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, 2013

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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes R 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  R

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 R 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 R 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.  R

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.

Large accelerated filer  R    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   R

The aggregate market value of Common Stock held by non-affiliates as of June 28, 2013: $24,462 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 696,944,638 shares of Marathon Oil Corporation Common Stock outstanding as of January 31, 2014.

Documents Incorporated By Reference:

Portions of the registrant’s proxy statement relating to its 2014 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

PART I
	Item 1.	Business	4
	Item 1A.	Risk Factors	25
	Item 1B.	Unresolved Staff Comments	32
	Item 2.	Properties	32
	Item 3.	Legal Proceedings	32
	Item 4.	Mine Safety Disclosures	32
PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	33
	Item 6.	Selected Financial Data	34
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	55
	Item 8.	Financial Statements and Supplementary Data	58
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	115
	Item 9A.	Controls and Procedures	115
	Item 9B.	Other Information	115
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	116
	Item 11.	Executive Compensation	116
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	116
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	117
	Item 14.	Principal Accounting Fees and Services	117
PART IV
	Item 15.	Exhibits, Financial Statement Schedules	118
		SIGNATURES	124

Definitions

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

AECO – Alberta Energy Company, a Canadian natural gas benchmark price.

AMPCO – Atlantic Methanol Production Company LLC, a company located in Equatorial Guinea 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 United States gallons liquid volume.

bbld – Barrels per day.

bboe – Billion barrels of oil equivalent. Natural gas is converted to a barrel of oil equivalent based on the energy equivalent, which on a dry gas basis is six thousand cubic feet 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 equivalence 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 on 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.

E.G. – Equatorial Guinea.

EGHoldings – Equatorial Guinea LNG Holdings Limited, a liquefied natural gas production company located in E.G. in which we own a 60 percent equity interest.

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 natural gas in an unproved area or find a new reservoir in a field previously found to be productive in another reservoir.

FASB – Financial Accounting Standards Board.

FPSO – Floating production, storage and offloading vessel.

IFRS – International Financial Reporting Standards.

Internal Losses –Production losses attributed to factors that are within our control which can be either planned, such as a planned turnaround, or unplanned, such as equipment failure.

International E&P – Our International Exploration and Production ("Int'l E&P") segment which explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as liquefied natural gas and methanol, in E.G.

IRS – United States Internal Revenue Service.

KRG – Kurdistan Regional Government.

LNG – Liquefied natural gas.

LPG – Liquefied petroleum gas.

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Light sweet crude - A crude oil with an American Petroleum Institute ("API") gravity of 38 degrees or more and a sulfur content of less than 0.5 percent.

Liquid hydrocarbons or liquids – Collectively, crude oil, condensate and natural gas liquids.

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 of 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.

mmta – Million metric tonnes per annum.

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.

NGL or NGLs – Natural gas liquid or natural gas liquids, which are naturally occurring substances found in natural gas, including ethane, butane, isobutane, propane and natural gasoline, that can be collectively removed from produced natural gas, separated into these substances and sold.

North America E&P ("N.A. E&P") – Our North America Exploration and Production segment which explores for, produces and markets liquid hydrocarbons and natural gas in North America.

OECD – Organization for Economic Cooperation and Development.

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.

Operational Availability –A term used to measure the ability of an asset to produce to its maximum capacity over a specified period of time.  This measurement considers Internal Losses that are within our control.

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 liquid hydrocarbon, natural gas and synthetic crude oil reserves are those quantities of liquid hydrocarbons, 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 for 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.

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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 liquid hydrocarbons, natural gas and synthetic crude oil 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 – United Kingdom Scottish Area Gas Evacuation system composed of a pipeline and processing terminal.

SAR or SARs – Stock appreciation right or stock appreciation rights.

SCOOP – South Central Oklahoma Oil Province.

SEC – United States 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 and 4-D factors in changes that occurred over time).

Total depth ("TD") – The bottom of a drilled hole, where drilling is stopped, logs are run and casing is cemented.

Total proved reserves – The summation of proved developed reserves and proved undeveloped reserves.

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.

WCS – Western Canadian Select, an oil index benchmark price.

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 sometimes burdened by overriding royalty interest or other interests.

WTI – West Texas Intermediate crude oil, an oil index benchmark 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 Annual Report on Form 10-K may include, but are not limited to statements that relate to (or statements that are subject to risks, contingencies or uncertainties that relate to): levels of revenues, income from operations, net income or earnings per share; levels of liquidity and the availability of financing options; budgets or levels of capital, exploration, environmental, construction or maintenance expenditures; the success or timing of completion of ongoing or anticipated capital, exploration, construction 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; quantitative or qualitative factors about market risk; the potential effect of judicial proceedings on our business and financial condition; levels of common share repurchases; the impact of government legislation and budgetary and tax measures; and the anticipated effects of actions of third parties such as competitors, or federal, foreign, state or local governments and regulatory authorities.

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PART I

Item 1. Business

General

Marathon Oil Corporation was incorporated in 2001 and is an international energy company engaged in the exploration, production and marketing of liquid hydrocarbons and natural gas, production and marketing of products manufactured from natural gas and oil sands mining with operations in the U.S., Angola, Canada, E.G., Ethiopia, Gabon, Kenya, the Kurdistan Region of Iraq, Libya, Norway and the U.K. We are based in Houston, Texas with our corporate headquarters at 5555 San Felipe Street, 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 stockholders 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. 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 for all periods prior to the spin-off with additional information in Item 8. Financial Statements and Supplementary Data - Note 3 to the consolidated financial statements.

Strategy and Results Summary

Our strategic imperatives are:

•Uncompromising focus on core values to protect our license to operate and drive business performance

• Investment in our people to grow and maintain our capabilities and competencies to ensure shareholders access to the full global opportunity set

• Relentless pursuit of operational and capital efficiency and recognition as the partner / operator of choice

• Acceleration of resource development to optimize value, grow profitable volumes and replace reserves

• Rigorous portfolio management integrated with robust capital allocation

• Quality resource capture through a focused exploration program and opportunistic business development

• Competitive shareholder value through disciplined long-term focus

We continue to focus on liquid hydrocarbon reserves and production worldwide, realizing significant increases in our three key unconventional liquids-rich plays in 2013: the Eagle Ford, Bakken and Oklahoma resource basins. In 2014, approximately 60 percent of our capital, investment and exploration spending budget is allocated to these areas and includes co-development of adjacent formations in parallel with the main horizons. Our exploration program includes prospects in E.G., Ethiopia, Gabon, the Gulf of Mexico, Kenya and the Kurdistan Region of Iraq.

We ended 2013 with proved reserves of approximately 2.2 bboe, an 8 percent increase over 2012. Proved reserve replacement was 194 percent, excluding dispositions.

During 2013, our cash additions to property, plant and equipment were $5.0 billion, including those related to discontinued operations, and we made acquisitions of $74 million. We expect continued spending, primarily funded with cash flow from operations or portfolio optimization, in exploration and development activities in order to realize continued reserve and sales volume growth. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Outlook, for discussion of our $5.9 billion capital, investment and exploration spending budget for 2014.

We continually evaluate ways to optimize our portfolio through acquisitions and divestitures and have exceeded our previously stated goal of divesting between $1.5 billion and $3.0 billion of assets over the period of 2011 through 2013, by closing or entering into agreements for approximately $3.5 billion in divestitures, of which $2.1 billion is from the sales of our Angola assets. The sale of our interest in Angola Block 31 closed in February 2014 and the sale of our interest in Angola Block 32 is expected to close in the first quarter of 2014. Additionally, in December 2013, we commenced efforts to market our assets in the North Sea, both in the U.K. and Norway, which would simplify and concentrate our portfolio to higher margin growth opportunities and increase our production growth rate.

The above discussion of strategy and results includes forward-looking statements with respect to the sale of our interest in Angola Block 32, the possible sale of our U.K. and Norway assets and projected spending and expected investment in exploration and development activities under the 2014 capital, investment and exploration budget. Some factors that could potentially affect the expected investment in exploration and development activities include changes in prices of and demand for liquid hydrocarbons, natural gas and synthetic crude oil, actions of competitors, occurrence of acquisitions or dispositions of oil and natural gas properties, future financial conditions, operating results and economic and/or regulatory factors affecting our businesses. The timing of closing

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the sale of our interest in Angola Block 32 is subject to customary closing conditions. The possible sale of our U.K. and Norway assets is subject to the identification of one or more buyers, successful negotiations, board approval and execution of definitive agreements. The projected spending under the 2014 capital, investment and exploration spending budget is a good faith estimate, 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.

The map below illustrates the locations of our worldwide operations.

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.

In the discussion that follows regarding our North America E&P, International E&P and Oil Sands Mining segments, references to net wells, acres, sales or investment indicate our ownership interest or share, as the context requires.

North America E&P Segment

We are engaged in oil and gas exploration, development and/or production activities in the U.S. and Canada.

Unconventional Resource Plays

Eagle Ford - As of December 31, 2013, we had approximately 211,000 net acres in the Eagle Ford in south Texas and 655 gross (493 net) operated producing wells in the Eagle Ford, Austin Chalk and Pearsall formations. With approximately 90 percent pad drilling in 2013, we continued to improve efficiencies and reduce development costs per well. The average spud-to-TD time per well decreased to 13 days during the last quarter of the year compared to 15 days in the same period of 2012. We reached TD on 299 gross operated wells and brought 307 gross operated wells to sales in 2013.

Throughout 2013, we evaluated the potential of downspacing to 40-acre and 60-acre spacing with several pilot programs. Overall, wells drilled in these programs at closer spacing showed improved completion efficiency which helped offset impacts due to tighter well spacing. Continued focus on stimulation design contributed to incremental improvements in well performance across our area of activity. Approximately 39 percent of our 2014 capital, investment and exploration budget is dedicated to the Eagle Ford. Our accelerated drilling plans include drilling 250 - 260 net wells (385 - 405 gross, of which we will operate 340 - 355) in 2014, an increase of almost 20 percent over 2013.

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Eagle Ford average net sales for 2013 were 81 mboed, composed of 51 mbbld of crude oil and condensate, 14 mbbld of NGLs and 94 mmcfd of natural gas, compared to 34 mboed in 2012, a 136 percent increase. Our 2013 exit rate was over 98 mboed, a 50 percent increase over December 2012. In 2013, we were able to transport approximately 70 percent of our Eagle Ford production by pipeline. We anticipate the volume of oil sold into pipelines will remain high, with the actual volume fluctuating from quarter to quarter as additional infrastructure to service the area is constructed and commensurate commitments for transportation are executed. The ability to transport more barrels by pipeline enables us to reduce costs, improve reliability and lessen our environmental footprint.

Evaluation of the Austin Chalk and Pearsall formations across our Eagle Ford acreage position in south Texas included four Austin Chalk wells and one well in the Pearsall formation in 2013. Early Austin Chalk production results suggest that the mix of crude oil and condensate, NGLs and natural gas is similar to Eagle Ford condensate wells. We plan to drill 5 to 12 additional gross wells in the Austin Chalk and Pearsall formations in 2014. We will continue to evaluate the Pearsall formation in 2014. Ongoing Austin Chalk and Eagle Ford co-development is planned, pending results from our early wells. Co-development will leverage the infrastructure investments we have made to support production growth across the Eagle Ford operating area.

Approximately 193 miles of gathering lines were installed in 2013 for a total of over 700 miles of operated gathering pipeline in the area. We now have 24 central gathering and treating facilities, with aggregate capacity of over 275 mboed. We also own and operate the Sugarloaf gathering system, a 37-mile natural gas pipeline through the heart of our acreage in Karnes, Atascosa, and Bee Counties of south Texas.

Bakken – We hold approximately 370,000 net acres in the Bakken shale oil play in North Dakota and eastern Montana, where we have been operating since 2006. Since inception, we have continuously sought improvement in efficiency and well performance through optimizing completion techniques. Our average time to drill a well continued to improve, averaging 15 days spud-to-TD in the last quarter of 2013, compared to 18 days in the same period of 2012. We have identified additional improvements to the 30-stage hydraulic fracturing designs put in place in 2012, which are expected to further increase both production rates and estimated ultimate recovery from our Bakken shale wells beyond the increases that were attained in 2012 and 2013. We reached TD on 76 gross operated wells and brought to sales 77 gross operated wells in 2013.  Our Bakken shale program includes plans to drill 80 - 90 net wells (200 - 220 gross, of which we will operate 75 - 85) in 2014. In addition, we plan to recomplete 22 - 26 gross wells to the stage design optimized in 2013.

Our net sales from the Bakken shale averaged 39 mboed in 2013, composed of 35 mbbld of crude oil and condensate, 2 mbbld of NGLs and 13 mmcfd of natural gas, a 34 percent increase over 29 mboed in 2012. Our production exit rate for 2013 was approximately 38 mboed. We sell our Bakken production primarily into local North Dakota markets via truck or pipeline in efforts to optimize price realizations and such production could be transported to other areas of the U.S. by the purchaser.

Oklahoma resource basins – We hold 209,000 net acres in unconventional Oklahoma resource basins, namely the Anadarko Woodford shale (including the SCOOP), the Southern Mississippi Trend, and the Granite Wash, of which approximately 147,000 net acres are held by production. We continued to add incremental acres to our SCOOP position in 2013. In the Anadarko Woodford shale, we reached TD on 10 gross operated wells and brought nine gross operated wells to sales in 2013. An additional four net non-operated Woodford wells were brought to sales. We spud three additional operated Woodford wells in the SCOOP near the end of the year.  We drilled two gross operated wells in the Southern Mississippi Trend and brought both wells to sales in the fourth quarter of 2013. We also participated in two gross non-operated Southern Mississippi Trend wells in 2013. Lastly, we spud our first operated well in the unconventional Granite Wash play near the end of 2013.

Sales from our Oklahoma resource basin plays in 2013 were primarily from the Anadarko Woodford shale and averaged 14 mboed, composed of 2 mbbld of crude oil and condensate, 4 mbbld of NGLs and 48 mmcfd of natural gas, for an increase of 68 percent over 2012 net sales of 8 mboed. Our accelerated drilling plans for the Oklahoma resource basins include drilling and completing 14 - 20 net (21 - 27 gross) operated wells in 2014, approximately double our 2013 program. Approximately six net non-operated wells are also expected to be completed.

See below for discussion of our conventional, primarily natural gas, production operations in Oklahoma.

Other United States

Gulf of Mexico – Production – On December 31, 2013, we held significant interests in 11 producing fields, 4 of which are company-operated. Average net sales for 2013 from the Gulf of Mexico were 17 mbbld of liquid hydrocarbons and 14 mmcfd of natural gas. Operational availability for our operated properties was strong at 97 percent, with internal unplanned losses of three percent.

We have a 65 percent operated working interest in the Ewing Bank Block 873 platform which is located 130 miles south of New Orleans, Louisiana. The platform 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.

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We have a 100 percent operated working interest in the Droshky development located on Green Canyon Block 244 and a 68 percent operated working interest in Ozona which is located on Garden Banks Block 515. The Ozona development ceased production in the first quarter of 2013 and is scheduled for abandonment in 2014.

We have a 50 percent working interest in the non-operated Petronius field on Viosca Knoll Blocks 786 and 830, located 130 miles southeast of New Orleans, which includes 14 producing wells. The Petronius platform is also capable of providing processing and transportation services to nearby third-party fields. A well side track project was successfully completed in 2013 and a similar project is planned for 2014.

We hold a 30 percent working interest in the non-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. A well side track project is planned for 2014.

We have an 18 percent working interest in the non-operated Gunflint field development located on Mississippi Canyon Blocks 948, 949, 992(N/2) and 993(N/2). The discovery well was drilled in 2008 and encountered pay in the Middle Miocene reservoirs. Two subsequent appraisal wells were drilled and evaluated in 2012 and 2013. First oil from this subsea tie-back development project is expected in 2016.

Gulf of Mexico – Exploration – We have a portfolio of over 17 prospects with multiple drilling opportunities in the Gulf of Mexico. As we evaluate these opportunities for drilling, we plan to seek partners to reduce our exploration risk on individual projects.

We have a 60 percent operated working interest in the Key Largo prospect located on Walker Ridge Block 578. The Key Largo prospect will be the first well drilled with a new ultra deep-water drillship for which we and another operator have recently secured a three-year contract. Drilling is expected to commence in the third quarter of 2014.

Prior to commencing drilling in September 2013, we reduced our working interest in the Madagascar prospect, located on De Soto Canyon Block 757, from 100 percent to 40 percent as a result of two farm-outs, which included drilling cost carries. Our operated exploration well on the Madagascar prospect did not encounter commercial hydrocarbons and the well costs and related unproved property were charged to exploration expense in 2013.

A deepwater oil discovery on the Shenandoah prospect, located on Walker Ridge Block 52, was drilled in 2009. We own a 10 percent non-operated working interest in this prospect. The first appraisal well on the Shenandoah prospect reached total depth in 2013. This appraisal well encountered more than 1,000 net feet of oil pay in multiple high-quality Lower Tertiary-aged reservoirs. Additional appraisal drilling is anticipated to begin in 2014.

In 2013, we were awarded 100 percent working interest leases in two Gulf of Mexico blocks: Keathley Canyon Block 153, an extension to the Meteor prospect on our existing Keathley Canyon Block 196 lease, and Keathley Canyon Block 340 on the Colonial prospect. Both of these blocks are inboard-Paleogene prospects.

Colorado – We hold leases with natural gas production in the Piceance Basin of Colorado, located in the Greater Grand Valley field complex, and held 154,000 net acres in the Niobrara shale located in the DJ Basin that were sold in June 2013. Net sales from Colorado averaged 2 mboed in 2013. We have no plans for operated drilling in Colorado in 2014.

Oklahoma – We have long-established operated and non-operated conventional production in several Oklahoma fields from which 2013 sales averaged 1 mbbld of liquid hydrocarbons and 43 mmcfd of natural gas. In 2013, we participated in seven gross non-operated wells in the state.

Texas/North Louisiana/New Mexico – We hold 268,000 net acres in these areas of which 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 three gross non-operated wells in the Haynesville shale play during 2013. Conventional production was primarily from the Mimms Creek, Pearwood and Oletha fields in 2013, with net sales averaging 5 mboed.

We also participate in several non-operated Permian Basin fields in west Texas and New Mexico. Net sales from this area averaged 7 mboed in 2013. We plan continued carbon dioxide flood programs in the Seminole and Vacuum fields during 2014.

Wyoming – We have ongoing enhanced oil recovery waterflood projects at the mature Bighorn Basin and Wind River Basin fields and at our 100 percent owned and operated Pitchfork field. We have conventional natural gas operations in the Greater Green River Basin and unconventional coal bed natural gas operations in the Powder River Basin. As of December 31, 2013, we had plugged and abandoned 376 of the total 600 wells in the Powder River Basin and expect production to cease in March 2014 as we wind down those operations.

Our Wyoming net sales averaged 16 mbbld of liquid hydrocarbons and 48 mmcfd of natural gas during 2013. We drilled 2 gross operated development wells in Wyoming in 2013 and plan to drill 10 gross operated wells in 2014. In addition, we own

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and operate the 420-mile Red Butte Pipeline. This crude oil pipeline connects Silvertip Station on the Montana/Wyoming state line to Casper, Wyoming.

Canada

We hold interests in both operated and non-operated exploration stage oil sand leases in Alberta, Canada, which would be developed using in-situ methods of extraction. These leases cover approximately 142,000 gross (54,000 net) acres in four project areas: Namur, in which we hold a 70 percent operated interest; Birchwood, in which we hold a 100 percent operated interest; Ells River, in which we hold a 20 percent non-operated interest; and Saleski in which we hold a 33 percent non-operated interest.

During the first quarter of 2012, we submitted a regulatory application relating to our Canada in-situ assets at Birchwood, for a proposed 12 mbbld steam assisted gravity drainage ("SAGD") demonstration project. We expect to receive regulatory approval for this project by the end of 2014.  Upon receiving this approval, we will further evaluate our development plans.

Acquisitions and Dispositions

In July 2013, we acquired 4,800 net undeveloped acres in the core of the Eagle Ford shale in a transaction valued at $97 million, including carried interest of $23 million.

In June 2013, we closed the sale of our interests in the DJ Basin for proceeds of $19 million. A pretax loss of $114 million was recorded in the second quarter of 2013.

In February 2013, we closed the sale of our interest in the Neptune gas plant, located onshore Louisiana, for proceeds of $166 million. A $98 million pretax gain was recorded in the first quarter of 2013.

In February 2013, we conveyed our interests in the Marcellus natural gas shale play to the operator. A $43 million pretax loss on this transaction was recorded in the first quarter of 2013.

In January 2013, we closed the sale of our remaining assets in Alaska, for proceeds of $195 million. A pretax gain of $55 million was recorded in 2013.

The above discussions include forward-looking statements with respect to accelerated rig and drilling activity in the Eagle Ford, Bakken, and Oklahoma resource basins, possible increased recoverable resources from improvements to the 30-stage hydraulic fracturing designs in the Bakken resource play, infrastructure improvements in the Eagle Ford resource play, potential development plans for the Austin Chalk and Pearsall formations in the Eagle Ford resource play and for the Petronius and Neptune fields in the Gulf of Mexico, anticipated future exploratory and development drilling activity, projected spending under the 2014 capital, investment and exploration spending budget, planned use of carbon dioxide flood programs, the abandonment of the Powder River Basin in Wyoming, the abandonment of the Ozona development in the Gulf of Mexico, the timing of first oil from the Gunflint development in the Gulf of Mexico, and the timing of project sanction for the the SAGD project. The average times to drill a well may not be indicative of future drilling times. Current production rates may not be indicative of future production rates. Some factors which could possibly affect these forward-looking statements include pricing, supply and demand for liquid hydrocarbons and natural gas, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, availability of materials and labor, other risks associated with construction projects, the inability to obtain or delay in obtaining necessary government and third-party approvals and permits, 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 projected spending under the 2014 capital, investment and exploration spending budget is a good faith estimate, and therefore, subject to change. The SAGD project may further be affected by board approval and transportation logistics. 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 difficult to predict. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

International E&P Segment

We are engaged in oil and gas exploration, development and/or production activities in Angola, E.G., Ethiopia, Gabon, Kenya, the Kurdistan Region of Iraq, Libya, Norway, and the U.K. We also include the results of our natural gas liquefaction operations and methanol production operations in E.G. in our International E&P segment.

Africa

Equatorial Guinea – Production – We own a 63 percent operated working interest under a PSC in the Alba field which is offshore E.G. During 2013, E.G. net liquid hydrocarbon sales averaged 34 mbbld and net natural gas sales averaged 442 mmcfd. Operational availability from our company-operated facilities continues to be excellent and averaged 99 percent in 2013, with internal unplanned losses of one percent. A compression project designed to maintain the production plateau two additional years and extend field life up to six years is underway and is expected to be operational in mid-2016.

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Dry natural gas from the Alba field, which remains after the condensate and LPG are removed by Alba Plant LLC, as discussed below, is supplied to AMPCO and EGHoldings under long-term contracts at fixed prices. Because of the location and limited local demand for natural gas in E.G., we consider the prices under the contracts with Alba Plant LLC, EGHoldings and AMPCO to be comparable to the price that could be realized from transactions with unrelated parties in this market under the same or similar circumstances. Any dry gas not sold is returned offshore and reinjected into the Alba field for later production.

Equatorial Guinea – Exploration – We hold a 63 percent operated working interest in the Deep Luba discovery on the Alba Block and an 80 percent operated working interest in the Corona well on Block D. We plan to develop Block D through a unitization with the Alba field, which is currently being negotiated. We also have an 80 percent operated working interest in exploratory Block A-12 offshore Bioko Island, located immediately west of our operated Alba Field. We have secured a rig to drill at least two exploration prospects and one Alba field infill well in 2014.

Equatorial Guinea – Gas Processing – We 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 some of the remaining dry natural gas in its operations. During 2013, the gross quantity of natural gas supplied to the LPG production facility was 866 mmcfd, from which 6 mbbld of secondary condensate and 21 mbbld of LPG were produced by Alba Plant LLC.

We also own 60 percent of EGHoldings and 45 percent of AMPCO, both of which are accounted for as equity method investments. EGHoldings operates an LNG production facility and AMPCO operates a methanol plant, both located on Bioko Island. These facilities allow us to monetize natural gas reserves from the Alba field.

EGHoldings' 3.7 mmta LNG production facility sells LNG under a 3.4 mmta, or 460 mmcfd, sales and purchase agreement through 2023. 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. Gross sales of LNG from this production facility totaled 3.98 mmta in 2013. Operational availability was 97 percent in 2013, including a planned turnaround, while internal unplanned losses were less than one percent.

AMPCO had gross sales totaling 1.01 mmt in 2013. Operational availability for this methanol plant was 90 percent in 2013 and internal unplanned losses were 10 percent. Production from the plant is used to supply customers in Europe and the U.S.

Libya – We hold a 16 percent non-operated working interest in the Waha concessions, which encompass almost 13 million acres located in the Sirte Basin of eastern Libya. Beginning in the third quarter of 2013, our Libya production operations were impacted by third-party labor strikes at the Es Sider oil terminal. We have had no oil liftings since July 2013. Uncertainty around production and sales levels from Libya have existed since the first quarter of 2011 when production operations were suspended until the fourth quarter of that year. We and our partners in the Waha concessions continue to assess the situation and the condition of our assets in Libya.

Angola – During 2013, we entered into agreements to sell our Angola assets. See discussion of the transactions in the Acquisitions and Dispositionssection below.

Gabon – We hold a 21.25 percent non-operated working interest in the Diaba License G4-223 and its related permit offshore Gabon, which covers 2.2 million gross (476,000 net) acres. The Diaman-1B well reached total depth in the third quarter of 2013, encountering 160-180 net feet of hydrocarbon pay in the deepwater pre-salt play. Preliminary analysis suggests that the hydrocarbons are natural gas with condensate content, pending results of ongoing analysis of well data. Multiple additional pre-salt prospects have been identified on this License.

In late October 2013, we were the high bidder as operator of two deepwater blocks in the pre-salt play offshore Gabon. One of the blocks has since been withdrawn by the government. Award of the other block is subject to government approval and negotiation of an exploration and production sharing contract.

Kenya – We hold a 50 percent non-operated working interest in Block 9, consisting of 3.9 million gross (1.9 million net) acres in northwest Kenya. The first exploratory well on Block 9, the Bahasi-1, completed drilling in the fourth quarter of 2013 and was plugged and abandoned. The Sala-1 exploration well is expected to spud in February 2014 on the eastern side of Block 9, where previous wells drilled in the sub-basin confirmed a working petroleum system. We have the right to assume the role of operator on Block 9 if a commercial discovery is made.

We also hold a 15 percent non-operated working interest in Block 12A, covering 5 million gross (750,000 net) acres, which is also located in northwest Kenya. Seismic acquisition on Block 12A began in 2013 and will be completed in the first quarter of 2014.

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Ethiopia – We hold a 20 percent non-operated interest in the onshore South Omo Block in Ethiopia. The concession has an area of approximately 5.4 million gross (1.1 million net) acres. The Sabisa-1 exploration well encountered reservoir quality sands, oil and heavy gas shows and a thick shale section. The presence of oil prone source rocks, reservoir sands and good seals is encouraging for the numerous fault bounded traps identified in the basin. Because of mechanical issues, the well was abandoned before a full evaluation could be completed. The Tultule-1 exploration well was also drilled in 2013, approximately two miles from the Sabisa-1 well in a frontier rift basin and was plugged and abandoned. At least two additional exploration wells are planned for the eastern side of the block in 2014 to test multiple sub-basins. The first of those wells, Shimela-1, is expected to spud in March 2014.

Europe

As discussed above, we commenced efforts in December 2013 to market our assets in the North Sea, including Norway and the U.K.

Norway – Production – At the end of 2013, we operated 9 licenses and held interests in 6 non-operated licenses, which encompass approximately 286,000 net acres offshore on the Norwegian continental shelf. In 2013, net sales from Norway averaged 71 mbbld of liquid hydrocarbons and 51 mmcfd of natural gas.

Our production operations in Norway are centered around the Alvheim complex which consists of an FPSO with subsea infrastructure tied to several producing developments. Produced oil is transported by shuttle tanker and produced natural gas is transported to the SAGE system by pipeline. Production in 2013 continued to benefit from slower than expected decline as a result of infill well success, reservoir management techniques, extended drilling capability and technology application. We safely completed a planned turnaround in nine days in 2013 on time and on budget. Operational availability continued to be a strong factor in 2013 performance with a rate of 96 percent and internal unplanned losses of one percent.

The Alvheim development is comprised of the Kameleon, East Kameleon and Kneler fields (PL 036C, PL 088BS and PL 203), in each of which we have a 65 percent operated working interest, and the Boa field, in which we have a 58 percent operated working interest. At the end of 2013, the Alvheim development included 12 producing, 3 temporarily shut-in and 2 water disposal wells. One infill well is planned for 2014 along with several well workovers.

The Vilje field (PL 036D), in which we own a 47 percent operated working interest, began producing through the Alvheim complex in August 2008. Vilje has two subsea templates and two production wells, and is tied back through a 12-mile pipeline to the Alvheim FPSO. A third production well, Vilje Sor, will be developed as a subsea tieback to the Vilje field. Production start-up is expected in the first half of 2014.

The Volund field (PL 150 and PL 150B), located five miles south of the Alvheim complex consists of four production wells and one water injection well at December 31, 2013. We own a 65 percent operated working interest in Volund.

The Viper oil discovery, in the immediate vicinity of the Volund Field, was announced in November 2009. Along with our partners, we are evaluating a possible tie-back to the Alvheim complex of the Viper discovery as a combined development with the 1997 Kobra discovery. Both discoveries are within PL203 where we hold a 65 percent operated working interest.

Norway – Exploration – The Boyla field (PL 340), formerly the Marihone discovery, is located approximately 17 miles south of the Alvheim complex. In October 2012, the Norwegian Ministry of Petroleum and Energy approved the plan for the development and operation of the Boyla field in which we hold a 65 percent operated working interest. Further development drilling is planned in the Boyla field in 2014, with first production expected in early 2015. Near Boyla, the Caterpillar discovery (PL 340BS) made in 2011 continues to be evaluated as a tie-back to the Alvheim complex through Boyla.

The Darwin (formerly Veslemoy) exploration well was drilled in the first quarter of 2013 on PL 531, in which we hold a 10 percent non-operated fully-carried working interest, and was plugged and abandoned. The 30 percent non-operated Sverdrup exploration well on PL 330 offshore Norway was drilled in the third quarter of 2013 and has been plugged and abandoned.

In January 2013, we were awarded a 20 percent non-operated working interest in PL 694, which consists of three blocks, south of the Sverdrup prospect area. We were also awarded additional acreage in the North Sea, north of the Alvheim area in PL 203B. Our 65 percent working interest and role as operator are the same as PL 203. In addition, in 2013 we withdrew from three licenses (PL505, PL505BS and PL570).

United Kingdom – Net sales from the U.K. averaged 15 mbbld of liquid hydrocarbons and 32 mmcfd of natural gas in 2013. 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 and East Brae fields are natural gas condensate fields which are produced via the Brae Bravo and the East Brae platforms, respectively. The East Brae platform also hosts the nearby Braemar field in which we have a 28 percent working interest. Two development wells are in the West Brae program, with the first to be spud in 2014. Operational availability was 92 percent and internal unplanned losses were eight percent.

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The strategic location of the Brae platforms, along with pipeline and onshore infrastructure, has generated third-party processing and transportation business since 1986. Currently, the operators of 30 third-party fields are contracted to use the Brae system and 62 mboed are being processed or transported through the Brae infrastructure. In addition to generating processing and pipeline tariff revenue, this third-party business optimizes infrastructure usage.

The working interest owners of the Brae area producing assets collectively own a 50 percent interest in the non-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.

We own working interests in the non-operated Foinaven area complex, consisting of a 28 percent working interest in the main Foinaven field, a 47 percent working interest in East Foinaven and a 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.

Poland – After an extensive evaluation of our exploration activities in Poland and unsuccessful attempts to find commercial levels of hydrocarbons, we have elected to conclude operations in the country. During 2013, we relinquished 7 of our 11 operated concessions to the government and are in the process of relinquishing the remainder.

Other International

Kurdistan Region of Iraq – In aggregate, we have access to approximately 145,000 net acres in the Kurdistan Region of Iraq. We have interests in two non-operated blocks located north-northwest of Erbil: Atrush with 15 percent working interest and Sarsang with 25 percent working interest. We also have a 45 percent operated working interest in the Harir block located northeast of Erbil.

On the non-operated Atrush block, following the successful appraisal program and a declaration of commerciality, a plan for field development was approved by the Kurdistan Ministry of Natural Resources in September 2013.  The development project will consist of drilling three production wells and constructing a central processing facility. We expect first production by early 2015 with estimated initial gross production of approximately 30 mbbld of oil. The approval of the field development plan for Phase 1 provides for a 25-year production period. Subject to further drilling and testing results, and partner and government approvals, a potential Phase 2 development could add an additional gross 30 mbbld facility. Within the potential Phase 2 development area, the Atrush-3 appraisal well, located approximately four miles east of existing wells, confirmed the extension of the oil bearing reservoirs and has been suspended as a potential future producer. Testing has commenced on the Atrush-4 development well, spud in October 2013, with anticipated completion in the first quarter of 2014. The Atrush-5 development well is expected to spud in the second quarter of 2014.

On the non-operated Sarsang block, tests have been completed on the Gara well. All zones were water-wet and the well was plugged and abandoned in August 2013. On the Mangesh well, five drill stem tests have been completed and further testing is planned. The East Swara Tika exploration well, which began in July 2013, has been drilled to a depth of 5,300 feet toward a planned total depth of 11,000 feet. This well will test additional resource potential to the northeast of the Swara Tika discovery.

On the operated Harir block, we announced the Mirawa-1 discovery in October 2013. The Mirawa-1 was drilled to a total depth of approximately 14,000 feet and encountered multiple stacked oil and natural gas producing zones with equipment constrained test flow rates of more than 11 mbbld of oil, 72 mmcfd of non-associated natural gas and 1,700 bbld of condensate. We have suspended the well for potential future use as a producing well. The Jisik-1 prospect, located nine miles to the northwest of the Mirawa-1 discovery, will test a similar structure. Drilling on the Jisik-1 prospect commenced in December 2013 and is expected to reach total depth in the second quarter of 2014. The Mirawa-2 appraisal well is expected to spud in the third quarter of 2014, subject to government approval of the Mirawa appraisal plan.

Acquisitions and Dispositions

In June and December 2013, we entered into agreements, valued in total at $2.1 billion before closing adjustments, to sell our non-operated 10 percent working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32. The sale of our interest in Block 31 closed in February 2014 and the sale of our interest in Block 32 is expected to close in the first quarter of 2014. Our Angola operations are reported as discontinued operations for all periods presented.

In October of 2013, we transfered our 45 percent working interest and operatorship in the Safen Block in the Kurdistan Region of Iraq at a pretax loss of $17 million.

In January 2013, government approval was received for our acquisition of a 20 percent non-operated interest in the onshore South Omo concession in Ethiopia.

The above discussions include forward-looking statements with respect to anticipated future exploratory and development drilling activity in the Kurdistan Region of Iraq, Ethiopia, Kenya, Norway, the U.K., and E.G., the anticipated start-up date of the

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compression project in E.G., the unitization of Block D and the Alba field in E.G., the award of one block in Gabon, plans to exit Poland, the possible sale of our U.K. and Norway assets, the timing of first production from the Boyla field, the timing of first production from the Atrush development, a potential Phase 2 development in the Atrush block, other potential development projects and the sale of our interest in Angola Block 32. Some factors which could possibly affect these forward-looking statements include pricing, supply and demand for liquid hydrocarbons and natural gas, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, the inability to obtain or delay in obtaining necessary government and third-party approvals and permits, 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 award of the block in Gabon is subject to government approval and negotiation of an exploration and production sharing contract. The possible sale of our U.K. and Norway assets is subject to the identification of one or more buyers, successful negotiations, board approval and execution of definitive agreements. The timing of closing the sale of our interest in Block 32 is subject to customary closing conditions. 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 difficult to predict. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

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Productive and Drilling Wells

For our North America E&P and International E&P segments and discontinued operations combined, the following tables set forth gross and net productive wells and service wells as of December 31, 2013, 2012 and 2011 and drilling wells as of December 31, 2013.

	Productive Wells(a)
	Oil		Natural Gas		Service Wells		Drilling Wells
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
2013
U.S.	6,632	2,568	2,763	1,482	2,349	744	58	28
E.G.	—	—	16	11	2	1	—	—
Other Africa	1,072	175	7	1	99	16	8	1
Total Africa	1,072	175	23	12	101	17	8	1
Total Europe	77	34	40	16	28	11	—	—
Total Other International	—	—	—	—	—	—	2	1
Worldwide	7,781	2,777	2,826	1,510	2,478	772	68	30
2012
U.S.	6,191	2,315	3,208	1,906	2,328	736
E.G.	—	—	14	9	4	3
Other Africa	1,050	171	6	1	101	16
Total Africa	1,050	171	20	10	105	19
Total Europe	77	34	40	16	28	11
Worldwide	7,318	2,520	3,268	1,932	2,461	766
2011
U.S.	5,809	2,058	3,121	1,876	2,313	734
E.G.	—	—	14	9	4	3
Other Africa(b)	—	—	—	—	1	—
Total Africa	—	—	14	9	5	3
Total Europe	73	31	40	16	28	10
Worldwide	5,882	2,089	3,175	1,901	2,346	747

^(a)  Of the gross productive wells, wells with multiple completions operated by us totaled 204, 188 and 168 as of December 31, 2013, 2012 and 2011. 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.

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Drilling Activity

For our North America E&P and International E&P segments and discontinued operations combined, 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
2013
U.S.	237	20	—	257	73	13	3	89	346
Total Africa	4	—	—	4	1	—	2	3	7
Total Europe	—	—	—	—	—	—	2	2	2
Total Other International	—	—	—	—	—	—	1	1	1
Worldwide	241	20	—	261	74	13	8	95	356
2012
U.S.	172	21	2	195	117	13	9	139	334
Total Africa	4	—	—	4	1	—	—	1	5
Total Europe	3	—	—	3	—	—	—	—	3
Worldwide	179	21	2	202	118	13	9	140	342
2011
U.S.	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	3	70	37	4	2	43	113

^(a)  Activity in Libya through February 2011.

Acreage

We believe we have satisfactory title to our North America E&P and International E&P 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 acreage held in our North America E&P and International E&P segments and discontinued operations combined as of December 31, 2013.

	Developed		Undeveloped		Developed and Undeveloped
(In thousands)	Gross	Net	Gross	Net	Gross	Net
U.S.	1,720	1,289	695	523	2,415	1,812
Canada	—	—	142	54	142	54
Total North America	1,720	1,289	837	577	2,557	1,866
E.G.	45	29	183	164	228	193
Other Africa	12,921	2,109	18,549	4,463	31,470	6,572
Total Africa	12,966	2,138	18,732	4,627	31,698	6,765
Total Europe	179	88	2,030	748	2,209	836
Other International	—	—	466	145	466	145
Worldwide	14,865	3,515	22,065	6,097	36,930	9,612

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 In the ordinary course of business, based on our evaluations of certain geologic trends and prospective economics, we have allowed certain lease acreage to expire and may allow additional acreage to expire in the future. If production is not established or we take no other action to extend the terms of the leases, licenses, or concessions, undeveloped acreage listed in the table below will expire over the next three years. We plan to continue the terms of many of these licenses and concession areas or retain leases through operational or administrative actions. For leases expiring in 2014 that we do not intend to extend or retain, unproved property impairments were recorded in 2013.

	Net Undeveloped Acres Expiring
(In thousands)	2014	2015	2016
U.S.	145	60	46
E.G. (a)	36	—	—
Other Africa	189	2,605	189
Total Africa	225	2,605	189
Total Europe	216	372	1
Other International	—	20	—
Worldwide	586	3,057	236

^(a) An exploratory well is planned on this acreage in 2014.

Oil Sands Mining Segment

We hold a 20 percent non-operated interest in the AOSP, an oil sands mining and upgrading joint venture located in Alberta, Canada. The joint venture produces bitumen from oil sands deposits in the Athabasca region utilizing mining techniques and upgrades the bitumen to synthetic crude oils and vacuum gas oil.

The AOSP’s mining and 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. The 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 AOSP's Scotford upgrader is at Fort Saskatchewan, northeast of Edmonton, Alberta.  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 oils 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 of December 31, 2013, we own or have rights to participate in developed and undeveloped leases totaling approximately 159,000 gross (32,000 net) acres. The underlying developed leases are held for the duration of the project, with royalties payable to the province of Alberta. Synthetic crude oil sales volumes for 2013 were 48 mbbld and net-of-royalty production was 42 mbbld.

In December 2013, a Jackpine mine expansion project received conditional approval from the Canadian government. The project includes additional mining areas, associated processing facilities and infrastructure. The government conditions relate to wildlife, the environment and aboriginal health issues. We will begin evaluating the potential expansion project and government conditions after current debottlenecking activities are complete and reliability improves.

The governments of Alberta and Canada have agreed to partially fund Quest CCS for 865 million Canadian dollars.  In the third quarter of 2012, the Energy and Resources Conservation Board ("ERCB"), Alberta's primary energy regulator at that time, conditionally approved the project and the AOSP partners approved proceeding to construct and operate Quest CCS.   Government funding has commenced and will continue to be paid as milestones are achieved during the development, construction and operating phases.  Failure of the AOSP to meet certain timing, performance and operating objectives may result in repaying some of the government funding.  Construction and commissioning of Quest CCS is expected to be completed by late 2015.

In May 2013, we announced that we terminated our discussions with respect to a potential sale of a portion of our 20 percent outside-operated interest in the AOSP.

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The above discussion contains forward-looking statements with regard to the Jackpine mine expansion and Quest CCS. Some factors that could affect the Jackpine mine expansion include the inability to obtain or delay in obtaining third-party approvals and permits. The Quest CCS is subject to the inability to obtain or delay in obtaining government funds, the availability of materials and labor, unforeseen hazards such as weather conditions and other risks customarily associated with these types of projects. 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 difficult to predict. 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 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, 2013, 2012 and 2011. Included in our liquid hydrocarbon reserves are NGLs which represent approximately 7 percent, 6 percent and 5 percent of our total proved reserves on an oil equivalent barrel basis as of December 2013, 2012 and 2011. Approximately 72 percent, 63 percent and 40 percent of those NGL reserves are associated with our U.S. unconventional resource plays as of December 31, 2013, 2012 and 2011.

Reserves are disclosed by continent and 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. Due to the agreements entered in 2013 to sell our Angola assets, estimated proved reserves for Angola are reported as discontinued operations ("Disc Ops") for all presented periods. Approximately 73 percent of our December 31, 2013 proved reserves are located in OECD countries.

	North America			Africa			Europe
December 31, 2013	U.S.	Canada	Total	E.G.	Other	Total	Total	Disc Ops	Grand Total
Proved Developed Reserves
Liquid hydrocarbons (mmbbl)	292	—	292	55	176	231	78	19	620
Natural gas (bcf)	540	—	540	823	95	918	41	—	1,499
Synthetic crude oil (mmbbl)	—	674	674	—	—	—	—	—	674
Total proved developed reserves  (mmboe)	382	674	1,056	193	192	385	84	19	1,544
Proved Undeveloped Reserves
Liquid hydrocarbons (mmbbl)	324	—	324	43	39	82	11	9	426
Natural gas (bcf)	485	—	485	497	110	607	80	—	1,172
Synthetic crude oil (mmbbl)	—	6	6	—	—	—	—	—	6
Total proved undeveloped reserves  (mmboe)	405	6	411	125	57	182	25	9	627
Total Proved Reserves
Liquid hydrocarbons (mmbbl)	616	—	616	98	215	313	89	28	1,046
Natural gas (bcf)	1,025	—	1,025	1,320	205	1,525	121	—	2,671
Synthetic crude oil (mmbbl)	—	680	680	—	—	—	—	—	680
Total proved reserves (mmboe)	787	680	1,467	318	249	567	109	28	2,171

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	North America			Africa			Europe
December 31, 2012	U.S.	Canada	Total	E.G.	Other	Total	Total	Disc Ops	Grand Total
Proved Developed Reserves
Liquid hydrocarbons (mmbbl)	198	—	198	68	168	236	84	—	518
Natural gas (bcf)	546	—	546	980	99	1,079	28	—	1,653
Synthetic crude oil (mmbbl)	—	653	653	—	—	—	—	—	653
Total proved developed reserves  (mmboe)	289	653	942	231	185	416	88	—	1,446
Proved Undeveloped Reserves
Liquid hydrocarbons (mmbbl)	277	—	277	42	41	83	5	18	383
Natural gas (bcf)	497	—	497	444	110	554	75	—	1,126
Total proved undeveloped reserves  (mmboe)	360	—	360	116	59	175	18	18	571
Total Proved Reserves
Liquid hydrocarbons (mmbbl)	475	—	475	110	209	319	89	18	901
Natural gas (bcf)	1,043	—	1,043	1,424	209	1,633	103	—	2,779
Synthetic crude oil (mmbbl)	—	653	653	—	—	—	—	—	653
Total proved reserves (mmboe)	649	653	1,302	347	244	591	106	18	2,017

	North America			Africa			Europe
December 31, 2011	U.S.	Canada	Total	E.G.	Other	Total	Total	Disc Ops	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	43	82	13	18	251
Natural gas (bcf)	321	—	321	467	—	467	79	—	867
Total proved undeveloped reserves  (mmboe)	191	—	191	117	43	160	26	18	395
Total Proved Reserves
Liquid hydrocarbons (mmbbl)	279	—	279	117	222	339	97	18	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	239	618	117	18	1,800

The increase in proved reserves from 2012 to 2013 was primarily due to drilling programs in our U.S. unconventional shale plays and better than expected performance in Norway. Synthetic crude oil reserves also increased due to approval of an improved recovery project and price and cost changes.

The above estimated quantities of 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 proved 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

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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

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 his staff of Reserve Coordinators. Liquid hydrocarbon and natural gas reserve estimates are developed or reviewed by Qualified Reserves Estimators ("QREs"). QREs are engineers or geoscientists with at least 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 QRE training course. Reserve Coordinators screen all fields with proved reserves of 20 mmboe or greater, every year, to determine if a field review will be performed. Any change to proved reserve estimates in excess of 1 mmboe on a total field basis, within a single month, 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 is a registered Professional Engineer in the State of Texas. In his 26 years with Marathon Oil, he has held numerous engineering and management positions, most recently managing our OSM segment. He is a member of the Society of Petroleum Engineers ("SPE") and a former member of the Petroleum Engineering Advisory Council for the University of Texas at Austin.

Estimates of synthetic crude oil reserves are prepared by GLJ Petroleum Consultants ("GLJ") of Calgary, Canada, third-party consultants. Their reports for all years are filed as exhibits to this Annual Report on Form 10-K. The team lead responsible for the estimates of our synthetic crude oil reserves has over 35 years of experience in petroleum engineering and has conducted surface mineable oil sands evaluations since 1986. He is a member of SPE and served as regional director from 1998 through 2001. The second GLJ team member has 13 years of experience in petroleum engineering and has conducted surface mineable oil sands evaluations since 2009. Both are registered Practicing Professional Engineers 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 and validating our internal reserve estimates. We exceeded this percentage for the four-year period ended December 31, 2013. We have 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 parties 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. In the very limited instances where differences outside the 10 percent tolerance cannot be resolved by year end, a plan to resolve the difference is developed and senior management consent is obtained. The audit process did not result in any significant changes to our reserve estimates for 2013, 2012 or 2011.

During 2013, 2012 and 2011, Netherland, Sewell & Associates, Inc. ("NSAI") prepared a certification of the prior year's reserves for the Alba field in E.G. The NSAI summary reports are filed as an exhibit to this Annual Report on Form 10-K. Members of the NSAI team have many years of industry experience, having worked for large, international oil and gas companies before joining NSAI. The senior technical advisor has over 35 years of practical experience in petroleum geosciences, with over 16 years experience in the estimation and evaluation of reserves. The second team member has over 9 years of practical experience in petroleum engineering, with over 4 years experience in the estimation and evaluation of reserves. Both are registered Professional Engineers in the State of Texas.

Ryder Scott Company ("Ryder Scott") also performed audits of several of our fields in 2013, 2012 and 2011. Their summary reports are filed as exhibits to this Annual Report on Form 10-K. The team lead for Ryder Scott has over 22 years of industry experience, having worked for a major international oil and gas company before joining Ryder Scott. He is a member of SPE, where he served on the Oil and Gas Reserves Committee, and is a registered Professional Engineer in the State of Texas.

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Changes in Proved Undeveloped Reserves

As of December 31, 2013, 627 mmboe of proved undeveloped reserves were reported, an increase of 56 mmboe from December 31, 2012. The following table shows changes in total proved undeveloped reserves for 2013:

(mmboe)
Beginning of year	571
Revisions of previous estimates	4
Improved recovery	7
Purchases of reserves in place	16
Extensions, discoveries, and other additions	142
Dispositions	(4	)
Transfer to Proved Developed	(109	)
End of year	627

Significant additions to proved undeveloped reserves during 2013 included 72 mmboe in the Eagle Ford and 49 mmboe in the Bakken shale plays due to development drilling. Transfers from proved undeveloped to proved developed reserves included 57 mmboe in the Eagle Ford, 18 mmboe in the Bakken and 7 mmboe in the Oklahoma resource basins due to producing wells. Costs incurred in 2013, 2012 and 2011 relating to the development of proved undeveloped reserves, were $2,536 million, $1,995 million and $1,107 million.

A total of 59 mmboe was booked as a result of reliable technology. Technologies included statistical analysis of production performance, decline curve analysis, rate transient analysis, reservoir simulation and volumetric analysis. The statistical nature of production performance coupled with highly certain reservoir continuity or quality within the reliable technology areas and sufficient proved undeveloped locations establish the reasonable certainty criteria required for booking reserves.

Projects can remain in proved undeveloped reserves for extended periods in certain situations such as large development projects which take more than five years to complete, or the timing of when additional gas compression is needed. Of the 627 mmboe of proved undeveloped reserves at December 31, 2013, 24 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 E.G. that was sanctioned by our Board of Directors in 2004. The timing of the installation of compression is being driven by the reservoir performance with this project intended to maintain maximum production levels. Performance of this field since the Board sanctioned the project has far exceeded expectations. Estimates of initial dry gas in place increased by roughly 10 percent between 2004 and 2010. During 2012, the compression project received the approval of the E.G. government, allowing design and planning work to progress towards implementation, with completion expected by mid-2016. The other component of Alba proved undeveloped reserves is an infill well approved in 2013 and to be drilled late 2014.

Proved undeveloped reserves for the North Gialo development, located in the Libyan Sahara desert, were booked for the first time as proved undeveloped reserves in 2010. This development, 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. Anecdotal evidence from similar development projects in the region led to an expected project execution of more than five years from the time the reserves were initially booked. Interruptions associated with the civil unrest in 2011 and third-party labor strikes in 2013 have extended the project duration. There are no other significant undeveloped reserves expected to be developed more than five years after their original booking.

As of December 31, 2013, future development costs estimated to be required for the development of proved undeveloped liquid hydrocarbon, natural gas and synthetic crude oil reserves related to continuing operations for the years 2014 through 2018 are projected to be $2,894 million, $2,567 million, $2,020 million, $1,452 million and $575 million.

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

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Net Production Sold

	North America			Africa			Europe
	U.S.	Canada	Total	E.G.	Other	Total	Total	Disc Ops	Grand Total
2013
Liquid hydrocarbons (mbbld)(a)	149	—	149	34	24	58	86	10	303
Natural gas (mmcfd)(b)(c)	312	—	312	442	22	464	76	—	852
Synthetic crude oil (mbbld)(d)	—	42	42	—	—	—	—	—	42
Total production sold (mboed)	201	42	243	107	27	134	99	10	486
2012
Liquid hydrocarbons (mbbld)(a)	107	—	107	36	42	78	97	—	282
Natural gas (mmcfd)(b)(c)	358	—	358	428	15	443	86	—	887
Synthetic crude oil (mbbld)(d)	—	41	41	—	—	—	—	—	41
Total production sold (mboed)	166	41	207	108	44	152	111	—	470
2011
Liquid hydrocarbons (mbbld)(a)	75	—	75	38	5	43	101	—	219
Natural gas (mmcfd)(b)(c)	326	—	326	443	—	443	81	—	850
Synthetic crude oil (mbbld)(d)	—	38	38	—	—	—	—	—	38
Total production sold (mboed)	129	38	167	112	5	117	115	—	399

^(a)  The amounts correspond with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.

^(b)  U.S. natural gas volumes exclude volumes produced in Alaska prior to our disposal of those assets in 2013 that were stored for later sale in response to seasonal demand, although our reserves had been reduced by those volumes.

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

^(d)  Upgraded bitumen excluding blendstocks.

Average Sales Price per Unit

	North America						Africa							Europe
(Dollars per unit)	U.S.		Canada		Total		E.G.			Other		Total		Total		Disc Ops		Grand Total
2013
Liquid hydrocarbons (bbl)	$	85.20	$	—	$	85.20	$	60.34		$	122.92	$	86.29	$	112.60	$	104.77	$	93.83
Natural gas (mcf)	3.84		—		3.84		0.24		(a)	5.44		0.49		12.13		—		2.75
Synthetic crude oil (bbl)	—		87.51		87.51		—			—		—		—		—		87.51
2012
Liquid hydrocarbons (bbl)	$	85.80	$	—	$	85.80	$	64.33		$	127.31	$	98.52	$	115.16	$	—	$	99.46
Natural gas (mcf)	3.92		—		3.92		0.24		(a)	5.76		0.43		10.45		—		2.80
Synthetic crude oil (bbl)	—		81.72		81.72		—			—		—		—		—		81.72
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		(a)	0.70		0.24		9.75		—		2.96
Synthetic crude oil (bbl)	—		91.65		91.65		—			—		—		—		—		91.65

^(a)  Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and EGHoldings, which are equity method investees. We include our share of income from each of these equity method investees in our International E&P Segment.

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Average Production Cost per Unit^(a) 

	North America						Africa						Europe
(Dollars per boe)	U.S.		Canada(b)		Total		E.G.		Other(c)		Total		Total		Disc Ops		Grand Total
2013	$	13.60	$	55.42	$	20.79	$	2.88	$	7.40	$	3.80	$	13.68	$	11.89	$	14.47
2012	13.61		53.61		21.51		3.59		3.57		3.59		9.62		—		12.91
2011	16.51		59.04		25.97		2.92		12.22		3.34		8.85		—		14.42

^(a)  Production, severance and property taxes are excluded from the production costs used in this calculation. See Item 8. Financial Statements and Supplementary Data – Supplementary Information on Oil and Gas Producing Activities - Results of Operations for Oil and Gas Production Activities for more information regarding production cost.

^(b)  Production costs in 2011 include a $64 million water abatement accrual.

^(c)  Production operations ceased in Libya in February 2011, resuming in 2012, but ceased again in the third quarter of 2013. Fixed costs continue to be incurred in these periods of downtime.

Marketing and Midstream

Our operating segments include activities related to the marketing and transportation of substantially all of our liquid hydrocarbon, synthetic crude oil and natural gas production. These activities include the transportation of production to market centers, the sale of commodities to third parties and the storage of production. We balance our various sales, storage and transportation positions in order to aggregate volumes to satisfy transportation commitments and to achieve flexibility within product types and delivery points. Such activities can include the purchase of commodities from third parties for resale.

As discussed previously, we currently own and operate gathering systems and other midstream assets in some of our production areas. We continue to evaluate midstream infrastructure investments in connection with our development plans.

Delivery Commitments

We have committed to deliver quantities of crude oil and synthetic crude oil to customers under a variety of contracts. As of December 31, 2013, those contracts for fixed and determinable quantities were at variable, market-based pricing and related primarily to Eagle Ford and Bakken liquid hydrocarbon production and OSM synthetic crude oil production. A minimum of 54 mbbld of Eagle Ford liquid hydrocarbon production is to be delivered through mid-2017 under two contracts. Under a 6-year contract ending May 2016, 15 mbbld of Bakken liquid hydrocarbon production is to be delivered. Under a 3-year contract expected to commence mid-2014, 14 mbbld of synthetic crude oil production is to be delivered. Our current production rates and proved reserves are sufficient to meet these commitments. The Eagle Ford and OSM contracts also provide the options of delivering third-party volumes or paying a monetary shortfall penalty if production is inadequate. The Bakken contract carries no penalty for shortfalls.

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. Based upon statistics compiled in the "2013 Global Upstream Performance Review" published by IHS Herold Inc., we rank ninth among U.S.-based petroleum companies on the basis of 2012 worldwide liquid hydrocarbon and natural gas production. See Item 1A. Risk Factors for discussion of specific areas in which we compete and related risks.

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 for liquid hydrocarbons, synthetic crude oil and natural gas, as well as changes in competitive conditions in the markets we serve. Generally, results from oil and gas production and OSM 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,

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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 the 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 we operate have their own 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 strict 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 2012, the U.S. EPA published final New Source Performance Standards ("NSPS") and National Emissions Standards for Hazardous Air Pollutants ("NESHAP") that amended existing NSPS and NESHAP standards for oil and gas facilities as well as created a new NSPS for oil and gas production, transmission and distribution facilities. These rules, which were updated in August 2013, have been challenged, and negotiations with the U.S. EPA over proposed changes to the rules continue. Compliance with these new rules will result in an increase in the costs of control equipment and labor and require additional notification, monitoring, reporting and recordkeeping for some of our facilities. The U.S. EPA was also notified in December 2012 that seven northeastern states intend to sue the U.S. EPA for failure to include methane standards in these rules. If successfully challenged, the addition of methane standards could further increase our costs to comply with these rules.

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. Rather than issuing pre-construction permits for our facilities on Tribal Lands in North Dakota, in August of 2012, the U.S. EPA finalized an Interim Final Rule under the CAA that requires certain control equipment, recordkeeping, monitoring, and reporting with respect to these facilities. Compliance with this new rule will result in an increase in the costs of control, equipment and labor and will require additional notification, monitoring, reporting and recordkeeping for our facilities on Tribal Lands in North Dakota.

The U.S. EPA is expected to propose the results of its 5-year review of the 2008 ozone National Ambient Air Quality Standards (“NAAQS”) in 2014, which are expected to encompass a proposal for a lower ozone NAAQS. A more stringent ozone NAAQS could result in additional areas being designated as non-attainment, including areas in which we operate, which may result in an increase in costs for emission controls and requirements for additional monitoring and testing, as well as a more cumbersome permitting process. Although there may be an adverse financial impact (including compliance costs, potential permitting delays and increased regulatory requirements) associated with any regulation or other action by the U.S. EPA that lowers the ozone

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NAAQS, the extent and magnitude of that impact cannot be reliably or accurately estimated due to the present uncertainty regarding any additional measures and how they will be implemented.

At the end of 2013, the U.S. EPA indicated that, in addition to sources already regulated under the current NSPS subpart OOOO, the U.S. EPA is considering petitions from members of the public to address other sources of emissions from oil and gas operations such as pneumatics, equipment leaks, liquids unloading, and associated gas. At this time, it is uncertain how the U.S. EPA may address these sources (e.g., additional regulations or voluntary programs), what the scope may be, what emission control levels or technology are being considered or the U.S. EPA’s timing. Although there may be an adverse financial impact associated with any such 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 present uncertainty regarding any additional measures and how they will be implemented.

Climate Change

In 2010, the U.S. EPA promulgated rules that require 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 cases 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 additional regulation affecting the hydraulic fracturing process, including subjecting the process to regulation under the Safe Drinking Water Act. 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 issued a progress report in late 2012, and expects to issue a draft report for public comment and peer review in 2014, with a final report expected in 2016.

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 open-pit mines, 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 tailings 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 ERCB issued a directive which more clearly defines criteria for managing oil sands tailings. We believe that we are substantially in compliance with the directive at this time. We could incur additional costs if further new regulations are issued or if we fail to comply in a timely manner.

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 2013, sales to British Petroleum and its affiliates accounted for more than 10 percent of our annual revenues. For 2012, sales to Statoil and to Shell Oil and its affiliates each accounted for more than 10 percent of our annual revenues. For 2011, 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.

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Trademarks, Patents and Licenses

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

Employees

We had 3,359 active, full-time employees as of December 31, 2013. 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, 2014, are as follows:

Lee M. Tillman	52	President and Chief Executive Officer
John R. Sult	54	Executive Vice President and Chief Financial Officer
Sylvia J. Kerrigan	48	Executive Vice President, General Counsel and Secretary
Annell R. Bay	58	Vice President, Global Exploration
T. Mitch Little	50	Vice President, International and Offshore Production Operations
Lance W. Robertson	41	Vice President, North America Production Operations
Howard J. Thill	54	Vice President, Corporate, Government and Investor Relations

With the exception of Mr. Tillman, Mr. Sult and Mr. Robertson, 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.

• Mr. Tillman was appointed president and chief executive officer effective August 2013. Mr. Tillman is also a member of our Board of Directors. Prior to this appointment, Mr. Tillman served as vice president of engineering for ExxonMobil Development Company. Between 2007 and 2010, Mr. Tillman served as North Sea production manager and lead country manager for subsidiaries of ExxonMobil, located in Stavanger, Norway. Mr. Tillman began his career in the oil and gas industry at Exxon Corporation in 1989 as a research engineer and has extensive operations management and leadership experience.

• Mr. Sult was appointed executive vice president and chief financial officer effective September 2013. Prior to this appointment, Mr. Sult served as executive vice president and chief financial officer of El Paso Corporation from 2010 to 2012, senior vice president and chief financial officer from 2009 until 2010, and senior vice president, chief accounting officer and controller from 2005 until 2009.

• Ms. Kerrigan was appointed executive vice president, general counsel and secretary effective October 2012, and was appointed general counsel and secretary effective November 2009. Prior to these appointments, Ms. Kerrigan was assistant general counsel since January 2003.

• Ms. Bay was appointed vice president, global exploration effective July 2011. Ms. Bay joined Marathon Oil in June 2008 as senior vice president, exploration.

• Mr. Little was appointed vice president, international and offshore production operations in September 2013 and served as vice president, international production operations effective September 2012. Prior to this appointment, Mr. Little was resident manager for our Norway operations and served as general manager, worldwide drilling and completions. Mr. Little joined Marathon Oil in 1986 and has held a number of engineering and management positions of increasing responsibility.

• Mr. Robertson was appointed vice president, North America production operations in September 2013 and served as vice president, Eagle Ford production operations since October 2012. Mr. Robertson joined Marathon Oil in October 2011 as regional vice president, South Texas/Eagle Ford. Between 2004 and 2011, Mr. Robertson held a number of senior engineering and operations management roles of increasing responsibility with Pioneer Natural Resources in the U.S. and Canada.

• Mr. Thill was appointed vice president, corporate, government and investor relations effective January 2014, and 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://marathonoil.com/Investor_Center/Corporate_Governance/.

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Our Annual Reports 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. When considering an investment in our securities, you should carefully consider the risk factors included below as well as those matters referenced in the foregoing pages under "Disclosures Regarding Forward-Looking Statements" and other information included and incorporated by reference into this Annual Report on Form 10-K.

A substantial, 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:

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

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

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

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

• changes in weather patterns and climate;

• natural disasters such as hurricanes and tornadoes;

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

• the effect of conservation efforts;

• domestic and foreign governmental regulations and taxes; and

• general economic conditions worldwide.

The long-term effects of these and other factors on the prices of liquid hydrocarbons and natural gas 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 Annual Report on Form 10-K 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 and approved 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 periods ended December 31, 2013, 2012 and 2011, as well as other conditions in existence at those dates. 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.

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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:

• 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 cash flows from our proved liquid hydrocarbon, natural gas and synthetic crude oil reserves reflected in this Annual Report on Form 10-K 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 cash flows 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 periods ended December 31, 2013, 2012 and 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 cash flows 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 or 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;

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• title problems;

• pressure or irregularities in formations;

• equipment failures or accidents;

• fires, explosions, blowouts or 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;

• increased costs or operational delays resulting from shortages of water;

• 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 capital projects.

We may incur substantial capital expenditures and operating costs as a result of compliance with, and/or changes in environmental, health, safety and security laws and regulations, and, as a result, our business, financial condition, results of operations 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 and the protection of endangered species as well as laws, regulations, and other requirements 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, regulations, and other requirements. 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, regulations, and other requirements 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 clean-ups or curtail operations that could materially and adversely affect our business, financial condition, results of operations 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, regulations, and other requirements 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 2013, 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 2012 at the Doha Climate Change Conference,

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countries agreed to extend the Kyoto Protocol to 2020. However, the U.S. Senate has not ratified the Kyoto Protocol, nor is it clear whether the U.S. Senate plans to ratify this agreement in the future. If the U.S. does ratify the Kyoto Protocol in the future or signs a new international agreement, such actions could result in increased costs to operate and maintain our facilities, capital expenditures to install new emission controls at our facilities, and 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 is conducting a comprehensive research study on the potential effects that hydraulic fracturing may have on water quality and public health, issued a progress report in late 2012, and expects to issue a draft report for public comment and peer review in 2014, with a final report expected in 2016. 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 liquid hydrocarbons and natural gas, including from the 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.

Worldwide political and economic developments and changes in law could adversely affect 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 55 percent of our liquid hydrocarbon and natural gas sales volumes in 2013 was derived from production outside the U.S. and 47 percent of our proved liquid hydrocarbon and natural gas reserves as of December 31, 2013 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 within or outside of the U.S. There are many risks associated with operations in countries such as E.G., Angola, Ethiopia, Gabon, Kenya, the Kurdistan Region of Iraq and Libya, and in global markets including:

• changes in governmental policies relating to liquid hydrocarbon or natural gas 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, Iraq, Libya, Syria, Tunisia and Yemen. Some political regimes in these countries are threatened or have changed as a result of such unrest.

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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 legislation and other changes in law, 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. Changes in law could also adversely affect our results, including new regulations resulting in higher costs to transport our production by pipeline, rail car, truck or vessel or the adoption of government payment transparency regulations that could require us to disclose competitively sensitive commercial information or that could cause us to violate the non-disclosure laws of other countries.

Our commodity price risk management and trading activities may prevent us from fully benefiting from commodity price increases and may expose us to other risks, including counterparty risk.

To the extent that we engage in price risk management activities to protect ourselves against commodity price declines, we may be prevented from fully realizing the benefits of price increases above the levels of the derivative instruments used to manage price risk. In addition, our hedging arrangements may expose us to the risk of financial loss in certain circumstances, including instances in which the counterparties to our hedging contracts fail to perform under the contracts. See Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

Our business could be negatively impacted by cyber-attacks targeting our computer and telecommunications systems and infrastructure.

Our business, like other companies in the oil and gas industry, has become increasingly dependent on digital technologies. Such technologies are integrated into our business operations and used as a part of our liquid hydrocarbon and natural gas production and distribution systems in the U.S. and abroad, including those systems used to transport production to market. Use of the internet and other public networks for communications, services, and storage, including “cloud” computing, exposes users (including our business) to cybersecurity risks. While our information systems and related infrastructure experienced attempted and actual minor breaches of our cybersecurity in the past, we have not suffered any losses or breaches which had a material effect on our business, operations or reputation relating to such attacks; however, there is no assurance that we will not suffer such losses or breaches in the future.  As cyber-attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information systems and related infrastructure security vulnerabilities.

Our operations may be adversely affected by pipeline, rail and other transportation capacity constraints.

The marketability of our production depends in part on the availability, proximity, and capacity of pipeline facilities, rail cars, trucks and vessels. If any pipelines, rail cars, trucks or vessels become unavailable, we would, to the extent possible, be required to find a suitable alternative to transport our liquid hydrocarbons and natural gas, which could increase the costs and/or reduce the revenues we might obtain from the sale of our production.

If we acquire crude oil and natural gas properties, our failure to fully identify existing and potential problems, to accurately estimate reserves, production rates or costs, or to effectively integrate the acquired properties into our operations could materially and adversely affect our business, financial condition and results of operations.

We typically seek the acquisition of crude oil and natural gas properties.  Although we perform reviews of properties to be acquired in a manner that we believe is diligent and consistent with industry practices, reviews of records and properties may not necessarily reveal existing or potential problems, nor may they permit us to become sufficiently familiar with the properties in

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order to fully assess possible deficiencies and potential problems.  Even when problems with a property are identified, we often assume environmental and other risks and liabilities in connection with acquired properties pursuant to the acquisition agreements.  Moreover, there are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves (as previously discussed), actual future production rates and associated costs with respect to acquired properties.  Actual reserves, production rates and costs may vary substantially from those assumed in our estimates.  In addition, an acquisition may have a material and adverse effect on our business and results of operations, particularly during the periods in which the operations of the acquired properties are being integrated into our ongoing operations or if we are unable to effectively integrate the acquired properties into our ongoing operations.

We operate in a highly competitive industry, and many of our competitors are larger and have available resources in excess of our own.

The oil and gas industry is highly competitive, and many competitors, including major integrated and independent oil and gas companies, as well as national oil companies, are larger and have substantially greater resources at their disposal than we do. We compete with these companies for the acquisition of oil and natural gas leases and other properties. We also compete with these companies for equipment and personnel, including petroleum engineers, geologists, geophysicists and other specialists, required to develop and operate those properties and in the marketing of crude oil and natural gas to end-users. Such competition can significantly increase costs and affect the availability of resources, which could provide our larger competitors a competitive advantage when acquiring equipment, leases and other properties. They may also be able to use their greater resources to attract and retain experienced personnel.

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 as 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 North America E&P and International E&P 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 OSM 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 our products from our facilities. A prolonged disruption in the ability of any pipelines, rail cars, trucks, or vessels to transport our production 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

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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.

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Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The location and general character of our principal liquid hydrocarbon and natural gas properties, oil sands mining properties and facilities, and other important physical properties have been described by segment under Item 1. Business.

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. In April 2013, we filed a counterclaim against Noble alleging, among other things, breach of contract and breach of the duty of good faith relating to the multi-year drilling contract. The counterclaim also included a breach of contract claim for reimbursement for the value of fuel used by Noble under an offshore daywork drilling contract. The parties settled this litigation in the fourth quarter of 2013, and the settlement did not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Environmental Proceedings

The following is a summary of proceedings involving us that were pending or contemplated as of December 31, 2013 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.

As of December 31, 2013, we have sites across the country where remediation is being sought under 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 total clean-up and remediation costs connected with these sites will be less than $24 million, the majority of which have already been incurred.

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.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

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

The principal market on which Marathon Oil common stock is traded is the New York Stock Exchange ("NYSE"). As of January 31, 2014, there were 41,356 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:

	2013			2012
(Dollars per share)	High Price	Low Price	Dividends	High Price	Low Price	Dividends
Quarter 1	$35.71	$31.59	$0.17	$35.06	$30.47	$0.17
Quarter 2	$36.38	$29.85	$0.17	$32.23	$23.32	$0.17
Quarter 3	$37.83	$32.61	$0.19	$31.09	$24.09	$0.17
Quarter 4	$37.93	$34.06	$0.19	$31.93	$29.30	$0.17
Full Year	$37.93	$29.85	$0.72	$35.06	$23.32	$0.68

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, 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.

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, 2013, 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)
10/01/13 – 10/31/13	9,404		$35.07	—	$	1,280,820,541
11/01/13 – 11/30/13	5,381		$35.18	—	$	1,280,820,541
12/01/13 – 12/31/13	33,682	(b)	$35.84	—	$	2,500,000,000
Total	48,467		$35.62	—

^(a)  21,898 shares of restricted stock were delivered by employees to Marathon Oil, upon vesting, to satisfy tax withholding requirements.

^(b)  In December 2013, 26,569 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)  In December 2013, our Board of Directors increased the authorization for repurchases of our common stock by $1.2 billion, bringing the remaining share repurchase authorization to $2.5 billion. As of December 31, 2013, we had repurchased 92 million common shares at a cost of $3,722 million, which includes transaction fees and commissions that are not reported in the table above. Of this total, 14 million shares were acquired at a cost of $500 million during the third quarter of 2013, 12 million shares at a cost of $300 million in the third quarter of 2011 and 66 million shares for $2,922 million prior to the spin-off of our downstream business.

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Item 6.   Selected Financial Data

(In millions, except per share data)	2013(a)(b)		2012(a)(b)		2011(a)(b)		2010(a)(b)		2009(b)
Statement of Income Data
Revenues	$	14,501	$	15,692	$	14,669	$	11,690	$	8,524
Income from continuing operations	1,593		1,613		1,718		1,448		756
Net income	1,753		1,582		2,946		2,568		1,463
Per Share Data
Basic:
Income from continuing operations	$2.26		$2.28		$2.42		$2.04		$1.06
Net income	$2.49		$2.24		$4.15		$3.62		$2.06
Diluted:
Income from continuing operations	$2.24		$2.27		$2.41		$2.03		$1.06
Net income	$2.47		$2.23		$4.13		$3.61		$2.06
Statement of Cash Flows Data(b)
Additions to property, plant and equipment related to continuing operations	$	4,766	$	4,593	$	2,986	$	3,269	$	3,056
Dividends paid	508		480		567		704		679
Dividends per share	$0.72		$0.68		$0.80		$0.99		$0.96
Balance Sheet Data as of December 31:
Total assets	$	35,620	$	35,306	$	31,371	$	50,014	$	47,052
Total long-term debt, including capitalized leases	6,394		6,512		4,674		7,601		8,436

^(a)  Includes impairments of $96 million, $371 million, $310 million and $447 million in 2013, 2012, 2011 and 2010 (see Item 8. Financial Statements and Supplementary Data – Note 15 to the consolidated financial statements).

^(b)  We entered into agreements to sell our Angola assets in 2013 (see Item 8. Financial Statements and Supplementary Data – Note 6 to the consolidated financial statements); our downstream business was spun-off on June 30, 2011 (see Item 8. Financial Statements and Supplementary Data – Note 3 to the consolidated financial statements); and our Ireland and previous Gabon businesses were sold in 2009. The applicable periods have been recast to reflect these businesses in discontinued operations.

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

Each of our segments is organized and managed based upon both geographic location and the nature of the products and services it offers:

• North America E&P – explores for, produces and markets liquid hydrocarbons and natural gas in North America;

• International E&P – explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and

• Oil Sands Mining – 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.

Certain sections of Management’s Discussion and Analysis of Financial Condition and Results of Operations include forward-looking statements concerning trends or events potentially affecting our business. These statements typically contain words such as "anticipates," "believes," "estimates," "expects," "targets," "plans," "projects," "could," "may," "should," "would" or similar words indicating that future outcomes are uncertain. In accordance with "safe harbor" provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in the forward-looking statements. 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 stockholders 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. 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 for all periods prior to the spin-off (see Item 8. Financial Statements and Supplementary Data – Note 3 to the consolidated financial statements for additional information).

Overview – Market Conditions

Prevailing prices for the various qualities of crude oil and natural gas that we produce significantly impact our revenues and cash flows.  The following table lists benchmark crude oil and natural gas price averages relative to our North America E&P and International E&P segments for the past three years.

Benchmark	2013	2012	2011
WTI crude oil (Dollars per bbl)	$98.05	$94.15	$95.11
Brent (Europe) crude oil (Dollars per bbl)	$108.64	$111.65	$111.26
Henry Hub natural gas (Dollars per mmbtu)(a)	$3.65	$2.79	$4.04

^(a)  Settlement date average.

North America E&P

Liquid hydrocarbons – The quality, location and composition of our liquid hydrocarbon production mix can cause our North America E&P price realizations to differ from the WTI benchmark.

Quality – Light sweet crude contains less sulfur and tends to be lighter than sour crude oil so that refining it is less costly and has historically produced higher value products; therefore, light sweet crude is considered of higher quality and has historically sold at a price that approximates WTI or at a premium to WTI. The percentage of our North America E&P crude oil and condensate production that is light sweet crude has been increasing as onshore production from the Eagle Ford and Bakken increases and production from the Gulf of Mexico declines. In 2013, the percentage of our U.S. crude oil and condensate production that was sweet averaged 76 percent compared to 63 percent and 42 percent in 2012 and 2011. 

Location – In recent years, crude oil sold along the U.S. Gulf Coast, such as that from the Eagle Ford, has been priced based on the Louisiana Light Sweet ("LLS") benchmark which has historically priced at a premium to WTI and has historically tracked closely to Brent, while production from inland areas farther from large refineries has been priced lower. The average annual WTI

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discount to Brent was narrower in 2013 than in 2012 and 2011. As a result of the significant increase in U.S. production of light sweet crude oil, the historical relationship between WTI, Brent and LLS pricing may not be indicative of future periods.

Composition – The proportion of our liquid hydrocarbon sales volumes that are NGLs continues to increase due to our development of United States unconventional liquids-rich plays. NGLs were 15 percent of our North America E&P liquid hydrocarbon sales volumes in 2013 compared to 10 percent in 2012 and 7 percent in 2011.

Natural gas –A significant portion of our natural gas production in the U.S. is sold at bid-week prices, or first-of-month indices relative to our specific producing areas.  Average Henry Hub settlement prices for natural gas were 31 percent higher for 2013 than for 2012.  

International E&P

Liquid hydrocarbons – Our International E&P crude oil production is relatively sweet and has historically sold in relation to the Brent crude benchmark, which on average was 3 percent lower for 2013 than 2012.

Natural gas –Our major International E&P natural gas-producing regions are Europe and E.G.  Natural gas prices in Europe have been considerably higher than the U.S. in recent years.  In the case of E.G., our natural gas sales are subject to term contracts, making realized prices in these areas less volatile.  The natural gas sales from E.G. are at fixed prices; therefore, our reported average International E&P natural gas realized prices may not fully track market price movements.

Oil Sands Mining

The Oil Sands Mining segment produces and sells various qualities of synthetic crude oil. Output mix can be impacted by operational problems or planned unit outages at the mines or upgrader. Sales prices for roughly two-thirds of the normal output mix has historically tracked movements in WTI and one-third has historically tracked movements in the Canadian heavy crude oil marker, primarily WCS. The WCS discount to WTI has been increasing on average in each year presented below. Despite a wider WCS discount in 2013, our average Oil Sands Mining price realizations increased due to a greater proportion of higher value synthetic crude oil sales volumes compared to 2012. 

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 AECO natural gas sales index and crude oil prices, respectively.

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

Benchmark	2013	2012	2011
WTI crude oil (Dollars per bbl)	$98.05	$94.15	$95.11
WCS (Dollars per bbl)(a)	$72.77	$73.18	$77.97
AECO natural gas sales index (Dollars per mmbtu)(b)	$3.08	$2.39	$3.68

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

^(b)  Monthly average day ahead index.

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Key Operating and Financial Activities

Significant 2013 activities related to our strategic imperatives:

•Production growth

•Total company net sales volume growth of 11 percent (excluding Alaska and Libya)

• North America E&P net sales volumes averaged 201 mboed, a 21 percent increase over last year

• Eagle Ford averaged net sales volumes of 81 mboed, a 136 percent increase

• Bakken averaged net sales volumes of 39 mboed, a 34 percent increase

• Oklahoma resource basins averaged net sales volumes of 14 mboed, a 68 percent increase

• Proved reserve replacement of 194 percent, excluding dispositions

• Total net proved reserves increased 8 percent to approximately 2.2 billion boe

• Quality resource capture through focused exploration

• Mirawa-1 discovery on operated Harir block in the Kurdistan Region of Iraq

• Diaman-1B discovery on non-operated Diaba License in Gabon

• Atrush block received approval from the KRG for the first phase of oil development in the Kurdistan Region of Iraq

• Shenandoah and Gunflint (both non-operated) prospects had successful appraisal wells in the Gulf of Mexico

• Rigorous portfolio management

• Exceeded three-year $1.5 billion to $3 billion divestiture target

• Agreements to sell working interests in Angola Blocks 31 and 32 with an aggregate transaction value of $2.1 billion, before closing adjustments

• Sold our interests in Alaska, the DJ Basin and the Neptune gas plant

• Acquired 4,800 additional net acres in the core of the Eagle Ford shale

• Grew SCOOP acreage position over 20 percent

• Commenced efforts to market our U.K. and Norway assets

• Competitive shareholder value

• Increased dividend by 12 percent to 19 cents per share

• Repurchased 14 million common shares for $500 million

• Announced $500 million share repurchase to begin upon closing of Angola Block 31 sale

• Authorized $1.2 billion increase in share repurchase program to $2.5 billion remaining

Significant 2014 activity through February 28, 2014 includes:

• Closed sale of our interest in Angola Block 31

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Consolidated Results of Operations: 2013 compared to 2012

Consolidated income from continuing operations before income taxes in 2013 was 20 percent lower than 2012 primarily due to lower liquid hydrocarbon net sales volumes in the International E&P segment and higher DD&A and exploration expenses, partially offset by higher liquid hydrocarbon net sales volumes in the North America E&P segment. The effective tax rate for continuing operations was 68 percent in 2013 compared to 74 percent in 2012, with the decrease primarily related to lower income from continuing operations in Libya and Norway, which are higher tax jurisdictions.

Sales and other operating revenues, including related partyare summarized by segment in the following table:

(In millions)	2013			2012
Sales and other operating revenues, including related party
North America E&P	$	5,068		$	3,944
International E&P	5,827			7,445
Oil Sands Mining	1,576			1,521
Segment sales and other operating revenues, including related party	12,471			12,910
Unrealized gain (loss) on crude oil derivative instruments	(52		)	53
Sales and other operating revenues, including related party	$	12,419		$	12,963

North America E&P sales and other operating revenues increased $1,124 million from 2012 to 2013 primarily due to higher liquid hydrocarbon net sales volumes resulting from ongoing development programs in the Eagle Ford, Bakken and Oklahoma resource basins, partially offset by lower natural gas net sales volumes, primarily the result of the sale of our Alaska assets in early 2013.

The following table gives details of net sales volumes and average price realizations of our North America E&P segment:

	2013	2012
North America E&P Operating Statistics
Net liquid hydrocarbon sales volumes (mbbld)	149	107
Liquid hydrocarbon average price realizations (per bbl)(a) (b)	$85.20	$85.80
Net crude oil and condensate sales volumes (mbbld)	126	96
Crude oil and condensate average price realizations (per bbl)(a)	$94.19	$91.30
Net natural gas liquids sales volumes (mbbld)	23	11
Natural gas liquids average price realizations (per bbl)(a)	$35.12	$39.57
Net natural gas sales volumes (mmcfd)	312	358
Natural gas average price realizations (per mcf) (a)	$3.84	$3.92

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

^(b)  Inclusion of realized gains (losses) on crude oil derivative instruments would have increased (decreased) average liquid hydrocarbon price realizations per bbl by $(0.27) for 2013 and $0.40 for 2012.

International E&P sales and other operating revenues decreased $1,618 million in 2013 from the prior year. This decrease was primarily due to lower liquid hydrocarbon net sales volumes in Libya and Norway and lower liquid hydrocarbon average price realizations.

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The following table gives details of net sales volumes and average price realizations of our International E&P segment:

	2013	2012
International E&P Operating Statistics
Net liquid hydrocarbon salesvolumes (mbbld)(a)
Europe	86	97
Africa	58	78
Total International E&P	144	175
Liquid hydrocarbon average price realizations (per bbl)
Europe	$112.60	$115.16
Africa	$86.29	$98.52
Total International E&P	$102.10	$107.78
Net natural gas sales volumes (mmcfd)
Europe(b)	83	101
Africa	464	443
Total International E&P	547	544
Natural gas average price realizations (per mcf)
Europe	$12.08	$10.47
Africa(c)	$0.49	$0.43
Total International E&P	$2.25	$2.29

^(a) Corresponds with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.

^(b) Includes natural gas acquired for injection and subsequent resale of 7 mmcfd and 15 mmcfd for 2013 and 2012.

^(c) Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO, and EGHoldings, equity method investees. We include our share of Alba Plant LLC's, AMPCO's and EGHoldings' income in our International E&P segment.

Oil Sands Mining sales and other operating revenues increased $55 million in 2013 from 2012. This increase was primarily due to a higher proportion of net sales volumes related to a premium grade synthetic crude oil and the associated average price realizations when compared to 2012. The increase was partially offset by lower feedstock sales in 2013.

The following table gives details of net sales volumes and average price realizations of our Oil Sands Mining segment:

	2013	2012
Oil Sands Mining Operating Statistics
Net synthetic crude oil sales volumes (mbbld)(a)	48	47
Synthetic crude oil average price realizations (per bbl)	$87.51	$81.72

(a) Includes blendstocks.

Unrealized gains and losses on crude oil derivative instruments are included in total sales and other operating revenues but are not allocated to the segments. These crude oil derivative instruments, all of which had terms that ended in December 2013, resulted in a $52 million net unrealized loss in 2013 compared to a net unrealized gain of $53 million in 2012. See Item 8. Financial Statements and Supplementary Data - Note 16 to the consolidated financial statements for information about our derivative positions.

Marketing revenues decreased $647 million in 2013 from 2012. North America E&P segment marketing activities, which serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points, decreased in 2013 as a result of market dynamics.

Income from equity method investments increased $53 million in 2013 from the prior year primarily due to higher LNG average price realizations.  

Net gain (loss) on disposal of assetsin 2013 primarily included a $114 million pretax loss on the sale of our interests in the DJ Basin, a $43 million pretax loss on the conveyance of our interests in the Marcellus natural gas shale play to the operator, a $98 million pretax gain on the sale of our interest in the Neptune gas plant, and a $55 million pretax gain on the sale of our remaining assets in Alaska. The net gain on disposal of assets in 2012 consisted primarily of a $166 million pretax gain on the sale of our interests in several Gulf of Mexico crude oil pipeline systems and a $36 million pretax loss related to our exit from Indonesia. See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for information about these dispositions.

