resources greater than those available to us. Acquiring 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 “2009 Global Upstream Performance Review” published by IHS Herold Inc., we rank eighth among U.S.-based petroleum companies on the basis of 2008 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

 

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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, 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 64 companies in the sale of refined products to wholesale marketing customers, including private-brand marketers and large commercial and industrial consumers; about 75 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 290 retailers in the retail sale of refined products. (A jobber is a business that does not carry out refining operations but supplies refiner-branded products to gasoline stations or convenience stores. Dealers refer to retail service station or convenience store operators affiliated with a brand identity.) We compete in the convenience store industry through SSA’s retail outlets. The retail outlets offer consumers gasoline, diesel fuel (at selected locations) and a broad mix of other merchandise and services. Several nontraditional fuel retailers, such as supermarkets, club stores and mass merchants, have affected the convenience store industry and the 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 Security organization has the responsibility to ensure that our operating organizations maintain environmental compliance systems that support and foster our compliance with applicable laws and regulations. Committees comprised of certain of our officers review our overall performance associated with various environmental compliance programs. We also have a Crisis Management Team which oversees our response to any major environmental or other emergency incident involving us or any of our properties.

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

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

For a discussion of environmental capital expenditures and costs of compliance for air, water, solid waste and remediation, see Item 3. Legal Proceedings and Item 7. Management’s Discussion and Analysis of Financial

 

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Condition and Results of Operations – Management’s Discussion and Analysis of Environmental Matters, Litigation and Contingencies.

Air

The EPA is in the process of implementing regulations to address the National Ambient Air Quality Standards (“NAAQS”) for fine particulate emissions and ozone. In connection with these standards, the EPA will designate certain areas as “nonattainment,” meaning that the air quality in such areas does not meet the NAAQS. 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 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. 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 cannot reasonably estimate the final financial impact of these revised NAAQS standard until the implementing rules are established and judicial challenges over the revised NAAQS standards are resolved.

Water

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

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”)

 

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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 2010, Canada will implement a ban on the land application of certain wastes. However, the ongoing waste handling and disposal-related costs associated with the Canadian land disposal restrictions are not 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 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. In September 2009, the AOSP Joint Venture Operator submitted a tailings management paper to the ERCB, that sets forth its plan to comply with the Directive. This plan is currently under review by the ERCB. Increased compliance costs may result if tailing pond reclamation technologies prove unsuccessful or 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 second Renewable Fuel Standard (“RFS2”). The EPA announced the final RFS2 regulations on February 4, 2010. The RFS2 requires 12.95 billion gallons of renewable fuel usage in 2010, increasing to 36.0 billion gallons by 2022. In the near term, the RFS2 will be satisfied primarily with fuel ethanol blended into gasoline. The RFS2 presents production and logistic challenges for both the fuel ethanol and petroleum refining industries. The RFS2 has required, and will likely in the future continue to require, additional capital expenditures or expenses by us to accommodate increased fuel ethanol use. Within the overall 36.0 billion gallon RFS2, EISA establishes an advanced biofuel RFS2 that begins with 0.95 billion gallons in 2010 and increases to 21.0 billion gallons by 2022. Subsets within the advanced biofuel RFS2 include 1.15 billion gallons of biomass-based diesel in 2010, 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.

 

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

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

Financial Matters Agreement

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

 

   

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

 

   

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

 

   

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

 

   

certain other guarantees.

The financial matters agreement also provides that, on or before 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.

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

Concentrations of Credit Risk

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

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.

 

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Employees

We had 28,855 active employees as of December 31, 2009. Of that number, 18,325 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. Certain employees at our Texas City refinery are represented by the same union under a labor agreement that expires on March 31, 2012. The International Brotherhood of Teamsters represents certain hourly employees 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, 2010, are as follows:

 

Clarence P. Cazalot, Jr.

   59    President and Chief Executive Officer

Janet F. Clark

   55    Executive Vice President and Chief Financial Officer

Gary R. Heminger

   56    Executive Vice President, Downstream

Jerry Howard

   61    Senior Vice President, Corporate Affairs

Sylvia J. Kerrigan

   44    Vice President, General Counsel and Secretary

Paul C. Reinbolt

   54    Vice President, Finance and Treasurer

David E. Roberts, Jr.

