Edgar Filing: MARATHON OIL CORP

Form 10-K

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, 2011

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 Street, Houston, TX 77056-2723

(Address of principal executive offices)

(713) 629-6600

(Registrant’s telephone number, including area code)

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


Title of Each Class		Name of Each Exchange on Which Registered
Common Stock, par value $1.00		New York Stock Exchange

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

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

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

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

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

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, 2011: $22,773 million. This amount is based on the closing price of the registrant’s Common Stock on the New York Stock Exchange on that date. Shares of Common Stock held by executive officers and directors of the registrant are not included in the computation. The registrant, solely for the purpose of this required presentation, has deemed its directors and executive officers to be affiliates.

There were 703,925,642 shares of Marathon Oil Corporation Common Stock outstanding as of January 31, 2012.

Documents Incorporated By Reference:

Portions of the registrant’s proxy statement relating to its 2012 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.

MARATHON OIL CORPORATION

Unless the context otherwise indicates, references to “Marathon Oil,” “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 Oil exerts significant influence by virtue of its ownership interest).

Table of Contents


			Page
PART I

	Item 1.	Business		3

	Item 1A.	Risk Factors		22

	Item 1B.	Unresolved Staff Comments		28

	Item 2.	Properties		28

	Item 3.	Legal Proceedings		28

PART II

	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		30

	Item 6.	Selected Financial Data		31

	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		32

	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		51

	Item 8.	Financial Statements and Supplementary Data		53

	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		107

	Item 9A.	Controls and Procedures		107

	Item 9B.	Other Information		107

PART III

	Item 10.	Directors, Executive Officers and Corporate Governance		107

	Item 11.	Executive Compensation		107

	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		108

	Item 13.	Certain Relationships and Related Transactions, and Director Independence		109

	Item 14.	Principal Accounting Fees and Services		109

PART IV

	Item 15.	Exhibits, Financial Statement Schedules		110

		SIGNATURES		116

DEFINITIONS

Throughout the following report, the following company or industry specific terms and abbreviations are used.

AMPCO – Atlantic Methanol Production Company LLC, a company in which we own a 45 percent equity interest.

AOSP – Athabasca Oil Sands Project, an oil sands mining, transportation and upgrading joint venture located in Alberta, Canada, in which we hold a 20 percent interest.

bbl – One stock tank barrel, which is 42 U.S. gallons liquid volume.

bbld – barrels per day.

bboe – Billion barrels of oil equivalent. Natural gas is converted to a boe based on the energy equivalent, which on a dry gas basis is six mcf of gas per one barrel of oil equivalent.

bcf – Billion cubic feet.

boe – Barrels of oil equivalent.

boed – Barrels of oil equivalent per day.

BOEMRE – United States Bureau of Ocean Energy Management, Regulation and Enforcement.

btu – British thermal unit, an energy equivalency measure.

DD&A – Depreciation, depletion and amortization.

Developed acreage – The number of acres which are allocated or assignable to producing wells or wells capable of production.

Development well – A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Downstream business – The refining, marketing and transportation (RM&T) operations, spun-off June 30, 2011 and now treated as discontinued operations.

Dry well – A well found to be incapable of producing either oil or natural gas in sufficient quantities to justify completion.

EG – Equatorial Guinea.

EGHoldings – Equatorial Guinea LNG Holdings Limited, an LNG production company located in Equatorial Guinea in which we own a 60 percent equity interest.

E&P – Our Exploration and Production segment which explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis.

EPA – Environmental Protection Agency.

Exit rate – The average daily rate of production from a well or group of wells in the last month of the period stated.

Exploratory well – A well drilled to find oil or gas in an unproved area, find a new reservoir in a field previously found to be productive in another reservoir, or extend a known reservoir.

FASB – Financial Accounting Standards Board.

Farmout – An assignment of an interest in a drilling location and related acreage conditional upon the drilling of a well on that location.

FPSO – Floating production, storage and offloading vessel.

IASB – International Accounting Standards Board.

IFRS – International Financial Reporting Standards.

IG – Our Integrated Gas segment which produces and markets products manufactured from natural gas, such as LNG and methanol, in EG.

IP – Average daily rate of production from a well in the initial 30 days of its operation, which may not be indicative of the rate of future production.

IRS – U.S. Internal Revenue Service.

KRG – Kurdistan Regional Government.

LNG – Liquefied natural gas.

LPG – Liquefied petroleum gas.

Marathon – The consolidated company prior to the June 30, 2011 spin-off of the downstream business.

Marathon Oil – The Company as it exists following the June 30, 2011 spin-off of the downstream business.

Marathon Petroleum Corporation (MPC) – The separate independent company which now owns and operates the downstream business.

mbbl – Thousand barrels.

mbbld – Thousand barrels per day.

mboe – Thousand barrels of oil equivalent.

mboed – Thousand barrels oil equivalent per day.

mcf – Thousand cubic feet.

mmbbl – Million barrels.

mmboe – Million barrels of oil equivalent.

mmbtu – Million British thermal units.

mmcfd – Million cubic feet per day.

mmt – Million metric tonnes.

mtd – Thousand metric tonnes per day.

Net acres or Net wells – The sum of the fractional working interests owned by us in gross acres or gross wells.

OPEC – Organization of Petroleum Exporting Countries.

OSM – Our Oil Sands Mining segment 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.

Productive well – A well that is not a dry well. Productive wells include producing wells and wells that are mechanically capable of production.

Proved reserves – Proved oil, natural gas and synthetic crude oil reserves are those quantities of oil, natural gas and synthetic crude oil, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible.

Proved developed reserves – Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

Proved undeveloped reserves – Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

PSC – Production sharing contract.

Quest CCS – Quest Carbon Capture and Storage project at the AOSP in Alberta, Canada.

Reserve replacement ratio – A ratio which measures the amount of proved reserves added to our reserve base during the year relative to the amount of oil and gas produced.

Royalty interest – An interest in an oil or natural gas property entitling the owner to a share of oil or natural gas production free of costs of production.

SAGE – U.K. Scottish Area Gas Evacuation system composed of a pipeline and processing terminal.

SEC – U.S. Securities and Exchange Commission.

Seismic – An exploration method of sending energy waves or sound waves into the earth and recording the wave reflections to indicate the type, size, shape and depth of subsurface rock formation (3-D seismic provides three-dimensional pictures).

U.K. – United Kingdom.

Undeveloped acreage – Acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

U.S. – United States of America.

U.S. GAAP – Accounting principles generally accepted in the U.S.

Working interest (WI) – The interest in a mineral property which gives the owner that share of production from the property. A working interest owner bears that share of the costs of exploration, development and production in return for a share of production. Working interests are typically burdened by overriding royalty interest or other interests.

WTI – West Texas Intermediate crude oil, an index price.

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, as amended and Section 21E of the Securities Exchange Act of 1934, as amended. 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, 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 or sales of liquid hydrocarbons, natural gas, and synthetic crude oil; levels of worldwide prices of liquid hydrocarbons and natural gas; levels of liquid hydrocarbon, natural gas and synthetic crude oil reserves; 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 incorporated in 2001 and is an international energy company engaged in exploration and production, oil sands mining and integrated gas with operations in the United States, Angola, Canada, Equatorial Guinea, Indonesia, the Iraqi Kurdistan Region, Libya, Norway, Poland and the United Kingdom. We are based in Houston, Texas with our corporate headquarters at 5555 San Felipe Road, Houston, Texas 77056-2723 and a telephone number of (713) 629-6600.

On June 30, 2011, the spin-off of Marathon’s downstream business was completed, creating two independent energy companies: Marathon Oil and MPC. Marathon shareholders at the close of business on the record date of June 27, 2011 received one share of MPC common stock for every two shares of Marathon common stock held. Fractional shares of MPC common stock were not distributed and any fractional share of MPC common stock otherwise issuable to a Marathon shareholder was sold in the open market on such shareholder’s behalf, and such shareholder received a cash payment with respect to that fractional share. A private letter ruling received in June 2011 from the IRS affirmed the tax-free nature of the spin-off. Activities related to the downstream business have been treated as discontinued operations in all periods presented in this Annual Report on Form 10-K, with additional information in Item 8. Financial Statements and Supplementary Data – Note 3 to the consolidated financial statements.

Strategy and Results Summary

Assets within our three segments are at various stages in their lifecycle: base, growth or exploration. We have a stable group of base assets, which include our OSM and IG segments and E&P assets in Norway, Equatorial Guinea, Libya, the U.K. and the U.S. These assets generate much of the cash that will be available for investment in our growth assets and exploration projects. Growth assets are where we expect to make significant investment in order to realize oil and gas production and reserve increases. We are focused on U.S. liquid hydrocarbon growth by developing liquids-rich shale play positions, including most recently the establishment of a strong position in the core of the Eagle Ford shale play. In addition to the U.S. shale plays, growth assets include the development of Angola Block 31, our discoveries in the Iraqi Kurdistan Region, select Gulf of Mexico blocks and our Canadian in-situ assets. Our areas of exploration are Poland, the Iraqi Kurdistan Region, Norway and the Gulf of Mexico. We continually evaluate ways to optimize our portfolio through acquisitions and divestitures, with a previously stated goal of divesting between $1.5 and $3.0 billion of non-core assets between 2011 and 2013. Through January 2012, we closed such transaction having values of $640 million.

We ended 2011 with proved reserves of 1.8 bboe, an 10 percent increase over 2010. Average sales volumes were 219 mbbld of liquid hydrocarbon, 866 mmcfd of natural gas and 43 mbbld of synthetic crude oil, with 66 percent of our liquid hydrocarbon sales volumes from international operations, for which average realizations have exceeded WTI prices. We invested in the development of assets in all our segments, totaling $3.4 billion in capital expenditures related to continuing operations for the year, with $3 billion related to our E&P segment. We expect continued capital expenditures, primarily funded with cash flow from operations, in exploration and development activities in order to realize continued reserve and sales growth. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Outlook, for discussion of our $4.8 billion capital spending budget for 2012.

The above discussion of strategy and results includes forward-looking statements with respect to the goal of divesting between $1.5 and $3.0 billion of non-core assets between 2011 and 2013 and expected investment in exploration and development activities. Some factors that could potentially affect the divestiture of non-core assets and expected investment in exploration and development activities include changes in prices of and demand for liquid hydrocarbons and natural gas, actions of competitors, occurrence of acquisitions or dispositions of oil and natural gas properties, future financial condition and operating results, and economic, and/or regulatory factors affecting our businesses, the identification of buyers and the negotiation of acceptable prices and other terms, as well as other customary closing conditions. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

The map below illustrates the locations of our worldwide operations.

LOGO

Segment and Geographic Information

For operating segment and geographic financial information, see Item 8. Financial Statements and Supplementary Data – Note 8 to the consolidated financial statements.

Exploration and Production Segment

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

We are engaged in oil and gas exploration, development and/or production activities in the United States, Angola, Canada, Equatorial Guinea, Indonesia, the Iraqi Kurdistan Region, Libya, Norway, Poland, and the United Kingdom.

Liquids-Rich Shale Plays

Eagle Ford – In the fourth quarter of 2011, we closed several acquisitions in the Eagle Ford shale play of south Texas for a total cash consideration of $4.5 billion. See Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements for additional information about these acquisitions.

Upon finalization of the 2011 Eagle Ford acquisition transactions, we will have just over 300,000 net acres in the Eagle Ford shale with an average working interest of approximately 80 percent. As of December 31, 2011, we had 14 operated drilling rigs active in the play, with plans to increase to 18 drilling rigs and 4 dedicated hydraulic fracturing crews by the end of 2012. Our plans include drilling and completing 200 – 230 gross (160 – 185 net) operated wells in 2012.

Including the impact of our fourth quarter 2011 acquisitions, annual net sales for 2011 were 2 mboed, with a December exit rate of 13 mboed. Our production from the Eagle Ford shale is either sold at the lease or moved via truck or pipeline to markets. We own and operate the Sugarloaf gathering system, a 42-mile natural gas pipeline through the heart of our recently purchased acreage in Karnes, Atascosa, and Bee Counties of south Texas. Our future production estimates will require additional markets, transportation, storage and plant processing to be either contracted or constructed and a variety of negotiations are underway with a goal of continued access to adequate infrastructure and markets. Key considerations in this development will be the timing of contract availability and efforts to receive optimal price based upon delivery location.

Bakken – We hold just over 400,000 net acres in the Bakken shale oil play in the Williston Basin of North Dakota and eastern Montana with an average working interest in the acreage of approximately 80 percent. Throughout 2011, we continued selective acreage acquisitions and leasing, adding approximately 40,000 net acres which expanded to a new prospect area. In 2011 we drilled 61 gross (55 net) operated wells and completed 71 gross (63 net) operated wells. We also moved from 20-stage to 30-stage hydraulic fracturing, which increases both production rates and estimated ultimate recovery from the wells. At December 31, 2011, we had 7 operated drilling rigs and 2 dedicated hydraulic fracturing crews in our Bakken shale program, and expect to add one more rig in 2012 to accomplish plans to drill 69 gross (53 net) and complete 72 – 84 gross (53 – 61 net) operated wells in 2012.

Our net sales from the Bakken shale averaged 17 mboed in 2011, a 36 percent increase over 2010, and our production exit rate for 2011 was 24 mboed. We sell our Bakken production into local markets predominately via trucking. A variety of negotiations are underway to provide adequate infrastructure and markets for our future estimated production levels, including the potential export of volumes from the regional markets via pipeline or rail projects.

Anadarko Woodford – In the Anadarko Woodford shale play in Oklahoma, we hold 160,000 net acres of which approximately 100,000 acres are held by production. In 2011, we executed an operated drilling program focused on the liquids-rich areas of the play, drilling 15 gross (11 net) exploration and 8 gross (6 net) development wells, of which 11 gross (9 net) wells were completed.

The Shi Randall well, in which we hold a 50 percent working interest, was completed in the third quarter of 2011. The Shi Randall had a gross IP of 455 bbld of liquid hydrocarbons and 6 mmcfd of natural gas, subject to pipeline constraints. It was one of the initial wells in the Knox area (southern Woodford) and is helping to prove up a prospective area where we have a strong acreage position.

The Anadarko Woodford shale averaged net sales of 2 mboed during 2011. In 2012, we plan to maintain our current level of 6 rigs and drill 35 – 40 gross (19 – 22 net) operated wells with more focus on development drilling. Outside-operated projects could add an additional 30 – 50 gross (6 – 10 net) wells. See below for additional discussion of our conventional, primarily natural gas production operations in Oklahoma.