Production expensesincreased $129 million in 2013 from 2012 primarily related to increased North America E&P net sales volumes in the Eagle Ford and Bakken and International E&P well workovers in Norway. The production expense rate (expense

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per boe) decreased in North America E&P in 2013 compared to 2012 primarily due to improved operating efficienciesin the Eagle Ford. The International E&P production expense rate increased in 2013 compared to 2012 primarily due to the well workovers in Norway.

The following table provides production expense rates for each segment:

($ per boe)	2013		2012
North America E&P		$10.86		$11.59
International E&P		$6.24		$5.13
Oil Sands Mining (a)		$46.30	$45.95

(a) Production expense per synthetic crude oil barrel (before royalties) includes production costs, shipping and handling, taxes other than income and insurance costs and excludes pre-development costs.

Marketing expenses decreased $672 million in 2013 from the prior year, consistent with the decrease in marketing revenues discussed above.

Exploration expenseswere $282 million higher in 2013 than in 2012, primarily due to larger non-cash unproved property impairments in our North America E&P segment related to Eagle Ford leases that either expired or that we did not expect to drill, partially offset by reduced geological and geophysical costs.

The following table summarizes the components of exploration expenses:

(In millions)	2013		2012
Unproved property impairments	$	580	$	227
Dry well costs	218		230
Geological and geophysical	84		135
Other	106		114
Total exploration expenses	$	988	$	706

Depreciation, depletion and amortizationincreased $313 million in 2013 from the prior year.  Our segments apply the units-of-production method to the majority of their assets, including capitalized asset retirement costs. Increased DD&A in 2013 primarily reflects the impact of higher North America E&P sales volumes as well as increased amortization of capitalized asset retirement costs due to revisions of estimates for abandonment obligations in the Gulf of Mexico and the U.K. However, the disposition of our Alaska assets in January 2013 and lower International E&P DD&A primarily due to 2013 reserve additions in Norway partially offset the increase. See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for information about the Alaska disposition.

The DD&A rate (expense per boe), which is impacted by changes in reserves and capitalized costs, can also cause changes to our DD&A.  A higher 2013 DD&A rate in North America E&P versus 2012 is due to the ongoing development programs in the U.S. resource plays. A lower International E&P DD&A rate in 2013 compared to 2012 was primarily due to reserve increases for Norway.  

The following table provides DD&A rates for each segment:

($ per boe)	2013		2012
North America E&P		$26.23		$23.45
International E&P		$7.26		$8.08
Oil Sands Mining		$12.39		$12.57

Impairmentsin 2013 primarily related to capitalized costs associated with engineering and feasibility studies for a second LNG production train in E.G., the Ozona development in the Gulf of Mexico, and our Powder River Basin asset in Wyoming. Impairments in 2012 were also related to the Ozona development and Powder River Basin.  See Item 8. Financial Statements and Supplementary Data - Note 15 to the consolidated financial statements for information about these impairments.

Taxes other than incomeinclude production, severance and ad valorem taxes in the United States, which tend to increase or decrease in relation to net sales volumes and revenues, and increased $104 million in 2013 from 2012. With the increase in North America E&P revenues and net sales volumes, production and severance taxes increased. In addition, ad valorem taxes were higher because the value of our North America E&P assets has increased with continued acquisitions in the Eagle Ford.

Net interest and otherincreased $55 million in 2013 from 2012 primarily due to higher interest expense related to our $2 billion issuance of senior notes in late 2012. See Item 8. Financial Statements and Supplementary Data - Note 9 to the consolidated financial statements for more detailed information.

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Provision for income taxesdecreased $1,180 million in 2013 from 2012 primarily due to the decrease in pretax income from continuing operations, primarily in Libya and Norway, which are higher tax jurisdictions. The following is an analysis of the effective tax rates for 2013 and 2012.

	2013		2012
Statutory rate applied to income from continuing operations before income taxes	35	%	35	%
Effects of foreign operations, including foreign tax credits	14		18
Adjustments to valuation allowances	18		21
Other	1		—
Effective income tax rate on continuing operations	68	%	74	%

The effective income tax rate is influenced by a variety of factors including the geographic sources of income and the relative magnitude of these sources of income. 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 appears in the "Corporate and other unallocated items" shown in the reconciliation of segment income to net income below.

Effects of foreign operations – The effects of foreign operations on our effective tax rate decreased in 2013 as compared to 2012, primarily due to decreased sales in Libya during 2013 as a result of third-party labor strikes at the Es Sider oil terminal.

Adjustments to valuation allowances – In 2013 and 2012, 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 those years.

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

Discontinued operations is presented net of tax. In 2013, we entered into agreements to sell our Angola assets; therefore, the Angola operations are reflected as discontinued operations in all periods presented. See Item 8. Financial Statements and Supplementary Data – Note 6 to the consolidated financial statements.

Segment Results: 2013 compared to 2012

Segment income for 2013 and 2012 is summarized and reconciled to net income in the following table.

(In millions)	2013			2012
North America E&P	$	529		$	382
International E&P	1,423			1,660
Oil Sands Mining	206			171
Segment income	2,158			2,213
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items	(473		)	(475		)
Unrealized gain (loss) on crude oil derivative instruments	(33		)	34
Net gain (loss) on dispositions	(20		)	72
Impairments	(39		)	(231		)
Income from continuing operations	1,593			1,613
Discontinued operations	160			(31		)
Net income	$	1,753		$	1,582

 North America E&P segment incomeincreased $147 million in 2013 compared to 2012. The increase was largely due to increased liquid hydrocarbon net sales volumes primarily in the Eagle Ford, Bakken and Oklahoma resource basins, partially offset by higher DD&A associated with the higher sales volumes. Segment income was also negatively impacted by higher exploration expenses related to non-cash unproved property impairments and the sale of our Alaska assets.

International E&P segment incomedecreased $237 million in 2013 compared to 2012. The decrease was primarily related to the lower liquid hydrocarbon net sales volumes in Libya and Norway and lower average liquid hydrocarbon price realizations, as well as higher exploration expenses, partially offset by lower DD&A associated with the lower sales volumes.  

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 Oil Sands Mining segment incomeincreased $35 million in 2013 compared to 2012. This increase was primarily due to a higher proportion of net sale volumes in 2013 related to a premium grade of synthetic crude oil with a higher corresponding price realization.

Consolidated Results of Operations: 2012 compared to 2011

Consolidated income from continuing operations before income taxes in 2012 was 38 percent higher than in 2011 primarily related to increases in North America E&P and International E&P liquid hydrocarbon net sales volumes and higher average price realizations in International E&P. The effective tax rate for continuing operations was 74 percent in 2012 compared to 61 percent in 2011, with the increase primarily related to resumption in 2012 of sales in Libya, which is a higher tax jurisdiction. Also, in 2011 we were not in an excess foreign tax credit position for the entire year as we were in 2012.

Sales and other operating revenues, including related partyare summarized by segment in the following table:

(In millions)	2012		2011
Sales and other operating revenues, including related party
North America E&P	$	3,944	$	3,364
International E&P	7,445		5,851
Oil Sands Mining	1,521		1,535
Segment sales and other operating revenues, including related party	12,910		10,750
Unrealized gain (loss) on crude oil derivative instruments	53		—
Sales and other operating revenues, including related party	$	12,963	$	10,750

North America E&P sales and other operating revenues increased $580 million in 2012 from 2011 primarily due to higher liquid hydrocarbon net sales volumes resulting from ongoing development programs in the Eagle Ford and Bakken, partially offset by lower average liquid hydrocarbon and natural gas price realizations, when compared to 2011. Realized gains on our North America E&P crude oil derivative instruments were $15 million in 2012, while there were no open crude oil derivative instruments in 2011.

The following table gives details of net sales volumes and average price realizations of our North America E&P segment:

	2012	2011
North America E&P Operating Statistics
Net liquid hydrocarbon sales volumes (mbbld)	107	75
Liquid hydrocarbon average price realizations (per bbl)(a)(b)	$85.80	$92.55
Net crude oil and condensate sales volumes (mbbld)	96	70
Crude oil and condensate average price realizations (per bbl)(a)	$91.30	$94.80
Net natural gas liquids sales volumes (mbbld)	11	5
Natural gas liquids average price realizations (per bbl)(a)	$39.57	$58.53
Net natural gas sales volumes (mmcfd)	358	326
Natural gas average price realizations (per mcf) (a)	$3.92	$4.95

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

^(b)  Inclusion of realized gains on crude oil derivative instruments would have increased average liquid hydrocarbon price realizations by $0.40 per bbl for 2012. There were no crude oil derivative instruments in 2011.

International E&P sales and other operating revenues increased $1,594 million in 2012 from 2011 primarily as a result of the previously discussed resumption of liquid hydrocarbon sales in Libya. Higher average liquid hydrocarbon price realizations during 2012, again primarily related to Libyan crude oil, also contributed to the revenue increase.

The following table gives details of net sales volumes and average price realizations of our International E&P segment:

	2012	2011
International E&P Operating Statistics
Net liquid hydrocarbon salesvolumes (mbbld)(a)
Europe	97	101
Africa	78	43
Total International E&P	175	144
Liquid hydrocarbon average price realizations (per bbl)
Europe	$115.16	$115.55
Africa	$98.52	$73.21
Total International E&P	$107.78	$102.96
Net natural gas sales volumes (mmcfd)
Europe(b)	101	97
Africa	443	443
Total International E&P	544	540
Natural gas average price realizations (per mcf)
Europe	$10.47	$9.84
Africa(c)	$0.43	$0.24
Total International E&P	$2.29	$1.97

^(a) Corresponds with the basis for fiscal settlements with governments, representing equity tanker liftings and direct deliveries of liquid hydrocarbons.

^(b) Includes natural gas acquired for injection and subsequent resale of 15 mmcfd and 16 mmcfd for 2012 and 2011.

^(c) Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO, and EGHoldings, equity method investees. We include our share of Alba Plant LLC's, AMPCO's and EGHoldings' income in our International E&P segment.

Oil Sands Mining sales and other operating revenues decreased $14 million in 2012 from 2011. This decrease was primarily the result of lower average price realizations which were partially offset by higher net sales volumes.

The following table gives details of net sales volumes and average price realizations of our Oil Sands Mining segment:

	2012	2011
Oil Sands Mining Operating Statistics
Net synthetic crude oil sales volumes (mbbld)(a)	47	43
Synthetic crude oil average price realizations (per bbl)	$81.72	$91.65

^(a)  Includes blendstocks.

Unrealized gains and losses on crude oil derivative instruments are included in total sales and other operating revenues but are not allocated to the segments. These crude oil derivative instruments resulted in a net unrealized gain of $53 million in 2012, however, there were no open crude oil derivative instruments in 2011. See Item 8. Financial Statements and Supplementary Data - Note 16 to the consolidated financial statements for additional information about our derivative positions.

Marketing revenues decreased $1,190 million in 2012 from 2011. North America E&P segment marketing activities, which serve to aggregate volumes in order to satisfy transportation commitments as well as to achieve flexibility within product types and delivery points, decreased in 2012 as a result of market dynamics and slightly lower commodity prices.

Income from equity method investmentsdecreased $92 million in 2012 from the prior year primarily due to lower natural gas prices and turnarounds early in 2012 at our facilities in E.G. Also, in January 2012, we sold our equity investments in several Gulf of Mexico crude oil pipelines.  

Net gain (loss) on disposal of assetsin 2012 consisted primarily of the $166 million pretax gain on the sale of our interests in several Gulf of Mexico crude oil pipeline systems and a $36 million pretax loss related to our exit from Indonesia. In 2011, the net gain on disposal of assets was primarily related to the $37 million pretax gain related to the assignment of interests in our DJ Basin acreage position, the $34 million pretax gain on the sale of our interest in the Burns Point gas plant and the $8 million pretax gain on the sale of our interest in the Alaska LNG facility. See Item 8. Financial Statements and Supplementary Data - Note 6 to the consolidated financial statements for information about these dispositions.

Production expensesincreased $251 million in 2012 from 2011. The increase is primarily related to increased liquid hydrocarbon net sales volumes in the Eagle Ford, Bakken and Libya as well as the 2012 planned turnaround in the U.K.

The following table provides production expense rates (expense per boe) for each segment:

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($ per boe)	2012		2011
North America E&P		$11.59		$11.51
International E&P		$5.13		$4.80
Oil Sands Mining (a)		$45.95		$46.27

(a) Production expense per synthetic crude oil barrel (before royalties) includes production costs, shipping and handling, taxes other than income and insurance costs and excludes pre-development costs.

Marketing expenses decreased $1,154 million in 2012 from the prior year, consistent with the decreases in marketing revenues discussed above.

Exploration expenseswere $65 million higher in 2012 than in 2011, primarily due to larger non-cash unproved property impairments. Unproved property impairments in 2012 related to Marcellus, Eagle Ford and Indonesia. The following table summarizes the components of exploration expenses.

(In millions)	2012		2011
Unproved property impairments	$	227	$	79
Dry well costs	230		278
Geological and geophysical	135		124
Other	114		160
Total exploration expenses	$	706	$	641

Depreciation, depletion and amortizationincreased $214 million in 2012 from the prior year.  Our segments apply the units-of-production method to the majority of their assets; therefore, the previously discussed increases in North America E&P and International E&P sales volumes generally result in similar changes in DD&A. There was no depletion of our Alaska assets for much of 2012 because they were held for sale, which partially offset the DD&A increase.

The DD&A rate (expense per boe), which is impacted by changes in reserves and capitalized costs, can also cause changes in our DD&A.  The decreases in both the North America E&P and International E&P DD&A rates in 2012 compared to 2011 were primarily due to proved reserve additions.

The following table provides DD&A rates for each segment:

($ per boe)	2012		2011
North America E&P		$23.45		$25.15
International E&P		$8.08		$9.70
Oil Sands Mining		$12.57		$12.43

Impairmentsin 2012 primarily related to the Ozona development in the Gulf of Mexico and to our Powder River Basin asset in Wyoming.  Impairments in 2011 primarily related to the Droshky development in the Gulf of Mexico and an intangible asset for an LNG delivery contract at Elba Island. See Item 8. Financial Statements and Supplementary Data - Note 15 to the consolidated financial statements for information about these impairments.

Taxes other than incomeinclude production, severance and ad valorem taxes in the United States, which tend to increase or decrease in relation to sales volumes and revenues, and increased $55 million in 2012 from 2011. With the increase in revenues related to higher sales volumes, production and severance taxes increased. In addition, ad valorem taxes are higher because the value of our U.S. assets increased with the acquisitions in the Eagle Ford shale.

Net interest and otherincreased $112 million in 2012 from 2011 primarily due to lower capitalized interest in 2012. See Item 8. Financial Statements and Supplementary Data - Note 9 to the consolidated financial statements for more detailed information.

Loss on early extinguishment of debt relates to debt retirements in February and March of 2011.

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Provision for income taxesincreased $1,791 million in 2012 from 2011 primarily due to the increase in pretax income from continuing operations, including the impact of the resumption of sales in Libya in the first quarter of 2012. The following is an analysis of the effective income tax rates for 2012 and 2011:

	2012		2011
Statutory rate applied to income from continuing operations before income taxes	35	%	35	%
Effects of foreign operations, including foreign tax credits	18		6
Change in permanent reinvestment assertion	—		5
Adjustments to valuation allowances	21		14
Tax law changes	—		1
Effective income tax rate on continuing operations	74	%	61	%

The effective income tax rate is influenced by a variety of factors including the geographic sources of income and the relative magnitude of these sources of income. 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 appears in the "Corporate and other unallocated items" shown in the reconciliation of segment income to net income below.

Effects of foreign operations – The effects of foreign operations on our effective tax rate increased in 2012 as compared to 2011, primarily due to the resumption of sales in Libya in the first quarter of 2012, where the statutory 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 recognizing deferred U.S. tax on previously undistributed earnings.

Adjustments to valuation allowances – In 2012 and 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 those years.

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

Discontinued operations is presented net of tax, andreflects our downstream business that was spun off June 30, 2011 and our Angola business which we agreed to sell in 2013. See Item 8. Financial Statements and Supplementary Data – Notes 3 and 6 to the consolidated financial statements for additional information.

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Segment Results: 2012 compared to 2011

Segment income for 2012 and 2011 is summarized and reconciled to net income in the following table.

(In millions)	2012			2011
North America E&P	$	382		$	392
International E&P	1,660			1,991
Oil Sands Mining	171			261
Segment income	2,213			2,644
Items not allocated to segments, net of income taxes:
Corporate and other unallocated items	(475		)	(359		)
Unrealized gain on crude oil derivative instruments	34			—
Net gain on dispositions	72			45
Impairments	(231		)	(195		)
Loss on early extinguishment of debt	—			(176		)
Tax effect of subsidiary restructuring	—			(122		)
Deferred income tax items	—			(61		)
Water abatement - Oil Sands	—			(48		)
Eagle Ford transaction costs	—			(10		)
Income from continuing operations	1,613			1,718
Discontinued operations	(31		)	1,228
Net income	$	1,582		$	2,946

 North America E&P segment incomedecreased $10 million in 2012 compared to 2011. The decrease is largely due to lower liquid hydrocarbon price realizations and increased exploration expenses due to non-cash unproved property impairments, partially offset by higher liquid hydrocarbon net sales volumes primarily in the Eagle Ford and Bakken.

International E&P segment incomedecreased $331 million in 2012 compared to 2011. The decrease included lower earnings in the U.K. and E.G., partially offset by higher earnings in Libya.  Also, in 2011 we were not in an excess foreign tax credit position for the entire year as we were in 2012.

 Oil Sands Mining segment incomedecreased $90 million in 2012 compared to 2011. The decrease is primarily due to lower synthetic crude oil price realizations partially offset by higher net sales volumes.

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

Cash Flows

Net cash provided by continuing operationswas $5,091 million in 2013 compared to $4,036 million in 2012 and $5,441 million in 2011. The $1,055 million increase in 2013 primarily reflects the impact of increased North America E&P liquid hydrocarbon net sales volumes on operating income. The $1,405 million decrease in 2012 was primarily the result of working capital changes related to the 2012 ramp-up of operations in the Eagle Ford and Libya along with the timing of tax payments.

Net cash used in investing activities related to continuing operations totaled $4,294 million in 2013 compared to $5,092 million in 2012 and $6,865 million in 2011. Significant investing activities include acquisitions, additions to property, plant and equipment and asset disposals.

Acquisitions in 2013, 2012 and 2011 included proved and unproved assets in the Eagle Ford. See Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements for further information about the transactions. In recent years, the focus of most of our capital spending has been in our North America E&P segment related to unconventional resource plays like the Eagle Ford, Bakken and Oklahoma resource basins.

Disposals of assets totaled $450 million, $467 million, and $518 million in 2013, 2012 and 2011. In 2013, net proceeds were primarily related to the sales of our interests in Alaska, the Neptune gas plant, and the DJ Basin. In 2012, net proceeds were primarily from the sales of our interests in several Gulf of Mexico crude oil pipeline systems, a sell-down of our interests in the Harir and Safen blocks in the Kurdistan Region of Iraq, and the final collection of proceeds on a 2009 asset sale. Several sales of non-core assets and acreage sell-downs in 2011 resulted in net proceeds of $518 million. See Item 8. Financial Statements and Supplementary Data – Note 6 to the consolidated financial statements for more information about dispositions.

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Financing activities related to continuing operations resulted in a use of cash of $1,162 million in 2013, provided cash of $1,600 million in 2012 and used cash of $5,211 million in 2011. Debt repayments of $182 million, $145 million, and $2,877 million occurred in 2013, 2012 and 2011. Purchases of common stock used $500 million in cash during 2013 and $300 million in 2011. Dividend payments were uses of cash in every year. Sources of cash in 2012 included the issuance of a net $200 million in commercial paper and $2 billion in senior notes. In connection with the spin-off, we distributed $1,622 million to MPC in the second quarter of 2011.

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 committed revolving credit facility and sales of non-strategic assets. Our working capital requirements are supported by these sources and we may issue commercial paper backed by our $2.5 billion revolving credit facility to meet short-term cash requirements. We issued $10,870 million and repaid $10,935 million of commercial paper in 2013, leaving a balance of $135 million outstanding at December 31, 2013. Because of the alternatives available to us as discussed above and access to capital markets through the shelf registration discussed below, 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, 2013, we had $6,462 million in long-term debt outstanding, $68 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, 2013, we had no borrowings against our revolving credit facility and had $135 million in commercial paper outstanding under our commercial paper program, which is backed by the revolving credit facility. See Item 8. Financial Statements and Supplementary Data – Note 17 to the consolidated financial statements for a description of the revolving credit facility.

2014 Asset Disposals

The sale of our interest in Angola Block 31 closed in February 2014 for proceeds of $1.5 billion before closing adjustments. These proceeds will be used to repurchase $500 million of common stock with the remainder to be used for general corporate purposes. The sale of our interest in Angola Block 32 for proceeds of $590 million before closing adjustments is expected to close in the first quarter of 2014.

Shelf Registration

We are a "well-known seasoned issuer" for purposes of SEC rules, thereby allowing us to use a universal shelf registration statement should we choose to issue and sell various types of equity and debt securities.  Beginning in the first quarter of 2013, we changed our reportable segments and subsequently have recast all periods presented in this Annual Report on Form 10-K to reflect these new segments in our consolidated financial statements.  We expect to update and file our universal shelf registration statement shortly after the filing of this Annual Report on Form 10-K with the SEC.

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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 25 percent at December 31, 2013 and 2012.

(Dollars in millions)	2013			2012
Commercial paper	$	135		$	200
Long-term debt due within one year	68			184
Long-term debt	6,394			6,512
Total debt	$	6,597		$	6,896
Cash	$	264		$	684
Equity	$	19,344		$	18,283
Calculation:
Total debt	$	6,597		$	6,896
Minus cash	264			684
Total debt minus cash	6,333			6,212
Total debt	6,597			6,896
Plus equity	19,344			18,283
Minus cash	264			684
Total debt plus equity minus cash	$	25,677		$	24,495
Cash-adjusted debt-to-capital ratio	25		%	25		%

Capital Requirements

Capital Spending

Our approved capital, investment and exploration spending budget for 2014 is $5,882 million. Additional details related to this 2014 budget are discussed in Outlook.

Share Repurchase Program

In 2013, our Board of Directors increased the authorization for repurchases of our common stock by $1.2 billion, bringing the total authorized to $6.2 billion of which $2.5 billion is remaining. As of December 31, 2013, we had repurchased 92 million common shares at a cost of $3,722 million, with 14 million shares acquired at a cost of $500 million during the third quarter of 2013, 12 million shares acquired at a cost of $300 million in the third quarter of 2011 and 66 million shares purchased for $2,922 million prior to the spin-off of our downstream business. As previously discussed, a portion of the proceeds from the sale of our interest in Angola Block 31 will be used to repurchase $500 million of common stock. Purchases under the repurchase 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.

Other Expected Cash Outflows

We plan to make contributions of up to $77 million to our funded pension plans during 2014, and $11 million of that amount was paid in January 2014. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are expected to be approximately $74 million and $19 million in 2014. As of December 31, 2013, $135 million of commercial paper and $68 million of our long-term debt is due in the next twelve months.

Dividends of $508 million were paid during 2013 reflecting quarterly dividends of $0.17 per share in the first two quarters of the year and $0.19 per share in the last two quarters for a per share increase of 12 percent. On January 29, 2014, we announced that our Board of Directors had declared a dividend of $0.19 cents per share on Marathon Oil common stock, payable March 10, 2014, to stockholders of record at the close of business on February 19, 2014.

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

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contains forward-looking statements regarding the use of proceeds from the sale of our interest in Angola Block 31, the timing and amount of repurchasing additional common stock and the timing of closing the sale of our interest in Angola Block 32. The expectations with respect to the use of proceeds from the sale of our interest in Angola Block 31 and the timing and amount of repurchasing additional common stock could be affected by changes in the prices and demand for liquid hydrocarbons and natural gas, actions of competitors, disruptions or interruptions of our exploration or production operations, unforeseen hazards such as weather conditions or acts of war or terrorist acts and other operating and economic considerations. The sale of our interest in Angola Block 32 is subject to customary closing conditions. The discussion of liquidity above also contains forward-looking statements regarding planned funding of pension plans, which are based on current expectations, estimates and projections and are not guarantees of actual performance.

Contractual Cash Obligations

The table below provides aggregated information on our consolidated obligations to make future payments under existing contracts as of December 31, 2013.

(In millions)	Total		2014		2015- 2016		2017- 2018		Later Years
Short and long-term debt (excludes interest)(a)	$	6,572	$	203	$	1,068	$	1,536	$	3,765
Lease obligations	235		46		78		44		67
Purchase obligations:
Oil and gas activities(b)	1,294		742		391		74		87
Service and materials contracts(c)	925		192		231		100		402
Transportation and related contracts	1,345		211		330		201		603
Drilling rigs and fracturing crews(d)	1,037		554		461		22		—
Other	237		42		57		32		106
Total purchase obligations	4,838		1,741		1,470		429		1,198
Other long-term liabilities reported in the consolidated balance sheet(e)	1,258		181		276		244		557
Total contractual cash obligations(f)	$	12,903	$	2,171	$	2,892	$	2,253	$	5,587

^(a)  We anticipate cash payments for interest of $299 million for 2014, $596 million for 2015-2016, $520 million for 2017-2018 and $2,619 million for the remaining years for a total of $4,034 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)  Some contracts may be canceled at an amount less than the contract amount. Were we to elect that option where possible at December 31, 2013 our minimum commitment would be $905 million.

^(e)  Primarily includes obligations for pension and other postretirement benefits including medical and life insurance. We have estimated projected funding requirements through 2023. Also includes amounts for uncertain tax positions.

^(f)  This table does not include the estimated discounted liability for dismantlement, abandonment and restoration costs of oil and gas properties of $2,096 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 E.G. Onshore E.G., 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.

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, 2013, 2012 and 2011 aggregated $119 million, $139 million, and $231 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 and future abandonment liabilities.

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Outlook

Budget

Our Board of Directors approved a capital, investment and exploration spending budget of $5,882 million for 2014, including budgeted capital expenditures of $5,777 million. Our capital, investment and exploration spending budget is broken down by reportable segment in the table below.

(In millions)	2014 Budget		Percent of Total
North America E&P	$	4,241	72	%
International E&P	1,242		21	%
Oil Sands Mining	294		5	%
Segment total	5,777		98	%
Corporate and other	105		2	%
Total capital, investment and exploration spending budget	$	5,882	100	%

We continue to focus on growing profitable reserves and production worldwide. In 2014, we are accelerating drilling activity in our three key U.S. unconventional resource plays: the Eagle Ford, Bakken and Oklahoma resource basins, which account for approximately 60 percent of our budget. The majority of spending in our unconventional resource plays is intended for drilling. With an increased number of rigs in each of these areas, we plan to drill more net wells in these areas than in any previous year. We also have dedicated a portion of our capital budget in these areas to facility construction and recompletions. In our conventional assets, we will follow a disciplined spending plan that is intended to provide stable production,with approximately 23 percent of our budget allocated to the development of these assets worldwide. We also plan to either drill or participate in 8 to 10 exploration wells throughout our portfolio, with 10 percent of our budget allocated to exploration projects. For additional information about expected exploration and development activities see Item 1. Business.

The above discussion includes forward-looking statements with respect to projected spending and investment in exploration and development activities under the 2014 capital, investment and exploration spending budget, accelerated rig and drilling activity in the Eagle Ford, Bakken, and Oklahoma resource basins, and future exploratory and development drilling activity. Some factors which could potentially affect these forward-looking statements include pricing, supply and demand for liquid hydrocarbons and natural gas, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, availability of materials and labor, other risks associated with construction projects, 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. These 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 development projects 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.

Sales Volumes

We expect to increase our U.S. resource plays' net sales volumes by more than 30 percent in 2014 compared to 2013, excluding dispositions. In addition, we expect total production growth to be approximately 4 percent in 2014 versus 2013, excluding dispositions and Libya.

Acquisitions and Dispositions

Excluded from our budget are the impacts of acquisitions and dispositions not previously announced. We continually evaluate ways to optimize our portfolio through acquisitions and divestitures and exceeded our previously stated goal of divesting between $1.5 billion and $3.0 billion of assets over the period of 2011 through 2013. For the three-year period ended December 31, 2013, we closed or entered agreements for approximately $3.5 billion in divestitures, of which $2.1 billion is from the sales of our Angola assets. The sale of our interest in Angola Block 31 closed in February 2014 and the sale of our interest in Angola Block 32 is expected to close in the first quarter of 2014.

In December 2013, we announced the commencement of efforts to market our assets in the North Sea, both in the U.K. and Norway, which would simplify and concentrate our portfolio to higher margin growth opportunities and increase our production growth rate.

The above discussion includes forward-looking statements with respect to our percentage growth rate of production, production available for sale, the sale of our interest in Angola Block 32 and the possible sale of our U.K. and Norway assets. Some factors

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which could potentially affect our percentage growth rate of production and production available for sale include pricing, supply and demand for liquid hydrocarbons and natural gas, the amount of capital available for exploration and development, regulatory constraints, timing of commencing production from new wells, drilling rig availability, availability of materials and labor, the inability to obtain or delay in obtaining necessary government or third-party approvals and permits, unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response thereto, and other geological, operating and economic considerations. 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 difficult to predict. The timing of closing the sale of our interest in Block 32 is subject to customary closing conditions. The possible sale of our U.K. and Norway assets is subject to the identification of one or more buyers, successful negotiations, board approval and execution of definitive agreements. The foregoing factors (among others) could cause actual results to differ materially from those set forth in the forward-looking statements.

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

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

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

We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. As environmental remediation matters proceed toward ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required. For additional information see Item 8. Financial Statements and Supplementary Data – Note 25 to the consolidated financial statements.

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

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

Critical Accounting Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the U.S. requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used.

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Estimated Quantities of Net Reserves

The estimation of quantities of net reserves is a highly technical process performed by our engineers for liquid hydrocarbons and natural gas and by outside consultants for synthetic crude oil, which is based upon several underlying assumptions that are subject to change. Estimates of reserves may change, either positively or negatively, as additional information becomes available and as contractual, operational, economic and political conditions change. We evaluate our reserves using drilling results, reservoir performance, seismic interpretation and future plans to develop acreage. The data for a given reservoir may also change substantially over time as a result of numerous factors including, but not limited to, additional development activity, production history and continual reassessment of the viability of production under varying economic conditions. Consequently, material revisions (upward or downward) to existing reserve estimates may occur from time to time. Reserve estimates are based upon an unweighted average of commodity prices in the prior 12-month period, using the closing prices on the first day of each month. These prices are not indicative of future market conditions. For a discussion of our reserve estimation process, including the use of third-party audits, see Item 1. Business.

We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved liquid hydrocarbon, natural gas and synthetic crude oil reserves.

The existence and the estimated amount of reserves affect, among other things, whether certain costs are capitalized or expensed, the amount and timing of costs depreciated, depleted or amortized into net income and the presentation of supplemental information on oil and gas producing activities. Additionally, both the expected future cash flows to be generated by oil and gas producing properties used in testing such properties for impairment and the expected future taxable income available to realize deferred tax assets also rely, in part, on estimates of quantities of net reserves.

Depreciation and depletion of liquid hydrocarbon, natural gas and synthetic crude oil producing properties is determined by the units-of-production method and could change with revisions to estimated proved reserves. Over the past three years, the impact on our depreciation and depletion rate due to revisions of previous reserve estimates has not been significant to any of our segments. The following table illustrates, on average, the sensitivity of each segment's units-of-production DD&A per boe and pretax income to a hypothetical five percent change in 2013 proved reserves based on 2013 production.

	Impact of a Five Percent Increase in Proved Reserves					Impact of a Five Percent Decrease in Proved Reserves
(In millions, except per boe)	DD&A per boe			Pretax Income		DD&A per boe		Pretax Income
North America E&P	$	(1.25	)	$	92	$	1.38	$	(101	)
International E&P	(0.35		)	30		0.38		(33		)
Oil Sands Mining	$	(0.46	)	$	7	$	0.73	$	(11	)

Asset Retirement Obligations

We have material legal, regulatory and contractual obligations to remove and dismantle long-lived assets and to restore land or seabed at the end of oil and gas production operations, including bitumen mining operations. A liability equal to the fair value of such obligations and a corresponding capitalized asset retirement cost are recognized on the balance sheet in the period in which the legal obligation is incurred and a reasonable estimate of fair value can be made. The capitalized asset retirement cost is depreciated using the units-of-production method and the discounted liability is accreted over the period until the obligation is satisfied, the impacts of which are recognized as DD&A in the consolidated statements of income. In many cases, the satisfaction and subsequent discharge of these liabilities is projected to occur many years, or even decades, into the future. Furthermore, the legal, regulatory and contractual requirements often do not provide specific guidance regarding removal practices and the criteria that must be fulfilled when the removal and/or restoration event actually occurs.

Estimates of retirement costs are developed for each property based on numerous factors, such as the scope of the dismantlement, timing of settlement, interpretation of legal, regulatory and contractual requirements, type of production and processing structures, depth of water (if applicable), reservoir characteristics, depth of the reservoir, market demand for equipment, currently available dismantlement and restoration procedures and consultations with construction and engineering professionals. Inflation rates and credit-adjusted-risk-free interest rates are then applied to estimate the fair values of the obligations. To the extent these or other assumptions change after initial recognition of the liability, the fair value estimate is revised and the recognized liability adjusted, with a corresponding adjustment made to the related asset balance. See Item 8. Financial Statements and Supplementary Data – Note 18 to the consolidated financial statements for disclosures regarding our asset retirement obligation estimates.

An estimate of the sensitivity to net income if other assumptions had been used in recording these liabilities is not practical because of the number of obligations that must be assessed, the number of underlying assumptions and the wide range of possible assumptions.

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Fair Value Estimates

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value, or range of present values, using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

• Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the measurement date.

• Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy. See Item 8. Financial Statements and Supplementary Data – Note 15 to the consolidated financial statements for disclosures regarding our fair value measurements.

Significant uses of fair value measurements include:

• impairment assessments of long-lived assets;

• impairment assessments of goodwill;

• allocation of the purchase price paid to acquire businesses to the assets acquired and liabilities assumed; and

• recorded value of derivative instruments.

Impairment Assessments of Long-Lived Assets and Goodwill

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

Long-lived assets in use are assessed for impairment whenever changes in facts and circumstances indicate that the carrying value of the assets may not be recoverable. For purposes of impairment evaluation, long-lived assets must be grouped at the lowest level for which independent cash flows can be identified, which generally is field-by-field for our North America E&P and International E&P assets and at the project level for OSM assets. If the sum of the undiscounted estimated cash flows from the use of the asset group and its eventual disposition is less than the carrying value of an asset group, the carrying value is written down to the estimated fair value.

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

Fair value calculated for the purpose of testing our long-lived assets and goodwill for impairment is estimated using the present value of expected future cash flows method and comparative market prices when appropriate. Significant judgment is involved in performing these fair value estimates since the results are based on forecasted assumptions. Significant assumptions include:

52

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

• Estimated quantities of liquid hydrocarbons, natural gas and synthetic crude oil. Such quantities are based on a combination of reserve categories such that the combined volumes represent the most likely expectation of recovery.

• Expected timing of production. Production forecasts are the outcome of engineer studies which estimate reserves, as well as expected capital development programs. The actual timing of the production could be different than the projection. Cash flows realized later in the projection period are less valuable than those realized earlier due to the time value of money. The expected timing of production that we use in our fair value estimates is consistent with that used in our planning and capital investment reviews.

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

• Future capital requirements. Our estimates of future capital requirements are based upon a combination of authorized spending and internal forecasts.

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

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

Acquisitions

In accounting for business combinations, the purchase price paid to acquire a business is allocated to its assets and liabilities based on the estimated fair values of the assets acquired and liabilities assumed as of the date of acquisition. The excess of the purchase price over the fair value of the net tangible and identifiable intangible assets acquired is recorded as goodwill. A significant amount of judgment is involved in estimating the individual fair values of property, plant and equipment and identifiable intangible assets. The most significant assumptions relate to the estimated fair values allocated to proved and unproved liquid hydrocarbon, natural gas and synthetic crude oil properties. Estimated fair values assigned to assets acquired can have a significant effect on our results of operations in the future. We use all available information to make these fair value determinations and, for certain acquisitions, engage third-party consultants for assistance. During 2013, 2012 and 2011, we completed several business combinations in the Eagle Ford, the purchase prices of which were allocated to the assets acquired and liabilities assumed based on their estimated fair values (see Item 8. Financial Statements and Supplementary Data – Note 5 to the consolidated financial statements).

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

Derivatives

We record all derivative instruments at fair value. Fair value measurements for all our derivative instruments are based on observable market-based inputs that are corroborated by market data and are discussed in Item 8. Financial Statements and Supplementary Data – Note 15 to the consolidated financial statements. Additional information about derivatives and their valuation may be found in Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

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Income Taxes

We are subject to income taxes in numerous taxing jurisdictions worldwide. Estimates of income taxes to be recorded involve interpretation of complex tax laws and assessment of the effects of foreign taxes on our U.S. federal income taxes.

We have recorded deferred tax assets and liabilities for temporary differences between book basis and tax basis, tax credit carryforwards and operating loss carryforwards. We routinely assess the realizability of our deferred tax assets and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. In assessing the need for additional or adjustments to existing valuation allowances, we consider the preponderance of evidence concerning the realization of the deferred tax asset. We must consider any prudent and feasible tax planning strategies that might minimize the amount of deferred tax liabilities recognized or the amount of any valuation allowance recognized against deferred tax assets, if we can implement the strategies and we expect to implement them in the event the forecasted conditions actually occur. Assumptions related to the permanent reinvestment of the earnings of our foreign subsidiaries are reconsidered quarterly to give effect to changes in our portfolio of producing properties and in our tax profile.

Our net deferred tax assets, after valuation allowances, are expected to be realized through our future taxable income and the reversal of temporary differences. Numerous judgments and assumptions are inherent in the estimation of future taxable income, including factors such as future operating conditions (particularly as related to prevailing liquid hydrocarbon, natural gas and synthetic crude oil prices) and the assessment of the effects of foreign taxes on our U.S. federal income taxes. The estimates and assumptions used in determining future taxable income are consistent with those used in our planning and capital investment reviews. We consider a combination of reserve categories related to our existing producing properties, as well as estimated quantities of liquid hydrocarbon, natural gas and synthetic crude oil related to undeveloped discoveries if, in our judgment, it is likely that development plans will be approved in the foreseeable future. Assumptions regarding our ability to realize the U.S. federal benefit of foreign tax credits are based on certain estimates concerning future operating conditions (particularly as related to liquid hydrocarbon, natural gas and synthetic crude oil prices), future financial conditions, income generated from foreign sources and our tax profile in the year that such credits may be claimed.

Pension and Other Postretirement Benefit Obligations

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

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

• the expected long-term return on plan assets;

• the rate of future increases in compensation levels; and

• health care cost projections.

We develop our demographics and utilize the work of third-party actuaries to assist in the measurement of these obligations. We have selected different discount rates for our U.S. pension plans and our other U.S. postretirement benefit plans due to the different projected benefit payment patterns. In determining the assumed discount rates, our methods include a review of market yields on high-quality corporate debt and use of our third-party actuary's discount rate model. This model calculates an equivalent single discount rate for the projected benefit plan cash flows using a yield curve derived from bond yields. The yield curve represents a series of annualized individual spot discount rates from 0.5 to 99 years. The bonds used are rated AA or higher by a recognized rating agency, only non-callable bonds are included and outlier bonds (bonds that have a yield to maturity that significantly deviates from the average yield within each maturity grouping) are removed. Each issue is required to have at least $250 million par value outstanding. The constructed yield curve is based on those bonds representing the 50 percent highest yielding issuances within each defined maturity group.

Of the assumptions used to measure obligations and estimated annual net periodic benefit cost as of December 31, the discount rate has the most significant effect on the periodic benefit cost reported for the plans. The hypothetical impacts of a 0.25 percent change in the discount rates of 4.28 percent for our U.S. pension plans and 4.85 percent for our other U.S. postretirement benefit plans is summarized in the table below:

	Impact of a 0.25 Percent Increase in Discount Rate						Impact of a 0.25 Percent Decrease in Discount Rate
(In millions)	Obligation			Expense			Obligation		Expense
U.S. pension plans	$	(38	)	$	(4	)	$	40	$	4
Other U.S. postretirement benefit plans	$	(7	)	$	—		$	8	$	—

The asset rate of return assumption for the funded U.S. plan considers the plan's asset mix (currently targeted at approximately 55 percent equity and high-yield bonds and 45 percent other fixed income securities), past performance and other factors. Certain

54

components of the asset mix are modeled with various assumptions regarding inflation, debt returns and stock yields. Our long-term asset rate of return assumption is compared to those of other companies and to our historical returns for reasonableness. Decreasing the 6.75 percent asset rate of return assumption by 0.25 would not have a significant impact on our defined benefit pension expense. Effective January 1, 2014, the expected long-term rate of return was changed from 7.25 percent to 6.75 percent and this change also did not have a significant impact.

Compensation change assumptions are based on historical experience, anticipated future management actions and demographics of the benefit plans. Health care cost trend assumptions are developed based on historical cost data, the near-term outlook and an assessment of likely long-term trends.

Item 8. Financial Statements and Supplementary Data – Note 20 to the consolidated financial statements includes detailed information about the assumptions used to calculate the components of our annual defined benefit pension and other postretirement plan expense, as well as the obligations and accumulated other comprehensive income reported on the consolidated balance sheets.

Contingent Liabilities

We accrue contingent liabilities for environmental remediation, tax deficiencies related to operating taxes, and litigation claims when such contingencies are probable and estimable. Actual costs can differ from estimates for many reasons. For instance, settlement costs for claims and litigation can vary from estimates based on differing interpretations of laws, opinions on responsibility and assessments of the amount of damages. Similarly, liabilities for environmental remediation may vary from estimates because of changes in laws, regulations and their interpretation, additional information on the extent and nature of site contamination, and improvements in technology. Our in-house legal counsel regularly assesses these contingent liabilities. In certain circumstances, outside legal counsel is utilized.

We generally record losses related to these types of contingencies as other operating expense or general and administrative expense in the consolidated statements of income, except for tax contingencies unrelated to income taxes, which are recorded as taxes other than income. For additional information on contingent liabilities, see 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.

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

Accounting Standards Not Yet Adopted

In June 2013, the FASB ratified the Emerging Issues Task Force consensus which requires that an unrecognized tax benefit (or a portion thereof ) be presented as a reduction to a deferred tax asset for an available net operating loss carryforward, a similar tax loss or tax credit carryforward. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied prospectively to unrecognized tax benefits that exist as of the effective date. Early adoption and retrospective application are permitted. Adoption of this accounting standards update will not have a significant impact on our consolidated results of operations, financial position or cash flows.

In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within U.S. GAAP. An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of 1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and 2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption is permitted. Adoption of this accounting standards update will not have a significant impact on our consolidated results of operations, financial position or cash flows.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risks related to the volatility of liquid hydrocarbon, natural gas and synthetic crude oil prices. We employ various strategies, including the use of commodity derivative instruments, to manage the risks related to these price fluctuations. We are also exposed to market risks related to changes in interest rates and foreign currency exchange rates. We employ various strategies, including the use of financial derivative instruments, to manage the risks related to these fluctuations.

55

We are at risk for changes in the fair value of all of our derivative instruments; however, such risk should be mitigated by price or rate changes related to the underlying commodity or financial transaction.

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

See Item 8. Financial Statements and Supplementary Data – Notes 15 and 16 to the consolidated financial statements for more information about the fair value measurement of our derivatives, the amounts recorded in our consolidated balance sheets and statements of income and the related notional amounts.

Commodity Price Risk

Our strategy is to obtain competitive prices for our products and allow operating results to reflect market price movements dictated by supply and demand. However, management will periodically protect prices on forecasted sales, as deemed appropriate. We use a variety of commodity derivative instruments, including futures, forwards, swaps and combinations of options, as part of an overall program to manage commodity price risk in our different businesses. Our consolidated results for 2013 and 2012 were impacted by crude oil derivatives related to a portion of our forecast North America E&P crude oil sales, all of which had terms that ended in December 2013.

We regularly use commodity derivative instruments in the North America E&P segment to manage natural gas price risk. Examples would include the hedging of storage and transportation assets, and when appropriate, managing equity price exposure.

Interest Rate Risk

We are impacted by interest rate fluctuations which affect the fair value of certain financial instruments. We manage our exposure to interest rate movements by utilizing financial derivative instruments. The primary objective of this program is to reduce our overall cost of borrowing by managing the mix of fixed and floating interest rate debt in our portfolio. As of December 31, 2013, we had multiple interest rate swap agreements with a total notional of $900 million designated as fair value hedges, which effectively results in an exchange of existing obligations to pay fixed interest rates for obligations to pay floating rates.

At December 31, 2013, our portfolio of long-term debt was substantially comprised of fixed rate instruments. Therefore, the fair value of the portfolio is relatively sensitive to interest rate fluctuations. Our sensitivity to interest rate declines and corresponding increases in the fair value of our debt portfolio unfavorably affects our results of operations and cash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices above carrying value.

Sensitivity analysis of the incremental effect of a hypothetical 10 percent change in interest rates on financial assets and liabilities as of December 31, 2013, is provided in the following table.

					Incremental
					Change in
(In millions)	Fair Value				Fair Value
Financial assets (liabilities): (a)
Interest rate swap agreements	$	8		(b)	$	4
Long-term debt, including amounts due within one year	$	(6,922	)	(b)(c)	$	(234	)

^(a)  Fair values of cash and cash equivalents, receivables, commercial paper, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.

^(b)  Fair value was based on market prices where available, or current borrowing rates for financings with similar terms and maturities.

^(c)  Excludes capital leases.

Foreign Currency Exchange Rate Risk

We may manage our exposure to foreign currency exchange rates by utilizing forward and option contracts. The primary objective of this program is to reduce our exposure to movements in foreign currency exchange rates by locking in such rates. As of December 31, 2013, our foreign currency forwards had a notional of 2,387 million Norwegian Kroner, which served as a hedge of our current Norwegian tax liability. The incremental change in the fair value of foreign currency derivative contracts of a hypothetical 10 percent change in exchange rates at December 31, 2013 would be $39 million.

Counterparty Risk

We are also exposed to financial risk in the event of nonperformance by counterparties. The creditworthiness of counterparties is reviewed and master netting agreements are used when appropriate.

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Safe Harbor

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

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Item 8. Financial Statements and Supplementary Data

Index

	Page
Management’s Responsibilities for Financial Statements	59
Management’s Report on Internal Control over Financial Reporting	59
Report of Independent Registered Public Accounting Firm	60
Audited Consolidated Financial Statements
Consolidated Statements of Income	61
Consolidated Statements of Comprehensive Income	62
Consolidated Balance Sheets	63
Consolidated Statements of Cash Flows	64
Consolidated Statements of Stockholders’ Equity	65
Notes to Consolidated Financial Statements	66
Select Quarterly Financial Data (Unaudited)	101
Supplementary Information on Oil and Gas Producing Activities (Unaudited)	102
Supplemental Statistics (Unaudited)	110

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Management’s Responsibilities for Financial Statements

To the Stockholders of Marathon Oil Corporation:

The accompanying consolidated financial statements of Marathon Oil Corporation and its consolidated subsidiaries ("Marathon Oil") are the responsibility of management and have been prepared in conformity with accounting principles generally accepted in the United States. They necessarily include some amounts that are based on best judgments and estimates. The financial information displayed in other sections of this Annual Report on Form 10-K is consistent with these consolidated financial statements.

Marathon Oil seeks to assure the objectivity and integrity of its financial records by careful selection of its managers, by organization arrangements that provide an appropriate division of responsibility and by communications programs aimed at assuring that its policies and methods are understood throughout the organization.

The Board of Directors pursues its oversight role in the area of financial reporting and internal control over financial reporting through its Audit and Finance Committee. This Committee, composed solely of independent directors, regularly meets (jointly and separately) with the independent registered public accounting firm, management and internal auditors to monitor the proper discharge by each of their responsibilities relative to internal accounting controls and the consolidated financial statements.

/s/ Lee M. Tillman	/s/ John R. Sult
President and Chief Executive Officer	Executive Vice President and Chief Financial Officer

Management’s Report on Internal Control over Financial Reporting

To the Stockholders of Marathon Oil Corporation:

Marathon Oil’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13(a) – 15(f) under the Securities Exchange Act of 1934). An evaluation of the design and effectiveness of our internal control over financial reporting, based on the original 1992 framework in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, was conducted under the supervision and with the participation of management, including our Chief Executive Officer and Chief Financial Officer. Based on the results of this evaluation, Marathon Oil’s management concluded that its internal control over financial reporting was effective as of December 31, 2013.

The effectiveness of Marathon Oil’s internal control over financial reporting as of December 31, 2013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

/s/ Lee M. Tillman	/s/ John R. Sult
President and Chief Executive Officer	Executive Vice President and Chief Financial Officer

59

Report of Independent Registered Public Accounting Firm

To the Stockholders of Marathon Oil Corporation:

In our opinion, the consolidated financial statements listed in the accompanying index present fairly, in all material respects, the financial position of Marathon Oil Corporation and its subsidiaries (the "Company") at December 31, 2013, and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in the original 1992 framework in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Houston, Texas

February 28, 2014

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MARATHON OIL CORPORATION

Consolidated Statements of Income

(In millions, except per share data)	2013			2012			2011
Revenues and other income:
Sales and other operating revenues, including related party	$	12,419		$	12,963		$	10,750
Marketing revenues	2,082			2,729			3,919
Income from equity method investments	423			370			462
Net gain (loss) on disposal of assets	(29		)	127			103
Other income	64			32			48
Total revenues and other income	14,959			16,221			15,282
Costs and expenses:
Production	2,331			2,202			1,951
Marketing, including purchases from related parties	2,072			2,744			3,898
Other operating	439			425			533
Exploration	988			706			641
Depreciation, depletion and amortization	2,790			2,477			2,263
Impairments	96			371			310
Taxes other than income	352			248			193
General and administrative	687			699			663
Total costs and expenses	9,755			9,872			10,452
Income from operations	5,204			6,349			4,830
Net interest and other	(274		)	(219		)	(107		)
Loss on early extinguishment of debt	—			—			(279		)
Income from continuing operations before income taxes	4,930			6,130			4,444
Provision for income taxes	3,337			4,517			2,726
Income from continuing operations	1,593			1,613			1,718
Discontinued operations	160			(31		)	1,228
Net income	$	1,753		$	1,582		$	2,946
Per Share Data
Basic:
Income from continuing operations	$	2.26		$	2.28		$	2.42
Discontinued operations	$	0.23		$	(0.04	)	$	1.73
Net income	$	2.49		$	2.24		$	4.15
Diluted:
Income from continuing operations	$	2.24		$	2.27		$	2.41
Discontinued operations	$	0.23		$	(0.04	)	$	1.72
Net income	$	2.47		$	2.23		$	4.13
Dividends	$	0.72		$	0.68		$	0.80
Weighted average shares:
Basic	705			706			710
Diluted	709			710			714

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

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MARATHON OIL CORPORATION

Consolidated Statements of Comprehensive Income

(In millions)	2013			2012			2011
Net income	$	1,753		$	1,582		$	2,946
Other comprehensive income (loss)
Postretirement and postemployment plans
Change in actuarial loss and other	296			(97		)	16
Income tax benefit (provision)	(112		)	35			20
Postretirement and postemployment plans, net of tax	184			(62		)	36
Derivative hedges
Net unrecognized gain	1			1			9
Income tax provision	—			—			(4		)
Derivative hedges, net of tax	1			1			5
Foreign currency translation and other
Unrealized gain (loss)	(3		)	1			(1		)
Income tax benefit (provision)	1			(3		)	—
Foreign currency translation and other, net of tax	(2		)	(2		)	(1		)
Other comprehensive income (loss)	183			(63		)	40
Comprehensive income	$	1,936		$	1,519		$	2,986

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

62

MARATHON OIL CORPORATION

Consolidated Balance Sheets

	December 31,
(In millions, except per share data)	2013			2012
Assets
Current assets:
Cash and cash equivalents	$	264		$	684
Receivables	2,134			2,418
Inventories	364			361
Other current assets	213			299
Total current assets	2,975			3,762
Equity method investments	1,201			1,279
Property, plant and equipment, less accumulated depreciation,
depletion and amortization of $21,895 and $19,266	28,145			28,272
Goodwill	499			525
Other noncurrent assets	2,800			1,468
Total assets	$	35,620		$	35,306
Liabilities
Current liabilities:
Commercial paper	$	135		$	200
Accounts payable	2,206			2,324
Payroll and benefits payable	240			217
Accrued taxes	1,445			1,983
Other current liabilities	239			173
Long-term debt due within one year	68			184
Total current liabilities	4,333			5,081
Long-term debt	6,394			6,512
Deferred tax liabilities	2,492			2,432
Defined benefit postretirement plan obligations	604			856
Asset retirement obligations	2,009			1,749
Deferred credits and other liabilities	444			393
Total liabilities	16,276			17,023
Commitments and contingencies
Stockholders’ Equity
Preferred stock - no shares issued or outstanding (no par value,
26 million shares authorized)	—			—
Common stock:
Issued – 770 million and 770 million shares (par value $1 per share,
1.1 billion shares authorized)	770			770
Securities exchangeable into common stock – no shares issued
or outstanding (no par value, 29 million shares authorized)	—			—
Held in treasury, at cost – 73 million and 63 million shares	(2,903		)	(2,560		)
Additional paid-in capital	6,592			6,616
Retained earnings	15,135			13,890
Accumulated other comprehensive loss	(250		)	(433		)
Total stockholders' equity	19,344			18,283
Total liabilities and stockholders' equity	$	35,620		$	35,306

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

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MARATHON OIL CORPORATION

Consolidated Statements of Cash Flows

(In millions)	2013			2012			2011
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	1,753		$	1,582		$	2,946
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations	(160		)	31			(1,228		)
Loss on early extinguishment of debt	—			—			279
Deferred income taxes	(60		)	(224		)	(193		)
Depreciation, depletion and amortization	2,790			2,477			2,263
Impairments	96			371			310
Pension and other postretirement benefits, net	45			(31		)	64
Exploratory dry well costs and unproved property impairments	798			457			357
Net (gain) loss on disposal of assets	29			(127		)	(103		)
Equity method investments, net	12			11			47
Changes in:
Current receivables	277			(502		)	9
Inventories	(16		)	(32		)	33
Current accounts payable and accrued liabilities	(616		)	71			489
All other operating, net	143			(48		)	168
Net cash provided by continuing operations	5,091			4,036			5,441
Net cash provided by (used in) discontinued operations	179			(19		)	1,083
Net cash provided by operating activities	5,270			4,017			6,524
Investing activities:
Acquisitions, net of cash acquired	(74		)	(1,033		)	(4,470		)
Additions to property, plant and equipment	(4,766		)	(4,593		)	(2,986		)
Disposal of assets	450			467			518
Investments - return of capital	61			57			59
Investing activities of discontinued operations	(227		)	(347		)	(802		)
All other investing, net	35			10			14
Net cash used in investing activities	(4,521		)	(5,439		)	(7,667		)
Financing activities:
Commercial paper, net	(65		)	200			—
Borrowings	—			1,997			—
Debt issuance costs	—			(21		)	—
Debt repayments	(182		)	(145		)	(2,877		)
Purchases of common stock	(500		)	—			(300		)
Dividends paid	(508		)	(480		)	(567		)
Financing activities of discontinued operations	—			—			2,916
Distribution in spin-off	—			—			(1,622		)
All other financing, net	93			49			155
Net cash provided by (used in) financing activities	(1,162		)	1,600			(2,295		)
Effect of exchange rate changes on cash	(7		)	13			(20		)
Net increase (decrease) in cash and cash equivalents	(420		)	191			(3,458		)
Cash and cash equivalents at beginning of period	684			493			3,951
Cash and cash equivalents at end of period	$	264		$	684		$	493

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

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MARATHON OIL CORPORATION

Consolidated Statements of Stockholders’ Equity

	Total Equity of Marathon Oil Stockholders
(In millions)	Preferred Stock		Common Stock		Securities Exchangeable into Common Stock		Treasury Stock			Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Loss			Non- controlling Interest			Total Equity
January 1, 2011 Balance	$	—	$	770	$	—	$	(2,665	)	$	6,756		$	19,907		$	(997	)	$	—		$	23,771
Shares issued - stock-based
compensation	—		—		—		257			(85		)	—			—			—			172
Shares repurchased	—		—		—		(308		)	—			—			—			—			(308		)
Stock-based compensation	—		—		—		—			4			—			—			—			4
Net income	—		—		—		—			—			2,946			—			—			2,946
Other comprehensive income	—		—		—		—			—			—			40			—			40
Dividends paid	—		—		—		—			—			(567		)	—			—			(567		)
Purchase of subsidiary
shares from non-
controlling interest	—		—		—		—			—			—			—			7			7
Spin-off of downstream	—		—		—		—			5			(9,498		)	587			—			(8,906		)
December 31, 2011 Balance	$	—	$	770	$	—	$	(2,716	)	$	6,680		$	12,788		$	(370	)	$	7		$	17,159
Shares issued - stock-based
compensation	—		—		—		164			(75		)	—			—			—			89
Shares repurchased	—		—		—		(8		)	—			—			—			—			(8		)
Stock-based compensation	—		—		—		—			22			—			—			—			22
Net income	—		—		—		—			—			1,582			—			—			1,582
Other comprehensive loss	—		—		—		—			—			—			(63		)	—			(63		)
Dividends paid	—		—		—		—			—			(480		)	—			—			(480		)
Purchase of subsidiary
shares from non-
controlling interest	—		—		—		—			—			—			—			(7		)	(7		)
Other	—		—		—		—			(11		)	—			—			—			(11		)
December 31, 2012 Balance	$	—	$	770	$	—	$	(2,560	)	$	6,616		$	13,890		$	(433	)	$	—		$	18,283
Shares issued - stock-based
compensation	—		—		—		170			(44		)	—			—			—			126
Shares repurchased	—		—		—		(513		)	—			—			—			—			(513		)
Stock-based compensation	—		—		—		—			20			—			—			—			20
Net income	—		—		—		—			—			1,753			—			—			1,753
Other comprehensive income	—		—		—		—			—			—			183			—			183
Dividends paid	—		—		—		—			—			(508		)	—			—			(508		)
December 31, 2013 Balance	$	—	$	770	$	—	$	(2,903	)	$	6,592		$	15,135		$	(250	)	$	—		$	19,344
(Shares in millions)	Preferred Stock		Common Stock		Securities Exchangeable into Common Stock		Treasury Stock
January 1, 2011 Balance	—		770		—		60
Shares issued - stock-based
compensation	—		—		—		(6		)
Shares repurchased	—		—		—		12
December 31, 2011 Balance	—		770		—		66
Shares issued - stock-based
compensation	—		—		—		(3		)
December 31, 2012 Balance	—		770		—		63
Shares issued - stock-based
compensation	—		—		—		(4		)
Shares repurchased	—		—		—		14
December 31, 2013 Balance	—		770		—		73

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

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

1. Summary of Principal Accounting Policies

We are engaged in worldwide exploration, production and marketing of liquid hydrocarbons and natural gas; production and marketing of products manufactured from natural gas, such as LNG and methanol, in E.G.; and oil sands mining, bitumen transportation and upgrading, and marketing of synthetic crude oil and vacuum gas oil in Canada.

Principles applied in consolidation – These consolidated financial statements include the accounts of our majority-owned, controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis.

Equity method investments – Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. This includes entities in which we hold majority ownership but the minority stockholders have substantive participating rights in the investee. Income from equity method investments represents our proportionate share of net income generated by the equity method investees.

Equity method investments are carried at our share of net assets plus loans and advances. Such investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net income. Differences in the basis of the investments and the separate net asset value of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets, except for the excess related to goodwill.

Discontinued operations – Disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations unless otherwise stated. Due to the agreements entered in 2013 to sell our Angola assets (see Note 6), the corresponding results of operations and cash flows have been classified as discontinued operations for all presented periods. As a result of the spin-off of our downstream business in 2011 (see Note 3), the related results of operations and cash flows have been classified as discontinued operations for all periods prior to the spin-off.

Use of estimates – The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods.

Reclassifications – Beginning in 2013, we changed the presentation of our consolidated statements of income, primarily to present additional details of revenues and expenses and to classify certain expenses more consistently with our peer group of independent exploration and production companies. To effect these changes, reclassifications of previously reported amounts were made and are reflected in these consolidated financial statements. As a result of the reclassifications, general and administrative expenses for 2012 and 2011 increased by $144 million and $119 million which primarily includes certain costs associated with operations support and operations management. Offsetting reductions are reflected in production, other operating and exploration expenses and taxes other than income.

Foreign currency transactions – The U.S. dollar is the functional currency of our foreign operating subsidiaries. Foreign currency transaction gains and losses are included in net income.

Revenue recognition – Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. We follow the sales method of accounting for crude oil and natural gas production imbalances and would recognize a liability if our existing proved reserves were not adequate to cover an imbalance. Imbalances have not been significant in the periods presented.

In the lower 48 states of the U.S., production volumes of liquid hydrocarbons and natural gas are generally sold immediately and transported to market. In international locations, liquid hydrocarbon production volumes may be stored as inventory and sold at a later time. In Canada, mined bitumen is first processed through an upgrader and then sold as synthetic crude oil. Both bitumen and synthetic crude oil may be stored as inventory.

Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with original maturities of three months or less.

Accounts receivable – The majority of our receivables are from joint interest owners in properties we operate or from purchasers of commodities, both of which are recorded at invoiced amounts and do not bear interest. We often have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We conduct credit reviews of commodity purchasers prior to making commodity sales to new customers or increasing credit for existing customers. Based on these reviews,

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

we may require a standby letter of credit or a financial guarantee. Uncollectible accounts receivable are reserved against the allowance for uncollectible accounts when it is determined the receivable will not be collected and the amount of any reserve may be reasonably estimated.

Inventories – Inventories are carried at the lower of cost or market value. The majority of our inventories are recorded at average cost. The last-in, first-out ("LIFO") method is used for our U.S. crude oil and natural gas inventories.

We may enter into a contract to sell a particular quantity and quality of crude oil at a specified location and date to a particular counterparty, and simultaneously agree to buy a particular quantity and quality of the same commodity at a specified location on the same or another specified date from the same counterparty. We account for such matching buy/sell arrangements as exchanges of inventory.

Derivative instruments – We may use derivatives to manage a portion of our exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk. All derivative instruments are recorded at fair value. Commodity derivatives and interest rate swaps are reflected on our consolidated balance sheet on a net basis by counterparty, as they are governed by master netting agreements. Cash flows related to derivatives used to manage commodity price risk, foreign currency risk and interest rate risk are classified in operating activities with the underlying transactions. Our derivative instruments contain no significant contingent credit features.

Cash flow hedges – We may use foreign currency forwards and options to manage foreign currency risk associated with anticipated transactions and designate them as cash flow hedges. No such derivatives were outstanding at December 31, 2013 and 2012. The effective portion of changes in fair value is recognized in other comprehensive income ("OCI") and is reclassified to net income when the underlying forecasted transaction is recognized in net income. Any ineffective portion is recognized in net interest and other as it occurs. For a discontinued cash flow hedge, prospective changes in the fair value of the derivative are recognized in net income. The accumulated gain or loss recognized in OCI at the time a hedge is discontinued continues to be deferred until the original forecasted transaction occurs. However, if it is determined that the likelihood of the original forecasted transaction occurring is no longer probable, the entire accumulated gain or loss recognized in OCI is immediately reclassified into net income.

We may use interest rate derivative instruments to manage the risk of interest rate changes during the period prior to anticipated borrowings and designate them as cash flow hedges. No such derivatives were outstanding at December 31, 2013 and 2012.

Fair value hedges – We may use interest rate swaps to manage our exposure to interest rate risk associated with fixed interest rate debt in our portfolio; commodity derivative instruments to manage the price risk on natural gas that we purchase to be marketed with our natural gas production; and foreign currency forwards to manage our exposure to changes in the value of foreign currency denominated tax liabilities. Changes in the fair values of both the hedged item and the related derivative are recognized immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect is to report in net income the extent to which the hedge is not effective in achieving offsetting changes in fair value.

Derivatives not designated as hedges – Derivatives that are not designated as hedges may include commodity derivatives used primarily to manage price risk on the forecasted sale of crude oil, natural gas and synthetic crude oil that we produce. Changes in the fair value of derivatives not designated as hedges are recognized immediately in net income.

Concentrations of credit risk – All of our financial instruments, including derivatives, involve elements of credit and market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The counterparties to our financial instruments consist primarily of major financial institutions and companies within the energy industry. To manage counterparty risk associated with financial instruments, we select and monitor counterparties based on our assessment of their financial strength and on credit ratings, if available. Additionally, we limit the level of exposure with any single counterparty.

Fair value transfer – We recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. When significant transfers occur, they are disclosed in Note 15 to the consolidated financial statements.

Property, plant and equipment – We use the successful efforts method of accounting for oil and gas producing activities, which include bitumen mining and upgrading.

Property acquisition costs – Costs to acquire mineral interests in traditional oil and natural gas properties or in oil sands mines, to drill and equip exploratory wells in progress and those that find proved reserves, to drill and equip development wells and to construct or expand oil sands mines and upgrading facilities are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves but cannot yet be classified as proved are capitalized if (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (2) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended exploratory well costs is monitored continuously and reviewed at least quarterly.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Depreciation, depletion and amortization – Capitalized costs to acquire oil and natural gas properties, which include bitumen mining and upgrading facilities, are depreciated and depleted on a units-of-production basis based on estimated proved reserves. Capitalized costs of exploratory wells and development costs are depreciated and depleted on a units-of-production basis based on estimated proved developed reserves. Support equipment and other property, plant and equipment related to oil and gas producing activities are depreciated on a straight-line basis over their estimated useful lives which range from 3 to 40 years.

Property, plant and equipment unrelated to oil and gas producing activities is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 40 years.

Impairments – We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells, development costs and our bitumen mining and upgrading facilities, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors and may apply an undiscounted future net cash flow approach when appropriate. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage are also considered. When unproved property investments are deemed to be impaired the expense is reported in exploration expenses.

Dispositions – When property, plant and equipment depreciated on an individual basis are sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale. Proceeds from the disposal of property, plant and equipment depreciated on a group basis are credited to accumulated depreciation, depletion and amortization with no immediate effect on net income until net book value is reduced to zero.

Goodwill – Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Such goodwill is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to impairments.

Major maintenance activities – Costs for planned major maintenance are expensed in the period incurred and can include the costs of contractor repair services, materials and supplies, equipment rentals and our labor costs.

Environmental costs – Environmental expenditures are capitalized only if the costs mitigate or prevent future contamination or if the costs improve the environmental safety or efficiency of the existing assets. We provide for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed or reliably determinable.

Asset retirement obligations – The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Our asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities, which include our bitumen mining facilities. Asset retirement obligations for such facilities include costs to dismantle and relocate or dispose of production platforms, mine assets, gathering systems, wells and related structures and restoration costs of land and seabed, including those leased. Estimates of these costs are developed for each property based on the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering professionals. Asset retirement obligations have not been recognized for certain of our international oil and gas producing facilities as we currently do not have a legal obligation associated with the retirement of those facilities. Asset retirement obligations have not been recognized for the removal of materials and equipment from or the closure of certain bitumen upgrading assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate.

Inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for oil and gas production facilities, which include our bitumen mining facilities, while accretion escalates over the lives of the assets.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Deferred income taxes – Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. We routinely assess the realizability of our deferred tax assets based on several interrelated factors and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. These factors include our expectation to generate sufficient future taxable income including future foreign source income, tax credits, operating loss carryforwards and management’s intent regarding the permanent reinvestment of the income from certain foreign subsidiaries.

Stock-based compensation arrangements – The fair value of stock options is estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock option award. Of the required assumptions, the expected life of the stock option award and the expected volatility of our stock price have the most significant impact on the fair value calculation. We have utilized historical data and analyzed current information which reasonably support these assumptions.

The fair value of our restricted stock awards and common stock units is determined based on the market value of our common stock on the date of grant. Unearned stock-based compensation is charged to stockholders’ equity when restricted stock awards are granted.

The fair value of our stock-based performance units is estimated using the Monte Carlo simulation method. Since these awards are settled in cash at the end of a defined performance period, they are classified as a liability and are re-measured quarterly until settlement.

Our stock-based compensation expense is recognized based on management’s best estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods.

2. Accounting Standards

Not Yet Adopted

In June 2013, the FASB ratified the Emerging Issues Task Force consensus which requires that an unrecognized tax benefit (or a portion thereof ) be presented as a reduction to a deferred tax asset for an available net operating loss carryforward, a similar tax loss or tax credit carryforward. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied prospectively to unrecognized tax benefits that exist as of the effective date. Early adoption and retrospective application are permitted. Adoption of this accounting standards update will not have a significant impact on our consolidated results of operations, financial position or cash flows.

In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within U.S. GAAP. An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of 1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and 2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption is permitted. Adoption of this accounting standards update will not have a significant impact on our consolidated results of operations, financial position or cash flows.

Recently Adopted

In February 2013, an accounting standards update was issued to improve the reporting of reclassifications out of accumulated other comprehensive income. This standard requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This accounting standards update was effective for us beginning the first quarter of 2013

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

and we present the required disclosures in Note 22. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

In December 2011, an accounting standards update designed to enhance disclosures about offsetting assets and liabilities was issued. Further clarification limiting the scope of these disclosures to derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions was issued in January 2013. The disclosures are intended to enable financial statement users to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. Entities are required to disclose both gross information and net information about in-scope financial instruments that are either offset in the statement of financial position or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. The accounting standards update was effective for us beginning the first quarter of 2013 and we include the required disclosures in Note 16. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

In September 2011, the FASB amended accounting standards to simplify how entities test goodwill for impairment. The amendment reduces complexity by allowing an entity the option to make a qualitative evaluation of whether it is necessary to perform the two-step goodwill impairment test. Adoption of this amendment in 2012 did not have a significant impact on our consolidated results of operations, financial position or cash flows.

The FASB amended the reporting standards for comprehensive income in June 2011 to eliminate the option to present the components of OCI as part of the statement of changes in stockholders' equity. All non-owner changes in stockholders’ equity are required to be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of OCI, and total comprehensive income. The presentation of items that are reclassified from OCI to net income on the income statement is also required. The amendments did not change the items that must be reported in OCI or when an item of OCI must be reclassified to net income. The amendments were effective for us beginning with the first quarter of 2012, except for the presentation of reclassifications, which was deferred and addressed in the February 2013 accounting standards update discussed above. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

In May 2011, the FASB issued an update amending the accounting standards for fair value measurement and disclosure, resulting in common principles and requirements under U.S. GAAP and IFRS. The amendments change the wording used to describe certain of the U.S. GAAP requirements either to clarify the intent of existing requirements, to change measurement or expand disclosure principles or to conform to the wording used in IFRS. Adoption of the amendments in 2012 did not have a significant impact on our consolidated results of operations, financial position or cash flows. To the extent they were necessary, we made the expanded disclosures in Notes 15 and 16.

3. Spin-off of 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. On June 30, 2011, stockholders of record as of 5:00 p.m. Eastern Daylight Savings time on June 27, 2011 (the "Record Date") received one common share of MPC stock for every two common shares of Marathon stock held as of the Record Date.

In order to effect the spin-off and govern our relationship with MPC after the spin-off, we entered into a Separation and Distribution Agreement, a Tax Sharing Agreement and an Employee Matters Agreement. The Separation and Distribution Agreement governed the separation of the downstream business, the distribution of MPC’s shares of common stock to our stockholders, transfer of assets and intellectual property, and other matters related to our relationship with MPC. The Separation and Distribution Agreement provides for cross-indemnities between Marathon Oil and MPC. In general, we have agreed to indemnify MPC for any liabilities relating to our historical exploration and production and oil sands mining operations, and MPC has agreed to indemnify us for any liabilities relating to the historical downstream operations.

The Tax Sharing Agreement governs the respective rights, responsibilities and obligations of Marathon Oil and MPC with respect to taxes and tax benefits, the filing of tax returns, the control of audits and other tax matters. In addition, the Tax Sharing Agreement reflects each company’s rights and obligations related to taxes that are attributable to periods prior to and including the separation date and taxes resulting from transactions effected in connection with the separation. In general, under the Tax Sharing Agreement, Marathon Oil is responsible for all U.S. federal, state, local and foreign income taxes attributable to Marathon Oil or any of its subsidiaries for any tax period that begins after the date of the spin-off, and MPC is responsible for all taxes attributable to it or its subsidiaries, whether accruing before, on or after the spin-off. The Tax Sharing Agreement contains covenants intended to protect the tax-free status of the spin-off. These covenants may restrict the ability of Marathon Oil and MPC to pursue strategic or other transactions that otherwise could maximize the values of their respective businesses and may discourage or delay a change of control of either company.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

The Employee Matters Agreement contains provisions concerning benefit protection for employees who became MPC employees prior to December 31, 2011, treatment of holders of Marathon stock options, stock appreciation rights, restricted stock and restricted stock units, and cooperation between Marathon Oil and MPC in the sharing of employee information and maintenance of confidentiality. Unvested equity-based compensation awards were converted to awards of the entity where the employee holding them worked post-separation. For vested equity-based compensation awards, employees received both Marathon Oil and MPC awards.

The results of operations of our downstream business have been reported as discontinued operations for 2011. The table below shows selected financial information reported in discontinued operations related to the spin-off.

(In millions)	2011
Revenues applicable to discontinued operations	$	38,602
Pretax income from discontinued operations	$	2,012

4. Variable Interest Entities

The owners of the AOSP, in which we hold a 20 percent undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership ("Corridor Pipeline") to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton. The contract, originally signed in 1999 by a company we acquired, allows each holder of an undivided interest in the AOSP to ship materials in accordance with its undivided interest. Costs under this contract are accrued and recorded on a monthly basis, with a $3 million current liability recorded at December 31, 2013, consistent with December 31, 2012. Under this agreement, the AOSP absorbs all of the operating and capital costs of the pipeline. Currently, no third-party shippers use the pipeline. Should shipments be suspended, by choice or due to force majeure, we remain responsible for the portion of the payments related to our undivided interest for all remaining periods. The contract expires in 2029; however, the shippers can extend its term perpetually. This contract qualifies as a variable interest contractual arrangement and the Corridor Pipeline qualifies as a variable interest entity ("VIE"). We hold a variable interest but are not the primary beneficiary because our shipments are only 20 percent of the total; therefore the Corridor Pipeline is not consolidated by Marathon Oil. Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was $723 million as of December 31, 2013. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term. We have not provided financial assistance to Corridor Pipeline and we do not have any guarantees of such assistance in the future.

5. Acquisitions

During 2013, 2012 and 2011, our business combinations related to properties acquired by our North America E&P segment in the Eagle Ford in south Texas. The pro forma impact of these transactions, individually and in the aggregate, is not material to our consolidated statements of income for any periods presented.

The fair values of assets acquired and liabilities assumed in each of these business combinations were measured primarily using an income approach, specifically utilizing a discounted cash flow analysis. The estimated fair values were based on significant inputs not observable in the market, and therefore represent Level 3 measurements. Significant inputs included estimated reserve volumes, the expected future production profile, estimated commodity prices and assumptions regarding future operating and development costs. The discount rates used in the discounted cash flow analyses were approximately 10 percent for the 2013 and 2012 transactions and 11 percent for the 2011 transaction.

2013

In July 2013, we acquired 4,800 net undeveloped acres in the Eagle Ford in a transaction valued at $97 million, including carried interest of $23 million. The transaction was accounted for as a business combination, with the entire up-front cash consideration of $74 million allocated to property, plant and equipment at the acquisition date.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

2012 & 2011

We acquired approximately 25,000 net acres in the core of the Eagle Ford during 2012. The largest transactions were the acquisitions of Paloma Partners II, LLC, which closed in the second quarter of 2012 for cash consideration of $768 million, and an acquisition of proved and unproved properties that closed in the third quarter of 2012 for cash consideration of $232 million. These transactions were accounted for as business combinations.

During the fourth quarter of 2011, we closed a series of transactions in the Eagle Ford that were accounted for as a business combination. The most significant of these transactions was the acquisition of Hilcorp Resources, LLC. The total cash consideration paid for all the transactions including approximately 167,000 net acres and a gathering system, was $4.5 billion.

The following table summarizes the amounts allocated to the assets acquired and liabilities assumed based upon their fair values at the acquisition dates:

	Closed in Quarter Ended
	June 30,		September 30,		December 31,
(In millions)	2012		2012		2011
Current assets:
Cash	$	8	$	—	$	—
Receivables	22		8		40
Inventories	1		—		4
Other current assets	—		—		30
Total current assets acquired	31		8		74
Property, plant and equipment	822		248		4,501
Other noncurrent assets	—		—		21
Total assets acquired	853		256		4,596
Current liabilities:
Accounts payable	78		23		101
Other current liabilities	—		—		20
Total current liabilities assumed	78		23		121
Asset retirement obligations	7		1		5
Total liabilities assumed	85		24		126
Net assets acquired	$	768	$	232	$	4,470

In addition, during 2011, our North America E&P segment acquired approximately 108,000 net acres in the Eagle Ford for approximately $265 million. These transactions were accounted for as asset acquisitions.

6. Dispositions

2013 - North America E&P

In June 2013, we closed the sale of our interests in the DJ Basin for proceeds of $19 million. A pretax loss of $114 million was recorded in the second quarter of 2013.

In February 2013, we conveyed our interests in the Marcellus natural gas shale play to the operator. A $43 million pretax loss on this transaction was recorded in the first quarter of 2013.

In February 2013, we closed the sale of our interest in the Neptune gas plant, located onshore Louisiana, for proceeds of $166 million. A $98 million pretax gain was recorded in the first quarter of 2013.

In January 2013, we closed the sale of our remaining assets in Alaska, for proceeds of $195 million, subject to a six-month escrow of $50 million which was collected in July 2013. After closing adjustments were made in the second quarter of 2013, the pretax gain on this sale was $55 million.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Assets held for sale in the December 31, 2012 consolidated balance sheet were related to the Neptune gas plant and Alaska dispositions that were pending at that date and included:

(In millions)	December 31, 2012
Other current assets	$	50
Other noncurrent assets	248
Total assets	$	298
Deferred credits and other liabilities	$	83
Total liabilities	$	83

2013 - International E&P

In the fourth quarter of 2013, we transfered our 45 percent working interest and operatorship in the Safen block in the Kurdistan Region of Iraq at a pretax loss of $17 million.

In June and December 2013, we entered into agreements, valued in total at $2.1 billion before closing adjustments, to sell our non-operated 10 percent working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32. The sale of our interest in Block 31 closed in February 2014 and the sale of our interest in Block 32 is expected to close in the first quarter of 2014. Block 31 is presented as held for sale and Block 32 is reflected as unproved property in property, plant and equipment in the December 31, 2013 consolidated balance sheet (See Note 13 for discussion of the capitalized costs related to suspended wells). Our entire Angola operations are reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented.

Assets held for sale in the December 31, 2013 consolidated balance sheet were related to the Angola Block 31 disposition that was pending at that date and included:

(In millions)	December 31, 2013
Other current assets	$	41
Other noncurrent assets	1,647
Total assets	$	1,688
Other current liabilities	$	25
Deferred credits and other liabilities	43
Total liabilities	$	68

Related amounts reported in discontinued operations for 2013, 2012 and 2011 were as follows:

(In millions)	2013		2012			2011
Revenues applicable to discontinued operations	$	361	$	—		$	—
Pretax income (loss) from discontinued operations	$	247	$	(17	)	$	(17	)

2012 - North America E&P

In the third quarter of 2012, we sold approximately 5,800 net undeveloped acres in the Eagle Ford for proceeds of $9 million. A pretax loss of $18 million was recorded.

In January 2012, we closed on the sale of our interests in several Gulf of Mexico crude oil pipeline systems for proceeds of $206 million. This included our equity method interests in Poseidon Oil Pipeline Company, L.L.C. and Odyssey Pipeline L.L.C., as well as certain other oil pipeline interests, including the Eugene Island pipeline system. A pretax gain of $166 million was recorded.

2012 - International E&P

In May 2012, we executed agreements to relinquish our operatorship of and participating interests in the Bone Bay and Kumawa exploration licenses in Indonesia. As a result, we reported a $36 million pretax loss on disposal of assets. Government ratification of the agreements released us from our obligations and further commitments related to these licenses.

2011 - North America E&P

In December 2011, we sold our 50 percent interest in the Burns Point gas plant, a cryogenic processing plant located in St. Mary Parish, Louisiana, for total consideration of $36 million and a pretax gain of $34 million.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

In September 2011, we sold our equity interest in an LNG processing facility in Alaska and a pretax gain on the transaction of $8 million was recorded.

In April 2011, we assigned a 30 percent undivided working interest in approximately 180,000 acres in the Niobrara shale play located within the DJ Basin of southeast Wyoming and northern Colorado for total consideration of $270 million, recording a pretax gain of $37 million. See the discussion of our 2013 disposal of the remaining interest above.

7.    Income per Common Share

Basic income per share is based on the weighted average number of common shares outstanding. Diluted income per share assumes exercise of stock options and stock appreciation rights, provided the effect is not antidilutive.

	2013				2012						2011
(In millions, except per share data)	Basic		Diluted		Basic			Diluted			Basic		Diluted
Income from continuing operations	$	1,593	$	1,593	$	1,613		$	1,613		$	1,718	$	1,718
Discontinued operations	160		160		(31		)	(31		)	1,228		1,228
Net income	$	1,753	$	1,753	$	1,582		$	1,582		$	2,946	$	2,946
Weighted average common shares outstanding	705		705		706			706			710		710
Effect of dilutive securities	—		4		—			4			—		4
Weighted average common shares, including dilutive effect	705		709		706			710			710		714
Per share:
Income from continuing operations	$	2.26	$	2.24	$	2.28		$	2.27		$	2.42	$	2.41
Discontinued operations	$	0.23	$	0.23	$	(0.04	)	$	(0.04	)	$	1.73	$	1.72
Net income	$	2.49	$	2.47	$	2.24		$	2.23		$	4.15	$	4.13

The per share calculations above exclude 5 million, 10 million and 7 million stock options in 2013, 2012 and 2011 that were antidilutive.

8. Segment Information

 Beginning in 2013, we changed our reportable segments and revised our management reporting to better reflect the growing importance of United States unconventional resource plays to our business. All periods presented have been recast to reflect these new segments.

We have three reportable operating segments.  Each of these segments is organized and managed based upon both geographic location and the nature of the products and services it offers:

• North America E&P ("N.A. E&P") – explores for, produces and markets liquid hydrocarbons and natural gas in North America;

• International E&P ("Int'l E&P") – explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and

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

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”).  Segment income represents income from continuing operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. These costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities, net of associated income tax effects. Unrealized gains or losses on crude oil derivative instruments, certain impairments, gains or losses on dispositions or other items that affect comparability (as determined by the CODM) also are not allocated to operating segments.

In 2013, we entered into agreements to sell our Angola assets; therefore, the Angola operations are reflected as discontinued operations and excluded from the International E&P segment in all periods presented.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

As discussed in Note 3, our downstream business was spun-off on June 30, 2011 and has been reported as discontinued operations for 2011.  Sales to MPC previously reported as intersegment revenues are reported as sales and other operating revenues because such sales were expected to continue subsequent to the spin-off.  These sales were $1.4 billion in the first six months of 2011.

2013							Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	5,068	$	5,827	$	1,576	$	(52	)	(c)	$	12,419
Marketing revenues	1,797		267		18		—				2,082
Total revenues	6,865		6,094		1,594		(52		)		14,501
Income from equity method investments	—		427		—		(4		)	(d)	423
Net gain (loss) on disposal of assets and other income	12		50		5		(32		)		35
Production expenses	797		534		1,000		—				2,331
Marketing costs	1,796		258		18		—				2,072
Exploration expenses	725		263		—		—				988
Depreciation, depletion and amortization	1,927		621		218		24				2,790
Impairments	41		—		—		55				96
Other expenses (a)	420		239		66		401				1,126
Taxes other than income	318		7		22		5				352
Net interest and other	—		—		—		274				274
Provision (benefit) for income taxes	324		3,226		69		(282		)		3,337
Segment income/Income from continuing operations	$	529	$	1,423	$	206	$	(565	)		$	1,593
Capital expenditures (b)	$	3,649	$	764	$	286	$	285			$	4,984

^(a)  Includes other operating expenses and general and administrative expenses.

^(b)  Includes accruals.

^(c)  Unrealized gain (loss) on crude oil derivative instruments.

^(d)  EGHoldings impairment (see Note 15).

2012							Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	3,944	$	7,445	$	1,521	$	53		(c)	$	12,963
Marketing revenues	2,451		248		30		—				2,729
Total revenues	6,395		7,693		1,551		53				15,692
Income from equity method investments	2		368		—		—				370
Net gain (loss) on disposal of assets and other income	11		30		4		114				159
Production expenses	706		500		996		—				2,202
Marketing costs	2,444		269		31		—				2,744
Exploration expenses	588		118		—		—				706
Depreciation, depletion and amortization	1,428		787		217		45				2,477
Impairments	11		—		—		360				371
Other expenses (a)	400		200		60		464				1,124
Taxes other than income	226		5		22		(5		)		248
Net interest and other	—		—		—		219				219
Provision (benefit) for income taxes	223		4,552		58		(316		)		4,517
Segment income/Income from continuing operations	$	382	$	1,660	$	171	$	(600	)		$	1,613
Capital expenditures (b)	$	3,988	$	489	$	188	$	466			$	5,131

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

2011								Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM			to Segments			Total
Sales and other operating revenues	$	3,364	$	5,851	$	1,535		$	—		$	10,750
Marketing revenues	3,614		252		53			—			3,919
Total revenues	6,978		6,103		1,588			—			14,669
Income from equity method investments	20		442		—			—			462
Net gain (loss) on disposal of assets and other income	21		73		(17		)	74			151
Production expenses	545		409		915			82			1,951
Marketing costs	3,598		247		53			—			3,898
Exploration expenses	388		253		—			—			641
Depreciation, depletion and amortization	1,191		828		196			48			2,263
Impairments	12		—		—			298			310
Other expenses (a)	494		191		46			465			1,196
Taxes other than income	182		6		17			(12		)	193
Net interest and loss on early extinguishment of debt	—		—		—			386			386
Provision (benefit) for income taxes	217		2,693		83			(267		)	2,726
Segment income/Income from continuing operations	$	392	$	1,991	$	261		$	(926	)	$	1,718
Capital expenditures (b)	$	2,163	$	544	$	308		$	384		$	3,399

Revenues from external customers are attributed to geographic areas based upon selling location. The following summarizes revenues from external customers by geographic area.