   49    Executive Vice President, Upstream

Michael K. Stewart

   52    Vice President, Accounting and Controller

Howard J. Thill

   50    Vice President, Investor Relations and Public Affairs

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

 

   

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

 

   

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

 

   

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

 

   

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. 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

 

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

Item 1A. Risk Factors

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

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 refineries;

 

   

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.

 

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

The proved reserve information included in this report has been derived from engineering estimates. Estimates of liquid hydrocarbon and natural gas reserves were prepared by our in-house teams of reservoir engineers and geoscience professionals and were reviewed, on a selected basis, by our Corporate Reserves Group or third-party consultants. The synthetic crude oil reserves estimates were prepared by GLJ Petroleum Consultants, a third-party consulting firm experienced in working with oil sands. Reserves were priced at the average of closing prices for the first day of each month in the 12-month period ended December 31, 2009, as well as other conditions in existence at the date. Any significant future price changes will have a material effect on the quantity and present value of our proved reserves. Future reserve revisions could also result from changes in governmental regulation, among other things.

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

 

   

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

 

   

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

 

   

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

 

   

the assumed effects of regulation by governmental agencies;

 

   

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

 

   

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

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

 

   

the amount and timing of production;

 

   

the revenues and costs associated with that production; and

 

   

the amount and timing of future development expenditures.

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

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

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

The rate of production from liquid hydrocarbon and natural gas properties generally declines as reserves are depleted. Except to the extent we acquire interests in additional properties containing proved reserves, conduct

 

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

 

   

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

 

   

drilling success;

 

   

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

 

   

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

 

   

the ability to fund such activity.

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

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

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 other requirements relating to the protection of the environment, including those relating to the discharge of materials into the environment, waste management, pollution prevention, greenhouse gas emissions, and characteristics and composition of gasoline and diesel fuels, as well as laws and regulations relating to public and employee safety and health and to facility security. We have incurred and 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

 

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potential greenhouse gas emissions or carbon trading or tax 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.

 

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

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

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

 

   

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

 

   

unplanned increases in the cost of construction materials or labor;

 

   

disruptions in transportation of components or construction materials;

 

   

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

 

   

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

 

   

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

 

   

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

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

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

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

Uncertainty 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 services including insurance, cash management, commercial letters of

 

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credit, derivative instruments, and short-term investments. Uncertainty affecting the financial markets and the possibility that financial institutions may consolidate or go bankrupt has altered levels of activity in the financial markets. A deterioration of the financial market conditions could significantly increase our costs associated with borrowing. Our liquidity and our ability to access the credit and/or capital markets may also be adversely affected by changes in the financial markets and the global economy. In addition, there could be a number of follow-on effects from continued turmoil on us, including insolvency of customers, key suppliers, partners, and other counterparties.

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

Local political and economic factors in global markets could have a material adverse effect on us. A total of 29 percent of our liquid hydrocarbon and natural gas sales volumes in 2009 was derived from production outside the United States and 71 percent of our proved liquid hydrocarbon and natural gas reserves as of December 31, 2009, were located outside the United States. All of our synthetic crude oil production and proved reserves are located in Canada. In addition, a significant portion of the feedstock requirements for our refineries is satisfied through supplies originating in Saudi Arabia, Kuwait, Canada, Mexico and various other foreign countries. We are, therefore, subject to the political, geographic and economic risks and possible terrorist activities attendant to doing business with suppliers located in, and supplies originating from, those areas. There are many risks associated with operations in global markets, including changes in governmental policies relating to liquid hydrocarbon, natural gas, bitumen, synthetic crude oil or refined product pricing and taxation, other political, economic or diplomatic developments and international monetary fluctuations. These risks include:

 

   

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

 

   

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

 

   

fluctuating currency values, hard currency shortages and currency controls.

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. We do not insure against all potential losses and therefore we could be seriously harmed by unexpected liabilities and increased costs.

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

 

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

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.

 

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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

None.