DJ Basin – In 2010, we began leasing in the Niobrara play in the DJ Basin of northern Colorado and southeast Wyoming and built an acreage position of approximately 180,000 acres. In April 2011, we farmed-out a 30 percent undivided working interest retaining 70 percent and operatorship. See Item 8. Financial Statements and Supplementary Data – Note 6 to the consolidated financial statements for additional information regarding this transaction. As of December 31, 2011 we hold 151,000 net acres. In 2011, we drilled a total of 12 gross (7 net) operated wells, with four gross (two net) operated wells completed. We are currently operating 2 drilling rigs in the DJ Basin and expect to drill 25 – 35 gross (13 – 19 net) operated wells in 2012. Outside-operated projects could add an additional 25 – 35 gross (4 – 5 net) wells. We exited December with a net production rate of 86 boed. We have other natural gas assets in Colorado which are discussed below.

United States

Alaska – We produce natural gas in the Cook Inlet and adjacent Kenai Peninsula of Alaska where we have operated and outside-operated interests in 10 fields covering 118,000 net acres. In 2011, we drilled 1 operated well in the Ninilchik field and participated in 1 non-operated horizontal well in the McArthur River field, both in the Cook Inlet. Plans for 2012 include continued investments in production optimization and operational reliability.

Net natural gas sales from Alaska averaged 94 mmcfd in 2011. 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.

Complementing our production operations in Alaska is our majority ownership in four operated natural gas pipelines totaling 140 miles. These are bidirectional systems providing transportation from multiple producers to numerous end users in and around the Cook Inlet.

Colorado – We hold leases of 8,700 net acres with natural gas production in the Piceance Basin of Colorado, located in the Greater Grand Valley field complex, with net sales of 20 mmcfd in 2011. Currently the field has 77 gross/net wells producing.

Oklahoma – We have long-established operated and non-operated conventional production operations in several Oklahoma fields from which 2011 sales averaged 2 mbbld of liquid hydrocarbons and 53 mmcfd of natural gas. In 2011 we participated in 7 gross (2 net), non-operated wells in the state. We also drilled 1 company operated well. Plans for 2012 include 11 gross (2 net) wells, targeting liquids.

Texas/North Louisiana/New Mexico – In east Texas and north Louisiana, we hold 184,000 net acres. Approximately 20,000 of the acres are in the Haynesville and Bossier natural gas shale plays. Most of the acreage in these shale plays is held by production. We participated in 3 gross (1 net) non-operated wells in the area during 2011. Conventional production was primarily from the Mimms Creek, Pearwood and Oletha fields, in 2011. Net sales from east Texas and north Louisiana averaged 7 mboed.

We also participate in several outside-operated Permian Basin fields in west Texas and New Mexico. Net sales from this area were 7 mboed in 2011. Activity in 2012 will center around carbon dioxide flood programs in the Seminole and Vacuum fields.

Wyoming – We hold 260,000 net acres in Wyoming and have almost 100 years of exploration and development in the state. We have ongoing enhanced oil recovery projects at the mature Bighorn Basin and Wind River Basin fields and initiated an additional enhanced recovery project at our 100 percent owned and operated Pitchfork field in 2011. We have conventional natural gas operations in the Greater Green River Basin and unconventional coal bed natural gas operations in the Powder River Basin. In 2011, we drilled 17 gross (17 net) operated development wells in Wyoming, which included five wellbore re-entries and plan 3 – 4 gross (3 – 4 net) operated wells in 2012. Our Wyoming sales averaged 17 mbbld of liquid hydrocarbons and 75 mmcfd of natural gas during 2011. In addition, we own and operate the 420-mile Red Butte Pipeline. This crude oil pipeline connects Silvertip Station on the Montana/Wyoming state line to Casper, Wyoming.

West Virginia/Pennsylvania – In the Appalachian Basin we hold 82,000 net acres in the Marcellus shale natural gas play in Pennsylvania and West Virginia. In February 2011, we entered into a joint venture on a large portion of our Marcellus shale acreage position. Under the agreement which ends in 2012, our joint venture partner will earn 50 percent of approximately 60,000 acres under a drilling carry and has an option to acquire our remaining acreage while we retain the rights to continue to market the acreage to others. In 2011, 2 gross (1 net) outside-operated wells were drilled with 1 gross (0.5 net) well awaiting completion. We expect to participate in 4 gross (2 net) wells in 2012.

Gulf of Mexico – Production

On December 31, 2011, we held material interests in seven producing fields, four of which are company-operated.

We operate and have a 65 percent working interest in the Ewing Bank Block 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 on Ewing Bank blocks 873, 917 and 963. The facility also processes third-party production via subsea tie-backs.

We own a 50 percent working interest in the outside-operated Petronius field on Viosca Knoll Blocks 786 and 830 located 130 miles southeast of New Orleans, which includes six producing wells. The Petronius platform is capable of providing processing and transportation services to nearby third-party fields. During 2012, we plan to acquire seismic data in order to identify future drilling opportunities.

We hold a 30 percent working interest in the outside-operated Neptune field located on Atwater Valley Block 575, 120 miles off the coast of Louisiana. The development includes seven subsea wells tied back to a stand-alone platform. Additional drilling and recompletion activity is being considered for 2012.

We have a 100 percent operated working interest and an 81 percent net revenue interest in the Droshky development located on Green Canyon Block 244 off the coast of Louisiana. This development began production in mid-July of 2010 and reached peak net production of 45 mboed in the third quarter of 2010. The field will be produced to abandonment pressures which are expected to be reached in the first half of 2012.

We hold a 68 percent working interest in Ozona. Development of our operated Ozona prospect, located on Garden Banks Block 515, was delayed by the Drilling Moratorium (discussed below) and subsequent regulatory changes. In 2011, we completed the Ozona well as a single zone producer tied back to a non-operated host platform. First production began in late December 2011.

Average net sales for 2011 from the Gulf of Mexico were 30 mbbld of liquid hydrocarbons and 24 mmcfd of natural gas.

We also own a 34 percent outside-operated interest in the Neptune gas plant located onshore Louisiana. This high efficiency gas plant, which services four high pressure offshore and onshore pipelines, has a 650 mmcfd capacity.

Gulf of Mexico – Exploration

We have 21 prospects, 16 of which are operated in the Gulf of Mexico. As a result of an explosion and significant spill from a deepwater rig in the Gulf of Mexico, the U.S. Department of the Interior issued a drilling moratorium on May 30, 2010 (“Drilling Moratorium”), to suspend the drilling of deepwater wells, and prohibit drilling any new deepwater wells

(defined as greater than 500 foot water depth). The Drilling Moratorium was lifted on October 12, 2010. Our first exploration plan approval was received in August 2011. In 2011, we received lease extensions for 26 blocks in the Gulf of Mexico which had been impacted by the Drilling Moratorium.

A successful deepwater oil discovery well was drilled on the Gunflint prospect located on Mississippi Canyon Block 948, 160 miles southeast of New Orleans in 2008. We own a 15.25 percent interest in this outside-operated prospect. Gunflint prospect appraisal wells were subject to the Drilling Moratorium. Drilling of the first appraisal well began in December 2011, and a second appraisal well is planned for mid-year 2012.

In the first quarter of 2009, we participated in a deepwater oil discovery on the Shenandoah prospect located on Walker Ridge Block 52. We own a 10 percent interest in this outside-operated prospect. The first appraisal well is planned for mid-year 2012.

In March 2011, we completed our evaluation of the Flying Dutchman exploratory well, located on Green Canyon Block 511. We determined that the options to develop were not viable and all well costs have been expensed.

In accordance with the federal government’s Drilling Moratorium, we temporarily suspended drilling an exploratory well on the Innsbruck prospect located on Mississippi Canyon Block 993 at a depth of 19,800 feet as compared to a proposed total depth of 29,500 feet. In 2011, we received approval for our current exploration plan from the BOEMRE. We have contracted a rig for this project and drilling is expected to commence in the third quarter of 2012. In December 2011, we assigned a 40 percent interest in the portion of Mississippi Canyon Block 993 that includes Innsbruck, in exchange for a 30 percent non-operated interest in Green Canyon Blocks 403 and 404 in the Kilchurn prospect plus reimbursement of certain well costs incurred to date on Innsbruck. We now have a 45 percent working interest in Innsbruck and continue to operate the prospect. The operator commenced drilling on the Kilchurn prospect in December 2011.

In October 2011, we received approval of an exploration plan from the BOEMRE for the Key Largo prospect located on Walker Ridge Block 578. We have a 60 percent working interest and are the operator of this prospect. Drilling is expected in the second half of 2012.

Africa

Equatorial Guinea – We own a 63 percent operated working interest under a PSC in the Alba field which is offshore EG. During 2011, EG net liquid hydrocarbon sales averaged 38 mbbld, and net natural gas sales were 443 mmcfd. Planned maintenance in EG is scheduled for a 28-day period from late first quarter through early second quarter 2012, with operations expected to be completely shut down for eight of those days.

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

We also own a 52 percent interest in Alba Plant LLC, an equity method investee that operates an onshore LPG processing plant located on Bioko Island. Alba field natural gas is processed by the LPG plant. Under a long-term contract at a fixed price per btu, the LPG plant extracts secondary condensate and LPG from the natural gas stream and uses the natural gas in its operations. During 2011, a gross 890 mmcfd of natural gas was supplied to the LPG production facility and 4 mbbld of secondary condensate and 11 mbbld of LPG were produced by Alba Plant LLC. 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.

As part of our Integrated Gas segment, we own 45 percent of AMPCO and 60 percent of EGHoldings, both of which are accounted for as equity method investments. AMPCO operates a methanol plant and EGHoldings operates an LNG production facility, both located on Bioko Island. Dry natural gas from the Alba field, which remains after the condensate and LPG are removed by Alba Plant LLC, 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 methanol produced by AMPCO and LNG produced by EGHoldings is reflected in our Integrated Gas segment as discussed below. During 2011, a gross 127 mmcfd of dry natural gas was supplied to the methanol plant and a gross 668 mmcfd of dry gas was supplied to the LNG production facility. Any remaining dry gas is returned offshore and reinjected into the Alba field for later production.

Libya – Civil unrest, which began in February 2011 in parts of North Africa, escalated to armed conflict in Libya where we hold a 16 percent working interest in the Waha concessions, which encompass almost 13 million acres located in the Sirte Basin of eastern Libya. During the first quarter 2011, all production operations in Libya were suspended. In the

fourth quarter of 2011, limited production resumed from the Waha concessions, but we made no deliveries of hydrocarbons. In January 2012, Libya produced 190 gross mbbld (25 net mbbld), and sales are planned to resume in the first quarter of 2012. The return of our operations in Libya to pre-conflict levels is unknown at this time; however, we and our partners in the Waha concessions are assessing the condition of our assets and determining when the full resumption of operations will be viable.

Angola – Offshore Angola, we hold 10 percent working interests in Blocks 31 and 32, both of which are outside-operated. The discoveries on Blocks 31 and 32 represent several potential development hubs. In 2008, we received approval to proceed with the first deepwater development project, called the PSVM development, which includes the Plutao, Saturno, Venus and Marte discoveries and one successful appraisal well in the northeastern portion of Block 31. The PSVM development will utilize an FPSO with a total of 48 production and injection wells. Development drilling began in 2010 and first production is anticipated in mid-2012. The potential for a second development hub on this block is being evaluated. Studies are underway to establish a development in the eastern part of Block 32 and to assess the development potential of the other discoveries. We anticipate at least one development on Block 32.

Europe

Norway – We operate 10 licenses and hold interests in over 249,000 net acres on the offshore Norwegian continental shelf. In 2011, net sales from Norway averaged 80 mbbld of liquid hydrocarbons and 42 mmcfd of gas.

The Alvheim development 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. It is produced to the Alvheim complex which consists of an FPSO with subsea infrastructure. In 2011, due to debottlenecking efforts, capacity of the FPSO increased to 86 mbbld net (149 mbbld gross). Produced oil is transported by shuttle tanker and produced natural gas is transported to the SAGE system by pipeline. At the end of 2011, the Alvheim development included 13 producing wells and two water disposal wells. An additional development well is planned in 2012.

The nearby outside-operated Vilje field, in which we own a 47 percent working interest, began producing through the Alvheim complex in August 2008. At the end of 2011, two wells were producing and an additional development, Vilje Sor had been approved. Production from Vilje Sor is estimated to begin near the end of 2013.

The Volund field, five miles south of the Alvheim FPSO was the second subsea development tied back to the Alvheim complex. The Volund development, in which we own a 65 percent operated working interest, consists of three production wells and one water injection well. First production from Volund was announced in September 2009. It initially functioned as a swing producer to allow us to maintain full capacity on the Alvheim FPSO until the second quarter of 2010 when we commenced full production. Drilling of an additional development well at Volund is planned for fourth quarter 2012, with first production scheduled in early 2013.

Also offshore Norway, are the Boyla (formerly Marihone) and Viper discoveries in which we hold a 65 percent operated working interest. The Boyla oil discovery is located in license PL340 about 12 miles south of the Volund and Alvheim fields. The Viper oil discovery is located in license PL203, immediately next to the Volund field in license PL150. Both discoveries are being evaluated for possible tie back to the Alvheim complex. An investment decision on Boyla could occur in the second quarter of 2012, with first production estimated to begin in the fourth quarter of 2014.

Exploration activities will continue in 2012 and 2013. The Velsemøy well is expected to begin drilling late in 2012 in license PL531 where we hold a 10 percent carried working interest. Drilling is expected to commence in the first quarter of 2013 on the Sverdrup well in license PL 330 where we hold a 30 percent operated working interest.

United Kingdom – Net sales from the U.K. averaged 21 mbbld of liquid hydrocarbons and 55 mmcfd of natural gas. 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 39 percent working interest in the East Brae field. The Brae Alpha platform and facilities host the South, Central and West Brae fields. The North Brae field, which is produced via the Brae Bravo platform, and the East Brae field, which is produced via the East Brae platform, are natural gas condensate fields. The East Brae platform also hosts the nearby Braemar field in which we have a 28 percent working interest. Two development wells were completed at West Brae in early 2011 and we continue to pursue Brae complex projects designed to maximize natural gas recovery and maintain deliverability rates to the U.K. market.

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 twenty-five third-party fields are contracted to use the Brae system and 73 mboed are being processed or transported through the Brae infrastructure. In 2011, we installed a new module to accommodate the tie back of the third-party operated Devenick field. In addition to generating processing and pipeline tariff revenue, this third-party business optimizes infrastructure usage.

The Brae group owns a 50 percent interest in the outside-operated SAGE system. The SAGE pipeline transports natural gas from the Brae area, and the third-party Beryl area, and has a total wet natural gas capacity of 1.1 bcf per day. The SAGE terminal at St. Fergus in northeast Scotland processes natural gas from the SAGE pipeline as well as approximately 1 bcf per day of third-party natural gas.