(In millions)	2013		2012		2011
United States	$	6,813	$	6,448	$	6,978
Norway	3,183		3,714		3,563
Canada	1,594		1,551		1,588
Libya(a)	1,106		1,989		216
Other international	1,805		1,990		2,324
Total revenues	$	14,501	$	15,692	$	14,669

^(a)  See Note 13 for discussion of Libya operations.

In 2013, sales to British Petroleum and its affiliates accounted for approximately 11 percent of our total revenues. In 2012, Statoil, the purchaser of the majority of our Libyan crude oil, accounted for approximately 15 percent of our total revenues, while sales to Shell Oil and its affiliates accounted for approximately 12 percent of total revenues. In 2011, our sales to MPC accounted for approximately 18 percent of total revenues.

Revenues by product line were:

(In millions)	2013		2012		2011
Liquid hydrocarbons	$	11,932	$	12,983	$	11,778
Natural gas	937		1,052		1,203
Synthetic crude oil	1,542		1,409		1,442
Other	90		248		246
Total revenues	$	14,501	$	15,692	$	14,669

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

The following summarizes certain long-lived assets by geographic area, including property, plant and equipment and equity method investments.

	December 31,
(In millions)	2013		2012
United States	$	14,635	$	13,677
Canada	9,794		9,693
Norway	977		987
Equatorial Guinea	1,977		2,081
Other international	1,963		3,113
Total long-lived assets	$	29,346	$	29,551

9. Other Items

Net interest and other

(In millions)	2013			2012			2011
Interest:
Interest income	$	6		$	13		$	12
Interest expense(a)	(307		)	(244		)	(228		)
Income on interest rate swaps	9			7			10
Interest capitalized	21			12			103
Total interest	(271		)	(212		)	(103		)
Other:
Net foreign currency gains	16			4			24
Write off of contingent proceeds	(4		)	—			(7		)
Other	(15		)	(11		)	(21		)
Total other	(3		)	(7		)	(4		)
Net interest and other	$	(274	)	$	(219	)	$	(107	)

^(a)  Excludes $1 million and $10 million paid by United States Steel in2012 and 2011 on assumed debt.

Foreign currency transactions – Aggregate foreign currency gains (losses) were included in the consolidated statements of income as follows:

(In millions)	2013		2012			2011
Net interest and other	$	16	$	4		$	24
Provision for income taxes	105		(80		)	57
Aggregate foreign currency gains (losses)	$	121	$	(76	)	$	81

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

10. Income Taxes

Income tax provisions (benefits) for continuing operations were:

	2013							2012									2011
(In millions)	Current		Deferred			Total		Current			Deferred			Total			Current			Deferred			Total
Federal	$	63	$	(46	)	$	17	$	(80	)	$	(30	)	$	(110	)	$	(193	)	$	(217	)	$	(410	)
State and local	44		1			45		(23		)	47			24			24			82			106
Foreign	3,290		(15		)	3,275		4,844			(241		)	4,603			3,088			(58		)	3,030
Total	$	3,397	$	(60	)	$	3,337	$	4,741		$	(224	)	$	4,517		$	2,919		$	(193	)	$	2,726

A reconciliation of the federal statutory income tax rate applied to income from continuing operations before income taxes to the provision for income taxes follows:

	2013		2012		2011
Statutory rate applied to income from continuing operations before income taxes	35	%	35	%	35	%
Effects of foreign operations, including foreign tax credits	14		18		6
Change in permanent reinvestment assertion	—		—		5
Adjustments to valuation allowances	18		21		14
Tax law changes	—		—		1
Other	1		—		—
Effective income tax rate on continuing operations	68	%	74	%	61	%

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income, the relative magnitude of these sources of income, and foreign currency remeasurement effects. 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 appears in the "Not Allocated to Segments" column of the tables in Note 8.

Effects of foreign operations – The effects of foreign operations on our effective tax rate decreased in 2013 as compared to 2012, primarily due to decreased sales in Libya in 2013 as a result of third-party labor strikes at the Es Sider oil terminal. The effects of foreign operations on our effective tax rate increased in 2012 from 2011, primarily due to the resumption of sales of Libyan production in 2012.

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 recognizing deferred U.S. tax on previously undistributed earnings.

Adjustments to valuation allowances – In 2013, 2012 and 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 those years.

Tax law changes – The U.K. enacted Finance Bill 2013 in July 2013 and Finance Bill 2012 in July 2012, which did not change the rate of corporation tax or the supplementary corporation tax for U.K. ring-fenced activities in the oil and gas sector. As such, this legislation did not have a material impact on our consolidated income tax provision. In July 2011, the U.K. enacted Finance Bill 2011 which increased the rate of the supplementary charge levied on profits from U.K. oil and gas production from 20 percent to 32 percent. As a result of this legislation, we recorded deferred tax expense of $10 million in 2011.

On May 25, 2011, Michigan enacted legislation that replaced the Michigan Business Tax ("MBT") with a corporate income tax ("CIT"), effective January 1, 2012. The CIT legislation eliminated the "book-tax difference deduction" that was provided under the MBT to mitigate the net increase in a taxpayer’s deferred tax liability resulting when Michigan moved from the Single Business Tax, a non-income tax, to the MBT, an income tax, on July 12, 2007. Such a change in the tax law must be recognized in earnings in the period enacted regardless of the effective date. The total effect of tax law changes on deferred tax balances is recorded as income tax expense related to continuing operations in the period the law is enacted, even if a portion of the deferred tax balances relates to discontinued operations. As a result of the new CIT legislation, we recorded deferred tax expense of $32 million in the second quarter of 2011.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Deferred tax assets and liabilities resulted from the following:

	December 31,
(In millions)	2013			2012
Deferred tax assets:
Employee benefits	$	387		$	510
Operating loss carryforwards	284			368
Foreign tax credits	5,730			4,351
Other	98			121
Valuation allowances:
Federal	(2,997		)	(2,067		)
State, net of federal benefit	(67		)	(60		)
Foreign	(149		)	(210		)
Total deferred tax assets	3,286			3,013
Deferred tax liabilities:
Property, plant and equipment	4,018			3,691
Investments in subsidiaries and affiliates	794			840
Other	67			12
Total deferred tax liabilities	4,879			4,543
Net deferred tax liabilities	$	1,593		$	1,530

Tax carryforwards – At December 31, 2013, our operating loss carryforwards included $744 million from Canada which expire in 2026 through 2030 and $128 million from the Kurdistan Region of Iraq that expire in 2016 through 2018. State operating loss carryforwards of $1,503 million expire in 2014 through 2033. Foreign tax credit carryforwards of $3,560 million expire in 2022 through 2023.

Valuation allowances – The estimated realizability of the benefit of foreign tax credits is based on certain estimates concerning future operating conditions (particularly as related to prevailing liquid hydrocarbon, natural gas and synthetic crude oil prices), future financial conditions, income generated from foreign sources and our tax profile in the years that such credits may be claimed. Federal valuation allowances increased $930 million, $1,277 million and $585 million in 2013, 2012 and 2011, because it is more likely than not that we will be unable to realize all U.S. benefits on foreign taxes accrued in those years.

Foreign valuation allowances decreased $61 million in 2013, primarily due the disposal of our Indonesian assets. Foreign valuation allowances increased $16 million and $52 million in 2012 and 2011, primarily due to deferred tax assets generated in the Kurdistan Region of Iraq, Angola and Indonesia.

Net deferred tax liabilities were classified in the consolidated balance sheets as follows:

	December 31,
(In millions)	2013		2012
Assets:
Other current assets	$	53	$	57
Other noncurrent assets	847		849
Liabilities:
Other current liabilities	1		4
Noncurrent deferred tax liabilities	2,492		2,432
Net deferred tax liabilities	$	1,593	$	1,530

We are continuously undergoing examination of our U.S. federal income tax returns by the IRS. Such audits have been completed through the 2009 tax year. We believe adequate provision has been made for federal income taxes and interest which may become payable for years not yet settled. Further, we are routinely involved in U.S. state income tax audits and foreign jurisdiction tax audits. We believe all other audits will be resolved within the amounts paid and/or provided for these liabilities.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

As of December 31, 2013, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:

United States(a)	2004-2012
Canada	2008-2012
Equatorial Guinea	2007-2012
Libya	2006-2012
Norway	2008-2012
United Kingdom	2008-2012

^(a)  Includes federal and state jurisdictions.

The following table summarizes the activity in unrecognized tax benefits:

(In millions)	2013			2012			2011
Beginning balance	$	98		$	157		$	103
Additions for tax positions related to the current year	14			—			4
Additions for tax positions of prior years	66			81			87
Reductions for tax positions of prior years	(25		)	(67		)	(29		)
Settlements	(5		)	(72		)	(8		)
Statute of limitations	(2		)	(1		)	—
Ending balance	$	146		$	98		$	157

If the unrecognized tax benefits as of December 31, 2013 were recognized, $98 million would affect our effective income tax rate. There were $11 million of uncertain tax positions as of December 31, 2013 for which it is reasonably possible that the amount of unrecognized tax benefits would significantly increase or decrease during the next twelve months.

Interest and penalties are recorded as part of the tax provision and were $13 million, $4 million and $13 million related to unrecognized tax benefits in 2013, 2012 and 2011. As of December 31, 2013 and 2012, $15 million and $24 million of interest and penalties were accrued related to income taxes.

Pretax income from continuing operations included amounts attributable to foreign sources of $4,874 million, $6,382 million and $4,886 million in 2013, 2012 and 2011.

Undistributed income of certain consolidated foreign subsidiaries at December 31, 2013 amounted to $1,438 million for which no U.S. deferred income tax provision has been recorded because we intend to permanently reinvest such income in our foreign operations. If such income was not permanently reinvested, income tax expense of approximately $503 million would be recorded, not including potential utilization of foreign tax credits.

11. Inventories

Inventories are carried at the lower of cost or market value. The LIFO method accounted for 4 percent and 6 percent of total inventory value at December 31, 2013 and 2012. Current acquisition costs were estimated to exceed the LIFO inventory value at December 31, 2013 and 2012 by $32 million and $29 million.

	December 31,
(In millions)	2013		2012
Liquid hydrocarbons, natural gas and bitumen	$	55	$	73
Supplies and other items	309		288
Inventories at cost	$	364	$	361

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

12. Equity Method Investments and Related Party Transactions

During 2013, 2012 and 2011 only our equity method investees were considered related parties and they included:

•Alba Plant LLC, in which we have a 52 percent noncontrolling interest. Alba Plant LLC processes LPG.

• AMPCO, in which we have a 45 percent interest. AMPCO is engaged in methanol production activity.

• EGHoldings, in which we have a 60 percent noncontrolling interest. EGHoldings is engaged in LNG production activity.

Our equity method investments are summarized in the following table:

	Ownership as of	December 31,
(In millions)	December 31, 2013	2013		2012
EGHoldings	60%	$	748	$	817
Alba Plant LLC	52%	263		264
AMPCO	45%	189		187
Other investments		1		11
Total		$	1,201	$	1,279

Dividends and partnership distributions received from equity method investees (excluding distributions that represented a return of capital previously contributed) were $435 million in 2013, $381 million in 2012 and $509 million in 2011.

Summarized financial information for equity method investees is as follows:

(In millions)	2013		2012		2011
Income data – year:
Revenues and other income	$	1,444	$	1,330	$	1,544
Income from operations	849		755		942
Net income	727		635		820
Balance sheet data – December 31:
Current assets	$	644	$	607
Noncurrent assets	1,590		1,743
Current liabilities	384		395
Noncurrent liabilities	33		29

Revenues from related parties were $55 million, $58 million and $60 million in 2013, 2012 and 2011, with the majority related to EGHoldings in all years. Purchases from related parties were $242 million, $248 million and $250 million in 2013, 2012 and 2011 with the majority related to Alba Plant LLC in all years.

Current receivables from related parties at December 31, 2013 and 2012, approximately split evenly between EGHoldings and AMPCO, were $30 million and $27 million. Payables to related parties were $20 million at December 31, 2013 and 2012, with the majority related to Alba Plant LLC.

13. Property, Plant and Equipment

	December 31,
(In millions)	2013			2012
North America E&P	$	26,755		$	23,748
International E&P	12,428			13,214
Oil Sands Mining	10,436			10,127
Corporate	421			449
Total property, plant and equipment	50,040			47,538
Less accumulated depreciation, depletion and amortization	(21,895		)	(19,266		)
Net property, plant and equipment	$	28,145		$	28,272

During the third quarter of 2013, our Libya production operations were impacted by third-party labor strikes at the Es Sider oil terminal. We have had no oil liftings in Libya since July 2013. Uncertainty around production and sales levels from Libya have existed since the first quarter of 2011 when production operations were suspended until the fourth quarter of that year.  We

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

and our partners in the Waha concessions continue to assess the condition of our assets in Libya and uncertainty around production and sales levels remains. As of December 31, 2013, our net property, plant and equipment investment in Libya is approximately $761 million and total proved reserves (unaudited) in Libya are 249 mmboe.

Deferred exploratory well costs were as follows:

	December 31,
(In millions)	2013			2012			2011
Amounts capitalized less than one year after completion of drilling	$	512		$	388		$	482
Amounts capitalized greater than one year after completion of drilling	281			229			222
Total deferred exploratory well costs	$	793		$	617		$	704
Number of projects with costs capitalized greater than one year after
completion of drilling	7			6			5
	December 31,
(In millions)	2013			2012			2011
Beginning balance	$	617		$	704		$	657
Additions	746			699			625
Dry well expense	(147		)	(111		)	(223		)
Transfers to development	(414		)	(629		)	(279		)
Dispositions	(9		)	(46		)	(76		)
Ending balance	$	793		$	617		$	704

Exploratory well costs capitalized greater than one year after completion of drilling as of December 31, 2013 are summarized by geographical area below:

(In millions)
Angola	$	153
Norway	70
E.G.	22
Canada	36
Total	$	281

Well costs that have been suspended for longer than one year are associated with seven projects. Management believes these projects with suspended exploratory drilling costs exhibit sufficient quantities of hydrocarbons to justify potential development.

Angola – Exploration on Angola Block 31 began in 2004, with costs accumulating through 2009. Exploration on Angola Block 32 began in 2011, with costs accumulating through 2013. In June and December 2013, we entered into agreements to sell our non-operated working interests in Angola Blocks 31 and 32 (see Note 6).

Norway – Three offshore Norway projects had costs incurred from 2009 through 2011. The development plan for Boyla was approved by the Norwegian government in October 2012. This will tie-back to the Alvheim FPSO and development drilling is planned in 2014, with first production expected in early 2015. Development options are being evaluated for the Caterpillar and Viper projects.

E.G. – The Corona well on Block D offshore E.G. was drilled in 2004, and we acquired an additional interest in the well in 2012. We plan to develop Block D through a unitization with the Alba field, which is currently being negotiated.

Canada – Exploration began on our Canadian in-situ assets at Birchwood in 2010 with costs accumulating through 2011. In 2012, we submitted a regulatory application for a proposed 12 mbbld SAGD demonstration project.  We expect to receive regulatory approval for this project by the end of 2014.  Upon receiving this approval, we will further evaluate our development plans.

14. Goodwill

Goodwill is tested for impairment on an annual basis, or when events or changes in circumstances indicate the fair value of a reporting unit with goodwill has been reduced below its carrying value. We performed our annual impairment tests during 2013, 2012 and 2011 and no impairment was required. The fair value of each of our reporting units with goodwill exceeded the book value appreciably.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

The changes in the carrying amount of goodwill for 2012 were as follows for the Exploration and Production ("E&P") and OSM segments in place for that year:

(In millions)	E&P			OSM			Total
2012
Beginning balance, gross	$	536		$	1,412		$	1,948
Less: accumulated impairments	—			(1,412		)	(1,412		)
Beginning balance, net	536			—			536
Dispositions	(11		)	—			(11		)
Ending balance, net	$	525		$	—		$	525

As discussed in Note 8, beginning in 2013, we changed our reportable segments. Goodwill related to the previously reported E&P segment was allocated between the North America E&P and International E&P segments as of January 1, 2013 based on the relative fair values of those reporting units. The fair values of the reporting units were measured using an income approach based upon internal estimates of future production levels, commodity prices and discount rates, all of which are Level 3 inputs.  Inputs to the fair value measurements included reserve and production estimates made by our reservoir engineers, estimated commodity prices adjusted for quality and location differentials, and forecasted operating expenses. The table below displays the allocated beginning goodwill balances by segment along with changes in the carrying amount of goodwill for 2013:

(In millions)	N.A. E&P			Int'l E&P			OSM			Total
2013
Beginning balance, gross	$	343		$	182		$	1,412		$	1,937
Less: accumulated impairments	—			—			(1,412		)	(1,412		)
Beginning balance, net	343			182			—			525
Dispositions	4		(a)	(30		)	—			(26		)
Ending balance, net	$	347		$	152		$	—		$	499

^(a) Goodwill related to our Alaska disposition was less than the estimate classified as held for sale in 2012.

15. Fair Value Measurements

Fair values – Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2013 and 2012 by fair value hierarchy level.

	December 31, 2013
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Interest rate	$	—	$	8	$	—	$	—	$	8
Foreign currency	—		2		—		—		2
Derivative instruments, assets	$	—	$	10	$	—	$	—	$	10
Derivative instruments, liabilities
Foreign currency	$	—	$	4	$	—	$	—	$	4
Derivative instruments, liabilities	$	—	$	4	$	—	$	—	$	4
	December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Commodity	$	—	$	52	$	—	$	1	$	53
Interest rate	—		21		—		—		21
Foreign currency	—		18		—		—		18
Derivative instruments, assets	$	—	$	91	$	—	$	1	$	92

Interest rate swaps are measured at fair value with a market approach using actionable broker quotes which are Level 2 inputs.  Foreign currency forwards are measured at fair value with a market approach using third-party pricing services, such as

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Bloomberg L.P., which have been corroborated with data from active markets for similar assets or liabilities, and are Level 2 inputs.

Commodity swaps in Level 2 are measured at fair value with a market approach using prices obtained from exchanges or pricing services, which have been corroborated with data from active markets for similar assets or liabilities.  Commodity options in Level 2 are valued using the Black-Scholes Model.  Inputs to this model include prices as noted above, discount factors, and implied market volatility.  The inputs to this fair value measurement are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.  Collateral deposits related to commodity derivatives are in broker accounts covered by master netting agreements.

Fair values – Nonrecurring

The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.

	2013				2012				2011
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	5	$	96	$	16	$	371	$	226	$	285
Intangible assets	—		—		—		—		—		25

International E&P

Long-lived assets held for use – In light of E.G.’s recent natural gas policy developments related to the country’s natural gas resources, we elected to cease our efforts to develop a second LNG production train on Bioko Island and recorded a $40 million impairment of all capitalized costs associated with engineering and feasibility studies in the fourth quarter of 2013. In addition, our share of income from EGHoldings included a $4 million impairment related to the same project which is reflected in income from equity method investments in the 2013 consolidated statement of income.

North America E&P

Long-lived assets held for use – The fair values were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs.  Inputs to the fair value measurement included reserve and production estimates made by our reservoir engineers, estimated commodity prices adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.

In the fourth quarter of 2012, declining natural gas prices related to our Powder River Basin asset prompted lower production expectations and reductions in estimated reserves which resulted in an impairment of $73 million. Subsequently, in the first quarter of 2013, as a result of our decision to wind down operations in the Powder River Basin due to poor economics, an additional impairment of $15 million was recorded to write down the asset's remaining fair value.

During early 2012, production rates from the Ozona development in the Gulf of Mexico declined significantly.  Accordingly, our reserve engineers performed evaluations of our future production as well as our reserves and an impairment was recorded in the first quarter of 2012. As the development produced toward abandonment pressures, further downward revisions of reserves were taken for an aggregate impairment of $289 million in 2012.  Ozona production ceased in the first quarter of 2013 and an additional $21 million impairment was recorded.

In May 2011, significant water production and reservoir pressure declines occurred at our Droshky development in the Gulf of Mexico. Plans for a waterflood were canceled and due to a decrease in proved reserves, a $273 million impairment of this asset to its $226 million fair value was recorded in 2011.

Other impairments of long-lived assets held for use in 2013, 2012 and 2011 were a result of reduced drilling expectations, reductions of estimated reserves or declining natural gas prices.

Intangible assets– In the second quarter of 2011, our outlook for U.S. natural gas prices made it unlikely that sufficient U.S. demand for LNG would materialize by 2021, which is when the rights lapse under our arrangements at the Elba Island, Georgia regasification facility. Using an income approach based upon internal estimates of gas prices and future deliveries, which are Level 3 inputs, we determined that the contract had no remaining fair value and recorded a full impairment of this intangible asset.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Fair values – Financial instruments

Our current assets and liabilities include financial instruments, the most significant of which are receivables, commercial paper and payables. We believe the carrying values of our receivables, commercial paper and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our investment-grade credit rating, and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.

The following table summarizes financial instruments, excluding receivables, commercial paper, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at December 31, 2013 and 2012.

	December 31,
	2013				2012
(In millions)	Fair Value		Carrying Amount		Fair Value		Carrying Amount
Financial assets
Other noncurrent assets	$	154	$	147	$	189	$	186
Total financial assets	$	154	$	147	$	189	$	186
Financial liabilities
Other current liabilities	$	13	$	13	$	13	$	13
Long-term debt, including current portion(a)	6,922		6,427		7,610		6,642
Deferred credits and other liabilities	149		147		94		94
Total financial liabilities	$	7,084	$	6,587	$	7,717	$	6,749

^(a)  Excludes capital leases.

Fair values of our financial assets included in other noncurrent assets, and of our financial liabilities included in other current liabilities and deferred credits and other liabilities are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.

Most of our long-term debt instruments are publicly-traded. A market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value of such debt. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.

16. Derivatives

For further information regarding the fair value measurement of derivative instruments see Note 15. See Note 1 for discussion of the types of derivatives we use and the reasons for them. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. Netting is assessed by counterparty, and as of December 31, 2013 and 2012, there were no offsetting amounts. Positions by contract were all either assets or liabilities. The following tables present the gross fair values of derivative instruments, excluding cash collateral, and the reported net amounts along with where they appear on the consolidated balance sheets as of December 31, 2013 and 2012.

	December 31, 2013
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	8	$	—	$	8	Other noncurrent assets
Foreign currency	2		—		2		Other current assets
Total Designated Hedges	$	10	$	—	$	10

	December 31, 2013
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	—	$	4	$	4	Other current liabilities
Total Designated Hedges	$	—	$	4	$	4

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

	December 31, 2012
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	21	$	—	$	21	Other noncurrent assets
Foreign currency	18		—		18		Other current assets
Total Designated Hedges	39		—		39
Not Designated as Hedges
Commodity	52		—		52		Other current assets
Total Not Designated as Hedges	52		—		52
Total	$	91	$	—	$	91

Derivatives Designated as Fair Value Hedges

The following table presents by maturity date, information about our interest rate swap agreements as of December 31, 2013, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.

Maturity Dates	Aggregate Notional Amount (in millions)		Weighted Average, LIBOR-Based, Floating Rate
October 1, 2017	$	600	4.65	%
March 15, 2018	$	300	4.50	%

As of December 31, 2012, we had multiple interest rate swap agreements with a total notional amount of $600 million, a weighted average, LIBOR-based, floating rate of 4.70 percent and a maturity date of October 1, 2017.

In connection with debt retirements in February and March 2011, we settled interest rate swaps with a notional amount of $1,450 million. We recorded a $29 million gain, which reduced the loss on early extinguishment of debt.

As of December 31, 2013 and 2012, our foreign currency forwards had an aggregate notional amount of 2,387 million and 3,043 million Norwegian Kroner at weighted average forward rates of 6.060 and 5.780. These forwards hedge our current Norwegian tax liability and those outstanding at December 31, 2013 have settlement dates through June 2014.

The pretax effect of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below. There is no ineffectiveness related to the fair value hedges.

		Gain (Loss)
(In millions)	Income Statement Location	2013			2012			2011
Derivative
Interest rate	Net interest and other	$	(13	)	$	16		$	28
Interest rate	Loss on early extinguishment of debt	—			—			29
Foreign currency	Provision for income taxes	(44		)	(1		)	—
Hedged Item
Long-term debt	Net interest and other	$	13		$	(16	)	$	(28	)
Long-term debt	Loss on early extinguishment of debt	—			—			(29		)
Accrued taxes	Provision for income taxes	44			1			—

Derivatives Not Designated as Hedges

In August 2012, we entered into crude oil derivative instruments related to a portion of our forecasted North America E&P crude oil sales. These commodity derivatives were not designated as hedges and had terms that ended in December 2013.

The impact of all commodity derivative instruments not designated as hedges appears in sales and other operating revenues in our consolidated statements of income and were a net loss of $67 million in 2013 and net gains of $70 million and $5 million in 2012 and 2011.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

17. Debt

Short-term debt

As of December 31, 2013, we had no borrowings against our revolving credit facility, as described below, and we had $135 million in commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.

Our $2.5 billion unsecured five-year revolving credit facility (the "Credit Facility") was entered in April 2012.  The Credit Facility matures in April 2017, but allows us to request two one-year extensions.   It contains an option to increase the commitment amount by up to an additional $1.0 billion, subject to the consent of any increasing lenders, and includes sub-facilities for swing-line loans and letters of credit up to an aggregate amount of $100 million and $500 million, respectively.  The agreement contains a covenant that requires our ratio of total debt to total capitalization not to exceed 65 percent as of the last day of each fiscal quarter.  If an event of default occurs, the lenders may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility.

Long-term debt

The following table details our long-term debt:

	December 31,
(In millions)	2013			2012
Senior unsecured notes:
9.125% notes due 2013	$	—		$	114
0.900% notes due 2015(a)	1,000			1,000
6.000% notes due 2017(a)	682			682
5.900% notes due 2018(a)	854			854
7.500% notes due 2019(a)	228			228
2.800% notes due 2022(a)	1,000			1,000
9.375% notes due 2022	32			32
Series A notes due 2022	3			3
8.500% notes due 2023	70			70
8.125% notes due 2023	131			131
6.800% notes due 2032(a)	550			550
6.600% notes due 2037	750			750
Capital leases:
Capital lease obligation of consolidated subsidiary due 2014 – 2049	10			11
Other obligations:
4.550% promissory note, semi-annual payments due 2014 – 2015	136			204
5.125% obligation relating to revenue bonds due 2037	1,000			1,000
Other	—			35
Total(b)	6,446			6,664
Unamortized discount	(9		)	(11		)
Fair value adjustments(c)	25			43
Amounts due within one year	(68		)	(184		)
Total long-term debt due after one year	$	6,394		$	6,512

^(a)  These notes contain a make-whole provision allowing us the right to repay the debt at a premium to market price.

^(b)  In the event of a change in control, as defined in the related agreements, debt obligations totaling $236 million at December 31, 2013, may be declared immediately due and payable.

^(c)  See Notes 15 and 16 for information on interest rate swaps.

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

The following table shows five years of long-term debt payments:

(In millions)
2014	$	68
2015	1,068
2016	—
2017	682
2018	854

18. Asset Retirement Obligations

The following summarizes the changes in asset retirement obligations:

(In millions)	2013			2012
Beginning balance	$	1,783		$	1,510
Incurred, including acquisitions	84			150
Settled, including dispositions	(78		)	(35		)
Accretion expense (included in depreciation, depletion and amortization)	106			91
Revisions to previous estimates	244			150
Held for sale	(43		)	(83		)
Ending balance(a)	$	2,096		$	1,783

^(a)  Includes asset retirement obligations of $87 million and $34 million classified as short-term at December 31,2013 and 2012.

19. Supplemental Cash Flow Information

(In millions)	2013			2012			2011
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	307		$	225		$	268
Income taxes paid to taxing authorities	3,904			4,974			2,893
Commercial paper:
Issuances	$	10,870		$	13,880		$	421
Repayments	(10,935		)	(13,680		)	(421		)
Net commercial paper	$	(65	)	$	200		$	—
Noncash investing and financing activities, related to continuing operations:
Additions to property, plant and equipment:
Asset retirement costs capitalized, excluding acquisitions	$	319		$	257		$	148
Change in capital expenditure accrual	(9		)	187			104
Liabilities assumed in acquisitions	—			109			126
Asset retirement obligations assumed by buyer	92			8			5
Debt payments made by United States Steel	—			20			214

20. Defined Benefit Postretirement Plans and Defined Contribution Plan

We have noncontributory defined benefit pension plans covering substantially all domestic employees as well as international employees located in Norway and the U.K. Benefits under these plans are based on plan provisions specific to each plan.

We also have defined benefit plans for other postretirement benefits covering our U.S. employees. Health care benefits are provided through comprehensive hospital, surgical and major medical benefit provisions subject to various cost-sharing features. Life insurance benefits are provided to certain retiree beneficiaries. Other postretirement benefits are not funded in advance.

Obligations and funded status– The accumulated benefit obligation for all defined benefit pension plans was $1,359 million and $1,442 million as of December 31, 2013 and 2012.    

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MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

As of December 31, 2013, our U.S. plans had accumulated benefit obligations in excess of plan assets, and as of December 31, 2012, our U.S. plans and our international ("Int'l") plans had accumulated benefit obligations in excess of plan assets. Summary information for these defined benefit pension plans follows.

	December 31,
	2013			2012
(In millions)	U.S.			U.S.			Int’l
Projected benefit obligation	$	(933	)	$	(1,146	)	$	(565	)
Accumulated benefit obligation	(791		)	(937		)	(505		)
Fair value of plan assets	625			630			500

The following summarizes the obligations and funded status for our defined benefit pension and other postretirement plans.

	Pension Benefits
	2013						2012						Other Benefits
(In millions)	U.S.			Int’l			U.S.			Int’l			2013			2012
Change in benefit obligations:
Beginning balance	$	1,146		$	565		$	986		$	465		$	311		$	301
Service cost	33			22			31			19			4			4
Interest cost	40			24			42			22			12			14
Actuarial loss (gain)	(140		)	40			196			49			(31		)	8
Foreign currency exchange rate changes	—			11			—			25			—			—
Benefits paid	(146		)	(13		)	(109		)	(15		)	(17		)	(16		)
Ending balance	$	933		$	649		$	1,146		$	565		$	279		$	311
Change in fair value of plan assets:
Beginning balance	$	630		$	500		$	516		$	412		$	—		$	—
Actual return on plan assets	65			74			66			57			—			—
Employer contributions	76			23			157			24			—			—
Foreign currency exchange rate changes	—			13			—			22			—			—
Benefits paid	(146		)	(13		)	(109		)	(15		)	—			—
Ending balance	$	625		$	597		$	630		$	500		$	—		$	—
Funded status of plans at December 31	$	(308	)	$	(52	)	$	(516	)	$	(65	)	$	(279	)	$	(311	)
Amounts recognized in the consolidated balance sheets:
Current liabilities	(16		)	—			(17		)	—			(19		)	(19		)
Noncurrent liabilities	(292		)	(52		)	(499		)	(65		)	(260		)	(292		)
Accrued benefit cost	$	(308	)	$	(52	)	$	(516	)	$	(65	)	$	(279	)	$	(311	)
Pretax amounts in accumulated other comprehensive loss:
Net loss (gain)	$	262		$	59		$	511		$	74		$	(8	)	$	23
Prior service cost (credit)	15			9			21			10			(5		)	(11		)

89

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Components of net periodic benefit cost and other comprehensive (income) loss – The following summarizes the net periodic benefit costs and the amounts recognized as other comprehensive (income) loss for our defined benefit pension and other postretirement plans.

	Pension Benefits
	2013						2012						2011						Other Benefits
(In millions)	U.S.			Int’l			U.S.			Int’l			U.S.			Int’l			2013			2012			2011
Components of net periodic benefit cost:
Service cost	$	33		$	22		$	31		$	19		$	28		$	19		$	4		$	4		$	4
Interest cost	40			24			42			22			44			22			12			14			16
Expected return on plan assets	(43		)	(24		)	(43		)	(22		)	(43		)	(23		)	—			—			—
Amortization:
- prior service cost (credit)	6			1			7			1			6			—			(6		)	(7		)	(7		)
- actuarial loss	43			4			48			4			47			2			—			—			—
Net settlement loss(a)	45			—			45			—			30			—			—			—			—
Net periodic benefit cost(b)	$	124		$	27		$	130		$	24		$	112		$	20		$	10		$	11		$	13
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax):
Actuarial loss (gain)	$	(161	)	$	(11	)	$	172		$	15		$	97		$	24		$	(31	)	$	7		$	1
Amortization of actuarial (loss) gain	(88		)	(4		)	(93		)	(4		)	(77		)	(2		)	—			—			—
Prior service cost (credit)	—			—			—			1			—			(11		)	—			—			—
Amortization of prior service credit (cost)	(6		)	(1		)	(7		)	(1		)	(6		)	—			6			7			7
Spin-off downstream business (c)	—			—			—			—			(24		)	—			—			—			—
Total recognized in other comprehensive (income) loss	$	(255	)	$	(16	)	$	72		$	11		$	(10	)	$	11		$	(25	)	$	14		$	8
Total recognized in net periodic benefit cost and other comprehensive (income) loss	$	(131	)	$	11		$	202		$	35		$	102		$	31		$	(15	)	$	25		$	21

^(a)  Settlement losses are recorded when lump sum payments from a plan in a period exceed the plan’s total service and interest costs for the period. Such settlements occurred in one or more of our U.S. plans in 2013, 2012 and 2011.

^(b)  Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.

^(c)  Includes net inter-company transfers of (gains)/losses due to the spin-off of the downstream business.

The estimated net loss and prior service cost for our defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2014 are $24 million and $6 million. The estimated prior service credit for our other defined benefit postretirement plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2014 is $5 million.

Plan assumptions – The following summarizes the assumptions used to determine the benefit obligations at December 31, and net periodic benefit cost for the defined benefit pension and other postretirement plans for 2013, 2012 and 2011.

	Pension Benefits
	2013					2012				2011				Other Benefits
(In millions)	U.S.			Int’l		U.S.		Int’l		U.S.		Int’l		2013		2012		2011
Weighted average assumptions used to determine benefit obligation:
Discount rate	4.28	%		4.60	%	3.44	%	4.40	%	4.45	%	4.70	%	4.85	%	4.06	%	4.90	%
Rate of compensation increase	5.00	%		4.90	%	5.00	%	4.50	%	5.00	%	4.30	%	5.00	%	5.00	%	5.00	%
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate	3.79	%		4.40	%	4.21	%	4.70	%	5.05	%	5.40	%	4.06	%	4.90	%	5.55	%
Expected long-term return on plan assets	7.25	%	(a)	4.90	%	7.75	%	5.20	%	8.50	%	5.86	%	—		—		—
Rate of compensation increase	5.00	%		4.50	%	5.00	%	4.30	%	5.00	%	5.10	%	5.00	%	5.00	%	5.00	%

^(a) Effective January 1, 2014, the expected long-term return on U.S. plan assets was changed from 7.25 percent to 6.75 percent.

90

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Expected long-term return on plan assets

U.S. plan – The expected long-term return on plan assets assumption for our U.S. funded plan is determined based on an asset rate-of-return modeling tool developed by a third-party investment group. The tool utilizes underlying assumptions based on actual returns by asset category and inflation and takes into account our U.S. pension plan’s asset allocation to derive an expected long-term rate of return on those assets. Capital market assumptions reflect the long-term capital market outlook. The assumptions for equity and fixed income investments are developed using a building-block approach, reflecting observable inflation information and interest rate information available in the fixed income markets. Long-term assumptions for other asset categories are based on historical results, current market characteristics and the professional judgment of our internal and external investment teams.

International plans – To determine the expected long-term return on plan assets assumption for our international plans, we consider the current level of expected returns on risk-free investments (primarily government bonds), the historical levels of the risk premiums associated with the other applicable asset categories and the expectations for future returns of each asset class. The expected return for each asset category is then weighted based on the actual asset allocation in our international pension plans to develop the overall expected long-term return on plan assets assumption.

Assumed health care cost trend rates

	2013		2012		2011
Health care cost trend rate assumed for the following year:
Medical
Pre-65	7.50	%	8.00	%	7.50	%
Post-65	6.50	%	7.00	%	7.00	%
Prescription drugs	7.00	%	7.00	%	7.50	%
EGWP subsidy(a)	8.70	%	7.50	%	n/a
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):
Medical
Pre-65	5.00	%	5.00	%	5.00	%
Post-65	5.00	%	5.00	%	5.00	%
Prescription drugs	5.00	%	5.00	%	5.00	%
EGWP subsidy(a)	5.00	%	5.00	%	n/a
Year that the rate reaches the ultimate trend rate:
Medical
Pre-65	2020		2020		2018
Post-65	2020		2018		2017
Prescription drugs	2020		2018		2018
EGWP subsidy(a)	2020		2020		n/a

^(a)  An employee group waiver plan ("EGWP") is a group Medicare Part D prescription drug plan. Effective January 1, 2013, we implemented the EGWP as a result of the Patient Protection and Affordable Care Act, which ended tax-free status of retiree drug subsidy programs but increased federal funding to Part D prescription drug plans.

Assumed health care cost trend rates have a significant effect on the amounts reported for defined benefit retiree health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

(In millions)	1-Percentage- Point Increase		1-Percentage- Point Decrease
Effect on total of service and interest cost components	$	2	$	(2	)
Effect on other postretirement benefit obligations	$	30	$	(25	)

Plan investment policies and strategies – The investment policies for our U.S. and international pension plan assets reflect the funded status of the plans and expectations regarding our future ability to make further contributions. Long-term investment goals are to: (1) manage the assets in accordance with the legal requirements of all applicable laws; (2) produce investment returns which meet or exceed the rates of return achievable in the capital markets while maintaining the risk parameters set by the plans’ investment committees and protecting the assets from any erosion of purchasing power; and (3) position the portfolios with a long-term risk/return orientation.

U.S. plan – Historical performance and future expectations suggest that common stocks will provide higher total investment returns than fixed income securities over a long-term investment horizon. Short-term investments are utilized for pension payments, expenses, and other liquidity needs. However, to reduce volatility in returns and to better match the plan’s liabilities over time,

91

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

as the plan’s funded ratio (as defined by the investment policy) improves, the allocation to equity securities will decrease while the amount allocated to fixed income securities will increase. As such, the plan’s current targeted asset allocation is comprised of 55 percent equity securities and high-yield bonds and 45 percent other fixed income securities.

The plan's assets are managed by a third-party investment manager. The investment manager is limited to pursuing the investment strategies regarding asset mix and purchases and sales of securities within the parameters defined in the investment policy guidelines and investment management agreement. Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies.

International plans – Our international plans’ target asset allocation is comprised of 70 percent equity securities and 30 percent fixed income securities. The plan assets are invested in eleven separate portfolios, mainly pooled fund vehicles, managed by several professional investment managers. Investments are diversified by industry and type, limited by grade and maturity. The use of derivatives by the investment managers is permitted, subject to strict guidelines. The investment managers' performance is measured independently by a third-party asset servicing consulting firm. Overall, investment performance and risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews and periodic asset and liability studies.

Fair value measurements – Plan assets are measured at fair value. The following provides a description of the valuation techniques employed for each major plan asset class at December 31, 2013 and 2012.

Cash and cash equivalents – Cash and cash equivalents include cash on deposit and an investment in a money market mutual fund that invests mainly in short-term instruments and cash, both of which are valued using a market approach and are considered Level 1. The money market mutual fund is valued at the net asset value ("NAV") of shares held. Cash and cash equivalents also include a cash reserve account (a collective short-term investment fund) that is valued using an income approach and is considered Level 2. The underlying assets are usually short-term bonds, discount notes, and commercial paper.

Equity securities – Investments in common stock, preferred stock, and real estate investment trusts ("REIT") are valued using a market approach at the closing price reported in an active market and are therefore considered Level 1. The non-public investment trust is valued using a market approach based on the underlying investments in the trust, which are publicly-traded securities, and is considered Level 2. Private equity investments include interests in limited partnerships which are valued based on the sum of the estimated fair values of the investments held by each partnership, determined using a combination of market, income and cost approaches, plus working capital, adjusted for liabilities, currency translation and estimated performance incentives. These private equity investments are considered Level 3.

Mutual funds – Investments in mutual funds are valued using a market approach. The shares or units held are traded on the public exchanges and such prices are Level 1 inputs.

Pooled funds – Investments in pooled funds are valued using a market approach at the NAV of units held, but investment opportunities in such funds are limited to institutional investors on the behalf of defined benefit plans. The various funds consist of either an equity or fixed income investment portfolio with underlying investments held in U.S. and non-U.S. securities. Nearly all of the underlying investments are publicly-traded. The majority of the pooled funds are benchmarked against a relative public index. These are considered Level 2.

Fixed income securities – Fixed income securities are valued using a market approach. U.S. treasury notes and exchange traded funds are valued at the closing price reported in an active market, and are considered Level 1. Treasury inflation-protected securities ("TIPS") are valued at the daily closing price reported in an active market. TIPS prices exclude adjustment factors for inflation and are considered Level 1. Corporate bonds, non-U.S. government bonds, private placements, and yankee bonds are valued using calculated yield curves created by models that incorporate factors such as interest rate, benchmark quotes, trade data, dealer quotes, primary and secondary market spread activity, and other market information and are considered Level 2. Taxable municipal bonds are valued using calculated yield curves considering market factors such as benchmark issues, trades, trading spreads between similar issuers or creditors, historical trading spreads over widely accepted market benchmarks, and verified bid information. These assets are considered Level 2. Municipal bonds are valued by an evaluation of terms and conditions of the security and considering market factors such as benchmark curves, trades, bid price or spreads, two-sided markets, and quotes. These assets are considered Level 2. The investment in the commingled fund is valued using the NAV of units held, and is considered Level 2. The commingled fund consists mostly of high-yield U.S. and non-U.S. corporate bonds. Investment opportunities in this fund are limited to qualified retirement plans and their plan participants. The investment objective of the portfolio is to provide long-term total return in excess of the Barclays U.S. High Yield Bond Index.

Real estate – Real estate investments are valued using a combination of the income and market approaches that is based on discounted cash flows, comparable sales, outside appraisals, price per square foot or some combination thereof and therefore are considered Level 3.

92

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Other – Other investments are composed of an investment in an unallocated annuity contract, an investment contract with an international insurance carrier, and investments in two limited liability companies (“LLCs") with no public market. The LLCs were formed to acquire timberland in the northwest and other properties. The investment in an unallocated annuity contract is valued using a market approach based on the experience of the assets held in an insurer’s general account. The majority of the general account is invested in a well-diversified portfolio of high-quality fixed income securities, primarily consisting of investment-grade bonds. Investment income is allocated among pension plans participating in the general account based on the investment year method. Under this method, a record of the book value of assets held is maintained in subdivisions according to the calendar year in which the funds are invested. The earnings rate for each of these calendar year subdivisions varies from year to year, reflecting the actual earnings on the assets attributed to that year. Due to the lack of transparency in the use of investment year subdivisions, this asset is considered Level 3. The insurance carrier contract is funded by premiums paid annually by the participating plans and the funds are invested by the insurance carrier in portfolios with different risk profiles (low, medium, high) that can be elected by clients. The majority of the underlying investments consists of a well-diversified mix of non-U.S. publicly traded equity securities valued at the closing price reported in an active market and fixed income securities valued using calculated yield curves. This asset is considered Level 2. The values of the LLCs are determined using a cost approach based on historical cost less depletion for timber previously harvested. These assets are considered Level 3.

The following tables present the fair values of our defined benefit pension plans’ assets, by level within the fair value hierarchy, as of December 31, 2013 and 2012.

	December 31, 2013
(In millions)	Level 1				Level 2				Level 3				Total
	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l		U.S.		Int’l
Cash and cash equivalents	$	19	$	1	$	1	$	—	$	—	$	—	$	20	$	1
Equity securities:
Common stock(a)	288		—		—		—		—		—		288		—
Preferred stock	4		—		—		—		—		—		4		—
Private equity	—		—		—		—		23		—		23		—
REIT	2		—		—		—		—		—		2		—
Mutual funds(b)	—		219		—		—		—		—		—		219
Pooled funds(c)	—		—		—		186		—		—		—		186
Fixed income securities:
U.S. treasury notes	63		—		—		—		—		—		63		—
Exchange traded funds	1		—		—		—		—		—		1		—
Corporate bonds(d)	—		—		127		—		—		—		127		—
Municipal bonds	—		—		1		—		—		—		1
Non-U.S. government bonds	—		—		7		—		—		—		7		—
Private placements	—		—		21		—		—		—		21		—
Taxable municipal bonds	—		—		13		—		—		—		13		—
Treasury inflation-protected securities	1		—		—		—		—		—		1		—
Yankee bonds	—		—		3		—		—		—		3		—
Commingled fund(e)	—		—		17		—		—		—		17		—
Pooled funds(f)	—		—		—		178		—		—		—		178
Real estate(g)	—		—		—		—		22		—		22		—
Other	—		—		—		13		12		—		12		13
Total investments, at fair value	$	378	$	220	$	190	$	377	$	57	$	—	$	625	$	597

93

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

	December 31, 2012
(In millions)	Level 1				Level 2				Level 3				Total
	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l		U.S.		Int’l
Cash and cash equivalents	$	16	$	1	$	1	$	—	$	—	$	—	$	17	$	1
Equity securities:
Common stock(a)	312		—		—		—		—		—		312		—
Private equity	—		—		—		—		25		—		25		—
REIT	2		—		—		—		—		—		2		—
Investment trust	—		—		1		—		—		—		1		—
Mutual funds(b)	—		171		—		—		—		—		—		171
Pooled funds(c)	—		—		—		152		—		—		—		152
Fixed income securities:
U.S. treasury notes	67		—		—		—		—		—		67		—
Exchange traded funds	8		—		—		—		—		—		8		—
Corporate bonds(d)	—		—		96		—		—		—		96		—
Non-U.S. government bonds	—		—		5		—		—		—		5		—
Private placements	—		—		18		—		—		—		18		—
Taxable municipal bonds	—		—		14		—		—		—		14		—
Yankee bonds	—		—		2		—		—		—		2		—
Commingled fund(e)	—		—		28		—		—		—		28		—
Pooled funds(f)	—		—		—		166		—		—		—		166
Real estate(g)	—		—		—		—		23		—		23		—
Other	—		—		—		10		12		—		12		10
Total investments, at fair value	$	405	$	172	$	165	$	328	$	60	$	—	$	630	$	500

^(a)  Includes approximately 60 percent of investments held in U.S. and non-U.S. common stocks in the banking, pharmaceuticals, oil and gas, insurance, telecommunications, electric, aerospace/defense, retail, transportation, food processing, semiconductors, and chemicals sectors. The remaining 40 percent of common stock is held in various other sectors.

^(b)  Includes approximately 75 percent of investments held in U.S. and non-U.S. common stocks in the consumer staples, financial services, health care, energy, basic materials, leisure, and industrial goods and services sectors and 25 percent of investments held among various other sectors. The funds' objective is to outperform their respective benchmark indexes, FTSE ALL Share 5% Capped Index and MSCI World Index, as defined by the investment policy.

^(c)  Includes approximately 80 percent of investments held in non-U.S. publicly traded common stocks (specifically Asia Pacific, except Japan, and the U.K.) in the financial, consumer staples, information technology, materials, energy, industrials, and telecommunication services sectors and the remaining 20 percent of investments held among various other sectors. The funds' objective is to outperform their respective benchmark indexes, MSCI AC Asia Pacific ex Japan Index, FTSE Small Cap Index, and MSCI Emerging Markets Index, as defined by the investment policy.

^(d)  Includes approximately 70 percent of U.S. and non-U.S. corporate bonds in the banking and finance, utilities, oil and gas, news/media, and health care sectors. The remaining 30 percent of corporate bonds are in various other sectors.

^(e)  Includes approximately 90 percent of investments held in U.S. and non-U.S. corporate bonds in the consumer discretionary, financial, industrial, telecommunication services, energy, health care, information technology and materials sectors and 10 percent of investments held among various other sectors.

^(f)  Includes approximately 75 percent of investments held in U.S. and non-U.S. publicly traded investment grade government and corporate bonds which include gilts, treasuries, financial, corporates, and collateralized asset backed securities and 25 percent of investments held among various other sectors. The funds' objective is to outperform their respective benchmark indexes, as defined by the investment policy.

^(g)  Includes investments diversified by property type and location. The largest property sector holdings, which represent approximately 70 percent of investments held, are office, hotel, residential, and retail with the greatest percentage of investments made in the U.S. and Asia, which includes the emerging markets of China and India.

94

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

The following is a reconciliation of the beginning and ending balances recorded for plan assets classified as Level 3 in the fair value hierarchy.

	2013
(In millions)	Private Equity			Real Estate			Other		Total
Beginning balance	$	25		$	23		$	12	$	60
Actual return on plan assets:
Realized gain	6			1			—		7
Unrealized gain (loss)	(1		)	1			—		—
Purchases	6			1			—		7
Sales	(13		)	(4		)	—		(17		)
Ending balance	$	23		$	22		$	12	$	57

	2012
(In millions)	Private Equity			Real Estate			Other			Total
Beginning balance	$	23		$	21		$	14		$	58
Actual return on plan assets:
Realized gain	2			—			—			2
Unrealized gain (loss)	1			1			(2		)	—
Purchases	4			3			—			7
Sales	(5		)	(2		)	—			(7		)
Ending balance	$	25		$	23		$	12		$	60

Cash flows

Estimated future benefit payments – The following gross benefit payments, which were estimated based on actuarial assumptions applied at December 31, 2013 and reflect expected future services, as appropriate, are to be paid in the years indicated.

	Pension Benefits				Other Benefits
(In millions)	U.S.		Int’l
2014(a)	$	96	$	14	$	19
2015	94		14		20
2016	95		16		20
2017	96		18		20
2018	92		21		20
2019 through 2023	368		120		98

^(a)  Primarily as a result of retirements effective January 1, 2014, actual 2014 U.S. gross benefit payments will exceed the actuarial estimate above, including approximately $163 million which will be paid during the first quarter of 2014.

Contributions to defined benefit plans – We expect to make contributions to the funded pension plans of up to $77 million in 2014, and $11 million of that amount was paid in January 2014. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are expected to be approximately $74 million and $19 million in 2014.

Contributions to defined contribution plan – We contribute to a defined contribution plan for eligible employees. Contributions to this plan totaled $26 million, $25 million and $21 million in 2013, 2012 and 2011.

21. Incentive Based Compensation

Description of stock-based compensation plans – The Marathon Oil Corporation 2012 Incentive Compensation Plan (the "2012 Plan") was approved by our stockholders in April 2012 and authorizes the Compensation Committee of the Board of Directors to grant stock options, SARs, stock awards (including restricted stock and restricted stock unit awards) and performance awards to employees. The 2012 Plan also allows us to provide equity compensation to our non-employee directors. No more than 50 million shares of our common stock may be issued under the 2012 Plan. For stock options and SARs, the number of shares available for issuance under the 2012 Plan will be reduced by one share for each share of our common stock in respect of which

95

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

the award is granted. For awards other than stock options or SARs, the number of shares available for issuance under the 2012 Plan will be reduced by 2.41 shares for each share of our common stock in respect of which the award is granted.

Shares subject to awards under the 2012 Plan that are forfeited, are terminated or expire unexercised become available for future grants. In addition, the number of shares of our common stock reserved for issuance under the 2012 Plan will not be increased by shares tendered to satisfy the purchase price of an award, exchanged for other awards or withheld to satisfy tax withholding obligations. Shares issued as a result of awards granted under the 2012 Plan are generally funded out of common stock held in treasury, except to the extent there are insufficient treasury shares, in which case new common shares are issued.

After approval of the 2012 Plan, no new grants were or will be made from the 2007 Incentive Compensation Plan, the 2003 Incentive Compensation Plan (the "2003 Plan"), the Non-Employee Director Stock Plan and the deferred stock benefit provision of the Deferred Compensation Plan for Non-Employee Directors (collectively, the "Prior Plans"). Any awards previously granted under the Prior Plans shall continue to be exercisable in accordance with their original terms and conditions.

Stock-based awards under the plans

Stock options – We grant stock options under the 2012 Plan and previously granted stock options under certain of the Prior Plans. Our stock options represent the right to purchase shares of our common stock at its fair market value on the date of grant. In general, our stock options vest ratably over a three-year period and have a maximum term of ten years from the date they are granted.

Stock appreciation rights – Prior to 2005, we granted SARs under the 2003 Plan. No SARs have been granted since then. SARs represent the right to receive shares of common stock equal in value to the excess of the fair market value of shares of common stock on the date the right is exercised over the grant price. In general, SARs vested ratably over a three-year period and have a maximum term of ten years from the date they were granted.

Restricted stock – We grant restricted stock and restricted stock units (collectively, "restricted stock awards") under the 2012 Plan and previously granted such awards under certain of the Prior Plans. The restricted stock awards granted officers generally vest three years from the date of grant, contingent on the recipient’s continued employment. We also grant restricted stock to certain non-officer employees and restricted stock units to certain international employees, based on their performance within certain guidelines and for retention purposes. The restricted stock awards to non-officers generally vest in one-third increments over a three-year period, contingent on the recipient’s continued employment. Prior to vesting, all restricted stock recipients have the right to vote such stock and receive dividends thereon. The non-vested shares are not transferable and are held by our transfer agent.

Stock-based performance units – Beginning in 2013, we grant stock-based performance units to officers under the 2012 Plan. At the grant date, each unit represents the value of one share of our common stock. These units provide a cash payout, based on the value of anywhere from zero to two times the number of units granted, upon the achievement of certain performance goals at the end of a 36-month performance period. The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR for a group of peer companies determined by the Compensation Committee of the Board of Directors. Dividend equivalents accrue during the performance period and are paid in cash at the end of the performance period based on the number of shares that would represent the value of the units.

Common stock units – We maintain an equity compensation program for our non-employee directors under the 2012 Plan and previously maintained such a program under certain of the Prior Plans.  All non-employee directors receive annual grants of common stock units.  Those units granted prior to 2012 must be held until completion of board service, at which time the non-employee director will receive common shares.  Common shares will be issued for units granted on or after January 1, 2012 upon completion of board service or three years from the date of grant, whichever is earlier. When dividends are paid on our common stock, directors receive dividend equivalents in the form of additional common stock units.

Total stock-based compensation expense – Total employee stock-based compensation expense was $75 million, $70 million and $65 million in 2013, 2012 and 2011, while the total related income tax benefits were $27 million, $25 million and $23 million in the same years. In 2013, 2012 and 2011, cash received upon exercise of stock option awards was $58 million, $41 million and $77 million. Tax benefits realized for deductions for stock awards exercised during 2013, 2012 and 2011 totaled $36 million, $24 million and $32 million.

96

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Stock option awards – During 2013, 2012 and 2011, we granted stock option awards to both officer and non-officer employees. The weighted average grant date fair value of these awards was based on the following weighted average Black-Scholes assumptions:

	2013		2012		2011
Exercise price per share	$33.54		$33.52		$32.30
Expected annual dividend yield	2.1	%	2.2	%	2.1	%
Expected life in years	6.1		5.5		5.3
Expected volatility	38	%	41	%	40	%
Risk-free interest rate	1.6	%	1.2	%	1.7	%
Weighted average grant date fair value of stock option awards granted	$10.25		$10.86		$10.44

The following is a summary of stock option award activity in 2013.

	Number of Shares	Weighted Average Exercise price
Outstanding at beginning of year	19,536,965	$26.19
Granted	2,051,386	$33.54
Exercised	(2,718,639)	$22.36
Canceled	(764,825)	$34.02
Outstanding at end of year	18,104,887	$27.27

The intrinsic value of stock option awards exercised during 2013, 2012 and 2011, was $35 million, $40 million and $59 million.

The following table presents information related to stock option awards at December 31, 2013.

	Outstanding			Exercisable
Range of Exercise Prices	Number of Shares Under Option	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price	Number of Shares Under Option	Weighted Average Exercise Price
$7.99-12.75	259,164	0.3 years	$10.53	259,164	$10.53
$12.76-16.81	1,937,181	3 years	$15.13	1,937,181	$15.13
$16.82-23.20	4,255,365	5 years	$18.57	4,255,365	$18.57
$23.21-29.24	1,740,398	4 years	$24.59	1,489,683	$24.05
$29.25-36.03	7,541,433	7 years	$33.06	3,967,422	$32.70
$36.04-46.41	2,371,346	3 years	$38.19	2,277,817	$38.26
Total	18,104,887	5 years	$27.27	14,186,632	$25.64

As of December 31, 2013, the aggregate intrinsic value of stock option awards outstanding was $152 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable were $144 million and 4 years.

As of December 31, 2013, the number of fully-vested stock option awards and stock option awards expected to vest was 18,023,888. The weighted average exercise price and weighted average remaining contractual life of these stock option awards were $27.24 and 5 years and the aggregate intrinsic value was $152 million. As of December 31, 2013, unrecognized compensation cost related to stock option awards was $16 million, which is expected to be recognized over a weighted average period of 2 years.

97

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

Restricted stock awards – The following is a summary of restricted stock award activity in 2013.

	Awards		Weighted Average Grant Date Fair Value
Unvested at beginning of year	4,177,884		$29.02
Granted	2,120,839		$33.69
Vested	(1,713,763	)	$27.78
Forfeited	(553,072	)	$30.58
Unvested at end of year	4,031,888		$31.80

The vesting date fair value of restricted stock awards which vested during 2013, 2012 and 2011 was $59 million, $36 million and $30 million. The weighted average grant date fair value of restricted stock awards was $31.80, $29.02, and $25.88 for awards unvested at December 31, 2013, 2012 and 2011.

As of December 31, 2013, there was $96 million of unrecognized compensation cost related to restricted stock awards which is expected to be recognized over a weighted average period of 2 years.

Stock-based performance unit awards – During 2013, we granted 353,600 stock-based performance unit awards to officers and at December 31, 2013, there were 93,100 units outstanding. The key assumptions used in the Monte Carlo simulation to determine the December 31, 2013 fair value of stock-based performance units were:

Valuation date stock price	$35.30
Expected annual dividend yield	2.1	%
Expected volatility	26	%
2-Year risk-free interest rate	0.4	%
Fair value of stock-based performance units outstanding	$34.08

Cash-based performance unit awards – Prior to 2013, cash-based performance unit awards were granted to officers that provide a cash payment upon the achievement of certain performance goals at the end of a defined measurement period. The performance goals are tied to our TSR as compared to TSR for a group of peer companies determined by the Compensation Committee of the Board of Directors. The target value of each performance unit is $1, with a maximum payout of $2 per unit, but the actual payout could be anywhere between zero and the maximum. Because performance units are to be settled in cash at the end of the performance period, they are accounted for as liability awards.

During 2012, we granted 12.7 million performance units, all having a 36-month performance period. During the third quarter of 2011, we granted 15 million performance units, a portion of which had a 30-month performance period and a portion of which had an 18-month performance period to reflect the remaining periods of the original 2011 and 2010 performance unit grants outstanding prior to the spin-off. Compensation expense associated with cash-based performance units was $9 million, $12 million and $32 million in 2013, 2012 and 2011. The expense for 2011 included $14 million paid on three groups of performance unit grants outstanding at June 30, 2011, that were accelerated with the total payout determined based on performance through the effective date of the spin-off of our downstream business.

98

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

22.  Reclassifications Out of Accumulated Other Comprehensive Loss

The following table presents a summary of amounts reclassified from accumulated other comprehensive loss to net income in their entirety:

(In millions)	2013			Income Statement Line
Accumulated Other Comprehensive Loss Components
	Income (Expense)
Postretirement and postemployment plans
Amortization of actuarial loss	$	(47	)	General and administrative
Net settlement loss	(45		)	General and administrative
	35			Provision for income taxes
	(57		)	Net of tax
Other insignificant items, net of tax	(1		)
Total reclassifications for the period	$	(58	)	Net income

23. Stockholders’ Equity

Share repurchase plan – In the third quarter of 2013, we acquired 14 million common shares at a cost of $500 million under our share repurchase program, initially authorized in 2006, bringing our total repurchases to 92 million common shares at a cost of $3,722 million. In December 2013, our Board of Directors increased the authorization by an additional $1.2 billion, bringing the total remaining share repurchase authorization to $2.5 billion. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The repurchase program does not include specific price targets or timetables.

24. Leases

We lease a wide variety of facilities and equipment under operating leases, including land, building space, equipment and vehicles. Most long-term leases include renewal options and, in certain leases, purchase options. Future minimum commitments for capital lease obligations and for operating lease obligations having noncancellable lease terms in excess of one year are as follows:

(In millions)	Capital Lease Obligations			Operating Lease Obligations
2014	$	1		$	45
2015	1			42
2016	1			34
2017	1			22
2018	1			20
Later years	23			48
Sublease rentals	—			(4		)
Total minimum lease payments	$	28		$	207
Less imputed interest costs	(18		)
Present value of net minimum lease payments	$	10

Operating lease rental expense related to continuing operations was $106 million, $103 million and $70 million in 2013, 2012 and 2011.

99

MARATHON OIL CORPORATION

Notes to Consolidated Financial Statements

25. Commitments and Contingencies

We are a 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. In April 2013, we filed a counterclaim against Noble alleging, among other things, breach of contract and breach of the duty of good faith relating to the multi-year drilling contract. The counterclaim also included a breach of contract claim for reimbursement for the value of fuel used by Noble under an offshore daywork drilling contract. The parties settled this litigation in the fourth quarter of 2013, and the settlement did not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Environmental matters – We are subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.

At December 31, 2013 and 2012, accrued liabilities for remediation were not significant. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties that may be imposed.

Guarantees – We have entered into a guarantee of a long-term transportation services agreement and a performance guarantee related to asset retirement obligations with aggregate maximum potential undiscounted payments totaling $96 million as of December 31, 2013. Under the terms of these guarantee arrangements, we would be required to perform should the guaranteed party fail to fulfill its obligations under the specified arrangements.

Over the years, we have sold various assets in the normal course of our business. Certain of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require us to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling assets. We are typically not able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the underlying triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based.

Contract commitments – At December 31, 2013 and 2012, contractual commitments to acquire property, plant and equipment totaled$1,270 millionand$949 million.

Other contingencies – During the second quarter of 2011, the AOSP operator determined the need and developed preliminary plans to address water flow into a previously mined and contained section of the Muskeg River mine. Our share of the estimated costs in the amount of $64 million was recorded to production expense in 2011. At December 31, 2013, the remaining liability is $29 million.

100

Select Quarterly Financial Data (Unaudited)

	2013								2012
(In millions, except per share data)	1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.		1st Qtr.			2nd Qtr.			3rd Qtr.			4th Qtr.
Revenues	$	3,784	$	3,839	$	3,699	$	3,179	$	3,793		$	3,732		$	4,036		$	4,131
Income from continuing operations before income taxes	1,367		1,467		1,278		818		1,350			1,421			1,733			1,626
Income from continuing operations	380		399		518		296		423			406			469			315
Discontinued operations (a)	3		27		51		79		(6		)	(13		)	(19		)	7
Net income	$	383	$	426	$	569	$	375	$	417		$	393		$	450		$	322
Income per share:
Basic:
Continuing operations	$0.54		$0.56		$0.73		$0.43		$0.60			$0.58			$0.67			$0.45
Discontinued operations (a)	$0.00		$0.04		$0.07		$0.11		($0.01)			($0.02)			($0.03)			$0.01
Net income	$0.54		$0.60		$0.80		$0.54		$0.59			$0.56			$0.64			$0.46
Diluted:
Continuing operations	$0.54		$0.56		$0.73		$0.43		$0.60			$0.58			$0.66			$0.44
Discontinued operations (a)	$0.00		$0.04		$0.07		$0.11		($0.01)			($0.02)			($0.03)			$0.01
Net income	$0.54		$0.60		$0.80		$0.54		$0.59			$0.56			$0.63			$0.45
Dividends paid per share	$0.17		$0.17		$0.19		$0.19		$0.17			$0.17			$0.17			$0.17

^(a) In 2013, we entered into agreements to sell our Angola assets; therefore, our Angola operations are reflected as discontinued operations in all periods presented.

101

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

The supplementary information is disclosed by the following geographic areas: the U.S.; Canada; E. G.; Other Africa, which primarily includes activities in Gabon, Kenya, Ethiopia and Libya; Europe, which primarily includes activities in Norway and the U.K.; and Other International ("Other Int’l"), which includes activities in the Kurdistan Region of Iraq. Our Angola operations are shown as discontinued operations ("Disc Ops") in all periods since we entered into agreements to sell these assets in 2013.

Estimated Quantities of Proved Oil and Gas Reserves

The estimation of net recoverable quantities of liquid hydrocarbons, natural gas and synthetic crude oil is a highly technical process, which is based upon several underlying assumptions that are subject to change. For a discussion of our reserve estimation process, including the use of third-party audits, see Item 1. Business – Reserves.

(mmbbl)	U.S.		Canada	E.G.(a)		Other Africa		Europe		Disc Ops		Total
Liquid Hydrocarbons
Proved developed and undeveloped reserves:
Beginning of year - 2011	173		—	119		224		99		15		630
Revisions of previous estimates	16		—	11		—		21		2		50
Improved recovery	1		—	—		—		—		—		1
Purchases of reserves in place	89		—	—		—		—		—		89
Extensions, discoveries and other
additions	27		—	—		—		14		1		42
Production	(27	)	—	(13	)	(2	)	(37	)	—		(79	)
End of year - 2011	279		—	117		222		97		18		733
Revisions of previous estimates	9		—	6		(5	)	28		—		38
Improved recovery	2		—	—		—		—		—		2
Purchases of reserves in place	52		—	—		—		—		—		52
Extensions, discoveries and other
additions	172		—	—		7		—		—		179
Production	(39	)	—	(13	)	(15	)	(36	)	—		(103	)
End of year - 2012	475		—	110		209		89		18		901
Revisions of previous estimates	46		—	(1	)	12		26		(1	)	82
Improved recovery	—		—	—		—		—		11		11
Purchases of reserves in place	14		—	—		—		—		—		14
Extensions, discoveries and other
additions	137		—	1		3		5		3		149
Production	(55	)	—	(12	)	(9	)	(31	)	(3	)	(110	)
Sales of reserves in place	(1	)	—	—		—		—		—		(1	)
End of year - 2013	616		—	98		215		89		28		1,046
Proved developed reserves:
Beginning of year - 2011	124		—	86		180		89		—		479
End of year - 2011	141		—	78		179		84		—		482
End of year - 2012	198		—	68		168		84		—		518
End of year - 2013	292		—	55		176		78		19		620
Proved undeveloped reserves:
Beginning of year - 2011	49		—	33		44		10		15		151
End of year - 2011	138		—	39		43		13		18		251
End of year - 2012	277		—	42		41		5		18		383
End of year - 2013	324		—	43		39		11		9		426

102

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Estimated Quantities of Proved Oil and Gas Reserves (continued)

(bcf)	U.S.		Canada	E.G.(a)		Other Africa		Europe		Disc Ops	Total
Natural Gas
Proved developed and undeveloped reserves:
Beginning of year - 2011	745		—	1,651		105		116		—	2,617
Revisions of previous estimates	18		—	81		(1	)	22		—	120
Purchases of reserves in place	119		—	—		—		—		—	119
Extensions, discoveries and other
additions	109		—	—		—		11		—	120
Production(b)	(119	)	—	(161	)	—		(30	)	—	(310	)
End of year - 2011	872		—	1,571		104		119		—	2,666
Revisions of previous estimates	(29	)	—	10		(1	)	15		—	(5	)
Purchases of reserves in place	105		—	—		—		—		—	105
Extensions, discoveries and other
additions	224		—	—		111		—		—	335
Production(b)	(129	)	—	(157	)	(5	)	(31	)	—	(322	)
End of year - 2012	1,043		—	1,424		209		103		—	2,779
Revisions of previous estimates	(4	)	—	45		4		43		—	88
Purchases of reserves in place	13		—	3		—		—		—	16
Extensions, discoveries and other
additions	163		—	9		—		3		—	175
Production(b)	(114	)	—	(161	)	(8	)	(28	)	—	(311	)
Sales of reserves in place	(76	)	—	—		—		—		—	(76	)
End of year - 2013	1,025		—	1,320		205		121		—	2,671
Proved developed reserves:
Beginning of year - 2011	591		—	1,186		104		43		—	1,924
End of year - 2011	551		—	1,104		104		40		—	1,799
End of year - 2012	546		—	980		99		28		—	1,653
End of year - 2013	540		—	823		95		41		—	1,499
Proved undeveloped reserves:
Beginning of year - 2011	154		—	465		1		73		—	693
End of year - 2011	321		—	467		—		79		—	867
End of year - 2012	497		—	444		110		75		—	1,126
End of year - 2013	485		—	497		110		80		—	1,172

103

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Estimated Quantities of Proved Oil and Gas Reserves (continued)

(mmbbl)	U.S.	Canada		E.G.(a)	Other Africa	Europe	Disc Ops	Total
Synthetic crude oil
Proved developed and undeveloped reserves:
Beginning of year - 2011	—	572		—	—	—	—	572
Revisions of previous estimates	—	17		—	—	—	—	17
Extensions, discoveries and other
additions	—	48		—	—	—	—	48
Production	—	(14	)	—	—	—	—	(14	)
End of year - 2011	—	623		—	—	—	—	623
Revisions of previous estimates	—	45		—	—	—	—	45
Production	—	(15	)	—	—	—	—	(15	)
End of year - 2012	—	653		—	—	—	—	653
Revisions of previous estimates	—	36		—	—	—	—	36
Extensions, discoveries and other
additions	—	6		—	—	—	—	6
Production	—	(15	)	—	—	—	—	(15	)
End of year - 2013	—	680		—	—	—	—	680
Proved developed reserves:
Beginning of year - 2011	—	433		—	—	—	—	433
End of year - 2011	—	623		—	—	—	—	623
End of year - 2012	—	653		—	—	—	—	653
End of year - 2013	—	674		—	—	—	—	674
Proved undeveloped reserves:
Beginning of year - 2011	—	139		—	—	—	—	139
End of year - 2011	—	—		—	—	—	—	—
End of year - 2012	—	—		—	—	—	—	—
End of year - 2013	—	6		—	—	—	—	6

104

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Estimated Quantities of Proved Oil and Gas Reserves (continued)

(mmboe)	U.S.		Canada		E.G.(a)		Other Africa		Europe		Disc Ops		Total
Total Proved Reserves
Proved developed and undeveloped reserves:
Beginning of year - 2011	297		572		394		242		118		15		1,638
Revisions of previous estimates	19		17		25		(1	)	25		2		87
Improved recovery	1		—		—		—		—		—		1
Purchases of reserves in place	109		—		—		—		—		—		109
Extensions, discoveries and other
additions	45		48		—		—		16		1		110
Production(b)	(47	)	(14	)	(40	)	(2	)	(42	)	—		(145	)
End of year - 2011	424		623		379		239		117		18		1,800
Revisions of previous estimates	5		45		7		(5	)	30		—		82
Improved recovery	2		—		—		—		—		—		2
Purchases of reserves in place	70		—		—		—		—		—		70
Extensions, discoveries and other
additions	209		—		—		26		—		—		235
Production(b)	(61	)	(15	)	(39	)	(16	)	(41	)	—		(172	)
End of year - 2012	649		653		347		244		106		18		2,017
Revisions of previous estimates	45		36		7		12		33		(1	)	132
Improved recovery	—		—		—		—		—		11		11
Purchases of reserves in place	16		—		1		—		—		—		17
Extensions, discoveries and other
additions	164		6		2		3		6		3		184
Production(b)	(74	)	(15	)	(39	)	(10	)	(36	)	(3	)	(177	)
Sales of reserves in place	(13	)	—		—		—		—		—		(13	)
End of year - 2013	787		680		318		249		109		28		2,171
Proved developed reserves:
Beginning of year - 2011	222		433		284		198		96		—		1,233
End of year - 2011	233		623		262		196		91		—		1,405
End of year - 2012	289		653		231		185		88		—		1,446
End of year - 2013	382		674		193		192		84		19		1,544
Proved undeveloped reserves:
Beginning of year - 2011	75		139		110		44		22		15		405
End of year - 2011	191		—		117		43		26		18		395
End of year - 2012	360		—		116		59		18		18		571
End of year - 2013	405		6		125		57		25		9		627

^(a)  Consists of estimated reserves from properties governed by production sharing contracts.

^(b)  Excludes the resale of purchased natural gas used in reservoir management.

105

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Capitalized Costs and Accumulated Depreciation, Depletion and Amortization

	December 31,
(In millions)	U.S.		Canada		E.G.		Other Africa (a)		Europe		Other Int’l		Total
2013 Capitalized Costs:
Proved properties	$	24,165	$	9,276	$	1,683	$	2,257	$	8,898	$	—	$	46,279
Unproved properties	2,097		1,508		31		693		296		214		4,839
Total	26,262		10,784		1,714		2,950		9,194		214		51,118
Accumulated depreciation,
depletion and amortization:
Proved properties	11,568		989		918		307		7,607		—		21,389
Unproved properties	180		1		—		13		7		8		209
Total	11,748		990		918		320		7,614		8		21,598
Net capitalized costs	$	14,514	$	9,794	$	796	$	2,630	$	1,580	$	206	$	29,520
2012 Capitalized Costs:
Proved properties	$	21,106	$	8,963	$	1,586	$	1,898	$	8,690	$	—	$	42,243
Unproved properties	3,222		1,513		29		602		160		146		5,672
Total	24,328		10,476		1,615		2,500		8,850		146		47,915
Accumulated depreciation,
depletion and amortization:
Proved properties	10,493		781		824		174		7,191		—		19,463
Unproved properties	293		1		—		13		—		20		327
Total	10,786		782		824		187		7,191		20		19,790
Net capitalized costs	$	13,542	$	9,694	$	791	$	2,313	$	1,659	$	126	$	28,125

^(a)  Includes Angola costs.

Costs Incurred for Property Acquisition, Exploration and Development^(a) 

(In millions)	U.S.		Canada		E.G.		Other Africa			Europe		Other Int’l			Disc Ops		Total
2013 Property acquisition:
Proved	$	51	$	30	$	9	$	—		$	—	$	—		$	—	$	90
Unproved	157		—		—		44			—		21			—		222
Exploration	885		9		4		124			102		137			10		1,271
Development	2,876		280		84		46			354		1			227		3,868
Total	$	3,969	$	319	$	97	$	214		$	456	$	159		$	237	$	5,451
2012 Property acquisition:
Proved	$	756	$	—	$	—	$	—		$	3	$	—		$	—	$	759
Unproved	432		—		18		63			—		(13		)	5		505
Exploration	1,587		31		3		25			54		136			20		1,856
Development	2,469		195		22		15			468		5			353		3,527
Total	$	5,244	$	226	$	43	$	103		$	525	$	128		$	378	$	6,647
2011 Property acquisition:
Proved	$	1,782	$	5	$	1	$	—		$	—	$	—		$	—	$	1,788
Unproved	3,271		—		—		—			7		57			1		3,336
Exploration	782		42		—		10			109		168			23		1,134
Development	889		293		18		(5		)	388		—			299		1,882
Total	$	6,724	$	340	$	19	$	5		$	504	$	225		$	323	$	8,140

^(a)  Includes costs incurred whether capitalized or expensed. 

106

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Results of Operations for Oil and Gas Producing Activities

(In millions)		U.S.			Canada			E.G.			Other Africa			Europe			Other Int’l			Total
2013	Revenues and other income:
	Sales	$	5,059		$	1,376		$	33		$	1,106		$	924		$	—		$	8,498
	Transfers	3			—			715			—			2,941			—			3,659
	Other income(a)	(9		)	—			—			—			—			(8		)	(17		)
	Total revenues and other income	5,053			1,376			748			1,106			3,865			(8		)	12,140
	Expenses:
	Production costs	(1,318		)	(867		)	(113		)	(73		)	(498		)	—			(2,869		)
	Exploration expenses	(717		)	(8		)	(3		)	(65		)	(123		)	(72		)	(988		)
	Depreciation, depletion and amortization(b)	(1,980		)	(218		)	(97		)	(28		)	(440		)	—			(2,763		)
	Administrative expenses	(185		)	(21		)	(30		)	(19		)	(36		)	(14		)	(305		)
	Total expenses	(4,200		)	(1,114		)	(243		)	(185		)	(1,097		)	(86		)	(6,925		)
	Results before income taxes	853			262			505			921			2,768			(94		)	5,215
	Income tax (provision) benefit	(323		)	(66		)	(182		)	(920		)	(2,004		)	26			(3,469		)
	Results of continuing operations	$	530		$	196		$	323		$	1		$	764		$	(68	)	$	1,746
	Results of discontinued operations	$	—		$	—		$	—		$	160		$	—		$	—		$	160
2012	Revenues and other income:
	Sales	$	3,879		$	1,261		$	29		$	2,000		$	835		$	—		$	8,004
	Transfers	2			—			818			—			3,601			—			4,421
	Other income(a)	(8		)	—			—			—			—			(32		)	(40		)
	Total revenues and other income	3,873			1,261			847			2,000			4,436			(32		)	12,385
	Expenses:
	Production costs	(1,054		)	(826		)	(141		)	(58		)	(398		)	—			(2,477		)
	Exploration expenses	(558		)	(30		)	(5		)	(10		)	(34		)	(69		)	(706		)
	Depreciation, depletion and amortization(b)	(1,792		)	(217		)	(95		)	(43		)	(615		)	—			(2,762		)
	Administrative expenses	(193		)	(8		)	(5		)	(4		)	(40		)	(12		)	(262		)
	Total expenses	(3,597		)	(1,081		)	(246		)	(115		)	(1,087		)	(81		)	(6,207		)
	Results before income taxes	276			180			601			1,885			3,349			(113		)	6,178
	Income tax (provision) benefit	(100		)	(45		)	(210		)	(1,795		)	(2,486		)	51			(4,585		)
	Results of continuing operations	$	176		$	135		$	391		$	90		$	863		$	(62	)	$	1,593
	Results of discontinued operations	$	—		$	—		$	—		$	(31	)	$	—		$	—		$	(31	)
2011	Revenues and other income:
	Sales	$	3,058		$	1,332		$	29		$	216		$	1,000		$	—		$	5,635
	Transfers	63			—			905			—			3,546			—			4,514
	Other income(a)	41			—			—			—			15			—			56
	Total revenues and other income	3,162			1,332			934			216			4,561			—			10,205
	Expenses:
	Production costs(c)	(961		)	(818		)	(118		)	(24		)	(376		)	—			(2,297		)
	Exploration expenses	(377		)	(11		)	(1		)	1			(86		)	(167		)	(641		)
	Depreciation, depletion and amortization(b)	(1,472		)	(196		)	(104		)	(9		)	(684		)	—			(2,465		)
	Administrative expenses	(182		)	(10		)	—			(1		)	(18		)	(10		)	(221		)
	Total expenses	(2,992		)	(1,035		)	(223		)	(33		)	(1,164		)	(177		)	(5,624		)
	Results before income taxes	170			297			711			183			3,397			(177		)	4,581
	Income tax (provision) benefit	(59		)	(75		)	(254		)	(176		)	(2,176		)	65			(2,675		)
	Results of continuing operations	$	111		$	222		$	457		$	7		$	1,221		$	(112	)	$	1,906
	Results of discontinued operations	$	—		$	—		$	—		$	(11	)	$	—		$	—		$	(11	)

^(a)  Includes net gain (loss) on dispositions.

^(b)  Includes long-lived asset impairments.

^(c)  2011 Canada production costs include $64 million accrued for Oil Sands water abatement.

107

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Results of Operations for Oil and Gas Producing Activities

The following reconciles results of operations for oil and gas producing activities to segment income:

(In millions)	2013		2012		2011
Results of continuing operations	$	1,746	$	1,593	$	1,906
Items not included in results of oil and gas operations, net of tax:
Marketing income and other non-oil and gas producing related activities	42		49		182
Income from equity method investments	340		309		351
Items not allocated to segment income, net of tax:
Loss (gain) on asset dispositions	20		31		(24		)
Long-lived asset impairments	10		231		181
Water abatement-Oil Sands Mining	—		—		48
Segment income	$	2,158	$	2,213	$	2,644

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves

	December 31,
(In millions)	U.S.			Canada			E.G.			Other Africa			Europe			Total
2013
Future cash inflows	$	54,099		$	59,585		$	5,911		$	28,195		$	11,395		$	159,185
Future production and administrative costs	(16,774		)	(35,954		)	(1,619		)	(976		)	(2,986		)	(58,309		)
Future development costs	(9,685		)	(9,694		)	(367		)	(793		)	(2,178		)	(22,717		)
Future income tax expenses	(7,592		)	(3,098		)	(1,032		)	(24,982		)	(4,581		)	(41,285		)
Future net cash flows	$	20,048		$	10,839		$	2,893		$	1,444		$	1,650		$	36,874
10 percent annual discount for estimated timing of cash flows	(9,940		)	(8,300		)	(1,084		)	(828		)	(252		)	(20,404		)
Standardized measure of discounted future net cash flows -
related to continuing operations	$	10,108		$	2,539		$	1,809		$	616		$	1,398		$	16,470
related to discontinued operations	$	—		$	—		$	—		$	1,302		$	—		$	1,302
2012
Future cash inflows	$	42,710		$	55,171		$	6,627		$	28,173		$	11,271		$	143,952
Future production and administrative costs	(13,765		)	(32,131		)	(1,829		)	(1,015		)	(2,302		)	(51,042		)
Future development costs	(11,104		)	(9,350		)	(451		)	(787		)	(1,673		)	(23,365		)
Future income tax expenses	(4,489		)	(2,948		)	(1,191		)	(25,020		)	(5,274		)	(38,922		)
Future net cash flows	$	13,352		$	10,742		$	3,156		$	1,351		$	2,022		$	30,623
10 percent annual discount for estimated timing of cash flows	(6,956		)	(7,842		)	(1,178		)	(743		)	(327		)	(17,046		)
Standardized measure of discounted future net cash flows -
related to continuing operations	$	6,396		$	2,900		$	1,978		$	608		$	1,695		$	13,577
related to discontinued operations	$	—		$	—		$	—		$	642		$	—		$	642
2011
Future cash inflows	$	28,108		$	59,365		$	7,318		$	28,197		$	12,120		$	135,108
Future production and administrative costs	(10,751		)	(28,048		)	(1,931		)	(1,099		)	(2,752		)	(44,581		)
Future development costs	(6,341		)	(10,346		)	(435		)	(559		)	(1,702		)	(19,383		)
Future income tax expenses	(2,740		)	(4,490		)	(1,368		)	(25,463		)	(5,375		)	(39,436		)
Future net cash flows	$	8,276		$	16,481		$	3,584		$	1,076		$	2,291		$	31,708
10 percent annual discount for estimated timing of cash flows	(4,539		)	(11,845		)	(1,331		)	(509		)	(446		)	(18,670		)
Standardized measure of discounted future net cash flows -
related to continuing operations	$	3,737		$	4,636		$	2,253		$	567		$	1,845		$	13,038
related to discontinued operations	$	—		$	—		$	—		$	743		$	—		$	743

108

Supplementary Information on Oil and Gas Producing Activities (Unaudited)

Changes in the Standardized Measure of Discounted Future Net Cash Flows

(In millions)	2013			2012			2011
Sales and transfers of oil and gas produced, net of production and administrative costs	$	(8,997	)	$	(9,696	)	$	(7,637	)
Net changes in prices and production and administrative costs related to future production	(243		)	(1,445		)	11,786
Extensions, discoveries and improved recovery, less related costs	3,457			2,763			1,369
Development costs incurred during the period	3,708			3,197			1,600
Changes in estimated future development costs	622			25			(1,069		)
Revisions of previous quantity estimates(a)	3,123			1,652			2,453
Net changes in purchases and sales of minerals in place	(229		)	909			230
Accretion of discount	3,054			3,073			1,989
Net change in income taxes	(1,602		)	61			(6,607		)
Net change for the year	2,893			539			4,114
Beginning of the year related to continuing operations	13,577			13,038			8,924
End of the year related to continuing operations	$	16,470		$	13,577		$	13,038
Net change for the year related to discontinued operations	$	660		$	(101	)	$	478

^(a) Includes amounts resulting from changes in the timing of production and other.

109

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

(In millions)	2013			2012			2011
Segment Income
North America E&P	$	529		$	382		$	392
International E&P	1,423			1,660			1,991
Oil Sands Mining	206			171			261
Segment income	2,158			2,213			2,644
Items not allocated to segments, net of income taxes	(565		)	(600		)	(926		)
Income from continuing operations	1,593			1,613			1,718
Discontinued operations(a)	160			(31		)	1,228
Net income	$	1,753		$	1,582		$	2,946
Capital Expenditures(b)
North America E&P	$	3,649		$	3,988		$	2,163
International E&P	764			489			544
Oil Sands Mining	286			188			308
Corporate	58			115			75
Discontinued operations(a)	227			351			309
Total	$	4,984		$	5,131		$	3,399
Exploration Expenses
North America E&P	$	725		$	588		$	388
International E&P	263			118			253
Total	$	988		$	706		$	641

^(a)  In 2013, we entered into agreements to sell our Angola assets; therefore, our Angola operations are reflected as discontinued operations in all periods presented. The spin-off of the downstream business was completed on June 30, 2011 and has been reported as discontinued operations in 2011.