Item 2. Properties

The location and general character of our principal liquid hydrocarbon and natural gas properties, oil sands mining properties and facilities, refineries, pipeline systems and other important physical properties have been described by segment under Item 1. Business. Except for oil and gas producing properties, including oil sands mines, which generally are leased, or as otherwise stated, such properties are held in fee. The plants and facilities have been constructed or acquired over a period of years and vary in age and operating efficiency. At the date of acquisition of important properties, titles were examined and opinions of counsel obtained, but no title examination has been made specifically for the purpose of this document. The properties classified as owned in fee generally have been held for many years without any material unfavorably adjudicated claim.

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

Item 3. Legal Proceedings

We are 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 27 cases arising in four states alleging damages for MTBE contamination. Like the cases that we settled in 2008, 12 of the remaining cases are consolidated in a multi-district litigation (“MDL”) in the Southern District of New York for pretrial proceedings. The other 15 cases are in New York state courts (Nassau and Suffolk Counties). Plaintiffs in 26 of the 27 cases allege damages to water supply wells from contamination of groundwater by MTBE, similar to the damages claimed in the cases settled in 2008. In the remaining case, the 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. We are vigorously defending these cases. We have engaged in settlement discussions related to the majority of these cases. We do not expect our share of liability for these cases to significantly impact our consolidated results of operations, financial position or cash flows. We voluntarily discontinued producing MTBE in 2002.

 

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Natural Gas Royalty Litigation

We are currently a party to one qui tam case, which alleges that Marathon and other defendants violated the False Claims Act with respect to the reporting 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 relator 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 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.

Product Contamination Litigation

A lawsuit filed in the U.S. District Court for the Southern District of West Virginia alleged 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 there was no permanent damage to wholesaler and retailer equipment. Class action certification was granted in August 2007. A settlement of the case was approved by the court on March 18, 2009, payment has been made and the case has been dismissed with prejudice. The settlement did 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. The mediation was unsuccessful; however the Court ultimately vacated the U.S. EPA’s approval of the 2003 and 2006 Montana standards and remanded the matter to the U.S. EPA with instructions for reconsideration. The federal government filed a Notice of Appeal, but subsequently filed a voluntary Motion to dismiss which was granted by the District Court. 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 a decision in the litigation with U.S. EPA in Wyoming Federal District Court, reversing U.S. EPA’s approval of the Montana regulations.

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 matter was resolved in the third quarter of 2009 with the 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

 

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Basin Natural Gas Plant. We believe there has been no adverse impact to public health or the environment, having implemented voluntary emission reduction measures over the years. We have finalized a consent order and the court has approved it. The order requires a cash penalty of $610,560 plus plant compliance projects and supplemental environmental projects estimated to cost over $5 million. We were the operator and part owner of the plant through June 2009. We are working with the other plant owners to obtain reimbursement for their share of these costs.

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 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, 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, 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 $1 million to $2 million or more each and the other site may be under $1 million. In addition, there are four sites for which we have received information requests or other indications that we may be a PRP under CERCLA, but for which sufficient information is not presently available to confirm the existence of liability.

There are also 116 sites, excluding retail marketing outlets, where remediation is being sought under other environmental statutes, both federal and state, or where private parties are seeking remediation through discussions or litigation. Based on currently available information, which is in many cases preliminary and incomplete, we believe that liability for clean-up and remediation costs in connection with five of these sites will be under $100,000 per site, that 55 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. With respect to the remaining 17 sites, Ashland retains

 

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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 $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 27 years, we anticipate spending approximately $4.6 million in remediation costs at this site. In 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 $434,000, respectively, with expenditures for remedial measures in 2010 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 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 million, as part of a settlement of an enforcement action for alleged CAA violations relating to benzene waste NESHAPS. We anticipate entering into a formal consent decree or amendment to resolve these matters in 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. This matter was concluded whereby all parties agreed to 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, Texas City, and St. Paul Park refineries with agreed–to penalties of $321,500 and $135,000 imposed in Canton and Texas City, respectively. No penalties were imposed as a result of the other inspections. Inspections may occur at Garyville in 2010 and further enforcement action by OSHA or equivalent state agency may result.

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

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

None.