In the U.K. Atlantic Margin west of the Shetland Islands, we own an average 30 percent working interest in the outside-operated Foinaven area complex, consisting of a 28 percent working interest in the main Foinaven field, 47 percent working interest in East Foinaven and 20 percent working interest in the T35 and T25 fields. The export of Foinaven liquid hydrocarbons is via shuttle tanker from the FPSO to market. All natural gas sales are to the non-operated Magnus platform for use as injection gas. An upgrade of equipment on the FPSO is expected to extend the life of the fields through 2021. Additionally, the planned installation of replacement flowlines should secure the long-term integrity of the subsea infrastructure, but the related downtime is expected to cause a reduction in sales volumes in 2012. Average net sales from Foinaven were 12 mboed in 2011.

Poland – Between December 2009 and October 2010, we acquired eleven 5-year licenses, totaling 2.3 million gross acres. In 2011, we farmed-out to two companies an aggregate 49 percent undivided interest in ten of these licenses which will be earned through drilling. As of December 31, 2011, we hold a 51 percent working interest in these 10 concessions, a 100 percent interest in the remaining concession for a total of 1.2 million net acres. We are operator under all licenses. We are in the early stages of exploring and evaluating the full potential of these holdings. We drilled, cored and logged our first vertical exploratory well in late 2011 and are evaluating the data. In addition, we expect to complete proprietary 2-D seismic acquisitions in the first quarter of 2012. We have a drilling commitment of one well per license and plan to drill 6 – 7 gross (3 – 4 net) exploration wells in 2012.

Canada

We hold interests in both operated and outside-operated exploration stage oil sand leases in Alberta, Canada, which would be developed using in-situ methods of extraction. These leases cover approximately 143,000 gross acres (52,000 net) in four project areas: Namur, in which we hold a 60 percent operated interest; Birchwood, in which we hold a 100 percent operated interest; Ells River, in which we hold a 20 percent outside-operated interest and Saleski in which we hold a 33 percent outside-operated interest. Exploration on the Birchwood prospect continued in the winter of 2011-2012 with a seismic program and water well drilling. Approximately 100 stratigraphic test wells were drilled on the Birchwood prospect in the winter of 2010-2011 providing data for the ongoing assessment of reservoir quality. We expect sanction of a pilot project in 2013.

Other International

Iraqi Kurdistan Region – In October 2010, we acquired a position in four exploration blocks in the Iraqi Kurdistan Region. In aggregate, these contracts provide us with access to approximately 368,000 net acres. We signed PSCs for operatorship and 80 percent ownership in the Harir and Safen blocks northeast of Erbil. The KRG holds a 20 percent carried interest in these blocks. We have committed to a seismic program and to drilling one well on both Hafir and Safen during the initial three-year exploration period. We were assigned interests in two additional outside-operated blocks located north-northwest of Erbil: Atrush, in which we have a 16 percent ownership (the KRG holds a 4 percent carried interest), and Sarsang, in which we have a 20 percent interest (the KRG holds a 5 percent carried interest). In 2011, we announced the Atrush-1 discovery on the Atrush block and a second discovery, the Swara Tika-1 well on the Sarsang block. The Swara Tika-2, an appraisal well on the Sarsang block, commenced drilling in the fourth quarter of 2011. The Atrush-2, an appraisal well on the Atrush block, is planned for 2012. Planning is underway on extended well testing and early production systems, with first production expected in the fourth quarter of 2012.

Indonesia – We are the operator of three exploration licenses in Indonesia: the Pasangkayu block with a 70 percent interest, the Kumawa block with a 55 percent interest, and the Bone Bay block with a 55 percent interest. In 2011 and 2010, wells were drilled on the Bravo and Romeo prospects in the Pasangkayu block. These wells were expensed as dry holes. We have notified our joint venture partner and the Indonesian government that we intend to relinquish the PSC on the Pasangkayu block. Discussions continue and we are awaiting a government response. We are evaluating the Bone Bay and Kumawa blocks.

Acquisitions and Dispositions

As previously discussed, during 2011 we closed several acquisition transactions in the Eagle Ford shale play and farmed-out minority interests in our DJ Basin and Poland acreage. Also, in March 2011, we closed the sale of our outside-operated interests in the Gudrun field development and the Brynhild and Eirin exploration areas offshore Norway.

In October 2011, we entered into definitive agreements to sell our equity method interests in Poseidon Oil Pipeline Company, L.L.C. and Odyssey Pipeline L.L.C. and certain other oil pipeline interests including the Eugene Island Pipeline System. The transaction closed on January 3, 2012.

In December 2011 we sold our 25 percent interest in the Stones prospect located on Walker Ridge Block 508 to the operator. We also exchanged a 100 percent interest in Atwater Valley Block 398 in the Sandpiper prospect, for a 100 percent interest in Walker Ridge Block 577 in the Key Largo prospect and a 20 percent interest in Green Canyon Block 286 in the Hypnos prospect. After this transaction, we hold a 50 percent interest in Green Canyon Block 286 and a 100 percent interest in Walker Ridge Block 577.

See Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements for additional information about the acquisitions and Note 6 for additional information about the farm-outs and divestitures.

The above discussion of the E&P segment includes forward-looking statements with respect to anticipated future exploratory and development drilling activity, drilling rig activity in the U.S., planned maintenance downtime, timing of reaching abandonment pressures in Droshky, continued investments in Alaska, timing of first production from Vilje Sor, Boyla and Kurdistan, planned acquisition of seismic data for Petronius, plans to achieve first production from the PSVM development on Block 31 offshore Angola and other possible developments, plans to resume sales in Libya and the expected extension of the Foinaven fields. Some factors which could possibly 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. Predicted planned maintenance and FPSO downtime are good faith estimates and preliminary, and therefore, subject to change. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Productive and Drilling Wells

For our E&P segment, the following tables set forth gross and net productive wells and service wells as of December 31, 2011, 2010 and 2009 and drilling wells as of December 31, 2011.


	Productive Wells^(a)
	Oil				Natural Gas				Service Wells				Drilling Wells
	Gross		Net		Gross		Net		Gross		Net		Gross		Net
2011
United States		5,809		2,058		3,121		1,876		2,313		734		55		28

Equatorial Guinea		-		-		14		9		4		3		-		-
Other Africa^(b)		-		-		-		-		1		-		-		-

Total Africa		-		-		14		9		5		3		-		-
Total Europe		73		31		40		16		28		10		2		1
Total Other International		-		-		-		-		-		-		1		-

Worldwide		5,882		2,089		3,175		1,901		2,346		747		58		29

2010
United States		4,818		1,860		3,145		1,905		2,466		746

Equatorial Guinea		-		-		13		9		5		3
Other Africa		1,022		168		3		-		94		16

Total Africa		1,022		168		16		9		99		19
Total Europe		71		30		40		16		29		11

Worldwide		5,911		2,058		3,201		1,930		2,594		776

2009
United States		4,806		1,788		5,158		3,569		2,447		734

Equatorial Guinea		-		-		13		9		5		3
Other Africa		976		160		-		-		91		15

Total Africa		976		160		13		9		96		18
Total Europe		67		27		44		18		27		10

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

^(a)	Of the gross productive wells, wells with multiple completions operated by us totaled 168, 164 and 170 as of December 31, 2011, 2010 and 2009. Information on wells with multiple completions operated by others is unavailable to us.

^(b)	As operations were resuming in Libya at December 31, 2011, an accurate count of productive wells was not possible; therefore no Libyan wells are included in this number. Production from Libya at December 31, 2011 was approximately 30 percent of the 45 mboed pre-conflict level.

Drilling Activity

For our E&P segment, the following table sets forth, by geographic area, the number of net productive and dry development and exploratory wells completed in each of the last three years.


	Development								Exploratory								Total
	Oil		Natural Gas		Dry		Total		Oil		Natural Gas		Dry		Total
2011
United States		46		17		3		66		37		4		1		42		108
Total Africa^(a)		2		-		-		2		-		-		-		-		2
Total Europe		2		-		-		2		-		-		-		-		2
Total Other International		-		-		-		-		-		-		1		1		1

Worldwide		50		17		2		70		37		4		2		43		113
2010
United States		35		46		1		82		20		11		3		34		116
Total Africa		5		-		-		5		1		-		-		1		6
Total Europe		2		-		-		2		-		-		-		-		2
Total Other International		-		-		-		-		1		-		1		2		2

Worldwide		42		46		1		89		22		11		4		37		126
2009
United States		11		54		2		67		37		9		2		48		115
Total Africa		5		1		-		6		-		-		-		-		6
Total Europe		1		-		-		1		1		-		-		1		2

Worldwide		17		55		2		74		38		9		2		49		123

^(a)	Activity in Libya through February 2011.

Acreage

We believe we have satisfactory title to our properties in accordance with standards generally accepted in the industry; nevertheless, we can be involved in title disputes from time to time which may result in litigation. In the case of undeveloped properties, an investigation of record title is made at the time of acquisition. Drilling title opinions are usually prepared before commencement of drilling operations. Our title to properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other similar interests and contractual arrangements customary in the industry. In addition, our interests may be subject to obligations or duties under applicable laws or burdens such as net profits interests, liens related to operating agreements, development obligations or capital commitments under international PSCs or exploration licenses.

The following table sets forth, by geographic area, the gross and net developed and undeveloped exploration and production acreage held in our E&P segment as of December 31, 2011.


	Developed				Undeveloped				Developed and Undeveloped
(In thousands)	Gross		Net		Gross		Net		Gross		Net
United States		1,620		1,215		1,449		1,143		3,069		2,358
Canada		-		-		143		55		143		55

Total North America		1,620		1,215		1,592		1,198		3,212		2,413
Equatorial Guinea		45		29		92		69		137		98
Other Africa		12,909		2,108		2,580		258		15,489		2,366

Total Africa		12,954		2,137		2,672		327		15,626		2,464
Total Europe		131		68		3,173		1,449		3,304		1,517
Other International		-		-		3,985		2,334		3,985		2,334

Worldwide		14,705		3,420		11,422		5,308		26,127		8,728

Of the 5.3 million net undeveloped acres held at December 31, 2011, 15 percent, 9 percent and 20 percent of those acres are under agreements scheduled to expire in the years 2012, 2013, and 2014.

Marketing Activities

Our E&P segment includes activities related to the marketing and transportation of substantially all of our liquid hydrocarbon and natural gas production. These activities include the transportation of production to market centers, the sale of commodities to third parties and storage of production. We balance our various sales, storage and transportation positions through what we call supply optimization, which can include the purchase of commodities from third parties for resale. Supply optimization serves to aggregate volumes in order to satisfy transportation commitments thereby optimizing transportation capacity and value and to achieve flexibility within product types and delivery points.

Oil Sands Mining Segment

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. The AOSP’s mining and extraction assets are located near Fort McMurray, Alberta and include the Muskeg River and the Jackpine mines. Gross design capacity of the combined mines is 255,000 (51,000 net to our interest) barrels of bitumen per day. As of December 31, 2011, we own or have rights to participate in developed and undeveloped leases totaling approximately 216,000 gross (43,000 net) acres. The underlying developed leases are held for the duration of the project, with royalties payable to the province of Alberta. The upgrading assets are located at Fort Saskatchewan, northeast of Edmonton, Alberta.

The five year AOSP Expansion 1 was completed in 2011. The Jackpine mine commenced production under a phased start-up in the third quarter of 2010 and began supplying oil sands ore to the base processing facility in the fourth quarter of 2010. The upgrader expansion was completed and commenced operations in the second quarter of 2011. Synthetic crude oil sales volumes for 2011 were 43 mbbld, with production of 38 mbbld. Phase one of debottlenecking opportunities was approved in 2011 and potential future expansions and additional debottlenecking opportunities remain under review.

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 upgrader produces 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.

As announced in the second quarter of 2011, the governments of Alberta and Canada have agreed to partially fund Quest CCS for 865 million Canadian dollars. Financing would be received over a period of 15 years, including development, construction and 10 years of operations. However, the funding is subject to conditions of achieving certain performance objectives. We expect a final investment decision on this project in 2012.

The above discussions include forward-looking statements with respect to Quest CCS. Some factors that could potentially affect these forward-looking statements include projected costs and satisfaction of remaining conditions necessary for final investment decision. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Reserves

Estimated Reserve Quantities

The following table sets forth estimated quantities of our net proved liquid hydrocarbon, natural gas and synthetic crude oil reserves based upon an unweighted average of closing prices for the first day of each month in the 12-month periods ended December 31, 2011, 2010 and 2009. Approximately 65 percent of our proved reserves are located in Organization for Economic Cooperation and Development (“OECD”) countries.

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


	North America						Africa						Europe
December 31, 2011	United States		Canada		Total		EG		Other		Total		Total		Grand Total
Proved Developed Reserves
Liquid hydrocarbons (mmbbl)		141		-		141		78		179		257		84		482
Natural gas (bcf)		551		-		551		1,104		104		1,208		40		1,799
Synthetic crude oil (mmbbl)		-		623		623		-		-		-		-		623
Total proved developed reserves (mmboe)		233		623		856		262		196		458		91		1,405
Proved Undeveloped Reserves
Liquid hydrocarbons (mmbbl)		138		-		138		39		61		100		13		251
Natural gas (bcf)		321		-		321		467		-		467		79		867
Total proved undeveloped reserves (mmboe)		191		-		191		117		61		178		26		395
Total Proved Reserves
Liquid hydrocarbons (mmbbl)		279		-		279		117		240		357		97		733
Natural gas (bcf)		872		-		872		1,571		104		1,675		119		2,666
Synthetic crude oil (mmbbl)		-		623		623		-		-		-		-		623
Total proved reserves (mmboe)		424		623		1,047		379		257		636		117		1,800


	North America						Africa						Europe
December 31, 2010	United States		Canada		Total		EG		Other		Total		Total		Grand Total
Proved Developed Reserves
Liquid hydrocarbons (mmbbl)		124		-		124		86		180		266		89		479
Natural gas (bcf)		591		-		591		1,186		104		1,290		43		1,924
Synthetic crude oil (mmbbl)		-		433		433		-		-		-		-		433
Total proved developed reserves (mmboe)		222		433		655		284		198		482		96		1,233
Proved Undeveloped Reserves
Liquid hydrocarbons (mmbbl)		49		-		49		33		59		92		10		151
Natural gas (bcf)		154		-		154		465		1		466		73		693
Synthetic crude oil (mmbbl)		-		139		139		-		-		-		-		139
Total proved undeveloped reserves (mmboe)		75		139		214		110		59		169		22		405
Total Proved Reserves
Liquid hydrocarbons (mmbbl)		173		-		173		119		239		358		99		630
Natural gas (bcf)		745		-		745		1,651		105		1,756		116		2,617
Synthetic crude oil (mmbbl)		-		572		572		-		-		-		-		572
Total proved reserves (mmboe)		297		572		869		394		257		651		118		1,638


	North America						Africa						Europe
December 31, 2009	United States		Canada		Total		EG		Other		Total		Total		Grand Total
Proved Developed Reserves
Liquid hydrocarbons (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 hydrocarbons (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 hydrocarbons (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 significant increase in proved reserves from 2010 to 2011 was primarily due to the Eagle Ford shale acquisitions. Also, synthetic crude oil reserves increased, primarily because of the inclusion of additional lease portions in the Jackpine mine and technical and economic reevaluations at year end.