^(b)  Capital expenditures include changes in accruals.

110

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

Net Sales Volumes	2013	2012	2011
North America E&P
Crude Oil and Condensate (mbbld)
Bakken	35	27	16
Eagle Ford	51	23	2
Oklahoma resource basins	2	1	—
Other North America	38	45	52
Total Crude Oil and Condensate	126	96	70
Natural Gas Liquids (mbbld)
Bakken	2	1	—
Eagle Ford	14	5	—
Oklahoma resource basins	4	2	1
Other North America	3	3	4
Total Natural Gas Liquids	23	11	5
Total Liquid Hydrocarbons (mbbld)
Bakken	37	28	16
Eagle Ford	65	28	2
Oklahoma resource basins	6	3	1
Other North America	41	48	56
Total Liquid Hydrocarbons	149	107	75
Natural Gas (mmcfd)
Bakken	13	8	6
Eagle Ford	94	37	2
Oklahoma resource basins	48	32	7
Alaska	7	92	94
Other North America	150	189	217
Total Natural Gas	312	358	326
Total North America E&P (mboed)	201	166	129

111

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

Net Sales Volumes	2013	2012	2011
International E&P
Total Liquid Hydrocarbons (mbbld)
Equatorial Guinea	34	36	38
Norway	71	81	80
United Kingdom	15	16	21
Libya	24	42	5
Total Liquid Hydrocarbons	144	175	144
Natural Gas (mmcfd)
Equatorial Guinea	442	428	443
Norway	51	53	42
United Kingdom(c)	32	48	55
Libya	22	15	—
Total Natural Gas	547	544	540
Total International E&P (mboed)	234	266	234
Oil Sands Mining
Synthetic Crude Oil (mbbld)(d)	48	47	43
Total Continuing Operations (mboed)	483	479	406
Discontinued Operations (mboed)(e)	10	—	—
Total Company (mboed)	493	479	406
Net Sales Volumes of Equity Method Investees
LNG (mtd)	6,548	6,290	6,681
Methanol (mtd)	1,249	1,298	1,282

^(c) Includes natural gas acquired for injection and subsequent resale of 7 mmcfd, 15 mmcfd and 16 mmcfd for 2013, 2012, and 2011.

^(d) Includes blendstocks.

^(e) In 2013, we entered into agreements to sell our Angola assets; therefore, our Angola operations are reflected as discontinued operations and excluded from segments in all periods presented.

112

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

Average Price Realizations (f)	2013		2012		2011
North America E&P
Crude Oil and Condensate (per bbl)
Bakken		$90.25		$83.11		$90.60
Eagle Ford	99.69		100.14		101.46
Oklahoma resource basins	94.84		89.26		—
Other North America	90.42		91.75		95.91
Total Crude Oil and Condensate	94.19		91.30		94.80
Natural Gas Liquids (per bbl)
Bakken		$41.60		$42.35	—
Eagle Ford	30.16		32.96		—
Oklahoma resource basins	35.28		31.82		$	36.95
Other North America	55.69		52.51		62.24
Total Natural Gas Liquids	35.12		39.57		58.53
Total Liquid Hydrocarbons (per bbl) (g)
Bakken		$87.76		$81.36		$90.29
Eagle Ford	84.95		88.09		95.84
Oklahoma resource basins	50.77		49.21		36.95
Other North America	88.16		89.03		93.70
Total Liquid Hydrocarbons	85.20		85.80		92.55
Natural Gas (per mcf)
Bakken		$3.90		$3.11		$6.92
Eagle Ford	3.67		3.03		4.12
Oklahoma resource basins	3.78		3.05		3.45
Alaska	7.79		6.86		6.53
Other North America	3.76		2.84		4.26
Total Natural Gas	3.84		3.92		4.95

^(f) Excludes gains or losses on derivative instruments.

^(g) Inclusion of realized gains (losses) on crude oil derivative instruments would have increased (decreased) average liquid hydrocarbon price realizations per barrel by $(0.27) and $0.40 for 2013 and 2012.

113

MARATHON OIL CORPORATION

Supplemental Statistics (Unaudited)

Average Price Realizations	2013		2012		2011
International E&P
Total Liquid Hydrocarbons (per bbl)
Equatorial Guinea		$60.34		$64.33		$67.70
Norway	113.38		116.70		116.62
United Kingdom	108.92		107.31		111.55
Libya	122.92		127.31		112.56
Total Liquid Hydrocarbons	102.10		107.78		102.96
Natural Gas (per mcf)
Equatorial Guinea(h)		$0.24		$0.24		$0.24
Norway	13.01		11.15		10.60
United Kingdom	10.64		9.72		9.26
Libya	5.44		5.76		0.70
Total Natural Gas	2.25		2.29		1.97
Oil Sands Mining
Synthetic Crude Oil (per bbl)		$87.51		$81.72		$91.65
Discontinued Operations (per bbl)(e)		$104.77	—		—
Total Proved Reserves (at year end)
Liquid Hydrocarbons (mmbbl)
North America E&P	616		475		279
International E&P	402		408		436
Total Continuing Operations	1,018		883		715
Natural Gas (bcf)
North America E&P	1,025		1,043		872
International E&P	1,646		1,736		1,794
Total Continuing Operations	2,671		2,779		2,666
Synthetic Crude Oil (mmbbl)
Oil Sands Mining	680		653		623
Continuing Operations (mmboe)	2,143		1,999		1,782
Discontinued Operations (mmboe)(e)	28		18		18
Total Proved Reserves (mmboe)	2,171		2,017		1,800

^(h) Primarily represents fixed prices under long-term contracts with Alba Plant LLC, AMPCO and EGHoldings, which are equity method investees. We include our share of income from each of these equity method investees in our International E&P segment.

114

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

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) was carried out under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer. As of the end of the period covered by this Report based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that the design and operation of these disclosure controls and procedures were effective as of December 31, 2013.

Internal Control Over Financial Reporting

In the first quarter of 2013, we completed the update of our existing Enterprise Resource Planning ("ERP") system. This update included a new general ledger, consolidations system and reporting tools. During the fourth quarter of 2013, there were no changes in our internal control over financial reporting that have materially affected, or were reasonably likely to materially affect, our internal control over financial reporting. See Item 8. Financial Statements and Supplementary Data — Management’s Report on Internal Control over Financial Reporting and – Report of Independent Registered Public Accounting Firm.

Item 9B. Other Information

None.

115

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information concerning our directors required by this item is incorporated by reference to the material appearing under the heading "Election of Directors" in our Proxy Statement for the 2014 Annual Meeting of Stockholders.

Our Board of Directors has established the Audit and Finance Committee and determined our "Audit Committee Financial Expert." The related information required by this item is incorporated by reference to the material appearing under the sub-heading "Audit and Finance Committee" located under the heading "The Board of Directors and Governance Matters" in our Proxy Statement for the 2014 Annual Meeting of Stockholders.

We have adopted a Code of Ethics for Senior Financial Officers. It is available on our website at http://www.marathonoil.com/Investor_Center/Corporate_Governance/Code_of_Ethics_for_Senior_Financial_Officers/.

Executive Officers of the Registrant

See Item 1. Business – Executive Officers of the Registrant for the names, ages and titles of our executive officers.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934, as amended, requires that our directors and executive officers, and persons who own more than ten percent of a registered class of our equity securities, file reports of beneficial ownership on Form 3 and changes in beneficial ownership on Form 4 or Form 5 with the SEC. Based solely on our review of the reporting forms and written representations provided to us from the individuals required to file reports, we believe that each of our directors and executive officers has complied with the applicable reporting requirements for transactions in Marathon Oil securities during the fiscal year ended December 31, 2013.

Item 11. Executive Compensation

Information required by this item is incorporated by reference to the material appearing under the heading "Executive Compensation Tables and Other Information," under the sub-headings "Compensation Committee" and "Compensation Committee Interlocks and Insider Participation," under the heading "The Board of Directors and Governance Matters" and under the heading "Compensation Committee Report" in our Proxy Statement for the 2014 Annual Meeting of Stockholders.

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

Information concerning security ownership of certain beneficial owners and management required by this item is incorporated by reference to the material appearing under the headings "Security Ownership of Certain Beneficial Owners" and "Security Ownership of Directors and Executive Officers" in our Proxy Statement for the 2014 Annual Meeting of Stockholders.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2013 with respect to shares of Marathon Oil common stock that may be issued under our existing equity compensation plans:

• Marathon Oil Corporation 2012 Incentive Compensation Plan (the "2012 Plan")

• Marathon Oil Corporation 2007 Incentive Compensation Plan (the "2007 Plan") – No additional awards will be granted under this plan.

• Marathon Oil Corporation 2003 Incentive Compensation Plan (the "2003 Plan") – No additional awards will be granted under this plan.

• Deferred Compensation Plan for Non-Employee Directors – No additional awards will be granted under this plan.

116

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted- average exercise price of outstanding options, warrants and rights(c)	Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by stockholders	19,244,830	(a)	$27.27	45,950,524	(d)
Equity compensation plans not approved by stockholders	20,984	(b)	N/A	—
Total	19,265,814		N/A	45,950,524

^(a)  Includes the following:

• 2,273,594 stock options outstanding under the 2012 Plan;

• 13,203,379 stock options outstanding under the 2007 Plan;

• 2,465,332 stock options outstanding under the 2003 Plan and the net number of stock-settled SARs that could be issued from this Plan. The number of stock-settled SARs is based on the closing price of Marathon Oil common stock on December 31, 2013 of $35.30 per share;

• 324,672 common stock units that have been credited to non-employee directors pursuant to the non-employee director deferred compensation program and the annual director stock award program established under the 2012 Plan, 2007 Plan and 2003 Plan; common stock units credited under the 2012 Plan, 2007 Plan and 2003 Plan were 51,196, 222,215 and 51,261, respectively;

• 977,853 restricted stock units granted to non-officers under the 2012 Plan and 2007 Plan and outstanding as of December 31, 2013.

In addition to the awards reported above 2,014,310 and 1,094,122 shares of restricted stock were issued and outstanding as of December 31, 2013, but subject to forfeiture restrictions under the 2012 Plan and 2007 Plan, respectively.

^(b)  Reflects awards of common stock units made to non-employee directors under the Deferred Compensation Plan for Non-Employee Directors prior to April 30, 2003. When a non-employee director leaves the Board, he or she will be issued actual shares of Marathon Oil common stock in place of the common stock units.

^(c)  The weighted-average exercise prices do not take the restricted stock units or common stock units into account as these awards have no exercise price.

^(d)  Reflects the shares available for issuance under the 2012 Plan. No more than 18,810,490 of these shares may be issued for awards other than stock options or stock appreciation rights. In addition, shares related to grants that are forfeited, terminated, canceled or expire unexercised shall again immediately become available for issuance.

The Deferred Compensation Plan for Non-Employee Directors is our only equity compensation plan that has not been approved by our stockholders. Our authority to make equity grants under this plan was terminated effective April 30, 2003. Under the Deferred Compensation Plan for Non-Employee Directors, all non-employee directors were required to defer half of their annual retainers in the form of common stock units. On the date the retainer would have otherwise been payable to the non-employee director, we credited an unfunded bookkeeping account for each non-employee director with a number of common stock units equal to half of his or her annual retainer divided by the fair market value of our common stock on that date. The ongoing value of each common stock unit equals the market price of a share of our common stock. When the non-employee director leaves the Board, he or she is issued actual shares of our common stock equal to the number of common stock units in his or her account at that time.

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

Information required by this item is incorporated by reference to the material appearing under the heading "Certain Relationships and Related Person Transactions," and under the sub-heading "Board and Committee Independence" under the heading "The Board of Directors and Governance Matters" in our Proxy Statement for the 2014 Annual Meeting of Stockholders.

Item 14. Principal Accounting Fees and Services

Information required by this item is incorporated by reference to the material appearing under the heading "Information Regarding the Independent Registered Public Accounting Firm’s Fees, Services and Independence" in our Proxy Statement for the 2014 Annual Meeting of Stockholders.

117

PART IV

Item 15. Exhibits, Financial Statement Schedules

A. Documents Filed as Part of the Report

1. Financial Statements (see Part II, Item 8. of this Report regarding financial statements)

2. Financial Statement Schedules

Financial statement schedules required under SEC rules but not included in this Report are omitted because they are not applicable or the required information is contained in the consolidated financial statements or notes thereto.

3. Exhibits:

References to Marathon Ashland Petroleum LLC or MAP are references to the entity now known as Marathon Petroleum Corporation.

Exhibit Number		Incorporated by Reference				Filed Herewith	Furnished Herewith
	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.
2	Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
2.1++	Separation and Distribution Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation	8-K	2.1	5/26/2011	001-05153
3	Articles of Incorporation and Bylaws
3.1	Restated Certificate of Incorporation of Marathon Oil Corporation	10-Q	3.1	8/8/2013	001-05153
3.2	Amended By-Laws of Marathon Oil Corporation effective February 25, 2014					X
3.3	Specimen of Common Stock Certificate					X
4	Instruments Defining the Rights of Security Holders, Including Indentures
4.1	Credit Agreement, dated as of April 5, 2012, among Marathon Oil Corporation, The Royal Bank of Scotland plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and UBS Securities LLC, as documentation agents, JPMorgan Chase Bank, N.A., as administrative agent, and certain other commercial lending institutions named therein.	8-K	4.1	4/10/2012	001-05153

118

Exhibit Number		Incorporated by Reference				Filed Herewith	Furnished Herewith
	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.
4.2	Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10 percent of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon its request.					X
10	Material Contracts
10.1	Tax Sharing Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Petroleum Corporation and MPC Investment LLC	8-K	10.1	5/26/2011	001-05153
10.2	Employee Matters Agreement dated as of May 25, 2011 among Marathon Oil Corporation and Marathon Petroleum Corporation	8-K	10.2	5/26/2011	001-05153
10.3	Amendment to Employee Matters Agreement dated as of June 30, 2011 between Marathon Oil Corporation and Marathon Petroleum Corporation	10-Q	10.3	8/8/2011	001-05153
10.4	Marathon Oil Corporation 2012 Incentive Compensation Plan	DEF 14A	App. III	3/8/2012	001-05153
10.5	Form of Initial CEO Option Grant Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan.	10-Q	10.1	11/6/2013	001-05153
10.6	Form of CEO Restricted Stock Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan (3-year prorata vesting).	10-Q	10.2	11/6/2013	001-05153
10.7	Form of CEO Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan (3-year cliff vesting).	10-Q	10.3	11/6/2013	001-05153
10.8	Marathon Oil Corporation Bonus Agreement Upon Commencement of Employment for Lee M. Tillman.	10-Q	10.4	11/6/2013	001-05153
10.9	Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Section 16 Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan	10-Q	10.1	5/10/2013	001-05153

119

Exhibit Number		Incorporated by Reference				Filed Herewith	Furnished Herewith
	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.
10.10	Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan	10-Q	10.2	5/10/2013	001-05153
10.11	Form of Nonqualified Stock Option Award Agreement for Section 16 reporting Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting)	10-K	10.5	2/22/2013	001-05153
10.12	Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting)	10-K	10.6	2/22/2013	001-05153
10.13	Form of Restricted Stock Award Agreement for Section 16 reporting Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year cliff vesting)	10-K	10.7	2/22/2013	001-05153
10.14	Form of Restricted Stock Award Agreement for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year cliff vesting)	10-K	10.8	2/22/2013	001-05153
10.15	Form of Restricted Stock Award Agreement for Section 16 reporting Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting)	10-K	10.9	2/22/2013	001-05153
10.16	Form of Restricted Stock Award Agreement for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting)	10-K	10.10	2/22/2013	001-05153
10.17	Form of Nonqualified Stock Option Award Agreement for non-officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting)	10-K	10.11	2/22/2013	001-05153
10.18	Form of Nonqualified Stock Option Award Agreement for non-officers in Canada granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting)	10-K	10.12	2/22/2013	001-05153
10.19	Form of Restricted Stock Award Agreement for non-officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting)	10-K	10.13	2/22/2013	001-05153

120

Exhibit Number		Incorporated by Reference				Filed Herewith	Furnished Herewith
	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.
10.20	Form of Restricted Stock Award Agreement for non-officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting)	10-K	10.14	2/22/2013	001-05153
10.21	Marathon Oil Corporation 2007 Incentive Compensation Plan	10-K	10.5	2/29/2012	001-05153
10.22	Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation's 2007 Incentive Compensation Plan, effective May 30, 2007	10-K	10.6	2/29/2012	001-05153
10.23	Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective February 24, 2010	10-K	10.5	2/28/2011	001-05153
10.24	Form of Officer Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective May 30, 2007	10-K	10.8	2/29/2012	001-05153
10.25	Form of Officer Restricted Stock Award Agreement for Section 16 officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective February 24, 2010	10-K	10.7	2/28/2011	001-05153
10.26	Form of Performance Unit Award Agreement (30 month Performance Cycle) for Section 16 Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective July 27, 2011	10-K	10.12	2/29/2012	001-05153
10.27	Form of Performance Unit Award Agreement (30 month Performance Cycle) for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective July 27, 2011	10-K	10.13	2/29/2012	001-05153
10.28	Form of Restricted Stock Award Agreement for Section 16 officers granted under Marathon Oil Corporation's 2007 Incentive Compensation Plan.	10-K	10.27	2/26/2010	001-05153
10.29	Form of Nonqualified Stock Option Award Agreement granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan	10-K	10.26	2/26/2010	001-05153
10.30	Marathon Oil Corporation 2003 Incentive Compensation Plan, Effective January 1, 2003	10-K	10.9	2/26/2010	001-05153
10.31	Form of Nonqualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Chief Executive Officer granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003	10-K	10.15	2/26/2010	001-05153

121

Exhibit Number		Incorporated by Reference				Filed Herewith	Furnished Herewith
	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.
10.32	Form of Nonqualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Executive Committee members granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003	10-K	10.16	2/26/2010	001-05153
10.33	Form of Nonqualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003	10-K	10.17	2/26/2010	001-05153
10.34	Form of Stock Appreciation Right Award Agreement for Chief Executive Officer granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003	10-K	10.19	2/26/2010	001-05153
10.35	Form of Stock Appreciation Right Award Agreement for Executive Committee members granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003	10-K	10.20	2/26/2010	001-05153
10.36	Form of Stock Appreciation Right Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003	10-K	10.21	2/26/2010	001-05153
10.37	Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan	10-K	10.22	2/26/2010	001-05153
10.38	Form of Officer Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan	10-K	10.23	2/26/2010	001-05153
10.39	Form of Nonqualified Stock Option Award Agreement for MAP officers granted under Marathon Oil Corporation's 2003 Incentive Compensation Plan, effective January 1, 2003	10-K	10.18	2/26/2010	001-05153
10.40	Marathon Oil Corporation Deferred Compensation Plan for Non-Employee Directors (Amended and Restated as of January 1, 2009)	10-K	10.14	2/27/2009	001-05153
10.41	Marathon Oil Company Deferred Compensation Plan Amended and Restated Effective June 30, 2011	10-K	10.32	2/29/2012	001-05153
10.42	Marathon Oil Company Excess Benefit Plan Amended and Restated	10-K	10.31	2/29/2012	001-05153
10.43	Marathon Oil Executive Change in Control Severance Benefits Plan, effective as of December 31, 2008	10-K	10.35	2/27/2009	001-05153

122

Exhibit Number		Incorporated by Reference				Filed Herewith	Furnished Herewith
	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.
10.44	First Amendment to the Marathon Oil Corporation Executive Change in Control Severance Benefits Plan, effective October 26, 2011.	10-Q	10.3	5/4/2012	001-05153
10.45	Marathon Oil Corporation 2011 Officer Change in Control Severance Benefits Plan (For Officers Hired or Promoted after October 26, 2011).	10-Q	10.4	5/4/2012	001-05153
10.46	Marathon Oil Corporation Policy for Repayment of Annual Cash Bonus Amounts	10-K	10.10	2/28/2011	001-05153
10.47	Marathon Oil Executive Tax, Estate, and Financial Planning Program, Amended and Restated, Effective January 1, 2009	10-K	10.32	2/27/2009	001-05153
10.48	Form of Performance Unit Award Agreement (2012-2014 Performance Cycle) granted under Marathon Oil Corporation's 2007 Incentive Compensation Plan.	10-Q	10.2	5/4/2012	001-05153
12.1	Computation of Ratio of Earnings to Fixed Charges					X
14.1	Code of Ethics for Senior Financial Officers	10-K	14.1	2/26/2010	001-05153
21.1	List of Significant Subsidiaries					X
23.1	Consent of Independent Registered Public Accounting Firm					X
23.2	Consent of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists					X
23.3	Consent of Ryder Scott Company, L.P., independent petroleum engineers and geologists					X
23.4	Consent of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists					X
31.1	Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934					X
31.2	Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934					X
32.1	Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350					X
32.2	Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350					X
99.1	Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2013					X

123

Exhibit Number		Incorporated by Reference				Filed Herewith	Furnished Herewith
	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.
99.2	Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2012	10-K	99.1	2/22/2013	001-05153
99.3	Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2011	10-K	99.1	2/29/2012	001-05153
99.4	Summary report of audits performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2013					X
99.5	Summary report of audits performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2012	10-K	99.4	2/22/2013	001-05153
99.6	Summary report of audits performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2011	10-K	99.4	2/29/2012	001-05153
99.7	Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2013					X
99.8	Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2012	10-K	99.6	2/22/2013	001-05153
99.9	Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2011	10-K	99.5	2/29/2012	001-05153
101.INS	XBRL Instance Document					X
101.SCH	XBRL Taxonomy Extension Schema					X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase					X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase					X
101.LAB	XBRL Taxonomy Extension Label Linkbase					X
101.DEF	XBRL Taxonomy Extension Definition Linkbase					X
++	Marathon Oil agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.

124

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

February 28, 2014	MARATHON OIL CORPORATION
	By:    /s/ John R. Sult
	Executive Vice President and Chief Financial Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on February 28, 2014 on behalf of the registrant and in the capacities indicated.

Signature	Title
/S/ LEE M. TILLMAN	President and Chief Executive Officer and Director
Lee M. Tillman
/S/ JOHN R. SULT	Executive Vice President and Chief Financial Officer
John R. Sult
/S/ DENNIS H. REILLEY	Chairman of the Board
Dennis H. Reilley
/S/ GREGORY H. BOYCE	Director
Gregory H. Boyce
/S/ PIERRE BRONDEAU	Director
Pierre Brondeau
/S/ LINDA Z. COOK	Director
Linda Z. Cook
/S/ CHADWICK C. DEATON	Director
Chadwick C. Deaton
/S/ SHIRLEY ANN JACKSON	Director
Shirley Ann Jackson
/S/ PHILIP LADER	Director
Philip Lader
/S/ MICHAEL E. J. PHELPS	Director
Michael E. J. Phelps

125

Exhibit Index

Exhibit Number		Incorporated by Reference				Filed Herewith	Furnished Herewith
	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.
2	Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
2.1++	Separation and Distribution Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation	8-K	2.1	5/26/2011	001-05153
3	Articles of Incorporation and Bylaws
3.1	Restated Certificate of Incorporation of Marathon Oil Corporation	10-Q	3.1	8/8/2013	001-05153
3.2	Amended By-Laws of Marathon Oil Corporation effective February 25, 2014					X
3.3	Specimen of Common Stock Certificate					X
4	Instruments Defining the Rights of Security Holders, Including Indentures
4.1	Credit Agreement, dated as of April 5, 2012, among Marathon Oil Corporation, The Royal Bank of Scotland plc, as syndication agent, Citibank, N.A., Morgan Stanley Senior Funding, Inc. and UBS Securities LLC, as documentation agents, JPMorgan Chase Bank, N.A., as administrative agent, and certain other commercial lending institutions named therein.	8-K	4.1	4/10/2012	001-05153
4.2	Indenture, dated as of February 26, 2002, between Marathon Oil Corporation and The Bank of New York Trust Company, N.A., successor in interest to JPMorgan Chase Bank as Trustee, relating to senior debt securities of Marathon Oil Corporation. Pursuant to CFR 229.601(b)(4)(iii), instruments with respect to long-term debt issues have been omitted where the amount of securities authorized under such instruments does not exceed 10 percent of the total consolidated assets of Marathon Oil. Marathon Oil hereby agrees to furnish a copy of any such instrument to the Securities and Exchange Commission upon its request.					X
10	Material Contracts
10.1	Tax Sharing Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Petroleum Corporation and MPC Investment LLC	8-K	10.1	5/26/2011	001-05153
10.2	Employee Matters Agreement dated as of May 25, 2011 among Marathon Oil Corporation and Marathon Petroleum Corporation	8-K	10.2	5/26/2011	001-05153

1

Exhibit Number		Incorporated by Reference				Filed Herewith	Furnished Herewith
	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.
10.3	Amendment to Employee Matters Agreement dated as of June 30, 2011 between Marathon Oil Corporation and Marathon Petroleum Corporation	10-Q	10.3	8/8/2011	001-05153
10.4	Marathon Oil Corporation 2012 Incentive Compensation Plan	DEF 14A	App. III	3/8/2012	001-05153
10.5	Form of Initial CEO Option Grant Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan.	10-Q	10.1	11/6/2013	001-05153
10.6	Form of CEO Restricted Stock Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan (3-year prorata vesting).	10-Q	10.2	11/6/2013	001-05153
10.7	Form of CEO Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2012 Incentive Compensation Plan (3-year cliff vesting).	10-Q	10.3	11/6/2013	001-05153
10.8	Marathon Oil Corporation Bonus Agreement Upon Commencement of Employment for Lee M. Tillman.	10-Q	10.4	11/6/2013	001-05153
10.9	Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Section 16 Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan	10-Q	10.1	5/10/2013	001-05153
10.10	Form of Performance Unit Award Agreement (2013-2015 Performance Cycle) for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan	10-Q	10.2	5/10/2013	001-05153
10.11	Form of Nonqualified Stock Option Award Agreement for Section 16 reporting Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting)	10-K	10.5	2/22/2013	001-05153
10.12	Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting)	10-K	10.6	2/22/2013	001-05153
10.13	Form of Restricted Stock Award Agreement for Section 16 reporting Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year cliff vesting)	10-K	10.7	2/22/2013	001-05153
10.14	Form of Restricted Stock Award Agreement for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year cliff vesting)	10-K	10.8	2/22/2013	001-05153

2

Exhibit Number		Incorporated by Reference				Filed Herewith	Furnished Herewith
	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.
10.15	Form of Restricted Stock Award Agreement for Section 16 reporting Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting)	10-K	10.9	2/22/2013	001-05153
10.16	Form of Restricted Stock Award Agreement for Officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting)	10-K	10.10	2/22/2013	001-05153
10.17	Form of Nonqualified Stock Option Award Agreement for non-officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting)	10-K	10.11	2/22/2013	001-05153
10.18	Form of Nonqualified Stock Option Award Agreement for non-officers in Canada granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting)	10-K	10.12	2/22/2013	001-05153
10.19	Form of Restricted Stock Award Agreement for non-officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting)	10-K	10.13	2/22/2013	001-05153
10.20	Form of Restricted Stock Award Agreement for non-officers granted under Marathon Oil Corporation's 2012 Incentive Compensation Plan (3-year prorata vesting)	10-K	10.14	2/22/2013	001-05153
10.21	Marathon Oil Corporation 2007 Incentive Compensation Plan	10-K	10.5	2/29/2012	001-05153
10.22	Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation's 2007 Incentive Compensation Plan, effective May 30, 2007	10-K	10.6	2/29/2012	001-05153
10.23	Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective February 24, 2010	10-K	10.5	2/28/2011	001-05153
10.24	Form of Officer Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective May 30, 2007	10-K	10.8	2/29/2012	001-05153
10.25	Form of Officer Restricted Stock Award Agreement for Section 16 officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective February 24, 2010	10-K	10.7	2/28/2011	001-05153

3

Exhibit Number		Incorporated by Reference				Filed Herewith	Furnished Herewith
	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.
10.26	Form of Performance Unit Award Agreement (30 month Performance Cycle) for Section 16 Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective July 27, 2011	10-K	10.12	2/29/2012	001-05153
10.27	Form of Performance Unit Award Agreement (30 month Performance Cycle) for Officers granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan, effective July 27, 2011	10-K	10.13	2/29/2012	001-05153
10.28	Form of Restricted Stock Award Agreement for Section 16 officers granted under Marathon Oil Corporation's 2007 Incentive Compensation Plan.	10-K	10.27	2/26/2010	001-05153
10.29	Form of Nonqualified Stock Option Award Agreement granted under Marathon Oil Corporation’s 2007 Incentive Compensation Plan	10-K	10.26	2/26/2010	001-05153
10.30	Marathon Oil Corporation 2003 Incentive Compensation Plan, Effective January 1, 2003	10-K	10.9	2/26/2010	001-05153
10.31	Form of Nonqualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Chief Executive Officer granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003	10-K	10.15	2/26/2010	001-05153
10.32	Form of Nonqualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Executive Committee members granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003	10-K	10.16	2/26/2010	001-05153
10.33	Form of Nonqualified Stock Option with Tandem Stock Appreciation Right Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003	10-K	10.17	2/26/2010	001-05153
10.34	Form of Stock Appreciation Right Award Agreement for Chief Executive Officer granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003	10-K	10.19	2/26/2010	001-05153
10.35	Form of Stock Appreciation Right Award Agreement for Executive Committee members granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003	10-K	10.20	2/26/2010	001-05153

4

Exhibit Number		Incorporated by Reference				Filed Herewith	Furnished Herewith
	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.
10.36	Form of Stock Appreciation Right Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan, effective January 1, 2003	10-K	10.21	2/26/2010	001-05153
10.37	Form of Nonqualified Stock Option Award Agreement for Officers granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan	10-K	10.22	2/26/2010	001-05153
10.38	Form of Officer Restricted Stock Award Agreement granted under Marathon Oil Corporation’s 2003 Incentive Compensation Plan	10-K	10.23	2/26/2010	001-05153
10.39	Form of Nonqualified Stock Option Award Agreement for MAP officers granted under Marathon Oil Corporation's 2003 Incentive Compensation Plan, effective January 1, 2003	10-K	10.18	2/26/2010	001-05153
10.40	Marathon Oil Corporation Deferred Compensation Plan for Non-Employee Directors (Amended and Restated as of January 1, 2009)	10-K	10.14	2/27/2009	001-05153
10.41	Marathon Oil Company Deferred Compensation Plan Amended and Restated Effective June 30, 2011	10-K	10.32	2/29/2012	001-05153
10.42	Marathon Oil Company Excess Benefit Plan Amended and Restated	10-K	10.31	2/29/2012	001-05153
10.43	Marathon Oil Executive Change in Control Severance Benefits Plan, effective as of December 31, 2008	10-K	10.35	2/27/2009	001-05153
10.44	First Amendment to the Marathon Oil Corporation Executive Change in Control Severance Benefits Plan, effective October 26, 2011.	10-Q	10.3	5/4/2012	001-05153
10.45	Marathon Oil Corporation 2011 Officer Change in Control Severance Benefits Plan (For Officers Hired or Promoted after October 26, 2011).	10-Q	10.4	5/4/2012	001-05153
10.46	Marathon Oil Corporation Policy for Repayment of Annual Cash Bonus Amounts	10-K	10.10	2/28/2011	001-05153
10.47	Marathon Oil Executive Tax, Estate, and Financial Planning Program, Amended and Restated, Effective January 1, 2009	10-K	10.32	2/27/2009	001-05153
10.48	Form of Performance Unit Award Agreement (2012-2014 Performance Cycle) granted under Marathon Oil Corporation's 2007 Incentive Compensation Plan.	10-Q	10.2	5/4/2012	001-05153
12.1	Computation of Ratio of Earnings to Fixed Charges					X
14.1	Code of Ethics for Senior Financial Officers	10-K	14.1	2/26/2010	001-05153
21.1	List of Significant Subsidiaries					X

5

Exhibit Number		Incorporated by Reference				Filed Herewith	Furnished Herewith
	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.
23.1	Consent of Independent Registered Public Accounting Firm					X
23.2	Consent of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists					X
23.3	Consent of Ryder Scott Company, L.P., independent petroleum engineers and geologists					X
23.4	Consent of Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists					X
31.1	Certification of President and Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934					X
31.2	Certification of Executive Vice President and Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934					X
32.1	Certification of President and Chief Executive Officer pursuant to 18 U.S.C. Section 1350					X
32.2	Certification of Executive Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350					X
99.1	Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2013					X
99.2	Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2012	10-K	99.1	2/22/2013	001-05153
99.3	Report of GLJ Petroleum Consultants LTD., independent petroleum engineers and geologists for 2011	10-K	99.1	2/29/2012	001-05153
99.4	Summary report of audits performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2013					X
99.5	Summary report of audits performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2012	10-K	99.4	2/22/2013	001-05153
99.6	Summary report of audits performed by Netherland, Sewell & Associates, Inc., independent petroleum engineers and geologists for 2011	10-K	99.4	2/29/2012	001-05153
99.7	Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2013					X
99.8	Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2012	10-K	99.6	2/22/2013	001-05153

6

Exhibit Number		Incorporated by Reference				Filed Herewith	Furnished Herewith
	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.
99.9	Summary report of audits performed by Ryder Scott Company, L.P., independent petroleum engineers and geologists for 2011	10-K	99.5	2/29/2012	001-05153
101.INS	XBRL Instance Document					X
101.SCH	XBRL Taxonomy Extension Schema					X
101.CAL	XBRL Taxonomy Extension Calculation Linkbase					X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase					X
101.LAB	XBRL Taxonomy Extension Label Linkbase					X
101.DEF	XBRL Taxonomy Extension Definition Linkbase					X
++	Marathon Oil agrees to furnish supplementally a copy of any omitted schedule to the SEC upon request.

7

EX-3.2

Exhibit 3.2

MARATHON OIL CORPORATION

BY-LAWS

February 25, 2014

ARTICLE I.

Stockholders.

Section 1.1 Time and Place of Meetings of Stockholders. The Corporation shall hold an annual meeting of its stockholders each calendar year for the purpose of electing directors of the Corporation, and transacting such other business as may be brought before such meeting in accordance with these By-laws, at such date, time and place as the Board of Directors by resolution may designate, or if the Board of Directors does not so designate a date, time and place, such annual meeting of stockholders of the Corporation shall be held at the principal executive office of the Corporation in Houston, Texas at 10:00 a.m., Central Time, on the last Wednesday in April in each year, if not a legal holiday, and if a legal holiday, then on the next succeeding Wednesday which is not a legal holiday.

Special meetings of the stockholders (i) may be called at any time by the Board of Directors and (ii) shall be called by the Chairman of the Board or the chief executive officer of the Corporation following receipt by the Secretary of a written request of a holder or holders, who, individually or collectively, have continuously held 20 percent or more of the outstanding shares of the Corporation’s common stock for at least one year prior to the date the Corporation receives the written request to call a special meeting. For this purpose, share ownership is to be calculated on a “net long” basis, determined by subtracting the stockholders’ short position from their long position, based on Rule 14e-4 under the Exchange Act. Any such request by a stockholder or stockholders to call a special meeting must: (i) be accompanied by proof of ownership of record of 20 percent or more of the outstanding shares of the Corporation’s common stock and state the purchase date of each such share; (ii) specify the matter or matters to be acted upon at such meeting, each of which must be a proper subject for stockholder action under applicable law, which specification must include the complete text of any resolution or any amendment to any document applicable to the Corporation intended to be presented at the meeting; (iii) state the reasons for conducting such business at a special meeting of stockholders; and (iv) provide any other information which may be required pursuant to these By-laws or any other information with respect to the matter or matters requested to be acted upon which may be required to be disclosed under the DGCL or included in a proxy statement filed pursuant to the rules of the U.S. Securities and Exchange Commission, and, as to each stockholder requesting the meeting and each other person, if any, who is a beneficial owner of the shares held by such stockholder, (a) their name and address, (b) the class and number of shares of the Corporation which are owned beneficially or of record, and (c) any material interest in the business to be brought before the meeting. Without limiting the generality of the

foregoing: (a) in the case of any such request to call a special meeting for the purpose of (or for multiple purposes that include) considering any nominee or nominees to serve on the Board of Directors, such request shall set forth all the information required to be included in a notice to which the provisions of the fourth sentence of Section 1.3 of these By-laws apply, and the provisions of the fifth sentence of Section 1.4 of these By-laws shall be applicable; and (b) in the case of any such request to call a special meeting for other purpose or purposes, such request shall set forth all the information required to be included in a notice to which the provisions of the sixth sentence of Section 1.4 of these By-laws apply. Notwithstanding the forgoing, neither the Chairman of the Board nor the chief executive officer of the Corporation shall be required to call a special stockholder meeting if (i) the special meeting request relates to an item of business that is not a proper subject for stockholder action under applicable law, (ii) a similar item was presented at any meeting of stockholders held within 120 calendar days prior to the receipt by the Corporation of the special meeting request, (iii) a similar item is included in the Corporation’s notice as an item of business to be brought before a stockholder meeting that has been called but not yet held, or (iv) the special meeting request is received by the Corporation during the period commencing 90 calendar days prior to the first anniversary of the preceding year’s annual meeting of stockholders.

Neither the annual meeting nor any special meeting of stockholders need be held within the State of Delaware.

Any action required to be taken at any annual or special meeting of the stockholders of the Corporation, or any action which may be taken at any annual or special meeting of the stockholders or otherwise, may not be taken without a meeting, prior notice and a vote, and stockholders may not act by written consent.

Section 1.2 Notice of Meetings of Stockholders. It shall be the duty of the Secretary to cause notice of each annual or special meeting to be mailed to all stockholders of record as of the record date as fixed by the Board of Directors for the determination of stockholders entitled to vote at such meeting. Such notice shall indicate briefly the action to be taken at such meeting and shall be mailed to the stockholders at the addresses of such stockholders as shown on the books of the Corporation at least 10 days but not more than 60 days preceding the meeting. Only matters stated in the notice of a special meeting of the stockholders shall be brought before and acted upon at the meeting. Any such notice may be satisfied by electronic transmission, subject to the requirements of Section 232 of the DGCL.

Section 1.3. Nomination of Directors. Only persons who are nominated in accordance with the following procedures shall be eligible for election as directors of the Corporation. Nomination for election to the Board of Directors at a meeting of stockholders may be made by the Board of Directors or by any stockholder of record of the Corporation entitled to vote generally for the election of directors at such meeting who complies with the notice procedures set forth in this Section 1.3. Such nominations, other than those made by or on behalf of the Board of Directors, shall be made by notice in writing delivered or mailed by first-class United States mail, postage prepaid, to the Secretary, and received not less than 90 days nor more than 120 days prior to the first anniversary of the date on which the Corporation first mailed its proxy materials for the preceding year’s annual meeting of stockholders; provided, however, that if the date

of the annual meeting is advanced more than 30 days prior to or delayed by more than 30 days after the anniversary of the preceding year’s annual meeting, notice by the stockholder to be timely must be so delivered not later than the close of business on the later of (i) the 90^th day prior to such annual meeting or (ii) the 10^th day following the day on which public announcement of the date of such meeting is first made. Such notice shall set forth (a) as to each proposed nominee (i) the name, age, business address and, if known, residence address of each such nominee, (ii) the principal occupation or employment of each such nominee, (iii) the number of shares of each class of the capital stock of the Corporation which are beneficially owned by each such nominee, and (iv) any other information concerning the nominee that must be disclosed as to nominees in proxy solicitations pursuant to Regulation 14A under the Exchange Act (including such person’s written consent to be named as a nominee and to serve as a director if elected); and (b) as to the stockholder giving the notice (i) the name and address, as they appear on the Corporation’s books, of such stockholder, (ii) the number of shares of each class of the capital stock of the Corporation which are beneficially owned by such stockholder, (iii) a description of any agreement, arrangement or understanding relating to any hedging or other transaction or series of transactions (including any derivative or short position profit interest, option, hedging transaction or borrowing or lending of shares) that has been entered into or made by such stockholder, the effect or intent of which is to mitigate loss, manage risk or benefit from share price changes or to increase or decrease the voting power of such stockholder or any of its Stockholder Associated Persons (as defined in Section 1.4), in any case with respect to any share of capital stock of the Corporation, and (iv) a description of any agreement, arrangement or understanding with respect to such nomination between or among the stockholder and any of its Stockholder Associated Persons, and any others (including their names) acting in concert with any of the foregoing. In addition, the notice shall include a representation that the stockholder will notify the Corporation in writing of any change in any of the information referenced above in this Section 1.3 as of the record date for the meeting promptly following the later of the record date or the date notice of the record date is first publicly disclosed. The Corporation may require any proposed nominee to furnish such other information as may reasonably be required by the Corporation to determine the eligibility of such proposed nominee to serve as a director of the Corporation, in accordance with applicable law and these By-laws. The provisions of this Section 1.3 regarding the timeliness of nominations by a stockholder shall apply to each such nomination, regardless of whether a stockholder making such nomination (i) desires to have such nomination reflected in the Corporation’s proxy statement for the meeting at which such nomination is to be made or (ii) intends to prepare separate proxy materials.

The chairman of the meeting shall, if the facts warrant, determine and declare to the meeting that a nomination was not made in accordance with the foregoing procedure, and if he should so determine, he shall so declare to the meeting and the defective nomination shall be disregarded.

Section 1.4. Notice of Business at Annual Meetings. At an annual meeting of the stockholders, only such business shall be conducted as shall have been properly brought before the meeting. To be properly brought before an annual meeting, business must be (a) specified in the notice of meeting (or any supplement thereto) given by or at

the direction of the Board of Directors, (b) otherwise properly brought before the meeting by or at the direction of the Board of Directors, or (c) otherwise properly brought before the meeting by a stockholder of record. For business to be properly brought before an annual meeting by such a stockholder, if such business relates to the election of directors of the Corporation, the stockholder must comply with the procedures set forth in Article I, Section 1.3. If such business relates to any other matter, the stockholder must have given timely notice thereof in writing to the Secretary. To be timely, a stockholder’s notice must be delivered to or mailed and received at the principal executive offices of the Corporation not less than 90 days nor more than 120 days prior to the first anniversary of the date on which the Corporation first mailed its proxy materials for the preceding year’s annual meeting of stockholders; provided, however, that if the date of the annual meeting is advanced more than 30 days prior to or delayed by more than 30 days after the anniversary of the preceding year’s annual meeting, notice by the stockholder to be timely must be so delivered not later than the close of business on the later of (i) the 90^th day prior to such annual meeting or (ii) the 10^th day following the day on which public announcement of the date of such meeting is first made. A stockholder’s notice to the Secretary shall set forth as to each matter the stockholder proposes to bring before the annual meeting (a) a brief description of the business desired to be brought before the annual meeting and the reasons for conducting such business at the annual meeting, (b) the name and address, as they appear on the Corporation’s books, of the stockholder proposing such business, (c) the number of shares of each class of the capital stock of the Corporation which are beneficially owned by the stockholder, (d) any material interest of the stockholder in such business and any Stockholder Associated Person (as defined below), individually or in the aggregate, including any anticipated benefit to the stockholder or the Stockholder Associated Person therefrom, and (e) a description of any agreement, arrangement or understanding relating to any hedging or other transaction or series of transactions (including any derivative or short position profit interest, option, hedging transaction or borrowing or lending of shares) that has been entered into or made, the effect or intent of which is to mitigate loss, manage risk or benefit from share price changes or to increase or decrease the voting power of such stockholder or any such Stockholder Associated Person, in any case with respect to any share of capital stock of the Corporation. In addition, the notice shall include a representation that the stockholder will notify the Corporation in writing of any change in any of the information referenced above in this Section 1.4 as of the record date for the meeting promptly following the later of the record date or the date notice of the record date is first publicly disclosed. With respect to the stockholder giving any such notice which includes information regarding any Stockholder Associated Person as contemplated by clauses (d) or (e) of the sixth sentence of this paragraph, the stockholder must include in such notice (i) the name and address of such Stockholder Associated Person, if any, (ii) the number of shares of each class of capital stock of the Corporation owned by such Stockholder Associated Person, if any, and (iii) to the extent known by the stockholder giving the notice, the name and address of any other stockholder supporting the proposal of other business on the date of such stockholder’s notice. Notwithstanding anything in the By-laws to the contrary, no business shall be conducted at any annual meeting except in accordance with the procedures set forth in this Section 1.4 and in

Section 1.3 of this Article I and except that any stockholder proposal which complies with Rule 14a-8 of the proxy rules (or any successor provision) promulgated under the Exchange Act and is to be included in the Corporation’s proxy statement for an annual meeting of stockholders shall be deemed to comply with the requirements of this Section 1.4. Without limiting the generality of the foregoing, the provisions of this Section 1.4 regarding the timeliness of a stockholder’s notice for a matter to be brought before an annual meeting shall apply to each such matter to be brought before the meeting, regardless of whether the stockholder proposing to bring the matter before the meeting (i) desires to have such matter reflected in the Corporation’s proxy statement for such meeting or (ii) intends to prepare separate proxy materials. Nothing in Section 1.3 or in this Section 1.4 shall be deemed to give any stockholder the right to have any nomination or proposal included in any proxy statement prepared by the Corporation, and, to the extent any such right exists under applicable law or governmental regulation, such right shall be limited to the right provided under such applicable law or governmental regulation.

The chairman of the meeting shall, if the facts warrant, determine and declare to the meeting that business was not properly brought before the meeting in accordance with the provisions of this Section 1.4, and if he should so determine, the chairman shall so declare to the meeting that any such business not properly brought before the meeting shall not be transacted.

For purposes of Section 1.3 and Section 1.4, “Stockholder Associated Person” of any stockholder shall mean (i) any person acting in concert with such stockholder, (ii) any person who beneficially owns shares of stock of the Corporation owned of record or beneficially by such stockholder and (iii) any person controlling, controlled by or under common control, directly or indirectly, such stockholder or any Stockholder Associated Person described in clause (i) or (ii) of this definition.

Section 1.5. Quorum. At each meeting of the stockholders, the holders of one- third of the voting power of the outstanding shares of stock entitled to vote generally at the meeting, present in person or represented by proxy, shall constitute a quorum, unless the representation of a larger number shall be required by law, and, in that case, the representation of the number so required shall constitute a quorum.

Except as otherwise required by law, a majority of the voting power of the shares of stock entitled to vote generally at a meeting and present in person or by proxy, whether or not constituting a quorum, may adjourn, from time to time, without notice other than by announcement at the meeting. At any such adjourned meeting at which a quorum shall be present, any business may be transacted which might have been transacted at the meeting as originally notified.

Section 1.6. Organization. The Chairman of the Board, or in his absence the Lead Director, or the chief executive officer of the Corporation in the order named, shall call meetings of the stockholders to order, and shall act as chairman of such meeting; provided, however, that the Board of Directors may appoint any person to act as chairman of any meeting in the absence of the Chairman of the Board or the Lead Director.

The Secretary of the Corporation shall act as secretary at all meetings of the stockholders; but, in the absence of the Secretary at any meeting of the stockholders, the presiding officer may appoint any person to act as secretary of the meeting.

Section 1.7. Voting. At each meeting of the stockholders, every stockholder shall be entitled to vote in person, or by proxy appointed by instrument in writing, subscribed by such stockholder or by his duly authorized attorney, or, to the extent permitted by applicable law, appointed by an electronic transmission, and delivered to the inspectors at the meeting; and such stockholder shall have the number of votes for each share of capital stock standing registered in such stockholder’s name at the date fixed by the Board of Directors pursuant to Section 4.4 of Article IV of these By-laws as may be determined in accordance with the Certificate of Incorporation, or as may be provided by applicable law. Voting at meetings of stockholders must be by written ballot in all elections of directors, but otherwise need not be by written ballot unless the Board of Directors, in its discretion, by resolution so requires or, in the case of any such meeting, the chairman of that meeting, in his or her discretion, so requires. The Board of Directors, in its discretion, may authorize the requirement of a written ballot in any case to be satisfied by electronic transmission, subject to the requirements of Section 211(e) of the DGCL.

At least ten days before each meeting of the stockholders, a full, true and complete list, in alphabetical order, of all of the stockholders entitled to vote at such meeting, showing the address of each stockholder, and indicating the class and number of shares held by each, shall be furnished and held open for inspection in such manner, as is required by applicable law. Only the persons in whose names shares of stock stand on the books of the Corporation at the date fixed by the Board of Directors pursuant to Section 4.4 of Article IV of these By-laws, as evidenced in the manner provided by applicable law, shall be entitled to vote in person or by proxy on the shares so standing in their names.

Prior to any meeting, but subsequent to the date fixed by the Board of Directors pursuant to Section 4.4 of Article IV of these By-laws, any proxy may submit his powers of attorney to the Secretary, or to the treasurer of this Corporation, for examination. The certificate of the Secretary, or of the treasurer of the Corporation, as to the regularity of such powers of attorney, and as to the class and number of shares held by the persons who severally and respectively executed such powers of attorney, shall be received as prima facie evidence of the class and number of shares represented by the holder of such powers of attorney for the purpose of establishing the presence of a quorum at such meeting and of organizing the same, and for all other purposes.

Except as otherwise provided in the Certificate of Incorporation, each director shall be elected by a vote of a majority of the votes cast with respect to the director at any meeting for the election of directors at which a quorum is present; provided, however, that the directors shall be elected by the vote of a plurality of the shares represented in person or by proxy at any such meeting and entitled to vote on the election of directors if, in connection with such meeting (i) the Secretary shall have received a notice that a stockholder has nominated a person for election to the Board in compliance with the advance-notice requirements for stockholder nominees for director set forth in Section 1.3 and (ii) such nomination shall not have been withdrawn by such

stockholder on or prior to the day next preceding the date the Corporation first mails its notice of meeting for such meeting to the stockholders of the Corporation. If directors are to be elected by a plurality of the votes cast pursuant to the provisions of the immediately preceding sentence, stockholders shall not be provided the option to vote against any one or more of the nominees, but shall only be provided the option to vote for one or more of the nominees or withhold their votes with respect to one or more of the nominees. For purposes hereof, a majority of the votes cast means that the number of shares voted “for” a director must exceed the number of votes cast “against” that director. (Accordingly, abstentions will not be taken into account for this purpose.)

In the case of any question to which the stockholder approval policy of any national securities exchange or quotation system on which capital stock of the Corporation is traded or quoted on the Corporation’s application, the requirements under the Exchange Act, or any provision of the Internal Revenue Code of 1986, as amended, or the rules and regulations thereunder (the “Code”) applies, in each case for which question the Certificate of Incorporation, these By-laws or the DGCL does not specify a higher voting requirement, that question will be decided by the requisite vote that stockholder approval policy, Exchange Act requirement or Code provision, as the case may be, specifies, or the highest requisite vote if more than one applies.

A majority of the votes of the shares present in person at the meeting and those represented by proxy and entitled to vote on the question whether to ratify the appointment of independent public accountants, if that question is submitted for a vote of stockholders, will be sufficient to ratify the appointment.

All other elections, proposals and questions which have properly come before any meeting will, unless the Certificate of Incorporation, these By-laws or applicable law otherwise provides, be decided by a majority of the votes of the shares present in person at the meeting and those represented by proxy and entitled to vote at that meeting.

Section 1.8. Inspectors. At each meeting of the stockholders, the polls shall be opened and closed, the proxies and ballots shall be received and be taken in charge, and all questions touching the qualification of voters and the validity of proxies and the acceptance or rejection of votes, shall be decided by one or more inspectors. Such inspector or inspectors shall be appointed by the Board of Directors before the meeting. If for any reason any of the inspectors previously appointed shall fail to attend or refuse or be unable to serve, inspectors in place of any so failing to attend or refusing or unable to serve, shall be appointed in like manner.

Section 1.9. Approval or Ratification of Acts or Contracts by Stockholders. The Board, in its discretion, may submit any act or contract for approval or ratification at any annual meeting of stockholders, or at any special meeting of stockholders called for the purpose of considering any such act or contract, and, except as applicable law or the Certificate of Incorporation otherwise provides, any act or contract that the holders of shares of stock of the Corporation present in person or by proxy at that meeting and having a majority of the votes entitled to vote on that approval or ratification approve or

ratify will, provided that a quorum is present, be as valid and as binding on the Corporation and on all stockholders as if every stockholder had approved or ratified it.

Section 1.10. Conduct of Meetings. The Board may adopt by resolution such rules and regulations for the conduct of meetings of stockholders as it deems appropriate. Except to the extent inconsistent with those rules and regulations, if any, the chairman of any meeting of stockholders will have the right and authority to prescribe such rules, regulations and procedures and to do all such acts as, in the judgment of that chairman, are appropriate for the proper conduct of that meeting. Those rules, regulations or procedures, by whomever so adopted, may include the following:

(a)the establishment of an agenda or order of business for the meeting;

(b)rules and procedures for maintaining order at the meeting and the safety of those present;

(c)limitations on attendance at or participation in the meeting to stockholders of record, their duly authorized and constituted proxies or such other persons as the chairman of the meeting may determine;

(d)restrictions on entry to the meeting after the time fixed for the commencement thereof; and

(e)limitations on the time allotted to questions or comments by participants.

Except to the extent the Board or the chairman of any meeting otherwise prescribes, no rules of parliamentary procedure will govern any meeting of stockholders.

ARTICLE II.

Board of Directors.

Section 2.1. Number, Classes and Terms of Office. The business and affairs of the Corporation shall be managed by or under the direction of the Board of Directors.

The number of directors shall be fixed from time to time by resolution of the Board, but the number thereof shall not be less than three.

At each annual meeting of the stockholders of the Corporation, the directors shall be elected for terms expiring at the next succeeding annual meeting of the stockholders of the Corporation, provided that each director shall serve until a successor is duly elected and qualified or until such director’s earlier death, resignation or removal.

In the case of any increase in the number of directors of the Corporation, the additional director or directors shall be elected only by the Board.

Section 2.2. Vacancies. Except as otherwise provided by law, in the case of any vacancy in the Board through death, resignation, disqualification or other cause, a successor to hold office for the unexpired portion of the term of the director whose place shall be vacant, and until the election of his successor, shall be elected only by a majority of the Board then in office, even if less than a quorum.

Section 2.3. Removal. Directors of the Corporation may be removed with or without cause.

Section 2.4. Retirements. No director shall continue to serve on the Board beyond the last day of the annual stockholder election term during which such director attains the age of 72, except that a former chief executive officer of the Corporation shall not continue to serve on the Board beyond the last day of the annual stockholder election term during which the age of 70 is attained. Notwithstanding the foregoing, officer-directors, other than a chief executive officer, shall retire from the Board at the time such officer-director ceases to be a principal officer of the Corporation.

Section 2.5 Place of Meetings, etc. The Board may hold its meetings, and may have an office and keep the books of the Corporation (except as otherwise may be provided for by law) in such place or places in the State of Delaware or outside of the State of Delaware, as the Board from time to time may determine.

Section 2.6. Regular Meetings. Regular meetings of the Board shall be held at such times as may be fixed by resolution of the Board. The Secretary shall give notice, as provided for special meetings, for each regular meeting.

Section 2.7. Special Meetings. Special meetings of the Board shall be held whenever called by direction of the Chairman of the Board, the Lead Director, the chief executive officer of the Corporation, or a majority of the directors then in office.

The Secretary shall give notice of each special meeting of the Board by mailing the same at least two days before the meeting, or by telegraph, telecopier, electronic transmission or other communications device at least one day before the meeting, to each director; but such notice may be waived by any director. Unless otherwise indicated in the notice thereof, any and all business of the Board may be transacted at a special meeting of the Board. At any Board meeting at which every director shall be present, even though without any notice, any business may be transacted.

Section 2.8. Telephonic and Other Meetings. Members of the Board may hold and participate in any Board meeting by means of conference telephone or other communications equipment that permits all persons participating in the meeting to hear each other, and participation of any director in a meeting under this Section 2.8 will constitute the presence in person of that director at that meeting for purposes of these By-laws, except in the case of a director who so participates only for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business on the ground that the meeting has not been called or convened in accordance with applicable law or these By-laws.

Section 2.9. Quorum. A majority of the total number of directors then in office shall constitute a quorum for the transaction of business; but if at any meeting of the Board there be less than a quorum present, a majority of those present may adjourn the meeting from time to time.

At any meeting of the Board, all matters shall be decided by the affirmative vote of a majority of directors then present, provided, that the affirmative vote of at least one-third of all the directors then in office shall be necessary for the passage of any resolution.

Section 2.10. Order of Business. At meetings of the Board business shall be transacted in such order as, from time to time, the Board may determine by resolution.

At all meetings of the Board, the Chairman of the Board, or in his absence the Lead Director, or the chief executive officer of the Corporation, in the order named, shall preside.

Section 2.11. Compensation of Directors. Each director of the Corporation who is not a salaried officer or employee of the Corporation, or of a subsidiary of the Corporation, shall receive an annual cash retainer and an annual common stock unit award for serving as a director of the Board as the Board may from time to time determine. The Lead Director and chairs of the Committees shall receive retainers as the Board may from time to time determine.

Section 2.12. Board Committees.

(a)The Board may, by resolution or by election of a majority vote, designate one or more Committees consisting of one or more of the directors. The Board may designate one or more directors as alternate members of any Committee, who may replace any absent or disqualified member at any meeting of that Committee. The member or members present at any meeting of any Committee and not disqualified from voting at that meeting may, whether or not constituting a quorum, unanimously appoint another director to act at that meeting in any place of any member of that Committee who is absent from or disqualified to vote at that meeting.

(b)The Board by resolution may change the membership of any Committee at any time and fill vacancies on any of those committees. A majority of the members of any Committee will constitute a quorum for the transaction of business by that Committee unless the Board by resolution requires a greater number for that purpose. The Board by resolution may elect a chair of any Committee. Except as expressly provided in these By-laws, the election or appointment of any director to a Committee will not create any contract rights of that director, and the Board’s removal of any member of any Committee will not prejudice any contract rights that member otherwise may have.

(c)Under Section 2.12(a) hereof, the Board may designate an executive Committee to exercise, subject to applicable provisions of law, any or all of the powers of the Board in the management of the business and affairs of the Corporation when the Board is not in session.

(d)Each other Committee the Board of Directors may designate under Section 2.12(a) hereof will, subject to applicable provisions of law, have and may exercise all the powers and authorities of the Board to the extent the Board of Directors’ resolution designating that Committee so provides.

(e)Committee Rules; Minutes.Unless the Board otherwise provides, each Committee may make, alter and repeal rules for the conduct of its business. In the absence of those rules, each Committee will conduct its business in the same manner as the Board of Directors conducts its business under Article II. Each Committee will

keep regular minutes of its meetings and will report the same to the Board of Directors as a whole.

ARTICLE III.

Officers.

Section 3.1. Officers. The principal officers of the Corporation will be elected by the Board and shall include a chief executive officer, president, chief accounting officer, chief financial officer, vice presidents, general counsel, secretary and treasurer. All other offices, titles, powers and duties with respect to principal officers shall be determined by the Board from time to time, which can include the Chairman as an officer of the Corporation. Each principal officer who shall be a member of the Board of Directors shall be considered an officer-director.

The Board of Directors or any Committee or officer designated by the Board or any Committee may appoint such other officers as necessary, who shall have such authority and shall perform such duties as from time to time may be assigned to them by or with the authority of the Board of Directors.

Any person may hold two or more offices.

In its discretion, the Board of Directors may leave unfilled any office.

All officers, agents and employees shall be subject to removal at any time by the Board of Directors. All officers, agents and employees, other than officers elected by the Board of Directors, shall hold office at the discretion of the Committee or of the officer appointing them.

Each of the salaried officers of the Corporation shall devote his or her entire time, skill and energy to the business of the Corporation, unless the contrary is expressly consented to by the Board of Directors.

Section 3.2. Chairman of the Board. The Chairman of the Board may be an employee or officer of the Corporation and will, if present, preside at meetings of the Board of Directors and stockholders. The Chairman of the Board will exercise and perform such other duties as may be assigned by the Board of Directors. The Chairman of the Board will report to the Board of Directors.

Section 3.3. Powers and Duties of the Chief Executive Officer. Subject to any applicable determination of the Board of Directors, the chief executive officer of the Corporation shall be in general charge of the management of the day-to-day affairs of the Corporation.

Section 3.4. Powers and Duties of the President. Subject to any applicable determination of the chief executive officer of the Corporation and the Board of Directors, the president of the Corporation shall have such duties as may be assigned by the Board.

Section 3.5. Powers and Duties of the Chief Accounting Officer and Chief Financial Officer. The chief accounting officer and chief financial officer of the

Corporation shall each have such authority and shall perform such duties, as may be assigned by the Board.

Section 3.6. Powers and Duties of the General Counsel. The general counsel shall be the chief consulting officer of the Corporation in all legal matters, and, subject to any applicable determination of the Board of Directors, shall have general control of all matters of legal import concerning the Corporation.

Section 3.7. Powers and Duties of the Treasurer. Subject to any applicable determination of any other officer of the Corporation as may be designated by the Board of Directors, the treasurer of the Corporation shall have custody of all the funds and securities of the Corporation which may have come into the hand of the Corporation; when necessary or proper he or she shall endorse, or cause to be endorsed, on behalf of the Corporation, for collection, checks, notes and other obligations, and shall cause the deposit of same to the credit of the Corporation in such bank or banks or depositary as the Board of Directors may designate or as the Board of Directors by resolution may authorize; he or she shall sign all receipts and vouchers for payments made to the Corporation other than routine receipts and vouchers, the signing of which he or she may delegate; he or she shall sign all checks made by the Corporation; provided, however, that the Board of Directors may authorize and prescribe by resolution the manner in which checks drawn on banks or depositaries shall be signed, including the use of facsimile signatures, and the manner in which officers, agents or employees shall be authorized to sign; he or she may sign with the president or a vice president all certificates representing shares in the capital stock of the Corporation; whenever required by the Board of Directors, he or she shall render a statement of his or her cash account; he or she shall enter regularly, in books of the Corporation to be kept for the purpose, full and accurate account of all moneys received and paid by him or her on account of the Corporation; he or she shall, at all reasonable times, exhibit his or her books and accounts to any director of the Corporation upon request at his or her office during business hours; and he or she shall perform all other acts incident to the position of treasurer.

The treasurer shall give a bond for the faithful discharge of the assigned duties in such sum as the Board of Directors may require.

Section 3.8. Powers and Duties of Secretary. The Secretary shall keep the minutes of all meetings of the Board of Directors, and the minutes of all meetings of the stockholders, and also (unless otherwise directed by the Board of Directors) the minutes of all Committees, in books provided for that purpose; he or she shall attend to the giving and serving of all notices of the Corporation; he or she may sign with any other duly authorized person, in the name of the Corporation, all contracts authorized by the Board of Directors, and affix the seal of the Corporation thereto; he or she shall have charge of the Corporation’s certificate books, transfer books and stock ledgers, and such other books and papers as the Board of Directors may direct, all of which shall, at all reasonable times, be open to the examination of any director, upon application at the Secretary’s office during business hours; and he or she shall in general perform all other duties incident to the office of Secretary, subject to the control of the Board of Directors.

Section 3.9. Voting upon Interests in Other Business Entities. Unless otherwise ordered by the Board of Directors or any Committee, any person or persons appointed in writing by any of them shall have full power and authority on behalf of the Corporation to attend and to act and to vote at any meetings of stockholders of any corporation in which the Corporation may hold capital stock, or at any other meetings of holders of ownership interests in business entities in which the Corporation may hold an interest, including limited liability companies, and at any such meeting shall possess and may exercise any and all rights and powers incident to the ownership of such stock or other interest, and which, as the owner thereof, the Corporation might have possessed and exercised if present. The Board of Directors, by resolution, from time to time, may confer like powers upon any other person or persons.

Section 3.10. Term of Office, etc. Each officer will hold office until the first regular meeting of the Board in each year (at which a quorum shall be present) held next after the annual meeting of stockholders, and until a successor is duly elected or appointed and qualified or until such officer’s earlier death, resignation or removal. No officer of the Corporation will have any contractual right against the Corporation for compensation by reason of the election or appointment as an officer of the Corporation beyond the date of service as such, except as a written employment or other contract otherwise may provide. The Board may remove any officer with or without cause at any time, but any such removal will not prejudice the contractual rights of that officer, if any, against the Corporation. The Board by resolution may fill any vacancy occurring in any office of the Corporation by death, resignation, removal or otherwise for the unexpired portion of the term of that office at any time.

ARTICLE IV.

Capital Stock - Seal.

Section 4.1. Certificates of Shares. Shares of each class of the capital stock of the Corporation shall be uncertificated and shall not be represented by certificates, except to the extent as may be required by applicable law or as may otherwise be authorized by the Secretary or an assistant secretary of the Corporation. Ownership of any such uncertificated shares shall be evidenced by book-entry notation on the stock transfer records of the Corporation. Notwithstanding the foregoing, shares of capital stock of the Corporation represented by a certificate and issued and outstanding on February 23, 2011 shall remain represented by a certificate until such certificate is surrendered to the Corporation. All certificates surrendered to the Corporation shall be cancelled, and no new certificate shall be issued, except as may be required by applicable law or as may be authorized by the Secretary or an assistant secretary of the Corporation.

No certificate representing shares of capital stock of the Corporation shall be valid unless it is signed by two principal officers of the Corporation, or one principal officer and an assistant secretary or an assistant treasurer of the Corporation, but, where such certificate is signed by a registrar other than the Corporation or its employee the signatures of any such officer and, where authorized by resolution of the Board of Directors, any transfer agent may be facsimiles. In case any officer or transfer

agent of the Corporation who has signed, or whose facsimile signature has been placed upon, any such certificate shall have ceased to such be such officer or transfer agent of the Corporation before such certificate is issued, such certificate may be issued by the Corporation with the same effect as though the person or persons were such officer or transfer agent of the Corporation at the date of issue.

With respect to each class of capital stock of the Corporation, any certificates issued shall be consecutively numbered. The name of the person owning the shares represented thereby, with the class and number of such shares and the date of issue, shall be entered on the Corporation’s books.

Section 4.2. Transfer of Shares. Transfers of shares shall be made on the stock transfer records of the Corporation only by the registered holder thereof, or by such holder’s attorney thereunto authorized by power of attorney duly executed and filed with the Secretary, or with a transfer agent duly appointed, and upon surrender of the certificate or certificates for such shares properly endorsed, if such shares are represented by a certificate, and payment of all taxes thereon. Upon receipt of proper transfer instructions from the registered holder of uncertificated shares, from an approved source duly authorized by such holder or from such holder’s attorney thereunto authorized by power of attorney duly executed and filed with the Secretary, or with a transfer agent duly appointed, such uncertificated shares shall be cancelled and issuance of new equivalent uncertificated shares shall be made to the person entitled thereto and the transaction shall be recorded on the stock transfer records of the Corporation. The person in whose name shares stand on the Corporation’s stock transfer records shall be deemed the absolute owner thereof for all purposes as regards the Corporation and, accordingly, the Corporation shall not be bound to recognize any equitable or other claim to or interest in such shares on the part of any other person, whether or not it shall have express or other notice thereof.

Section 4.3. Regulations. The Board of Directors shall have power and authority to make all such additional rules and regulations as it may deem expedient concerning the issue, transfer and registration or replacement of shares of the capital stock of the Corporation.

The Board of Directors may appoint one or more transfer agents or assistant transfer agents, including the Corporation, and one or more registrars of transfers, including the Corporation, and may require any stock certificates to bear the signature of a transfer agent or assistant transfer agent and a registrar of transfers. The Board of Directors may at any time terminate the appointment of any transfer agent or any assistant transfer agent or any registrar of transfers.

Section 4.4. Fixing Date for Determination of Stockholders’ Rights. The Board of Directors is authorized from time to time to fix in advance a date, not exceeding 60 days preceding the date of any meeting of stockholders, or the date for the payment of any dividend, or the date for the allotment of rights, or the date when any change or conversion or exchange of capital stock shall go into effect, as a record date for the determination of the stockholders entitled to notice of, and to vote at, any such meeting and any adjournment thereof, or entitled to receive payment of any such dividend, or to any such allotment of rights, or to exercise the rights in respect of any such change,

conversion or exchange of capital stock, and in such case such stockholders and only such stockholders as shall be stockholders of record on the date so fixed shall be entitled to such notice of, and to vote at, such meeting and any adjournment thereof, or to receive payment of such dividend, or to receive such allotment of rights, or to exercise such rights, as the case may be, notwithstanding any transfer of any stock on the books of the Corporation after any such record date fixed as aforesaid.

Section 4.5. Dividends. The Board of Directors may from time to time declare such dividends as the Board shall deem advisable and proper, subject to such restrictions as may be imposed by applicable law and the Certificate of Incorporation.

Section 4.6. Facsimile Signatures. In addition to the provisions for the use of facsimile signatures elsewhere specifically authorized in these By-laws, facsimile signatures of any officer or officers of this Corporation may be used whenever and as authorized by the Board of Directors.

Section 4.7. Corporate Seal. The Board of Directors shall provide a suitable seal, containing the name of the Corporation, which seal shall be in charge of the Secretary. Unless otherwise directed by the Board of Directors, duplicates of the seal may be kept and used by the treasurer or by any assistant secretary or assistant treasurer of the Corporation.

ARTICLE V.

Indemnification.

Section 5.1. Right to Indemnification. The Corporation shall indemnify and hold harmless to the fullest extent permitted by law any person who was or is made or is threatened to be made a party or is involved in any Proceeding whether civil, criminal, administrative or investigative by reason of the fact that he, or a person for whom he is the legal representative, is or was a director, officer, employee or agent of the Corporation or is or was serving at the request of the Corporation as a director, officer, employee or agent of another corporation or of a partnership, joint venture, trust, enterprise or non-profit entity, including service with respect to employee benefit plans, against all expenses, liability, and loss reasonably incurred or suffered by such person. The Corporation shall indemnify any person seeking indemnity in connection with a Proceeding initiated by such person only if the Proceeding was authorized by the Board of Directors.

Section 5.2. Advancement of Expenses

(a)If and whenever any Indemnitee is, or is threatened to be made, a party to any Proceeding that may give rise to a right of that Indemnitee to indemnification under Section 5.1, the Corporation will advance (unless such advance is in violation of law) all Expenses reasonably incurred by or on behalf of that Indemnitee in connection with that Proceeding within 10 days after the Corporation receives a statement or statements from that Indemnitee requesting the advance or advances from time to time, whether prior to or after final disposition of that Proceeding; provided, however, that the

Corporation will have no obligation to advance Expenses if such advance will be in violation of applicable law. Each such statement must reasonably evidence the Expenses incurred by or on behalf of that Indemnitee and include or be preceded or accompanied by an undertaking by or on behalf of that Indemnitee to repay any Expenses advanced if it ultimately is determined that the Indemnitee is not entitled to be indemnified by the Corporation under Section 5.1 against those Expenses. The Corporation will accept any such undertaking without reference to the financial ability of Indemnitee to make repayment. If the Corporation advances Expenses in connection with any Claim as to which an Indemnitee has requested or may request indemnification under Section 5.1 and a determination is made under Section 5.4 that the Indemnitee is not entitled to that indemnification, the Indemnitee will not be required to reimburse the Corporation for those advances until the 180th day following the date of that determination; provided, however, that if the Indemnitee timely commences and thereafter prosecutes in good faith a judicial proceeding or arbitration under Section 5.6 or otherwise to obtain that indemnification, the Indemnitee will not be required to reimburse the Corporation for those Expenses until a determination in that proceeding or arbitration that the Indemnitee is not entitled to that indemnification has become final and nonappealable.

(b)The Corporation may advance Expenses under Section 5.2(a) to an Indemnitee or, at the Corporation’s option, directly to the Person to which those Expenses are owed, and any Indemnitee’s request for an advance under Section 5.2(a) will constitute that Indemnitee’s consent to any such direct payment, to Indemnitee’s legal counsel or any other Person.

Section 5.3. Notification and Defense of Claims.

(a)If any Indemnitee receives notice, otherwise than from the Corporation, that the Indemnitee is or will be made, or is threatened to be made, a party to any Proceeding in respect of which the Indemnitee intends to seek indemnification under this Article V, the Indemnitee must promptly notify the Corporation in writing of the nature and, to the Indemnitee’s knowledge, status of that Proceeding. If this Section 5.3(a) requires any Indemnitee to give such a notice, but that Indemnitee fails to do so, that failure will not relieve the Corporation from, or otherwise affect the obligations the Corporation may have to indemnify that Indemnitee under this Article V, unless the Corporation can establish that the failure has resulted in actual prejudice to the Corporation.

(b)Except as this Section 5.3(b) otherwise provides, in the case of any Proceeding in respect of which any Indemnitee seeks indemnification under this Article V:

(1)the Corporation and any Related Enterprise that also may be obligated to indemnify that Indemnitee in respect of that Proceeding will be entitled to participate at its own expense in that Proceeding;

(2)the Corporation or that Related Enterprise, or either of them, will be entitled to assume the defense of all Claims, other than (A) Corporation Claims, if any, and (B) other Claims, if any, as to which that Indemnitee shall reasonably reach the conclusion clause (3) of the next sentence describes, in that Proceeding against that Indemnitee by prompt written notice of that election to that Indemnitee; and

(3)if clause (2) above entitles the Corporation or that Related Enterprise to assume the defense of any of those Claims and it delivers to that Indemnitee notice of that assumption under clause (2), the Corporation will not be liable to that Indemnitee under this Article V for any fees or expenses of legal counsel for that Indemnitee which that Indemnitee incurs after that Indemnitee receives that notice.

That Indemnitee will have the right to employ that Indemnitee’s own legal counsel in that Proceeding, but, as clause (3) of the preceding sentence provides, will bear the fees and expenses of that counsel unless:

(1)the Corporation has authorized that Indemnitee in writing to retain that counsel;

(2)the Corporation shall not within a reasonable period of time actually have employed counsel to assume the defense of those Claims; or

(3)that Indemnitee shall have (A) reasonably concluded that a conflict of interest may exist between that Indemnitee and the Corporation as to the defense of one or more of those Claims and (B) communicated that conclusion to the Corporation in writing.

(c)The Corporation will not be obligated hereunder to, or to cause another Corporation Entity to, indemnify any Indemnitee against or hold that Indemnitee harmless from and in respect of any amounts paid, or agreed to be paid, by that Indemnitee in settlement of any Claim against that Indemnitee which that Indemnitee effects without the Corporation’s prior written consent. The Corporation will not settle any Claim against any Indemnitee in any manner that would impose any penalty or limitation on that Indemnitee without that Indemnitee’s prior written consent. Neither the Corporation nor any Indemnitee will unreasonably delay or withhold consent to any such settlement the other party proposes to effect.

Section 5.4. Procedure for Determination of Entitlement to Indemnification

(a)To obtain indemnification under this Article V, any Indemnitee must submit to the Corporation a written request therefor which specifies the Section or Sections under which that Indemnitee is seeking indemnification and which includes, or is accompanied by, such documentation and information as is reasonably available to that Indemnitee and is reasonably necessary to determine whether and to what extent that Indemnitee is entitled to that indemnification. Any Indemnitee may request indemnification under this Article V at any time and from time to time as that Indemnitee deems appropriate in that Indemnitee’s sole discretion. In the case of any request by any Indemnitee for indemnification under Section 5.1 as to any Claim which is pending or threatened at the time that Indemnitee delivers that request to the Corporation and would not be resolved with finality, whether by judgment, order, settlement or otherwise,

on payment of the indemnification requested, the Corporation may defer the determination under Section 5.4(c) of that Indemnitee’s entitlement to that indemnification to a date that is no later than 45 days after the effective date of that final resolution if the Board concludes in good faith that an earlier determination would be materially prejudicial to the Corporation or a Related Enterprise.

(b)On written request by any Indemnitee under Section 5.4(a) for indemnification under Section 5.1, the determination of that Indemnitee’s entitlement to that indemnification will be made:

(1)if that Indemnitee will be a director or officer of the Corporation at the time that determination is made, under Section 5.4(c) in each case; or

(2)if that Indemnitee will not be a director or officer of the Corporation at the time that determination is made, under Section 5.4(c) in any case, if so requested in writing by that Indemnitee or so directed by the Board, or, in the absence of that request and direction, as the Board shall duly authorize or direct.

(c)Each determination of any Indemnitee’s entitlement to indemnification under Section 5.1 to which this Section 5.4(c) applies will be made as follows:

(1)by a majority vote of the Disinterested Directors, even though less than a quorum; or

(2)by a committee of Disinterested Directors a majority vote of the Disinterested Directors may designate, even though less than a quorum; or

(3)if (A) there are no Disinterested Directors or (B) a majority vote of the Disinterested Directors so directs, by an Independent Counsel in a written opinion to the Board, a copy of which the Corporation will deliver to that Indemnitee;

provided, however, that if that Indemnitee has so requested in that Indemnitee’s request for indemnification, an Independent Counsel will make that determination in a written opinion to the Board, a copy of which the Corporation will deliver to Indemnitee.

(d)If it is determined that any Indemnitee is entitled to indemnification under Section 5.1, the Corporation will, or will cause another Corporation Entity to, subject to the provisions of Section 5.4(f):

(1)within 10 days after that determination pay to that Indemnitee all amounts (A) theretofore incurred by or on behalf of that Indemnitee in respect of which that Indemnitee is entitled to that indemnification by reason of that determination and (B) requested from the Corporation in writing by that Indemnitee; and

(2)thereafter on written request by that Indemnitee, pay to that Indemnitee within 10 days after that request such additional amounts theretofore incurred by or on behalf of that Indemnitee in respect of which that Indemnitee is entitled to that indemnification by reason of that determination.

Each Indemnitee must cooperate with the Person or Persons making the determination under Section 5.4(c) with respect to that Indemnitee’s entitlement to indemnification

under Section 5.1, including providing to such Person or Persons, on reasonable advance request, any documentation or information that is:

(1)not privileged or otherwise protected from disclosure;

(2)reasonably available to that Indemnitee; and

(3)reasonably necessary to that determination.

(e)If an Independent Counsel is to make a determination under Section 5.4(c) of entitlement of any Indemnitee to indemnification under Section 5.1, the Board will select the Independent Counsel and give written notice to that Indemnitee which names the Person it has selected, whereupon that Indemnitee may, within 10 days after that Indemnitee’s receipt of that notice, deliver to the Secretary a written objection to the selection; provided, however, that any such objection may be asserted only on the ground that the Person selected is not an “Independent Counsel” as Section 5.11 defines that term, and the objection must set forth with particularity the factual basis for that assertion. Absent a proper and timely objection, the person or firm so selected will act as Independent Counsel under Section 5.4(c). If any such written objection is so made and substantiated, the Person selected may not serve as Independent Counsel unless and until the objection is withdrawn or a court of competent jurisdiction has determined that the objection is without merit.

If the Person that will act as Independent Counsel has not been determined within 30 days after any Indemnitee’s submission of the related request for indemnification, either the Corporation or that Indemnitee may petition the Court of Chancery for resolution of any objection that has been made by that Indemnitee to the Board’s selection of Independent Counsel or for the appointment as Independent Counsel of a Person selected by the Court of Chancery or by such other Person as the Court of Chancery designates, and the Person with respect to whom all objections are so resolved or the Person so appointed will act as Independent Counsel under Section 5.4(c).

The Corporation will pay any and all reasonable fees and expenses the Independent Counsel incurs in connection with acting under Section 5.4(c), and the Corporation will pay all reasonable fees and expenses incident to the procedures this Section 5.4(e) sets forth, regardless of the manner in which the Independent Counsel is selected or appointed.

If any Indemnitee becomes entitled to, and does, initiate any judicial proceeding or arbitration under Section 5.6, the Corporation will terminate its engagement of the Person acting as Independent Counsel, whereupon that Person will be, subject to the applicable standards of professional conduct then prevailing, relieved of any further responsibility in the capacity of Independent Counsel.

(f)The amount of any indemnification against Expenses to which any Indemnitee becomes entitled under any provision of this Article V, including Section 5.1, will be determined subject to the provisions of this Section 5.4(f). Each Indemnitee will have the burden of showing that that Indemnitee actually has incurred the Expenses for

which that Indemnitee requests indemnification. If the Corporation or a Corporation Entity has made any advance in respect of any Expense incurred by any Indemnitee without objecting in writing to that Indemnitee at the time of the advance to the reasonableness thereof, the incurrence of that Expense by that Indemnitee will be deemed for all purposes hereof to have been reasonable. In the case of any Expense as to which such an objection has been made, or any Expense for which no advance has been made, the incurrence of that Expense will be presumed to have been reasonable, and the Corporation will have the burden of proof to overcome that presumption.

Section 5.5 Presumptions and Effect of Certain Proceedings.

(a)In making a determination under Section 5.4(c) with respect to entitlement of any Indemnitee to indemnification under Section 5.1, the Person or Persons making that determination must presume that that Indemnitee is entitled to that indemnification if that Indemnitee has submitted a request for indemnification in accordance with Section 5.4(a), and the Corporation will have the burden of proof to overcome that presumption in connection with the making by any Person or Persons of any determination contrary to that presumption.

(b)The termination of any Proceeding or of any Claim therein, by judgment, order, settlement or conviction, or on a plea of nolo contendere or its equivalent, will not, except as this Article V otherwise expressly provides, of itself adversely affect the right of any Indemnitee to indemnification under this Article V or, in the case of any determination under Section 5.4(c) of any Indemnitee’s entitlement to indemnification under Section 5.1, create a presumption that that Indemnitee did not act in good faith and in a manner that Indemnitee reasonably believed to be in or not opposed to the best interests of the Corporation or, with respect to any criminal action or proceeding, that Indemnitee had reasonable cause to believe that that Indemnitee’s conduct was unlawful.

(c)Any service of any Indemnitee as a Functionary of the Corporation or any Related Enterprise which imposes duties on, or involves services by, that Indemnitee with respect to any Related Enterprise that is an employee benefit or welfare plan or related trust, if any, or that plan’s participants or that trust’s beneficiaries, will be deemed for all purposes hereof as service at the request of the Corporation, and any action that Indemnitee takes or omits to take in connection with any such plan or trust will, if taken or omitted in good faith by that Indemnitee and in a manner that Indemnitee reasonably believed to be in the interest of the participants in or beneficiaries of that plan or trust, be deemed to have been taken or omitted in a manner “not opposed to the best interests of the Corporation” for all purposes of this Article V.

(d)For purposes of any determination under this Article V as to whether any Indemnitee has performed services or engaged in conduct on behalf of any Enterprise in good faith, that Indemnitee will be deemed to have acted in good faith if that Indemnitee acted in reliance on the records of the Enterprise or on information, opinions, reports or statements, including financial statements and other financial

information, concerning the Enterprise or any other Person which were prepared or supplied to that Indemnitee by:

(1)one or more of the officers or employees of the Enterprise;

(2)appraisers, engineers, investment bankers, legal counsel or other Persons as to matters that Indemnitee reasonably believed were within the professional or expert competence of those Persons; and

(3)any committee of the board of directors or equivalent managing body of the Enterprise of which that Indemnitee is or was, at the relevant time, not a member;

provided, however, that if that Indemnitee has actual knowledge as to any matter that makes any such reliance unwarranted as to that matter, this Section 5.5(d) will not entitle that Indemnitee to any presumption that that Indemnitee acted in good faith respecting that matter.

(e)For purposes of any determination under this Article V as to whether any Indemnitee is entitled to indemnification under Section 5.1, neither the knowledge nor the conduct of any other Functionary of the Corporation or any Related Enterprise shall be imputed to that Indemnitee.

(f)Any Indemnitee will be deemed a party to a Proceeding for all purposes of this Article V if that Indemnitee is named as a defendant or respondent in a complaint or petition for relief in that Proceeding, regardless of whether that Indemnitee ever is served with process or makes an appearance in that Proceeding.

(g)If any Indemnitee serves or served as a Functionary of a Related Enterprise, that service will be deemed to be “at the request of the Corporation” for all purposes of this Article V notwithstanding that the request is not evidenced by a writing or shown to have been made orally. In the event the Corporation were to extend the rights of indemnification and advancement of Expenses under this Article V to any Indemnitee’s serving at the request of the Corporation as a Functionary of any Enterprise other than the Corporation or a Related Enterprise, that Indemnitee must show that the request was made by the Board or at its authorization.

Section 5.6 Remedies of Indemnitee in Certain Cases.

(a) If any Indemnitee makes a written request in compliance with Section 5.4(a) for indemnification under Section 5.1 and either:

(1)no determination as to the entitlement of that Indemnitee to that indemnification is made before the last to occur of (A) the close of business on the date, if any, the Corporation has specified under Section 5.4(a) as the outside date for that determination or (B) the elapse of the 45-day period beginning the day after the date the Corporation receives that request; or

(2)a determination is made under Section 5.4(c) that that Indemnitee is not entitled to that indemnification in whole or in any part in respect of any Claim to which that request related,

that Indemnitee will be entitled to an adjudication from the Court of Chancery of that Indemnitee’s entitlement to that indemnification. Alternatively, that Indemnitee, at that Indemnitee’s option, may seek an award in arbitration to be conducted by a single arbitrator in accordance with the Commercial Arbitration Rules of the American Arbitration Association. In the case of any determination under Section 5.5(d) that is adverse to an Indemnitee, that Indemnitee must commence any such judicial proceeding or arbitration within 180 days following the date on which that Indemnitee first has the right to commence that proceeding under this Section 5.6(a) or that Indemnitee will be bound by that determination for all purposes of this Article V.

(b)If a determination has been made under Section 5.4 that an Indemnitee is not entitled to indemnification under Section 5.1, any judicial proceeding or arbitration commenced by that Indemnitee under this Section 5.6 will be conducted in all respects as a de novo trial or arbitration on the merits, and that Indemnitee will not be prejudiced by reason of that adverse determination. In any judicial proceeding or arbitration commenced under this Section 5.6, the Corporation will have the burden of proving that the Indemnitee is not entitled to indemnification hereunder, and the Corporation may not, for any purpose, refer to or introduce into evidence any determination under Section 5.4(c) which is adverse to the Indemnitee.