 

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PART II

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

The principal market on which Marathon common stock is traded is the New York Stock Exchange. 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.

The following is the quarterly high and low sales prices for Marathon common stock:

 

     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.

Issuer Purchases of Equity Securities

The following table provides information about purchases by Marathon and its affiliated purchaser during the quarter ended December 31, 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)
 

10/01/09 – 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)

31,849 shares of restricted stock were delivered by employees to Marathon, upon vesting, to satisfy tax withholding requirements.

(b)

Under the terms of the transaction whereby we acquired the minority interest in Marathon Petroleum Company and other businesses from Ashland Inc. (“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 $52.17 per share. In the fourth quarter of 2009, we acquired 7 shares due to acquisition share exchanges and Ashland share transfers pending at the closing of the transaction.

(c)

47,835 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”) by the administrator of the Dividend Reinvestment Plan. Shares needed to meet the requirements of the Dividend Reinvestment Plan are either purchased in the open market or issued directly by Marathon.

(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, 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 shares have been repurchased under this program since August 2008.

 

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Item 6. Selected Financial Data

 

(Dollars in millions, except as noted)    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   
(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 15 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 13 to the consolidated financial statements).

(c)

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

(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.

(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.

(f)

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

 

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

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

 

   

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

 

   

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

 

   

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

 

   

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

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

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.

Overview

Exploration and Production

Prevailing prices for the various grades of crude oil and natural gas that we produce significantly impact our revenues and cash flows. Prices were volatile in 2009, but not as much as in the previous year. Prices in 2009 were also lower than in recent years as illustrated by the annual averages for key benchmark prices below.

 

Benchmark    2009    2008    2007

WTI crude oil (Dollars per barrel)

   $ 62.09    $ 99.75    $ 72.41

Dated Brent crude oil (Dollars per barrel)

   $ 61.67    $ 97.26    $ 72.39

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

   $ 3.99    $ 9.04    $ 6.86
(a)

First-of-month price index.

Crude oil prices rose sharply through the first half of 2008 as a result of strong global demand, a declining dollar, ongoing concerns about supplies of crude oil, and geopolitical risk. Later in 2008, crude oil prices sharply declined as the U.S. dollar rebounded and global demand decreased as a result of economic recession. The price decrease continued into 2009, but reversed after dropping below $33.98 in February, ending the year at $79.36.

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

 

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Natural gas prices on average were lower in 2009 than in 2008 and in 2007, with prices in 2008 hitting uniquely high levels. A significant portion of our natural gas production in the lower 48 states of the U.S. is sold at bid-week prices or first-of-month indices relative to our specific producing areas. A 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 be less than benchmark natural gas 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 the upgrader.

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

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

 

Benchmark    2009    2008    2007

WTI crude oil (Dollars per barrel)

   $ 62.09    $ 99.75    $ 72.41

Western Canadian Select (Dollars per barrel)(a)

   $ 52.13    $ 79.59    $ 49.60

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.

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. and Europe.

Our most significant LNG investment is our 60 percent ownership in a production facility in Equatorial Guinea, which sells LNG under a long-term contract at prices tied to Henry Hub natural gas prices. In 2009, the gross sales from the plant were 3.9 million metric tonnes, while in 2008, its first full year of operations, the plant sold 3.4 million metric tonnes. Industry estimates of 2009 LNG trade are approximately 185 million metric tonnes. More LNG production facilities and tankers were under construction in 2009. As a result of the sharp worldwide economic downturn in 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. Gross 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 2010 Chemical Markets Associates, Inc. estimates world demand for methanol in 2009 was 41 million metric tonnes. Our plant capacity is 1.1 million, or about 3 percent of total demand.

Refining, Marketing and Transportation

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

 

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

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, which include depreciation.

Manufacturing costs are primarily driven by the cost of energy 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 and 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 levels. The gross margin on merchandise sold at retail outlets has been historically less volatile.

 

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2009 Highlights

E&P Segment

 

   

Realized exceptional utilization of the Alvheim floating production, storage and offloading (FPSO) vessel, with a record average monthly production rate of 90,000 net boepd in October 2009.

 

   

Achieved first oil from the Volund field in Norway ahead of schedule.