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

Preparation of Reserve Estimates

Our estimation of economically producible volumes of liquid hydrocarbons and natural gas is a highly technical process performed primarily by in-house teams of reservoir engineers and geoscience professionals. All estimates of reserves are made in compliance with SEC Rule 4-10 of Regulation S-X. Liquid hydrocarbon, natural gas and synthetic crude oil reserve estimates are reviewed and approved by our Corporate Reserves Group, which includes our Director of Corporate Reserves and her staff of Coordinators. Reserve estimates are developed and reviewed by Qualified Reserve Estimators (“QRE”). QREs are engineers or geoscientists with a minimum of a Bachelor of Science degree in the appropriate technical field, have a minimum of three years of industry experience with at least one year in reserve estimation and have completed Marathon Oil’s Qualified Reserve Estimator training course. The Reserve Coordinators review all reserve estimates for all fields with proved reserves greater than 3 mmboe at a minimum of once every three years. Any change to proved reserve estimates in excess of 2.5 mmboe on a total field basis, within a single month, must be approved by Corporate Reserves Group management. All other proved reserve changes must be approved by a Reserve Coordinator.

Our Director of Corporate Reserves, who reports to our Chief Financial Officer, has a Bachelor of Science degree in petroleum engineering and a Master of Business Administration. Her 37 years of experience in the industry include 26 with Marathon Oil. She is active in industry and professional groups, having served on the Society of Petroleum Engineers (“SPE”) Oil and Gas Reserves Committee (“OGRC”), chairing in 2008 and 2009. As a member of the OGRC, she participated in the development of the Petroleum Resource Management System. 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. Their reports for all years are filed as exhibits to this Annual Report on Form 10-K. The engineer responsible

for the estimates of our oil sands mining reserves has 33 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 from 1998 through 2001 and is a registered Practicing Professional Engineer in the Province of Alberta.

Audits of Estimates

Third-party consultants are engaged to provide independent estimates for fields that comprise 80 percent of our total proved reserves over a rolling four-year period for the purpose of auditing the in-house reserve estimates. We met this goal for the four-year period ended December 31, 2011. We established a tolerance level of 10 percent 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 2011 or 2009. There were no third-party audits performed in 2010.

During 2011, Netherland, Sewell & Associates, Inc. (“NSAI”) prepared a Certification of December 31, 2010 reserves for the Alba field in Equatorial Guinea. The NSAI summary report is filed as an exhibit to this Annual Report on Form 10-K. The senior members of the NSAI team have over 50 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 degree 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 2011 and 2009. Their summary report on audits performed in 2011 is filed as an exhibit to this Annual Report on Form 10-K. The team lead for Ryder Scott has over 20 years of industry experience, having worked for a major international oil and gas company before joining Ryder Scott. He has a Bachelor of Science degree in mechanical engineering, is a member of SPE and is a registered Professional Engineer in the state of Texas.

The Corporate Reserves Group also performs separate, detailed technical reviews of reserve estimates for significant fields that were acquired recently or for properties with other indicators such as excessively short or long lives, performance above or below expectations or changes in economic or operating conditions.

Changes in Proved Undeveloped Reserves

As of December 31, 2011, 395 mmboe of proved undeveloped reserves were reported, a decrease of 10 mmboe from December 31, 2010. The following table shows changes in total proved undeveloped reserves for 2011:


Beginning of year	405
Revisions of previous estimates	15
Improved recovery	1
Purchases of reserves in place	91
Extensions, discoveries, and other additions	49
Transfer to Proved Developed	(166	)

End of year	395

Significant additions to proved undeveloped reserves during 2011 include 91 mmboe due to acreage acquisition in the Eagle Ford shale, 26 mmboe related to Anadarko Woodford shale development, 10 mmboe for development drilling in the Bakken shale play and 8 mmboe for additional drilling in Norway. Additionally, 139 mmboe were transferred from proved undeveloped to proved developed reserves due to startup of the Jackpine upgrader expansion in Canada. Costs incurred in 2011, 2010 and 2009 relating to the development of proved undeveloped reserves, were $1,107 million, $1,463 million and $792 million.

Projects can remain in proved undeveloped reserves for extended periods in certain situations such as behind-pipe zones where reserves will not be accessed until the primary producing zone depletes, large development projects which take more than five years to complete, and the timing of when additional gas compression is needed. Of the 395 mmboe of proved undeveloped reserves at year end 2011, 34 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 our Board of Directors in 2004 and is expected to be completed by 2016. Performance of this field has exceeded expectations, and estimates of initial dry gas in place increased by roughly 10 percent between 2004 and 2010. Production is not expected to experience a natural decline from facility-limited plateau production until 2014, or possibly 2015. The timing of the installation of compression is being driven by the reservoir performance.

Proved undeveloped reserves for the North Gialo project, located in the Libyan Sahara desert, were booked for the first time as proved undeveloped reserves in 2010. This project, which is anticipated to take more than five years to be developed, is being executed by the operator and encompasses a continuous drilling program including the design, fabrication and installation of extensive liquid handling and gas recycling facilities. In 2010, an engineering firm was awarded the front-end engineering and design activities. The remoteness of the North Gialo project is expected to extend the duration of project execution more than five years after the reserves were initially booked. For example, lead time for delivery of required highly specialized compressors is approximately 24 months. There are no other significant undeveloped reserves expected to be developed more than five years after their original booking.

As of December 31, 2011, 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 2012 through 2016 are projected to be $2,023 million, $1,537 million, $1,229 million, $804 million, and $439 million.

The timing of future projects and estimated future development costs relating to the development of proved undeveloped liquid hydrocarbons, 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, timing and development costs could be different than current estimates.

Net Production Sold


	North America						Africa						Europe
	United States		Canada^(a)		Total		EG		Other		Total		Total		Disc. Ops^(b)		Total
Year Ended December 31, 2011
Liquid hydrocarbons (mbbld)^(c)		75		-		75		38		5		43		101		-		219
Natural gas (mmcfd)^(d)(e)		326		-		326		443		-		443		81		-		850
Synthetic crude oil (mbbld)		-		38		38		-		-		-		-		-		38
Total production sold (mboed)		129		38		167		112		5		117		115		-		399
Year Ended December 31, 2010
Liquid hydrocarbons (mbbld)^(c)		70		-		70		38		45		83		92		-		245
Natural gas (mmcfd)^(d)(e)		364		-		364		405		4		409		87		-		860
Synthetic crude oil (mbbld)		-		24		24		-		-		-		-		-		24
Total production sold (mboed)		131		24		155		106		45		151		106		-		412
Year Ended December 31, 2009
Liquid hydrocarbons (mbbld)^(c)		64		-		64		42		45		87		92		5		248
Natural gas (mmcfd)^(d)(e)		373		-		373		426		4		430		116		17		936
Total production sold (mboed)		126		-		126		113		46		159		111		7		403

^(a)	Before December 31, 2009, reserves related to OSM were not included in the SEC’s definition of oil and gas producing activities; therefore, synthetic crude oil production of 27 mbbld is not reported for 2009.

^(b)	Our businesses in Ireland and Gabon were sold in 2009 and were reported as discontinued operations.

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

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

^(e)	Excludes volumes acquired from third parties for injection and subsequent resale.

Average Sales Price per Unit


	North America						Africa						Europe
(Dollars per unit)	United States		Canada^(a)		Total		EG		Other		Total		Total		Disc. Ops^(b)		Total
Year Ended December 31, 2011
Liquid hydrocarbons (bbl)	$	92.55		-	$	92.55	$	67.70	$	112.56	$	73.21	$	115.55	$	-	$	99.37
Natural gas (mcf)		4.95		-		4.95		0.24		0.70		0.24		9.75		-		2.96
Synthetic crude oil (bbl)		-		91.65		91.65		-		-		-		-		-		91.65
Year Ended December 31, 2010
Liquid hydrocarbons (bbl)	$	72.30		-	$	72.30	$	50.57	$	89.15	$	71.71	$	81.95	$	-	$	75.73
Natural gas (mcf)		4.71		-		4.71		0.24		0.70		0.25		7.04		-		2.82
Synthetic crude oil (bbl)		-		71.06		71.06		-		-		-		-		-		71.06
Year Ended December 31, 2009
Liquid hydrocarbons (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

^(a)	Before December 31, 2009, OSM was not included in the SEC’s definition of oil and gas producing activities; therefore, synthetic crude oil prices are not reported for 2009.

^(b)	Our businesses in Ireland and Gabon were sold in 2009 and were reported as discontinued operations.

Average Production Cost per Unit^(a)


	North America						Africa						Europe
(Dollars per boe)	United States		Canada^(b)		Total		EG		Other^(c)		Total		Total		Disc. Ops^(d)		Grand Total
Years ended December 31:
2011	$	16.42	$	55.65	$	25.68	$	2.87	$	17.16	$	3.53	$	8.24	$	-	$	14.26
2010		14.16		65.15		22.36		2.81		4.18		3.23		7.49		-		11.54
2009		14.03		-		14.03		2.63		3.64		2.93		6.99		19.14		7.80

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

^(b)	Before December 31, 2009 OSM was not included in the SEC’s definition of oil and gas producing activities; therefore, production costs are not reported for 2009. Production costs in 2010 include costs associated with a major turnaround and $64 million for a water abatement accrual in 2011.

^(c⁾	Production operations ceased in Libya in February 2011, but fixed costs continued to be incurred.

^(d)	Our businesses in Ireland and Gabon were sold in 2009 and were reported as discontinued operations.

Integrated Gas

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

We hold a 60 percent interest in EGHoldings, which is accounted for under the equity method of accounting. EGHoldings has a 3.7 mmta LNG production facility on Bioko Island in EG. LNG from the production facility is sold under a 3.4 mmta, or 460 mmcfd, sales and purchase agreement with a 17-year term ending in 2024. The purchaser under the agreement takes delivery of the LNG on Bioko Island, with pricing linked principally to the Henry Hub index, regardless of destination. This production facility allows us to monetize our natural gas reserves from the Alba field, as natural gas for the facility is purchased from the Alba field participants under a long-term natural gas supply agreement. Gross sales of LNG from this production facility totaled 4.1 mmt in 2011. Planned maintenance at the LNG production facility is scheduled for a 30 day period from late first quarter through early second quarter 2012, with operations expected to be completely shut down for 10 of those days. In 2011, we continued discussions with the government of EG and our partners regarding a potential second LNG production train on Bioko Island.

We own a 45 percent interest in AMPCO, which is accounted for under the equity method of accounting. AMPCO owns a methanol plant located on Bioko Island in 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 1.04, 0.85 and 0.96 mmt in 2011, 2010 and 2009. Production from the plant is used to supply customers in Europe and the U.S.

We sold our 30 percent outside-operated interest in a natural gas liquefaction plant in Kenai Alaska in the third quarter of 2011 at which time our sales from this facility ceased.

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

Competition and Market Conditions

Strong competition exists in all sectors of the oil and gas industry and, in particular, in the exploration for and development of new reserves. We compete with major integrated and independent oil and gas companies, as well as national oil companies, for the acquisition of oil and natural gas leases and other properties. We compete with these companies for the equipment and labor required to develop and operate those properties and in the marketing of oil and natural gas to end-users. Many of our competitors have financial and other resources greater than those available to us. Acquiring exploration opportunities frequently requires competitive bids involving front-end bonus payments or commitments-to-work programs. We also compete in attracting and retaining personnel, including petroleum engineers, geologists, geophysicists and other specialists. Based upon statistics compiled in the “2011 Global Upstream Performance Review” published by IHS Herold Inc., we rank tenth among U.S.-based petroleum companies on the basis of 2010 worldwide liquid hydrocarbon and natural gas production.

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

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. Market conditions in the oil and gas industry are cyclical and subject to global economic and political events and new and changing governmental regulations. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, Overview – Market Conditions for additional discussion of the impact of prices on our operations.

Environmental, Health and Safety Matters

The Health, Environmental, Safety and Corporate Responsibility Committee of our Board of Directors is responsible for overseeing our position on public issues, including environmental, health and safety 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 Corporate Emergency Response Team which oversees our response to any major environmental or other emergency incident involving us or any of our properties.

Our businesses are subject to numerous laws and regulations relating to the protection of the environment, health and safety. These laws and regulations include the Occupational Safety and Health Act (“OSHA”) with respect to the protection of health and safety of employees, the Clean Air Act (“CAA”) with respect to air emissions, the Federal Water Pollution Control Act (also known as the Clean Water Act (“CWA”) with respect to water discharges, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) with respect to releases and remediation of hazardous substances, the Oil Pollution Act of 1990 (“OPA-90”) with respect to oil pollution and response, the National Environmental Policy Act with respect to evaluation of environmental impacts, the Endangered Species Act with respect to the protection of endangered or threatened species, the Resource Conservation and Recovery Act (“RCRA”) with respect to solid and hazardous waste treatment, storage and disposal, and the U.S. Emergency Planning and Community Right-to-Know Act with respect to the dissemination of information relating to certain chemical inventories. In addition, many other states and countries in which where we operate have their own similar laws dealing with similar matters.

These laws and regulations could result in costs to remediate releases of regulated substances, including crude oil, into the environment, or costs to remediate sites to which we sent regulated substances for disposal. In some cases, these

laws 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 (such as prior owners or operators of our assets) or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. New laws have been 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 defined. Based on regulatory trends, particularly with respect to the CAA and its implementing regulations, we have incurred and will continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including the age and location of its operating facilities, marketing areas and production processes.

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

Air

In August 2011, the U.S. Environmental Protection Agency (“U.S. EPA”) published proposed New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAP”) that will both amend existing NSPS and NESHAP standards for oil and gas facilities as well as create a new NSPS for oil and gas production, transmission and distribution facilities. If the proposed rules are finalized without substantial modification, compliance with the rules will result in an increase in costs of control, equipment and labor and require additional notification, monitoring, reporting and recordkeeping. The U.S. EPA is required to finalize this rule by April, 2012.