(c)If a determination has been made under Section 5.4 that any Indemnitee is entitled to indemnification under Section 5.1, the Corporation will be bound by that determination in any judicial proceeding or arbitration that Indemnitee thereafter commences under this Section 5.6 or otherwise, absent:

(1)a misstatement by that Indemnitee of a material fact, or an omission by that Indemnitee of a material fact necessary to make that Indemnitee’s statements not materially misleading, in connection with that Indemnitee’s request for indemnification; or

(2)a prohibition of that indemnification under applicable law.

(d)If any Indemnitee, under this Section 5.6 or otherwise, seeks a judicial adjudication of or an award in arbitration to enforce that Indemnitee’s rights under this Article V, that Indemnitee will be entitled to recover from the Corporation, and will be indemnified by the Corporation against, any and all expenses, of the types the definition of Expenses in Section 5.11 describes, reasonably incurred by or on behalf of that Indemnitee in that judicial adjudication or arbitration, but only if that Indemnitee prevails therein. If it is determined in that judicial adjudication or arbitration that that Indemnitee is entitled to receive part of, but not all, the indemnification or advancement of expenses sought, the expenses incurred by that Indemnitee in connection with that judicial adjudication or arbitration will be appropriately prorated between those in respect of which this Article V entitles that Indemnitee to indemnification and those that Indemnitee must bear.

(e)In any judicial proceeding or arbitration under this Section 5.6, the Corporation:

(1)will not, and will not permit any other Person acting on its behalf to, assert that the procedures or presumptions this Article V establishes are not valid, binding and enforceable; and

(2)will stipulate that it is bound by all the provisions of this Article V.

Section 5.7 Non-exclusivity; Equivalence to Contract Rights; Survival of Rights; Insurance; Subrogation.

(a) The rights to indemnification and advancement of Expenses and the remedies this Article V provides are not and will not be deemed exclusive of any other rights or remedies to which any Indemnitee may at any time be entitled under applicable law, the Certificate of Incorporation, any agreement, a vote of stockholders or Disinterested Directors, or otherwise, but each such right or remedy under this Article V will be cumulative with all such other rights and remedies. The rights to indemnification and advancement of Expenses this Article V provides shall be considered the equivalent of a contract right that vests upon the occurrence or alleged occurrence of any act or omission that forms the basis for or is related to the claim for which indemnification is sought by an Indemnitee, to the same extent as if the provisions of this Article V were set forth in a separate, written contract between such Indemnitee and the Corporation, and no amendment, modification or repeal of this Article V or any provision hereof will limit or restrict any right of any Indemnitee under this Article V in respect of any action that Indemnitee has taken or omitted in that Indemnitee’s capacity as a Functionary of the Corporation or any Related Enterprise prior to that amendment, modification or repeal. This Article V will not limit or restrict the power or right of the Corporation, to the extent and in the manner applicable law permits, to indemnify and advance expenses to Persons other than Indemnitees when and as authorized by the Board or by other appropriate corporate action.

(b)If the Corporation maintains an insurance policy or policies providing liability insurance for directors or officers of the Corporation, each Indemnitee will be covered by the policy or policies in accordance with its or their terms to the maximum extent of the coverage available for any such director or officer under the policy or policies. If the Corporation receives written notice from any source of a pending Proceeding to which any Indemnitee is a party and in respect of which that Indemnitee might be entitled to indemnification under Section 5.1 and the Corporation then maintains any such policy of which that Indemnitee is a beneficiary, the Corporation will:

(1)promptly give notice of that Proceeding to the relevant insurers in accordance with the applicable policy procedures; and

(2)thereafter take all action necessary to cause those insurers to pay, on behalf of that Indemnitee, all amounts payable in accordance with the applicable policy terms as a result of that Proceeding;

provided, however, that the Corporation need not comply with the provisions of this sentence if its failure to do so would not actually be prejudicial to that Indemnitee in any material respect.

(c)The Corporation will not be liable under this Article V to make or cause to be made any payment of amounts otherwise indemnifiable under this Article V, or to make or cause to be made any advance this Article V otherwise requires it to make or cause to be made, to or for the account of any Indemnitee, if and to the extent that the Indemnitee has otherwise actually received or had applied for the Indemnitee’s benefit that payment or advance or otherwise obtained the entire benefit therefrom under any insurance policy, any other contract or agreement or otherwise.

(d)If the Corporation makes or causes to be made any payment under this Article V to or for the account of any Indemnitee, it will be subrogated to the extent of that payment to all the rights of recovery of that Indemnitee, who must execute all papers required and take all action necessary to secure those rights, including execution of such documents as are necessary to enable the Corporation to bring suit to enforce those rights.

(e)The Corporation’s obligation to make or cause to be made any payment or advance under this Article V to or for the account of any Indemnitee with respect to that Indemnitee’s service at the request of the Corporation as a Functionary of any Related Enterprise will be reduced by any amount that Indemnitee has actually received as indemnification or advancement of expenses from that Related Enterprise.

Section 5.8 Benefit of this Article V.

The provisions of this Article V will inure to the benefit of each Indemnitee and that Indemnitee’s spouse, heirs, executors and administrators.

Section 5.9 Severability.

If any provision or provisions of this Article V is or are invalid, illegal or unenforceable for any reason whatsoever:

(1)the validity, legality and enforceability of the remaining provisions of this Article V, including each portion of any Section containing any such invalid, illegal or unenforceable provision which is not itself invalid, illegal or unenforceable, will not in any way be affected or impaired thereby;

(2)such provision or provisions will be deemed reformed to the extent necessary to conform to applicable law and to give the maximum effect to the intent of the Corporation as expressed in this Article V; and

(3)to the fullest extent possible, the provisions of this Article V, including each portion of any Section containing any such invalid, illegal or unenforceable provision which is not itself invalid, illegal or unenforceable, will be construed so as to give effect to the intent manifested thereby.

Section 5.10 Exceptions to Right of Indemnification or Advancement of Expenses. No provision in this Article V will obligate the Corporation to pay or cause to be paid any indemnity to or for the account of any Indemnitee in connection with or as a result of:

(1)any Claim made against that Indemnitee for an accounting of profits, under Section 16(b) of the Exchange Act or similar provision of state statutory or common law, from the purchase and sale, or sale and purchase, by that Indemnitee of securities of the Corporation or any Related Enterprise; or

(2)except for any Claim initiated by that Indemnitee, whether as a cause of action or as a defense to a cause of action under Section 5.6 or otherwise, to enforce or establish, by declaratory judgment or otherwise, that Indemnitee’s rights or remedies under this Article V, any Claim initiated by that Indemnitee without the prior authorization of the Board against the Corporation or any Related Enterprise or any of their respective present or former Functionaries.

Section 5.11 Definitions.

(a) For purposes of this Article V:

“Affiliate” has the meaning Exchange Act Rule 12b-2 specifies.

“Claim” means any claim for damages or a declaratory, equitable or other substantive remedy, or any other issue or matter, in any Proceeding.

“Corporation Claim” means, in the case of any Indemnitee, any Claim brought by or in the right of the Corporation or a Related Enterprise against that Indemnitee.

“Corporation Entity” means any Related Enterprise, other than an employee benefit or welfare plan or its related trust, if any.

“Court of Chancery” means the Court of Chancery of the State of Delaware.

“Disinterested Director” means a director of the Corporation who is not and was not a party to the Proceeding, or any Claim therein, in respect of which indemnification is sought by any Indemnitee under this Article V.

“Enterprise” means any business trust, corporation, joint venture, limited liability company, partnership or other entity or enterprise, including any operational division of any entity, or any employee benefit or welfare plan or related trust.

“Expenses” include all attorneys’ fees, retainers, court costs, transcript costs, fees of experts, witness fees, travel expenses, duplicating costs, printing and binding costs, telephone charges, postage, delivery service fees, all other disbursements or expenses of the types customarily incurred in connection with prosecuting, defending, preparing to prosecute or defend, investigating, being or preparing to be a witness in, or otherwise participating in, a Proceeding. Should any payments by the Corporation to or for the account of any Indemnitee under this Article V be determined to be subject to any federal, state or local income or excise tax, “Expenses” also will include such amounts as are necessary to place that Indemnitee in the same after-tax position, after giving effect to all applicable taxes,

that Indemnitee would have been in had no such tax been determined to apply to those payments.

“Functionary” of any Enterprise means any director, officer, manager, administrator, employee, agent, representative or other functionary of that Enterprise, including, in the case of any employee benefit or welfare plan, any member of any committee administering that plan or any individual to whom the duties of that committee are delegated.

“Indemnitee” means at any time any director, officer, employee or agent of the Corporation or any person that is or was serving at the request of the Corporation as a director, officer, employee or agent of another corporation or of a partnership, joint venture, trust, limited liability company, enterprise, non-profit entity or other entity including, without limitation, service with respect to employee benefit plans.

“Independent Counsel” means, in the case of any determination under Section 5.4(c) of the entitlement of any Indemnitee to indemnification under Section 5.1, a law firm, or a member of a law firm, that or who is experienced in matters of corporation law and neither presently is, nor in the past five years has been, retained to represent:

(1)the Corporation or any of its Affiliates or that Indemnitee in any matter material to any such Person; or

(2)any other party to the Proceeding giving rise to a claim of that Indemnitee for that indemnification;

notwithstanding the foregoing, the term “Independent Counsel” does not include at any time any Person who, under the applicable standards of professional conduct then prevailing, would have a conflict of interest in representing either the Corporation or a Related Enterprise or that Indemnitee in an action to determine that Indemnitee’s rights under these By-laws.

“Person” means any natural person, sole proprietorship, corporation, partnership, limited liability company, business trust, unincorporated organization or association, mutual company, joint stock company, joint venture or any other entity of any kind having a separate legal status or any estate, trust, union or employee organization or governmental authority.

“Proceeding” includes:

(1)any threatened, pending or completed action, suit, arbitration, alternate dispute resolution procedure, investigation, inquiry or other threatened, actual or completed proceeding, whether of a civil, criminal, administrative, investigative or private nature and irrespective of the initiator thereof; and

(2)any appeal in any such proceeding.

“Related Enterprise” means at any time any Enterprise:

(1)50% or more of the outstanding capital stock or other ownership interests of which, or the assets of which, the Corporation owns or controls, or previously owned or controlled, directly or indirectly, at that time;

(2)50% or more of the outstanding voting power of the outstanding capital stock or other ownership interests of which the Corporation owns or controls, or previously owned or controlled, directly or indirectly, at that time;

(3)that is, or previously was, an Affiliate of the Corporation which the Corporation controls, or previously controlled, by ownership, contract or otherwise and whether alone or together with another Person, directly or indirectly, at that time; or

(4)if that Enterprise is an employee benefit or welfare plan or related trust, whose participants or beneficiaries are present or former employees of the Corporation or any other Related Enterprise.

Section 5.12 Contribution. If it is established, under Section 5.4(c) or otherwise, that any Indemnitee has the right to be indemnified under Section 5.1 in respect of any Claim, but that right is unenforceable by reason of any applicable law or public policy, then, to the fullest extent applicable law permits, the Corporation, in lieu of indemnifying or causing the indemnification of that Indemnitee under Section 5.1, will contribute or cause to be contributed to the amount that Indemnitee has incurred, whether for judgments, fines, penalties, excise taxes, amounts paid or to be paid in settlement or for Expenses reasonably incurred, in connection with that Claim, in such proportion as is deemed fair and reasonable in light of all the circumstances of that Claim in order to reflect:

(1)the relative benefits that Indemnitee and the Corporation have received as a result of the event(s) or transaction(s) giving rise to that Claim; or

(2)the relative fault of that Indemnitee and of the Corporation and its other Functionaries in connection with those event(s) or transaction(s).

Section 5.13 Submission to Jurisdiction. Each Indemnitee, by seeking any indemnification or advance of Expenses under this Article V, will be deemed, except with respect to any arbitration that Indemnitee commences under Section 5.6:

(1)to have agreed that any Proceeding arising out of or in connection with this Article V must be brought only in the Court of Chancery and not in any other state or federal court in the United States of America or any court in any other country;

(2)to have consented to submit to the exclusive jurisdiction of the Court of Chancery for purposes of any Proceeding arising out of or in connection with this Article V;

(3)to have waived any objection to the laying of venue of any such Proceeding in the Court of Chancery; and

(4)to have waived, and to have agreed not to plead or to make, any claim that any such Proceeding brought in the Court of Chancery has been brought in an improper or otherwise inconvenient forum. The Corporation shall indemnify and hold harmless to the fullest extent permitted by applicable law any person who was or is made or is threatened to be made a party or is involved in any Proceeding whether civil, criminal, administrative or investigative by reason of the fact that he, or a person for whom he is the legal representative, is or was a director, officer, employee or agent of the Corporation or is or was serving at the request of the Corporation as a director, officer, employee or agent of another corporation or of a partnership, joint venture, trust, enterprise or non-profit entity, including service with respect to employee benefit plans, against all expenses, liability, and loss reasonably incurred or suffered by such person. The Corporation shall indemnify any person seeking indemnity in connection with a proceeding initiated by such person only if the proceeding was authorized by the Board of Directors.

ARTICLE VI.

Miscellaneous.

Section 6.1 Amendments. The Board of Directors shall have the power to adopt, amend and repeal the By-laws at any regular or special meeting of the Board, provided that notice of intention to adopt, amend or repeal the By-laws in whole or in part shall have been included in the notice of meeting; or, without any such notice, by a vote of two-thirds of the directors then in office.

Stockholders may adopt, amend and repeal the By-laws at any regular or special meeting of the stockholders by an affirmative vote of the majority of shares present in person or represented by proxy at the meeting and entitled to vote thereon, provided that notice of intention to adopt, amend or repeal the By-laws in whole or in part shall have been included in the notice of the meeting.

Section 6.2Offices. The Corporation’s registered office shall be in the City of Wilmington, County of New Castle, State of Delaware. The Corporation may have such other offices within and without the State of Delaware as have heretofore been established or may hereafter be established by or with the authority of the Board. The Corporation’s administrative office shall be located at 5555 San Felipe Street, Houston, Texas.

Section 6.3 Fiscal Year. The fiscal year of the Corporation will end on December 31.

Section 6.4 Interested Directors; Quorum. No contract or transaction between the Corporation and one or more of its directors or officers, or between the Corporation and any other Entity in which one or more of its directors or officers are directors or

officers (or hold equivalent offices or positions), or have a financial interest, will be void or voidable solely for this reason, or solely because the director or officer is present at or participates in the meeting of the Board or Committee which authorizes the contract or transaction, or solely because his or her votes are counted for that purpose, if:

(1)the material facts as to the relationship or interest of the director or officer and as to the contract or transaction are disclosed or are known to the Board or the Committee, and the Board or Committee in good faith authorizes the contract or transaction by the affirmative votes of a majority of the disinterested directors, even though the disinterested directors be less than a quorum; or

(2)the material facts as to the relationship of the director or officer or interest and as to the contract or transaction are disclosed or are known to the stockholders entitled to vote thereon, and the contract or transaction is specifically approved in good faith by vote of those stockholders; or

(3)the contract or transaction is fair as to the Corporation as of the time it is authorized, approved or ratified by the Board, a Committee or the stockholders.

Common or interested directors may be counted in determining the presence of a quorum at a meeting of the Board or of a Board Committee which authorizes the contract or transaction.

Section 6.5 Form of Records. Any records the Corporation maintains in the regular course of its business, including its stock ledger, books of account, and minute books, may be kept in electronic form, provided that the records so kept can be converted into clearly legible form within a reasonable time.

Section 6.6 Notices; Waiver of Notice. Whenever any notice is required to be given to any stockholder, director or member of any Committee under the provisions of the DGCL, the Certificate of Incorporation or these By-laws, that notice will be deemed to be sufficient if given (a) by telegraphic, facsimile, cable or wireless or electronic transmission or (b) by deposit of the same in the United States mail, with postage paid thereon, addressed to the person entitled thereto at his address as it appears in the records of the Corporation, and that notice will be deemed to have been given on the day of such transmission or mailing, as the case may be.

Whenever any notice is required to be given to any stockholder or director under the provisions of the DGCL, the Certificate of Incorporation or these By-laws, a waiver thereof in writing signed by or by electronic transmission from the person or persons entitled to that notice, whether before or after the time stated therein, will be equivalent to the giving of that notice. Attendance of a person at a meeting will constitute a waiver of notice of that meeting, except when the person attends a meeting for the express purpose of objecting, at the beginning of the meeting, to the transaction of any business because the meeting is not lawfully called or convened. Neither the business to be transacted at, nor the purpose of, any regular or special meeting of the stockholders, the Board or any Committee need be specified in any waiver of notice in writing or by electronic transmission unless the Certificate of Incorporation or these By-laws so require.

Section 6.7 Resignations. Any director or officer of the Corporation may resign at any time. Any such resignation must be made in writing or by electronic transmission to the Corporation and will take effect at the time specified in that writing or electronic transmission, or, if that resignation does not specify any time, at the time of its receipt by the Chairman or the Secretary. The acceptance of a resignation will not be necessary to make it effective, unless that resignation expressly so provides.

If an incumbent director who is nominated for re-election to the Board does not receive sufficient votes “for” to be elected in accordance with Section 1.7, that incumbent director shall promptly tender his or her resignation to the Board. The Corporate Governance and Nominating Committee of the Board (the “Corporate Governance and Nominating Committee”) shall make a recommendation to the Board as to whether to accept or reject the tendered resignation, or whether other action should be taken. The Board shall act on the tendered resignation, taking into account the Corporate Governance and Nominating Committee’s recommendation, and publicly disclose (by a press release, a filing with the Securities and Exchange Commission or other broadly disseminated means of communication) its decision regarding the tendered resignation within 90 days from the date of the certification of the election results. The Corporate Governance and Nominating Committee in making its recommendation, and the Board in making its decision, may each consider any factors or other information that it considers appropriate and relevant. The director who tenders his or her resignation should not participate in the recommendation of the Corporate Governance and Nominating Committee or the decision of the Board with respect to his or her resignation. If such incumbent director’s resignation is not accepted by the Board, such director shall continue to serve until the next annual meeting of the stockholders of the Corporation and until his or her successor is duly elected, or his or her earlier resignation or removal. If a director’s resignation is accepted by the Board pursuant to this Section 6.7, or if a nominee for director is not elected and the nominee is not an incumbent director, then the Board, in its sole discretion, may fill any resulting vacancy pursuant to the provisions of Article Seventh of the Certificate of Incorporation or may decrease the size of the Board pursuant to the provisions of Section 2.1.

Section 6.8 Forum for Adjudication of Disputes. Unless the Corporation consents in writing to the selection of an alternative forum, the sole and exclusive forum for (a) any derivative action or proceeding brought on behalf of the Corporation, (b) any action asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of the Corporation to the Corporation or the Corporation’s stockholders, (c) any action asserting a claim arising pursuant to any provision of the DGCL, or (d) any action asserting a claim governed by the internal affairs doctrine shall be a state or federal court located within the State of Delaware, in all cases subject to the court’s having personal jurisdiction over the indispensable parties named as defendants. Any person or entity purchasing or otherwise acquiring any interest in shares of capital stock of the Corporation shall be deemed to have notice of and consented to the provisions of this Section 6.8.

Section 6.9 Facsimile Signatures. In addition to the provisions for the use of facsimile signatures these By-laws elsewhere specifically authorize, facsimile signatures

of any officer or officers of the Corporation may be used as and whenever the Board by resolution so authorizes.

Section 6.10 Reliance on Books, Reports and Records. Each director and each member of any Committee designated by the Board will, in the performance of his duties, be fully protected in relying in good faith on the books of account or reports made to the Corporation by any of its officers, or by an independent certified public accountant, or by an appraiser selected with reasonable care by the Board or by any such committee, or in relying in good faith upon other records of the Corporation.

Section 6.11 Certain Definitional Provisions. (a) In these By-laws:

“Board” or “Board of Directors” means the board of directors of the Corporation.

“Certificate of Incorporation” means at any time the original certificate of incorporation of the Corporation as amended and restated from time to time to that time, including each certificate of designation, if any, respecting any class or series of preferred stock of the Corporation.

“Chairman” or “Chairman of the Board” means the chairman of the Board.

“Committee” means any committee of the Board.

“DGCL” means the General Corporation Law of the State of Delaware.

“Exchange Act” means the U.S. Securities Exchange Act of 1934, as amended.

“Lead Director” means the Director elected by the Board, not less than annually, by the affirmative vote of a majority of the non-employee Directors in the event (i) the Chairman and chief executive officer positions are not separate, or (ii) the Chairman is not independent according to the categorical standards for director independence set forth in the Corporation’s Corporate Governance Principles.

“Secretary” means the secretary of the Corporation.

(b)When used in these By-laws, the words “herein,” “hereof” and “hereunder” and words of similar import refer to these By-laws as a whole and not to any provision of these By-laws, and the words “Article” and “Section” refer to Articles and Sections of these By-laws unless otherwise specified.

(c)Whenever the context so requires, the singular number includes the plural and vice versa, and a reference to one gender includes the other gender and the neuter.

(d)The word “including” (and, with correlative meaning, the word “include”) means including, without limiting the generality of any description preceding that word, and the words “shall” and “will” are used interchangeably and have the same meaning.

Section 6.12 Captions. Captions to Articles and Sections of these By-laws are included for convenience of reference only, and these captions do not constitute a part hereof for any other purpose or in any way affect the meaning or construction of any provision hereof.

EX-3.3

EX-4.2

Exhibit 4.2

MARATHON OIL CORPORATION,

Issuer

and

JPMORGAN CHASE BANK,

Trustee

INDENTURE

Dated as of February 26, 2002

Senior Debt Securities

Reconciliation and Tie between Sections 3.10 through 3.18(a),

Inclusive, of the Trust Indenture Act of 1939

and Sections of this Indenture:

Section of Trust Indenture Act of 1939		Sections of Indenture
§3.10	(a)(1)	6.09
	(a)(2)	6.09
	(a)(3)	Not Applicable
	(a)(4)	Not Applicable
	(a)(5)	6.09
	(b)	6.08, 6.10
§3.11	(a)	6.13
	(b)	6.13
	(c)	Not Applicable
§3.12	(a)	7.01, 7.02
	(b)	7.02
	(c)	7.02
§3.13	(a)	7.03
	(b)	7.03
	(c)	7.03
	(d)	7.03
§3.14	(a)	7.04
	(a)(4)	1.01, 10.04
	(b)	Not Applicable
	(c)(1)	1.02
	(c)(2)	1.02
	(c)(3)	Not Applicable
	(d)	Not Applicable
	(e)	1.02
§3.15	(a)	6.01, 6.03
	(b)	6.02
	(c)	6.01
	(d)(1)	6.01
	(d)(2)	6.01, 6.03
	(d)(3)	6.01, 6.03
	(e)	5.14
§3.16	(a)(1)(A)	5.02, 5.12
	(a)(1)(B)	5.13
	(a)(2)	Not Applicable
	(a) (last sentence)	1.01
	(b)	5.08
	(c)	1.04
§3.17	(a)(1)	5.03
	(a)(2)	5.04
	(b)	10.03
§3.18	(a)	1.07

NOTE: This reconciliation and tie shall not, for any purpose, be deemed to be a part of the Indenture.

Table of Contents

		Page
ARTICLE I    DEFINITIONS AND OTHER PROVISIONS OF GENERAL APPLICATION		1
SECTION 1.01	Definitions	1
SECTION 1.02	Compliance Certificates and Opinions	8
SECTION 1.03	Form of Documents Delivered to Trustee	8
SECTION 1.04	Acts of Holders; Record Dates	9
SECTION 1.05	Notices, Etc., to Trustee and Company	10
SECTION 1.06	Notice to Holders; Waiver of Notice	10
SECTION 1.07	Conflict With Trust Indenture Act	10
SECTION 1.08	Effect of Headings and Table of Contents	11
SECTION 1.09	Successors and Assigns	11
SECTION 1.10	Separability Clause	11
SECTION 1.11	Benefits of Indenture; No Recourse Against Others	11
SECTION 1.12	Governing Law	11
SECTION 1.13	Legal Holidays	11
ARTICLE II    SECURITY FORMS		12
SECTION 2.01	Forms Generally	12
SECTION 2.02	Form of Face of Security	12
SECTION 2.03	Form of Reverse of Security	14
SECTION 2.04	Form of Legend for Global Securities	18
SECTION 2.05	Form of Trustee’s Certificate of Authentication	18
ARTICLE III    THE SECURITIES		18
SECTION 3.01	Amount Unlimited; Issuable in Series	18
SECTION 3.02	Denominations	21
SECTION 3.03	Execution, Authentication, Delivery and Dating	21
SECTION 3.04	Temporary Securities	22
SECTION 3.05	Registration, Registration of Transfer and Exchange	23
SECTION 3.06	Mutilated, Destroyed, Lost and Stolen Securities	25
SECTION 3.07	Payment of Interest; Interest Rights Preserved	25
SECTION 3.08	Persons Deemed Owners	26
SECTION 3.09	Cancellation	27
SECTION 3.10	Computation of Interest	27
ARTICLE IV    SATISFACTION AND DISCHARGE		27
SECTION 4.01	Satisfaction and Discharge of Indenture	27
SECTION 4.02	Application of Trust Money	28
ARTICLE V    REMEDIES		29
SECTION 5.01	Events of Default	29
SECTION 5.02	Acceleration of Maturity; Rescission and Annulment	30
SECTION 5.03	Collection of Indebtedness and Suits for Enforcement by Trustee	31

i

SECTION 5.04	Trustee May File Proofs of Claim	32
SECTION 5.05	Trustee May Enforce Claims Without Possession of Securities	33
SECTION 5.06	Application of Money Collected	33
SECTION 5.07	Limitation on Suits	34
SECTION 5.08	Unconditional Right of Holders to Receive Principal, Premium and Interest	34
SECTION 5.09	Restoration of Rights and Remedies	34
SECTION 5.10	Rights and Remedies Cumulative	35
SECTION 5.11	Delay or Omission Not Waiver	35
SECTION 5.12	Control by Holders	35
SECTION 5.13	Waiver of Past Defaults	35
SECTION 5.14	Undertaking for Costs	36
SECTION 5.15	Waiver of Usury, Stay or Extension Laws	36
ARTICLE VI    THE TRUSTEE		36
SECTION 6.01	Certain Duties and Responsibilities	36
SECTION 6.02	Notice of Defaults	36
SECTION 6.03	Certain Rights of Trustee	37
SECTION 6.04	Not Responsible for Recitals or Issuance of Securities	38
SECTION 6.05	May Hold Securities	38
SECTION 6.06	Money Held in Trust	38
SECTION 6.07	Compensation, Reimbursement and Indemnification	38
SECTION 6.08	Conflicting Interests	39
SECTION 6.09	Corporate Trustee Required; Eligibility	39
SECTION 6.10	Resignation and Removal; Appointment of Successor	40
SECTION 6.11	Acceptance of Appointment by Successor	41
SECTION 6.12	Merger, Conversion, Consolidation or Succession to Business	42
SECTION 6.13	Preferential Collection of Claims Against Company	43
SECTION 6.14	Appointment of Authenticating Agent	43
ARTICLE VII    HOLDERS’ LISTS AND REPORTS BY TRUSTEE AND COMPANY		45
SECTION 7.01	Company to Furnish Trustee Names and Addresses of Holders	45
SECTION 7.02	Preservation of Information; Communications to Holders	45
SECTION 7.03	Reports by Trustee	45
SECTION 7.04	Reports by Company	46
ARTICLE VIII    CONSOLIDATION, MERGER, CONVEYANCE, TRANSFER OR LEASE		46
SECTION 8.01	Company May Consolidate, Etc., Only on Certain Terms	46
SECTION 8.02	Successor Substituted	47
SECTION 8.03	Trustee Entitled to Opinion	47
ARTICLE IX    SUPPLEMENTAL INDENTURES		47
SECTION 9.01	Supplemental Indentures Without Consent of Holders	47
SECTION 9.02	Supplemental Indentures With Consent of Holders	49
SECTION 9.03	Execution of Supplemental Indentures	50
SECTION 9.04	Effect of Supplemental Indentures	50

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SECTION 9.05	Conformity With Trust Indenture Act	50
SECTION 9.06	Reference in Securities to Supplemental Indentures	50
ARTICLE X    COVENANTS		51
SECTION 10.01	Payment of Principal, Premium and Interest	51
SECTION 10.02	Maintenance of Office or Agency	51
SECTION 10.03	Money for Securities Payments to be Held in Trust	51
SECTION 10.04	Statement by Officers as to Default	52
SECTION 10.05	Mortgage of Certain Property	53
SECTION 10.06	Sale and Leaseback of Certain Properties	54
SECTION 10.07	Waiver of Certain Covenants	55
ARTICLE XI    REDEMPTION OF SECURITIES		56
SECTION 11.01	Applicability of Article	56
SECTION 11.02	Election to Redeem; Notice to Trustee	56
SECTION 11.03	Selection by Trustee of Securities to be Redeemed	56
SECTION 11.04	Notice of Redemption	57
SECTION 11.05	Deposit of Redemption Price	57
SECTION 11.06	Securities Payable on Redemption Date	58
SECTION 11.07	Securities Redeemed in Part	58
ARTICLE XII    SINKING FUNDS		58
SECTION 12.01	Applicability of Article	58
SECTION 12.02	Satisfaction of Sinking Fund Payments with Securities	59
SECTION 12.03	Redemption of Securities for Sinking Fund	59
ARTICLE XIII    DEFEASANCE AND COVENANT DEFEASANCE		59
SECTION 13.01	Company’s Option to Effect Defeasance or Covenant Defeasance	59
SECTION 13.02	Defeasance and Discharge	60
SECTION 13.03	Covenant Defeasance	60
SECTION 13.04	Conditions to Defeasance or Covenant Defeasance	61
SECTION 13.05	Deposited Money and U.S. Government Obligations to Be Held in Trust; Miscellaneous Provisions	63
SECTION 13.06	Reinstatement	64

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INDENTURE, dated as of February 26, 2002, between MARATHON OIL CORPORATION, a corporation duly organized and existing under the laws of the State of Delaware (herein called the “Company”), having its principal office at 5555 San Felipe Road, Houston, Texas 77056-2723, and JPMORGAN CHASE BANK, a corporation duly organized and existing under the laws of the State of New York, as Trustee (herein called the “Trustee”).

RECITALS OF THE COMPANY

The Company has duly authorized the execution and delivery of this Indenture to provide for the issuance from time to time of its debentures, notes or other evidences of indebtedness (herein called the “Securities”), to be issued in one or more series as in this Indenture provided.

All things necessary to make this Indenture a valid agreement of the Company, in accordance with its terms, have been done.

NOW, THEREFORE, THIS INDENTURE WITNESSETH:

For and in consideration of the premises and the purchase of the Securities by the Holders thereof, it is mutually agreed, for the equal and proportionate benefit of all Holders of the Securities or of series thereof, as follows:

ARTICLE I

DEFINITIONS AND OTHER PROVISIONS

OF GENERAL APPLICATION

SECTION 1.01 Definitions.

For all purposes of this Indenture, except as otherwise expressly provided or unless the context otherwise requires:

(1) the terms defined in this Article have the meanings assigned to them in this Article and include the plural as well as the singular;

(2) all other terms used herein which are defined in the Trust Indenture Act, either directly or by reference therein, have the meanings assigned to them therein;

(3) all accounting terms not otherwise defined herein have the meanings assigned to them in accordance with generally accepted accounting principles in the United States of America, and, except as otherwise expressly provided herein, the term “generally accepted accounting principles” with respect to any computation required or permitted hereunder shall mean such accounting principles as are generally accepted in the United States of America at the date of such computation;

(4) unless the context otherwise requires, any reference to an “Article” or a “Section” refers to an Article or a Section, as the case may be, of this Indenture; and

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(5) the words “herein,” “hereof” and “hereunder” and other words of similar import refer to this Indenture as a whole and not to any particular Article, Section or other subdivision of this Indenture.

“Act,” when used with respect to any Holder, has the meaning specified in Section 1.04.

“Affiliate” of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For the purposes of this definition, “control” when used with respect to any specified Person means the power to direct the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise; and the terms “controlling” and “controlled” have meanings correlative to the foregoing.

“Authenticating Agent” means any Person authorized by the Trustee pursuant to Section 6.14 to act on behalf of the Trustee to authenticate Securities of one or more series.

“Board of Directors” means the board of directors of the Company or any duly authorized committee of that board.

“Board Resolution” means a copy of a resolution certified by the Secretary or an Assistant Secretary of the Company to have been duly adopted by the Board of Directors and to be in full force and effect on the date of such certification, and delivered to the Trustee.

“Business Day,” when used with respect to any Place of Payment, means each Monday, Tuesday, Wednesday, Thursday and Friday which is not a day on which banking institutions in that Place of Payment are authorized or obligated by law or executive order to close.

“Commission” means the Securities and Exchange Commission.

“Company” means Marathon Oil Corporation until a successor corporation shall have become such pursuant to the applicable provisions of this Indenture, and thereafter “Company” shall mean that successor corporation.

“Company Request” or “Company Order” means a written request or order signed in the name of the Company by its Chairman of the Board, any Vice Chairman of the Board, Chief Executive Officer, President, Chief Operating Officer, Chief Financial Officer or any Vice President, and by its Treasurer, any Assistant Treasurer, the Comptroller, any Assistant Comptroller, its Secretary or any Assistant Secretary, and delivered to the Trustee.

“Consolidated Net Tangible Assets” means the aggregate value of all assets of the Company and its Subsidiaries after deducting therefrom (i) all current liabilities (excluding all long-term debt due within one year), (ii) all investments in unconsolidated subsidiaries and all investments accounted for on the equity basis, and (iii) all goodwill, patents and trademarks, unamortized debt discounts and other similar intangibles (all determined in conformity with generally accepted accounting principles and calculated on a basis consistent with the Company’s most recent audited consolidated financial statements).

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“Corporate Trust Office” means the principal office of the Trustee at which at any particular time its corporate trust business shall be administered, which at the date of original execution of this Indenture is located at JPMorgan Chase Bank, 600 Travis Street, Suite 1150, Houston, Texas 77002, Attention: Mr. Gary Jones, except that, with respect to presentation of securities for payment or registration of transfers or exchanges, such term means the office or agency of the Trustee located at JPMorgan Chase Bank, 55 Water Street, North Building, Room 234, New York, New York 10041.

“corporation” includes associations, corporations, companies, limited liability companies and business trusts.

“Covenant Defeasance” has the meaning specified in Section 13.03.

“Defaulted Interest” has the meaning specified in Section 3.07.

“Defeasance” has the meaning specified in Section 13.02.

“Depositary” means, with respect to Securities of any series issuable or issued in whole or in part in the form of one or more Global Securities, a clearing agency registered under the Exchange Act that is designated to act as Depositary for such Securities as contemplated by Section 3.01.

“Dollar” means the coin or currency of the United States as at the time of payment is legal tender for the payment of public and private debts.

“Establishment Action” shall mean

(i) resolution duly adopted by the Company’s board of directors establishing one or more series of Securities and authorizing the issuance of any Security or

(ii) a resolution or action by a committee, officer or employee of the Company, establishing one or more series of Securities and/or authorizing the issuance of any Security, in each case, pursuant to a resolution duly adopted by the Company’s board of directors.

“Event of Default” has the meaning specified in Section 5.01.

“Exchange Act” means the Securities Exchange Act of 1934 and any statute successor thereto, in each case as amended from time to time.

“Foreign Currency” means a currency of the government, or governments, of any country, or countries, other than the United States of America.

“Foreign Government Obligations” means, with respect to the Securities of any series that are denominated in a Foreign Currency, securities that are

(i) direct obligations of the government, or governments, that issued or caused to be issued such currency for the payment of which obligations its, or their, full faith and credit is pledged or

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(ii) obligations of a Person controlled or supervised by and acting as an agency or instrumentality of such government, or governments, the timely payment of which is unconditionally guaranteed as a full faith and credit obligation by such government, or governments,

which, in either case under clause (i) or (ii), are not callable or redeemable at the option of the issuer thereof.

“Global Security” means a Security that evidences all or part of the Securities of any series and bears the legend set forth in Section 2.04 (or such legend as may be specified as contemplated by Section 3.01 for such Securities).

“Holder” means a Person in whose name a Security is registered in the Security Register.

“Indenture” means this instrument as originally executed and as it may from time to time be supplemented or amended by one or more indentures supplemental hereto.

“interest,” when used with respect to an Original Issue Discount Security which by its terms bears interest only after Maturity, means interest payable after Maturity.

“Interest Payment Date,” when used with respect to any Security, means the Stated Maturity of an installment of interest on such Security.

“Maturity,” when used with respect to any Security, means the date on which the principal of such Security or an installment of principal becomes due and payable as therein or herein provided, whether at the Stated Maturity or by declaration of acceleration, call for redemption or otherwise.

“Mortgage” means, as the context may require, (i) to mortgage, pledge, encumber or subject to a lien or (ii) a mortgage, pledge, encumbrance or lien.

“Notice of Default” means a written notice of the kind specified in Section 5.01(4).

“Officers’ Certificate” means a certificate signed by the Chairman of the Board, any Vice Chairman of the Board, Chief Executive Officer, President, Chief Operating Officer, Chief Financial Officer or any Vice President, and by the Treasurer, any Assistant Treasurer, the Comptroller, any Assistant Comptroller, the Secretary or any Assistant Secretary, of the Company, and delivered to the Trustee. One of the officers signing an Officers’ Certificate given pursuant to Section 10.04 shall be the principal executive, financial or accounting officer of the Company.

“Opinion of Counsel” means a written opinion of counsel, who may be an employee of, or counsel to, the Company, and who shall be reasonably acceptable to the Trustee.

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“Original Issue Discount Security” means any Security which provides for an amount less than the principal amount thereof to be due and payable upon a declaration of acceleration of the Maturity thereof pursuant to Section 5.02.

“Outstanding,” when used with respect to Securities, means, as of the date of determination, all Securities theretofore authenticated and delivered under this Indenture, except:

(i) Securities theretofore cancelled by the Trustee or delivered to the Trustee for cancellation;

(ii) Securities for whose payment or redemption money in the necessary amount has been theretofore deposited with the Trustee or any Paying Agent (other than the Company) in trust or set aside and segregated in trust by the Company (if the Company shall act as its own Paying Agent) for the Holders of such Securities; provided that, if such Securities are to be redeemed, notice of such redemption has been duly given pursuant to this Indenture or provision therefor satisfactory to the Trustee has been made;

(iii) Securities as to which Defeasance has been effected pursuant to Section 13.02; and

(iv) Securities which have been paid pursuant to Section 3.06 or issued in exchange for or in lieu of which other Securities have been authenticated and delivered pursuant to this Indenture, other than any such Securities in respect of which there shall have been presented to the Trustee proof satisfactory to it that such Securities are held by a bona fide purchaser in whose hands such Securities are valid obligations of the Company;

provided, however, that in determining whether the Holders of the requisite principal amount of the Outstanding Securities have given, made or taken any request, demand, authorization, direction, notice, consent, waiver or other action hereunder as of any date:

(A) the principal amount of an Original Issue Discount Security which shall be deemed to be Outstanding shall be the amount of the principal thereof which would be due and payable as of such date of such determination upon acceleration of the Maturity thereof to such date pursuant to Section 5.02;

(B) if, as of such date, the principal amount payable at the Stated Maturity of a Security is not determinable, the principal amount of such Security which shall be deemed to be Outstanding shall be the amount as specified or determined as contemplated by Section 3.01;

(C) the principal amount of a Security denominated in one or more foreign currencies or currency units which shall be deemed to be Outstanding shall be the U.S. dollar equivalent, determined as of such date in the manner provided as contemplated by Section 3.01, of the principal amount of such Security (or, in the case of a Security described in clause (A) or (B) above, of the amount determined as provided in such clause); and

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(D) Securities owned by the Company or any other obligor upon the Securities or any Affiliate of the Company or of such other obligor shall be disregarded and deemed not to be Outstanding, except that, in determining whether the Trustee shall be protected in relying upon any such request, demand, authorization, direction, notice, consent, waiver or other action, only Securities which the Trustee knows to be so owned shall be so disregarded.

Securities so owned which have been pledged in good faith may be regarded as Outstanding if the pledgee establishes to the satisfaction of the Trustee the pledgee’s right so to act with respect to such Securities and that the pledgee is not the Company or any other obligor upon the Securities or any Affiliate of the Company or of such other obligor.

“Paying Agent” means the Company or any Person authorized by the Company to pay the principal of and/or any premium or interest on any Securities on behalf of the Company.

“Person” means any individual, association, corporation, partnership, joint venture, limited liability company, joint-stock company, trust, unincorporated organization or government or any agency or political subdivision thereof.

“Place of Payment,” when used with respect to the Securities of any series, means the place or places where the principal of and/or any premium or interest on the Securities of that series are payable as specified as contemplated by Section 3.01(6).

“Predecessor Security” of any particular Security means every previous Security evidencing all or a portion of the same debt as that evidenced by such particular Security; and, for the purposes of this definition, any Security authenticated and delivered under Section 3.06 in exchange for or in lieu of a mutilated, destroyed, lost or stolen Security shall be deemed to evidence the same debt as the mutilated, destroyed, lost or stolen Security.

“Redemption Date,” when used with respect to any Security to be redeemed, means the date fixed for such redemption by or pursuant to this Indenture.

“Redemption Price,” when used with respect to any Security to be redeemed, means the price at which it is to be redeemed pursuant to this Indenture.

“Regular Record Date” for the interest payable on any Interest Payment Date on the Securities of any series means the date specified for that purpose as contemplated by Section 3.01.

“Responsible Officer,” when used with respect to the Trustee, means an officer in the Institutional Trust Services department of the Trustee having direct responsibility for administration of this Indenture.

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“Securities” has the meaning stated in the first recital of this Indenture and more particularly means any Securities authenticated and delivered under this Indenture.

“Securities Act” means the Securities Act of 1933 and any statute successor thereto, in each case as amended from time to time.

“Security Register” and “Security Registrar” have the respective meanings specified in Section 3.05.

“Special Record Date” for the payment of any Defaulted Interest means a date fixed by the Trustee pursuant to Section 3.07.

“Stated Maturity,” when used with respect to any Security or any installment of principal thereof or interest thereon, means the date specified in such Security as the fixed date on which the principal of such Security or such installment of principal or interest is due and payable.

“Subsidiary” means a corporation more than 50% of the outstanding Voting Stock of which is owned, directly or indirectly, by the Company or by one or more other Subsidiaries, or by the Company and one or more other Subsidiaries.

“Trust Indenture Act” means the Trust Indenture Act of 1939 as in force at the date as of which this instrument was executed; provided, however, that in the event the Trust Indenture Act of 1939 is amended after such date, “Trust Indenture Act” means, to the extent required by any such amendment, the Trust Indenture Act of 1939 as so amended.

“Trustee” means the Person named as the “Trustee” in the first paragraph of this instrument until a successor Trustee shall have become such pursuant to the applicable provisions of this Indenture, and thereafter “Trustee” shall mean or include each Person who is then a Trustee hereunder, and if at any time there is more than one such Person, “Trustee” as used with respect to the Securities of any series shall mean the Trustee with respect to Securities of that series.

“United States” means the United States of America (including the states and the District of Columbia) and its possessions at the relevant date. As of the date of this Indenture, the possessions of the United States include Puerto Rico, the U.S. Virgin Islands, Guam, American Samoa, Wake Island and the Northern Mariana Islands.

“U.S. Government Obligation” has the meaning specified in Section 13.04.

“Vice President,” when used with respect to the Company or the Trustee, means any vice president, whether or not designated by a number or a word or words added before or after the title “vice president.”

“Voting Power” means the total voting power represented by all outstanding shares of all classes of Voting Stock.

“Voting Stock” means a corporation’s stock of any class or classes (however designated), including membership interests, membership shares or other similar equity interests, having ordinary Voting Power for the election of the directors of such corporation, other than stock having such power only by reason of the happening of a contingency.

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SECTION 1.02 Compliance Certificates and Opinions.

Upon any application or request by the Company to the Trustee to take any action under any provision of this Indenture, the Company shall furnish to the Trustee such certificates and opinions as may be required under the Trust Indenture Act. Each such certificate or opinion shall be given in the form of an Officers’ Certificate, if to be given by an officer of the Company, or an Opinion of Counsel, if to be given by counsel, and shall comply with the requirements of the Trust Indenture Act and any other requirements set forth in this Indenture.

Every certificate or opinion with respect to compliance with a condition or covenant provided for in this Indenture (except for certificates provided for in Section 10.04) shall include,

(1) a statement that each individual signing such certificate or opinion has read such covenant or condition and the definitions herein relating thereto;

(2) a brief statement as to the nature and scope of the examination or investigation upon which the statements or opinions contained in such certificate or opinion are based;

(3) a statement that, in the opinion of each such individual, he has made such examination or investigation as is necessary to enable him to express an informed opinion as to whether or not such covenant or condition has been complied with; and

(4) a statement as to whether, in the opinion of each such individual, such condition or covenant has been complied with.

SECTION 1.03 Form of Documents Delivered to Trustee.

In any case where several matters are required to be certified by, or covered by an opinion of, any specified Person, it is not necessary that all such matters be certified by, or covered by the opinion of, only one such Person, or that they be so certified or covered by only one document, but one such Person may certify or give an opinion with respect to some matters and one or more other such Persons as to other matters, and any such Person may certify or give an opinion as to such matters in one or several documents.

Any certificate or opinion of an officer of the Company may be based, insofar as it relates to legal matters, upon a certificate or opinion of, or representations by, counsel, unless such officer knows, or in the exercise of reasonable care should know, that the certificate or opinion or representations with respect to the matters upon which his certificate or opinion is based are erroneous. Any such certificate or opinion of counsel may be based, insofar as it relates to factual matters, upon a certificate or opinion of, or representations by, an officer or officers of the Company stating that the information with respect to such factual matters is in the possession of the Company, unless such counsel knows, or in the exercise of reasonable care should know, that the certificate or opinion or representations with respect to such matters are erroneous.

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Where any Person is required to make, give or execute two or more applications, requests, consents, certificates, statements, opinions or other instruments under this Indenture, they may, but need not, be consolidated and form one instrument.

SECTION 1.04 Acts of Holders; Record Dates.

Any request, demand, authorization, direction, notice, consent, waiver or other action provided or permitted by this Indenture to be given, made or taken by Holders may be embodied in and evidenced by one or more instruments of substantially similar tenor signed by such Holders in person or by an agent duly appointed in writing; and, except as herein otherwise expressly provided, such action shall become effective when such instrument or instruments are delivered to the Trustee and, where it is herein expressly required, to the Company. Such instrument or instruments (and the action embodied therein and evidenced thereby) are herein sometimes referred to as the “Act” of the Holders signing such instrument or instruments. Proof of execution of any such instrument or of a writing appointing any such agent shall be sufficient for any purpose of this Indenture and (subject to Section 6.01) conclusive in favor of the Trustee and the Company, if made in the manner provided in this Section.

The fact and date of the execution by any Person of any such instrument or writing may be proved by the affidavit of a witness of such execution or by a certificate of a notary public or other officer authorized by law to take acknowledgments of deeds, certifying that the individual signing such instrument or writing acknowledged to him the execution thereof. Where such execution is by a signer acting in a capacity other than his individual capacity, such certificate or affidavit shall also constitute sufficient proof of his authority. The fact and date of the execution of any such instrument or writing, or the authority of the Person executing the same, may also be proved in any other manner which the Trustee deems sufficient.

The ownership of Securities shall be proved by the Security Register.

Any request, demand, authorization, direction, notice, consent, waiver or other Act of the Holder of any Security shall bind every future Holder of the same Security and the Holder of every Security issued upon the registration of transfer thereof or in exchange therefor or in lieu thereof in respect of anything done, omitted or suffered to be done by the Trustee or the Company in reliance thereon, whether or not notation of such action is made upon such Security.

The Company may, in the circumstances permitted by the Trust Indenture Act, fix any day as the record date for the purpose of determining the Holders of Securities entitled to give or take any request, demand, authorization, direction, notice, consent, waiver or other action, or to vote on any action, authorized or permitted to be given or taken by Holders of Securities. If not set by the Company prior to the first solicitation of a Holder of Securities made by any Person in respect of any such action, or, in the case of any such vote, prior to such vote, the record date for any such action or vote shall be the 30th day (or, if later, the date of the most recent list of Holders required to be provided) prior to such first solicitation or vote, as the case may be. With regard to any record date, only the Holders of Securities on such date (or their duly designated proxies) shall be entitled to give or take, or vote on, the relevant action.

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SECTION 1.05 Notices, Etc., to Trustee and Company.

Any request, demand, authorization, direction, notice, consent, waiver or Act of Holders or other document provided or permitted by this Indenture to be made upon, given or furnished to, or filed with,

(1) the Trustee by any Holder or by the Company shall be sufficient for every purpose hereunder if made, given, furnished or filed in writing to or with and received by the Trustee at its Corporate Trust Office, or

(2) the Company by the Trustee or by any Holder shall be sufficient for every purpose hereunder (unless otherwise herein expressly provided) if in writing and mailed, first-class postage prepaid, to the Company addressed to: the address last furnished in writing to the Trustee by the Company, or, if no such address has been furnished, Treasurer, Marathon Oil Corporation, 5555 San Felipe Road, Houston, Texas 77056-2723.

SECTION 1.06 Notice to Holders; Waiver of Notice.

Where this Indenture provides for notice to Holders of any event, such notice shall be sufficiently given (unless otherwise herein expressly provided) if in writing and mailed, first-class postage prepaid, to each Holder affected by such event, at the address as it appears in the Security Register, not later than the latest date (if any), and not earlier than the earliest date (if any), prescribed for the giving of such notice. In any case where notice to Holders is given by mail, neither the failure to mail such notice, nor any defect in any notice so mailed, to any particular Holder shall affect the sufficiency of such notice with respect to other Holders. Where this Indenture provides for notice in any manner, such notice may be waived in writing by the Person entitled to receive such notice, either before or after the event, and such waiver shall be the equivalent of such notice. Waivers of notice by Holders shall be filed with the Trustee, but such filing shall not be a condition precedent to the validity of any action taken in reliance upon such waiver.

In case by reason of the suspension of regular mail service or by reason of any other cause it shall be impracticable to give such notice by mail, then such notification as shall be made with the approval of the Trustee shall constitute a sufficient notification for every purpose hereunder.

SECTION 1.07 Conflict With Trust Indenture Act.

If any provision hereof limits, qualifies or conflicts with a provision of the Trust Indenture Act which is required under such Act to be a part of and govern this Indenture, the latter provision shall control. If any provision of this Indenture modifies or excludes any provision of the Trust Indenture Act which may be so modified or excluded, the latter provision shall be deemed to apply to this Indenture as so modified or to be excluded, as the case may be.

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SECTION 1.08 Effect of Headings and Table of Contents.

The Article and Section headings herein and the Table of Contents are for convenience only and shall not affect the construction hereof.

SECTION 1.09 Successors and Assigns.

All covenants and agreements in this Indenture by the Company shall bind its successors and assigns, whether so expressed or not.

SECTION 1.10 Separability Clause.

In case any provision in this Indenture or in the Securities shall be invalid, illegal or unenforceable, the validity, legality and enforceability of the remaining provisions shall not in any way be affected or impaired thereby.

SECTION 1.11 Benefits of Indenture; No Recourse Against Others.

Nothing in this Indenture or in the Securities, express or implied, shall give to any Person, other than the parties hereto and their successors hereunder and the Holders, any benefit or any legal or equitable right, remedy or claim under this Indenture. A director, officer, employee, stockholder, partner or other owner of the Company or the Trustee, as such, shall not have any liability for any obligations of the Company under the Securities or for any obligations of the Company or the Trustee under this Indenture or for any claim based on, in respect of or by reason of those obligations or their creation. Each Holder by accepting a Security waives and releases all that liability. The waiver and release shall be part of the consideration for the issue of Securities.

SECTION 1.12 Governing Law.

This Indenture and the Securities shall be governed by and construed in accordance with the law of the State of New York, without giving effect to any principles of conflicts of laws thereunder to the extent the application of the laws of another jurisdiction would be required thereby.

SECTION 1.13 Legal Holidays.

In any case where any Interest Payment Date, Redemption Date or Stated Maturity of any Security shall not be a Business Day at any Place of Payment, then (notwithstanding any other provision of this Indenture or of the Securities (other than a provision of any Security which specifically states that such provision shall apply in lieu of this Section)) payment of interest or principal (and premium, if any) need not be made at such Place of Payment on such date, but may be made on the next succeeding Business Day at such Place of Payment with the same force and effect as if made on the Interest Payment Date or Redemption Date, or at the Stated Maturity.

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ARTICLE II

SECURITY FORMS

SECTION 2.01 Forms Generally.

The Securities of each series shall be in substantially the form set forth in this Article, or in such other form as shall be established by an Establishment Action or in one or more indentures supplemental hereto, in each case with such appropriate insertions, omissions, substitutions and other variations as are required or permitted by this Indenture, and may have such letters, numbers or other marks of identification and such legends or endorsements placed thereon as may be required to comply with the rules of any securities exchange or Depositary therefor or as may, consistently herewith, be determined by the officers executing such Securities, as evidenced by their execution thereof. If the form of Securities of any series is established by action taken pursuant to a Board Resolution, a copy of an appropriate record of such action shall be certified by the Secretary or an Assistant Secretary of the Company and delivered to the Trustee at or prior to the delivery of the Company Order contemplated by Section 3.03 for the authentication and delivery of such Securities.

The definitive Securities shall be printed, lithographed or engraved on steel engraved borders or may be produced in any other manner, all as determined by the officers executing such Securities, as evidenced by their execution of such Securities.

SECTION 2.02 Form of Face of Security.

[Insert any legend required by the Internal Revenue Code and the regulations thereunder.]

MARATHON OIL CORPORATION

[Insert title of the Series]

No. $

MARATHON OIL CORPORATION, a corporation duly organized and existing under the laws of the State of Delaware (herein called the “Company,” which term includes any successor Person under the Indenture hereinafter referred to), for value received, hereby promises to pay to , or registered assigns, the principal sum of Dollars on [if the Security is to bear interest prior to Maturity, insert — , and to pay interest thereon from or from the most recent Interest Payment Date to which interest has been paid or duly provided for, semi-annually on and in each year, commencing , at the rate of % per annum, until the principal hereof is paid or made available for payment [if applicable, insert — , provided that any principal and premium, and any such installment of interest, which is overdue shall bear interest at the rate of % per annum (to the extent that the payment of such interest shall be legally enforceable), from the dates such amounts are due until they are paid or made available for payment, and such interest shall be payable on demand]. The interest so payable, and punctually paid or duly provided for, on any Interest Payment Date will, as provided in such Indenture, be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of

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business on the Regular Record Date for such interest, which shall be the or (whether or not a Business Day), as the case may be, next preceding such Interest Payment Date. Any such interest not so punctually paid or duly provided for will forthwith cease to be payable to the Holder on such Regular Record Date and may either be paid to the Person in whose name this Security (or one or more Predecessor Securities) is registered at the close of business on a Special Record Date for the payment of such Defaulted Interest to be fixed by the Trustee, notice whereof shall be given to Holders of Securities of this series not less than 10 days prior to such Special Record Date, or be paid at any time in any other lawful manner not inconsistent with the requirements of any securities exchange on which the Securities of this series may be listed, and upon such notice as may be required by such exchange, all as more fully provided in said Indenture].

[If the Security is not to bear interest prior to Maturity, insert — The principal of this Security shall not bear interest except in the case of a default in payment of principal upon acceleration, upon redemption or at Stated Maturity and in such case the overdue principal and any overdue premium shall bear interest at the rate of % per annum (to the extent that the payment of such interest shall be legally enforceable), from the dates such amounts are due until they are paid or made available for payment. Interest on any overdue principal or premium shall be payable on demand. [Any such interest on overdue principal or premium which is not paid on demand shall bear interest at the rate of % per annum (to the extent that the payment of such interest on interest shall be legally enforceable), from the date of such demand until the amount so demanded is paid or made available for payment. Interest on any overdue interest shall be payable on demand.]]

Payment of the principal of (and premium, if any) and [if applicable, insert — any such] interest on this Security will be made at the office or agency of the Company maintained for that purpose in , in such [coin or currency of the United States of America] [Foreign Currency, consistent with the provisions below,] as at the time of payment is legal tender for payment of public and private debts [if applicable, insert — ; provided, however, that at the option of the Company payment of interest may be made by check mailed to the address of the Person entitled thereto as such address shall appear in the Security Register or by electronic funds transfer to an account maintained by the Person entitled thereto as specified in the Security Register, provided that such Person shall have given the Trustee written instructions].

[If the security is payable in a foreign currency, insert the appropriate provision.]

Reference is hereby made to the further provisions of this Security set forth on the reverse hereof, which further provisions shall for all purposes have the same effect as if set forth at this place.

Unless the certificate of authentication hereon has been executed by the Trustee referred to on the reverse hereof by manual signature, this Security shall not be entitled to any benefit under the Indenture or be valid or obligatory for any purpose.

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IN WITNESS WHEREOF, the Company has caused this instrument to be duly executed under its corporate seal.

Dated:.

MARATHON OIL CORPORATION

By

Attest:

SECTION 2.03 Form of Reverse of Security.

This Security is one of a duly authorized issue of securities of the Company (herein called the “Securities”), issued and to be issued in one or more series under an Indenture, dated as of February 26, 2002 (herein called the “Indenture,” which term shall have the meaning assigned to it in such instrument), between the Company and JPMorgan Chase Bank, as Trustee (herein called the “Trustee,” which term includes any successor trustee under the Indenture), and reference is hereby made to the Indenture for a statement of the respective rights, limitations of rights, duties and immunities thereunder of the Company, the Trustee and the Holders of the Securities and of the terms upon which the Securities are, and are to be, authenticated and delivered. This Security is one of the series designated on the face hereof [if applicable, insert — , limited in aggregate principal amount to $].

[If applicable, insert — The Securities of this series are subject to redemption upon not less than 30 days’ notice by mail, [if applicable, insert — (1) on in any year commencing with the year and ending with the year through operation of the sinking fund for this series at a Redemption Price equal to 100% of the principal amount, and (2)] at any time [if applicable, insert — on or after , 20], as a whole or in part, at the election of the Company, at the following Redemption Prices (expressed as percentages of the principal amount): If redeemed [if applicable, insert — on or before , %, and if redeemed] during the 12-month period beginning of the years indicated,

Year Redemption Price Year Redemption Price

and thereafter at a Redemption Price equal to % of the principal amount, together in the case of any such redemption [if applicable, insert — (whether through operation of the sinking

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fund or otherwise)] with accrued interest to the Redemption Date, but interest installments whose Stated Maturity is on or prior to such Redemption Date will be payable to the Holders of such Securities, or one or more Predecessor Securities, of record at the close of business on the relevant Record Dates referred to on the face hereof, all as provided in the Indenture.]

[If applicable, insert — The Securities of this series are subject to redemption upon not less than 30 days’ notice by mail, (1) on in any year commencing with the year and ending with the year through operation of the sinking fund for this series at the Redemption Prices for redemption through operation of the sinking fund (expressed as percentages of the principal amount) set forth in the table below, and (2) at any time [if applicable, insert — on or after ], as a whole or in part, at the election of the Company, at the Redemption Prices for redemption otherwise than through operation of the sinking fund (expressed as percentages of the principal amount) set forth in the table below: If redeemed during the 12-month period beginning of the years indicated,

Year Redemption Price for Redemption Through Operation of the Sinking Fund Redemption Price for Redemption Otherwise Than Through Operation of the Sinking Fund

and thereafter at a Redemption Price equal to % of the principal amount, together in the case of any such redemption (whether through operation of the sinking fund or otherwise) with accrued interest to the Redemption Date, but interest installments whose Stated Maturity is on or prior to such Redemption Date will be payable to the Holders of such Securities, or one or more Predecessor Securities, of record at the close of business on the relevant Regular Record Dates or Special Record Dates referred to on the face hereof, all as provided in the Indenture.]

[If applicable, insert — The sinking fund for this series provides for the redemption on in each year beginning with the year and ending with the year of [if applicable, insert — not less than $ (“mandatory sinking fund”) and not more than] $ aggregate principal amount of Securities of this series. Securities of this series acquired or redeemed by the Company otherwise than through [if applicable, insert — mandatory] sinking fund payments may be credited against subsequent [if applicable, insert — mandatory] sinking fund payments otherwise required to be made [if applicable, insert —, in the inverse order in which they become due].]

[If the Security is subject to redemption of any kind, insert — In the event of redemption of this Security in part only, a new Security or Securities of this series and of like tenor for the unredeemed portion hereof will be issued in the name of the Holder hereof upon the cancellation hereof.]

[If applicable, insert — The Indenture contains provisions for defeasance at any time of [the entire indebtedness of this Security] [or] [certain restrictive covenants and Events of Default with respect to this Security] [, in each case] upon compliance with certain conditions set forth in the Indenture.]

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[If the Security is an Original Issue Discount Security, insert — If an Event of Default with respect to Securities of this series shall occur and be continuing, an amount of principal of the Securities of this series may be declared due and payable in the manner and with the effect provided in the Indenture. Such amount shall be equal to — insert formula for determining the amount. Upon payment (i) of the amount of principal so declared due and payable and (ii) of interest on any overdue principal, premium and interest (in each case to the extent that the payment of such interest shall be legally enforceable), all of the Company’s obligations in respect of the payment of the principal of and premium and interest, if any, on the Securities of this series shall terminate.]

[If applicable, insert a paragraph regarding the indexing of the Security.]

The Indenture contains provisions permitting the Company and the Trustee to modify the Indenture or any supplemental indenture without the consent of the Holders for one or more of the following purposes: (1) to evidence the succession of another corporation to the Company; (2) to add to the covenants of the Company; (3) to add additional events of default for the benefit of Holders of all or any series of Securities; (4) to add to or change provisions of the Indenture to allow the issuance of Securities in other forms; (5) to add to, change or eliminate any of the provisions of the Indenture in respect of one or more series of Securities thereunder, under certain conditions specified therein; (6) to secure the Securities pursuant to the requirements of Section 10.05 of the Indenture or otherwise; (7) to establish the form or terms of Securities of any series as permitted by Sections 2.01 and 3.01 of the Indenture; (8) to evidence the appointment of a successor Trustee; and (9) to cure any ambiguity, to correct or supplement any provision of the Indenture which may be defective or inconsistent with any other provision of the Indenture, or to make any other provisions with respect to matters or questions arising under the Indenture as shall not adversely affect the interests of the Holders in any material respect.

The Indenture also permits, with certain exceptions as therein provided, the amendment thereof and the modification of the rights and obligations of the Company and the rights of the Holders of the Securities of each series to be affected under the Indenture at any time by the Company and the Trustee with the consent of the Holders of not less than a majority in principal amount of the Securities at the time Outstanding of each series to be affected. The Indenture also contains provisions permitting the Holders of specified percentages in principal amount of the Securities of each series at the time Outstanding, on behalf of the Holders of all Securities of such series, to waive compliance by the Company with certain provisions of the Indenture and certain past defaults under the Indenture and their consequences. Any such consent or waiver by the Holder of this Security shall be conclusive and binding upon such Holder and upon all future Holders of this Security and of any Security issued upon the registration of transfer hereof or in exchange herefor or in lieu hereof, whether or not notation of such consent or waiver is made upon this Security.

As provided in and subject to the provisions of the Indenture, the Holder of this Security shall not have the right to institute any proceeding with respect to the Indenture or for the appointment of a receiver or trustee or for any other remedy thereunder, unless such Holder shall

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have previously given the Trustee written notice of a continuing Event of Default with respect to the Securities of this series, the Holders of not less than 25% in principal amount of the Securities of this series at the time Outstanding shall have made written request to the Trustee to institute proceedings in respect of such Event of Default as Trustee and offered the Trustee reasonable indemnity, and the Trustee shall not have received from the Holders of a majority in principal amount of Securities of this series at the time Outstanding a direction inconsistent with such request, and shall have failed to institute any such proceeding, for 60 days after receipt of such notice, request and offer of indemnity. The foregoing shall not apply to any suit instituted by the Holder of this Security for the enforcement of any payment of principal hereof or any premium or interest hereon on or after the respective due dates expressed herein.

No reference herein to the Indenture and no provision of this Security or of the Indenture shall alter or impair the obligation of the Company, which is absolute and unconditional, to pay the principal of and any premium and interest on this Security at the times, place and rate, and in the coin or currency, herein prescribed.

As provided in the Indenture and subject to certain limitations therein set forth, the transfer of this Security is registrable in the Security Register, upon surrender of this Security for registration of transfer at the office or agency of the Company in any place where the principal of and any premium and interest on this Security are payable, duly endorsed by, or accompanied by a written instrument of transfer in form satisfactory to the Company and the Security Registrar duly executed by, the Holder hereof or his attorney duly authorized in writing, and thereupon one or more new Securities of this series and of like tenor, of authorized denominations and for the same aggregate principal amount, will be issued to the designated transferee or transferees.

The Securities of this series are issuable only in registered form without coupons in denominations of $ and any integral multiple thereof. As provided in the Indenture and subject to certain limitations therein set forth, Securities of this series are exchangeable for a like aggregate principal amount of Securities of this series and of like tenor of a different authorized denomination, as requested by the Holder surrendering the same.

No service charge shall be made for any such registration of transfer or exchange, but the Company may require payment of a sum sufficient to cover any tax or other governmental charge payable in connection therewith.

Prior to due presentment of this Security for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name this Security is registered as the owner hereof for all purposes, whether or not this Security be overdue, and neither the Company, the Trustee nor any such agent shall be affected by notice to the contrary.

All terms used in this Security which are defined in the Indenture shall have the meanings assigned to them in the Indenture.

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SECTION 2.04 Form of Legend for Global Securities.

Unless otherwise specified as contemplated by Section 3.01 for the Securities evidenced thereby, every Global Security authenticated and delivered hereunder shall bear a legend in substantially the following form:

This Security is a Global Security within the meaning of the Indenture hereinafter referred to and is registered in the name of a Depositary or a nominee thereof. This Security may not be exchanged in whole or in part for a Security registered, and no transfer of this Security in whole or in part may be registered, in the name of any Person other than such Depositary or a nominee thereof, except in the limited circumstances described in the Indenture.

SECTION 2.05 Form of Trustee’s Certificate of Authentication.

The Trustee’s certificates of authentication shall be in substantially the following form:

This is one of the Securities of the series designated therein referred to in the within-mentioned Indenture.

JPMORGAN CHASE BANK, As Trustee
By
	Authorized Signatory

ARTICLE III

THE SECURITIES

SECTION 3.01 Amount Unlimited; Issuable in Series.

The aggregate principal amount of Securities which may be authenticated and delivered under this Indenture is unlimited.

The Securities may be issued from time to time in one or more series. The terms of each series of Securities shall be either:

(i) established in an Establishment Action; or

(ii) established in one or more indentures supplemental hereto, prior to the issuance of Securities of any series.

Such Establishment Action or supplemental indenture shall provide:

(1) the title of the Securities of the series (which shall distinguish the Securities of the series from Securities of any other series) and a statement that the Securities will be offered pursuant to this Indenture;

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(2) any limit upon the aggregate principal amount of the Securities of the series which may be authenticated and delivered under this Indenture (except for Securities authenticated and delivered upon registration of transfer of, or in exchange for, or in lieu of, other Securities of the series pursuant to Section 3.04, 3.05, 3.06, 9.06 or 11.07 and except for any Securities which, pursuant to Section 3.03, are deemed never to have been authenticated and delivered hereunder) and the price (expressed as a percentage of the aggregate principal amount thereof) at which the Securities of the series will be issued;

(3) the Person to whom any interest on a Security of the series shall be payable, if other than the Person in whose name that Security (or one or more Predecessor Securities) is registered at the close of business on the Regular Record Date for such interest;

(4) the date or dates on which the principal of any Securities of the series is payable;

(5) the rate or rates at which any Securities of the series shall bear interest, if any, the date or dates from which any such interest shall accrue, the Interest Payment Dates on which any such interest shall be payable and the Regular Record Date for any such interest payable on any Interest Payment Date;

(6) the place or places where the principal of and/or any premium or interest on any Securities of the series shall be payable;

(7) the period or periods within which, the price or prices at which, the currency or currencies (including currency units) in which and the other terms and conditions upon which any Securities of the series may be redeemed, in whole or in part, at the option of the Company and, if other than by a Board Resolution, the manner in which any election by the Company to redeem the Securities shall be evidenced;

(8) the obligation, if any, of the Company to redeem or purchase any Securities of the series pursuant to any sinking fund or analogous provisions or at the option of the Holder thereof and the period or periods within which, the price or prices at which and the terms and conditions upon which any Securities of the series shall be redeemed or purchased, in whole or in part, pursuant to such obligation;

(9) if other than denominations of $1,000 and any integral multiple thereof, the denominations in which any Securities of the series shall be issuable;

(10) if the amount of principal of or any premium or interest on any Securities of the series may be determined with reference to an index, pursuant to a formula or other method, the manner in which such amounts shall be determined;

(11) if other than the currency of the United States of America, the currency, currencies or currency units in which the principal of or any premium or interest on any Securities of the series shall be payable and the manner of determining the equivalent thereof in the currency of the United States of America for any purpose, including for purposes of the definition of “Outstanding” in Section 1.01;

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(12) if the principal of or any premium or interest on any Securities of the series is to be payable, at the election of the Company or the Holder thereof, in one or more currencies or currency units other than that or those in which such Securities are stated to be payable, the currency, currencies or currency units in which the principal of or any premium or interest on such Securities as to which such election is made shall be payable, the periods within which and the terms and conditions upon which such election is to be made and the amount so payable (or the manner in which such amount shall be determined);

(13) if other than the entire principal amount thereof, the portion of the principal amount of any Securities of the series which shall be payable upon declaration of acceleration of the Maturity thereof pursuant to Section 5.02;

(14) if the principal amount payable at the Stated Maturity of any Securities of the series will not be determinable as of any one or more dates prior to the Stated Maturity, the amount which shall be deemed to be the principal amount of such Securities as of any such date for any purpose thereunder or hereunder, including the principal amount thereof which shall be due and payable upon any Maturity other than the Stated Maturity or which shall be deemed to be Outstanding as of any date prior to the Stated Maturity (or, in any such case, the manner in which such amount deemed to be the principal amount shall be determined);

(15) if applicable, that the Securities of the series, in whole or any specified part, shall be defeasible pursuant to Section 13.02 or Section 13.03 or both such Sections (or, if defeasible by another method, such other method) and, if other than by an action pursuant to a Board Resolution, the manner in which any election by the Company to defease such Securities shall be evidenced;

(16) if applicable, that any Securities of the series shall be issuable in whole or in part in the form of one or more Global Securities and, in such case, the respective Depositaries for such Global Securities, the form of any legend or legends which shall be borne by any such Global Security in addition to or in lieu of that set forth in Section 2.04 and any circumstances in addition to or in lieu of those set forth in clause (2) of the last paragraph of Section 3.05 in which any such Global Security may be exchanged in whole or in part for Securities registered, and any transfer of such Global Security in whole or in part may be registered, in the name or names of Persons other than the Depositary for such Global Security or a nominee thereof;

(17) any addition to or change in the Events of Default which applies to any Securities of the series and any change in the right of the Trustee or the requisite Holders of such Securities to declare the principal amount thereof due and payable pursuant to Section 5.02;

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(18) any addition to or change in the covenants set forth in Article X which applies to Securities of the series; and

(19) any other terms of the series (which terms shall not be inconsistent with the provisions of this Indenture, except as permitted by Section 9.01(5)).

All Securities of any one series shall be substantially identical except as to denomination and except as may otherwise be provided in the Establishment Action referred to above or in any indenture supplemental hereto. The Company shall provide to the Trustee a copy of any such Establishment Action.

SECTION 3.02 Denominations.

The Securities of each series shall be issuable only in registered form without coupons and only in such denominations as shall be specified as contemplated by Section 3.01. In the absence of any such specified denomination with respect to the Securities of any series, the Securities of such series shall be issuable in denominations of $1,000 and any integral multiple thereof.

SECTION 3.03 Execution, Authentication, Delivery and Dating.

The Securities shall be executed on behalf of the Company by its Chairman of the Board, any Vice Chairman of the Board, its President or one of its Vice Presidents, under its corporate seal reproduced thereon attested by its Treasurer or an Assistant Treasurer or its Secretary or one of its Assistant Secretaries. The signature of any of these officers on the Securities may be manual or facsimile. The seal of the Company may be in the form of a facsimile thereof and may be impressed, affixed, imprinted or otherwise reproduced on the Security.

Securities bearing the manual or facsimile signatures of individuals who were at any time the proper officers of the Company shall bind the Company, notwithstanding that such individuals or any of them have ceased to hold such offices prior to the authentication and delivery of such Securities or did not hold such offices at the date of such Securities.

At any time and from time to time after the execution and delivery of this Indenture, the Company may deliver Securities of any series executed by the Company to the Trustee for authentication, together with a Company Order for the authentication and delivery of such Securities, and the Trustee in accordance with the Company Order shall authenticate and deliver such Securities. If the form or terms of the Securities of the series have been established by one or more Establishment Actions as permitted by Sections 2.01 and 3.01, in authenticating such Securities, and accepting the additional responsibilities under this Indenture in relation to such Securities, the Trustee shall be entitled to receive, and (subject to Section 6.01) shall be fully protected in relying upon, an Opinion of Counsel stating:

(1) if the form of such Securities has been established by an Establishment Action as permitted by Section 2.01, that such form has been established in conformity with the provisions of this Indenture;

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(2) if the terms of such Securities have been established by an Establishment Action as permitted by Section 3.01, that such terms have been established in conformity with the provisions of this Indenture; and

(3) that such Securities, when authenticated and delivered by the Trustee and issued by the Company in the manner and subject to any conditions specified in such Opinion of Counsel, will constitute valid and legally binding obligations of the Company enforceable in accordance with their terms, subject to bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and similar laws of general applicability relating to or affecting creditors’ rights and to general equity principles.

If such form or terms have been so established, the Trustee shall not be required to authenticate such Securities if the issue of such Securities pursuant to this Indenture will affect the Trustee’s own rights, duties or immunities under the Securities and this Indenture or otherwise in a manner which is not reasonably acceptable to the Trustee.

Notwithstanding the provisions of Section 3.01 and of the preceding paragraph, if all Securities of a series are not to be originally issued at one time, it shall not be necessary to deliver the Establishment Action otherwise required pursuant to Section 3.01 or the Company Order and Opinion of Counsel otherwise required pursuant to such preceding paragraph at or prior to the authentication of each Security of such series if such documents are delivered at or prior to the authentication upon original issuance of the first Security of such series to be issued.

Each Security shall be dated the date of its authentication.

No Security shall be entitled to any benefit under this Indenture or be valid or obligatory for any purpose unless there appears on such Security a certificate of authentication substantially in the form provided for herein executed by the Trustee by manual signature, and such certificate upon any Security shall be conclusive evidence, and the only evidence, that such Security has been duly authenticated and delivered hereunder. Notwithstanding the foregoing, if any Security shall have been authenticated and delivered hereunder but never issued and sold by the Company, and the Company shall deliver such Security to the Trustee for cancellation as provided in Section 3.09, for all purposes of this Indenture such Security shall be deemed never to have been authenticated and delivered hereunder and shall never be entitled to the benefits of this Indenture.

SECTION 3.04 Temporary Securities.

Pending the preparation of definitive Securities of any series, the Company may execute, and upon Company Order the Trustee shall authenticate and deliver, temporary Securities which are printed, lithographed, typewritten, mimeographed or otherwise produced, in any authorized denomination, substantially of the tenor of the definitive Securities in lieu of which they are issued and with such appropriate insertions, omissions, substitutions and other variations as the officers executing such Securities may determine, as evidenced by their execution of such Securities.

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If temporary Securities of any series are issued, the Company will cause definitive Securities of that series to be prepared without unreasonable delay. After the preparation of definitive Securities of such series, the temporary Securities of such series shall be exchangeable for definitive Securities of such series upon surrender of the temporary Securities of such series at the office or agency of the Company in a Place of Payment for that series, without charge to the Holder. Upon surrender for cancellation of any one or more temporary Securities of any series, the Company shall execute and the Trustee shall authenticate and deliver in exchange therefor one or more definitive Securities of the same series, of any authorized denominations and of like tenor and aggregate principal amount. Until so exchanged, the temporary Securities of any series shall in all respects be entitled to the same benefits under this Indenture as definitive Securities of such series and tenor.

SECTION 3.05 Registration, Registration of Transfer and Exchange.

The Company shall cause to be kept in an office or agency of the Company in a Place of Payment a register (the register maintained in any such office or agency of the Company in a Place of Payment being herein sometimes collectively referred to as the “Security Register”) in which, subject to such reasonable regulations as it may prescribe, the Company shall provide for the registration of Securities and of transfers of Securities. The Trustee, or any other party serving in such capacity with the Trustee’s consent, is hereby appointed “Security Registrar” for the purpose of registering Securities and transfers of Securities as herein provided.

Upon surrender for registration of transfer of any Security of a series at the office or agency of the Company in a Place of Payment for that series, the Company shall execute, and the Trustee shall authenticate and deliver, in the name of the designated transferee or transferees, one or more new Securities of the same series, of any authorized denominations and of like tenor and aggregate principal amount.

At the option of the Holder, Securities of any series may be exchanged for other Securities of the same series, of any authorized denominations and of like tenor and aggregate principal amount, upon surrender of the Securities to be exchanged at such office or agency. Whenever any Securities are so surrendered for exchange, the Company shall execute, and the Trustee shall authenticate and deliver, the Securities which the Holder making the exchange is entitled to receive.

All Securities issued upon any registration of transfer or exchange of Securities shall be the valid obligations of the Company, evidencing the same debt, and entitled to the same benefits under this Indenture, as the Securities surrendered upon such registration of transfer or exchange.

Every Security presented or surrendered for registration of transfer or for exchange shall (if so required by the Company or the Trustee) be duly endorsed, or be accompanied by a written instrument of transfer in form satisfactory to the Company and the Security Registrar duly executed, by the Holder thereof or his attorney duly authorized in writing.

No service charge shall be made for any registration of transfer or exchange of Securities, but the Company may require payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in connection with any registration of transfer or exchange of Securities, other than exchanges pursuant to Section 3.04, 9.06 or 11.07 not involving any transfer.

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If the Securities of any series (or of any series and specified tenor) are to be redeemed in part, the Company shall not be required (A) to issue, register the transfer of or exchange any Securities of that series (or of that series and specified tenor, as the case may be) during a period beginning at the opening of business 15 days before the day of the mailing of a notice of redemption of any such Securities selected for redemption under Section 11.03 and ending at the close of business on the day of such mailing, or (B) to register the transfer of or exchange any Security so selected for redemption in whole or in part, except the unredeemed portion of any Security being redeemed in part.

The provisions of the following clauses shall apply only to Global Securities:

(1) Each Global Security authenticated under this Indenture shall be registered in the name of the Depositary designated for such Global Security or a nominee thereof and delivered to such Depositary or a nominee thereof or custodian therefor, and each such Global Security shall constitute a single Security for all purposes of this Indenture.

(2) Notwithstanding any other provision in this Indenture, no Global Security may be exchanged in whole or in part for Securities registered, and no transfer of a Global Security in whole or in part may be registered, in the name of any Person other than the Depositary for such Global Security or a nominee thereof unless:

(A) such Depositary

(i) has notified the Company that it is unwilling or unable to continue as Depositary for such Global Security or

(ii) has ceased to be a clearing agency registered under the Exchange Act;

(B) there shall have occurred and be continuing an Event of Default with respect to such Global Security; or

(C) there shall exist such circumstances, if any, in addition to or in lieu of the foregoing as have been specified for this purpose as contemplated by Section 3.01.

(3) Subject to clause (2) above, any exchange of a Global Security for other Securities may be made in whole or in part, and all Securities issued in exchange for a Global Security or any portion thereof shall be registered in such names as the Depositary for such Global Security shall direct.

(4) Every Security authenticated and delivered upon registration of transfer of, or in exchange for or in lieu of, a Global Security or any portion thereof, whether pursuant to this Section, Section 3.04, 3.06, 9.06 or 11.07 or otherwise, shall be

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authenticated and delivered in the form of, and shall be, a Global Security, unless such Security is registered in the name of a Person other than the Depositary for such Global Security or a nominee thereof.

SECTION 3.06 Mutilated, Destroyed, Lost and Stolen Securities.

If any mutilated Security is surrendered to the Trustee, the Company shall execute and the Trustee shall authenticate and deliver in exchange therefor a new Security of the same series and of like tenor and principal amount and bearing a number not contemporaneously outstanding.

If there shall be delivered to the Company and the Trustee (i) evidence to their satisfaction of the destruction, loss or theft of any Security and (ii) such security or indemnity as may be required by them to save each of them and any agent of either of them harmless, then, in the absence of notice to the Company or the Trustee that such Security has been acquired by a bona fide purchaser, the Company shall execute and the Trustee shall authenticate and deliver, in lieu of any such destroyed, lost or stolen Security, a new Security of the same series and of like tenor and principal amount and bearing a number not contemporaneously outstanding.

In case any such mutilated, destroyed, lost or stolen Security has become or is about to become due and payable, the Company in its discretion may, instead of issuing a new Security, pay such Security.

Upon the issuance of any new Security under this Section, the Company may require the payment of a sum sufficient to cover any tax or other governmental charge that may be imposed in relation thereto and any other expenses (including the fees and expenses of the Trustee) connected therewith.

Every new Security of any series issued pursuant to this Section in lieu of any destroyed, lost or stolen Security shall constitute an original additional contractual obligation of the Company, whether or not the destroyed, lost or stolen Security shall be at any time enforceable by anyone, and shall be entitled to all the benefits of this Indenture equally and proportionately with any and all other Securities of that series duly issued hereunder.

The provisions of this Section are exclusive and shall preclude (to the extent lawful) all other rights and remedies with respect to the replacement or payment of mutilated, destroyed, lost or stolen Securities.

SECTION 3.07 Payment of Interest; Interest Rights Preserved.

Except as otherwise provided as contemplated by Section 3.01 with respect to any series of Securities, interest on any Security which is payable, and is punctually paid or duly provided for, on any Interest Payment Date shall be paid to the Person in whose name that Security (or one or more Predecessor Securities) is registered at the close of business on the Regular Record Date for such interest.

Any interest on any Security of any series which is payable, but is not punctually paid or duly provided for, on any Interest Payment Date (herein called “Defaulted Interest”) shall

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forthwith cease to be payable to the Holder on the relevant Regular Record Date by virtue of having been such Holder, and such Defaulted Interest may be paid by the Company, at its election in each case, as provided in clause (1) or (2) below:

(1) The Company may elect to make payment of any Defaulted Interest to the Persons in whose names the Securities of such series (or their respective Predecessor Securities) are registered at the close of business on a Special Record Date for the payment of such Defaulted Interest, which shall be fixed in the following manner. The Company shall notify the Trustee in writing of the amount of Defaulted Interest proposed to be paid on each Security of such series and the date of the proposed payment, and at the same time the Company shall deposit with the Trustee an amount of money equal to the aggregate amount proposed to be paid in respect of such Defaulted Interest or shall make arrangements satisfactory to the Trustee for such deposit prior to the date of the proposed payment, such money when deposited to be held in trust for the benefit of the Persons entitled to such Defaulted Interest as in this clause provided. Thereupon, the Trustee shall fix a Special Record Date for the payment of such Defaulted Interest which shall be not more than 15 days and not less than 10 days prior to the date of the proposed payment and not less than 10 days after the receipt by the Trustee of the notice of the proposed payment. The Trustee shall promptly notify the Company of such Special Record Date and, in the name and at the expense of the Company, shall cause notice of the proposed payment of such Defaulted Interest and the Special Record Date therefor to be given to each Holder of Securities of such series in the manner set forth in Section 1.06, not less than 10 days prior to such Special Record Date. Notice of the proposed payment of such Defaulted Interest and the Special Record Date therefor having been so mailed, such Defaulted Interest shall be paid to the Persons in whose names the Securities of such series (or their respective Predecessor Securities) are registered at the close of business on such Special Record Date and shall no longer be payable pursuant to the following clause (2).

(2) The Company may make payment of any Defaulted Interest on the Securities of any series in any other lawful manner not inconsistent with the requirements of any securities exchange on which such Securities may be listed, and upon such notice as may be required by such exchange, if, after notice given by the Company to the Trustee of the proposed payment pursuant to this clause, such manner of payment shall be deemed practicable by the Trustee.

Subject to the foregoing provisions of this Section, each Security delivered under this Indenture upon registration of transfer of or in exchange for or in lieu of any other Security shall carry the rights to interest accrued and unpaid, and to accrue, which were carried by such other Security.

SECTION 3.08 Persons Deemed Owners.

Prior to due presentment of a Security for registration of transfer, the Company, the Trustee and any agent of the Company or the Trustee may treat the Person in whose name such

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Security is registered as the owner of such Security for the purpose of receiving payment of principal of and any premium and (subject to Section 3.07) any interest on such Security and for all other purposes whatsoever, whether or not such Security be overdue, and neither the Company, the Trustee nor any agent of the Company or the Trustee shall be affected by notice to the contrary.

SECTION 3.09 Cancellation.

All Securities surrendered for payment, redemption, registration of transfer or exchange or for credit against any sinking fund payment shall, if surrendered to any Person other than the Trustee, be delivered to the Trustee and shall be promptly cancelled by it. The Company may at any time deliver to the Trustee for cancellation any Securities previously authenticated and delivered hereunder which the Company may have acquired in any manner whatsoever, and may deliver to the Trustee (or to any other Person for delivery to the Trustee) for cancellation any Securities previously authenticated hereunder which the Company has not issued and sold, and all Securities so delivered shall be promptly cancelled by the Trustee. No Securities shall be authenticated in lieu of or in exchange for any Securities cancelled as provided in this Section, except as expressly permitted by this Indenture. Until directed otherwise by a Company Order, all cancelled Securities held by the Trustee shall be conspicuously marked as such and thereafter treated in accordance with the Trustee’s document retention policies; provided, however, if any cancelled Security is destroyed by the Trustee, the Trustee shall deliver to the Company a certificate with respect to such destruction.