 

   

Awarded 49 percent interest and will serve as operator in the Kumawa block offshore Indonesia.

 

   

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

 

   

Progressed Droshky development in the Gulf of Mexico – currently on schedule and under budget.

 

   

Announced Shenandoah deepwater discovery and leased 16 new blocks in the Gulf of Mexico.

 

   

Announced Leda, Oberon and Tebe deepwater discoveries in Angola.

 

   

Continued Bakken Shale production ramp-up, reaching a year-end rate over 11,000 net boepd.

 

   

Added three onshore exploration licenses in Poland with shale gas potential (including one added in January 2010).

OSM Segment

 

   

Added three additional leases in the AOSP area in Canada, which increased net proved reserves by 168 mmbbl.

 

   

Progressed construction of the AOSP Phase 1 expansion, with mining operations anticipated in the second half of 2010, and the upgrader operations anticipated in late 2010 or early 2011.

Reserves

 

   

Added 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 Equatorial 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 Upgrading Project, with 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 2008.

Divestitures

 

   

Disposed of our exploration 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.

 

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Consolidated Results of Operations: 2009 compared to 2008

Revenues are summarized in the following table:

 

(In millions)    2009     2008  

E&P

   $         7,851     $         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

 

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      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”) during 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 portion of our outside-operated Permian Basin producing assets in New Mexico and west Texas, plus sales of other oil and gas properties and retail stores. In 2008, we sold our outside-operated interests (24 percent of Heimdal field, 47 percent

 

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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.

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 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 operations reflect 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.

 

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Segment Results: 2009 compared to 2008

Segment income for 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.

 

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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 averaged 957 mbpd of crude oil throughput in 2009 and 944 mbpd in 2008. Total refinery throughputs averaged 1,153 mbpd in 2009 compared to 1,151 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 operations in 2008.

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

Revenues are summarized in the following table.

 

(In millions)    2008     2007  

E&P

   $ 12,047     $ 8,699  

OSM

     1,122       221  

IG

     93       218  

RM&T

     64,481       56,075  
                

Segment revenues

     77,743       65,213  
                

Elimination of intersegment revenues

     (1,207     (885

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

     218       (232
                

Total revenues

   $ 76,754     $ 64,096  
                

Items included in both revenues and costs:

    

Consumer excise taxes on petroleum products and merchandise

   $ 5,065     $ 5,163  

E&P segment revenues increased $3,348 million from 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.

 

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      2008    2007

E&P Operating Statistics

     

Net Liquid Hydrocarbon Sales (mbpd)(a)

     

United States

   63    64

Europe

   55    33

Africa

   87    90
         

Total International

   142    123
         

Worldwide Continuing Operations

   205    187

Discontinued Operations(b)

   6    10
         

Worldwide

   211    197

Natural Gas Sales (mmcfd)

     

United States

   448    477

Europe(c)

   161    177

Africa

   370    232
         

Total International

   531    409
         

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. 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 32 mmcfd and 47 mmcfd in 2008 and 2007.

(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 U.K. that were accounted for as derivative instruments.

OSM segment revenues increased $901 million from 2007 to 2008, 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

 

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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 from 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 from 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.

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 $10,548 million from 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 15 to the consolidated financial statements for further information about the impairment.

Net interest and other financial income or costs reflected $28 million in costs for 2008 and $33 million of income for 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 $565 million from 2007 to 2008, a 20 percent increase, although income from continuing operations before income taxes increased only $183 million, or 3 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 $249 million benefit from the remeasurement of foreign currency denominated deferred tax balances. See Note 11 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.

 

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Segment Results: 2008 compared to 2007

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

 

(In millions)    2008     2007  

E&P

    

United States

   $ 869     $ 623  

International

     1,687       929  
                

E&P segment

     2,556       1,552  

OSM

     258       (63

IG

     302       132  

RM&T

     1,179       2,077  
                

Segment income

     4,295       3,698  

Items not allocated to segments, net of income taxes:

    

Corporate and other unallocated items

     (75     (128

Foreign currency effects on tax balances

     249       19  

Impairments(a)

     (1,437     -     

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

     111       (118 <