In July 2011, the U.S. EPA finalized a Federal Implementation Plan under the CAA that includes New Source Review (“NSR”) regulations which apply to air emissions sources on Tribal Lands. This rule became effective on August 30, 2011, and requires the registration and/or pre-construction permitting of most of our facilities on Tribal Lands in Wyoming, Oklahoma and North Dakota. To minimize pre-construction delays in the near term, we entered into an Administrative Compliance and Consent Agreement (“Agreement”) that temporarily suspended the requirement for pre-construction permits for facilities on Trial Lands in North Dakota as long as permit applications were filed in accordance with the Agreement. We cannot reasonably estimate the financial impact of these permitting requirements until the U.S. EPA finalizes its internal permitting procedures. The U.S. EPA has indicated that this rule will be finalized during the first half of 2012.

Climate Change

In 2010, the U.S. EPA promulgated rules that required us to monitor and submit an annual report on our greenhouse gas emissions. Further, state, national and international requirements to reduce greenhouse emissions are being proposed and in some cased promulgated. These requirements apply 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. 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.

Hydraulic Fracturing

Hydraulic fracturing is a commonly used process that involves injecting water, sand, and small volumes of chemicals into the wellbore to fracture the hydrocarbon-bearing rock thousands of feet below the surface to facilitate higher flow of hydrocarbons into the wellbore. Hydraulic fracturing has been regulated at the state level through permitting and compliance requirements. State level initiatives in regions with substantial shale resources have been or may be proposed or implemented to further regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used, or implement temporary or permanent bans on hydraulic fracturing. In addition, the U.S. Congress has considered legislation that would require regulation affecting the hydraulic fracturing process. In the first quarter of 2010, the U.S. EPA announced its intention to conduct a comprehensive research study on the potential effects that hydraulic fracturing may have on water quality and public health. The U.S. EPA has begun preparation for the study and expects to issue an interim report in 2012 followed by a final report in 2014.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal or state laws or the

implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and increased compliance costs, which could increase costs of our operations and cause considerable delays in acquiring regulatory approvals to drill and complete wells.

Remediation

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

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. For the years 2011, 2010 and 2009, transactions with MPC accounted for more than 10 percent of our annual revenues. The majority of those transactions occurred while MPC was a wholly-owned subsidiary. In addition, for the years 2010 and 2009, sales of crude oil to the Libyan National Oil Company accounted for more than 10 percent of our annual revenues. These transactions were restricted to sales of crude oil produced in Libya during those periods.

Trademarks, Patents and Licenses

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

Employees

We had 3,322 active, full-time employees as of December 31, 2011. We consider labor relations with our employees to be satisfactory. We have not had any work stoppages or strikes pertaining to our employees.

Executive Officers of the Registrant

The executive officers of Marathon Oil and their ages as of February 1, 2012, are as follows:


Clarence P. Cazalot, Jr.	61	Chairman, President and Chief Executive Officer
Janet F. Clark	57	Executive Vice President and Chief Financial Officer
David E. Roberts, Jr.	51	Executive Vice President and Chief Operating Officer
Eileen M. Campbell	54	Vice President, Public Policy
Steven P. Guidry	53	Vice President, Business Development
Sylvia J. Kerrigan	46	Vice President, General Counsel and Secretary
Michael K. Stewart	54	Vice President, Finance and Accounting, Controller and Treasurer
Howard J. Thill	52	Vice President, Investor Relations and Public Affairs

All of the executive officers have held responsible management or professional positions with Marathon Oil or its subsidiaries for more than the past five years.

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Mr. Cazalot was appointed chairman of the board of directors effective July 2011 and was appointed president and chief executive officer effective January 2002.

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

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Mr. Roberts was appointed executive vice president and chief operating officer effective July 2011. Mr. Roberts joined Marathon in June 2006 as senior vice president, business development and was appointed executive vice president, upstream in April 2008.

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

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Mr. Guidry was appointed vice president, business development effective July 2011. Mr. Guidry previously served as regional vice president for our Libya operations from November 2008 to June 2011. Prior to the Libya assignment, Mr. Guidry was regional vice president for Marathon’s North American Production Operations from August 2006 to November 2008.

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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.

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Mr. Stewart was appointed vice president, finance and accounting, controller and treasurer effective December 2011. Mr. Stewart previously served as vice president, accounting and controller from May 2006 to December 2011 and as controller from July 2005 to April 2006.

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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 Oil, including the Corporate Governance Principles and Charters for the Audit and Finance Committee, Compensation Committee, Corporate Governance and Nominating Committee and Health, Environmental, Safety and Corporate Responsibility Committee, can be found at www.marathonoil.com. In addition, our Code of Business Conduct and Code of Ethics for Senior Financial Officers are available at http://www.marathonoil.com/Investor_Center/.

Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after the reports are filed or furnished with the SEC. These documents are also available in hard copy, free of charge, by contacting our Investor Relations office. Information contained on our website is not incorporated into this Annual Report on Form 10-K or other securities filings.

Item 1A. Risk Factors

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

A substantial or extended decline in liquid hydrocarbon or natural gas prices 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 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. Historically, the markets for liquid hydrocarbons and natural gas have been volatile and may continue to be volatile in the future. Many of the factors influencing prices of liquid hydrocarbons and natural gas are beyond our control. These factors include:

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

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

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the ability of the members of OPEC to agree to and maintain production controls;

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

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changes in weather patterns and climate;

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natural disasters such as hurricanes and tornados;

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

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domestic and foreign governmental regulations and taxes; and

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general economic conditions worldwide.

The long-term effects of these and other factors on the prices of liquid hydrocarbons and natural gas 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 could require us to reduce our capital expenditures or impair the carrying value of our assets.

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

Offshore exploration and development operations present technological challenges and operating risks because of the marine environment. Activities in deepwater areas may pose incrementally greater risks because of water depths that limit intervention capability and the physical distance to oilfield service infrastructure and service providers. Environmental remediation and other costs resulting from spills or releases may result in substantial liabilities.

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. 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 valued based on the unweighted average of closing prices for the first day of each month in the 12-month period ended December 31, 2011, as well as other conditions in existence at the date. Any significant future price change will have a material effect on the quantity and present value of our proved reserves. Future reserve revisions could also result from changes in governmental regulation, among other things.

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

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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 unweighted average of closing prices for the first day of each month in the 12-month period ended December 31, 2011, and costs applicable at the date of the estimate, while actual future prices and costs may be materially higher or lower.

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

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

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

•

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

•

drilling success;

•

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

•

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

•

the ability to fund such activity.

Future exploration and drilling results are uncertain and involve substantial costs.

Drilling for liquid hydrocarbons and natural gas involves numerous risks, including the risk that we may not encounter commercially productive liquid hydrocarbon and natural gas reservoirs. The costs of drilling, completing and operating wells are often uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:

•

unexpected drilling conditions;

•

title problems;

•

pressure or irregularities in formations;

•

equipment failures or accidents;

•

fires, explosions, blowouts and surface cratering;

•

lack of access to pipelines or other transportation methods; and

•

shortages or delays in the availability of services or delivery of equipment.

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.

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

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

We believe it is likely that the scientific and political attention to issues concerning the extent, causes of and responsibility for climate change will continue, with the potential for further regulations that could affect our operations. Currently, various legislative and regulatory measures to address greenhouse gas emissions (including carbon dioxide, methane and nitrous oxides) are in various phases of review, discussion or implementation in countries where we operate, including the U.S., Canada, and Norway, and the European Union. Our operations result in these greenhouse gas emissions. Through 2011, domestic legislative and regulatory efforts included proposed federal legislation and state actions to develop statewide or regional programs, each of which could impose reductions in greenhouse gas emissions. Further, in December 2011 at the Durban Climate Change Conference, countries such as the U.S., China and India, and the European Union agreed in principal to replace the Kyoto Protocol (which expires in 2012) with a new legally binding agreement. However, at this time it is not certain whether a legally binding resolution will be reached, what the terms of any agreement would be, or whether the U.S. Senate would ratify such an agreement. These actions could result in increased: (1) costs to operate and maintain our facilities, (2) capital expenditures to install new emission controls at our facilities, and (3) costs to administer and manage any 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 liquid hydrocarbons and natural gas, and create delays in our obtaining air pollution permits for new or modified facilities.

Although there may be adverse financial impact (including compliance costs, potential permitting delays and potential reduced demand for liquid hydrocarbons or natural gas) associated with any legislation, regulation, or other action by the U.S. EPA, 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 any additional measures and how they will be implemented. Private party litigation has also been brought against some emitters of greenhouse gas emissions.

The potential adoption of federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas wells.

Hydraulic fracturing is a commonly used process that involves injecting water, sand, and small volumes of chemicals into the wellbore to fracture the hydrocarbon-bearing rock thousands of feet below the surface to facilitate higher flow of hydrocarbons into the wellbore. The U.S. Congress has considered legislation that would require additional regulation affecting the hydraulic fracturing process. Consideration of new federal regulation and increased state oversight continues to arise. The U.S. EPA announced in the first quarter of 2010 its intention to conduct a comprehensive research study on the potential effects that hydraulic fracturing may have on water quality and public health. The U.S. EPA has begun preparation for the study and expects to issue an interim report in 2012 followed by a final report in 2014. In addition, various state-level initiatives in regions with substantial shale gas resources have been or may be proposed or implemented to further regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used, or implement temporary or permanent bans on hydraulic fracturing.

Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal or state laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and increased compliance costs.

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 64 percent of our liquid hydrocarbon and natural gas sales volumes in 2011 was derived from production outside the U.S. and 64 percent of our proved liquid hydrocarbon and natural gas reserves as of December 31, 2011, were located outside the U.S. All of our synthetic crude oil production and proved reserves are located in Canada. We are, therefore, subject to the political, geographic and economic risks and possible terrorist activities attendant to doing business with suppliers located within or outside of the U.S. There are many risks associated with operations in countries and in global markets, such as Equatorial Guinea, Indonesia, Libya and the Iraqi Kurdistan Region, including:

•

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

•

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

•

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

•

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

•

fluctuating currency values, hard currency shortages and currency controls.

Since January 2010, there have been varying degrees of political instability and public protests, including demonstrations which have been marked by violence, within some countries in the Middle East including Bahrain, Egypt, Libya, Syria, Tunisia and Yemen. Some political regimes in these countries are threatened or have changed as a result of such unrest. If such unrest continues to spread, conflicts could result in civil wars, regional conflicts, and regime changes resulting in governments that are hostile to the U.S. These may have the following results, among others:

•

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

•

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

•

security concerns leading to the prolonged evacuation of our personnel;

•

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

•

inability of our service and equipment providers to deliver items necessary for us to conduct our operations.

Continued hostilities in the Middle East and the occurrence or threat of future terrorist attacks could adversely affect the economies of the U.S. 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 and natural gas. 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 U.S. 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.

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. In addition, misconduct, fraud, noncompliance with applicable laws and regulations or improper activities by or on behalf of one or more of our partners could have a significant negative impact on our business and reputation.

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, tsunamis, earthquakes, volcanic eruptions or nuclear or

other disasters, 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. These same risks can be applied to the third-parties which transport crude oil from our facilities. A prolonged disruption in the ability of any pipeline or vessels to transport crude oil could contribute to a business interruption or increase costs.

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

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

We currently are defending litigation and anticipate that we will be required to defend new litigation in the future. The subject matter of such litigation may include releases of hazardous substances from our facilities, privacy laws, antitrust laws or any other laws or regulations that apply to our operations. 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. In addition to substantial liability, litigation may also seek injunctive relief which could have an adverse effect on our future operations.

In connection with our separation from MPC, MPC agreed to indemnify us for certain liabilities. However, there can be no assurance that the indemnity will be sufficient to protect us against the full amount of such liabilities, or that MPC’s ability to satisfy its indemnification obligations will not be impaired in the future.

Pursuant to the separation and distribution agreement and the tax sharing agreement we entered into with MPC in connection with the spin-off, MPC agreed to indemnify us for certain liabilities. However, third parties could seek to hold us responsible for any of the liabilities that MPC agreed to retain or assume, and there can be no assurance that the indemnification from MPC will be sufficient to protect us against the full amount of such liabilities, or that MPC will be able to fully satisfy its indemnification obligations. In addition, even if we ultimately succeed in recovering from MPC any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves.

The spin-off could result in substantial tax liability.

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

If, notwithstanding receipt of the private letter ruling and opinion of counsel, the spin-off were determined not to qualify under Section 355 of the Code, each U.S. holder of our common stock who received shares of MPC common stock in the spin-off would generally be treated as receiving a taxable distribution of property in an amount equal to the fair market value of the shares of MPC common stock received. That distribution would be taxable to each such stockholder as a dividend to the extent of our accumulated earnings and profits as of the effective date of the spin-off. For each such stockholder, any amount that exceeded those earnings and profits would be treated first as a non-taxable return of capital to the extent of such stockholder’s tax basis in its shares of our common stock with any remaining amount being taxed as a capital gain. We would be subject to tax as if we had sold all the outstanding shares of MPC common stock in a taxable sale for their fair market value and would recognize taxable gain in an amount equal to the excess of the fair market value of such shares over our tax basis in such shares.

Under the terms of the tax sharing agreement we entered into with MPC in connection with the spin-off, MPC is generally responsible for any taxes imposed on MPC or us and our subsidiaries in the event that the spin-off and/or certain related transactions were to fail to qualify for tax-free treatment as a result of actions taken, or breaches of representations and warranties made in the tax sharing agreement, by MPC or any of its affiliates. However, if the spin-off and/or certain related transactions were to fail to qualify for tax-free treatment because of actions or failures to act by us or any of our affiliates, we would be responsible for all such taxes.

We may issue preferred stock whose terms could dilute the voting power or reduce the value of Marathon Oil 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 Oil 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 Oil 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, 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 are set forth in Item 8. Financial Statements and Supplementary Data – Supplemental Statistics. Estimated net proved liquid hydrocarbon, natural gas and synthetic crude oil reserves are set forth in Item 8. Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities – Estimated Quantities of Proved Oil and Gas Reserves. The basis for estimating these reserves is discussed in Item 1. Business – Reserves.

Item 3. Legal Proceedings

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

Litigation

In March 2011, Noble Drilling (U.S.) LLC (“Noble”) filed a lawsuit against us in the District Court of Harris County, Texas alleging, among other things, breach of contract, breach of the duty of good faith and fair dealing, and negligent misrepresentation, relating to a multi-year drilling contract for a newly constructed drilling rig to be deployed in the U.S. Gulf of Mexico. We filed an answer in April 2011, contending, among other things, failure to perform, failure to comply

with material obligations, failure to mitigate alleged damages and that Noble failed to provide the rig according to the operating, performance and safety requirements specified in the drilling contract. Noble is seeking an unspecified amount of damages. We are vigorously defending this litigation. The ultimate outcome of this lawsuit, including any financial effect on us, remains uncertain. We do not believe an estimate of a reasonably probable loss (or range of loss) can be made for this lawsuit at this time.