SECTION 3.10 Computation of Interest.

Except as otherwise specified as contemplated by Section 3.01 for Securities of any series, interest on the Securities of each series shall be computed on the basis of a 360-day year of twelve 30-day months.

ARTICLE IV

SATISFACTION AND DISCHARGE

SECTION 4.01 Satisfaction and Discharge of Indenture.

This Indenture shall upon Company Request cease to be of further effect with respect to any (or all) series of Securities (except as to any surviving rights of registration of transfer or exchange of Securities herein expressly provided for), and the Trustee, at the expense of the Company, shall execute proper instruments acknowledging satisfaction and discharge of this Indenture with respect to such Securities, when:

(1) either

(A) all such Securities theretofore authenticated and delivered (other than

(i) Securities which have been destroyed, lost or stolen and which have been replaced or paid as provided in Section 3.06 and

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(ii) Securities for whose payment money has theretofore been deposited in trust or segregated and held in trust by the Company and thereafter repaid to the Company or discharged from such trust, as provided in Section 10.03)

have been delivered to the Trustee for cancellation; or

(B) all such Securities not theretofore delivered to the Trustee for cancellation

(i) have become due and payable, or

(ii) will become due and payable at their Stated Maturity within one year, or

(iii) are to be called for redemption within one year under arrangements reasonably satisfactory to the Trustee for the giving of notice of redemption by the Trustee in the name, and at the expense, of the Company,

and the Company, in the case of (i), (ii) or (iii) above, has deposited or caused to be deposited with the Trustee as trust funds in trust for the purpose money in an amount sufficient to pay and discharge the entire indebtedness on such Securities not theretofore delivered to the Trustee for cancellation, for principal and any premium and interest to the date of such deposit (in the case of Securities which have become due and payable) or to the Stated Maturity or Redemption Date, as the case may be;

(2) the Company has paid or caused to be paid all other sums payable hereunder by the Company; and

(3) the Company has delivered to the Trustee an Officers’ Certificate and an Opinion of Counsel, each stating that all conditions precedent herein provided for relating to the satisfaction and discharge of this Indenture with respect to such Securities have been complied with.

Notwithstanding the satisfaction and discharge of this Indenture, the obligations of the Company to the Trustee under Section 6.07, the obligations of the Trustee to any Authenticating Agent under Section 6.14 and, if money shall have been deposited with the Trustee pursuant to subclause (B) of clause (1) of this Section, the obligations of the Trustee under Section 4.02, Article VI and the last paragraph of Section 10.03 shall survive.

SECTION 4.02 Application of Trust Money.

Subject to the provisions of the last paragraph of Section 10.03, all money deposited with the Trustee pursuant to Section 4.01 shall be held in trust and applied by it, in accordance with the provisions of the Securities and this Indenture, to the payment, either directly or through any Paying Agent (including the Company acting as its own Paying Agent) as the Trustee may determine, to the Persons entitled thereto, of the principal and any premium and interest for whose payment such money has been deposited with the Trustee.

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ARTICLE V

REMEDIES

SECTION 5.01 Events of Default.

“Event of Default,” wherever used herein with respect to Securities of any series, means any one of the following events (whatever the reason for such Event of Default and whether it shall be voluntary or involuntary or be effected by operation of law or pursuant to any judgment, decree or order of any court or any order, rule or regulation of any administrative or governmental body):

(1) default in the payment of any interest upon any Security of that series when it becomes due and payable, and continuance of such default for a period of 30 days; or

(2) default in the payment of the principal of or any premium on any Security of that series at its Maturity; or

(3) default in the deposit of any sinking fund payment, when and as due by the terms of a Security of that series; or

(4) default in the performance, or breach, of any covenant or warranty of the Company in this Indenture (other than a covenant or warranty a default in whose performance or whose breach is elsewhere in this Section specifically dealt with or which has expressly been included in this Indenture solely for the benefit of series of Securities other than that series), and continuance of such default or breach for a period of 90 days after there has been given, by registered or certified mail, to the Company by the Trustee or to the Company and the Trustee by the Holders of at least 25% in principal amount of the Outstanding Securities of that series a written notice specifying such default or breach and requiring it to be remedied and stating that such notice is a “Notice of Default” hereunder; or

(5) the entry by a court having jurisdiction in the premises of a decree or order

(A) for relief in respect of the Company in an involuntary case or proceeding under any applicable Federal or State bankruptcy, insolvency, reorganization or other similar law;

(B) adjudging the Company a bankrupt or insolvent or approving as properly filed a petition seeking reorganization, arrangement, adjustment or composition of or in respect of the Company under any applicable Federal or State bankruptcy, insolvency, reorganization or other similar law;

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(C) appointing a custodian, receiver, liquidator, assignee, trustee, sequestrator or other similar official of the Company or of any substantial part of its property; or

(D) ordering the winding up or liquidation of its affairs, and the continuance of any such decree or order for relief or any such other decree or order unstayed and in effect for a period of 60 consecutive days;

or

(6)    (A)  the commencement by the Company of a voluntary case or proceeding under any applicable Federal or State bankruptcy, insolvency, reorganization or other similar law to be adjudicated a bankrupt or insolvent;

(B) the consent by the Company to the entry of a decree or order for relief in respect of it in an involuntary case or proceeding under any applicable Federal or State bankruptcy, insolvency, reorganization or other similar law or the consent by it to the commencement of any bankruptcy or insolvency case or proceeding against it;

(C) the filing by the Company of a petition or answer or consent seeking reorganization or relief under any applicable Federal or State bankruptcy, insolvency, reorganization or other similar law, or the consent by the Company to the filing of such petition;

(D) the consent by the Company to the appointment of or taking possession by a custodian, receiver, liquidator, assignee, trustee, sequestrator or other similar official of the Company or of any substantial part of its property;

(E) the making by the Company of an assignment for the benefit of creditors;

(F) the admission by the Company in writing of its inability to pay its debts generally as they become due; or

(G) the taking of corporate action by the Company in furtherance of any such action;

or

(7) any other Event of Default provided with respect to Securities of that series.

SECTION 5.02 Acceleration of Maturity; Rescission and Annulment.

If an Event of Default (other than an Event of Default specified in Section 5.01(5) or 5.01(6)) with respect to Securities of any series at the time Outstanding occurs and is continuing, then in every such case the Trustee or the Holders of not less than 25% in principal amount of the Outstanding Securities of that series may declare the principal amount of all the Securities of

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that series (or, if any Securities of that series are Original Issue Discount Securities, such portion of the principal amount of such Securities as may be specified by the terms thereof) to be due and payable immediately, by a notice in writing to the Company (and to the Trustee if given by Holders), and upon any such declaration such principal amount (or specified amount) shall become immediately due and payable. If an Event of Default specified in Section 5.01(5) or 5.01(6) with respect to Securities of any series at the time Outstanding occurs, the principal amount of all the Securities of that series (or, if any Securities of that series are Original Issue Discount Securities, such portion of the principal amount of such Securities as may be specified by the terms thereof) shall automatically, and without any declaration or other action on the part of the Trustee or any Holder, become immediately due and payable.

At any time after such a declaration of acceleration with respect to Securities of any series has been made and before a judgment or decree for payment of the money due has been obtained by the Trustee as hereinafter in this Article provided, the Holders of a majority in principal amount of the Outstanding Securities of that series, by written notice to the Company and the Trustee, may rescind and annul such declaration and its consequences if:

(1) the Company has paid or deposited with the Trustee a sum sufficient to pay

(A) all overdue interest on all Securities of that series,

(B) the principal of (and premium, if any, on) any Securities of that series which have become due otherwise than by such declaration of acceleration and any interest thereon at the rate or rates prescribed therefor in such Securities,

(C) to the extent that payment of such interest is lawful, interest upon overdue interest at the rate or rates prescribed therefor in such Securities, and

(D) all sums paid or advanced by the Trustee hereunder and the reasonable compensation, expenses, disbursements and advances of the Trustee, its agents and counsel;

and

(2) all Events of Default with respect to Securities of that series, other than the non-payment of the principal of Securities of that series which have become due solely by such declaration of acceleration, have been cured or waived as provided in Section 5.13.

No such rescission shall affect any subsequent default or impair any right consequent thereon.

SECTION 5.03 Collection of Indebtedness and Suits for Enforcement by Trustee.

The Company covenants that if

(1) default is made in the payment of any interest on any Security when such interest becomes due and payable and such default continues for a period of 30 days, or

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(2) default is made in the payment of the principal of (or premium, if any, on) any Security at the Maturity thereof,

the Company will, upon demand of the Trustee, pay to it, for the benefit of the Holders of such Securities, the whole amount then due and payable on such Securities for principal and any premium and interest and, to the extent that payment of such interest shall be legally enforceable, interest on any overdue principal and premium and on any overdue interest, at the rate or rates (or yield to maturity in the case of Original Issue Discount Securities) prescribed therefor in such Securities, and, in addition thereto, such further amount as shall be sufficient to cover the costs and expenses of collection, including the reasonable compensation, expenses, disbursements and advances of the Trustee, its agents and counsel, except as a result of the Trustee’s negligence or bad faith.

If an Event of Default with respect to Securities of any series occurs and is continuing, the Trustee may in its discretion proceed to protect and enforce its rights and the rights of the Holders of Securities of such series by such appropriate judicial proceedings as the Trustee shall deem most effectual to protect and enforce any such rights, whether for the specific enforcement of any covenant or agreement in this Indenture or in aid of the exercise of any power granted herein, or to enforce any other proper remedy.

SECTION 5.04 Trustee May File Proofs of Claim.

In case of any judicial proceeding relative to the Company (or any other obligor upon the Securities), its property or its creditors, the Trustee shall be entitled and empowered, by intervention in such proceeding or otherwise, to take any and all actions authorized under the Trust Indenture Act in order to have claims of the Holders and the Trustee allowed in any such proceeding. In particular, the Trustee shall be authorized to collect and receive any moneys or other property payable or deliverable on any such claims and to distribute the same; and any custodian, receiver, assignee, trustee, liquidator, sequestrator or other similar official in any such judicial proceeding is hereby authorized by each Holder to make such payments to the Trustee and, in the event that the Trustee shall consent to the making of such payments directly to the Holders, to pay to the Trustee any amount due it for the reasonable compensation, expenses, disbursements and advances of the Trustee, its agents and counsel, and any other amounts due the Trustee under Section 6.07 except as a result of its negligence or bad faith.

No provision of this Indenture shall be deemed to authorize the Trustee to authorize or consent to or accept or adopt on behalf of any Holder any plan of reorganization, arrangement, adjustment or composition affecting the Securities or the rights of any Holder thereof or to authorize the Trustee to vote in respect of the claim of any Holder in any such proceeding; provided, however, that the Trustee may, on behalf of the Holders, vote for the election of a trustee in bankruptcy or similar official and be a member of a creditors’ or other similar committee.

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SECTION 5.05 Trustee May Enforce Claims Without Possession of Securities.

All rights of action and claims under this Indenture or the Securities may be prosecuted and enforced by the Trustee without the possession of any of the Securities or the production thereof in any proceeding relating thereto, and any such proceeding instituted by the Trustee shall be brought in its own name as trustee of an express trust, and any recovery of judgment shall, after provision for the payment of the reasonable compensation, expenses, disbursements and advances of the Trustee, its agents and counsel (except no such provision shall be made respecting compensation, expenses, disbursements and advances made as a result of Trustee’s negligence), be for the ratable benefit of the Holders of the Securities in respect of which such judgment has been recovered.

SECTION 5.06 Application of Money Collected.

Any money collected by the Trustee pursuant to this Article shall be applied in the following order, at the date or dates fixed by the Trustee and, in case of the distribution of such money on account of principal or any premium or interest, upon presentation of the Securities and the notation thereon of the payment if only partially paid and upon surrender thereof if fully paid:

FIRST: To the payment of costs and expenses of collection, reasonable compensation to the Trustee, its agents, attorneys and counsel, and all other expenses and liabilities incurred, and all advances made, by the Trustee except as a result of its negligence or bad faith.

SECOND: In case the principal of the outstanding Securities of any series in respect of which such moneys have been collected shall not have become due, to the payment of interest on the Securities of such series, in the order of maturity of the installments of such interest, with interest (to the extent that such interest has been collected by the Trustee) upon the overdue installments of interest at the same rate or the yield to maturity (in the case of Original Issue Discount Securities) specified on the Securities of such series, such payments to be made ratably to the persons entitled thereto, without discrimination or preference.

THIRD: In case the principal of the outstanding Securities of any series in respect of which such moneys have been collected shall have become due, by declaration, or otherwise, to the payment of the whole amount then owing and unpaid upon the Securities of such series for principal, premium (if any) and interest, with interest upon the overdue principal, premium (if any) and (to the extent that such interest has been collected by the Trustee) upon overdue installments of interest at the same rate or the yield to maturity (in the case of Original Issue Discount Securities) specified on the Securities of such series; and in case such moneys shall be insufficient to pay in full the whole amount so due and unpaid upon the Securities of such series, then to the payment of such principal, premium (if any) and interest, without preference or priority of principal and premium (if any), or of any installment of interest over any other installment of interest, or of any Security of such series over any other Security of such series, ratably to the aggregate of such principal and accrued and unpaid interest.

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SECTION 5.07 Limitation on Suits.

No Holder of any Security of any series shall have any right to institute any proceeding, judicial or otherwise, with respect to this Indenture, or for the appointment of a receiver or trustee, or for any other remedy hereunder, unless:

(1) such Holder has previously given written notice to the Trustee of a continuing Event of Default with respect to the Securities of that series;

(2) The Holders of not less than 25% in principal amount of the Outstanding Securities of that series shall have made written request to the Trustee to institute proceedings in respect of such Event of Default in its own name as Trustee hereunder;

(3) such Holder or Holders have offered to the Trustee reasonable indemnity against the costs, expenses and liabilities to be incurred in compliance with such request;

(4) the Trustee for 60 days after its receipt of such notice, request and offer of indemnity has failed to institute any such proceeding; and

(5) no direction inconsistent with such written request has been given to the Trustee during such 60-day period by the Holders of a majority in principal amount of the Outstanding Securities of that series;

it being understood and intended that no one or more of such Holders shall have any right in any manner whatever by virtue of, or by availing of, any provision of this Indenture to affect, disturb or prejudice the rights of any other of such Holders, or to obtain or to seek to obtain priority or preference over any other of such Holders or to enforce any right under this Indenture, except in the manner herein provided and for the equal and ratable benefit of all of such Holders.

SECTION 5.08 Unconditional Right of Holders to Receive Principal, Premium and Interest.

Notwithstanding any other provision in this Indenture, the Holder of any Security shall have the right, which is absolute and unconditional, to receive payment of the principal of and any premium and (subject to Section 3.07) interest on such Security on the respective Stated Maturities expressed in such Security (or, in the case of redemption, on the Redemption Date) and to institute suit for the enforcement of any such payment, and such rights shall not be impaired without the consent of such Holder.

SECTION 5.09 Restoration of Rights and Remedies.

If the Trustee or any Holder has instituted any proceeding to enforce any right or remedy under this Indenture and such proceeding has been discontinued or abandoned for any reason, or has been determined adversely to the Trustee or to such Holder, then and in every such case, subject to any determination in such proceeding, the Company, the Trustee and the Holders shall be restored severally and respectively to their former positions hereunder and thereafter all rights and remedies of the Trustee and the Holders shall continue as though no such proceeding had been instituted.

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SECTION 5.10 Rights and Remedies Cumulative.

Except as otherwise provided with respect to the replacement or payment of mutilated, destroyed, lost or stolen Securities in the last paragraph of Section 3.06, no right or remedy herein conferred upon or reserved to the Trustee or to the Holders is intended to be exclusive of any other right or remedy, and every right and remedy shall, to the extent permitted by law, be cumulative and in addition to every other right and remedy given hereunder or now or hereafter existing at law or in equity or otherwise. The assertion or employment of any right or remedy hereunder, or otherwise, shall not prevent the concurrent assertion or employment of any other appropriate right or remedy.

SECTION 5.11 Delay or Omission Not Waiver.

No delay or omission of the Trustee or of any Holder of any Securities to exercise any right or remedy accruing upon any Event of Default shall impair any such right or remedy or constitute a waiver of any such Event of Default or an acquiescence therein. Every right and remedy given by this Article or by law to the Trustee or to the Holders may be exercised from time to time, and as often as may be deemed expedient, by the Trustee or by the Holders, as the case may be.

SECTION 5.12 Control by Holders.

The Holders of a majority in principal amount of the Outstanding Securities of any series shall have the right to direct the time, method and place of conducting any proceeding for any remedy available to the Trustee, or exercising any trust or power conferred on the Trustee, with respect to the Securities of such series, provided that:

(1) such direction shall not be in conflict with any rule of law or with this Indenture; and

(2) the Trustee may take any other action deemed proper by the Trustee which is not inconsistent with such direction.

SECTION 5.13 Waiver of Past Defaults.

The Holders of not less than a majority in principal amount of the Outstanding Securities of any series may on behalf of the Holders of all the Securities of such series waive any past default hereunder with respect to such series and its consequences, except a default:

(1) in the payment of the principal of or any premium or interest on any Security of such series; or

(2) in respect of a covenant or provision hereof which under Article IX cannot be modified or amended without the consent of the Holder of each Outstanding Security of such series affected.

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Upon any such waiver, such default shall cease to exist, and any Event of Default arising therefrom shall be deemed to have been cured, for every purpose of this Indenture; but no such waiver shall extend to any subsequent or other default or impair any right consequent thereon.

SECTION 5.14 Undertaking for Costs.

In any suit for the enforcement of any right or remedy under this Indenture, or in any suit against the Trustee for any action taken, suffered or omitted by it as Trustee, a court may require any party litigant in such suit to file an undertaking to pay the costs of such suit, and may assess costs against any such party litigant, in the manner and to the extent provided in the Trust Indenture Act; provided that neither this Section nor the Trust Indenture Act shall be deemed to authorize any court to require such an undertaking or to make such an assessment in any suit instituted by the Company.

SECTION 5.15 Waiver of Usury, Stay or Extension Laws.

The Company covenants (to the extent that it may lawfully do so) that it will not at any time insist upon, or plead, or in any manner whatsoever claim or take the benefit or advantage of, any usury, stay or extension law wherever enacted, now or at any time hereafter in force, which may affect the covenants or the performance of this Indenture; and the Company (to the extent that it may lawfully do so) hereby expressly waives all benefit or advantage of any such law and covenants that it will not hinder, delay or impede the execution of any power herein granted to the Trustee, but will suffer and permit the execution of every such power as though no such law had been enacted.

ARTICLE VI

THE TRUSTEE

SECTION 6.01 Certain Duties and Responsibilities.

The duties and responsibilities of the Trustee shall be as provided by the Trust Indenture Act. Notwithstanding the foregoing, no provision of this Indenture shall require the Trustee to expend or risk its own funds or otherwise incur any financial liability in the performance of any of its duties hereunder, or in the exercise of any of its rights or powers, if it shall have reasonable grounds for believing that repayment of such funds or adequate indemnity against such risk or liability is not reasonably assured to it. Whether or not therein expressly so provided, every provision of this Indenture relating to the conduct or affecting the liability of or affording protection to the Trustee shall be subject to the provisions of this Section.

SECTION 6.02 Notice of Defaults.

If a default occurs hereunder with respect to Securities of any series, the Trustee shall give the Holders of Securities of such series notice of such default as and to the extent provided by the Trust Indenture Act; provided, however, that in the case of any default of the character specified in Section 5.01(4) with respect to Securities of such series, no such notice to Holders shall be given until at least 60 days after the occurrence thereof. For the purpose of this Section, the term “default” means any event or events, as the case may be, specified in Section 5.01, not including periods of grace, if any, provided for therein.

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SECTION 6.03 Certain Rights of Trustee.

Subject to the provisions of Section 6.01:

(1) the Trustee may rely and shall be protected in acting or refraining from acting upon any resolution, action, certificate, statement, instrument, opinion, report, notice, request, direction, consent, order, bond, debenture, note, other evidence of indebtedness or other paper or document believed by it to be genuine and to have been signed or presented by the proper party or parties;

(2) any request or direction of the Company mentioned herein shall be sufficiently evidenced by a Company Request or Company Order, and any resolution of the Board of Directors or Establishment Action may be sufficiently evidenced by a Board Resolution or Establishment Action, as the case may be;

(3) whenever in the administration of this Indenture the Trustee shall deem it desirable that a matter be proved or established prior to taking, suffering or omitting any action hereunder, the Trustee (unless other evidence be herein specifically prescribed) may, in the absence of bad faith on its part, rely upon an Officers’ Certificate;

(4) the Trustee may consult with counsel, and the written advice of such counsel or any Opinion of Counsel shall be full and complete authorization and protection in respect of any action taken, suffered or omitted by it hereunder in good faith and in reliance thereon;

(5) the Trustee shall be under no obligation to exercise any of the rights or powers vested in it by this Indenture at the request or direction of any of the Holders pursuant to this Indenture, unless such Holders shall have offered to the Trustee reasonable security or indemnity against the costs, expenses and liabilities which might be incurred by it in compliance with such request or direction;

(6) the Trustee shall not be bound to make any investigation into the facts or matters stated in any resolution, action, certificate, statement, instrument, opinion, report, notice, request, direction, consent, order, bond, debenture, note, other evidence of indebtedness or other paper or document, but the Trustee, in its discretion, may make such further inquiry or investigation into such facts or matters as it may see fit, and, if the Trustee shall determine to make such further inquiry or investigation, it shall be entitled to examine the books, records and premises of the Company, personally or by agent or attorney;

(7) the Trustee may execute any of the trusts or powers hereunder or perform any duties hereunder either directly or by or through agents or attorneys, and the Trustee shall not be responsible for any misconduct or negligence on the part of any agent or attorney appointed with due care by it hereunder;

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(8) the Trustee shall not be liable for any action taken by it in good faith and believed by it to be authorized or within the discretion or rights or powers conferred upon it by this Indenture; and

(9) the Trustee is not required to take notice or deemed to have notice of any default or Event of Default hereunder, except any Event of Default under Section 5.01(1), (2) or (3), unless a Responsible Officer of the Trustee has actual knowledge thereof or has received notice in writing of such default or Event of Default from the Company or the Holders of at least 25% in aggregate principal amount of the Outstanding Securities, and, in the absence of any such notice, the Trustee may conclusively assume that no such default or Event of Default exists.

SECTION 6.04 Not Responsible for Recitals or Issuance of Securities.

The recitals contained herein and in the Securities, except the Trustee’s certificates of authentication, shall be taken as the statements of the Company, and neither the Trustee nor any Authenticating Agent assumes any responsibility for their correctness. The Trustee makes no representations as to the validity or sufficiency of this Indenture or of the Securities. Neither the Trustee nor any Authenticating Agent shall be accountable for the use or application by the Company of Securities or the proceeds thereof.

SECTION 6.05 May Hold Securities.

The Trustee, any Authenticating Agent, any Paying Agent, any Security Registrar or any other agent of the Company, in its individual or any other capacity, may become the owner or pledgee of Securities and, subject to 6.08 and 6.13, may otherwise deal with the Company with the same rights it would have if it were not Trustee, Authenticating Agent, Paying Agent, Security Registrar or such other agent.

SECTION 6.06 Money Held in Trust.

Money held by the Trustee, or any Paying Agent, in trust hereunder need not be segregated from other funds except to the extent required by law. Neither the Trustee nor any Paying Agent shall be under any liability for interest on any money received by it hereunder except as otherwise agreed in writing with the Company.

SECTION 6.07 Compensation, Reimbursement and Indemnification.

The Company agrees:

(1) to pay to the Trustee from time to time reasonable compensation as shall be agreed in writing between the Company and the Trustee for all services rendered by it hereunder (which compensation shall not be limited by any provision of law in regard to the compensation of a trustee of an express trust);

(2) except as otherwise expressly provided herein, to reimburse the Trustee upon its request for all reasonable expenses, disbursements and advances incurred or made by the Trustee in accordance with any provision of this Indenture (including the

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reasonable compensation and the expenses and disbursements of its agents and counsel), except any such expense, disbursement or advance as may be attributable to its negligence or bad faith; and

(3) to indemnify the Trustee for, and to hold it harmless against, any loss, liability or expense incurred without negligence or bad faith on its part, arising out of or in connection with the acceptance or administration of the trust or trusts hereunder, including the costs and expenses of defending itself against any claim or liability in connection with the exercise or performance of any of its powers or duties hereunder and the costs and expenses of enforcing this right to indemnification.

In the event any action, suit or proceeding is brought against any Trustee in connection with any claim for which it is entitled to indemnity hereunder, it shall promptly (but no later than ten days following service) notify the Company in writing, enclosing a copy of all papers served. All counsel employed to defend any such claim shall be retained directly by the Company and may serve as counsel to the Company and/or one or more Trustees. Absent a conflict of interest, the Company shall not be required to pay the fees and expenses of more than one law firm in connection with its obligations hereunder. A Trustee entitled to indemnification may, in addition to counsel engaged by the Company, engage counsel to represent such Trustee at its sole expense. Notwithstanding any other provision of this Indenture, the Company shall not be liable to pay any settlement agreed to without its written consent.

In the event the Trustee incurs expenses or renders services in any proceedings which result from the occurrence or continuance of an Event of Default under Section 5.01(5) or 5.01(6) hereof, or from the occurrence of any event which, solely by virtue of the passage of time, would become such an Event of Default, the expenses so incurred and compensation for services so rendered are intended to constitute expenses of administration under the United States Bankruptcy Code or equivalent law.

SECTION 6.08 Conflicting Interests.

If the Trustee has or shall acquire a conflicting interest within the meaning of the Trust Indenture Act, the Trustee shall either eliminate such interest or resign, to the extent and in the manner provided by, and subject to the provisions of, the Trust Indenture Act and this Indenture. To the extent permitted by such Act, the Trustee shall not be deemed to have a conflicting interest by virtue of being a trustee under this Indenture with respect to Securities of more than one series or a trustee under the indenture dated February 26, 2002 between the Company and the Trustee respecting debt of the Company which is subordinated in right of payment to debt issued pursuant to this Indenture.

SECTION 6.09 Corporate Trustee Required; Eligibility.

There shall at all times be one (and only one) Trustee hereunder with respect to the Securities of each series, which may be Trustee hereunder for Securities of one or more other series. Each Trustee shall be a Person that is eligible pursuant to the Trust Indenture Act to act as such and has a combined capital and surplus of at least $50,000,000. If any such Person publishes reports of condition at least annually, pursuant to law or to the requirements of its

39

supervising or examining authority, then for the purposes of this Section and to the extent permitted by the Trust Indenture Act, the combined capital and surplus of such Person shall be deemed to be its combined capital and surplus as set forth in its most recent report of condition so published. If at any time the Trustee with respect to the Securities of any series shall cease to be eligible in accordance with the provisions of this Section, it shall resign immediately in the manner and with the effect hereinafter specified in this Article.

SECTION 6.10 Resignation and Removal; Appointment of Successor.

(a) No resignation or removal of the Trustee and no appointment of a successor Trustee pursuant to this Article shall become effective until the acceptance of appointment by the successor Trustee in accordance with the applicable requirements of Section 6.11.

(b) The Trustee may resign at any time with respect to the Securities of one or more series by giving written notice thereof to the Company. If the instrument of acceptance by a successor Trustee required by Section 6.11 shall not have been delivered to the Trustee within 30 days after the giving of such notice of resignation, the resigning Trustee may petition any court of competent jurisdiction for the appointment of a successor Trustee with respect to the Securities of such series.

(c) The Trustee may be removed at any time with respect to the Securities of any series by Act of the Holders of a majority in principal amount of the Outstanding Securities of such series, delivered to the Trustee and to the Company. If the instrument of acceptance by a successor Trustee required by Section 6.11 shall not have been delivered to the Trustee within 30 days after the giving of such notice of removal, the Trustee being removed may petition any court of competent jurisdiction for the appointment of a successor Trustee with respect to the Securities of such series.

(d) If, at any time,

(1) the Trustee shall fail to comply with Section 6.08 after written request therefor by the Company or by any Holder who has been a bona fide Holder of a Security for at least six months, or

(2) the Trustee shall cease to be eligible under Section 6.09 and shall fail to resign after written request therefor by the Company or by any such Holder, or

(3) the Trustee shall become incapable of acting or shall be adjudged a bankrupt or insolvent or a receiver of the Trustee or of its property shall be appointed or any public officer shall take charge or control of the Trustee or of its property or affairs for the purpose of rehabilitation, conservation or liquidation,

then, in any such case,

(A) the Company by a Board Resolution may remove the Trustee with respect to all Securities, or

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(B) subject to Section 5.14, any Holder who has been a bona fide Holder of a Security for at least six months may, on behalf of himself and all others similarly situated, petition any court of competent jurisdiction for the removal of the Trustee with respect to all Securities and the appointment of a successor Trustee or Trustees.

(e) If the Trustee shall resign, be removed or become incapable of acting, or if a vacancy shall occur in the office of Trustee for any cause, with respect to the Securities of one or more series, the Company, by a Board Resolution, shall promptly appoint a successor Trustee or Trustees with respect to the Securities of that or those series (it being understood that any such successor Trustee may be appointed with respect to the Securities of one or more or all of such series and that at any time there shall be only one Trustee with respect to the Securities of any particular series) and shall comply with the applicable requirements of Section 6.11. If, within one year after such resignation, removal or incapability, or the occurrence of such vacancy, a successor Trustee with respect to the Securities of any series shall be appointed by Act of the Holders of a majority in principal amount of the Outstanding Securities of such series delivered to the Company and the retiring Trustee, the successor Trustee so appointed shall, forthwith upon its acceptance of such appointment in accordance with the applicable requirements of Section 6.11, become the successor Trustee with respect to the Securities of such series and to that extent supersede the successor Trustee appointed by the Company. If no successor Trustee with respect to the Securities of any series shall have been so appointed by the Company or the Holders and accepted appointment in the manner required by Section 6.11, any Holder who has been a bona fide Holder of a Security of such series for at least six months may, on behalf of himself and all others similarly situated, petition any court of competent jurisdiction for the appointment of a successor Trustee with respect to the Securities of such series.

(f) The Company shall give notice of each resignation and each removal of the Trustee with respect to the Securities of any series and each appointment of a successor Trustee with respect to the Securities of any series to all Holders of Securities of such series in the manner provided in Section 1.06. Each notice shall include the name of the successor Trustee with respect to the Securities of such series and the address of its Corporate Trust Office.

SECTION 6.11 Acceptance of Appointment by Successor.

In case of the appointment hereunder of a successor Trustee with respect to all Securities, every such successor Trustee so appointed shall execute, acknowledge and deliver to the Company and to the retiring Trustee an instrument accepting such appointment, and thereupon the resignation or removal of the retiring Trustee shall become effective and such successor Trustee, without any further act, deed or conveyance, shall become vested with all the rights, powers, trusts and duties of the retiring Trustee; but, on the request of the Company or the successor Trustee, such retiring Trustee shall, upon payment of its charges, execute and deliver an instrument transferring to such successor Trustee all the rights, powers and trusts of the retiring Trustee and shall duly assign, transfer and deliver to such successor Trustee all property and money held by such retiring Trustee hereunder.

In case of the appointment hereunder of a successor Trustee with respect to the Securities of one or more (but not all) series, the Company, the retiring Trustee and each successor Trustee

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with respect to the Securities of one or more series shall execute and deliver an indenture supplemental hereto wherein each successor Trustee shall accept such appointment and which (i) shall contain such provisions as shall be necessary or desirable to transfer and confirm to, and to vest in, each successor Trustee all the rights, powers, trusts and duties of the retiring Trustee with respect to the Securities of that or those series to which the appointment of such successor Trustee relates, (ii) if the retiring Trustee is not retiring with respect to all Securities, shall contain such provisions as shall be deemed necessary or desirable to confirm that all the rights, powers, trusts and duties of the retiring Trustee with respect to the Securities of that or those series as to which the retiring Trustee is not retiring shall continue to be vested in the retiring Trustee, and (iii) shall add to or change any of the provisions of this Indenture as shall be necessary to provide for or facilitate the administration of the trusts hereunder by more than one Trustee, it being understood that nothing herein or in such supplemental indenture shall constitute such Trustees co-trustees of the same trust and that each such Trustee shall be trustee of a trust or trusts hereunder separate and apart from any trust or trusts hereunder administered by any other such Trustee; and, upon the execution and delivery of such supplemental indenture, the resignation or removal of the retiring Trustee shall become effective to the extent provided therein and each such successor Trustee, without any further act, deed or conveyance, shall become vested with all the rights, powers, trusts and duties of the retiring Trustee with respect to the Securities of that or those series to which the appointment of such successor Trustee relates; but, on request of the Company or any successor Trustee, such retiring Trustee shall duly assign, transfer and deliver to such successor Trustee all property and money held by such retiring Trustee hereunder with respect to the Securities of that or those series to which the appointment of such successor Trustee relates.

Upon request of any such successor Trustee, the Company shall execute any and all instruments for more fully and certainly vesting in and confirming to such successor Trustee all such rights, powers and trusts referred to in the first or second preceding paragraph, as the case may be.

No successor Trustee shall accept its appointment unless at the time of such acceptance such successor Trustee shall be qualified and eligible under this Article.

SECTION 6.12 Merger, Conversion, Consolidation or Succession to Business.

Any corporation into which the Trustee may be merged or converted or with which it may be consolidated, or any corporation resulting from any merger, conversion or consolidation to which the Trustee shall be a party, or any corporation succeeding to all or substantially all the corporate trust business of the Trustee, shall be the successor of the Trustee hereunder, provided such corporation shall be otherwise qualified and eligible under this Article, without the execution or filing of any paper or any further act on the part of any of the parties hereto. In case any Securities shall have been authenticated, but not delivered, by the Trustee then in office, any successor by merger, conversion or consolidation to such authenticating Trustee may adopt such authentication and deliver the Securities so authenticated with the same effect as if such successor Trustee had itself authenticated such Securities.

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SECTION 6.13 Preferential Collection of Claims Against Company.

If and when the Trustee shall be or become a creditor of the Company (or any other obligor upon the Securities), the Trustee shall be subject to the provisions of the Trust Indenture Act regarding the collection of claims against the Company (or any such other obligor).

SECTION 6.14 Appointment of Authenticating Agent.

The Trustee may appoint an Authenticating Agent or Agents with respect to one or more series of Securities which shall be authorized to act on behalf of the Trustee to authenticate Securities of such series issued upon original issue and upon exchange, registration of transfer or partial redemption thereof or pursuant to Section 3.06, and Securities so authenticated shall be entitled to the benefits of this Indenture and shall be valid and obligatory for all purposes as if authenticated by the Trustee hereunder. Wherever reference is made in this Indenture to the authentication and delivery of Securities by the Trustee or the Trustee’s certificate of authentication, such reference shall be deemed to include authentication and delivery on behalf of the Trustee by an Authenticating Agent and a certificate of authentication executed on behalf of the Trustee by an Authenticating Agent. Each Authenticating Agent must be acceptable to the Company and shall at all times be a corporation organized and doing business under the laws of the United States of America, any State thereof or the District of Columbia, authorized under such laws to act as Authenticating Agent, having a combined capital and surplus of not less than $50,000,000 and subject to supervision or examination by Federal or State authority. If such Authenticating Agent publishes reports of condition at least annually, pursuant to law or to the requirements of said supervising or examining authority, then for the purposes of this Section, the combined capital and surplus of such Authenticating Agent shall be deemed to be its combined capital and surplus as set forth in its most recent report of condition so published. If at any time an Authenticating Agent shall cease to be eligible in accordance with the provisions of this Section, such Authenticating Agent shall resign immediately in the manner and with the effect specified in this Section.

Any corporation into which an Authenticating Agent may be merged or converted or with which it may be consolidated, or any corporation resulting from any merger, conversion or consolidation to which such Authenticating Agent shall be a party, or any corporation succeeding to all or substantially all of the corporate agency or corporate trust business of an Authenticating Agent, shall continue to be an Authenticating Agent, provided such corporation shall be otherwise eligible under this Section, without the execution or filing of any paper or any further act on the part of the Trustee or the Authenticating Agent.

In case at the time such successor to any Authenticating Agent with respect to any series shall succeed to such Authenticating Agent, any of the Securities of such series shall have been authenticated but not delivered, any such successor to such Authenticating Agent may adopt the certificate of authentication of any predecessor Authenticating Agent and deliver such Securities so authenticated; and in case at that time any of the Securities of such series shall not have been authenticated, any successor to any Authenticating Agent may authenticate such Securities either in the name of any predecessor hereunder or in the name of successor Authenticating Agent; and in all such cases such certificate shall have the full force which it is anywhere in the Securities of such series or in this Indenture provided that the certificate of the predecessor Authenticating

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Agent shall have; provided, however, that the right to adopt the certificate of authentication of any predecessor Authenticating Agent or to authenticate Securities in the name of any predecessor Authenticating Agent shall apply only to its successor or successors by merger, conversion or consolidation.

An Authenticating Agent may resign at any time by giving written notice thereof to the Trustee and to the Company. The Trustee may at any time terminate the agency of an Authenticating Agent by giving written notice thereof to such Authenticating Agent and to the Company. Upon receiving such a notice of resignation or upon such a termination, or in case at any time such Authenticating Agent shall cease to be eligible in accordance with the provisions of this Section, the Trustee may appoint a successor Authenticating Agent which must be acceptable to the Company and shall give notice of such appointment in the manner provided in Section 1.06 to all Holders of Securities of the series with respect to which such Authenticating Agent will serve. Any successor Authenticating Agent upon acceptance of its appointment hereunder shall become vested with all the rights, powers and duties of its predecessor hereunder, with like effect as if originally named as an Authenticating Agent. No successor Authenticating Agent shall be appointed unless eligible under the provisions of this Section.

Any Authenticating Agent by the acceptance of its appointment shall be deemed to have agreed with the Trustee that: it will perform and carry out the duties of an Authenticating Agent as herein set forth; it will keep and maintain and furnish to the Trustee from time to time as requested by the Trustee appropriate records of all transactions carried out by it as Authenticating Agent and will furnish the Trustee such other information and reports as the Trustee may reasonably require; it is eligible for appointment as Authenticating Agent under this Section 6.14 and will notify the Trustee promptly if it shall cease to be so qualified; and it will indemnify the Trustee against any loss, liability or expense incurred by the Trustee and will defend any claim asserted against the Trustee by reason of acts or failures to act of the Authenticating Agent but it shall have no liability for any action taken by it at the specific written direction of the Trustee.

The Trustee agrees to pay to each Authenticating Agent from time to time reasonable compensation for its services under this Section, and the Trustee shall be entitled to be reimbursed for such payments, subject to the provisions of Section 6.07.

If an appointment with respect to one or more series is made pursuant to this Section, the Securities of such series may have endorsed thereon, in addition to the Trustee’s certificate of authentication, an alternative certificate of authentication in the following form:

This is one of the Securities of the series designated therein referred to in the within-mentioned Indenture.

JPMORGAN CHASE BANK, As Trustee
By
	As Authenticating Agent

By
	Authorized Officer

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ARTICLE VII

HOLDERS’ LISTS AND REPORTS BY TRUSTEE AND COMPANY

SECTION 7.01 Company to Furnish Trustee Names and Addresses of Holders.

The Company will furnish or cause to be furnished to the Trustee:

(1) semi-annually, not later than June 30 and December 31 in each year, a list, in such form as the Trustee may reasonably require, of the names and addresses of the Holders of Securities of each series as of a date no more than 15 days prior to the date such list is furnished; and

(2) at such other times as the Trustee may request in writing, within 30 days after the receipt by the Company of any such request, a list of similar form and content as of a date not more than 15 days prior to the time such list is furnished;

excluding from any such list names and addresses received by the Trustee in its capacity as Security Registrar.

SECTION 7.02 Preservation of Information; Communications to Holders.

The Trustee shall preserve, in as current a form as is reasonably practicable, the names and addresses of Holders contained in the most recent list furnished to the Trustee as provided in Section 7.01 and the names and addresses of Holders received by the Trustee, or its designee, in its capacity as Security Registrar. The Trustee may destroy any list furnished to it as provided in Section 7.01 upon receipt of a new list so furnished.

The rights of Holders to communicate with other Holders with respect to their rights under this Indenture or under the Securities, and the corresponding rights and privileges of the Trustee, shall be as provided by the Trust Indenture Act.

Every Holder of Securities, by receiving and holding the same, agrees with the Company and the Trustee that neither the Company nor the Trustee nor any agent of either of them shall be held accountable by reason of any disclosure of information as to names and addresses of Holders made pursuant to the Trust Indenture Act.

SECTION 7.03 Reports by Trustee.

The Trustee shall transmit to Holders such reports concerning the Trustee and its actions under this Indenture as may be required pursuant to the Trust Indenture Act at the times and in the manner provided pursuant thereto.

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Reports so required to be transmitted at stated intervals of not more than 12 months shall be transmitted no later than sixty days after each May 15 following the date of first issuance.

A copy of each such report shall, at the time of such transmission to Holders, be filed by the Trustee with each stock exchange upon which any Securities are listed, with the Commission and with the Company. (The Company will notify the Trustee when any Securities are listed on any stock exchange pursuant to Section 7.04.)

SECTION 7.04 Reports by Company.

The Company shall file with the Trustee and the Commission, and transmit to Holders, such information, documents and other reports, and such summaries thereof, as may be required pursuant to the Trust Indenture Act at the times and in the manner provided pursuant to such Act; provided that any such information, documents or reports required to be filed with the Commission pursuant to Section 13 or 15(d) of the Exchange Act shall be filed with the Trustee within 15 days after the same is so required to be filed with the Commission.

The Company shall notify the Trustee when any Securities are listed on any stock exchange.

ARTICLE VIII

CONSOLIDATION, MERGER, CONVEYANCE, TRANSFER OR LEASE

SECTION 8.01 Company May Consolidate, Etc., Only on Certain Terms.

The Company covenants that it will not merge or consolidate with any other corporation or sell or convey all or substantially all of its assets to any person, firm or corporation, except that the Company may merge or consolidate with, or sell or convey all or substantially all of its assets to, any other corporation, provided that:

(1	)	(A)	the Company shall be the continuing corporation or:
		(B)	(i)	the successor corporation (if other than the Company) shall be a corporation organized and existing under the laws of the United States of America or a state thereof; and
			(ii)	such corporation shall expressly assume the due and punctual payment of the principal of and any premium and interest on all the Securities, according to their tenor, and the due and punctual performance and observance of all of the covenants and conditions of this Indenture to be performed by the Company;
		and
(2	)	the Company or such successor corporation, as the case may be, shall not, immediately after such merger or consolidation, or such sale or conveyance, be in default in the performance of any such covenant or condition and no event which with the lapse of time, the giving of notice or both would constitute an Event of Default shall have occurred and be continuing.

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For purposes of this Section 8.01, “substantially all of its assets” shall mean, at any date, a portion of the non-current assets reflected in the Company’s consolidated balance sheet as of the end of the most recent quarterly period that represents at least sixty-six and two-thirds percent (66 2/3%) of the total reported value of such assets.

SECTION 8.02 Successor Substituted.

In case of any such consolidation, merger, sale or conveyance and upon the assumption by the successor corporation of the obligations under this Indenture and the Securities in accordance with Section 8.01, such successor corporation shall succeed to and be substituted for the Company, with the same effect as if it had been named herein as a party hereto, and the Company shall thereupon be relieved of any further obligations or liabilities hereunder and upon the Securities and the Company as the predecessor corporation may thereupon or at any time thereafter be dissolved, wound-up or liquidated. Such successor corporation thereupon may cause to be signed, and may issue either in its own name or in the name of the predecessor corporation, any or all of the Securities issuable hereunder which theretofore shall not have been signed by the Company and delivered to the Trustee and, upon the order of such successor corporation, instead of the Company, and subject to all the terms, conditions and limitations in this Indenture prescribed, the Trustee shall authenticate and shall deliver any Securities which previously shall have been signed and delivered by the officers of the Company to the Trustee for authentication and any Securities which such successor corporation thereafter shall cause to be signed and delivered to the Trustee for that purpose. All the Securities so issued shall in all respects have the same legal rank and benefit under this Indenture as the Securities theretofore or thereafter issued in accordance with the terms of this Indenture as though all of such Securities had been issued at the date of the execution hereof.

In case of any such consolidation, merger, sale or conveyance, such changes in phraseology and form (but not in substance) may be made in the Securities thereafter to be issued as may be appropriate.

SECTION 8.03 Trustee Entitled to Opinion.

The Trustee, subject to the provisions of Sections 6.01 and 6.03, may receive an Opinion of Counsel as conclusive evidence that any such consolidation, merger, sale or conveyance, and any such assumption, complies with the provisions of this Article.

ARTICLE IX

SUPPLEMENTAL INDENTURES

SECTION 9.01 Supplemental Indentures Without Consent of Holders.

Without the consent of any Holders, the Company, when authorized by its Board of Directors, and the Trustee, at any time and from time to time, may enter into one or more indentures supplemental hereto, in form satisfactory to the Trustee, for one or more of the following purposes:

(1) to evidence the succession of another Person to the Company and the assumption by any such successor of the covenants of the Company herein and in the Securities; or

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(2) to add to the covenants of the Company for the benefit of the Holders of all or any series of Securities (and if such covenants are to be for the benefit of less than all series of Securities, stating that such covenants are expressly being included solely for the benefit of such series) or to surrender any right or power herein conferred upon the Company; or

(3) to add any additional Events of Default for the benefit of the Holders of all or any series of Securities (and if such additional Events of Default are to be for the benefit of less than all series of Securities, stating that such additional Events of Default are expressly being included solely for the benefit of such series); or

(4) to add to or change any of the provisions of this Indenture to such extent as shall be necessary to permit or facilitate the issuance of Securities in bearer form, registrable or not registrable as to principal, and with or without interest coupons, or to permit or facilitate the issuance of Securities in uncertificated form; or

(5) to add to, change or eliminate any of the provisions of this Indenture in respect of one or more series of Securities, provided that any such addition, change or elimination

(A) shall neither

(i) apply to any Security of any series created prior to the execution of such supplemental indenture and entitled to the benefit of such provision nor

(ii) modify the rights of the Holder of any such Security with respect to such provision

or

(B) shall become effective only when there is no such Security Outstanding; or

(6) to secure the Securities pursuant to the requirements of Section 10.05 or to otherwise secure the Securities of any series; or

(7) to establish the form or terms of Securities of any series as permitted by Sections 2.01 and 3.01; or

(8) to evidence and provide for the acceptance of appointment hereunder by a successor Trustee with respect to the Securities of one or more series and to add to or change any of the provisions of this Indenture as shall be necessary to

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provide for or facilitate the administration of the trusts hereunder by more than one Trustee, pursuant to the requirements of Section 6.11; or

(9) to cure any ambiguity, to correct or supplement any provision herein which may be defective or inconsistent with any other provision herein, or to make any other provisions with respect to matters or questions arising under this Indenture, provided that such action pursuant to this clause (9) shall not adversely affect the interests of the Holders of Securities of any series in any material respect.

SECTION 9.02 Supplemental Indentures With Consent of Holders.

With the consent of the Holders of not less than a majority in principal amount of the Outstanding Securities of each series affected by such supplemental indenture, by Act of said Holders delivered to the Company and the Trustee, the Company, when authorized by its Board of Directors, and the Trustee may enter into an indenture or indentures supplemental hereto for the purpose of adding any provisions to or changing in any manner or eliminating any of the provisions of this Indenture or modifying in any manner the rights of the Holders of Securities of such series under this Indenture; provided, however, that no such supplemental indenture shall, without the consent of the Holder of each Outstanding Security affected thereby:

(1) change the Stated Maturity of the principal of, or any installment of principal of or interest on, any Security, or reduce the principal amount thereof or the rate of interest thereon or any premium payable upon the redemption thereof, or reduce the amount of the principal of an Original Issue Discount Security or any other Security which would be due and payable upon a declaration of acceleration of the Maturity thereof pursuant to Section 5.02, or change the coin or currency in which any Security or any premium or interest thereon is payable, or impair the right to institute suit for the enforcement of any such payment on or after the Stated Maturity thereof (or, in the case of redemption, on or after the Redemption Date), or adversely affect any right of the Holder of any Security to require the Company to repurchase such Security;

(2) reduce the percentage in principal amount of the Outstanding Securities of any series, the consent of whose Holders is required for any such supplemental indenture, or the consent of whose Holders is required for any waiver (of compliance with certain provisions of this Indenture or certain defaults hereunder and their consequences) provided for in this Indenture; or

(3) modify any of the provisions of this Section, Section 5.13 or Section 10.07, except to increase any percentage set forth in such Sections or to provide that certain other provisions of this Indenture cannot be modified or waived without the consent of the Holder of each Outstanding Security affected thereby; provided, however, that this clause shall not be deemed to require the consent of any Holder with respect to changes in the references to “the Trustee” and concomitant changes in this Section and Section 10.07, or the deletion of this proviso, in accordance with the requirements of Sections 6.11 and 9.01(8).

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A supplemental indenture which changes or eliminates any covenant or other provision of this Indenture which has expressly been included solely for the benefit of one or more particular series of Securities, or which modifies the rights of the Holders of Securities of such series with respect to such covenant or other provision, shall be deemed not to affect the rights under this Indenture of the Holders of Securities of any other series.

It shall not be necessary for any Act of Holders under this Section to approve the particular form of any proposed supplemental indenture, but it shall be sufficient if such Act shall approve the substance thereof.

SECTION 9.03 Execution of Supplemental Indentures.

In executing, or accepting the additional trusts created by, any supplemental indenture permitted by this Article or the modifications thereby of the trusts created by this Indenture, the Trustee shall be entitled to receive, and (subject to Section 6.01) shall be fully protected in relying upon, an Opinion of Counsel stating that the execution of such supplemental indenture is authorized or permitted by this Indenture. The Trustee may, but shall not be obligated to, enter into any such supplemental indenture which affects the Trustee’s own rights, duties or immunities under this Indenture or otherwise.

SECTION 9.04 Effect of Supplemental Indentures.

Upon the execution of any supplemental indenture under this Article, this Indenture shall be modified in accordance therewith, and such supplemental indenture shall form a part of this Indenture for all purposes; and every Holder of Securities theretofore or thereafter authenticated and delivered hereunder shall be bound thereby.

SECTION 9.05 Conformity With Trust Indenture Act.

Every supplemental indenture executed pursuant to this Article shall conform to the requirements of the Trust Indenture Act.

SECTION 9.06 Reference in Securities to Supplemental Indentures.

Securities of any series authenticated and delivered after the execution of any supplemental indenture pursuant to this Article may, and shall if required by the Trustee, bear a notation in form approved by the Trustee as to any matter provided for in such supplemental indenture. If the Company shall so determine, new Securities of any series so modified as to conform, in the opinion of the Trustee and the Company, to any such supplemental indenture may be prepared and executed by the Company and authenticated and delivered by the Trustee in exchange for Outstanding Securities of such series.

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ARTICLE X

COVENANTS

SECTION 10.01 Payment of Principal, Premium and Interest.

The Company covenants and agrees for the benefit of each series of Securities that it will duly and punctually pay or cause to be paid the principal of (including any amount in respect of original issue discount) and any premium and interest on each of the Securities of such series at the Place of Payment, at the respective times and in the manner provided in the Securities and this Indenture. The principal of, premium, and interest on the Securities shall be payable only in accordance with the terms of the relevant Security.

SECTION 10.02 Maintenance of Office or Agency.

The Company will maintain in the Borough of Manhattan, The City of New York, and in each other Place of Payment for any series of Securities an office or agency where Securities of that series may be presented or surrendered for payment, where Securities of that series may be surrendered for registration of transfer or exchange and where notices and demands to or upon the Company in respect of the Securities of that series and this Indenture may be served. The Company will give prompt written notice to the Trustee of the location, and any change in the location, of such office or agency. If at any time the Company shall fail to maintain any such required office or agency or shall fail to furnish the Trustee with the address thereof, such presentations, surrenders, notices and demands may be made or served at the Corporate Trust Office of the Trustee, or an affiliate of the Trustee, and the Company hereby appoints the Trustee as its agent to receive all such presentations, surrenders, notices and demands.

The Company may also from time to time designate one or more other offices or agencies where the Securities of one or more series may be presented or surrendered for any or all such purposes and may from time to time rescind such designations; provided, however, that no such designation or rescission shall in any manner relieve the Company of its obligation to maintain an office or agency in the Borough of Manhattan, The City of New York, and in each other Place of Payment for Securities of any series for such purposes. The Company will give prompt written notice to the Trustee of any such designation or rescission and of any change in the location of any such other office or agency.

SECTION 10.03 Money for Securities Payments to be Held in Trust.

If the Company shall at any time act as its own Paying Agent with respect to any series of Securities, it will, on or before each due date of the principal of or any premium or interest on any of the Securities of that series, segregate and hold in trust for the benefit of the Persons entitled thereto a sum sufficient to pay the principal and any premium and interest so becoming due until such sums shall be paid to such Persons or otherwise disposed of as herein provided and will promptly notify the Trustee of its action or failure so to act.

Whenever the Company shall have one or more Paying Agents for any series of Securities, it will, prior to each due date of the principal of or any premium or interest on any Securities of that series, deposit with a Paying Agent a sum sufficient to pay such amount, such sum to be held as provided by the Trust Indenture Act, and (unless such Paying Agent is the Trustee) the Company will promptly notify the Trustee of its action or failure so to act.

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The Company will cause each Paying Agent, other than the Trustee or the Company, for any series of Securities to execute and deliver to the Trustee an instrument in which such Paying Agent shall agree with the Trustee, subject to the provisions of this Section, that such Paying Agent will (1) comply with the provisions of the Trust Indenture Act applicable to it as a Paying Agent and (2) during the continuance of any default by the Company (or any other obligor upon the Securities of that series) in the making of any payment in respect of the Securities of that series, upon the written request of the Trustee, forthwith pay to the Trustee all sums held in trust by such Paying Agent for payment in respect of the Securities of that series. Each of the Company and the Trustee, having agreed to the foregoing on its behalf as a Paying Agent by its execution and delivery of this instrument, has hereby satisfied the provisions of this paragraph with respect to itself as a Paying Agent.

The Company may at any time, for the purpose of obtaining the satisfaction and discharge of this Indenture or for any other purpose, pay, or by Company Order direct any Paying Agent to pay, to the Trustee all sums held in trust by the Company or such Paying Agent, such sums to be held by the Trustee upon the same trusts as those upon which such sums were held by the Company or such Paying Agent; and, upon such payment by any Paying Agent to the Trustee, such Paying Agent shall be released from all further liability with respect to such money.

Any money deposited with the Trustee or any Paying Agent, or then held by the Company, in trust for the payment of the principal of or any premium or interest on any Security of any series and remaining unclaimed for two years after such principal, premium or interest has become due and payable shall be paid to the Company on Company Request, or (if then held by the Company) shall be discharged from such trust; and the Holder of such Security shall thereafter, as an unsecured general creditor, look only to the Company for payment thereof, and all liability of the Trustee or such Paying Agent with respect to such trust money, and all liability of the Company as trustee thereof, shall thereupon cease; provided, however, that the Trustee or such Paying Agent, before being required to make any such repayment, may at the expense of the Company cause to be published once, in a newspaper published in the English language, customarily published on each Business Day and of general circulation in New York, New York, notice that such money remains unclaimed and that, after a date specified therein, which shall not be less than 30 days from the date of such publication, any unclaimed balance of such money then remaining will be repaid to the Company free of the trust formerly impressed upon it.

SECTION 10.04 Statement by Officers as to Default.

The Company will deliver to the Trustee, within 120 days after the end of each fiscal year of the Company ending after the date hereof, an Officers’ Certificate, stating whether or not to the knowledge of the signers thereof the Company is in default in the performance and observance of any of the terms, provisions and conditions of this Indenture (without regard to any period of grace or requirement of notice provided hereunder) and, if the Company shall be in default, specifying all such defaults and the nature and status thereof of which they may have knowledge.

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SECTION 10.05 Mortgage of Certain Property.

If the Company or any Subsidiary of the Company shall Mortgage as security for any indebtedness for money borrowed any property capable of producing oil or gas which (i) is located in the United States and (ii) is determined to be a principal property by the Board of Directors in its discretion, the Company will secure or will cause such Subsidiary to secure each series of the Securities equally and ratably with all indebtedness or obligations secured by the Mortgage then being given and with any other indebtedness of the Company or such Subsidiary then entitled thereto; provided, however, that this covenant shall not apply in the case of:

(1) any Mortgage existing on the date of this Indenture (whether or not such Mortgage includes an after-acquired property provision);

(2) any Mortgage, including a purchase money Mortgage, incurred in connection with the acquisition of any property (for purposes hereof, the creation of any Mortgage within one hundred eighty (180) days after the acquisition or completion of construction of such property shall be deemed to be incurred in connection with the acquisition of such property), the assumption of any Mortgage previously existing on such acquired property or any Mortgage existing on the property of any corporation when such corporation becomes a Subsidiary of the Company;

(3) any Mortgage on such property in favor of the United States of America, any State, or any agency, department, political subdivision or other instrumentality of either, to secure partial, progress, advance or other payments to the Company or any Subsidiary of the Company pursuant to the provisions of any contract or any statute;

(4) any Mortgage on such property in favor of the United States of America, any State, or any agency, department, political subdivision or other instrumentality of either, to secure borrowings by the Company or any Subsidiary of the Company for the purchase or construction of the property Mortgaged;

(5) any Mortgage in connection with a sale or other transfer of:

(A) oil, gas or other minerals in place for a period of time until, or in an amount such that, the purchaser will realize therefrom a specified amount of money (however determined) or a specified amount of minerals; or

(B) any interest in property of the character commonly referred to as an “oil payment” or “production payment”;

(6) any Mortgage on any property arising in connection with or to secure all or any part of the cost of the repair, construction, improvement, alteration, exploration, development or drilling of such property or any portion thereof;

(7) any Mortgage on any pipeline, gathering system, pumping or compressor station, pipeline storage facility, other pipeline facility, drilling equipment, drilling platform, drilling barge, any movable railway, marine or automotive equipment,

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gas plant, office building, storage tank, or warehouse facility, any of which is located at or on any such principal property;

(8) any Mortgage on any equipment or other personal property used in connection with any such principal property;

(9) any Mortgage on any such principal property arising in connection with the sale of accounts receivable resulting from the sale of oil or gas at the wellhead; or

(10) any renewal of or substitution for any Mortgage permitted under any of the preceding clauses.

Notwithstanding the foregoing restriction contained in this Section 10.05, the Company may and may permit its Subsidiaries to incur liens or grant Mortgages on property covered by the restriction above so long as the net book value of the property so encumbered, together with all property subject to the restriction on sale and leasebacks contained in Section 10.06, does not, at the time such lien or Mortgage is granted, exceed ten percent (10%) of Consolidated Net Tangible Assets.

SECTION 10.06 Sale and Leaseback of Certain Properties.

The Company will not, nor will it permit any Subsidiary of the Company to, sell or transfer any property capable of producing oil or gas which (i) is located in the United States and (ii) is determined to be a principal property by the Board of Directors in its discretion, with the intention of taking back a lease of such property; provided, however, this covenant shall not apply if:

(1	)	the lease is between the Company and a Subsidiary or between Subsidiaries;
(2	)	the lease is for a temporary period by the end of which it is intended that the use of such property by the lessee will be discontinued;
(3	)	the Company or a Subsidiary of the Company could, in accordance with Section 10.05, Mortgage such property without equally and ratably securing the Securities;
(4	)	the transfer is incident to or necessary to effect any operating, farm-out, farm-in, unitization, acreage exchange, acreage contribution, bottom-hole or dry-hole arrangement or pooling agreement or any other agreement of the same general nature relating to the acquisition, exploration, maintenance, development or operation of oil or gas properties in the ordinary course of business or as required by any regulatory agency having jurisdiction over the property; or
(5	)	(A)    the Company promptly informs the Trustee of such sale,
		(B)     the net proceeds of such sale are at least equal to the fair value (as determined by resolution adopted by the Board           of Directors) of such property and

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(C) the Company shall, and in any such case the Company covenants that it will, within one hundred and eighty (180) days after such sale, apply an amount equal to the net proceeds of such sale to the retirement of debt of the Company, or of a Subsidiary of the Company in the case of property of such Subsidiary, maturing by its terms more than one (1) year after the date on which it was originally incurred (herein called “funded debt”); provided that the amount to be applied to the retirement of funded debt of the Company or of a Subsidiary of the Company shall be reduced by the amount below if, within seventy-five (75) days after such sale, the Company shall deliver to the Trustee an Officers’ Certificate

(i) stating that on a specified date after such sale the Company or a Subsidiary of the Company, as the case may be, voluntarily retired a specified principal amount of funded debt,

(ii) stating that such retirement was not effected by payment at maturity or pursuant to any applicable mandatory sinking fund or prepayment provision (other than provisions requiring retirement of any funded debt of the Company or a Subsidiary of the Company, as the case may be, under the circumstances referred to in this Section 10.06), and

(iii) stating the then optional redemption or prepayment price applicable to the funded debt so retired or, if there is no such price applicable, the amount applied by the Company or a Subsidiary of the Company, as the case may be, to the retirement of such funded debt.

In the event of such a sale or transfer, the Company shall deliver to the Trustee a certified copy of the resolution of the Board of Directors referred to in the parenthetical phrase contained in subclause (5)(B) of this Section 10.06 and an Officers’ Certificate setting forth all material facts under this Section 10.06. For the purposes of this Section 10.06 the term retirement of such funded debt shall include the “in substance defeasance” of such funded debt in accordance with then applicable accounting rules.

SECTION 10.07 Waiver of Certain Covenants.

Except as otherwise specified as contemplated by Section 3.01 for Securities of such series, the Company may, with respect to the Securities of any series, omit in any particular instance to comply with any term, provision or condition set forth in any covenant provided pursuant to Section 3.01(18), 9.01(2) or 9.01(7) for the benefit of the Holders of such series or in Section 10.05 or 10.06, if before the time for such compliance the Holders of at least a majority in principal amount of the Outstanding Securities of such series shall, by Act of such Holders, either waive such compliance in such instance or generally waive compliance with such term, provision or condition, but no such waiver shall extend to or affect such term, provision or condition except to the extent so expressly waived, and, until such waiver shall become effective, the obligations of the Company and the duties of the Trustee in respect of any such term, provision or condition shall remain in full force and effect.

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ARTICLE XI

REDEMPTION OF SECURITIES

SECTION 11.01 Applicability of Article.

Securities of any series which are redeemable before their Stated Maturity shall be redeemable in accordance with their terms and (except as otherwise specified as contemplated by Section 3.01 for such Securities) in accordance with this Article.

SECTION 11.02 Election to Redeem; Notice to Trustee.

The election of the Company to redeem any Securities shall be evidenced by a Board Resolution or in another manner specified as contemplated by Section 3.01 for such Securities. In case of any redemption at the election of the Company of less than all the Securities of any series (including any such redemption affecting only a single Security), the Company shall, at least 60 days prior to the Redemption Date fixed by the Company (unless a shorter notice shall be satisfactory to the Trustee), notify the Trustee of such Redemption Date, of the principal amount of Securities of such series to be redeemed and, if applicable, of the tenor of the Securities to be redeemed. In the case of any redemption of Securities prior to the expiration of any restriction on such redemption provided in the terms of such Securities or elsewhere in this Indenture, the Company shall furnish the Trustee with an Officers’ Certificate evidencing compliance with such restriction.

SECTION 11.03 Selection by Trustee of Securities to be Redeemed.

If less than all the Securities of any series are to be redeemed (unless all the Securities of such series and of a specified tenor are to be redeemed or unless such redemption affects only a single Security), the particular Securities to be redeemed shall be selected not more than 60 days prior to the Redemption Date by the Trustee, from the Outstanding Securities of such series not previously called for redemption, by such method as the Trustee shall deem fair and appropriate and which may provide for the selection for redemption of a portion of the principal amount of any Security of such series, provided that the unredeemed portion of the principal amount of any Security shall be in an authorized denomination (which shall not be less than the minimum authorized denomination or any integral multiple thereof) for such Security. If less than all the Securities of such series and of a specified tenor are to be redeemed (unless such redemption affects only a single Security), the particular Securities to be redeemed shall be selected not more than 60 days prior to the Redemption Date by the Trustee, from the Outstanding Securities of such series and specified tenor not previously called for redemption in accordance with the preceding sentence.

The Trustee shall promptly notify the Company in writing of the Securities selected for redemption as aforesaid and, in case of any Securities selected for partial redemption as aforesaid, the principal amount thereof to be redeemed.

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The provisions of the two preceding paragraphs shall not apply with respect to any redemption affecting only a single Security, whether such Security is to be redeemed in whole or in part. In the case of any such redemption in part, the unredeemed portion of the principal amount of the Security shall be in an authorized denomination (which shall not be less than the minimum authorized denomination) for such Security.

For all purposes of this Indenture, unless the context otherwise requires, all provisions relating to the redemption of Securities shall relate, in the case of any Securities redeemed or to be redeemed only in part, to the portion of the principal amount of such Securities which has been or is to be redeemed.

SECTION 11.04 Notice of Redemption.

Notice of redemption shall be given by first-class mail, postage prepaid, mailed not less than 30 nor more than 60 days prior to the Redemption Date, to each Holder of Securities to be redeemed, at his address appearing in the Security Register.

All notices of redemption shall state:

(1) the Redemption Date,

(2) the Redemption Price,

(3) if less than all the Outstanding Securities of any series consisting of more than a single Security are to be redeemed, the identification (and, in the case of partial redemption of any such Securities, the principal amounts) of the particular Securities to be redeemed and, if less than all the Outstanding Securities of any series consisting of a single Security are to be redeemed, the principal amount of the particular Security to be redeemed,

(4) that on the Redemption Date the Redemption Price will become due and payable upon each such Security to be redeemed and, if applicable, that interest thereon will cease to accrue on and after said date,

(5) the place or places where each such Security is to be surrendered for payment of the Redemption Price, and

(6) that the redemption is for a sinking fund, if such is the case.

Notice of redemption of Securities to be redeemed at the election of the Company shall be given by the Company or, at the Company’s request, by the Trustee in the name and at the expense of the Company and shall be irrevocable.

SECTION 11.05 Deposit of Redemption Price.

Prior to any Redemption Date, the Company shall deposit with the Trustee or with a Paying Agent (or, if the Company is acting as its own Paying Agent, segregate and hold in trust as provided in Section 10.03) an amount of money sufficient to pay the Redemption Price of, and (except if the Redemption Date shall be an Interest Payment Date) accrued interest on, all the Securities which are to be redeemed on that date.

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SECTION 11.06 Securities Payable on Redemption Date.

Notice of redemption having been given as aforesaid, the Securities so to be redeemed shall, on the Redemption Date, become due and payable at the Redemption Price therein specified, and from and after such date (unless the Company shall default in the payment of the Redemption Price and accrued interest) such Securities shall cease to bear interest. Upon surrender of any such Security for redemption in accordance with said notice, such Security shall be paid by the Company at the Redemption Price, together with accrued interest to the Redemption Date; provided, however, that, unless otherwise specified as contemplated by Section 3.01, installments of interest whose Stated Maturity is on or prior to the Redemption Date will be payable to the Holders of such Securities, or one or more Predecessor Securities, registered as such at the close of business on the relevant Record Dates according to their terms and the provisions of Section 3.07.

If any Security called for redemption shall not be so paid upon surrender thereof for redemption, the principal and any premium shall, until paid, bear interest from the Redemption Date at the rate prescribed therefor in the Security.

SECTION 11.07 Securities Redeemed in Part.

Any Security which is to be redeemed only in part shall be surrendered at a Place of Payment therefor (with, if the Company or the Trustee so requires, due endorsement by, or a written instrument of transfer in form satisfactory to the Company and the Trustee duly executed by, the Holder thereof or his attorney duly authorized in writing), and the Company shall execute, and the Trustee shall authenticate and deliver to the Holder of such Security without service charge, a new Security or Securities of the same series and of like tenor, of any authorized denomination as requested by such Holder, in aggregate principal amount equal to and in exchange for the unredeemed portion of the principal of the Security so surrendered.

ARTICLE XII

SINKING FUNDS

SECTION 12.01 Applicability of Article.

The provisions of this Article shall be applicable to any sinking fund for the retirement of Securities of any series except as otherwise specified as contemplated by Section 3.01 for such Securities.

The minimum amount of any sinking fund payment provided for by the terms of any Securities is herein referred to as a “mandatory sinking fund payment,” and any payment in excess of such minimum amount provided for by the terms of such Securities is herein referred to as an “optional sinking fund payment.” If provided for by the terms of any Securities, the cash amount of any sinking fund payment may be subject to reduction as provided in Section 12.02. Each sinking fund payment shall be applied to the redemption of Securities as provided for by the terms of such Securities.

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SECTION 12.02 Satisfaction of Sinking Fund Payments with Securities.

The Company

(1) may deliver Outstanding Securities of a series (other than any Securities previously called for redemption) and

(2) may apply as a credit Securities of a series which have been redeemed either at the election of the Company pursuant to the terms of such Securities or through the application of permitted optional sinking fund payments pursuant to the terms of such Securities,

in each case in satisfaction of all or any part of any sinking fund payment with respect to any Securities of such series required to be made pursuant to the terms of such Securities as and to the extent provided for by the terms of such Securities; provided that the Securities to be so credited have not been previously so credited. The Securities to be so credited shall be received and credited for such purpose by the Trustee at the Redemption Price, as specified in the Securities so to be redeemed, for redemption through operation of the sinking fund and the amount of such sinking fund payment shall be reduced accordingly.

SECTION 12.03 Redemption of Securities for Sinking Fund.

Not less than 45 days prior to each sinking fund payment date for any Securities, the Company will deliver to the Trustee an Officers’ Certificate specifying the amount of the next ensuing sinking fund payment for such Securities pursuant to the terms of such Securities, the portion thereof, if any, which is to be satisfied by payment of cash and the portion thereof, if any, which is to be satisfied by delivering and crediting Securities pursuant to Section 12.02 and will also deliver to the Trustee any Securities to be so delivered. Not less than 15 nor more than 45 days prior to each such sinking fund payment date, the Trustee shall select the Securities to be redeemed upon such sinking fund payment date in the manner specified in Section 11.03 and cause notice of the redemption thereof to be given in the name of and at the expense of the Company in the manner provided in Section 11.04. Such notice having been duly given, the redemption of such Securities shall be made upon the terms and in the manner stated in Sections 11.06 and 11.07.

ARTICLE XIII

DEFEASANCE AND COVENANT DEFEASANCE

SECTION 13.01 Company’s Option to Effect Defeasance or Covenant Defeasance.

The Company may elect, at its option at any time, to have Section 13.02 or Section 13.03 applied to any Securities or any series of Securities, as the case may be, designated pursuant to Section 3.01 as being defeasible pursuant to such Section 13.02 or 13.03, in accordance with any applicable requirements provided pursuant to Section 3.01 and upon compliance with the conditions set forth below in this Article. Any such election shall be evidenced by a Board Resolution or in another manner specified as contemplated by Section 3.01 for such Securities.

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SECTION 13.02 Defeasance and Discharge.

Upon the Company’s exercise of its option (if any) to have this Section applied to any Securities or any series of Securities, as the case may be, the Company shall be deemed to have been discharged from its obligations with respect to such Securities as provided in this Section on and after the date the conditions set forth in Section 13.04 are satisfied (hereinafter called “Defeasance”). For this purpose, such Defeasance means that the Company shall be deemed to have paid and discharged the entire indebtedness represented by such Securities and to have satisfied all its other obligations under such Securities and this Indenture insofar as such Securities are concerned (and the Trustee, at the expense of the Company, shall execute proper instruments acknowledging the same), subject to the following which shall survive until otherwise terminated or discharged hereunder:

(1) the rights of Holders of such Securities to receive, solely from the trust fund described in Section 13.04 and as more fully set forth in such Section, payments in respect of the principal of and any premium and interest on such Securities when payments are due,

(2) the Company’s obligations with respect to such Securities under Sections 3.04, 3.05, 3.06, 10.02 and 10.03,

(3) the rights, powers, trusts, duties and immunities of the Trustee hereunder and

(4) this Article.

Subject to compliance with this Article, the Company may exercise its option (if any) to have this Section applied to any Securities notwithstanding the prior exercise of its option (if any) to have Section 13.03 applied to such Securities.

SECTION 13.03 Covenant Defeasance.

Upon the Company’s exercise of its option (if any) to have this Section applied to any Securities or any series of Securities, as the case may be,

(1) the Company shall be released from its obligations under Section 8.01(1)(B)(i), Section 10.05, Section 10.06 and any covenants provided pursuant to Section 3.01(18), 9.01(2) or 9.01(7) for the benefit of the Holders of such Securities, and

(2) the occurrence of any event specified in Sections 5.01(3), 5.01(4) (with respect to any of Section 8.01(1)(B)(i), Section 10.05, Section 10.06 and any such covenants provided pursuant to Section 3.01(18), 9.01(2) or 9.01(7)) and 5.01(7) shall be deemed not to be or result in an Event of Default,

in each case with respect to such Securities as provided in this Section on and after the date the conditions set forth in Section 13.04 are satisfied (hereinafter called “Covenant Defeasance”). For this purpose, such Covenant Defeasance means that, with respect to such Securities, the Company may omit to comply with and shall have no liability in respect of any term, condition

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or limitation set forth in any such specified Section (to the extent so specified in the case of Section 5.01(4)), whether directly or indirectly by reason of any reference elsewhere herein to any such Section or by reason of any reference in any such Section to any other provision herein or in any other document, but the remainder of this Indenture and such Securities shall be unaffected thereby.

SECTION 13.04 Conditions to Defeasance or Covenant Defeasance.

The following shall be the conditions to the application of Section 13.02 or Section 13.03 to any Securities or any series of Securities, as the case may be:

(1) The Company shall irrevocably have deposited or caused to be deposited with the Trustee (or another trustee which satisfies the requirements contemplated by Section 6.09 and agrees to comply with the provisions of this Article applicable to it) as trust funds in trust for the purpose of making the following payments, specifically pledged as security for, and dedicated solely to, the benefits of the Holders of such Securities,

(A) money in an amount (in such currency, currencies or currency unit or units in which the Securities of such series are payable), or

(B) in the case of Securities denominated in Dollars, U.S. Government Obligations, or, in the case of Securities denominated in a Foreign Currency, Foreign Government Obligations, which through the scheduled payment of principal and interest in respect thereof in accordance with their terms will provide, not later than one day before the due date of any payment, money in an amount, or

(C) a combination thereof,

in each case sufficient, in the opinion of a nationally recognized firm of independent public accountants expressed in a written certification thereof delivered to the Trustee, to pay and discharge, and which shall be applied by the Trustee (or any such other qualifying trustee) to pay and discharge, the principal of and any premium and interest on such Securities on the respective Stated Maturities, in accordance with the terms of this Indenture and such Securities. As used herein, “U.S. Government Obligation” means:

(x) any security which is

(i) a direct obligation of the United States of America for the payment of which the full faith and credit of the United States of America is pledged or

(ii) an obligation of a Person controlled or supervised by and acting as an agency or instrumentality of the United States of America the payment of which is unconditionally guaranteed as a full faith and credit obligation by the United States of America, which, in either case (i) or (ii), is not callable or redeemable at the option of the issuer thereof; and

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(y) any depositary receipt issued by a bank (as defined in Section 3(a)(2) of the Securities Act) as custodian with respect to any U.S. Government Obligation which is specified in clause (x) above and held by such bank for the account of the holder of such depositary receipt, or with respect to any specific payment of principal of or interest on any U.S. Government Obligation which is so specified and held, provided that (except as required by law) such custodian is not authorized to make any deduction from the amount payable to the holder of such depositary receipt from any amount received by the custodian in respect of the U.S. Government Obligation or the specific payment of principal or interest evidenced by such depositary receipt.

(2) In the event of an election to have Section 13.02 apply to any Securities or any series of Securities, as the case may be, the Company shall have delivered to the Trustee an Opinion of Counsel stating that

(A) the Company has received from, or there has been published by, the Internal Revenue Service a ruling, or

(B) since the date of this instrument, there has been a change in the applicable Federal income tax law,

in either case (A) or (B) to the effect that, and based thereon such opinion shall confirm that, the Holders of such Securities will not recognize gain or loss for Federal income tax purposes as a result of the deposit, Defeasance and discharge to be effected with respect to such Securities and will be subject to Federal income tax on the same amount, in the same manner and at the same times as would be the case if such deposit, Defeasance and discharge were not to occur.

(3) In the event of an election to have Section 13.03 apply to any Securities or any series of Securities, as the case may be, the Company shall have delivered to the Trustee an Opinion of Counsel to the effect that the Holders of such Securities will not recognize gain or loss for Federal income tax purposes as a result of the deposit and Covenant Defeasance to be effected with respect to such Securities and will be subject to Federal income tax on the same amount, in the same manner and at the same times as would be the case if such deposit and Covenant Defeasance were not to occur.

(4) No event which is, or after notice or lapse of time or both would become, an Event of Default with respect to such Securities or any other Securities shall have occurred and be continuing at the time of such deposit or, with regard to any such event specified in Sections 5.01(5) and (6), at any time on or prior to the 90th day after the date of such deposit (it being understood that this condition shall not be deemed satisfied until after such 90th day).

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(5) Such Defeasance or Covenant Defeasance shall not cause the Trustee to have a conflicting interest within the meaning of the Trust Indenture Act (assuming all Securities are in default within the meaning of such Act).

(6) Such Defeasance or Covenant Defeasance shall not result in a breach or violation of, or constitute a default under, any other agreement or instrument to which the Company is a party or by which it is bound.

(7) Such Defeasance or Covenant Defeasance shall not result in the trust arising from such deposit constituting an investment company within the meaning of the Investment Company Act of 1940 (and any statute successor thereto) unless such trust shall be registered under such Act or exempt from registration thereunder.

(8) The Company shall have delivered to the Trustee an Officer’s Certificate and an Opinion of Counsel, each stating that all conditions precedent with respect to such Defeasance or Covenant Defeasance have been complied with.

SECTION 13.05 Deposited Money and U.S. Government Obligations to Be Held in Trust; Miscellaneous Provisions.

Subject to the provisions of the last paragraph of Section 10.03, all money, U.S. Government Obligations (including the proceeds thereof) and Foreign Government Obligations (including the proceeds thereof) deposited with the Trustee or other qualifying trustee (solely for purposes of this Section and Section 13.06, the Trustee and any such other trustee are referred to collectively as the “Trustee”) pursuant to Section 13.04 in respect of any Securities shall be held in trust and applied by the Trustee, in accordance with the provisions of such Securities and this Indenture, to the payment, either directly or through any such Paying Agent (including the Company acting as its own Paying Agent) as the Trustee may determine, to the Holders of such Securities, of all sums due and to become due thereon in respect of principal and any premium and interest, but money so held in trust need not be segregated from other funds except to the extent required by law.

The Company shall pay and indemnify the Trustee against any tax, fee or other charge imposed on or assessed against the U.S. Government Obligations and Foreign Government Obligations deposited pursuant to Section 13.04 or the principal and interest received in respect thereof, other than any such tax, fee or other charge which by law is for the account of the Holders of Outstanding Securities.

Anything in this Article to the contrary notwithstanding, the Trustee shall deliver or pay to the Company from time to time upon Company Request any money, U.S. Government Obligations or Foreign Government Obligations held by it as provided in Section 13.04 with respect to any Securities which, in the opinion of a nationally recognized firm of independent public accountants expressed in a written certification thereof delivered to the Trustee, are in excess of the amount thereof which would then be required to be deposited to effect the Defeasance or Covenant Defeasance, as the case may be, with respect to such Securities.

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SECTION 13.06 Reinstatement.

If the Trustee or the Paying Agent is unable to apply any money in accordance with this Article with respect to any Securities by reason of any order or judgment of any court or governmental authority enjoining, restraining or otherwise prohibiting such application, then the obligations under this Indenture and such Securities from which the Company has been discharged or released pursuant to Section 13.02 or 13.03 shall be revived and reinstated as though no deposit had occurred pursuant to this Article with respect to such Securities, until such time as the Trustee or Paying Agent is permitted to apply all money held in trust pursuant to Section 13.05 with respect to such Securities in accordance with this Article; provided, however, that if the Company makes any payment of principal of or any premium or interest on any such Security following such reinstatement of its obligations, the Company shall be subrogated to the rights (if any) of the Holders of such Securities to receive such payment from the money so held in trust.

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IN WITNESS WHEREOF, the parties hereto have caused this Indenture to be duly executed, and their respective corporate seals to be hereunto affixed and attested, all as of the day and year first above written.

MARATHON OIL CORPORATION
By:	/s/ John T. Mills
	John T. Mills
	Chief Financial Officer

JPMORGAN CHASE BANK
By:	/s/ John G. Jones
	John G. Jones
	Vice President and Trust Officer

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STATE OF TEXAS	§
	§
COUNTY OF HARRIS	§

On the 26th day of February, 2002, before me personally came John T. Mills, to me known, who, being by me duly sworn, did depose and say that he is Chief Financial Officer of Marathon Oil Corporation, one of the corporations described in and which executed the foregoing instrument; that he knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by authority of the Board of Directors of said corporation; and that he signed his name thereto by like authority.

/s/ Nancy J. Fischer

Notary Public

[NOTARIAL SEAL]

STATE OF TEXAS	§
	§
COUNTY OF HARRIS	§

On the 26th day of February, 2002, before me personally came John G. Jones, to me known, who, being by me duly sworn, did depose and say that he is a Vice President and Trust Officer of JPMorgan Chase Bank, one of the corporations described in and which executed the foregoing instrument; that he knows the seal of said corporation; that the seal affixed to said instrument is such corporate seal; that it was so affixed by authority of the Board of Directors of said corporation; and that he signed his name thereto by like authority.