Environmental Proceedings

The following is a summary of proceedings involving us that were pending or contemplated as of December 31, 2011, 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 (“PRP”) for each site include present and former owners and operators of, transporters to and generators of the substances at the site. We had been identified as a PRP at five CERCLA waste sites, however, after the June 30, 2011 spin-off of our downstream business, MPC has indemnified Marathon and retained liability for all of these sites.

As of December 31, 2011, we have identified 20 sites 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 these sites will be less than $25 million.

We have been working with the North Dakota Department of Health to resolve voluntary disclosures we made in 2009 relating to potential Clean Air Act violations relating to our operations on state lands in the Bakken shale. The amount of the potential fine is estimated to be $100,000.

The projected liability for clean-up and remediation provided in the preceding paragraph is a forward-looking statement. To the extent that our assumptions prove to be inaccurate, future expenditures may differ materially from those stated in the forward-looking statement.

SEC Investigation Relating to Libya

On May 25, 2011, we received a subpoena issued by the SEC requiring production of documents related to payments made to the government of Libya, or to officials and persons affiliated with officials of the government of Libya. We have been and intend to continue cooperating with the SEC in its investigation.

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 Oil common stock is traded is the New York Stock Exchange (“NYSE”). As of January 31, 2012, there were 46,783 registered holders of Marathon Oil common stock.

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


	2011*						2010
Dollars per share	High Price		Low Price		Dividends		High Price		Low Price		Dividends
Quarter 1	$	53.31	$	37.34	$	0.25	$	32.85	$	28.04	$	0.24
Quarter 2		54.17		49.06		0.25		34.11		30.19		0.25
Quarter 3		34.07		21.58		0.15		34.98		30.21		0.25
Quarter 4		29.34		20.27		0.15		37.03		33.07		0.25
Full Year	$	54.17	$	20.27	$	0.80	$	37.03	$	28.04	$	0.99

*	On June 30, 2011, we completed the spin-off our downstream business. The June 30, 2011 closing price of our common stock on the NYSE was $52.68. On July 1, 2011, the opening price of our common stock on the NYSE was $32.95. Our quarterly dividend was also adjusted to $0.15 per share.

Dividends

Our Board of Directors intends to declare and pay dividends on Marathon Oil 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 Oil common stock, the Board will rely on the consolidated financial statements of Marathon Oil. Dividends on Marathon Oil common stock are limited to our legally available funds.

On January 27, 2012, we announced a 13 percent increase in our quarterly dividend to $0.17 per share.

Issuer Purchases of Equity Securities

The following table provides information about purchases by Marathon Oil and its affiliated purchaser during the quarter ended December 31, 2011, of equity securities that are registered by Marathon Oil pursuant to Section 12 of the Securities Exchange Act of 1934:


	Column (a)			Column (b)		Column (c)		Column (d)
Period	Total Number of Shares Purchased^(a)			Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs^(c)		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs^(c)
10/01/11 – 10/31/11		6,217		$	20.84		-	$	1,780,609,536
11/01/11 – 11/30/11		12,748		$	25.03		-	$	1,780,609,536
12/01/11 – 12/31/11		40,420	^(b)	$	27.21		-	$	1,780,609,536
Total		59,385		$	26.08		-

^(a)	26,396 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

^(b)

32,989 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 Oil.

^(c)

We announced a share repurchase program in January 2006, and amended it several times in 2007 for a total authorized program of $5 billion. As of December 31, 2011, 78 million common shares had been acquired at a cost of $3,222 million, which includes transaction fees and commissions that are not reported in the table above. Of this total, 66 million shares had been acquired at a cost of $2,922 million prior the spin-off of the downstream business (see Item 8. Financial Statements and Supplementary Data—Note 3 to the consolidated financial statements).

Item 6. Selected Financial Data


(Dollars in millions, except as noted)	2011^(b)		2010^(c)		2009^(d)		2008^(d)(e)		2007^(d)(f)(g)
Statement of Income Data^(a)
Revenues	$	14,663	$	11,690	$	8,524	$	13,162	$	8,569
Income from continuing operations		1,707		1,882		716		2,192		1,699
Net income		2,946		2,568		1,463		3,528		3,956

Per Share Data
Basic :
Income from continuing operations	$	2.40	$	2.65	$	1.01	$	3.09	$	2.46
Net income	$	4.15	$	3.62	$	2.06	$	4.97	$	5.73
Diluted :
Income from continuing operations	$	2.39	$	2.65	$	1.01	$	3.08	$	2.44
Net income	$	4.13	$	3.61	$	2.06	$	4.95	$	5.69

Statement of Cash Flows Data^(a)
Additions to property, plant and equipment related to continuing operations	$	3,295	$	3,536	$	3,349	$	4,202	$	2,354
Dividends paid		567		704		679		681		637
Dividends per share	$	0.80	$	0.99	$	0.96	$	0.96	$	0.92

Balance Sheet Data as of December 31:
Total assets	$	31,371	$	50,014	$	47,052	$	42,686	$	42,746
Total long-term debt, including capitalized leases		4,674		7,601		8,436		7,087		6,084

^(a)	Our downstream business was spun-off on June 30, 2011. Previous periods have been recast to reflect the business in discontinued operations (see Item 8. Financial Statements and Supplementary Data – Note 3 to the consolidated financial statements).

^(b)	Includes impairments of $310 million primarily related to E&P segment assets (see Item 8. Financial Statements and Supplementary Data – Note 15 to the consolidated financial statements).

^(c)	Includes impairments of $447 million primarily related to E&P segment assets (see Item 8. Financial Statements and Supplementary Data – Note 15 to the consolidated financial statements).

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

^(e)	Includes a $1,412 million impairment of goodwill related to the OSM reporting unit.

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

^(g)

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

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

We are an international energy company with operations in the U.S., Canada, Africa, the Middle East and Europe. Our operations are organized into three reportable segments:

•

E&P which explores for, produces and markets liquid hydrocarbons and natural gas on a worldwide basis.

•

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.

•

IG which produces and markets products manufactured from natural gas, such as LNG and methanol, in EG.

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 forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in this Annual Report on Form 10-K.

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 and Item 8. Financial Statements and Supplementary Data found in this Annual Report on Form 10-K.

Spin-off Downstream Business

On June 30, 2011, the spin-off of Marathon’s downstream business was completed, creating two independent energy companies: Marathon Oil and MPC. Marathon shareholders at the close of business on the record date of June 27, 2011 received one share of MPC common stock for every two shares of Marathon common stock held. Fractional shares of MPC common stock were not distributed and any fractional share of MPC common stock otherwise issuable to a Marathon shareholder was sold in the open market on such shareholder’s behalf, and such shareholder received a cash payment with respect to that fractional share. A private letter tax ruling received in June 2011 from the IRS affirmed the tax-free nature of the spin-off. Activities related to the downstream business have been treated as discontinued operations in all periods presented in this Annual Report on Form 10-K (see Item 8. Financial Statements and Supplementary Data—Note 3 to the consolidated financial statements for additional information).

Overview – Market Conditions

Exploration and Production

Prevailing prices for the various grades of crude oil and natural gas that we produce significantly impact our revenues and cash flows. Prices of crude oil have been volatile in recent years. In 2011, crude prices increased over 2010 levels, with increases in Brent averages outstripping those in WTI. During much of 2010, both WTI and Brent crude oil monthly average prices remained in the $75 to $85 per barrel range. Crude oil prices reached a low of $33.98 in February 2009, following global demand declines in an economic recession, but recovered quickly ending 2009 at $79.36. The following table lists benchmark crude oil and natural gas price annual averages for the past three years.


Benchmark	2011		2010		2009
WTI crude oil (Dollars per bbl)	$	95.11	$	79.61	$	62.09
Brent (Europe) crude oil (Dollars per bbl)		111.26		79.51		61.49
Henry Hub natural gas (Dollars per mmbtu)^(a)	$	4.04	$	4.39	$	3.99

^(a)	Settlement date average.

Our U.S. crude oil production was approximately 58 percent sour in 2011 and 68 percent in 2010. Sour crude contains more sulfur than light sweet WTI does. Sour crude oil also tends to be heavier than light sweet crude oil and sells at a discount to light sweet crude oil because of higher refining costs and lower refined product values. Our international crude oil production is relatively sweet and is generally sold in relation to the Brent crude benchmark. The differential between WTI and Brent average prices widened significantly in 2011 to $16.15 in comparison to differentials of less than $1.00 in 2010 and 2009.

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. Average settlement date Henry Hub natural gas prices have been relatively stable for the periods of this report; however, a decline began in September 2011 which has continued in 2012 with February averaging $2.68 per mmbtu. Should U.S. natural gas prices remain depressed, an impairment charge related to our natural gas assets may be necessary.

Our other major natural gas-producing regions are Europe and EG. Natural gas prices in Europe have been significantly higher than in the U.S. In the case of EG our natural gas sales are subject to term contracts, making realized prices less volatile. The natural gas sales from EG are at fixed prices; therefore, our worldwide reported average natural gas realized prices may not fully track market price movements.

Oil Sands Mining

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

The operating cost structure of the oil sands mining operations is predominantly fixed and therefore many of the costs incurred in times of full operation continue during production downtime. Per-unit costs are sensitive to production rates. Key variable costs are natural gas and diesel fuel, which track commodity markets such as the Canadian Alberta Energy Company (“AECO”) natural gas sales index and crude oil prices, respectively. Recently AECO prices have declined, much as Henry Hub prices have. We would expect a significant, continued declined in natural gas prices to have a favorable impact on OSM operating costs.

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


Benchmark	2011		2010		2009
WTI crude oil (Dollars per bbl)	$	95.11	$	79.61	$	62.09
Western Canadian Select (Dollars per bbl)^(a)		77.97		65.31		52.13
AECO natural gas sales index (Dollars per mmbtu)^(b)	$	3.68	$	3.89	$	3.49

^(a)	Monthly pricing based upon average WTI adjusted for differentials unique to western Canada.

^(b)	Monthly average day ahead index.

Integrated Gas

Our integrated gas operations include production and marketing of products manufactured from natural gas, such as LNG and methanol, in EG.

World LNG trade in 2011 has been estimated to be 241 mmt. Long-term, LNG continues to be in demand as markets seek the benefits of clean burning natural gas. Market prices for LNG are not reported or posted. In general, LNG delivered to the U.S. is tied to Henry Hub prices and will track with changes in U.S. natural gas prices, while LNG sold in Europe and Asia is indexed to crude oil prices and will track the movement of those prices. We have a 60 percent ownership in an LNG production facility in Equatorial Guinea, which sells LNG under a long-term contract at prices tied to Henry Hub natural gas prices. Gross sales from the plant were 4.1 mmt, 3.7 mmt and 3.9 mmt in 2011, 2010 and 2009.

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 1,039,657, 850,605 and 960,374 metric tonnes in 2011, 2010 and 2009. Methanol demand has a direct impact on AMPCO’s earnings. Because global demand for methanol is rather limited, changes in the supply-demand balance can have a significant impact on sales prices. World demand for methanol in 2011 has been estimated to be 55.4 mmt. Our plant capacity of 1.1 mmt is about 2 percent of total demand.

Operating and Financial Highlights

Significant operating and financial highlights during 2011 include:

•

Completed the spin-off of our downstream business on June 30, 2011

•

Acquired a significant operated position in the Eagle Ford shale play in south Texas

•

Added net proved reserves, for the E&P and OSM segments combined, of 307 mmboe, excluding dispositions, for a 212 percent reserve replacement ratio

•

Increased proved liquid hydrocarbon, including synthetic crude oil, reserves to 78 percent from 75 percent of proved reserves

•

Increased E&P net sales volumes, excluding Libya, by 7 percent

•

Recorded 96 percent average operational availability for all major company-operated E&P assets, compared to 94 percent in 2010

•

Completed debottlenecking work that increased crude oil production capacity at the Alvheim FPSO in Norway to 150,000 gross bbld from the previous capacity of 142,000 gross bbld and the original 2008 capacity of 120,000 gross bbld

•

Announced two non-operated discoveries in the Iraqi Kurdistan Region and began drilling in Poland

•

Completed AOSP Expansion 1, including the start-up of the expanded Scotford upgrader, realizing an increase in net synthetic crude oil sales volumes of 48 percent

•

Completed dispositions of non-core assets and interests in acreage positions for net proceeds of $518 million

•

Repurchased 12 million shares of our common stock at a cost of $300 million

•

Retired $2,498 million principal of our long-term debt

•

Resumed limited production in Libya in the fourth quarter of 2011 following the February 2011 temporary suspension of operations

Consolidated Results of Operations: 2011 compared to 2010

Due to the spin-off of our downstream business on June 30, 2011, which is reported as discontinued operations, income from continuing operations is more representative of Marathon Oil as an independent energy company. Consolidated income from continuing operations before income taxes was 9 percent higher in 2011 than in 2010, largely due to higher liquid hydrocarbon prices. This improvement was offset by increased income taxes primarily the result of excess foreign tax credits generated during 2011 that we do not expect to utilize in the future. The effective income tax rate for continuing operations was 61 percent in 2011 compared to 54 percent in 2010.

Revenues are summarized in the following table:


(In millions)	2011		2010
E&P	$	13,029	$	10,782
OSM		1,588		833
IG		93		150

Segment revenues		14,710		11,765
Elimination of intersegment revenues		(47)		(75)

Total revenues	$	14,663	$	11,690

E&P segment revenues increased $2,247 million from 2010 to 2011, primarily due to higher average liquid hydrocarbon realizations, which were $99.37 per bbl in 2011, a 31 percent increase over 2010. Revenues in 2010 included net pre-tax gains of $95 million on derivative instruments intended to mitigate price risk on future sales of liquid hydrocarbons and natural gas.

Included in our E&P segment are supply optimization activities which include the purchase of commodities from third parties for resale. Supply optimization serves to aggregate volumes in order to satisfy transportation commitments and to achieve flexibility within product types and delivery points. See the Cost of revenues discussion as revenues from supply optimization approximate the related costs. Higher average crude oil prices in 2011 compared to 2010 increased revenues related to supply optimization.

Revenues from the sale of our U.S. production are higher in 2011 primarily as a result of higher liquid hydrocarbon and natural gas price realizations, but sales volumes declined.

The following table gives details of net sales and average realizations of our U.S. operations.


	2011		2010
United States Operating Statistics
Net liquid hydrocarbon sales (mbbld)^(a)		75		70
Liquid hydrocarbon average realizations (per bbl)^(b)	$	92.55	$	72.30
Net natural gas sales (mmcfd)		326		364
Natural gas average realizations (per mcf)^(b)	$	4.95	$	4.71

^(a)	Includes crude oil, condensate and natural gas liquids.

^(b)	Excludes gains and losses on derivative instruments.

Increased liquid hydrocarbon sales volumes in 2011 were a result of new wells in the Bakken shale, new production from acreage acquired in the Eagle Ford shale and increased production from the Droshky development in the Gulf of Mexico, which commenced operations in July 2010. Natural gas sales volumes were lower in 2011 as compared to 2010 due to the sale of a portion of our Powder River Basin asset in 2010, decreased demand in Alaska and natural field declines, partly offset by increased natural gas production from the Droshky development.

The following table gives details of net sales and average realizations of our international operations.


	2011		2010
International Operating Statistics
Net liquid hydrocarbon sales (mbbld)^(a)
Europe		101		92
Africa		43		83

Total International		144		175
Liquid hydrocarbon average realizations (per bbl)^(b)
Europe	$	115.55	$	81.95
Africa		73.21		71.71
Total International	$	102.96	$	77.11
Net natural gas sales (mmcfd)
Europe^(c)		97		105
Africa		443		409

Total International		540		514
Natural gas average realizations (per mcf)^(b)
Europe	$	9.84	$	7.10
Africa		0.24		0.25
Total International	$	1.97	$	1.65

^(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)	Excludes gains and losses on derivative instruments.

^(c)	Includes natural gas acquired for injection and subsequent resale of 16 mmcfd and 18 mmcfd in 2011 and 2010.

Compared to 2010, international liquid hydrocarbon sales volumes are lower due to the temporary cessation of production from Libya in February 2011. In the fourth quarter of 2011, limited production resumed from the Waha concessions, but we made no deliveries of hydrocarbons. Sales are planned to resume in the first quarter of 2012. Partially offsetting the impact of Libya, were higher liquid hydrocarbon sales from Norway due to increasing capacity of the Alvheim FPSO and from two new West Brae wells in the U.K. Natural gas sales volumes from EG were higher in 2011 due to a turnaround in 2010, while natural gas sales volumes from Europe were down primarily related to 2011 planned turnarounds and normal production declines in the U.K.

OSM segment revenues increased $755 million from 2010 to 2011. Revenues were impacted by net pre-tax gains of $25 million on derivative instruments in 2010. The increase in revenue is due to higher synthetic crude oil sales volumes and realizations as shown on the table below.


	2011		2010
OSM Operating Statistics
Net synthetic crude oil sales (mbbld)^(a)		43		29
Synthetic crude average realizations (per bbl)	$	91.65	$	71.06

^(a)	Includes blendstocks.

The 2011 sales volumes improved as a result of the Jackpine mine, which commenced operations in late 2010, and the upgrader expansion which was completed and commenced operations in the second quarter of 2011. Sales volumes in 2010 were impacted by a turnaround that commenced in late March 2010 that caused production to be completely shut down in April, with a staged resumption in May 2010.

IG segment revenues decreased $57 million in 2011 from 2010 because sales of LNG from our Alaska operations declined throughout 2011 as we planned to shut down the LNG facility. In the third quarter of 2011, sales from the LNG facility ceased completely because we sold our equity interest in the facility.

Income from equity method investments increased $118 million in 2011 from 2010 primarily due to the impact of higher liquid hydrocarbon prices on the earnings of certain of our equity method investees in 2011.

Net gain on disposal of assets in 2011 is primarily related to sales of non-core assets, such as the Burns Point gas plant and the Alaska LNG facility, and the assignment of interests in our DJ Basin and Poland acreage positions. The 2010 gain is primarily related to the pretax gain of $811 million on the sale of a 20 percent outside-operated interest in our Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola. See Item 8. Financial Statements and Supplementary Data – Note 6 to the consolidated financial statements for discussion of significant dispositions.

Cost of revenues increased $1,439 million from 2010 to 2011 primarily due to the impact of higher crude oil prices on our supply optimization activities. Costs related to supply optimization were $3,599 million in 2011 compared to $2,530 million in 2010.

Additionally, total OSM segment costs increased for 2011 primarily because the Jackpine mine commenced production in late 2010 and the upgrader expansion came online in 2011. Although gross costs are up due to the increased volumes from the expansion, per barrel costs have been declining in comparison with 2010. OSM segment costs also increased in 2011 when compared to 2010 due to the expansion’s operation start-up costs. These increases were partially offset by no turnaround costs in 2011. We incurred $99 million in 2010 associated with the turnaround. Additionally, estimated net costs of $64 million were recorded in 2011 to address water flow in a previously mined and contained area of the Muskeg River mine.

Purchases from related parties increased $78 million from 2010 as a result of purchases from the Alba LPG plant in EG, in which we own an equity interest. Higher liquid hydrocarbon prices in 2011 increased the value of those purchases.

Depreciation, depletion and amortization increased $210 million in 2011 from 2010. Since both our E&P and OSM segments apply the units-of-production method to the majority of their assets, the previously discussed increases or decreases in sales volumes generally result in similar changes in DD&A. Increased DD&A expense in 2011 reflects the impact of higher OSM segment sales volumes, partially offset by decreases in E&P segment sales volumes. The DD&A rate (expense per barrel of oil equivalent), which is impacted by changes in proved reserves and capitalized costs, can also cause changes in our DD&A. The following table provides DD&A rates for our E&P and OSM segments.


($ per boe)	2011		2010
DD&A rate
E&P Segment
United States	$	25	$	22
International		10		9
OSM Segment	$	18	$	16

Impairments in 2011 related primarily to our Droshky development in the Gulf of Mexico for $273 million and an intangible asset for an LNG delivery contract at Elba Island. Impairments in 2010 include $423 million related to our Powder River Basin field in the first quarter, as well as smaller impairments to other E&P segment fields due to reductions in estimated reserves, reduced drilling expectations and declining natural gas prices. See Item 8. Financial Statements and Supplementary Data—Note 15 to the consolidated financial statements for further information about the impairments.

General and administrative expenses increased $53 million in 2011 compared to 2010 primarily due to additional compensation expense related to performance units and stock based compensation expense.

Other taxes increased $31 million in 2011 compared to 2010. With the increase in revenues, particularly related to higher prices, production and ad valorem taxes increased.

Exploration expenses were higher in 2011 than 2010 primarily due to higher dry well costs. Dry wells primarily related to Indonesia, the Gulf of Mexico, Norway and various U.S. onshore properties in both 2011 and 2010. In addition, costs related to some suspended exploratory wells in Equatorial Guinea were expensed in 2010. Geologic and seismic costs have increased in 2011 over 2010 primarily related to the U.S. shale plays, Poland and the Iraqi Kurdistan Region.

The following table summarizes components of exploration expenses:


(In millions)	2011		2010
Dry well and unproved property impairment	$	357	$	223
Geological, geophysical, seismic		120		116
Other		167		159

Total exploration expenses	$	644	$	498

Loss on early extinguishment of debt relates to debt retirements in February and March of 2011 and in April of 2010. See Item 8. Financial Statements and Supplementary Data—Note 17 to the consolidated financial statements for additional discussion of these transactions.

Provision for income taxes increased $545 million from 2010 to 2011 in part due to the increase in pretax income. In 2011, we increased the valuation allowance against foreign tax credits because it is more likely than not that we will be unable to realize all U.S. benefits on foreign taxes accrued in 2011. A higher price and production outlook over the next several years for Norway due to better than expected performance contributed to generating these excess foreign tax credits. The following is an analysis of the effective income tax rates for 2011 and 2010:


	2011			2010
Statutory rate applied to income from continuing operations before income taxes		35	%		35	%
Effects of foreign operations, including foreign tax credits		6			20
Change in permanent reinvestment assertion		5			-
Adjustments to valuation allowances		14			(2)
Tax law changes		1			1

Effective income tax rate on continuing operations		61	%		54	%

The effective tax rate is influenced by a variety of factors including the geographical and functional sources of income, the relative magnitude of these sources of income, foreign currency remeasurement effects, and tax legislation changes. The provision for income taxes is allocated on a discrete, stand-alone basis to pretax segment income and to individual items not allocated to segments. The difference between the total provision and the sum of the amounts allocated to segments and to individual items not allocated to segments is reported in “Corporate and other unallocated items” shown in Item 8. Financial Statements and Supplementary Data—Note 8 to the consolidated financial statements.

Effects of foreign operations – The effects of foreign operations on our effective tax rate decreased in 2011 as compared to 2010, primarily due to the suspension of all production operations in Libya in the first quarter of 2011, where the statutory tax rate is in excess of 90 percent.

Change in permanent reinvestment assertion – In the second quarter of 2011, we recorded $716 million of deferred U.S. tax on undistributed earnings of $2,046 million that we previously intended to permanently reinvest in foreign operations. Offsetting this tax expense were associated foreign tax credits of $488 million. In addition, we reduced our valuation allowance related to foreign tax credits by $228 million due to recognized deferred U.S. tax on previously undistributed earnings.

Adjustments to valuation allowance – In 2011, we increased the valuation allowance against foreign tax credits because it is more likely than not that we will be unable to realize all U.S. benefits on foreign taxes accrued in 2011.

See Item 8. Financial Statements and Supplementary Data—Note 10 to the consolidated financial statements for further information about income taxes.

Discontinued operations reflect the June 30, 2011 spin-off of our downstream business and the historical results of those operations, net of tax, for all periods presented. See Item 8. Financial Statements and Supplementary Data—Note 3 to the consolidated financial statements.

Segment Results: 2011 compared to 2010

Segment income for 2011 and 2010 is summarized and reconciled to net income in the following table.


(In millions)	2011		2010
E&P
United States	$	366	$	251
International		1,791		1,690

E&P segment		2,157		1,941
OSM		256		(50)
IG		178		142

Segment income		2,591		2,033
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(326)		(202)
Foreign currency remeasurement of taxes		9		32
Impairments		(195)		(286)
Loss on early extinguishment of debt		(176)		(57)
Tax effect of subsidiary restructuring		(122)		-
Deferred income taxes		(61)		(45)
Water abatement – Oil Sands		(48)		-
Eagle Ford transaction costs		(10)		-
Gain on dispositions		45		407

Income from continuing operations		1,707		1,882
Discontinued operations		1,239		686

Net income	$ 2,946		$ 2,568

United States E&P income increased $115 million from 2010 to 2011. The majority of the income increase was due to higher liquid hydrocarbon realizations in 2011, along with higher liquid hydrocarbon sales volumes, partially offset by higher DD&A in the Gulf of Mexico and increased exploration and operating costs.

International E&P income increased $101 million from 2010 to 2011. This increase was primarily related to higher liquid hydrocarbon realizations, partially offset by lower liquid hydrocarbon sales volumes and higher income taxes.

OSM segment income increased $306 million from 2010 to 2011. The increase in segment income was primarily the result of higher synthetic crude oil sales volumes and higher price realizations.

IG segment income increased $36 million from 2010 to 2011. The increase in income was primarily the result of higher LNG and methanol sales volumes, somewhat offset by lower Henry Hub gas prices.

Consolidated Results of Operations: 2010 compared to 2009

Revenues are summarized in the following table:


(In millions)	2010		2009
E&P	$	10,782	$	7,738
OSM		833		692
IG		150		50

Segment revenues		11,765		8,480
Elimination of intersegment revenues		(75)		(28)
Gain on U.K. natural gas contracts		-		72

Total revenues		$ 11,690		$ 8,524

E&P segment revenues increased $3,044 million from 2009 to 2010, primarily due to higher average liquid hydrocarbon and natural gas realizations, slightly offset by lower natural gas sales volumes. On average, our worldwide liquid hydrocarbon realizations were 30 percent higher in 2010 than in 2009 and our worldwide natural gas realizations were 18 percent higher.

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

Included in our E&P segment are supply optimization activities which include the purchase of commodities from third parties for resale. Supply optimization serves to aggregate volumes in order to satisfy transportation commitments and to achieve flexibility within product types and delivery points. See the Cost of revenues discussion as revenues from supply optimization are approximately equal to those costs. Higher average crude oil prices in 2010 compared to 2009 increased revenues related to supply optimization.

The following table gives details of net sales and average realizations of our U.S. operations.


	2010		2009
United States Operating Statistics
Net liquid hydrocarbon sales (mbbld)^(a)		70		64
Liquid hydrocarbon average realizations (per bbl)^(b)	$	72.30	$	54.67
Net natural gas sales (mmcfd)		364		373
Natural gas average realizations (per mcf)^(b)	$	4.71	$	4.14

^(a)	Includes crude oil, condensate and natural gas liquids.

^(b)	Excludes gains and losses on derivative instruments.

Liquid hydrocarbon sales volumes in 2010 benefited from the Droshky development in the Gulf of Mexico, which commenced production mid-year 2010.

The following table gives details of net sales and average realizations of our international operations.


	2010		2009
International Operating Statistics
Net liquid hydrocarbon sales (mbbld)^(a)
Europe		92		92
Africa		83		87

Total International		175		179
Liquid hydrocarbon average realizations (per bbl)^(b)
Europe	$	81.95	$	64.46
Africa		71.71		53.91
Total International	$	77.11	$	59.31
Net natural gas sales (mmcfd)
Europe^(c)		105		138
Africa		409		430

Total International		514		568
Natural gas average realizations (per mcf)^(b)
Europe	$	7.10	$	4.90
Africa		0.25		0.25
Total International	$	1.65	$	1.38

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

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

Compared to 2009, international natural gas sales volumes are lower primarily due to a turnarounds in 2010 in EG and the U.K.

OSM segment revenues increased $141 million from 2009 to 2010. Revenues were impacted by net gains of $25 million and $13 million on derivative instruments in 2010 and 2009. Excluding the derivatives impact, the increase in revenue reflects the 26 percent increase in synthetic crude oil realizations. Synthetic crude oil sales volumes were lower in 2010 due to the impact of the planned turnaround at the Muskeg River mine and upgrader that began in late March 2010 and halted production in April before a staged resumption of operations in May 2010.


	2010		2009
OSM Operating Statistics
Net synthetic crude oil sales (mbbld)^(a)		29		32
Synthetic crude average realizations (per bbl)	$	71.06	$	56.44

^(a)	Includes blendstocks.

IG segment revenues increased $100 million from 2009 to 2010 primarily due to higher commodity prices.

Income from equity method investments increased $76 million in 2010 from 2009 primarily due to the impact of higher commodity prices on the earnings of many of our equity method investees in 2010.

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

Cost of revenues increased $1,616 million from 2009 to 2010 primarily due the impact of higher crude oil prices on our supply optimization activities. Costs related to supply optimization were $2,530 million in 2010 compared to $1,445 million in 2009. Additionally, OSM segment costs were higher in 2010 due to the planned turnaround at the Muskeg River mine and the upgrader.

Purchases from related parties increased $26 million from 2009 as a result of purchases from the Alba LPG plant in EG, in which we own an equity interest. Higher liquid hydrocarbon prices in 2010 increased the value of those purchases.