/s/ Nikki N. Robertson

Notary Public

[NOTARIAL SEAL]

66

EX-12.1

Exhibit 12.1

Marathon Oil Corporation

Computation of Ratio of Earnings to Fixed Charges

TOTAL ENTERPRISE BASIS - Unaudited

(In millions)
	2013		2012		2011		2010		2009
Portion of rentals representing interest,	$	34	$	24	$	51	$	88	$	77
including discontinued operations
Capitalized interest,
including discontinued operations	27		68		208		410		441
Other interest and fixed charges,
including discontinued operations	295		236		239		105		160
Total fixed charges (A)	$	356	$	328	$	498	$	603	$	678
Earnings-pretax income with applicable adjustments (B)	$	5,288	$	6,449	$	4,723	$	3,607	$	3,163
Ratio of (B) to (A)	14.85		19.66		9.48		5.98		4.67

EX-21.1

Exhibit 21.1

Subsidiaries of Marathon Oil Corporation

Company Name	Country	Region
Alaska Transportation Service Company	United States	Delaware
Alba Associates LLC	Cayman Islands
Alba Equatorial Guinea Partnership, L.P.	United States	Delaware
Alba Plant LLC	Cayman Islands
Albian Sands Energy Inc.	Canada
Alchemix Corporation	United States	Arizona
Alvheim AS	Norway
Amethyst Calypso Pipeline LLC	United States	Delaware
AMPCO Marketing, L.L.C.	United States	Michigan
AMPCO Services, L.L.C.	United States	Michigan
Arctic Sun Shipping Company, Ltd.	United States	Delaware
Atlantic Methanol Associates LLC	Cayman Islands
Atlantic Methanol Production Company LLC	Cayman Islands
Beluga Pipe Line Company	United States	Delaware
CIGGS LLC	United States	Delaware
E.G. Global LNG Services, Ltd.	United States	Delaware
Eagle Sun Company Limited	Liberia
Equatorial Guinea LNG Company, S.A.	Equatorial Guinea
Equatorial Guinea LNG Holdings Limited	Bahamas
Equatorial Guinea LNG Operations, S.A.	Equatorial Guinea
Equatorial Guinea LNG Train 1, S.A.	Equatorial Guinea
FWA Equipment & Mud Company, Inc.	United States	Delaware
Glacier Drilling Company	United States	Delaware
Globex Energy, Inc.	United States	Delaware
GRT, Inc.	United States	Delaware
GTLI LLC	United States	Delaware
In-Depth Systems, Inc.	United States	Texas
Indonesia Kumawa Energy Limited	Cayman Islands
Kenai Kachemak Pipeline, LLC	United States	Alaska
Kenai Nikiski Pipeline LLC	United States	Delaware
Marathon Alaska Holding LLC	United States	Delaware
Marathon Alaska Natural Gas Company	United States	Delaware
Marathon Alaska Production LLC	United States	Delaware
Marathon Alpha Holdings LLC	United States	Delaware
Marathon Baja Limited	Cayman Islands
Marathon Canada Holdings Limited	Canada	Nova Scotia
Marathon Canada Petroleum ULC	Canada	Nova Scotia
Marathon Canada Production ULC	Canada	Alberta
Marathon Canadian Oil Sands Holding Limited	Canada	Alberta
Marathon Delta Holdings Limited	Cayman Islands
Marathon Delta Investment Limited	Cayman Islands
Marathon Dutch Investment B.V.	Netherlands
Marathon Dutch Investment Coöperatief U.A.	Netherlands
Marathon Dutch Investment LLC	United States	Delaware
Marathon E.G. Alba Limited	Cayman Islands
Marathon E.G. Holding Limited	Cayman Islands
Marathon E.G. International Limited	Cayman Islands
Marathon E.G. LNG Holding Limited	Cayman Islands
Marathon E.G. LPG Limited	Cayman Islands
Marathon E.G. Methanol Limited	Cayman Islands
Marathon E.G. Offshore Limited	Cayman Islands
Marathon E.G. Oil Operations Limited	Cayman Islands
Marathon E.G. Production Limited	Cayman Islands
Marathon Eagle Ford Midstream LLC	United States	Delaware
Marathon East Texas Holdings LLC	United States	Delaware

Marathon Ethiopia Limited B.V.	Netherlands
Marathon Exploration Tunisia, Ltd.	United States	Delaware
Marathon Financing Trust I	United States	Delaware
Marathon Financing Trust II	United States	Delaware
Marathon Gabon Holding, Ltd.	United States	Delaware
Marathon Global Services, Ltd.	United States	Delaware
Marathon Green B.V.	Netherlands
Marathon GTF Technology, Ltd.	United States	Delaware
Marathon Indonesia (Bone Bay) Limited	Cayman Islands
Marathon Indonesia (Kumawa) Limited	Cayman Islands
Marathon Indonesia Exploration Limited	Cayman Islands
Marathon Indonesia Holding Limited	Cayman Islands
Marathon Indonesia New Ventures Limited	Cayman Islands
Marathon International Oil (G.B.) Limited	United Kingdom	England and Wales
Marathon International Oil Angola Block 31 Limited	Cayman Islands
Marathon International Oil Angola Block 32 Limited	Cayman Islands
Marathon International Oil Blanco Limited	Cayman Islands
Marathon International Oil Canada, Ltd.	United States	Delaware
Marathon International Oil Company	United States	Delaware
Marathon International Oil Holdings LLC	United States	Delaware
Marathon International Oil Libya Limited	Cayman Islands
Marathon International Oil Morado Limited	Cayman Islands
Marathon International Oil Portfolio Coöperatief U.A.	Netherlands
Marathon International Oil Supply Company (G.B.) Limited	United Kingdom	England and Wales
Marathon International Oil Turquesa Limited	Cayman Islands
Marathon International Oil Ukraine Holding Limited	Cayman Islands
Marathon International Oil Ventures Limited	Cayman Islands
Marathon International Petroleum Asia Pacific Limited	Cayman Islands
Marathon International Petroleum Indonesia Limited	Cayman Islands
Marathon International Services Limited	Cayman Islands
Marathon International Upstream, Ltd.	United States	Delaware
Marathon Kenya Limited B.V.	Netherlands
Marathon LNG Marketing LLC	United States	Delaware
Marathon Methanol Holding LLC	United States	Delaware
Marathon Nigerian Ventures LLC	United States	Delaware
Marathon Norway Investment Coöperatief U.A.	Netherlands
Marathon Norway Investment LLC	United States	Delaware
Marathon Offshore Alpha Limited	Cayman Islands
Marathon Offshore Beta Limited	Cayman Islands
Marathon Offshore Delta Limited	Cayman Islands
Marathon Offshore Epsilon Limited	Cayman Islands
Marathon Offshore Investment Limited	Cayman Islands
Marathon Offshore Libya Service Company, Ltd.	United States	Delaware
Marathon Oil (East Texas) L.P.	United States	Texas
Marathon Oil (Suisse) SA	Switzerland
Marathon Oil (West Texas) L.P.	United States	Texas
Marathon Oil Canada Corporation	Canada	Alberta
Marathon Oil Cap Bon, Ltd.	United States	Delaware
Marathon Oil Company	United States	Ohio
Marathon Oil Decommissioning Services LLC	United States	Delaware
Marathon Oil Dutch Holdings B.V.	Netherlands
Marathon Oil Dutch Holdings Coöperatief U.A.	Netherlands
Marathon Oil Dutch Investment C.V.	Netherlands
Marathon Oil Eastern, Ltd.	United States	Delaware
Marathon Oil EF II LLC	United States	Delaware
Marathon Oil EF LLC	United States	Delaware
Marathon Oil Exploration (U.K.) Limited	United Kingdom	England and Wales
Marathon Oil Gabon LDC	Cayman Islands

Marathon Oil Holdings (Barbados) Inc.	Barbados
Marathon Oil Holdings U.K. Limited	United Kingdom	England and Wales
Marathon Oil International Holding C.V.	Netherlands
Marathon Oil International LLC	United States	Delaware
Marathon Oil Investment LLC	United States	Delaware
Marathon Oil Jenein Limited	Cayman Islands
Marathon Oil Jupiter Limited	Cayman Islands
Marathon Oil KDV B.V.	Netherlands
Marathon Oil Lapis Limited	Cayman Islands
Marathon Oil Libya Limited	Cayman Islands
Marathon Oil Norge AS	Norway
Marathon Oil North Sea (G.B.) Limited	United Kingdom	England and Wales
Marathon Oil Norway Holdings C.V.	Netherlands
Marathon Oil Norway Investment LLC	United States	Delaware
Marathon Oil Polska Sp. z o.o.	Poland
Marathon Oil Preferred Funding, Ltd.	United States	Delaware
Marathon Oil Salmagundi, Ltd.	United States	Delaware
Marathon Oil Sands (U.S.A.) Inc.	United States	Delaware
Marathon Oil Supply Company (U.S.) Limited	United Kingdom	England and Wales
Marathon Oil Switzerland B.V.	Netherlands
Marathon Oil Timor Gap East, Ltd.	United States	Delaware
Marathon Oil Timor Gap West, Ltd.	United States	Delaware
Marathon Oil U.K. LLC	United States	Delaware
Marathon Oil Upstream, Ltd.	United States	Delaware
Marathon Oil Venus Limited	Cayman Islands
Marathon Oil West of Shetlands Limited	United Kingdom	England and Wales
Marathon Petroleum Company (Norway) LLC	United States	Delaware
Marathon Portfolio International Limited	Cayman Islands
Marathon Service (G.B.) Limited	United Kingdom	England and Wales
Marathon Service Company	United States	Delaware
Marathon Upstream Gabon Limited	Cayman Islands
Marathon Upstream Nigeria Limited	Nigeria
Marathon Upstream North Sea (G.B.) Limited	United Kingdom	England and Wales
Marathon Upstream U.K. LLC	United States	Delaware
Marathon US Holdings Inc.	United States	Delaware
Marathon West Texas Holdings LLC	United States	Delaware
Marathon Western Saudi Arabia Limited	Cayman Islands
Miltiades Limited	United Kingdom	England and Wales
MOC Portfolio Delaware, Inc.	United States	Delaware
MP Ukraine Holding Limited	Cyprus
MWV Gas Gathering, Inc.	United States	Delaware
Navatex Gathering LLC	United States	Delaware
Oil Casualty Insurance, Ltd.	Bermuda
Old Main Assurance Ltd.	Bermuda
Palmyra Petroleum Company	Syrian Arab Republic
Pan Ocean Energy Company	United States	Delaware
Pennaco Energy, Inc.	United States	Delaware
Pheidippides Finance B.V.	Netherlands
Polar Eagle Shipping Company, Ltd.	United States	Delaware
Red Butte Pipe Line Company	United States	Delaware
SCAL Technology, Inc.	United States	Texas
Seaborn Properties LLC	United States	Delaware
Tarragon Resources (U.S.A.) Inc.	United States	Delaware
Texas Oil & Gas Corp.	United States	Delaware
Vermilion Energy Ireland Limited	Cayman Islands
Western Bluewater Resources (Trinidad) Limited	Trinidad and Tobago
Yorktown Assurance Corporation	United States	Vermont

EX-23.1

EXHIBIT 23.1

[PWC Letterhead]

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements listed below of Marathon Oil Corporation of our report dated February 27, 2014 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

On Form S-3 ASR:		Relating to:
File No.	333-168171	Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
	333-180014	Dividend Reinvestment and Direct Stock Purchase Plan
On Form S-8:		Relating to:
File No.	33-56828	Marathon Oil Company Thrift Plan
	333-29709	Marathon Oil Company Thrift Plan
	333-104910	Marathon Oil Corporation 2003 Incentive Compensation Plan
	333-143010	Marathon Oil Corporation 2007 Incentive Compensation Plan
	333-181301	Marathon Oil Corporation 2012 Incentive Compensation Plan

\s\ PricewaterhouseCoopers LLP

Houston, Texas

February 27, 2014

EX-23.2

EXHIBIT 23.2

[Letterhead of “GLJ Petroleum Consultants LTD.”]

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS

We hereby consent to the references in this Annual Report on Form 10-K of Marathon Oil Corporation ("the Company"), to our summary reports on audits of the estimated quantities of certain proved reserves of oil and gas, net to the Company's interest, and to such report and this consent being filed as exhibits to this Form 10-K. We also consent to the incorporation by reference of such reports in the Registration Statements indicated below.

Form S-3ASR:	Relating to:
Reg. No.	333-168171	Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
	333-180014	Dividend Reinvestment and Direct Stock Purchase Plan
Form S-8:	Relating to:
Reg. No.	33-56828	Marathon Oil Company Thrift Plan
	333-29709	Marathon Oil Company Thrift Plan
	333-104910	Marathon Oil Corporation 2003 Incentive Compensation Plan
	333-143010	Marathon Oil Corporation 2007 Incentive Compensation Plan
	333-181301	Marathon Oil Corporation 2012 Incentive Compensation Plan

Yours truly,

GLJ PETROLEUM CONSULTANTS LTD.

“Originally Signed By”

Tim R. Freeborn, P. Eng.

Manager, Engineering

Calgary, Alberta

February 26, 2014

EX-23.3

EXHIBIT 23.3

[Letterhead of “Ryder Scott Company, L.P.”]

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the references in this Annual Report on Form 10-K of Marathon Oil Corporation ("the Company"), to our summary reports on audits of the estimated quantities of certain proved reserves of oil and gas, net to the Company's interest, and to such report and this consent being filed as exhibits to this Form 10-K. We also consent to the incorporation by reference of such reports in the Registration Statements indicated below.

Form S-3ASR:	Relating to:
Reg. No.	333-168171	Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants and Stock Purchase Contracts/Units
	333-180014	Dividend Reinvestment and Direct Stock Purchase Plan
Form S-8:	Relating to:
Reg. No.	33-56828	Marathon Oil Company Thrift Plan
	333-29709	Marathon Oil Company Thrift Plan
	333-104910	Marathon Oil Corporation 2003 Incentive Compensation Plan
	333-143010	Marathon Oil Corporation 2007 Incentive Compensation Plan
	333-181301	Marathon Oil Corporation 2012 Incentive Compensation Plan

/s/ RYDER SCOTT COMPANY, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

February 26, 2014

EX-23.4

[Letterhead of Netherland, Sewell & Associates, Inc.]

EXHIBIT 23.4

CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS

We hereby consent to the references in this Annual Report on Form 10-K of Marathon Oil Corporation ("the Company"), to our summary report on the estimated quantities of certain proved reserves of oil and gas and to such report and this consent being filed as exhibits to this Form 10‑K. We also consent to the incorporation by reference of such reports in the Registration Statements indicated below.

On Form S-3ASR:		Relating to:
Reg. No.	333-168171	Marathon Oil Corporation Debt Securities, Common Stock, Preferred Stock, Warrants, and Stock Purchase Contracts/Units
	333-180014	Dividend Reinvestment and Direct Stock Purchase Plan
On Form S-8:		Relating to:
Reg. No.	33-56828	Marathon Oil Company Thrift Plan
	333-29709	Marathon Oil Company Thrift Plan
	333-104910	Marathon Oil Corporation 2003 Incentive Compensation Plan
	333-143010	Marathon Oil Corporation 2007 Incentive Compensation Plan
	333-181301	Marathon Oil Corporation 2012 Incentive Compensation Plan

NETHERLAND, SEWELL & ASSOCIATES, INC.

/s/ Danny D. Simmons

By: ___________________________________

Danny D. Simmons, P.E.

President and Chief Operating Officer

Houston, Texas

February 26, 2014

EX-31.1

Exhibit 31.1

MARATHON OIL CORPORATION

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

I, Lee M. Tillman, certify that:

1. I have reviewed this report on Form 10-K of Marathon Oil Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

February 28, 2014	/s/ Lee M. Tillman
	Lee M. Tillman
	President and Chief Executive Officer

EX-31.2

Exhibit 31.2

MARATHON OIL CORPORATION

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

I, John R. Sult, certify that:

1.I have reviewed this report on Form 10-K of Marathon Oil Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

February 28, 2014	/s/ John R. Sult
	John R. Sult
	Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Marathon Oil Corporation (the “Company”) on Form 10-K for the period ending December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Lee M. Tillman, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 28, 2014

/s/ Lee M. Tillman

Lee M. Tillman

President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Marathon Oil Corporation (the “Company”) on Form 10-K for the period ending December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, John R. Sult, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

February 28, 2014

/s/ John R. Sult

John R. Sult

Executive Vice President and Chief Financial Officer

EX-99.1

EXHIBIT 99.1

January 29, 2014

Project 1132297

The Board of Directors of Marathon Oil Corporation

Marathon Oil Corporation

2400, 440 - 2^nd Avenue SW

Calgary, Alberta T2P 5E9

Dear Board Members:

Re:Third Party Report on Reserves

This report was prepared to satisfy requirements contained in Item 1202(a)(8) of U.S. Securities and Exchange Commission Regulation S-K and to provide the qualifications of the technical persons responsible for overseeing the reserve estimation process.

The numbering of items below corresponds to the requirements set out in Item 1202(a)(8) of Regulation S-K. Terms to which a meaning is ascribed in Regulation S-K and Regulation S-X have the same meaning in this report.

i. We have prepared an independent evaluation of the Canadian mineable oil sands reserves of Marathon Oil Corporation (the "Company") for the management and the board of directors of the Company. The primary purpose of our evaluation report was to provide estimates of reserves information in support of the Company’s year-end reserves reporting requirements under US Securities Regulation S-K and for other internal business and financial needs of the Company.

ii. We have evaluated and reviewed certain reserves of the Company as at December 31, 2013. The completion (transmittal) date of our report is January 29, 2014.

iii. The following table sets forth the total proved net after royalty reserves under constant prices and costs covered by our report by geographic area, and the proportion of the Company covered.

	Oil and NGL	Natural Gas	Synthetic Crude Oil1	Oil Equivalent2
Location	MMbbl	Bcf	MMbbl	MMbbl
Canada			680	680
Total Company Reserves3	1,046	2,671	680	2,171
Portion of Total Covered	0%	0%	100%	31%

The Company provided to us the total Company reported reserves to derive the portion evaluated by GLJ. We express no opinion on this portion of the Company’s reserves that we did not evaluate.

iv. Our report covered 100 percent of the Company’s mineable, synthetic crude oil (SCO) reserves; our evaluation coverage from the perspective of the Company’s total reserves is provided above in item iii. We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the "COGE Handbook") with the necessary modifications to reflect definitions and standards under the U.S. Financial Accounting Standards Board policies (the “FASB Standards”) and the legal requirements under the U.S. Securities and Exchange Commission (“SEC requirements”).

The royalty obligations on the evaluated oil sands property, the Athabasca Oil Sands Project (AOSP), are determined upstream, on a bitumen basis. There are two royalty projects, one for Muskeg River Mine operations and one for Jackpine Mine operations. The synthetic crude oil (SCO) reserves reflect both the upgrading yield on bitumen and product value differences between SCO and bitumen. As a consequence of differences in revenue, the royalty rate for SCO is lower than it is on bitumen. No reserves are attributed to internally produced products that are consumed as fuel.

The economic evaluation was prepared to reflect the net present value of Marathon Oil Canada Corporation (MOCC) before any incremental US taxes. Canadian income taxes were included, as well as MOCC supplied estimates of Calgary Office overhead and abandonment and reclamation obligations.

Data used in our evaluation were obtained from regulatory agencies, public sources and from Company personnel and Company files. In the preparation of our report we have accepted as presented, and have relied, without independent verification, upon a variety of information furnished by the Company such as interests and burdens, recent production, product transportation and marketing and sales agreements, historical revenue, capital costs, operating expense data, budget forecasts, capital cost estimates and well data for recently drilled wells. If in the course of our evaluation, the validity or sufficiency of any material information was brought into question, we did not rely on such information until such concerns were satisfactorily resolved.

The Company has warranted in a representation letter to us that, to the best of the Company’s knowledge and belief, all data furnished to us was accurate in all material respects, and no material data relevant to our evaluation was omitted.

A field examination of the evaluated property was not performed nor was it considered necessary for the purposes of our report.

In our opinion, estimates provided in our report have, in all material respects, been determined in accordance with the applicable industry standards, and results provided in our report and summarized herein are appropriate for inclusion in filings under Regulation S-K.

v. As required under SEC Regulation S-K, reserves are those quantities of oil and gas that are estimated to be economically producible under existing economic conditions. As specified, in determining economic production, constant product reference prices have been based on a 12 month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12 month period prior to the effective date of our report. In our economic analysis, operating and capital costs are those costs estimated as applicable at the effective date of our report, with no future escalation. Where deemed appropriate, the capital costs and revised operating costs associated with the implementation of committed projects designed to modify specific field operations in the future may be included in economic projections.

vi. Our report has been prepared assuming the continuation of existing regulatory and fiscal conditions subject to the guidance in the COGE Handbook and SEC regulations. Notwithstanding that the Company currently has regulatory approval to produce the reserves identified in our report, there is no assurance that changes in regulation will not occur; such changes, which cannot reliably be predicted, could impact the Company’s ability to recover the estimated reserves.

vii. Oil and gas reserves estimates have an inherent degree of associated uncertainty, the degree of which is affected by many factors. Reserves estimates will vary due to the limited and imprecise nature of data upon which the estimates of reserves are predicated. Moreover, the methods and data used in estimating reserves are often necessarily indirect or analogical in character rather than direct or deductive. Furthermore, the persons involved in the preparation of reserves estimates and associated information are required, in applying geosciences, engineering and evaluation principles, to make numerous unbiased judgments based upon their educational background, professional training, and professional experience. The extent and significance of the judgments to be made are, in themselves, sufficient to render reserves estimates inherently imprecise.Reserves estimates may change substantially as additional data becomes available and as economic conditions impacting oil and gas prices and costs change. Reserves estimates will also change over time due to other factors such as knowledge and technology, fiscal and economic conditions, and contractual, statutory and regulatory provisions.

viii. In our opinion, the reserves information evaluated by us have, in all material respects, been determined in accordance with all appropriate industry standards, methods and procedures applicable for the filing of reserves information under U.S. SEC Regulation S-K.

ix. A summary of the Company reserves evaluated by us was provided for item iii. Of the 680 MMbbl SCO total proved net after royalty reserves evaluated by us, 674 MMbbl SCO are proved developed and 6 MMbbl SCO are proved undeveloped.

GLJ is a private firm established in 1972 whose business is the provision of independent geological and engineering services to the petroleum industry. GLJ is among the largest evaluation firms in North America with approximately 70 engineering and geoscience personnel. GLJ evaluates the reserves of the four producing integrated oil sands mining operations for various owners. Mr. Willmon and Mr. Freeborn conducted the evaluation. Both individuals are qualified, independent reserves evaluators as defined in COGEH, and are registered Practicing Professional Engineers in the Province of Alberta. Mr. Willmon has in excess of 35 years of practical experience in petroleum engineering, has been employed at GLJ as an

evaluator/auditor since 1982, and has been involved in evaluations of surface mineable oil sands reserves since 1986. Mr. Freeborn has in excess of 13 years of practical experience in petroleum engineering, and has been employed at GLJ as an evaluator/auditor since 1999, and has been involved in evaluations of surface mineable oil sands reserves since 2009.

We trust this meets your current requirements.

Yours truly,

GLJ PETROLEUM CONSULTANTS LTD.

“ORIGINALLY SIGNED BY”

Tim R. Freeborn, P. Eng.

“ORIGINALLY SIGNED BY”

James H Willmon, P. Eng.

Vice President

TRF/JHW/ljn

EX-99.4

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Exhibit 99.4

January 14, 2014                

Marathon Oil Corporation

5555 San Felipe Road

Houston, Texas 77056

Ladies and Gentlemen:

In accordance with your request, we have prepared a reserves certification and deliverability analysis, as of December 31, 2012, for Alba Field, located offshore Equatorial Guinea. Pursuant to the terms of the Gas Purchase and Sales Agreement (GPSA) between the Alba Field Production Sharing Contract (PSC) contractors (referred to herein as the "Alba Field owners") and Atlantic Methanol Production Company (AMPCO), the primary purpose of this report is to verify, using field downtime and gas disposition assumptions specified by Marathon Oil Corporation (Marathon), that there are (1) sufficient proved (1P) reserves in Alba Field to cover delivery of gas from the Alba Field owners to AMPCO equal to 100 percent of the stated maximum daily quantities over the remaining term of the GPSA that ends May 3, 2026, and (2) sufficient proved developed (PD) reserves in Alba Field to deliver, for a period of five years, 102 percent of the maximum daily contract quantity. The maximum daily contract quantity stipulated in the most recent amendment to the GPSA is 145,000 MMBTU per day, but the annual average daily contract quantity shall not exceed 135,000 MMBTU per day, or approximately 139 million cubic feet of gas per day (MMCFD). For the purposes of this report, we consider the maximum daily contract quantity to be 135,000 MMBTU. Economic analysis was performed only to confirm economic producibility and determine economic limits for the properties. Monetary values shown in this report are expressed in United States dollars ($). For each reserves category, the economic life of the field is either the economic limit or the end of the GPSA, May 3, 2026, whichever is earliest.

We completed our evaluation on or about March 5, 2013. It is our understanding that Marathon's share of the gross (100 percent) proved reserves estimated in this report constituted approximately 17 percent of all proved reserves owned by Marathon, as of December 31, 2012. The estimates in this report have been prepared in accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and conform to the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas. Definitions are presented immediately following this letter. This report has been prepared for Marathon's use in filing with the SEC; in our opinion the assumptions, data, methods, and procedures used in the preparation of this report are appropriate for such purpose, provided that, as required by the SEC, Marathon lists its net interest after application of the PSC terms.

We estimate the gross (100 percent) reserves in Alba Field, as of December 31, 2012, to be:

	Gross (100 Percent) Reserves
	Gas	Condensate	LPG
Category	(BCF)	(MMBBL)	(MMBBL)
Proved Developed (PD)	1,878	87	44
Proved (1P)	2,611	117	62

Gas volumes are dry gas and are expressed in billions of cubic feet (BCF) at standard temperature and pressure bases. Condensate and liquefied petroleum gas (LPG) volumes are expressed in millions of barrels (MMBBL); a barrel is equivalent to 42 United States gallons.

The estimates shown in this report are for proved developed producing and proved undeveloped reserves. Our study indicates that there are no proved developed non-producing reserves for these properties at this time. No study was made to determine whether probable or possible reserves might be established for these properties.

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The estimates of proved undeveloped reserves included in this report are dependent on the installation of an offshore compression platform in 2016, the substantial investment for which prohibits us from categorizing these reserves as PD. Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on development and production status. The estimates of reserves included herein have not been adjusted for risk. In this report, we have attributed estimated gas sales volumes and LPG reserves to Alba Field, even though the LPG plant is separate from the field facilities. This designation is based on our interpretation of the agreement between the Alba Field owners and the LPG plant owners that states that title to the feedstock gas sales volumes and LPG liquids is transferred from the Alba Field owners at the tailgate of the LPG plant and that those volumes are valued on an MMBTU basis. It is our understanding that this interpretation is consistent with Marathon's internal reserves booking practice for Alba Field.

In order to satisfy the primary objective of this report, we made certain assumptions regarding future field production and injection rates. The most significant assumption pertains to the feed rate of Alba Field gas to the LNG plant. Three LNG plant feed scenarios have been considered: a low-take case, a mid-take case, and a high-take case. The LNG plant low-take case ranges from 519 to 560 MMCFD, the mid-take case ranges from 519 to 600 MMCFD, and the high-take case ranges from 519 to 628 MMCFD. The high-take case LNG plant feed volumes are based on Marathon's current projection of volumes to be utilized over the next five years. The estimates of reserves shown in this report are based on the high-take case because this case is the most representative of current operating conditions. For the purposes of this report, we define the period during which all forecasted supply targets can be met to be the supply plateau period.

For all cases presented in this report, following the end of the supply plateau period we have reduced supply to the LNG plant prior to reducing supply to the AMPCO methanol plant. Our estimates are based on annual gas rate constraints and annual downtime averages and do not account for any operational or contractual issues that may arise on a day-to-day basis throughout the year. For all three LNG plant feed scenarios, we have determined that there are (1) sufficient 1P reserves to supply the AMPCO methanol plant until termination of the GPSA and (2) sufficient PD reserves to supply the AMPCO methanol plant with 102 percent of the maximum daily contract quantity for a period of five years.

For our study, we had access to certain data and analyses provided by Marathon that were initially presented to us in various reviews and meetings held from June through September 2003. We have received updated data on an annual basis for the purposes of performing an audit of Alba Field reserves on behalf of Noble Energy, Inc. We have also received periodic updates on development plans and the latest analysis done by Marathon. Most recently, this update consisted of a review held in January 2013, where Marathon presented its most recent outlook for Alba. The information and data received to date include, but are not limited to, a geological and geophysical review of Marathon's interpretation of the Alba Field area, limited structure and amplitude maps, formation test results and fluid gradient analysis, petrophysical methodology, fluid property analysis methodology, and potential future development plans. We were provided a digital backup of a Landmark OpenWorks project (3‑D seismic data), multiple interpreted seismic horizons, routine and special core analysis data, pressure data, fluid and laboratory analysis reports and subsequent fluid property analysis, digital log data, capillary pressure data, and historical production data.

Our study is an update of previous work that consisted of (1) a geophysical and geological review of the Alba Reservoir; (2) a review of structure and generation of gross isopach maps; (3) a petrophysical analysis of net hydrocarbon pay, porosity, and connate water saturation; (4) a review of pressure and temperature properties as well as fluid properties using existing fluid laboratory analysis and black oil correlations; (5) the generation of proved estimates of wet gas-in-place, dry gas-in-place, condensate-in-place, and LPG-in-place; (6) a reservoir simulation to derive estimates of dry gas, condensate, and LPG recoveries; (7) a review of contractual sales and deliverability obligations for Alba Field, the Alba LPG plant, the LNG plant, and the methanol plant; (8) the generation of production profiles for primary and secondary condensate, LPG, offshore and onshore fuel and flare gas, gas used by the LPG and methanol plants, and remaining gas available for the LNG plant; and (9) a review of economic terms of the Alba PSC and LPG plant contracts. For this study, we have incorporated new

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production and pressure data into the simulation history matching process and the latest development plans into the simulation prediction cases.

Gas, condensate, and LPG prices were used only to confirm economic producibility and determine economic limits for the properties. The gas price used is the fixed contract price of $0.25 per MMBTU and is adjusted for energy content. Condensate and LPG prices are based on the 12-month unweighted arithmetic average of the first-day-of-the-month Dated Brent spot price for each month in the period January through December 2012. The average price of $110.63 per barrel is adjusted for quality and a regional price differential. All prices are held constant throughout the lives of the properties. The average adjusted product prices weighted by production over the remaining lives of the properties are $0.243 per MCF of gas, $106.58 per barrel of condensate, and $68.24 per barrel of LPG.

Costs were used only to confirm economic producibility and determine economic limits for the properties. Operating costs used in this report are based on operating expense records of Marathon, the operator of the properties. As requested, operating costs are limited to direct platform-, plant-, and field-level costs and Marathon's estimate of the portion of its headquarters general and administrative overhead expenses necessary to operate the properties. Operating costs have been divided into field-level costs, plant-level costs, per-well costs, and per-unit-of-production costs. Capital costs used in this report were provided by Marathon and are based on its internal planning budgets. Capital costs are included as required for installation of an offshore compression platform and production equipment. Based on our understanding of future development plans, a review of the records provided to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable. Operating costs and capital costs are not escalated for inflation.

For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the mechanical operation or condition of the wells and facilities. We have not investigated possible environmental liability related to the properties.

The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be estimated with reasonable certainty to be economically producible; probable and possible reserves are those additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based on certain assumptions including, but not limited to, that the properties will be developed consistent with current development plans, that the properties will be operated in a prudent manner, that no governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover the reserves, and that our projections of future production will prove consistent with actual performance. If the reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the estimated amounts used to confirm economic producibility and determine economic limits for the properties. Because of governmental policies and uncertainties of supply and demand, the sales rates, prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made while preparing this report.

For the purposes of this report, we used technical and economic data including, but not limited to, well logs, geologic maps, seismic data, well test data, production data, historical price and cost information, and property ownership interests.The reserves in this report have been estimated using deterministic methods; these estimates have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a combination of methods, including performance analysis, volumetric analysis, and reservoir modeling, that we considered to be appropriate and necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.

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The data used in our estimates were obtained from Marathon and the nonconfidential files of Netherland, Sewell & Associates, Inc. and were accepted as accurate. Supporting work data are on file in our office. We have not examined the contractual rights to the properties or independently confirmed the actual degree or type of interest owned. The technical persons responsible for preparing the estimates presented herein meet the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE Standards. We are independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these properties nor are we employed on a contingent basis.

Sincerely,

NETHERLAND, SEWELL & ASSOCIATES, INC.

Texas Registered Engineering Firm F-2699

/s/ C.H. (Scott) Rees III

By:

C.H. (Scott) Rees III, P.E.

Chairman and Chief Executive Officer

/s/ John R. Cliver/s/ Patrick L. Higgs

By:By:

John R. Cliver, P.E. 107216Patrick L. Higgs, P.G. 985

Vice PresidentVice President

Date Signed: January 14, 2014Date Signed: January 14, 2014

JRC:JLM

Please be advised that the digital document you are viewing is provided by Netherland, Sewell & Associates, Inc. (NSAI) as a convenience to our clients. The digital document is intended to be substantively the same as the original signed document maintained by NSAI. The digital document is subject to the parameters, limitations, and conditions stated in the original document. In the event of any differences between the digital document and the original document, the original document shall control and supersede the digital document.

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4‑10(a). Also included is supplemental information from (1) the 2007 Petroleum Resources Management System approved by the Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas, and (3) the SEC's Compliance and Disclosure Interpretations.

(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.

(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties, reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the following characteristics with the reservoir of interest:

(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);

(ii) Same environment of deposition;

(iii) Similar geological structure; and

(iv) Same drive mechanism.

Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the reservoir of interest.

(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.

(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation procedure.

(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) 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; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Supplemental definitions from the 2007 Petroleum Resources Management System:

Developed Producing Reserves - Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate. Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves - Developed Non-Producing Reserves include shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not yet started producing, (2) wells which were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future recompletion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Definitions - Page 1 of 7

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves.

(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.

(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems.

(iv) Provide improved recovery systems.

(8) Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

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

(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this section.

(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and cumulative production as of that date.

(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and applicable operating costs of support equipment and facilities and other costs of exploration activities, are:

(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies, and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively, these are sometimes referred to as geological and geophysical or "G&G" costs.

(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal costs for title defense, and the maintenance of land and lease records.

(iii) Dry hole contributions and bottom hole contributions.

(iv) Costs of drilling and equipping exploratory wells.

(v) Costs of drilling exploratory-type stratigraphic test wells.

(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well as those items are defined in this section.

(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.

Definitions - Page 2 of 7

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.

(16) Oil and gas producing activities.

(i) Oil and gas producing activities include:

(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural states and original locations;

(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing the oil or gas from such properties;

(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs, including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such as:

(1) Lifting the oil and gas to the surface; and

(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and

(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities undertaken with a view to such extraction.

Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point", which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be appropriate to regard the terminal point for the production function as:

a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a refinery, or a marine terminal; and

b. In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into synthetic oil or gas.

Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.

(ii) Oil and gas producing activities do not include:

(A) Transporting, refining, or marketing oil and gas;

(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant that does not have the legal right to produce or a revenue interest in such production;

(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which synthetic oil and gas can be extracted; or

(D) Production of geothermal steam.

(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable reserves.

(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus possible reserves estimates.

Definitions - Page 3 of 7

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by a defined project.

(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than the recovery quantities assumed for probable reserves.

(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented, including comparisons to results in successful similar projects.

(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in communication with the proved reservoir.

(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.

(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.

(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.

(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally higher than the proved area if these areas are in communication with the proved reservoir.

(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery of the hydrocarbons in place than assumed for proved reserves.

(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.

(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full range of possible outcomes and their associated probabilities of occurrence.

(20) Production costs.

(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

(A) Costs of labor to operate the wells and related equipment and facilities.

(B) Repairs and maintenance.

(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities.

Definitions - Page 4 of 7

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.

(E) Severance taxes.

(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil and gas producing activities, their depreciation and applicable operating costs become exploration, development or production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and development costs are not production costs but also become part of the cost of oil and gas produced along with production (lifting) costs identified above.

(21) Proved area. The part of a property to which proved reserves have been specifically attributed.

(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

(23) Proved properties. Properties with proved reserves.

(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90%

Definitions - Page 5 of 7

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DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

probability that the quantities actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.

(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas:

932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the following shall be disclosed as of the end of the year:

a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)

b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer of those reserves (see paragraph 932-235-50-7).

The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be combined for reporting purposes.

932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:

a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent provided by contractual arrangements in existence at year-end.

b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall be presented separately from estimated production costs.

c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.

d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future income tax expenses from future cash inflows.

e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future net cash flows relating to proved oil and gas reserves.

f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed discount.

(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Definitions - Page 6 of 7

[NSAI Company Logo]

DEFINITIONS OF OIL AND GAS RESERVES

Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)

(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include both discovered and undiscovered accumulations.

(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection, observation, or injection for in-situ combustion.

(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production. The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in a known area.

(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are reserves of any category 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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):

Although several types of projects - such as constructing offshore platforms and development in urban areas, remote locations or environmentally sensitive locations - by their nature customarily take a longer time to develop and therefore often do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception, and not the rule.

Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though development may extend past five years include, but are not limited to, the following:

• The company's level of ongoing significant development activities in the area to be developed (for example, drilling only the minimum number of wells necessary to maintain the lease generally would not constitute significant development activities);

• The company's historical record at completing development of comparable long-term projects;

• The amount of time in which the company has maintained the leases, or booked the reserves, without significant development activities;

• The extent to which the company has followed a previously adopted development plan (for example, if a company has changed its development plan several times without taking significant steps to implement any of those plans, recognizing proved undeveloped reserves typically would not be appropriate); and

• The extent to which delays in development are caused by external factors related to the physical operating environment (for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by internal factors (for example, shifting resources to develop properties with higher priority).

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

(32) Unproved properties. Properties with no proved reserves.

Definitions - Page 7 of 7

EX-99.7

Exhibit 99.7

MARATHON OIL CORPORATION

Estimated

Future Reserves

Attributable to Certain

Leasehold Interests

and

Derived Through Certain Production Sharing Contracts

SEC Parameters

As of

December 31, 2012

\s\ Jeffrey D. Wilson

Jeffery D. Wilson, P.E.

TBPE License No. 86426

Managing Senior Vice President

[SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

[Ryder Scott Company Logo]

January 20, 2014

Marathon Oil Corporation

5555 San Felipe

P.O. Box 3128

Houston, Texas 77253-3128

Gentlemen:

At the request of Marathon Oil Corporation (Marathon), Ryder Scott Company, L.P. (Ryder Scott) has conducted a reserves audit of the estimates of the proved reserves as of December 31, 2012 prepared by Marathon’s engineering and geological staff based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party reserves audit, completed on October 17, 2013 and presented herein, was prepared for public disclosure by Marathon in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations. The estimated reserves shown herein represent Marathon’s estimated net reserves attributable to the leasehold interests and derived through certain production sharing contracts in certain properties owned by Marathon and the portion of those reserves reviewed by Ryder Scott, as of December 31, 2012. The properties reviewed by Ryder Scott incorporate Marathon reserve determinations and are located in the states of Texas and North Dakota and in Libya.

The properties reviewed by Ryder Scott account for a portion of Marathon’s total net proved reserves as of December 31, 2012. Based on the estimates of total net proved reserves prepared by Marathon, the reserves audit conducted by Ryder Scott addresses 22 percent of the total proved developed net liquid hydrocarbon reserves, 8 percent of the total proved developed net gas reserves, 75 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 30 percent of the total proved undeveloped net gas reserves of Marathon.

As prescribed by the Society of Petroleum Engineers in Paragraph 2.2(f) of the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (SPE auditing standards), a reserves audit is defined as “the process of reviewing certain of the pertinent facts interpreted and assumptions made that have resulted in an estimate of reserves prepared by others and the rendering of an opinion about (1) the appropriateness of the methodologies employed; (2) the adequacy and quality of the data relied upon; (3) the depth and thoroughness of the reserves estimation process; (4) the classification of reserves appropriate to the relevant definitions used; and (5) the reasonableness of the estimated reserve quantities.”

Based on our review, including the data, technical processes and interpretations presented by Marathon, it is our opinion that the overall procedures and methodologies utilized by Marathon in preparing their estimates of the proved reserves as of December 31, 2012 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Marathon are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

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Marathon Oil Corporation

January 20, 2014

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The estimated reserves presented in this report are related to hydrocarbon prices. Marathon has informed us that in the preparation of their reserve and income projections, as of December 31, 2012, they used average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary significantly from the prices required by SEC regulations; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The net reserves as estimated by Marathon attributable to Marathon's interest in properties that we reviewed are summarized as follows:

SEC PARAMETERS

Estimated Net Reserves

Attributable to Certain Leasehold Interests and

Derived Through Certain Production Sharing Contracts of

Marathon Oil Corporation

As of December 31, 2012

	Proved
			Total
	Developed	Undeveloped	Proved
Net Reserves of Properties Audited by Ryder Scott
Oil/Condensate - MBarrels	240,042	238,102	478,144
Plant Products - MBarrels	20,948	48,396	69,344
Gas - MMCF	137,054	339,351	476,405
MBOE	283,832	343,057	626,889

Liquid hydrocarbons are expressed in thousands of standard 42 gallon barrels (MBarrels). All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMCF) at the official temperature and pressure bases of the areas in which the gas reserves are located. The net remaining reserves are also shown herein on an equivalent unit basis wherein natural gas is converted to oil equivalent using a factor of 6,000 cubic feet of natural gas per one barrel of oil equivalent. MBOE means thousands barrels of oil equivalent.

Reserves Included in This Report

In our opinion, the proved reserves presented in this report conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “Petroleum Reserves Definitions” is included as an attachment to this report.

The various proved reserve status categories are defined under the attachment entitled “Petroleum Reserves Status Definitions and Guidelines” in this report. The proved reserves included herein consist of the developed and undeveloped categories.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of

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reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Marathon’s request, this report addresses only the proved reserves attributable to the properties reviewed herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves when based on deterministic methods as a “high degree of confidence that the quantities will be recovered.”

Provedreserve estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered could be more or less than the estimated amounts.

Audit Data, Methodology, Procedure and Assumptions

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods; (2) volumetric-based methods; and (3) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserve evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserve quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserve category assigned by the evaluator. Therefore, it is the categorization of reserve quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely than not to be achieved.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that

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“possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserve category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserve categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserve categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated primarily by performance-based methods and analogy. All of the proved reserves attributable to producing wells and/or reservoirs were estimated by performance methods. These performance methods include, but may not be limited to, decline curve and other production analysis. These analyses utilized extrapolations of historical production data available through December 2012 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Marathon or obtained from public data sources and were considered sufficient for the purpose thereof.

The undeveloped reserves were estimated by analogy to the historical performance of mature areas within each unit or field where these analogues were applied. These estimates were also verified with volumetrics as a secondary method in certain cases. Data was furnished to Ryder Scott by Marathon or obtained from public data sources that were available through December 2012. The data utilized from theanalogues were considered sufficient for the purpose thereof.

The fields located in Texas and North Dakota are oil shales and are developed almost entirely using horizontal drilling technology.

For the Libyan properties, reserves estimated to be produced beyond the current contract life were not included in the reported volumes. Additionally, those properties are also subject to OPEC restrictions. These restrictions can effect reserve volumes due to the limited contract life. As of the effective date of this report, Marathon has estimated the effects of these restrictions in their reserve estimates; however those adjustments have been excluded from this report. Marathon’s estimate of these volumes is not material (i.e. less than five percent).

To estimate economically recoverable proved oil and gas reserves, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in conducting this review.

As stated previously, proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. To confirm that the proved reserves

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January 20, 2014

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reviewed by us meet the SEC requirements to be economically producible, we have reviewed certain primary economic data utilized by Marathon relating to hydrocarbon prices and costs as noted herein.

The hydrocarbon prices furnished by Marathon for the properties reviewed by us are based on SEC price parameters using the average prices during the 12-month period prior to the ending date of the period covered in this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

The initial SEC hydrocarbon prices in effect on December 31, 2012 for the properties reviewed by us were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used by Marathon for the geographic areas reviewed by us. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used by Marathon to determine the future gross revenue for each property reviewed by us reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used by Marathon were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Marathon.

The table below summarizes Marathon’s net volume weighted benchmark prices adjusted for differentials for the properties reviewed by us and referred to herein as Marathon’s “average realized prices.” The average realized prices shown in the table below were determined from Marathon’s estimate of the total future gross revenue before production taxes and Marathon’s estimate of the total net reserves for the geographic area. The data shown in the table below is presented in accordance with SEC disclosure requirements for each of the geographic areas reviewed by us.

Geographic Area	Price Reference	Price Reference	Average Benchmark Prices	Average Realized Prices
North America
United States	Oil/Condensate	WTI Cushing	$94.71/Bbl	$102.71/Bbl
	NGL	Propane, Mont Belvieu	$43.24/Bbl	$28.41/Bbl
	Gas	Henry Hub	$2.81/MCF	$2.76/MCF
Libya	Oil/Condensate	Brent	$111.21/Bbl	$111.51/Bbl
	Gas	Contract	NA	$6.71/Mcf

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in Marathon’s individual property evaluations.

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Marathon Oil Corporation

January 20, 2014

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Accumulated gas production imbalances, if any, were not taken into account in the proved gas reserve estimates reviewed. The proved gas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Operating costs furnished by Marathon are based on the operating expense reports of Marathon and include only those costs directly applicable to the leases or wells for the properties reviewed by us. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. Where applicable operating costs were included for transportation, tariffs and/or processing fees. The operating costs furnished by Marathon were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Marathon. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs furnished by Marathon are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished by Marathon were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Marathon.

The proved developed (non-producing) and undeveloped reserves for the properties reviewed by us have been incorporated herein in accordance with the operator’s plans to develop these reserves as of December 31, 2012. The implementation of the operator’s development plans as presented to us is subject to the approval process adopted by Marathon’s management. As the result of our inquiries during the course of our review, Marathon has informed us that the development activities for the properties reviewed by us have been subjected to and received the internal approvals required by Marathon’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Marathon. Additionally, Marathon has informed us that they are not aware of any legal, regulatory, political or economic obstacles that would significantly alter their plans.

Current costs used by Marathon were held constant throughout the life of the properties.

The net reserves for the Libya properties are derived through a concession agreement, and as such are directly impacted by the cost and price assumptions applied herein. The concession terms were supplied by Marathon and accepted as factual data and reviewed for their reasonableness. We have not conducted a detailed review of the contract or Marathon’s interpretation and/or application of the contract terms.

Marathon’s forecasts of future production rates are based on historical performance from wells currently on production. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied to depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used by Marathon to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Marathon. Wells or locations that are not currently producing may start producing earlier or later than anticipated in

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Marathon’s estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

The proved reserves reported herein are limited to the period prior to expiration of current contracts providing the legal right to produce or a revenue interest in such production. Reserves associated with contract extension in Libya were not included. Furthermore, properties in the different countries may be subjected to significantly varying contractual fiscal terms that affect the net revenue to Marathon for the production of these volumes. The prices and economic return received for these net volumes can vary significantly based on the terms of these contracts. Therefore, when applicable, Ryder Scott reviewed the fiscal terms of such contracts and discussed with Marathon the net economic benefit attributed to such operations for the determination of the net hydrocarbon volumes and income thereof. Ryder Scott has not conducted an exhaustive audit or verification of such contractual information. Neither our review of such contractual information nor our acceptance of Marathon’s representations regarding such contractual information should be construed as a legal opinion on this matter.

Ryder Scott did not evaluate the country and geopolitical risks in the countries where Marathon operates or has interests. Marathon’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons including the granting, extension or termination of production sharing contracts, the fiscal terms of various production sharing contracts, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax, and foreign trade and investment and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Marathon either owns or derives an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included by Marathon for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Certain technical personnel of Marathon are responsible for the preparation of reserve estimates on new properties and for the preparation of revised estimates, when necessary, on old properties. These personnel assembled the necessary data and maintained the data and workpapers in an orderly manner. We consulted with these technical personnel and had access to their workpapers and supporting data in the course of our audit.

Marathon has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In performing our audit of Marathon’s forecast of future proved production, we have relied upon data furnished by Marathon with respect to property interests owned or derived, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as

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transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Marathon. We consider the factual data furnished to us by Marathon to be appropriate and sufficient for the purpose of our review of Marathon’s estimates of reserves. In summary, we consider the assumptions, data, methods and analytical procedures used by Marathon and as reviewed by us appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate under the circumstances to render the conclusions set forth herein.

Audit Opinion

Based on our review, including the data, technical processes and interpretations presented by Marathon, it is our opinion that the overall procedures and methodologies utilized by Marathon in preparing their estimates of the proved reserves as of December 31, 2012 comply with the current SEC regulations and that the overall proved reserves for the reviewed properties as estimated by Marathon are, in the aggregate, reasonable within the established audit tolerance guidelines of 10 percent as set forth in the SPE auditing standards.

We were in reasonable agreement with Marathon's estimates of proved reserves for the properties which we reviewed; although in certain cases there was more than an acceptable variance between Marathon’s estimates and our estimates due to a difference in interpretation of data or due to our having access to data which were not available to Marathon when its reserve estimates were prepared. However not withstanding, it is our opinion that on an aggregate basis the data presented herein for the properties that we reviewed fairly reflects the estimated net reserves owned by Marathon.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world for over seventy-five years. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have over eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization.

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Marathon Oil Corporation

January 20, 2014

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We are independent petroleum engineers with respect to Marathon. Neither we nor any of our employees have any interest in the subject properties, and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this audit, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing, reviewing and approving the review of the reserves information discussed in this report, are included as an attachment to this letter.

Terms of Usage

The results of our third party audit, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Marathon.

Marathon makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Marathon has certain registration statements filed with the SEC under the 1933 Securities Actinto which any subsequently filed Form 10-Kis incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8of Marathon of the references to our name as well as to the references to our third party report for Marathon, which appears in the December 31, 2013 annual report on Form 10-K of Marathon. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Marathon.

We have provided Marathon with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filings made by Marathon and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

\s\ Jeffrey D. Wilson

Jeffrey D. Wilson, P.E.

TBPE License No. 86426

Managing Senior Vice President

[SEAL]

JDW (FWZ)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Professional Qualifications of Primary Technical Engineer

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Jeffrey D. Wilson was the primary technical person responsible for the estimate of the reserves, future production and income presented herein.

Mr. Wilson, an employee of Ryder Scott Company L.P. (Ryder Scott) since 1998, is a Senior Vice President and also serves as a member of the Board of Directors responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Wilson served in a number of engineering positions with Exxon. For more information regarding Mr. Wilson’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com/Experience/Employees.

Mr. Wilson earned a Bachelor of Science degree in Mechanical Engineering from the University of Houston in 1991, graduating with Magna Cum Laude honors, and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers and currently serves as a member of the SPE Oil and Gas Reserves Committee.

The Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Wilson fulfills. As part of his 2013 continuing education hours, Mr. Wilson attended 15hours of seminars on various topics including SEC oil and gas reporting requirements, the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, overviews of the various productive basins, evaluations of resource play reserves, and ethics training. Mr. Wilson also earned additional continuing education credits by attending various SPE Oil and Gas Reserves Committee meetings and making multiple presentations of the results of his study of the SEC’s 2012 comment letters.

Based on his educational background, professional training and more than 22 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Wilson has attained the professional qualifications as a Reserves Estimator and Reserves Auditor set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible-from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations-prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

PROVED RESERVES (SEC DEFINITIONS) CONTINUED

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) 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; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

Developed Producing Reserves

Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate, but which have not started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells, which will require additional completion work or future re-completion prior to start of production.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category 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.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

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Other Items (Tables)

12 Months Ended

Dec. 31, 2013

Other Items [Abstract]

Schedule Of Net Interest And Other Financing Table

Net interest and other

(In millions)	2013			2012			2011
Interest:
Interest income	$	6		$	13		$	12
Interest expense(a)	(307		)	(244		)	(228		)
Income on interest rate swaps	9			7			10
Interest capitalized	21			12			103
Total interest	(271		)	(212		)	(103		)
Other:
Net foreign currency gains	16			4			24
Write off of contingent proceeds	(4		)	—			(7		)
Other	(15		)	(11		)	(21		)
Total other	(3		)	(7		)	(4		)
Net interest and other	$	(274	)	$	(219	)	$	(107	)

^(a)  Excludes $1 million and $10 million paid by United States Steel in2012 and 2011 on assumed debt.

Schedule Of Foreign Currency Transactions Table

Foreign currency transactions – Aggregate foreign currency gains (losses) were included in the consolidated statements of income as follows:

(In millions)	2013		2012			2011
Net interest and other	$	16	$	4		$	24
Provision for income taxes	105		(80		)	57
Aggregate foreign currency gains (losses)	$	121	$	(76	)	$	81

XML

Summary of Principal Accounting Policies DDA (Details)	12 Months Ended
	Dec. 31, 2013
Wells and Related Equipment and Facilities [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Wells and Related Equipment and Facilities [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	40 years
Property, Plant and Equipment, Other Types [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	3 years
Property, Plant and Equipment, Other Types [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	40 years

XML

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Change in Asset Retirement Obligation

The following summarizes the changes in asset retirement obligations:

(In millions)	2013			2012
Beginning balance	$	1,783		$	1,510
Incurred, including acquisitions	84			150
Settled, including dispositions	(78		)	(35		)
Accretion expense (included in depreciation, depletion and amortization)	106			91
Revisions to previous estimates	244			150
Held for sale	(43		)	(83		)
Ending balance(a)	$	2,096		$	1,783

^(a)  Includes asset retirement obligations of $87 million and $34 million classified as short-term at December 31,2013 and 2012.

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Equity Method Investments and Related Party Transactions (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 1,201	$ 1,279
Equity Method Investment, Summarized Financial Information, Income Statement [Abstract]
Revenues and other income	1,444	1,330	1,544
Income from operations	849	755	942
Net income	727	635	820
Equity Method Investment Balance Sheet Reported Amounts [Abstract]
Current assets	644	607
Noncurrent assets	1,590	1,743
Current liabilities	384	395
Noncurrent liabilities	33	29
Proceeds from Equity Method Investment, Dividends or Distributions	435	381	509
Related Party Transactions [Abstract]
Revenue from Related Parties	55	58	60
Related Party Transaction, Purchases from Related Party	242	248	250
Accounts Receivable, Related Parties, Current	30	27
Accounts Payable, Related Parties, Current	20	20
EG Holdings [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	60.00%
Equity Method Investments	748	817
Alba Plant LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	52.00%
Equity Method Investments	263	264
AMPCO [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Ownership Percentage	45.00%
Equity Method Investments	189	187
Other Equity Method Investees [Member]
Schedule of Equity Method Investments [Line Items]
Equity Method Investments	$ 1	$ 11

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Summary of Principal Accounting Policies Summary of Principal Accounting Policies Reclassifications (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
General and Administrative Expense	$ 687	$ 699	$ 663
Reclassifications [Member]
General and Administrative Expense		$ 144	$ 119

XML

Derivatives (Details-BS) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		$ 91
Derivative Asset, Fair Value, Gross Liability		0
Derivative Asset, Fair Value, Net		91
Not Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		52
Derivative Asset, Fair Value, Gross Liability		0
Derivative Asset, Fair Value, Net		52
Commodity [Member] | Other Current Assets [Member] | Not Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset		52
Derivative Asset, Fair Value, Gross Liability		0
Derivative Asset, Fair Value, Net		52
Fair Value Hedging [Member] | Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	10	39
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset, Fair Value, Net	10	39
Derivative Liability, Fair Value, Gross Asset	0
Derivative Liability, Fair Value, Gross Liability	4
Derivative Liability, Fair Value, Net	4
Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Other Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Asset	0
Derivative Liability, Fair Value, Gross Liability	4
Derivative Liability, Fair Value, Net	4
Fair Value Hedging [Member] | Foreign Exchange Contract [Member] | Other Current Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	2	18
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset, Fair Value, Net	2	18
Fair Value Hedging [Member] | Interest rate [Member] | Other Noncurrent Assets [Member] | Designated as Hedging Instrument [Member]
Derivatives Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	8	21
Derivative Asset, Fair Value, Gross Liability	0	0
Derivative Asset, Fair Value, Net	$ 8	$ 21

XML

Derivatives (Tables)

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives as they appear on the Balance Sheet

The following tables present the gross fair values of derivative instruments, excluding cash collateral, and the reported net amounts along with where they appear on the consolidated balance sheets as of December 31, 2013 and 2012.

	December 31, 2013
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	8	$	—	$	8	Other noncurrent assets
Foreign currency	2		—		2		Other current assets
Total Designated Hedges	$	10	$	—	$	10

	December 31, 2013
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	—	$	4	$	4	Other current liabilities
Total Designated Hedges	$	—	$	4	$	4

	December 31, 2012
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	21	$	—	$	21	Other noncurrent assets
Foreign currency	18		—		18		Other current assets
Total Designated Hedges	39		—		39
Not Designated as Hedges
Commodity	52		—		52		Other current assets
Total Not Designated as Hedges	52		—		52
Total	$	91	$	—	$	91

Schedule of Interest Rate Derivatives [Table Text Block]

The following table presents by maturity date, information about our interest rate swap agreements as of December 31, 2013, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.

Maturity Dates	Aggregate Notional Amount (in millions)		Weighted Average, LIBOR-Based, Floating Rate
October 1, 2017	$	600	4.65	%
March 15, 2018	$	300	4.50	%

Effects of derivatives designated as fair value hedges

The pretax effect of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below. There is no ineffectiveness related to the fair value hedges.

		Gain (Loss)
(In millions)	Income Statement Location	2013			2012			2011
Derivative
Interest rate	Net interest and other	$	(13	)	$	16		$	28
Interest rate	Loss on early extinguishment of debt	—			—			29
Foreign currency	Provision for income taxes	(44		)	(1		)	—
Hedged Item
Long-term debt	Net interest and other	$	13		$	(16	)	$	(28	)
Long-term debt	Loss on early extinguishment of debt	—			—			(29		)
Accrued taxes	Provision for income taxes	44			1			—

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Summary of Principal Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Principles applied in consolidation

Principles applied in consolidation – These consolidated financial statements include the accounts of our majority-owned, controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis.

Equity method investments – Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. This includes entities in which we hold majority ownership but the minority stockholders have substantive participating rights in the investee. Income from equity method investments represents our proportionate share of net income generated by the equity method investees.

Equity method investments are carried at our share of net assets plus loans and advances. Such investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net income. Differences in the basis of the investments and the separate net asset value of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets, except for the excess related to goodwill.

Discontinued operations – Disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations unless otherwise stated. Due to the agreements entered in 2013 to sell our Angola assets (see Note 6), the corresponding results of operations and cash flows have been classified as discontinued operations for all presented periods. As a result of the spin-off of our downstream business in 2011 (see Note 3), the related results of operations and cash flows have been classified as discontinued operations for all periods prior to the spin-off.

Use of estimates

Use of estimates – The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods.

Revision

Reclassifications – Beginning in 2013, we changed the presentation of our consolidated statements of income, primarily to present additional details of revenues and expenses and to classify certain expenses more consistently with our peer group of independent exploration and production companies. To effect these changes, reclassifications of previously reported amounts were made and are reflected in these consolidated financial statements. As a result of the reclassifications, general and administrative expenses for 2012 and 2011 increased by $144 million and $119 million which primarily includes certain costs associated with operations support and operations management. Offsetting reductions are reflected in production, other operating and exploration expenses and taxes other than income.

Foreign currency transactions

Foreign currency transactions – The U.S. dollar is the functional currency of our foreign operating subsidiaries. Foreign currency transaction gains and losses are included in net income.

Revenue recognition

Revenue recognition – Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. We follow the sales method of accounting for crude oil and natural gas production imbalances and would recognize a liability if our existing proved reserves were not adequate to cover an imbalance. Imbalances have not been significant in the periods presented.

In the lower 48 states of the U.S., production volumes of liquid hydrocarbons and natural gas are generally sold immediately and transported to market. In international locations, liquid hydrocarbon production volumes may be stored as inventory and sold at a later time. In Canada, mined bitumen is first processed through an upgrader and then sold as synthetic crude oil. Both bitumen and synthetic crude oil may be stored as inventory.

Gas balancing policy

We follow the sales method of accounting for crude oil and natural gas production imbalances and would recognize a liability if our existing proved reserves were not adequate to cover an imbalance. Imbalances have not been significant in the periods presented.

Cash and cash equivalents

Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with original maturities of three months or less.

Accounts receivable

Accounts receivable – The majority of our receivables are from joint interest owners in properties we operate or from purchasers of commodities, both of which are recorded at invoiced amounts and do not bear interest. We often have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We conduct credit reviews of commodity purchasers prior to making commodity sales to new customers or increasing credit for existing customers. Based on these reviews, we may require a standby letter of credit or a financial guarantee. Uncollectible accounts receivable are reserved against the allowance for uncollectible accounts when it is determined the receivable will not be collected and the amount of any reserve may be reasonably estimated.

Inventories

Inventories – Inventories are carried at the lower of cost or market value. The majority of our inventories are recorded at average cost. The last-in, first-out ("LIFO") method is used for our U.S. crude oil and natural gas inventories.

We may enter into a contract to sell a particular quantity and quality of crude oil at a specified location and date to a particular counterparty, and simultaneously agree to buy a particular quantity and quality of the same commodity at a specified location on the same or another specified date from the same counterparty. We account for such matching buy/sell arrangements as exchanges of inventory.

Derivative instruments

Derivative instruments – We may use derivatives to manage a portion of our exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk. All derivative instruments are recorded at fair value. Commodity derivatives and interest rate swaps are reflected on our consolidated balance sheet on a net basis by counterparty, as they are governed by master netting agreements. Cash flows related to derivatives used to manage commodity price risk, foreign currency risk and interest rate risk are classified in operating activities with the underlying transactions. Our derivative instruments contain no significant contingent credit features.

Cash flow and Fair value hedges

Cash flow hedges – We may use foreign currency forwards and options to manage foreign currency risk associated with anticipated transactions and designate them as cash flow hedges. No such derivatives were outstanding at December 31, 2013 and 2012. The effective portion of changes in fair value is recognized in other comprehensive income ("OCI") and is reclassified to net income when the underlying forecasted transaction is recognized in net income. Any ineffective portion is recognized in net interest and other as it occurs. For a discontinued cash flow hedge, prospective changes in the fair value of the derivative are recognized in net income. The accumulated gain or loss recognized in OCI at the time a hedge is discontinued continues to be deferred until the original forecasted transaction occurs. However, if it is determined that the likelihood of the original forecasted transaction occurring is no longer probable, the entire accumulated gain or loss recognized in OCI is immediately reclassified into net income.

We may use interest rate derivative instruments to manage the risk of interest rate changes during the period prior to anticipated borrowings and designate them as cash flow hedges. No such derivatives were outstanding at December 31, 2013 and 2012.

Fair value hedges – We may use interest rate swaps to manage our exposure to interest rate risk associated with fixed interest rate debt in our portfolio; commodity derivative instruments to manage the price risk on natural gas that we purchase to be marketed with our natural gas production; and foreign currency forwards to manage our exposure to changes in the value of foreign currency denominated tax liabilities. Changes in the fair values of both the hedged item and the related derivative are recognized immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect is to report in net income the extent to which the hedge is not effective in achieving offsetting changes in fair value.

Derivatives not designated as hedges

Derivatives not designated as hedges – Derivatives that are not designated as hedges may include commodity derivatives used primarily to manage price risk on the forecasted sale of crude oil, natural gas and synthetic crude oil that we produce. Changes in the fair value of derivatives not designated as hedges are recognized immediately in net income

Fair value transfer

Fair value transfer – We recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. When significant transfers occur, they are disclosed in Note 15 to the consolidated financial statements.

Property, plant and equipment

Property, plant and equipment – We use the successful efforts method of accounting for oil and gas producing activities, which include bitumen mining and upgrading.

Property acquisition costs

Property acquisition costs – Costs to acquire mineral interests in traditional oil and natural gas properties or in oil sands mines, to drill and equip exploratory wells in progress and those that find proved reserves, to drill and equip development wells and to construct or expand oil sands mines and upgrading facilities are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves but cannot yet be classified as proved are capitalized if (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (2) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended exploratory well costs is monitored continuously and reviewed at least quarterly.

Depreciation, depletion and amortization

Depreciation, depletion and amortization – Capitalized costs to acquire oil and natural gas properties, which include bitumen mining and upgrading facilities, are depreciated and depleted on a units-of-production basis based on estimated proved reserves. Capitalized costs of exploratory wells and development costs are depreciated and depleted on a units-of-production basis based on estimated proved developed reserves. Support equipment and other property, plant and equipment related to oil and gas producing activities are depreciated on a straight-line basis over their estimated useful lives which range from 3 to 40 years.

Property, plant and equipment unrelated to oil and gas producing activities is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 40 years.

Impairments

Impairments – We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells, development costs and our bitumen mining and upgrading facilities, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors and may apply an undiscounted future net cash flow approach when appropriate. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage are also considered. When unproved property investments are deemed to be impaired the expense is reported in exploration expenses.

Dispositions

Dispositions – When property, plant and equipment depreciated on an individual basis are sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale. Proceeds from the disposal of property, plant and equipment depreciated on a group basis are credited to accumulated depreciation, depletion and amortization with no immediate effect on net income until net book value is reduced to zero.

Goodwill

Goodwill – Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Such goodwill is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to impairments.

Major maintenance activities

Major maintenance activities – Costs for planned major maintenance are expensed in the period incurred and can include the costs of contractor repair services, materials and supplies, equipment rentals and our labor costs.

Environmental costs

Environmental costs – Environmental expenditures are capitalized only if the costs mitigate or prevent future contamination or if the costs improve the environmental safety or efficiency of the existing assets. We provide for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed or reliably determinable.

Asset retirement obligations

Asset retirement obligations – The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Our asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities, which include our bitumen mining facilities. Asset retirement obligations for such facilities include costs to dismantle and relocate or dispose of production platforms, mine assets, gathering systems, wells and related structures and restoration costs of land and seabed, including those leased. Estimates of these costs are developed for each property based on the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering professionals. Asset retirement obligations have not been recognized for certain of our international oil and gas producing facilities as we currently do not have a legal obligation associated with the retirement of those facilities. Asset retirement obligations have not been recognized for the removal of materials and equipment from or the closure of certain bitumen upgrading assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate.

Inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for oil and gas production facilities, which include our bitumen mining facilities, while accretion escalates over the lives of the assets.

Deferred income taxes

Deferred income taxes – Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. We routinely assess the realizability of our deferred tax assets based on several interrelated factors and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. These factors include our expectation to generate sufficient future taxable income including future foreign source income, tax credits, operating loss carryforwards and management’s intent regarding the permanent reinvestment of the income from certain foreign subsidiaries.

Stock based compensation arrangements

Stock-based compensation arrangements – The fair value of stock options is estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock option award. Of the required assumptions, the expected life of the stock option award and the expected volatility of our stock price have the most significant impact on the fair value calculation. We have utilized historical data and analyzed current information which reasonably support these assumptions.

The fair value of our restricted stock awards and common stock units is determined based on the market value of our common stock on the date of grant. Unearned stock-based compensation is charged to stockholders’ equity when restricted stock awards are granted.

The fair value of our stock-based performance units is estimated using the Monte Carlo simulation method. Since these awards are settled in cash at the end of a defined performance period, they are classified as a liability and are re-measured quarterly until settlement.

Our stock-based compensation expense is recognized based on management’s best estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods.

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Derivatives (Details 2-Fair Value Hedges) (Fair Value Hedging [Member]) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2011 Interest Rate Contract [Member] USD ($)	Dec. 31, 2013 Foreign Exchange Contract [Member] NOK	Dec. 31, 2012 Foreign Exchange Contract [Member] NOK	Dec. 31, 2013 Debentures Due 2017 [Member] Interest Rate Contract [Member] USD ($)	Dec. 31, 2012 Debentures Due 2017 [Member] Interest Rate Contract [Member] USD ($)	Dec. 31, 2013 Notes Due 2018 [Member] Interest Rate Contract [Member] USD ($)
Derivatives, Fair Value [Line Items]
Derivative, Notional Amount	$ 1,450	2,387	3,043	$ 600	$ 600	$ 300
Interest Rate Swaps	$ 29
Weighted-average, LIBOR-based, floating rate				4.65%	4.70%	4.50%
Derivative, Average Forward Exchange Rate		6.060	5.780

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Property, Plant and Equipment (Details 3) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amounts capitalized greater than one year after completion of drilling	$ 281	$ 229	$ 222
Angola Capitalized Greater One Year [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amounts capitalized greater than one year after completion of drilling	153
Norway Capitalized Greater One Year [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amounts capitalized greater than one year after completion of drilling	70
Equatorial Guinea Capitalized Greater One Year [Member]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amounts capitalized greater than one year after completion of drilling	22
Canada Capitalized Greater One Year [Domain]
Projects with Exploratory Well Costs Capitalized for More than One Year [Line Items]
Amounts capitalized greater than one year after completion of drilling	$ 36

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Defined Benefit Postretirement Plans and Defined Contribution Plan (Details 4) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components	$ 2
Defined Benefit Plan, Effect of One Percentage Point Decrease on Service and Interest Cost Components	(2)
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation	30
Defined Benefit Plan, Effect of One Percentage Point Decrease on Accumulated Postretirement Benefit Obligation	$ (25)
Medical Pre-65 [Member]
Defined Benefit Plan Assumed Health Care Cost Trend Rates [Line Items]
Health care cost trend rate assumed for the following year:	7.50%		8.00%		7.50%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):	5.00%		5.00%		5.00%
Year that the rate reaches the ultimate trend rate:	2020		2020		2018
Medical Post-65 [Member]
Defined Benefit Plan Assumed Health Care Cost Trend Rates [Line Items]
Health care cost trend rate assumed for the following year:	6.50%		7.00%		7.00%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):	5.00%		5.00%		5.00%
Year that the rate reaches the ultimate trend rate:	2020		2018		2017
Assumed Health Care Cost Prescription Drugs [Member]
Defined Benefit Plan Assumed Health Care Cost Trend Rates [Line Items]
Health care cost trend rate assumed for the following year:	7.00%		7.00%		7.50%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):	5.00%		5.00%		5.00%
Year that the rate reaches the ultimate trend rate:	2020		2018		2018
EGWP subsidy [Member]
Defined Benefit Plan Assumed Health Care Cost Trend Rates [Line Items]
Health care cost trend rate assumed for the following year:	8.70%	[1]	7.50%	[1]
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):	5.00%	[1]	5.00%	[1]
Year that the rate reaches the ultimate trend rate:	2020	[1]	2020	[1]
Equity Securities [Member] | United States Pension Plans of US Entity, Defined Benefit [Member]
Defined Benefit Plan Assumed Health Care Cost Trend Rates [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	55.00%
Equity Securities [Member] | Foreign Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Assumed Health Care Cost Trend Rates [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	70.00%
Fixed Income Securities [Member] | United States Pension Plans of US Entity, Defined Benefit [Member]
Defined Benefit Plan Assumed Health Care Cost Trend Rates [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	45.00%
Fixed Income Securities [Member] | Foreign Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Assumed Health Care Cost Trend Rates [Line Items]
Defined Benefit Plan, Target Plan Asset Allocations	30.00%

[1] An employee group waiver plan ("EGWP") is a group Medicare Part D prescription drug plan. Effective January 1, 2013, we implemented the EGWP as a result of the Patient Protection and Affordable Care Act, which ended tax-free status of retiree drug subsidy programs but increased federal funding to Part D prescription drug plans.

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Variable Interest Entities (Details) (Variable Interest Entity, Not Primary Beneficiary [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Variable Interest Entity, Not Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage	20.00%
Recorded liability related to unconsolidated VIE	$ 3
Maximum exposure to loss related to unconsolidated VIE	$ 723

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Fair Value Measurements (Details 2-Nonrecurring) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended			3 Months Ended	12 Months Ended	3 Months Ended		12 Months Ended	3 Months Ended
	Dec. 31, 2013 Assets Held and Used Eq Guinea Lng [Member]	Dec. 31, 2013 Fair Value, Measurements, Nonrecurring [Member]	Dec. 31, 2012 Fair Value, Measurements, Nonrecurring [Member]	Dec. 31, 2011 Fair Value, Measurements, Nonrecurring [Member]	Mar. 31, 2013 Fair Value, Measurements, Nonrecurring [Member] Fair Value, Inputs, Level 3 [Member] Assets Held and Used Ozona [Member]	Dec. 31, 2012 Fair Value, Measurements, Nonrecurring [Member] Fair Value, Inputs, Level 3 [Member] Assets Held and Used Ozona [Member]	Mar. 31, 2013 Fair Value, Measurements, Nonrecurring [Member] Fair Value, Inputs, Level 3 [Member] Assets Held and Used Powder River Basin [Member]	Dec. 31, 2012 Fair Value, Measurements, Nonrecurring [Member] Fair Value, Inputs, Level 3 [Member] Assets Held and Used Powder River Basin [Member]	Dec. 31, 2011 Fair Value, Measurements, Nonrecurring [Member] Fair Value, Inputs, Level 3 [Member] Assets Held and Used Droshky [Member]	Dec. 31, 2013 Fair Value, Measurements, Nonrecurring [Member] Fair Value, Inputs, Level 3 [Member] Assets Held and Used Eq Guinea Lng [Member]
Fair Value, Assets and Liabilities Measured on Nonrecurring Basis, Financial Statement [Line Items]
Property, Plant, and Equipment, Fair Value Disclosure		$ 5	$ 16	$ 226					$ 226
Assets, Fair Value Adjustment		96	371	285	(21)	289	15	73	273	40
Fair Value of Intangible Assets, year-to-date		0	0	0
Impairment of Intangible Assets, Finite-lived		0	0	25
Equity Method Investment, Other than Temporary Impairment	$ 4

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Defined Benefit Postretirement Plans and Defined Contribution Plan (Details) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets [Abstract]
Accumulated benefit obligation	$ 1,359,000,000	$ 1,442,000,000
United States Pension Plans of US Entity, Defined Benefit [Member]
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets [Abstract]
Projected benefit obligation	(933,000,000)	(1,146,000,000)
Accumulated benefit obligation	791,000,000	937,000,000
Fair value of plan assets	625,000,000	630,000,000
Change in benefit obligations:
Benefit obligations at January 1	1,146,000,000	986,000,000
Service cost	33,000,000	31,000,000	28,000,000
Interest cost	40,000,000	42,000,000	44,000,000
Actuarial loss	(140,000,000)	196,000,000
Foreign currency exchange rate changes	0	0
Benefits paid	(146,000,000)	(109,000,000)
Benefit obligations at December 31	933,000,000	1,146,000,000	986,000,000
Change in plan assets:
Fair value of plan assets at January 1	630,000,000	516,000,000
Actual return on plan assets	65,000,000	66,000,000
Employer contributions	76,000,000	157,000,000
Foreign currency exchange rate changes	0	0
Benefits paid	(146,000,000)	(109,000,000)
Fair value of plan assets at December 31	625,000,000	630,000,000	516,000,000
Funded status of plans at December 31
Funded status of plans at December 31	(308,000,000)	(516,000,000)
Amounts recognized in the consolidated balance sheet:
Current liabilities	(16,000,000)	(17,000,000)
Noncurrent liabilities	(292,000,000)	(499,000,000)
Accrued benefit cost	(308,000,000)	(516,000,000)
Pretax amounts in accumulated other comprehensive loss:
Net loss	262,000,000	511,000,000
Prior service cost (credit)	15,000,000	21,000,000
Foreign Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Pension Plans with Accumulated Benefit Obligations in Excess of Plan Assets [Abstract]
Projected benefit obligation		(565,000,000)
Accumulated benefit obligation		505,000,000
Fair value of plan assets		500,000,000
Change in benefit obligations:
Benefit obligations at January 1	565,000,000	465,000,000
Service cost	22,000,000	19,000,000	19,000,000
Interest cost	24,000,000	22,000,000	22,000,000
Actuarial loss	40,000,000	49,000,000
Foreign currency exchange rate changes	11,000,000	25,000,000
Benefits paid	(13,000,000)	(15,000,000)
Benefit obligations at December 31	649,000,000	565,000,000	465,000,000
Change in plan assets:
Fair value of plan assets at January 1	500,000,000	412,000,000
Actual return on plan assets	74,000,000	57,000,000
Employer contributions	23,000,000	24,000,000
Foreign currency exchange rate changes	13,000,000	22,000,000
Benefits paid	(13,000,000)	(15,000,000)
Fair value of plan assets at December 31	597,000,000	500,000,000	412,000,000
Funded status of plans at December 31
Funded status of plans at December 31	(52,000,000)	(65,000,000)
Amounts recognized in the consolidated balance sheet:
Current liabilities	0	0
Noncurrent liabilities	(52,000,000)	(65,000,000)
Accrued benefit cost	(52,000,000)	(65,000,000)
Pretax amounts in accumulated other comprehensive loss:
Net loss	59,000,000	74,000,000
Prior service cost (credit)	9,000,000	10,000,000
Other Postretirement Benefit Plans, Defined Benefit [Member]
Change in benefit obligations:
Benefit obligations at January 1	311,000,000	301,000,000
Service cost	4,000,000	4,000,000	4,000,000
Interest cost	12,000,000	14,000,000	16,000,000
Actuarial loss	(31,000,000)	8,000,000
Foreign currency exchange rate changes	0	0
Benefits paid	(17,000,000)	(16,000,000)
Benefit obligations at December 31	279,000,000	311,000,000	301,000,000
Change in plan assets:
Fair value of plan assets at January 1	0	0
Actual return on plan assets	0	0
Employer contributions	0	0
Foreign currency exchange rate changes	0	0
Benefits paid	(17,000,000)	(16,000,000)
Fair value of plan assets at December 31	0	0	0
Funded status of plans at December 31
Funded status of plans at December 31	(279,000,000)	(311,000,000)
Amounts recognized in the consolidated balance sheet:
Current liabilities	(19,000,000)	(19,000,000)
Noncurrent liabilities	(260,000,000)	(292,000,000)
Accrued benefit cost	(279,000,000)	(311,000,000)
Pretax amounts in accumulated other comprehensive loss:
Net loss	(8,000,000)	23,000,000
Prior service cost (credit)	$ (5,000,000)	$ (11,000,000)

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Derivatives Derivatives (Details 4-Non Hedges Commodity) (Details) (Commodity [Member], Sales and Other Operating Revenues [Member], Not Designated as Hedging Instrument [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Commodity [Member] | Sales and Other Operating Revenues [Member] | Not Designated as Hedging Instrument [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative Instruments, Gain (Loss) Recognized in Income, Net	$ (67)	$ (70)	$ (5)

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Defined Benefit Postretirement Plans and Defined Contribution Plan (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
United States Pension Plans of US Entity, Defined Benefit [Member]
Components of net periodic benefit cost:
Service cost	$ 33		$ 31		$ 28
Interest cost	40		42		44
Expected return on plan assets	(43)		(43)		(43)
Depreciation, Depletion and Amortization [Abstract]
- prior service cost (credit)	6		7		6
- actuarial loss	43		48		47
Net settlement loss(a)	45	[1]	45	[1]	30	[1]
Net periodic benefit cost(b)	124	[2]	130	[2]	112	[2]
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax):
Actuarial loss (gain)	(161)		172		97
Amortization of actuarial (loss) gain	(88)		(93)		(77)
Prior service cost	0		0		0
Amortization of prior service credit (cost)	(6)		(7)		(6)
Spin-off downstream business (c)	0	[3]	0	[3]	(24)	[3]
Total recognized in other comprehensive (income) loss	(255)		72		(10)
Total recognized in net periodic benefit cost and other comprehensive (income) loss	(131)		202		102
Foreign Pension Plans, Defined Benefit [Member]
Components of net periodic benefit cost:
Service cost	22		19		19
Interest cost	24		22		22
Expected return on plan assets	(24)		(22)		(23)
Depreciation, Depletion and Amortization [Abstract]
- prior service cost (credit)	1		1		0
- actuarial loss	4		4		2
Net settlement loss(a)	0	[1]	0	[1]	0	[1]
Net periodic benefit cost(b)	27	[2]	24	[2]	20	[2]
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax):
Actuarial loss (gain)	(11)		15		24
Amortization of actuarial (loss) gain	(4)		(4)		(2)
Prior service cost	0		1		(11)
Amortization of prior service credit (cost)	(1)		(1)		0
Spin-off downstream business (c)	0	[3]	0	[3]	0	[3]
Total recognized in other comprehensive (income) loss	(16)		11		11
Total recognized in net periodic benefit cost and other comprehensive (income) loss	11		35		31
Other Postretirement Benefit Plans, Defined Benefit [Member]
Components of net periodic benefit cost:
Service cost	4		4		4
Interest cost	12		14		16
Expected return on plan assets	0		0		0
Depreciation, Depletion and Amortization [Abstract]
- prior service cost (credit)	(6)		(7)		(7)
- actuarial loss	0		0		0
Net settlement loss(a)	0	[1]	0	[1]	0	[1]
Net periodic benefit cost(b)	10	[2]	11	[2]	13	[2]
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax):
Actuarial loss (gain)	(31)		7		1
Amortization of actuarial (loss) gain	0		0		0
Prior service cost	0		0		0
Amortization of prior service credit (cost)	6		7		7
Spin-off downstream business (c)	0	[3]	0	[3]	0	[3]
Total recognized in other comprehensive (income) loss	(25)		14		8
Total recognized in net periodic benefit cost and other comprehensive (income) loss	(15)		25		21
Subsequent Event [Member] | Other Postretirement Benefit Plans, Defined Benefit [Member]
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Defined Benefit Plan, Amortization of Net Prior Service Cost (Credit)	5
Subsequent Event [Member] | United States and Foreign Pension Plans Defined Benefit [Member]
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year [Abstract]
Defined Benefit Plan, Amortization of Net Gains (Losses)	24
Defined Benefit Plan, Amortization of Net Prior Service Cost (Credit)	$ (6)

[1] Settlement losses are recorded when lump sum payments from a plan in a period exceed the plan’s total service and interest costs for the period. Such settlements occurred in one or more of our U.S. plans in 2013, 2012 and 2011.

[2] Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.

[3] Includes net inter-company transfers of (gains)/losses due to the spin-off of the downstream business.

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Fair Value Measurements (Details 3-Reported) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Estimate of Fair Value Measurement [Member]
Financial assets
Other noncurrent financial assets	$ 154		$ 189
Total financial assets	154		189
Financial liabilities
Other current financial liabilities	13		13
Long-term debt, including current portion(a)	6,922	[1]	7,610	[1]
Deferred credits and other liabilities	149		94
Total financial liabilities	7,084		7,717
Reported Value Measurement [Member]
Financial assets
Other noncurrent financial assets	147		186
Total financial assets	147		186
Financial liabilities
Other current financial liabilities	13		13
Long-term debt, including current portion(a)	6,427	[1]	6,642	[1]
Deferred credits and other liabilities	147		94
Total financial liabilities	$ 6,587		$ 6,749

[1] Excludes capital leases

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Property, Plant and Equipment (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Less accumulated depreciation, depletion and amortization	$ (21,895)	$ (19,266)
Property, plant and equipment, net	28,145	28,272
North America Exploration and Production [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross	26,755	23,748
International Exploration and Production [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross	12,428	13,214
Oil Sands Mining Segment [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross	10,436	10,127
Corporate [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross	421	449
Total All Segments [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, gross	50,040	47,538
Libya [Member]
Segment Reporting Information [Line Items]
Property, plant and equipment, net	$ 761
Proved Developed and Undeveloped Reserves, Net (BOE)	249,000,000

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Asset Retirement Obligations (Notes)

12 Months Ended

Dec. 31, 2013

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

The following summarizes the changes in asset retirement obligations:

(In millions)	2013			2012
Beginning balance	$	1,783		$	1,510
Incurred, including acquisitions	84			150
Settled, including dispositions	(78		)	(35		)
Accretion expense (included in depreciation, depletion and amortization)	106			91
Revisions to previous estimates	244			150
Held for sale	(43		)	(83		)
Ending balance(a)	$	2,096		$	1,783

^(a)  Includes asset retirement obligations of $87 million and $34 million classified as short-term at December 31,2013 and 2012.

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Defined Benefit Postretirement Plans and Defined Contribution Plan (Tables)

12 Months Ended

Dec. 31, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Schedule of Accumulated Benefit Obligations in Excess of Fair Value of Plan Assets

Summary information for these defined benefit pension plans follows.

	December 31,
	2013			2012
(In millions)	U.S.			U.S.			Int’l
Projected benefit obligation	$	(933	)	$	(1,146	)	$	(565	)
Accumulated benefit obligation	(791		)	(937		)	(505		)
Fair value of plan assets	625			630			500

Summary Of Defined Benefit Pension Plans With Accumulated Benefit Obligations

The following summarizes the obligations and funded status for our defined benefit pension and other postretirement plans.

	Pension Benefits
	2013						2012						Other Benefits
(In millions)	U.S.			Int’l			U.S.			Int’l			2013			2012
Change in benefit obligations:
Beginning balance	$	1,146		$	565		$	986		$	465		$	311		$	301
Service cost	33			22			31			19			4			4
Interest cost	40			24			42			22			12			14
Actuarial loss (gain)	(140		)	40			196			49			(31		)	8
Foreign currency exchange rate changes	—			11			—			25			—			—
Benefits paid	(146		)	(13		)	(109		)	(15		)	(17		)	(16		)
Ending balance	$	933		$	649		$	1,146		$	565		$	279		$	311
Change in fair value of plan assets:
Beginning balance	$	630		$	500		$	516		$	412		$	—		$	—
Actual return on plan assets	65			74			66			57			—			—
Employer contributions	76			23			157			24			—			—
Foreign currency exchange rate changes	—			13			—			22			—			—
Benefits paid	(146		)	(13		)	(109		)	(15		)	—			—
Ending balance	$	625		$	597		$	630		$	500		$	—		$	—
Funded status of plans at December 31	$	(308	)	$	(52	)	$	(516	)	$	(65	)	$	(279	)	$	(311	)
Amounts recognized in the consolidated balance sheets:
Current liabilities	(16		)	—			(17		)	—			(19		)	(19		)
Noncurrent liabilities	(292		)	(52		)	(499		)	(65		)	(260		)	(292		)
Accrued benefit cost	$	(308	)	$	(52	)	$	(516	)	$	(65	)	$	(279	)	$	(311	)
Pretax amounts in accumulated other comprehensive loss:
Net loss (gain)	$	262		$	59		$	511		$	74		$	(8	)	$	23
Prior service cost (credit)	15			9			21			10			(5		)	(11		)

Schedule Of Net Periodic Benefit Cost And Other Comprehensive Income

Components of net periodic benefit cost and other comprehensive (income) loss – The following summarizes the net periodic benefit costs and the amounts recognized as other comprehensive (income) loss for our defined benefit pension and other postretirement plans.

	Pension Benefits
	2013						2012						2011						Other Benefits
(In millions)	U.S.			Int’l			U.S.			Int’l			U.S.			Int’l			2013			2012			2011
Components of net periodic benefit cost:
Service cost	$	33		$	22		$	31		$	19		$	28		$	19		$	4		$	4		$	4
Interest cost	40			24			42			22			44			22			12			14			16
Expected return on plan assets	(43		)	(24		)	(43		)	(22		)	(43		)	(23		)	—			—			—
Amortization:
- prior service cost (credit)	6			1			7			1			6			—			(6		)	(7		)	(7		)
- actuarial loss	43			4			48			4			47			2			—			—			—
Net settlement loss(a)	45			—			45			—			30			—			—			—			—
Net periodic benefit cost(b)	$	124		$	27		$	130		$	24		$	112		$	20		$	10		$	11		$	13
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax):
Actuarial loss (gain)	$	(161	)	$	(11	)	$	172		$	15		$	97		$	24		$	(31	)	$	7		$	1
Amortization of actuarial (loss) gain	(88		)	(4		)	(93		)	(4		)	(77		)	(2		)	—			—			—
Prior service cost (credit)	—			—			—			1			—			(11		)	—			—			—
Amortization of prior service credit (cost)	(6		)	(1		)	(7		)	(1		)	(6		)	—			6			7			7
Spin-off downstream business (c)	—			—			—			—			(24		)	—			—			—			—
Total recognized in other comprehensive (income) loss	$	(255	)	$	(16	)	$	72		$	11		$	(10	)	$	11		$	(25	)	$	14		$	8
Total recognized in net periodic benefit cost and other comprehensive (income) loss	$	(131	)	$	11		$	202		$	35		$	102		$	31		$	(15	)	$	25		$	21

^(a)  Settlement losses are recorded when lump sum payments from a plan in a period exceed the plan’s total service and interest costs for the period. Such settlements occurred in one or more of our U.S. plans in 2013, 2012 and 2011.

^(b)  Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.

^(c)  Includes net inter-company transfers of (gains)/losses due to the spin-off of the downstream business.

Schedule of Assumptions Used

Plan assumptions – The following summarizes the assumptions used to determine the benefit obligations at December 31, and net periodic benefit cost for the defined benefit pension and other postretirement plans for 2013, 2012 and 2011.