Depreciation, depletion and amortization increased $122 million in 2010 from 2009. Since both our E&P and OSM segments apply the units-of-production method to the majority of their assets, the previously discussed increases or decreases in sales volumes generally result in similar changes in DD&A. Increased DD&A in 2010 reflects the impact of higher sales volumes at a higher rate of DD&A per barrel on our U.S. E&P assets. The DD&A rate (expense per barrel of oil equivalent), which is impacted by changes in proved reserves and capitalized costs, can also cause changes in our DD&A. The following table provides DD&A rates for our E&P and OSM segments.


($ per boe)	2010		2009
DD&A rate
E&P Segment
United States	$	22	$	18
International		9		9
OSM Segment	$	16	$	12

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

General and administrative expenses increased $40 million in 2010 compared to 2009 primarily due to additional compensation expense and higher defined benefit costs (see Item 8. Financial Statements and Supplementary Data—Note 20 to the consolidated financial statements for further information about defined benefit costs).

Other taxes increased $26 million in 2010 compared to 2009. With the increase in revenues, particularly related to higher prices, production and ad valorem taxes increased.

Exploration expenses were higher in 2010 than 2009 primarily due to higher dry well costs. Dry wells primarily related to Gulf of Mexico, Indonesia, Norway and various U.S. onshore properties in 2010 and to Europe and Africa in 2009. The following table summarizes the components of exploration expenses.


(In millions)	2010		2009
Dry well and unproved property impairment	$	223	$	83
Geological, geophysical, seismic		116		105
Other		159		119

Total exploration expenses	$	498	$	307

Loss on early extinguishment of debt relates to debt retirements in April of 2010. See Item 8. Financial Statements and Supplementary Data—Note 17 to the consolidated financial statements for additional discussion of these transactions.

Provision for income taxes increased $128 million from 2009 to 2010 primarily due to the increase in pretax income. The effective rate, however, decreased from 74 percent in 2009 to 54 percent in 2010. In 2009 more income was generated in high tax jurisdictions than in 2010. In addition, in 2009, it was determined that we may not be able to realize all recorded foreign tax benefits and therefore a valuation allowance was recorded against these benefits.

The following is an analysis of the effective income tax rates for 2010 and 2009:


	2010			2009
Statutory rate applied to income from continuing operations before income taxes		35	%		35	%
Effects of foreign operations, including foreign tax credits		20			16
Foreign currency remeasurement loss		-			11
Adjustments to valuation allowances		(2)			10
Tax law change		1			-
Other		-			2

Effective income tax rate on continuing operations		54	%		74	%

The effective tax rate is influenced by a variety of factors including the geographical and functional sources of income, the relative magnitude of these sources of income, foreign currency remeasurement effects, and tax legislation changes. See Item 8. Financial Statements and Supplementary Data—Note 10 to the consolidated financial statements for further information about income taxes.

Discontinued operations reflect the June 30, 2011 spin-off of our downstream business and the 2009 disposals of our E&P businesses in Ireland and Gabon and their historical operating results, net of tax, for all periods presented. See Item 8. Financial Statements and Supplementary Data—Notes 3 and 6 to the consolidated financial statements.

Segment Results: 2010 compared to 2009

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


(In millions)	2010		2009
E&P
United States	$	251	$	52
International		1,690		1,166

E&P segment		1,941		1,218
OSM		(50)		44
IG		142		90

Segment income		2,033		1,352
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items		(202)		(431)
Foreign currency remeasurement of taxes		32		(319)
Impairments		(286)		(45)
Loss on early extinguishment of debt		(57)		-
Deferred income taxes		(45)		-
Gain on dispositions		407		122
Gain on U.K. natural gas contracts^(a)		-		37

Income from continuing operations		1,882		716
Discontinued operations		686		747

Net income	$	2,568	$	1,463

^(a)	Amounts relate to natural gas contracts in the U. K. that were accounted for as derivative instruments and recorded at fair value.

United States E&P income increased $199 million from 2009 to 2010. The majority of the income increase was due to higher liquid hydrocarbon and natural gas realizations in 2010, along with higher liquid hydrocarbon sales volumes, partially offset by higher DD&A and higher exploration and operating costs. Exploration expenses were $275 million for 2010, compared to $153 million for 2009, reflecting increased geological and geophysical spending focused on shale plays and exploration dry well expense, primarily the Flying Dutchman well in the Gulf of Mexico.

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

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

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

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

Cash Flows

Net cash provided by continuing operations was $5,434 million in 2011 compared to $4,194 million in 2010 and $3,172 million in 2009. The $1,240 million increase in 2011 and the $1,022 million increase in 2010 primarily reflect increasing average realized prices.

Net cash used in investing activities related to continuing operations totaled $7,174 million in 2011 compared to $2,157 million in 2010 and $2,359 million in 2009. Significant investing activities include acquisitions, additions to property, plant and equipment and asset disposals.

Acquisitions in 2011 included proved and unproved assets in the Eagle Ford shale play in south Texas. See Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements for further information about the transactions.

The most significant additions to property, plant and equipment relate to our long-term projects, which cross several years. In our E&P segment, exploration and development projects in Angola impacted all three years. Development of fields tied back to the Alvheim FPSO occurred in 2009 and 2010. Spending on U.S. exploration and development projects has been increasing over the years, related to unconventional resource plays and Gulf of Mexico exploration when drilling was allowed. In the OSM segment, the AOSP Expansion 1, which began in 2008, was substantially complete in 2010.

Disposal of assets totaled $518 million, $1,368 million and $812 million in 2011, 2010 and 2009. Several sales of non-core assets in 2011 and acreage farmouts resulted in net proceeds of $518 million. In 2010, we closed the sale of our 20 percent outside-operated undivided interest in the Production Sharing Contract and Joint Operating Agreement in Block 32 offshore Angola for $1.3 billion. In 2009, we sold all of our operated and outside-operated interests in Ireland and Gabon, reporting the disposals as discontinued operations. We also sold our operated and a portion of our outside-operated Permian Basin producing assets in New Mexico and west Texas. See Item 8. Financial Statements and Supplementary Data – Note 6 to the consolidated financial statements for more information about dispositions.

Financing activities related to continuing operations resulted in a use of cash of $5,211 million in 2011, but provided cash of $1,343 million in 2010 and $737 million 2009. In connection with the spin-off, we distributed $1.6 billion to MPC in the second quarter of 2011. Early debt repayments of $2,498 million and $500 million occurred in 2011 and 2010. Purchases of common stock used $300 million in cash during 2011. Sources of cash in 2009 included the issuance of $1.5 billion in senior notes. Dividend payments were uses of cash in every year.

Liquidity and Capital Resources

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

Capital Resources

Credit Arrangements and Borrowings

At December 31, 2011, we had $4,815 million in long-term debt outstanding, $141 million of which is due within one year. We do not have any triggers on any of our corporate debt that would cause an event of default in the case of a downgrade of our credit ratings.

At December 31, 2011, we had no borrowings outstanding against our $3 billion revolving credit facility, the vast majority of which has a termination date of May 2013, and no commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.

Shelf Registration

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

Cash-Adjusted Debt-To-Capital Ratio

Our cash-adjusted debt-to-capital ratio (total debt-minus-cash to total debt-plus-equity-minus-cash) was 20 percent and 14 percent at December 31, 2011 and 2010.


(Dollars in millions)	2011		2010
Long-term debt due within one year	$	141	$	295
Long-term debt		4,674		7,601

Total debt	$	4,815	$	7,896

Cash	$	493	$	3,951
Equity	$	17,159	$	23,771
Calculation:
Total debt	$	4,815	$	7,896
Minus cash		493		3,951

Total debt minus cash		4,322		3,945

Total debt		4,815		7,896
Plus equity		17,159		23,771
Minus cash		493		3,951

Total debt plus equity minus cash	$	21,481	$	27,716

Cash-adjusted debt-to-capital ratio		20%		14%

Capital Requirements

Capital Spending

Our approved capital, investment and exploration budget for 2012 is $4,822 million. Additional details related to the 2012 budget are discussed in Outlook.

Other Expected Cash Outflows

We plan to make contributions of up to $113 million to our pension plans during 2012. As of December 31, 2011, $141 million of our long-term debt is due in the next twelve months.

Dividends of $0.80 per common share or $567 million were paid during 2011 reflecting quarterly dividends of $0.25 per share in the first two quarters and $0.15 per share in the two quarters after the spin-off of our downstream business. On January 27, 2012, we announced that our Board of Directors had declared a dividend of $0.17 cents per share on Marathon Oil common stock, payable March 12, 2012, to stockholders of record at the close of business on February 16, 2012. This is a 13 percent increase over the dividend paid in the preceding quarter.

Share Repurchase Program

Since January 2006, our Board of Directors has authorized a common share repurchase program totaling $5 billion. As of December 31, 2011, we had repurchased 78 million common shares at a cost of $3,222 million, with 66 million shares purchased for $2,922 million prior to the spin-off of our downstream business and 12 million shares acquired at a cost of $300 million in the third quarter of 2011. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The program’s authorization does not include specific price targets or timetables. The timing of purchases under the program will be influenced by cash generated from operations, proceeds from potential asset sales, cash from available borrowings and market conditions.

Our opinions concerning liquidity and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors including cash provided from operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and credit ratings by rating agencies. The discussion of liquidity above also contains forward-looking statements regarding expected capital, investment and exploration spending and planned funding of our pension plans. The forward-looking statements about our capital, investment and exploration budget are based on current expectations, estimates and projections and are not guarantees of future performance. The forward-looking statements about our common share repurchase program are

based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include prices of and demand for liquid hydrocarbons, natural gas and synthetic crude oil, actions of competitors, disruptions or interruptions of our production or oil sands mining and bitumen upgrading operations due to the shortage of skilled labor and unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other operating and economic considerations.

Contractual Cash Obligations

The table below provides aggregated information on our consolidated obligations to make future payments under existing contracts as of December 31, 2011.


(In millions)	Total		2012		2013- 2014		2015- 2016		Later Years
Long-term debt (excludes interest)^(a)	$	4,794	$	141	$	274	$	69	$	4,310
Lease obligations		275		64		69		53		89
Purchase obligations:
Oil and gas activities^(b)		2,709		541		814		549		805
Service and materials contracts^(c)		1,044		169		198		129		548
Transportation and related contracts		1,303		322		174		129		678
Drilling rigs and fracturing crews		1,079		506		551		22
Other		276		108		85		28		55

Total purchase obligations		6,411		1,646		1,822		857		2,086
Other long-term liabilities reported in the consolidated balance sheet^(d)		1,231		176		273		251		531
Total contractual cash obligations^(e)	$	12,711	$	2,027	$	2,438	$	1,230	$	7,016

^(a)	We anticipate cash payments for interest of $286 million for 2012, $542 million for 2013-2014, $535 million for 2015-2016 and $2,965 million for the remaining years for a total of $4,328 million.

^(b)	Oil and gas activities include contracts to acquire property, plant and equipment and commitments for oil and gas exploration such as costs related to contractually obligated exploratory work programs that are expensed immediately.

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

^(d)	Primarily includes obligations for pension and other postretirement benefits including medical and life insurance. We have estimated projected funding requirements through 2021. Also includes amounts for uncertain tax positions.

^(e)	This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of $1,510 million. See Item 8. Financial Statements and Supplementary Data – Note 18 to the consolidated financial statements.

Transactions with Related Parties

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

Off-Balance Sheet Arrangements

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

We will issue stand alone letters of credit when required by a business partner. Such letters of credit outstanding at December 31, 2011, 2010 and 2009 aggregated $231 million, $439 million and $224 million. Most of the letters of credit are in support of obligations recorded in the consolidated balance sheet. For example, they are issued to counterparties to insure our payments for outstanding company debt, future abandonment liabilities and prior to June 30, 2011, crude purchases by our downstream business which we spun-off on that date. The decline in the level of our outstanding letters of credit in 2011 is primarily related to the spin-off of our downstream business.

Outlook

Our Board of Directors approved a capital, investment and exploration budget of $4,822 million for 2012, including budgeted capital expenditures of $4,402 million which represented a 29 percent increase from 2011 spending. Our focus in 2012 continues to be our U.S. liquids-rich growth assets, which account for almost 65 percent of the 2012 budget. Further detail of our budget by segment and asset lifecycle is presented below. For additional information about expected exploration and development activities on specific assets see Item 1. Business.

Exploration and Production

The worldwide exploration and production budget for 2012 is $4,387 million, a 44 percent increase over 2011 capital spending. The exploration and production strategy is based on three key elements: a solid portfolio of base assets, growth assets and impact exploration. Almost two thirds, or $3,041 million of the budget is allocated to our growth assets and almost one half of that is targeted to ramp up our operations in the Eagle Ford shale play in Texas. We will also continue to build on our substantial positions in the Bakken and Anadarko Woodford shale plays and to establish our business in the emerging Niobrara shale play of the DJ Basin. Approximately $2.7 billion of our budget is concentrated in these four U.S. liquids-rich resource plays.

Spending on our base E&P assets is budgeted at $913 million for 2012. These assets include production operations in the Gulf of Mexico, Norway, U.S. conventional oil and gas plays, Equatorial Guinea, the U.K. and Libya which generate much of the cash that will be available for investment in our growth assets and exploration projects.

Impact exploration projects account for 9 percent, or $433 million of the 2012 budget and include conducting seismic surveys and drilling 12 – 18 gross (6 – 10 net) wells on prospects in the deepwater Gulf of Mexico, the Iraqi Kurdistan Region and Poland.

The above discussion includes forward-looking statements with respect to anticipated future exploratory and development drilling activity, investments in new and existing resource plays and potential development projects. Some factors which could potentially affect these forward-looking statements include pricing, supply and demand for petroleum products, the amount of capital available for exploration and development, regulatory constraints, drilling rig availability, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other geological, operating and economic considerations. The foregoing forward-looking statements may be further affected by the inability to obtain or delay in obtaining necessary government and third-party approvals or permits. The offshore developments could further be affected by presently known data concerning size and character of reservoirs, economic recoverability, future drilling success and production experience. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

Oil Sands Mining

The Oil Sands Mining segment budget for 2012 is $275 million. The 2012 budget includes funds for the initiation of debottlenecking projects, continued evaluation of Quest CCS and other capital expenditures. A final investment decision on Quest CCS is expected to be made in 2012, and is subject to regulatory approvals, stakeholder engagement, detailed engineering studies, as well as a final joint venture partner agreement.

Corporate and Other

The remaining $160 million of our 2012 budget is split roughly in half between capitalized interest on ongoing projects and other corporate activities. Additionally, $1 million is budgeted for our Integrated Gas segment.

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