	Pension Benefits
	2013					2012				2011				Other Benefits
(In millions)	U.S.			Int’l		U.S.		Int’l		U.S.		Int’l		2013		2012		2011
Weighted average assumptions used to determine benefit obligation:
Discount rate	4.28	%		4.60	%	3.44	%	4.40	%	4.45	%	4.70	%	4.85	%	4.06	%	4.90	%
Rate of compensation increase	5.00	%		4.90	%	5.00	%	4.50	%	5.00	%	4.30	%	5.00	%	5.00	%	5.00	%
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate	3.79	%		4.40	%	4.21	%	4.70	%	5.05	%	5.40	%	4.06	%	4.90	%	5.55	%
Expected long-term return on plan assets	7.25	%	(a)	4.90	%	7.75	%	5.20	%	8.50	%	5.86	%	—		—		—
Rate of compensation increase	5.00	%		4.50	%	5.00	%	4.30	%	5.00	%	5.10	%	5.00	%	5.00	%	5.00	%

^(a) Effective January 1, 2014, the expected long-term return on U.S. plan assets was changed from 7.25 percent to 6.75 percent.

Schedule of Health Care Cost Trend Rates

Assumed health care cost trend rates

	2013		2012		2011
Health care cost trend rate assumed for the following year:
Medical
Pre-65	7.50	%	8.00	%	7.50	%
Post-65	6.50	%	7.00	%	7.00	%
Prescription drugs	7.00	%	7.00	%	7.50	%
EGWP subsidy(a)	8.70	%	7.50	%	n/a
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):
Medical
Pre-65	5.00	%	5.00	%	5.00	%
Post-65	5.00	%	5.00	%	5.00	%
Prescription drugs	5.00	%	5.00	%	5.00	%
EGWP subsidy(a)	5.00	%	5.00	%	n/a
Year that the rate reaches the ultimate trend rate:
Medical
Pre-65	2020		2020		2018
Post-65	2020		2018		2017
Prescription drugs	2020		2018		2018
EGWP subsidy(a)	2020		2020		n/a

^(a)  An employee group waiver plan ("EGWP") is a group Medicare Part D prescription drug plan. Effective January 1, 2013, we implemented the EGWP as a result of the Patient Protection and Affordable Care Act, which ended tax-free status of retiree drug subsidy programs but increased federal funding to Part D prescription drug plans.

Schedule of Effect of One-Percentage-Point Change in Assumed Health Care Cost Trend Rates

A one-percentage-point change in assumed health care cost trend rates would have the following effects:

(In millions)	1-Percentage- Point Increase		1-Percentage- Point Decrease
Effect on total of service and interest cost components	$	2	$	(2	)
Effect on other postretirement benefit obligations	$	30	$	(25	)

Fair Value of Defined Benefit Pension Plans Assets

The following tables present the fair values of our defined benefit pension plans’ assets, by level within the fair value hierarchy, as of December 31, 2013 and 2012.

	December 31, 2013
(In millions)	Level 1				Level 2				Level 3				Total
	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l		U.S.		Int’l
Cash and cash equivalents	$	19	$	1	$	1	$	—	$	—	$	—	$	20	$	1
Equity securities:
Common stock(a)	288		—		—		—		—		—		288		—
Preferred stock	4		—		—		—		—		—		4		—
Private equity	—		—		—		—		23		—		23		—
REIT	2		—		—		—		—		—		2		—
Mutual funds(b)	—		219		—		—		—		—		—		219
Pooled funds(c)	—		—		—		186		—		—		—		186
Fixed income securities:
U.S. treasury notes	63		—		—		—		—		—		63		—
Exchange traded funds	1		—		—		—		—		—		1		—
Corporate bonds(d)	—		—		127		—		—		—		127		—
Municipal bonds	—		—		1		—		—		—		1
Non-U.S. government bonds	—		—		7		—		—		—		7		—
Private placements	—		—		21		—		—		—		21		—
Taxable municipal bonds	—		—		13		—		—		—		13		—
Treasury inflation-protected securities	1		—		—		—		—		—		1		—
Yankee bonds	—		—		3		—		—		—		3		—
Commingled fund(e)	—		—		17		—		—		—		17		—
Pooled funds(f)	—		—		—		178		—		—		—		178
Real estate(g)	—		—		—		—		22		—		22		—
Other	—		—		—		13		12		—		12		13
Total investments, at fair value	$	378	$	220	$	190	$	377	$	57	$	—	$	625	$	597

	December 31, 2012
(In millions)	Level 1				Level 2				Level 3				Total
	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l		U.S.		Int’l
Cash and cash equivalents	$	16	$	1	$	1	$	—	$	—	$	—	$	17	$	1
Equity securities:
Common stock(a)	312		—		—		—		—		—		312		—
Private equity	—		—		—		—		25		—		25		—
REIT	2		—		—		—		—		—		2		—
Investment trust	—		—		1		—		—		—		1		—
Mutual funds(b)	—		171		—		—		—		—		—		171
Pooled funds(c)	—		—		—		152		—		—		—		152
Fixed income securities:
U.S. treasury notes	67		—		—		—		—		—		67		—
Exchange traded funds	8		—		—		—		—		—		8		—
Corporate bonds(d)	—		—		96		—		—		—		96		—
Non-U.S. government bonds	—		—		5		—		—		—		5		—
Private placements	—		—		18		—		—		—		18		—
Taxable municipal bonds	—		—		14		—		—		—		14		—
Yankee bonds	—		—		2		—		—		—		2		—
Commingled fund(e)	—		—		28		—		—		—		28		—
Pooled funds(f)	—		—		—		166		—		—		—		166
Real estate(g)	—		—		—		—		23		—		23		—
Other	—		—		—		10		12		—		12		10
Total investments, at fair value	$	405	$	172	$	165	$	328	$	60	$	—	$	630	$	500

^(a)  Includes approximately 60 percent of investments held in U.S. and non-U.S. common stocks in the banking, pharmaceuticals, oil and gas, insurance, telecommunications, electric, aerospace/defense, retail, transportation, food processing, semiconductors, and chemicals sectors. The remaining 40 percent of common stock is held in various other sectors.

^(b)  Includes approximately 75 percent of investments held in U.S. and non-U.S. common stocks in the consumer staples, financial services, health care, energy, basic materials, leisure, and industrial goods and services sectors and 25 percent of investments held among various other sectors. The funds' objective is to outperform their respective benchmark indexes, FTSE ALL Share 5% Capped Index and MSCI World Index, as defined by the investment policy.

^(c)  Includes approximately 80 percent of investments held in non-U.S. publicly traded common stocks (specifically Asia Pacific, except Japan, and the U.K.) in the financial, consumer staples, information technology, materials, energy, industrials, and telecommunication services sectors and the remaining 20 percent of investments held among various other sectors. The funds' objective is to outperform their respective benchmark indexes, MSCI AC Asia Pacific ex Japan Index, FTSE Small Cap Index, and MSCI Emerging Markets Index, as defined by the investment policy.

^(d)  Includes approximately 70 percent of U.S. and non-U.S. corporate bonds in the banking and finance, utilities, oil and gas, news/media, and health care sectors. The remaining 30 percent of corporate bonds are in various other sectors.

^(e)  Includes approximately 90 percent of investments held in U.S. and non-U.S. corporate bonds in the consumer discretionary, financial, industrial, telecommunication services, energy, health care, information technology and materials sectors and 10 percent of investments held among various other sectors.

^(f)  Includes approximately 75 percent of investments held in U.S. and non-U.S. publicly traded investment grade government and corporate bonds which include gilts, treasuries, financial, corporates, and collateralized asset backed securities and 25 percent of investments held among various other sectors. The funds' objective is to outperform their respective benchmark indexes, as defined by the investment policy.

^(g)  Includes investments diversified by property type and location. The largest property sector holdings, which represent approximately 70 percent of investments held, are office, hotel, residential, and retail with the greatest percentage of investments made in the U.S. and Asia, which includes the emerging markets of China and India.

Schedule of Effect of Significant Unobservable Inputs, Changes in Plan Assets

The following is a reconciliation of the beginning and ending balances recorded for plan assets classified as Level 3 in the fair value hierarchy.

	2013
(In millions)	Private Equity			Real Estate			Other		Total
Beginning balance	$	25		$	23		$	12	$	60
Actual return on plan assets:
Realized gain	6			1			—		7
Unrealized gain (loss)	(1		)	1			—		—
Purchases	6			1			—		7
Sales	(13		)	(4		)	—		(17		)
Ending balance	$	23		$	22		$	12	$	57

	2012
(In millions)	Private Equity			Real Estate			Other			Total
Beginning balance	$	23		$	21		$	14		$	58
Actual return on plan assets:
Realized gain	2			—			—			2
Unrealized gain (loss)	1			1			(2		)	—
Purchases	4			3			—			7
Sales	(5		)	(2		)	—			(7		)
Ending balance	$	25		$	23		$	12		$	60

Schedule of Expected Benefit Payments

Estimated future benefit payments – The following gross benefit payments, which were estimated based on actuarial assumptions applied at December 31, 2013 and reflect expected future services, as appropriate, are to be paid in the years indicated.

	Pension Benefits				Other Benefits
(In millions)	U.S.		Int’l
2014(a)	$	96	$	14	$	19
2015	94		14		20
2016	95		16		20
2017	96		18		20
2018	92		21		20
2019 through 2023	368		120		98

^(a)  Primarily as a result of retirements effective January 1, 2014, actual 2014 U.S. gross benefit payments will exceed the actuarial estimate above, including approximately $163 million which will be paid during the first quarter of 2014.

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Equity Method Investments and Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2013

Equity Method Investments Disclosure [Abstract]

Schedule of Equity Method Investments

Our equity method investments are summarized in the following table:

	Ownership as of	December 31,
(In millions)	December 31, 2013	2013		2012
EGHoldings	60%	$	748	$	817
Alba Plant LLC	52%	263		264
AMPCO	45%	189		187
Other investments		1		11
Total		$	1,201	$	1,279

Income And Balance Sheet Information of Equity Investees Table

Summarized financial information for equity method investees is as follows:

(In millions)	2013		2012		2011
Income data – year:
Revenues and other income	$	1,444	$	1,330	$	1,544
Income from operations	849		755		942
Net income	727		635		820
Balance sheet data – December 31:
Current assets	$	644	$	607
Noncurrent assets	1,590		1,743
Current liabilities	384		395
Noncurrent liabilities	33		29

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Fair Value Measurements (Details-Recurring) (Fair Value, Measurements, Recurring [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	$ 10	$ 92
Derivative Liability	4
Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets		53
Interest rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	8	21
Foreign Exchange Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	2	18
Derivative Liability	4
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Derivative Liability	0
Fair Value, Inputs, Level 1 [Member] | Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets		0
Fair Value, Inputs, Level 1 [Member] | Interest rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Fair Value, Inputs, Level 1 [Member] | Foreign Exchange Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Derivative Liability	0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	10	91
Derivative Liability	4
Fair Value, Inputs, Level 2 [Member] | Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets		52
Fair Value, Inputs, Level 2 [Member] | Interest rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	8	21
Fair Value, Inputs, Level 2 [Member] | Foreign Exchange Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	2	18
Derivative Liability	4
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Derivative Liability	0
Fair Value, Inputs, Level 3 [Member] | Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets		0
Fair Value, Inputs, Level 3 [Member] | Interest rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Fair Value, Inputs, Level 3 [Member] | Foreign Exchange Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Derivative Liability	0
Fair Value (no inputs) Collateral [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	1
Derivative Liability	0
Fair Value (no inputs) Collateral [Member] | Commodity [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets		1
Fair Value (no inputs) Collateral [Member] | Interest rate [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Fair Value (no inputs) Collateral [Member] | Foreign Exchange Contract [Member]
Fair Value, Assets and Liabilities Measured on Recurring Basis, Financial Statement [Line Items]
Derivative Assets	0	0
Derivative Liability	$ 0

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Reclassifications Out of Accumulated Other Comprehensive Income (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Provision for income taxes	$ (3,337)	$ (4,517)	$ (2,726)
Other insignificant items	(439)	(425)	(533)
Net Income (Loss) Attributable to Parent	1,753	1,582	2,946
Reclassification out of Accumulated Other Comprehensive Income [Member]
Reclassification Adjustment out of Accumulated Other Comprehensive Income on Derivatives [Line Items]
Amortization of actuarial loss	(47)
Net settlement loss	(45)
Provision for income taxes	35
Income from operations before income taxes	(57)
Other insignificant items	(1)
Net Income (Loss) Attributable to Parent	$ (58)

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Income per Common Share (Tables)

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

	2013				2012						2011
(In millions, except per share data)	Basic		Diluted		Basic			Diluted			Basic		Diluted
Income from continuing operations	$	1,593	$	1,593	$	1,613		$	1,613		$	1,718	$	1,718
Discontinued operations	160		160		(31		)	(31		)	1,228		1,228
Net income	$	1,753	$	1,753	$	1,582		$	1,582		$	2,946	$	2,946
Weighted average common shares outstanding	705		705		706			706			710		710
Effect of dilutive securities	—		4		—			4			—		4
Weighted average common shares, including dilutive effect	705		709		706			710			710		714
Per share:
Income from continuing operations	$	2.26	$	2.24	$	2.28		$	2.27		$	2.42	$	2.41
Discontinued operations	$	0.23	$	0.23	$	(0.04	)	$	(0.04	)	$	1.73	$	1.72
Net income	$	2.49	$	2.47	$	2.24		$	2.23		$	4.15	$	4.13

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Reclassifications Out of Accumulated Other Comprehensive Income (Tables)

12 Months Ended

Dec. 31, 2013

Reclassifications out of AccumulatedOtherComprehensiveIncome [Abstract]

Reclassification out of AOCI [Text Block]

Reclassifications Out of Accumulated Other Comprehensive Loss

The following table presents a summary of amounts reclassified from accumulated other comprehensive loss to net income in their entirety:

(In millions)	2013			Income Statement Line
Accumulated Other Comprehensive Loss Components
	Income (Expense)
Postretirement and postemployment plans
Amortization of actuarial loss	$	(47	)	General and administrative
Net settlement loss	(45		)	General and administrative
	35			Provision for income taxes
	(57		)	Net of tax
Other insignificant items, net of tax	(1		)
Total reclassifications for the period	$	(58	)	Net income

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Income Taxes (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Tax carryforwards [Abstract]
Deferred Tax Assets, Tax Credit Carryforwards, Foreign	$ 3,560
Assets
Other current assets	53	57
Other noncurrent assets	847	849
Liabilities
Other current liabilities	1	4
Noncurrent deferred tax liabilities	2,492	2,432
Net deferred tax liabilities	1,593	1,530
State and Local Jurisdiction [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards	1,503
Foreign Country Kurdistan [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards	128
CANADA
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards	744
Foreign Tax Authority [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Charged to Cost and Expense	(61)	16	52
Internal Revenue Service (IRS) [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Valuation Allowances and Reserves, Charged to Cost and Expense	$ 930	$ 1,277	$ 585

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Segment Information (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Segment Reporting Information [Line Items]
Sales and other operating revenues	$ 12,419		$ 12,963		$ 10,750
Marketing revenues	2,082		2,729		3,919
Total revenues	14,501		15,692		14,669
Income from equity method investments	423		370		462
Net gain (loss) on disposal of assets and other income	35		159		151
Production expenses	2,331		2,202		1,951
Marketing costs	2,072		2,744		3,898
Exploration expenses	988		706		641
Depreciation, depletion and amortization	2,790		2,477		2,263
Impairments	96		371		310
Other expenses	1,126	[1]	1,124	[1]	1,196	[1]
Taxes other than income	352		248		193
Net interest and other	274		219		386
Provision for income taxes	3,337		4,517		2,726
Segment income/Income from continuing operations	1,593		1,613		1,718
Property, Plant and Equipment, Additions	4,984	[2]	5,131	[2]	3,399	[2]
North America Exploration and Production [Member]
Segment Reporting Information [Line Items]
Sales and other operating revenues	5,068		3,944		3,364
Marketing revenues	1,797		2,451		3,614
Total revenues	6,865		6,395		6,978
Income from equity method investments	0		2		20
Net gain (loss) on disposal of assets and other income	12		11		21
Production expenses	797		706		545
Marketing costs	1,796		2,444		3,598
Exploration expenses	725		588		388
Depreciation, depletion and amortization	1,927		1,428		1,191
Impairments	41		11		12
Other expenses	420	[1]	400	[1]	494	[1]
Taxes other than income	318		226		182
Net interest and other	0		0		0
Provision for income taxes	324		223		217
Segment income/Income from continuing operations	529		382		392
Property, Plant and Equipment, Additions	3,649	[2]	3,988	[2]	2,163	[2]
International Exploration and Production [Member]
Segment Reporting Information [Line Items]
Sales and other operating revenues	5,827		7,445		5,851
Marketing revenues	267		248		252
Total revenues	6,094		7,693		6,103
Income from equity method investments	427		368		442
Net gain (loss) on disposal of assets and other income	50		30		73
Production expenses	534		500		409
Marketing costs	258		269		247
Exploration expenses	263		118		253
Depreciation, depletion and amortization	621		787		828
Impairments	0		0		0
Other expenses	239	[1]	200	[1]	191	[1]
Taxes other than income	7		5		6
Net interest and other	0		0		0
Provision for income taxes	3,226		4,552		2,693
Segment income/Income from continuing operations	1,423		1,660		1,991
Property, Plant and Equipment, Additions	764	[2]	489	[2]	544	[2]
Oil Sands Mining Segment [Member]
Segment Reporting Information [Line Items]
Sales and other operating revenues	1,576		1,521		1,535
Marketing revenues	18		30		53
Total revenues	1,594		1,551		1,588
Income from equity method investments	0		0		0
Net gain (loss) on disposal of assets and other income	5		4		(17)
Production expenses	1,000		996		915
Marketing costs	18		31		53
Exploration expenses	0		0		0
Depreciation, depletion and amortization	218		217		196
Impairments	0		0		0
Other expenses	66	[1]	60	[1]	46	[1]
Taxes other than income	22		22		17
Net interest and other	0		0		0
Provision for income taxes	69		58		83
Segment income/Income from continuing operations	206		171		261
Property, Plant and Equipment, Additions	286	[2]	188	[2]	308	[2]
Corporate and Other [Member]
Segment Reporting Information [Line Items]
Sales and other operating revenues	(52)	[3]	53	[3]	0
Marketing revenues	0		0		0
Total revenues	(52)		53		0
Income from equity method investments	(4)	[4]	0		0
Net gain (loss) on disposal of assets and other income	(32)		114		74
Production expenses	0		0		82
Marketing costs	0		0		0
Exploration expenses	0		0		0
Depreciation, depletion and amortization	24		45		48
Impairments	55		360		298
Other expenses	401	[1]	464	[1]	465	[1]
Taxes other than income	5		(5)		(12)
Net interest and other	274		219		386	[5]
Provision for income taxes	(282)		(316)		(267)
Segment income/Income from continuing operations	(565)		(600)		(926)
Property, Plant and Equipment, Additions	$ 285	[2]	$ 466	[2]	$ 384	[2]

[1] Includes other operating expenses and general and administrative expenses.

[2] Includes accruals.

[3] Unrealized gain (loss) on crude oil derivative instruments.

[4] EGHoldings impairment (see Note 15).

[5] {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOmE0OTBkNDI3NDNiMzQ1ZThhOGRiZDFhMDU0MGZkYzRlfFRleHRTZWxlY3Rpb246REEyOTY1QjUzRDBDRDQ0MUI1RTA1MTkyNzE2ODVFRTUM}

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Debt (Tables)

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Debt Instrument Table

The following table details our long-term debt:

	December 31,
(In millions)	2013			2012
Senior unsecured notes:
9.125% notes due 2013	$	—		$	114
0.900% notes due 2015(a)	1,000			1,000
6.000% notes due 2017(a)	682			682
5.900% notes due 2018(a)	854			854
7.500% notes due 2019(a)	228			228
2.800% notes due 2022(a)	1,000			1,000
9.375% notes due 2022	32			32
Series A notes due 2022	3			3
8.500% notes due 2023	70			70
8.125% notes due 2023	131			131
6.800% notes due 2032(a)	550			550
6.600% notes due 2037	750			750
Capital leases:
Capital lease obligation of consolidated subsidiary due 2014 – 2049	10			11
Other obligations:
4.550% promissory note, semi-annual payments due 2014 – 2015	136			204
5.125% obligation relating to revenue bonds due 2037	1,000			1,000
Other	—			35
Total(b)	6,446			6,664
Unamortized discount	(9		)	(11		)
Fair value adjustments(c)	25			43
Amounts due within one year	(68		)	(184		)
Total long-term debt due after one year	$	6,394		$	6,512

^(a)  These notes contain a make-whole provision allowing us the right to repay the debt at a premium to market price.

^(b)  In the event of a change in control, as defined in the related agreements, debt obligations totaling $236 million at December 31, 2013, may be declared immediately due and payable.

^(c)  See Notes 15 and 16 for information on interest rate swaps.

Five Year Schedule Of Debt Payments Table

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Summary of Principal Accounting Policies

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Summary of Principal Accounting Policies

Summary of Principal Accounting Policies

We are engaged in worldwide exploration, production and marketing of liquid hydrocarbons and natural gas; production and marketing of products manufactured from natural gas, such as LNG and methanol, in E.G.; and oil sands mining, bitumen transportation and upgrading, and marketing of synthetic crude oil and vacuum gas oil in Canada.

Principles applied in consolidation – These consolidated financial statements include the accounts of our majority-owned, controlled subsidiaries. Investments in unincorporated joint ventures and undivided interests in certain operating assets are consolidated on a pro rata basis.

Equity method investments – Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. This includes entities in which we hold majority ownership but the minority stockholders have substantive participating rights in the investee. Income from equity method investments represents our proportionate share of net income generated by the equity method investees.

Equity method investments are carried at our share of net assets plus loans and advances. Such investments are assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred, if the loss is deemed to be other than temporary. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net income. Differences in the basis of the investments and the separate net asset value of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets, except for the excess related to goodwill.

Discontinued operations – Disclosures in this report related to results of operations and cash flows are presented on the basis of continuing operations unless otherwise stated. Due to the agreements entered in 2013 to sell our Angola assets (see Note 6), the corresponding results of operations and cash flows have been classified as discontinued operations for all presented periods. As a result of the spin-off of our downstream business in 2011 (see Note 3), the related results of operations and cash flows have been classified as discontinued operations for all periods prior to the spin-off.

Use of estimates – The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods.

Reclassifications – Beginning in 2013, we changed the presentation of our consolidated statements of income, primarily to present additional details of revenues and expenses and to classify certain expenses more consistently with our peer group of independent exploration and production companies. To effect these changes, reclassifications of previously reported amounts were made and are reflected in these consolidated financial statements. As a result of the reclassifications, general and administrative expenses for 2012 and 2011 increased by $144 million and $119 million which primarily includes certain costs associated with operations support and operations management. Offsetting reductions are reflected in production, other operating and exploration expenses and taxes other than income.

Foreign currency transactions – The U.S. dollar is the functional currency of our foreign operating subsidiaries. Foreign currency transaction gains and losses are included in net income.

Revenue recognition – Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. We follow the sales method of accounting for crude oil and natural gas production imbalances and would recognize a liability if our existing proved reserves were not adequate to cover an imbalance. Imbalances have not been significant in the periods presented.

In the lower 48 states of the U.S., production volumes of liquid hydrocarbons and natural gas are generally sold immediately and transported to market. In international locations, liquid hydrocarbon production volumes may be stored as inventory and sold at a later time. In Canada, mined bitumen is first processed through an upgrader and then sold as synthetic crude oil. Both bitumen and synthetic crude oil may be stored as inventory.

Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with original maturities of three months or less.

Accounts receivable – The majority of our receivables are from joint interest owners in properties we operate or from purchasers of commodities, both of which are recorded at invoiced amounts and do not bear interest. We often have the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. We conduct credit reviews of commodity purchasers prior to making commodity sales to new customers or increasing credit for existing customers. Based on these reviews, we may require a standby letter of credit or a financial guarantee. Uncollectible accounts receivable are reserved against the allowance for uncollectible accounts when it is determined the receivable will not be collected and the amount of any reserve may be reasonably estimated.

Inventories – Inventories are carried at the lower of cost or market value. The majority of our inventories are recorded at average cost. The last-in, first-out ("LIFO") method is used for our U.S. crude oil and natural gas inventories.

We may enter into a contract to sell a particular quantity and quality of crude oil at a specified location and date to a particular counterparty, and simultaneously agree to buy a particular quantity and quality of the same commodity at a specified location on the same or another specified date from the same counterparty. We account for such matching buy/sell arrangements as exchanges of inventory.

Derivative instruments – We may use derivatives to manage a portion of our exposure to commodity price risk, interest rate risk and foreign currency exchange rate risk. All derivative instruments are recorded at fair value. Commodity derivatives and interest rate swaps are reflected on our consolidated balance sheet on a net basis by counterparty, as they are governed by master netting agreements. Cash flows related to derivatives used to manage commodity price risk, foreign currency risk and interest rate risk are classified in operating activities with the underlying transactions. Our derivative instruments contain no significant contingent credit features.

Cash flow hedges – We may use foreign currency forwards and options to manage foreign currency risk associated with anticipated transactions and designate them as cash flow hedges. No such derivatives were outstanding at December 31, 2013 and 2012. The effective portion of changes in fair value is recognized in other comprehensive income ("OCI") and is reclassified to net income when the underlying forecasted transaction is recognized in net income. Any ineffective portion is recognized in net interest and other as it occurs. For a discontinued cash flow hedge, prospective changes in the fair value of the derivative are recognized in net income. The accumulated gain or loss recognized in OCI at the time a hedge is discontinued continues to be deferred until the original forecasted transaction occurs. However, if it is determined that the likelihood of the original forecasted transaction occurring is no longer probable, the entire accumulated gain or loss recognized in OCI is immediately reclassified into net income.

We may use interest rate derivative instruments to manage the risk of interest rate changes during the period prior to anticipated borrowings and designate them as cash flow hedges. No such derivatives were outstanding at December 31, 2013 and 2012.

Fair value hedges – We may use interest rate swaps to manage our exposure to interest rate risk associated with fixed interest rate debt in our portfolio; commodity derivative instruments to manage the price risk on natural gas that we purchase to be marketed with our natural gas production; and foreign currency forwards to manage our exposure to changes in the value of foreign currency denominated tax liabilities. Changes in the fair values of both the hedged item and the related derivative are recognized immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect is to report in net income the extent to which the hedge is not effective in achieving offsetting changes in fair value.

Derivatives not designated as hedges – Derivatives that are not designated as hedges may include commodity derivatives used primarily to manage price risk on the forecasted sale of crude oil, natural gas and synthetic crude oil that we produce. Changes in the fair value of derivatives not designated as hedges are recognized immediately in net income.

Concentrations of credit risk – All of our financial instruments, including derivatives, involve elements of credit and market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The counterparties to our financial instruments consist primarily of major financial institutions and companies within the energy industry. To manage counterparty risk associated with financial instruments, we select and monitor counterparties based on our assessment of their financial strength and on credit ratings, if available. Additionally, we limit the level of exposure with any single counterparty.

Fair value transfer – We recognize transfers between levels of the fair value hierarchy as of the end of the reporting period. When significant transfers occur, they are disclosed in Note 15 to the consolidated financial statements.

Property, plant and equipment – We use the successful efforts method of accounting for oil and gas producing activities, which include bitumen mining and upgrading.

Property acquisition costs – Costs to acquire mineral interests in traditional oil and natural gas properties or in oil sands mines, to drill and equip exploratory wells in progress and those that find proved reserves, to drill and equip development wells and to construct or expand oil sands mines and upgrading facilities are capitalized. Costs to drill exploratory wells that do not find proved reserves, geological and geophysical costs and costs of carrying and retaining unproved properties are expensed. Costs incurred for exploratory wells that find reserves but cannot yet be classified as proved are capitalized if (1) the well has found a sufficient quantity of reserves to justify its completion as a producing well and (2) we are making sufficient progress assessing the reserves and the economic and operating viability of the project. The status of suspended exploratory well costs is monitored continuously and reviewed at least quarterly.

Depreciation, depletion and amortization – Capitalized costs to acquire oil and natural gas properties, which include bitumen mining and upgrading facilities, are depreciated and depleted on a units-of-production basis based on estimated proved reserves. Capitalized costs of exploratory wells and development costs are depreciated and depleted on a units-of-production basis based on estimated proved developed reserves. Support equipment and other property, plant and equipment related to oil and gas producing activities are depreciated on a straight-line basis over their estimated useful lives which range from 3 to 40 years.

Property, plant and equipment unrelated to oil and gas producing activities is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which range from 3 to 40 years.

Impairments – We evaluate our oil and gas producing properties, including capitalized costs of exploratory wells, development costs and our bitumen mining and upgrading facilities, for impairment of value whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Oil and gas producing properties are reviewed for impairment on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future net cash flows or, if available, comparable market value. We evaluate our unproved property investment and record impairment based on time or geologic factors and may apply an undiscounted future net cash flow approach when appropriate. Information such as drilling results, reservoir performance, seismic interpretation or future plans to develop acreage are also considered. When unproved property investments are deemed to be impaired the expense is reported in exploration expenses.

Dispositions – When property, plant and equipment depreciated on an individual basis are sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale. Proceeds from the disposal of property, plant and equipment depreciated on a group basis are credited to accumulated depreciation, depletion and amortization with no immediate effect on net income until net book value is reduced to zero.

Goodwill – Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Such goodwill is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, then the recorded goodwill is impaired to its implied fair value with a charge to impairments.

Major maintenance activities – Costs for planned major maintenance are expensed in the period incurred and can include the costs of contractor repair services, materials and supplies, equipment rentals and our labor costs.

Environmental costs – Environmental expenditures are capitalized only if the costs mitigate or prevent future contamination or if the costs improve the environmental safety or efficiency of the existing assets. We provide for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed or reliably determinable.

Asset retirement obligations – The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Our asset retirement obligations primarily relate to the abandonment of oil and gas producing facilities, which include our bitumen mining facilities. Asset retirement obligations for such facilities include costs to dismantle and relocate or dispose of production platforms, mine assets, gathering systems, wells and related structures and restoration costs of land and seabed, including those leased. Estimates of these costs are developed for each property based on the type of production structure, depth of water, reservoir characteristics, depth of the reservoir, market demand for equipment, currently available procedures and consultations with construction and engineering professionals. Asset retirement obligations have not been recognized for certain of our international oil and gas producing facilities as we currently do not have a legal obligation associated with the retirement of those facilities. Asset retirement obligations have not been recognized for the removal of materials and equipment from or the closure of certain bitumen upgrading assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate.

Inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is generally determined on a units-of-production basis for oil and gas production facilities, which include our bitumen mining facilities, while accretion escalates over the lives of the assets.

Deferred income taxes – Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases as reported in our filings with the respective taxing authorities. We routinely assess the realizability of our deferred tax assets based on several interrelated factors and reduce such assets by a valuation allowance if it is more likely than not that some portion or all of the deferred tax assets will not be realized. These factors include our expectation to generate sufficient future taxable income including future foreign source income, tax credits, operating loss carryforwards and management’s intent regarding the permanent reinvestment of the income from certain foreign subsidiaries.

Stock-based compensation arrangements – The fair value of stock options is estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions, based on management’s best estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the life of the stock option award. Of the required assumptions, the expected life of the stock option award and the expected volatility of our stock price have the most significant impact on the fair value calculation. We have utilized historical data and analyzed current information which reasonably support these assumptions.

The fair value of our restricted stock awards and common stock units is determined based on the market value of our common stock on the date of grant. Unearned stock-based compensation is charged to stockholders’ equity when restricted stock awards are granted.

The fair value of our stock-based performance units is estimated using the Monte Carlo simulation method. Since these awards are settled in cash at the end of a defined performance period, they are classified as a liability and are re-measured quarterly until settlement.

Our stock-based compensation expense is recognized based on management’s best estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods.

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Segment Information (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Revenues from External Customers and Long-Lived Assets [Line Items]
Total revenues	$ 14,501		$ 15,692		$ 14,669
Long-Lived Assets	29,346		29,551
UNITED STATES
Revenues from External Customers and Long-Lived Assets [Line Items]
Total revenues	6,813		6,448		6,978
Long-Lived Assets	14,635		13,677
NORWAY
Revenues from External Customers and Long-Lived Assets [Line Items]
Total revenues	3,183		3,714		3,563
Long-Lived Assets	977		987
CANADA
Revenues from External Customers and Long-Lived Assets [Line Items]
Total revenues	1,594		1,551		1,588
Long-Lived Assets	9,794		9,693
LIBYAN ARAB JAMAHIRIYA
Revenues from External Customers and Long-Lived Assets [Line Items]
Total revenues	1,106	[1]	1,989	[1]	216	[1]
Other International [Member]
Revenues from External Customers and Long-Lived Assets [Line Items]
Total revenues	1,805		1,990		2,324
Long-Lived Assets	1,963		3,113
EQUATORIAL GUINEA
Revenues from External Customers and Long-Lived Assets [Line Items]
Long-Lived Assets	$ 1,977		$ 2,081

[1] See Note 13 for discussion of Libya operations.

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Schedule Of Property Plant And Equipment

Property, Plant and Equipment

	December 31,
(In millions)	2013			2012
North America E&P	$	26,755		$	23,748
International E&P	12,428			13,214
Oil Sands Mining	10,436			10,127
Corporate	421			449
Total property, plant and equipment	50,040			47,538
Less accumulated depreciation, depletion and amortization	(21,895		)	(19,266		)
Net property, plant and equipment	$	28,145		$	28,272

Schedule of Aging of Capitalized Exploratory Well Costs

Deferred exploratory well costs were as follows:

	December 31,
(In millions)	2013			2012			2011
Amounts capitalized less than one year after completion of drilling	$	512		$	388		$	482
Amounts capitalized greater than one year after completion of drilling	281			229			222
Total deferred exploratory well costs	$	793		$	617		$	704
Number of projects with costs capitalized greater than one year after
completion of drilling	7			6			5
	December 31,
(In millions)	2013			2012			2011
Beginning balance	$	617		$	704		$	657
Additions	746			699			625
Dry well expense	(147		)	(111		)	(223		)
Transfers to development	(414		)	(629		)	(279		)
Dispositions	(9		)	(46		)	(76		)
Ending balance	$	793		$	617		$	704

Schedule of Projects with Exploratory Well Costs Capitalized for More than One Year

Exploratory well costs capitalized greater than one year after completion of drilling as of December 31, 2013 are summarized by geographical area below:

(In millions)
Angola	$	153
Norway	70
E.G.	22
Canada	36
Total	$	281

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Reclassifications Out of Accumulated Other Comprehensive Income (Notes)

12 Months Ended

Dec. 31, 2013

Reclassifications out of AccumulatedOtherComprehensiveIncome [Abstract]

Reclassification out of AOCI [Text Block]

Reclassifications Out of Accumulated Other Comprehensive Loss

The following table presents a summary of amounts reclassified from accumulated other comprehensive loss to net income in their entirety:

(In millions)	2013			Income Statement Line
Accumulated Other Comprehensive Loss Components
	Income (Expense)
Postretirement and postemployment plans
Amortization of actuarial loss	$	(47	)	General and administrative
Net settlement loss	(45		)	General and administrative
	35			Provision for income taxes
	(57		)	Net of tax
Other insignificant items, net of tax	(1		)
Total reclassifications for the period	$	(58	)	Net income

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Incentive Based Compensation Plans

12 Months Ended

Dec. 31, 2013

Incentive Based Compensation Plans [Abstract]

Incentive Based Compensation

Incentive Based Compensation

Description of stock-based compensation plans – The Marathon Oil Corporation 2012 Incentive Compensation Plan (the "2012 Plan") was approved by our stockholders in April 2012 and authorizes the Compensation Committee of the Board of Directors to grant stock options, SARs, stock awards (including restricted stock and restricted stock unit awards) and performance awards to employees. The 2012 Plan also allows us to provide equity compensation to our non-employee directors. No more than 50 million shares of our common stock may be issued under the 2012 Plan. For stock options and SARs, the number of shares available for issuance under the 2012 Plan will be reduced by one share for each share of our common stock in respect of which the award is granted. For awards other than stock options or SARs, the number of shares available for issuance under the 2012 Plan will be reduced by 2.41 shares for each share of our common stock in respect of which the award is granted.

Shares subject to awards under the 2012 Plan that are forfeited, are terminated or expire unexercised become available for future grants. In addition, the number of shares of our common stock reserved for issuance under the 2012 Plan will not be increased by shares tendered to satisfy the purchase price of an award, exchanged for other awards or withheld to satisfy tax withholding obligations. Shares issued as a result of awards granted under the 2012 Plan are generally funded out of common stock held in treasury, except to the extent there are insufficient treasury shares, in which case new common shares are issued.

After approval of the 2012 Plan, no new grants were or will be made from the 2007 Incentive Compensation Plan, the 2003 Incentive Compensation Plan (the "2003 Plan"), the Non-Employee Director Stock Plan and the deferred stock benefit provision of the Deferred Compensation Plan for Non-Employee Directors (collectively, the "Prior Plans"). Any awards previously granted under the Prior Plans shall continue to be exercisable in accordance with their original terms and conditions.

Stock-based awards under the plans

Stock options – We grant stock options under the 2012 Plan and previously granted stock options under certain of the Prior Plans. Our stock options represent the right to purchase shares of our common stock at its fair market value on the date of grant. In general, our stock options vest ratably over a three-year period and have a maximum term of ten years from the date they are granted.

Stock appreciation rights – Prior to 2005, we granted SARs under the 2003 Plan. No SARs have been granted since then. SARs represent the right to receive shares of common stock equal in value to the excess of the fair market value of shares of common stock on the date the right is exercised over the grant price. In general, SARs vested ratably over a three-year period and have a maximum term of ten years from the date they were granted.

Restricted stock – We grant restricted stock and restricted stock units (collectively, "restricted stock awards") under the 2012 Plan and previously granted such awards under certain of the Prior Plans. The restricted stock awards granted officers generally vest three years from the date of grant, contingent on the recipient’s continued employment. We also grant restricted stock to certain non-officer employees and restricted stock units to certain international employees, based on their performance within certain guidelines and for retention purposes. The restricted stock awards to non-officers generally vest in one-third increments over a three-year period, contingent on the recipient’s continued employment. Prior to vesting, all restricted stock recipients have the right to vote such stock and receive dividends thereon. The non-vested shares are not transferable and are held by our transfer agent.

Stock-based performance units – Beginning in 2013, we grant stock-based performance units to officers under the 2012 Plan. At the grant date, each unit represents the value of one share of our common stock. These units provide a cash payout, based on the value of anywhere from zero to two times the number of units granted, upon the achievement of certain performance goals at the end of a 36-month performance period. The performance goals are tied to our total shareholder return (“TSR”) as compared to TSR for a group of peer companies determined by the Compensation Committee of the Board of Directors. Dividend equivalents accrue during the performance period and are paid in cash at the end of the performance period based on the number of shares that would represent the value of the units.

Common stock units – We maintain an equity compensation program for our non-employee directors under the 2012 Plan and previously maintained such a program under certain of the Prior Plans.  All non-employee directors receive annual grants of common stock units.  Those units granted prior to 2012 must be held until completion of board service, at which time the non-employee director will receive common shares.  Common shares will be issued for units granted on or after January 1, 2012 upon completion of board service or three years from the date of grant, whichever is earlier. When dividends are paid on our common stock, directors receive dividend equivalents in the form of additional common stock units.

Total stock-based compensation expense – Total employee stock-based compensation expense was $75 million, $70 million and $65 million in 2013, 2012 and 2011, while the total related income tax benefits were $27 million, $25 million and $23 million in the same years. In 2013, 2012 and 2011, cash received upon exercise of stock option awards was $58 million, $41 million and $77 million. Tax benefits realized for deductions for stock awards exercised during 2013, 2012 and 2011 totaled $36 million, $24 million and $32 million.

Stock option awards – During 2013, 2012 and 2011, we granted stock option awards to both officer and non-officer employees. The weighted average grant date fair value of these awards was based on the following weighted average Black-Scholes assumptions:

	2013		2012		2011
Exercise price per share	$33.54		$33.52		$32.30
Expected annual dividend yield	2.1	%	2.2	%	2.1	%
Expected life in years	6.1		5.5		5.3
Expected volatility	38	%	41	%	40	%
Risk-free interest rate	1.6	%	1.2	%	1.7	%
Weighted average grant date fair value of stock option awards granted	$10.25		$10.86		$10.44

The following is a summary of stock option award activity in 2013.

	Number of Shares	Weighted Average Exercise price
Outstanding at beginning of year	19,536,965	$26.19
Granted	2,051,386	$33.54
Exercised	(2,718,639)	$22.36
Canceled	(764,825)	$34.02
Outstanding at end of year	18,104,887	$27.27

The intrinsic value of stock option awards exercised during 2013, 2012 and 2011, was $35 million, $40 million and $59 million.

The following table presents information related to stock option awards at December 31, 2013.

	Outstanding			Exercisable
Range of Exercise Prices	Number of Shares Under Option	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price	Number of Shares Under Option	Weighted Average Exercise Price
$7.99-12.75	259,164	0.3 years	$10.53	259,164	$10.53
$12.76-16.81	1,937,181	3 years	$15.13	1,937,181	$15.13
$16.82-23.20	4,255,365	5 years	$18.57	4,255,365	$18.57
$23.21-29.24	1,740,398	4 years	$24.59	1,489,683	$24.05
$29.25-36.03	7,541,433	7 years	$33.06	3,967,422	$32.70
$36.04-46.41	2,371,346	3 years	$38.19	2,277,817	$38.26
Total	18,104,887	5 years	$27.27	14,186,632	$25.64

As of December 31, 2013, the aggregate intrinsic value of stock option awards outstanding was $152 million. The aggregate intrinsic value and weighted average remaining contractual life of stock option awards currently exercisable were $144 million and 4 years.

As of December 31, 2013, the number of fully-vested stock option awards and stock option awards expected to vest was 18,023,888. The weighted average exercise price and weighted average remaining contractual life of these stock option awards were $27.24 and 5 years and the aggregate intrinsic value was $152 million. As of December 31, 2013, unrecognized compensation cost related to stock option awards was $16 million, which is expected to be recognized over a weighted average period of 2 years.

Restricted stock awards – The following is a summary of restricted stock award activity in 2013.

	Awards		Weighted Average Grant Date Fair Value
Unvested at beginning of year	4,177,884		$29.02
Granted	2,120,839		$33.69
Vested	(1,713,763	)	$27.78
Forfeited	(553,072	)	$30.58
Unvested at end of year	4,031,888		$31.80

The vesting date fair value of restricted stock awards which vested during 2013, 2012 and 2011 was $59 million, $36 million and $30 million. The weighted average grant date fair value of restricted stock awards was $31.80, $29.02, and $25.88 for awards unvested at December 31, 2013, 2012 and 2011.

As of December 31, 2013, there was $96 million of unrecognized compensation cost related to restricted stock awards which is expected to be recognized over a weighted average period of 2 years.

Stock-based performance unit awards – During 2013, we granted 353,600 stock-based performance unit awards to officers and at December 31, 2013, there were 93,100 units outstanding. The key assumptions used in the Monte Carlo simulation to determine the December 31, 2013 fair value of stock-based performance units were:

Valuation date stock price	$35.30
Expected annual dividend yield	2.1	%
Expected volatility	26	%
2-Year risk-free interest rate	0.4	%
Fair value of stock-based performance units outstanding	$34.08

Cash-based performance unit awards – Prior to 2013, cash-based performance unit awards were granted to officers that provide a cash payment upon the achievement of certain performance goals at the end of a defined measurement period. The performance goals are tied to our TSR as compared to TSR for a group of peer companies determined by the Compensation Committee of the Board of Directors. The target value of each performance unit is $1, with a maximum payout of $2 per unit, but the actual payout could be anywhere between zero and the maximum. Because performance units are to be settled in cash at the end of the performance period, they are accounted for as liability awards.

During 2012, we granted 12.7 million performance units, all having a 36-month performance period. During the third quarter of 2011, we granted 15 million performance units, a portion of which had a 30-month performance period and a portion of which had an 18-month performance period to reflect the remaining periods of the original 2011 and 2010 performance unit grants outstanding prior to the spin-off. Compensation expense associated with cash-based performance units was $9 million, $12 million and $32 million in 2013, 2012 and 2011. The expense for 2011 included $14 million paid on three groups of performance unit grants outstanding at June 30, 2011, that were accelerated with the total payout determined based on performance through the effective date of the spin-off of our downstream business.

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Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Water abatement Oil Sands [Member]	Jun. 30, 2011 Water abatement Oil Sands [Member]	Dec. 31, 2013 Other Guarantee [Member]
Guarantor Obligations [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted					$ 96
Payments to Acquire Property, Plant, and Equipment [Abstract]
Commitments to acquire property, plant and equipment	1,270	949
Site Contingency [Line Items]
Site Contingency, Accrual, Undiscounted Amount			$ 29	$ 64

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Spin-Off (Details) (USD $) In Millions, except Share data, unless otherwise specified			12 Months Ended
	Jun. 30, 2011 independent_energy_company	Jun. 27, 2011	Dec. 31, 2011 Spinoff [Member]
Spin Off Disclosure [Abstract]
Number of Independent Energy Companies	2
Number of Common Shares Received of MPC		1
Number of Common Shares of Marathon Stock Owned		2
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues applicable to discontinued operations			$ 38,602
Pretax income from discontinued operations			$ 2,012

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Goodwill (Tables)

12 Months Ended

Dec. 31, 2013

Goodwill Disclosure [Abstract]

Schedule of Goodwill [Table Text Block]

The changes in the carrying amount of goodwill for 2012 were as follows for the Exploration and Production ("E&P") and OSM segments in place for that year:

(In millions)	E&P			OSM			Total
2012
Beginning balance, gross	$	536		$	1,412		$	1,948
Less: accumulated impairments	—			(1,412		)	(1,412		)
Beginning balance, net	536			—			536
Dispositions	(11		)	—			(11		)
Ending balance, net	$	525		$	—		$	525

As discussed in Note 8, beginning in 2013, we changed our reportable segments. Goodwill related to the previously reported E&P segment was allocated between the North America E&P and International E&P segments as of January 1, 2013 based on the relative fair values of those reporting units. The fair values of the reporting units were measured using an income approach based upon internal estimates of future production levels, commodity prices and discount rates, all of which are Level 3 inputs.  Inputs to the fair value measurements included reserve and production estimates made by our reservoir engineers, estimated commodity prices adjusted for quality and location differentials, and forecasted operating expenses. The table below displays the allocated beginning goodwill balances by segment along with changes in the carrying amount of goodwill for 2013:

(In millions)	N.A. E&P			Int'l E&P			OSM			Total
2013
Beginning balance, gross	$	343		$	182		$	1,412		$	1,937
Less: accumulated impairments	—			—			(1,412		)	(1,412		)
Beginning balance, net	343			182			—			525
Dispositions	4		(a)	(30		)	—			(26		)
Ending balance, net	$	347		$	152		$	—		$	499

^(a) Goodwill related to our Alaska disposition was less than the estimate classified as held for sale in 2012.

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Stockholders Equity (Notes)

12 Months Ended

Dec. 31, 2013

Stockholders' Equity Attributable to Parent [Abstract]

Stockholders’ Equity

Stockholders’ Equity

Share repurchase plan – In the third quarter of 2013, we acquired 14 million common shares at a cost of $500 million under our share repurchase program, initially authorized in 2006, bringing our total repurchases to 92 million common shares at a cost of $3,722 million. In December 2013, our Board of Directors increased the authorization by an additional $1.2 billion, bringing the total remaining share repurchase authorization to $2.5 billion. Purchases under the program may be in either open market transactions, including block purchases, or in privately negotiated transactions using cash on hand, cash generated from operations, proceeds from potential asset sales or cash from available borrowings to acquire shares. This program may be changed based upon our financial condition or changes in market conditions and is subject to termination prior to completion. The repurchase program does not include specific price targets or timetables.

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Leases (Notes)

12 Months Ended

Dec. 31, 2013

Leases [Abstract]

Leases

Leases

We lease a wide variety of facilities and equipment under operating leases, including land, building space, equipment and vehicles. Most long-term leases include renewal options and, in certain leases, purchase options. Future minimum commitments for capital lease obligations and for operating lease obligations having noncancellable lease terms in excess of one year are as follows:

(In millions)	Capital Lease Obligations			Operating Lease Obligations
2014	$	1		$	45
2015	1			42
2016	1			34
2017	1			22
2018	1			20
Later years	23			48
Sublease rentals	—			(4		)
Total minimum lease payments	$	28		$	207
Less imputed interest costs	(18		)
Present value of net minimum lease payments	$	10

Operating lease rental expense related to continuing operations was $106 million, $103 million and $70 million in 2013, 2012 and 2011.

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Accounting Standards

12 Months Ended

Dec. 31, 2013

Accounting Standards Disclosure [Abstract]

Accounting Standards

Accounting Standards

Not Yet Adopted

In June 2013, the FASB ratified the Emerging Issues Task Force consensus which requires that an unrecognized tax benefit (or a portion thereof ) be presented as a reduction to a deferred tax asset for an available net operating loss carryforward, a similar tax loss or tax credit carryforward. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied prospectively to unrecognized tax benefits that exist as of the effective date. Early adoption and retrospective application are permitted. Adoption of this accounting standards update will not have a significant impact on our consolidated results of operations, financial position or cash flows.

In February 2013, an accounting standards update was issued to provide guidance for the recognition, measurement, and disclosure of obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date, except for obligations such as asset retirement and environmental obligations, contingencies, guarantees, income taxes and retirement benefits, which are separately addressed within U.S. GAAP. An entity is required to measure obligations resulting from joint and several liability arrangements for which the total amount of the obligation is fixed at the reporting date as the sum of 1) the amount the entity agreed to pay on the basis of its arrangement among its co-obligors and 2) any amount the entity expects to pay on behalf of its co-obligors. Disclosure of the nature of the obligation, including how the liability arose, the relationship with other co-obligors and the terms and conditions of the arrangement is required. In addition, the total outstanding amount under the arrangement, not reduced by the effect of any amounts that may be recoverable from other entities, plus the carrying amount of any liability or receivable recognized must be disclosed. This accounting standards update is effective for us beginning in the first quarter of 2014 and should be applied retrospectively for those in-scope obligations resulting from joint and several liability arrangements that exist at the beginning of 2014. Early adoption is permitted. Adoption of this accounting standards update will not have a significant impact on our consolidated results of operations, financial position or cash flows.

Recently Adopted

In February 2013, an accounting standards update was issued to improve the reporting of reclassifications out of accumulated other comprehensive income. This standard requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. In addition, an entity is required to present, either on the face of the statement where net income is presented or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income but only if the amount reclassified is required under U.S. GAAP to be reclassified to net income in its entirety in the same reporting period. For other amounts that are not required under U.S. GAAP to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures required under U.S. GAAP that provide additional detail about those amounts. This accounting standards update was effective for us beginning the first quarter of 2013 and we present the required disclosures in Note 22. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

In December 2011, an accounting standards update designed to enhance disclosures about offsetting assets and liabilities was issued. Further clarification limiting the scope of these disclosures to derivatives, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions was issued in January 2013. The disclosures are intended to enable financial statement users to evaluate the effect or potential effect of netting arrangements on an entity’s financial position. Entities are required to disclose both gross information and net information about in-scope financial instruments that are either offset in the statement of financial position or subject to an enforceable master netting arrangement or similar agreement, irrespective of whether they are offset. The accounting standards update was effective for us beginning the first quarter of 2013 and we include the required disclosures in Note 16. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

In September 2011, the FASB amended accounting standards to simplify how entities test goodwill for impairment. The amendment reduces complexity by allowing an entity the option to make a qualitative evaluation of whether it is necessary to perform the two-step goodwill impairment test. Adoption of this amendment in 2012 did not have a significant impact on our consolidated results of operations, financial position or cash flows.

The FASB amended the reporting standards for comprehensive income in June 2011 to eliminate the option to present the components of OCI as part of the statement of changes in stockholders' equity. All non-owner changes in stockholders’ equity are required to be presented either in a single continuous statement of comprehensive income or in two separate but consecutive statements. In the two statement approach, the first statement should present total net income and its components followed consecutively by a second statement that should present total other comprehensive income, the components of OCI, and total comprehensive income. The presentation of items that are reclassified from OCI to net income on the income statement is also required. The amendments did not change the items that must be reported in OCI or when an item of OCI must be reclassified to net income. The amendments were effective for us beginning with the first quarter of 2012, except for the presentation of reclassifications, which was deferred and addressed in the February 2013 accounting standards update discussed above. Adoption of this standard did not have a significant impact on our consolidated results of operations, financial position or cash flows.

In May 2011, the FASB issued an update amending the accounting standards for fair value measurement and disclosure, resulting in common principles and requirements under U.S. GAAP and IFRS. The amendments change the wording used to describe certain of the U.S. GAAP requirements either to clarify the intent of existing requirements, to change measurement or expand disclosure principles or to conform to the wording used in IFRS. Adoption of the amendments in 2012 did not have a significant impact on our consolidated results of operations, financial position or cash flows. To the extent they were necessary, we made the expanded disclosures in Notes 15 and 16.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

We are a 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. In April 2013, we filed a counterclaim against Noble alleging, among other things, breach of contract and breach of the duty of good faith relating to the multi-year drilling contract. The counterclaim also included a breach of contract claim for reimbursement for the value of fuel used by Noble under an offshore daywork drilling contract. The parties settled this litigation in the fourth quarter of 2013, and the settlement did not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Environmental matters – We are subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance.

At December 31, 2013 and 2012, accrued liabilities for remediation were not significant. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties that may be imposed.

Guarantees – We have entered into a guarantee of a long-term transportation services agreement and a performance guarantee related to asset retirement obligations with aggregate maximum potential undiscounted payments totaling $96 million as of December 31, 2013. Under the terms of these guarantee arrangements, we would be required to perform should the guaranteed party fail to fulfill its obligations under the specified arrangements.

Over the years, we have sold various assets in the normal course of our business. Certain of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require us to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling assets. We are typically not able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the underlying triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based.

Contract commitments – At December 31, 2013 and 2012, contractual commitments to acquire property, plant and equipment totaled$1,270 millionand$949 million.

Other contingencies – During the second quarter of 2011, the AOSP operator determined the need and developed preliminary plans to address water flow into a previously mined and contained section of the Muskeg River mine. Our share of the estimated costs in the amount of $64 million was recorded to production expense in 2011. At December 31, 2013, the remaining liability is $29 million.

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Debt (Details) (USD $)	12 Months Ended
	Dec. 31, 2013 extension	Dec. 31, 2012
Debt Instrument [Line Items]
Line of Credit Facility, Amount Outstanding	$ 0
Commercial paper	135,000,000	200,000,000
Line of Credit Facility, Maximum Borrowing Capacity	2,500,000,000
Line of Credit Facility, Expiration Date	Apr. 30, 2017
Line Of Credit Extended Borrowing Capacity	1,000,000,000
Line of Credit Facility, Number of One Year Extensions	2
Ratio of Indebtedness to Net Capital		0.65
Bridge Loan [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	100,000,000
Letter of Credit [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 500,000,000

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

Income tax provisions (benefits) for continuing operations were:

	2013							2012									2011
(In millions)	Current		Deferred			Total		Current			Deferred			Total			Current			Deferred			Total
Federal	$	63	$	(46	)	$	17	$	(80	)	$	(30	)	$	(110	)	$	(193	)	$	(217	)	$	(410	)
State and local	44		1			45		(23		)	47			24			24			82			106
Foreign	3,290		(15		)	3,275		4,844			(241		)	4,603			3,088			(58		)	3,030
Total	$	3,397	$	(60	)	$	3,337	$	4,741		$	(224	)	$	4,517		$	2,919		$	(193	)	$	2,726

Schedule of Effective Income Tax Rate Reconciliation

A reconciliation of the federal statutory income tax rate applied to income from continuing operations before income taxes to the provision for income taxes follows:

	2013		2012		2011
Statutory rate applied to income from continuing operations before income taxes	35	%	35	%	35	%
Effects of foreign operations, including foreign tax credits	14		18		6
Change in permanent reinvestment assertion	—		—		5
Adjustments to valuation allowances	18		21		14
Tax law changes	—		—		1
Other	1		—		—
Effective income tax rate on continuing operations	68	%	74	%	61	%

Schedule of Deferred Tax Assets and Liabilities

Deferred tax assets and liabilities resulted from the following:

	December 31,
(In millions)	2013			2012
Deferred tax assets:
Employee benefits	$	387		$	510
Operating loss carryforwards	284			368
Foreign tax credits	5,730			4,351
Other	98			121
Valuation allowances:
Federal	(2,997		)	(2,067		)
State, net of federal benefit	(67		)	(60		)
Foreign	(149		)	(210		)
Total deferred tax assets	3,286			3,013
Deferred tax liabilities:
Property, plant and equipment	4,018			3,691
Investments in subsidiaries and affiliates	794			840
Other	67			12
Total deferred tax liabilities	4,879			4,543
Net deferred tax liabilities	$	1,593		$	1,530

Net Deferred Tax Assets Liabilities Table

Net deferred tax liabilities were classified in the consolidated balance sheets as follows:

	December 31,
(In millions)	2013		2012
Assets:
Other current assets	$	53	$	57
Other noncurrent assets	847		849
Liabilities:
Other current liabilities	1		4
Noncurrent deferred tax liabilities	2,492		2,432
Net deferred tax liabilities	$	1,593	$	1,530

Income Tax Returns Remaining Subject To Examination Table

As of December 31, 2013, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:

United States(a)	2004-2012
Canada	2008-2012
Equatorial Guinea	2007-2012
Libya	2006-2012
Norway	2008-2012
United Kingdom	2008-2012

^(a)  Includes federal and state jurisdictions.

Summary Of Activity In Unrecognized Tax Benefits Table

The following table summarizes the activity in unrecognized tax benefits:

(In millions)	2013			2012			2011
Beginning balance	$	98		$	157		$	103
Additions for tax positions related to the current year	14			—			4
Additions for tax positions of prior years	66			81			87
Reductions for tax positions of prior years	(25		)	(67		)	(29		)
Settlements	(5		)	(72		)	(8		)
Statute of limitations	(2		)	(1		)	—
Ending balance	$	146		$	98		$	157

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Leases (Tables)

12 Months Ended

Dec. 31, 2013

Leases [Abstract]

Future Minimum Commitments For Capital And Operating Leases Table

Future minimum commitments for capital lease obligations and for operating lease obligations having noncancellable lease terms in excess of one year are as follows:

(In millions)	Capital Lease Obligations			Operating Lease Obligations
2014	$	1		$	45
2015	1			42
2016	1			34
2017	1			22
2018	1			20
Later years	23			48
Sublease rentals	—			(4		)
Total minimum lease payments	$	28		$	207
Less imputed interest costs	(18		)
Present value of net minimum lease payments	$	10

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Property, Plant and Equipment (Details 2) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013 project	Dec. 31, 2012 project	Dec. 31, 2011 project
Property, Plant and Equipment [Abstract]
Amounts capitalized less than one year after completion of drilling	$ 512	$ 388	$ 482
Amounts capitalized greater than one year after completion of drilling	281	229	222
Total deferred exploratory well costs	793	617	704
Projects that have Exploratory Well Costs that have been Capitalized for Period Greater than One Year, Number of Projects	7	6	5
Increase (Decrease) in Capitalized Exploratory Well Costs that are Pending Determination of Proved Reserves [Roll Forward]
Beginning balance	617	704	657
Additions	746	699	625
Dry well expense	(147)	(111)	(223)
Transfers to development	(414)	(629)	(279)
Dispositions	(9)	(46)	(76)
Ending balance	$ 793	$ 617	$ 704

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Consolidated Statements of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues and other income:
Sales and other operating revenues, including related party	$ 12,419	$ 12,963	$ 10,750
Marketing revenues	2,082	2,729	3,919
Income from equity method investments	423	370	462
Net gain (loss) on disposal of assets	(29)	127	103
Other income	64	32	48
Total revenues and other income	14,959	16,221	15,282
Costs and expenses:
Production	2,331	2,202	1,951
Marketing, including purchases from related parties	2,072	2,744	3,898
Other operating	439	425	533
Exploration	988	706	641
Depreciation, depletion and amortization	2,790	2,477	2,263
Impairments	96	371	310
Taxes other than income	352	248	193
General and administrative	687	699	663
Total costs and expenses	9,755	9,872	10,452
Income from operations	5,204	6,349	4,830
Net interest and other	(274)	(219)	(107)
Loss on early extinguishment of debt	0	0	(279)
Income from continuing operations before income taxes	4,930	6,130	4,444
Provision for income taxes	3,337	4,517	2,726
Income from continuing operations	1,593	1,613	1,718
Discontinued operations	160	(31)	1,228
Net income	$ 1,753	$ 1,582	$ 2,946
Basic:
Income from continuing operations (in dollars per share)	$ 2.26	$ 2.28	$ 2.42
Discontinued operations (in dollars per share)	$ 0.23	$ (0.04)	$ 1.73
Net income (in dollars per share)	$ 2.49	$ 2.24	$ 4.15
Diluted:
Income from continuing operations (in dollars per share)	$ 2.24	$ 2.27	$ 2.41
Discontinued operations (in dollars per share)	$ 0.23	$ (0.04)	$ 1.72
Net income (in dollars per share)	$ 2.47	$ 2.23	$ 4.13
Dividends (in dollars per share)	$ 0.72	$ 0.68	$ 0.8
Weighted average shares:
Basic	705	706	710
Diluted	709	710	714

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Fair Value Measurements Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2013 and 2012 by fair value hierarchy level.

	December 31, 2013
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Interest rate	$	—	$	8	$	—	$	—	$	8
Foreign currency	—		2		—		—		2
Derivative instruments, assets	$	—	$	10	$	—	$	—	$	10
Derivative instruments, liabilities
Foreign currency	$	—	$	4	$	—	$	—	$	4
Derivative instruments, liabilities	$	—	$	4	$	—	$	—	$	4
	December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Commodity	$	—	$	52	$	—	$	1	$	53
Interest rate	—		21		—		—		21
Foreign currency	—		18		—		—		18
Derivative instruments, assets	$	—	$	91	$	—	$	1	$	92

Fair Value, Assets and Liabilities Measured on Nonrecurring Basis

The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.

	2013				2012				2011
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	5	$	96	$	16	$	371	$	226	$	285
Intangible assets	—		—		—		—		—		25

Fair Value, by Balance Sheet Grouping

The following table summarizes financial instruments, excluding receivables, commercial paper, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at December 31, 2013 and 2012.

	December 31,
	2013				2012
(In millions)	Fair Value		Carrying Amount		Fair Value		Carrying Amount
Financial assets
Other noncurrent assets	$	154	$	147	$	189	$	186
Total financial assets	$	154	$	147	$	189	$	186
Financial liabilities
Other current liabilities	$	13	$	13	$	13	$	13
Long-term debt, including current portion(a)	6,922		6,427		7,610		6,642
Deferred credits and other liabilities	149		147		94		94
Total financial liabilities	$	7,084	$	6,587	$	7,717	$	6,749

^(a)  Excludes capital leases.

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Incentive Based Compensation Plans (Details 5-Performance) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended			3 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 30, 2011 Performance Unit [Member]	Dec. 31, 2013 Performance Unit [Member]	Dec. 31, 2012 Performance Unit [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Term				30 months	36 months
Performance Unit Term, Portion				18 months
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	2,120,839			15,000,000	353,600	12,700,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	4,031,888	4,177,884			93,100
Valuation date stock price					$ 35.30
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Dividend Rate	2.10%	2.20%	2.10%		2.10%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate	38.00%	41.00%	40.00%		26.00%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	2.00%	1.00%	0.00%		0.40%
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 31.80	$ 29.02	$ 25.88		$ 34.08
Award instruments other than options performance unit compensation expense	$ 9	$ 12	$ 32
Award instruments other than options performance unit compensation expense accelerated			$ 14

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating activities:
Net income	$ 1,753	$ 1,582	$ 2,946
Adjustments to reconcile net income to net cash provided by operating activities:
Discontinued operations	(160)	31	(1,228)
Loss on early extinguishment of debt	0	0	279
Deferred income taxes	(60)	(224)	(193)
Depreciation, depletion and amortization	2,790	2,477	2,263
Impairments	96	371	310
Pension and other postretirement benefits, net	45	(31)	64
Exploratory dry well costs and unproved property impairments	798	457	357
Net (gain) loss on disposal of assets	29	(127)	(103)
Equity method investments, net	12	11	47
Changes in:
Current receivables	277	(502)	9
Inventories	(16)	(32)	33
Current accounts payable and accrued liabilities	(616)	71	489
All other operating, net	143	(48)	168
Net cash provided by continuing operations	5,091	4,036	5,441
Net cash provided by (used in) discontinued operations	179	(19)	1,083
Net cash provided by operating activities	5,270	4,017	6,524
Investing activities:
Acquisitions, net of cash acquired	(74)	(1,033)	(4,470)
Additions to property, plant and equipment	(4,766)	(4,593)	(2,986)
Disposal of assets	450	467	518
Investments - return of capital	61	57	59
Investing activities of discontinued operations	(227)	(347)	(802)
All other investing, net	35	10	14
Net cash used in investing activities	(4,521)	(5,439)	(7,667)
Financing activities:
Commercial paper, net	(65)	200	0
Borrowings	0	1,997	0
Debt issuance costs	0	(21)	0
Debt repayments	(182)	(145)	(2,877)
Purchases of common stock	(500)	0	(300)
Dividends paid	(508)	(480)	(567)
Financing activities of discontinued operations	0	0	2,916
Distribution in spin-off	0	0	(1,622)
All other financing, net	93	49	155
Net cash provided by (used in) financing activities	(1,162)	1,600	(2,295)
Effect of exchange rate changes on cash	(7)	13	(20)
Net increase (decrease) in cash and cash equivalents	(420)	191	(3,458)
Cash and cash equivalents at beginning of period	684	493	3,951
Cash and cash equivalents at end of period	$ 264	$ 684	$ 493

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Incentive Based Compensation (Details 3 - Stock Options) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range End Of Period [Line Items]
Number of Shares Outstanding Under Option	18,104,887
Weighted Average Remaining Contractual Life	5 years
Weighted Average Exercise Price - Outstanding Shares	$ 27.27
Number of Shares Exercisable Under Option	14,186,632
Weighted Average Exercise Price - Exercisable Shares	$ 25.64
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding, Intrinsic Value	$ 152
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Intrinsic Value	144
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercisable, Weighted Average Remaining Contractual Term	4 years
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Exercisable, Number	18,023,888
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Exercisable, Weighted Average Exercise Price	$ 27.24
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Outstanding, Weighted Average Remaining Contractual Term	5 years
Share-based Compensation Arrangement by Share-based Payment Award, Options, Vested and Expected to Vest, Exercisable, Aggregate Intrinsic Value	152
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 16
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition	2 years
$ 7.99-12.75
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range End Of Period [Line Items]
Number of Shares Outstanding Under Option	259,164
Weighted Average Remaining Contractual Life	0 years 4 months
Weighted Average Exercise Price - Outstanding Shares	$ 10.53
Number of Shares Exercisable Under Option	259,164
Weighted Average Exercise Price - Exercisable Shares	$ 10.53
12.76-16.81
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range End Of Period [Line Items]
Number of Shares Outstanding Under Option	1,937,181
Weighted Average Remaining Contractual Life	3 years
Weighted Average Exercise Price - Outstanding Shares	$ 15.13
Number of Shares Exercisable Under Option	1,937,181
Weighted Average Exercise Price - Exercisable Shares	$ 15.13
16.82-23.20
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range End Of Period [Line Items]
Number of Shares Outstanding Under Option	4,255,365
Weighted Average Remaining Contractual Life	5 years
Weighted Average Exercise Price - Outstanding Shares	$ 18.57
Number of Shares Exercisable Under Option	4,255,365
Weighted Average Exercise Price - Exercisable Shares	$ 18.57
23.21-29.24
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range End Of Period [Line Items]
Number of Shares Outstanding Under Option	1,740,398
Weighted Average Remaining Contractual Life	4 years
Weighted Average Exercise Price - Outstanding Shares	$ 24.59
Number of Shares Exercisable Under Option	1,489,683
Weighted Average Exercise Price - Exercisable Shares	$ 24.05
29.25-36.03
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range End Of Period [Line Items]
Number of Shares Outstanding Under Option	7,541,433
Weighted Average Remaining Contractual Life	7 years
Weighted Average Exercise Price - Outstanding Shares	$ 33.06
Number of Shares Exercisable Under Option	3,967,422
Weighted Average Exercise Price - Exercisable Shares	$ 32.70
36.04-46.41
Share Based Compensation Shares Authorized Under Stock Option Plans Exercise Price Range End Of Period [Line Items]
Number of Shares Outstanding Under Option	2,371,346
Weighted Average Remaining Contractual Life	3 years
Weighted Average Exercise Price - Outstanding Shares	$ 38.19
Number of Shares Exercisable Under Option	2,277,817
Weighted Average Exercise Price - Exercisable Shares	$ 38.26

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Dispositions (Details) (USD $)	12 Months Ended			1 Months Ended			1 Months Ended				7 Months Ended	12 Months Ended						3 Months Ended	1 Months Ended		12 Months Ended	3 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jun. 30, 2013 DJ Basin [Member]	Apr. 30, 2011 DJ Basin [Member] acre	Feb. 28, 2013 Marcellus Shale [Member]	Feb. 28, 2013 Neptune Gas Plant [Member]	Jan. 31, 2013 Alaska EP [Member]	Dec. 31, 2012 Alaska Assets And Neptune Gas Plant [Member]	Dec. 31, 2013 Safen Block [Member]	Dec. 31, 2013 Angola Assets [Member]	Dec. 31, 2013 Angola Assets [Member]	Dec. 31, 2012 Angola Assets [Member]	Dec. 31, 2011 Angola Assets [Member]	Dec. 31, 2013 Angola Blk 31 [Member]	Jun. 30, 2013 Angola Blk 31 [Member]	Dec. 31, 2013 Angola Blk 32 [Member]	Sep. 30, 2012 Eagle Ford Shale Member [Member] acre	Jan. 31, 2012 GOM Pipelines [Member]	May 31, 2012 INDONESIA	Dec. 31, 2011 Burnspoint [Member]	Sep. 30, 2011 Alaska LNG [Member]
Dispositions Detail [Line Items]
Agreement of Sale of Oil and Gas Property and Equipment											$ 2,100,000,000
Gas and oil acreages undeveloped and developed net					180,000													5,800
Proceeds from Sale of Oil and Gas Property and Equipment	450,000,000	467,000,000	518,000,000	19,000,000	270,000,000		166,000,000	195,000,000										9,000,000	206,000,000		36,000,000	8,000,000
Proceeds from Sale of Oil and Gas Property and Equipment, Six Month Escrow								50,000,000
Pretax gain/loss on sale				114,000,000	(37,000,000)	43,000,000	(98,000,000)	(55,000,000)		17,000,000								18,000,000	(166,000,000)	36,000,000	(34,000,000)	(8,000,000)
Interest Percentage					30.00%					45.00%						10.00%	10.00%				50.00%
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Disposal Group, Including Discontinued Operation, Revenue												361,000,000
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax												247,000,000	(17,000,000)	(17,000,000)
Disposal Group, Including Discontinued Operation, Balance Sheet Disclosures [Abstract]
Assets of Disposal Group, Including Discontinued Operation, Current									50,000,000						41,000,000
Disposal Group, Including Discontinued Operation, Other Noncurrent Assets									248,000,000						1,647,000,000
Total assets									298,000,000						1,688,000,000
Liabilities of Disposal Group, Including Discontinued Operation, Current															25,000,000
Liabilities of Disposal Group, Including Discontinued Operation, Noncurrent									83,000,000						43,000,000
Total liabilities									$ 83,000,000						$ 68,000,000

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Leases (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Year 1 Operating	$ 45
Year 2 Operating	42
Year 3 Operating	34
Year 4 Operating	22
Year 5 Operating	20
Later years, Operating Leases	48
Sublease rentals	(4)
Operating Leases, Future Minimum Payments Due	207
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Year 1 Capital	1
Year 2 Capital	1
Year 3 Capital	1
Year 4 Capital	1
Year 5 Capital	1
Later years, Capital Leases	23
Capital Leases, Future Minimum Sublease Rentals	0
Capital Leases, Future Minimum Payments Due	28
Less imputed interest costs	(18)
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments	10
Operating Leases, Rent Expense, Net [Abstract]
Operating Leases, Rent Expense	$ 106	$ 103	$ 70

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Acquisitions (Tables)

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

The following table summarizes the amounts allocated to the assets acquired and liabilities assumed based upon their fair values at the acquisition dates:

	Closed in Quarter Ended
	June 30,		September 30,		December 31,
(In millions)	2012		2012		2011
Current assets:
Cash	$	8	$	—	$	—
Receivables	22		8		40
Inventories	1		—		4
Other current assets	—		—		30
Total current assets acquired	31		8		74
Property, plant and equipment	822		248		4,501
Other noncurrent assets	—		—		21
Total assets acquired	853		256		4,596
Current liabilities:
Accounts payable	78		23		101
Other current liabilities	—		—		20
Total current liabilities assumed	78		23		121
Asset retirement obligations	7		1		5
Total liabilities assumed	85		24		126
Net assets acquired	$	768	$	232	$	4,470

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Other Items (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Net Interest and Other Financing [Abstract]
Interest income	$ 6		$ 13		$ 12
Interest expense(a)	(307)	[1]	(244)	[1]	(228)	[1]
Income on interest rate swaps	9		7		10
Interest capitalized	21		12		103
Total interest	(271)		(212)		(103)
Net foreign currency gains (losses)	16		4		24
Write off of contingent proceeds	(4)		0		(7)
Other	(15)		(11)		(21)
Total other	(3)		(7)		(4)
Net interest and other	(274)		(219)		(107)
Interest payments made on our behalf			1		10
Aggregate foreign currency gains losses [Abstract]
Net interest and other	16		4		24
Provision for income taxes	105		(80)		57
Aggregate foreign currency gains (losses)	$ 121		$ (76)		$ 81

[1] Excludes $1 million and $10 million paid by United States Steel in 2012 and 2011 on assumed debt.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2013

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

Fair values – Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2013 and 2012 by fair value hierarchy level.

	December 31, 2013
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Interest rate	$	—	$	8	$	—	$	—	$	8
Foreign currency	—		2		—		—		2
Derivative instruments, assets	$	—	$	10	$	—	$	—	$	10
Derivative instruments, liabilities
Foreign currency	$	—	$	4	$	—	$	—	$	4
Derivative instruments, liabilities	$	—	$	4	$	—	$	—	$	4
	December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Derivative instruments, assets
Commodity	$	—	$	52	$	—	$	1	$	53
Interest rate	—		21		—		—		21
Foreign currency	—		18		—		—		18
Derivative instruments, assets	$	—	$	91	$	—	$	1	$	92

Interest rate swaps are measured at fair value with a market approach using actionable broker quotes which are Level 2 inputs.  Foreign currency forwards are measured at fair value with a market approach using third-party pricing services, such as Bloomberg L.P., which have been corroborated with data from active markets for similar assets or liabilities, and are Level 2 inputs.

Commodity swaps in Level 2 are measured at fair value with a market approach using prices obtained from exchanges or pricing services, which have been corroborated with data from active markets for similar assets or liabilities.  Commodity options in Level 2 are valued using the Black-Scholes Model.  Inputs to this model include prices as noted above, discount factors, and implied market volatility.  The inputs to this fair value measurement are categorized as Level 2 because predominantly all assumptions and inputs are observable in active markets throughout the term of the instruments.  Collateral deposits related to commodity derivatives are in broker accounts covered by master netting agreements.

Fair values – Nonrecurring

The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition.

	2013				2012				2011
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for use	$	5	$	96	$	16	$	371	$	226	$	285
Intangible assets	—		—		—		—		—		25

International E&P

Long-lived assets held for use – In light of E.G.’s recent natural gas policy developments related to the country’s natural gas resources, we elected to cease our efforts to develop a second LNG production train on Bioko Island and recorded a $40 million impairment of all capitalized costs associated with engineering and feasibility studies in the fourth quarter of 2013. In addition, our share of income from EGHoldings included a $4 million impairment related to the same project which is reflected in income from equity method investments in the 2013 consolidated statement of income.

North America E&P

Long-lived assets held for use – The fair values were measured using an income approach based upon internal estimates of future production levels, prices and discount rate, all of which are Level 3 inputs.  Inputs to the fair value measurement included reserve and production estimates made by our reservoir engineers, estimated commodity prices adjusted for quality and location differentials, and forecasted operating expenses for the remaining estimated life of the reservoir.

In the fourth quarter of 2012, declining natural gas prices related to our Powder River Basin asset prompted lower production expectations and reductions in estimated reserves which resulted in an impairment of $73 million. Subsequently, in the first quarter of 2013, as a result of our decision to wind down operations in the Powder River Basin due to poor economics, an additional impairment of $15 million was recorded to write down the asset's remaining fair value.

During early 2012, production rates from the Ozona development in the Gulf of Mexico declined significantly.  Accordingly, our reserve engineers performed evaluations of our future production as well as our reserves and an impairment was recorded in the first quarter of 2012. As the development produced toward abandonment pressures, further downward revisions of reserves were taken for an aggregate impairment of $289 million in 2012.  Ozona production ceased in the first quarter of 2013 and an additional $21 million impairment was recorded.

In May 2011, significant water production and reservoir pressure declines occurred at our Droshky development in the Gulf of Mexico. Plans for a waterflood were canceled and due to a decrease in proved reserves, a $273 million impairment of this asset to its $226 million fair value was recorded in 2011.

Other impairments of long-lived assets held for use in 2013, 2012 and 2011 were a result of reduced drilling expectations, reductions of estimated reserves or declining natural gas prices.

Intangible assets– In the second quarter of 2011, our outlook for U.S. natural gas prices made it unlikely that sufficient U.S. demand for LNG would materialize by 2021, which is when the rights lapse under our arrangements at the Elba Island, Georgia regasification facility. Using an income approach based upon internal estimates of gas prices and future deliveries, which are Level 3 inputs, we determined that the contract had no remaining fair value and recorded a full impairment of this intangible asset.

Fair values – Financial instruments

Our current assets and liabilities include financial instruments, the most significant of which are receivables, commercial paper and payables. We believe the carrying values of our receivables, commercial paper and payables approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) our investment-grade credit rating, and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.

The following table summarizes financial instruments, excluding receivables, commercial paper, payables and derivative financial instruments, and their reported fair value by individual balance sheet line item at December 31, 2013 and 2012.

	December 31,
	2013				2012
(In millions)	Fair Value		Carrying Amount		Fair Value		Carrying Amount
Financial assets
Other noncurrent assets	$	154	$	147	$	189	$	186
Total financial assets	$	154	$	147	$	189	$	186
Financial liabilities
Other current liabilities	$	13	$	13	$	13	$	13
Long-term debt, including current portion(a)	6,922		6,427		7,610		6,642
Deferred credits and other liabilities	149		147		94		94
Total financial liabilities	$	7,084	$	6,587	$	7,717	$	6,749

^(a)  Excludes capital leases.

Fair values of our financial assets included in other noncurrent assets, and of our financial liabilities included in other current liabilities and deferred credits and other liabilities are measured using an income approach and most inputs are internally generated, which results in a Level 3 classification. Estimated future cash flows are discounted using a rate deemed appropriate to obtain the fair value.

Most of our long-term debt instruments are publicly-traded. A market approach, based upon quotes from major financial institutions, which are Level 2 inputs, is used to measure the fair value of such debt. The fair value of our debt that is not publicly-traded is measured using an income approach. The future debt service payments are discounted using the rate at which we currently expect to borrow. All inputs to this calculation are Level 3.

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Dispositions (Tables)

12 Months Ended

Dec. 31, 2013

Discontinued Operations and Disposal Groups [Abstract]

Schedule of Disposal Groups, Including Discontinued Operations, Income Statement, Balance Sheet and Additional Disclosures [Table Text Block]

Assets held for sale in the December 31, 2013 consolidated balance sheet were related to the Angola Block 31 disposition that was pending at that date and included:

(In millions)	December 31, 2013
Other current assets	$	41
Other noncurrent assets	1,647
Total assets	$	1,688
Other current liabilities	$	25
Deferred credits and other liabilities	43
Total liabilities	$	68

Related amounts reported in discontinued operations for 2013, 2012 and 2011 were as follows:

(In millions)	2013		2012			2011
Revenues applicable to discontinued operations	$	361	$	—		$	—
Pretax income (loss) from discontinued operations	$	247	$	(17	)	$	(17	)

Assets held for sale in the December 31, 2012 consolidated balance sheet were related to the Neptune gas plant and Alaska dispositions that were pending at that date and included:

(In millions)	December 31, 2012
Other current assets	$	50
Other noncurrent assets	248
Total assets	$	298
Deferred credits and other liabilities	$	83
Total liabilities	$	83

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Stockholders Equity (Details) (USD $) Share data in Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 11, 2013
Stockholders' Equity Attributable to Parent [Abstract]
Treasury Stock, Shares, Acquired	14
Treasury Stock, Value, Acquired, Cost Method	$ 500,000,000	$ 513,000,000	$ 8,000,000	$ 308,000,000
Authorized Stock Repurchase Program Repurchased Number Of Shares		92
Authorized Stock Repurchase Program Repurchase Amount		3,722,000,000
Additional Treasury Stock Amount of Repurchase Authorization					1,200,000,000
Stock Repurchase Program, Remaining Authorized Repurchase Amount		$ 2,500,000,000

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Debt

12 Months Ended

Dec. 31, 2013

Debt Disclosure [Abstract]

Debt

Debt

Short-term debt

As of December 31, 2013, we had no borrowings against our revolving credit facility, as described below, and we had $135 million in commercial paper outstanding under our U.S. commercial paper program that is backed by the revolving credit facility.

Our $2.5 billion unsecured five-year revolving credit facility (the "Credit Facility") was entered in April 2012.  The Credit Facility matures in April 2017, but allows us to request two one-year extensions.   It contains an option to increase the commitment amount by up to an additional $1.0 billion, subject to the consent of any increasing lenders, and includes sub-facilities for swing-line loans and letters of credit up to an aggregate amount of $100 million and $500 million, respectively.  The agreement contains a covenant that requires our ratio of total debt to total capitalization not to exceed 65 percent as of the last day of each fiscal quarter.  If an event of default occurs, the lenders may terminate the commitments under the Credit Facility and require the immediate repayment of all outstanding borrowings and the cash collateralization of all outstanding letters of credit under the Credit Facility.

Long-term debt

The following table details our long-term debt:

	December 31,
(In millions)	2013			2012
Senior unsecured notes:
9.125% notes due 2013	$	—		$	114
0.900% notes due 2015(a)	1,000			1,000
6.000% notes due 2017(a)	682			682
5.900% notes due 2018(a)	854			854
7.500% notes due 2019(a)	228			228
2.800% notes due 2022(a)	1,000			1,000
9.375% notes due 2022	32			32
Series A notes due 2022	3			3
8.500% notes due 2023	70			70
8.125% notes due 2023	131			131
6.800% notes due 2032(a)	550			550
6.600% notes due 2037	750			750
Capital leases:
Capital lease obligation of consolidated subsidiary due 2014 – 2049	10			11
Other obligations:
4.550% promissory note, semi-annual payments due 2014 – 2015	136			204
5.125% obligation relating to revenue bonds due 2037	1,000			1,000
Other	—			35
Total(b)	6,446			6,664
Unamortized discount	(9		)	(11		)
Fair value adjustments(c)	25			43
Amounts due within one year	(68		)	(184		)
Total long-term debt due after one year	$	6,394		$	6,512

^(a)  These notes contain a make-whole provision allowing us the right to repay the debt at a premium to market price.

^(b)  In the event of a change in control, as defined in the related agreements, debt obligations totaling $236 million at December 31, 2013, may be declared immediately due and payable.

^(c)  See Notes 15 and 16 for information on interest rate swaps.

The following table shows five years of long-term debt payments:

(In millions)
2014	$	68
2015	1,068
2016	—
2017	682
2018	854

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Income Taxes (Details 3) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Unrecognized Tax Benefit Rollforward [Abstract]
Unrecognized Tax Benefits, Beginning Balance	$ 98	$ 157	$ 103
Additions for tax positions related to the current year	14	0	4
Additions for tax positions of prior years	66	81	87
Reductions for tax positions of prior years	(25)	(67)	(29)
Settlements	(5)	(72)	(8)
Statute of limitations	(2)	(1)	0
Unrecognized Tax Benefits, Ending Balance	146	98	157
Unrecognized Tax Benefits That Would Impact Effective Tax Rate	98
Significant Change In Unrecognized Tax Benefits Is Reasonably Possible Amount Of Unrecorded Benefit	11
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense [Abstract]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Expense	13	4	13
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued [Abstract]
Unrecognized Tax Benefits, Income Tax Penalties and Interest Accrued	15	24
Foreign Source Income [Abstract]
Foreign Earnings Repatriated	4,874	6,382	4,886
Undistributed Income Of Certain Consolidated Foreign Subsidiaries	1,438
Deferred Tax Liability Not Recognized, Amount of Unrecognized Deferred Tax Liability, Undistributed Earnings of Foreign Subsidiaries	$ 503

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Consolidated Statements of Stockholders Equity (USD $) In Millions, except Share data, unless otherwise specified	Total	Preferred Stock [Member]	Common Stock [Member]	Securities Exchangeable for Common Stock[Member]	Treasury Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Noncontrolling Interest [Member]
Beginning Balance at Dec. 31, 2010	$ 23,771	$ 0	$ 770		$ (2,665)	$ 6,756	$ 19,907	$ (997)
Treasury shares at Dec. 31, 2010					60,000,000
Shares Beginning Balance at Dec. 31, 2010			770,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued - stock based compensation	172				257	85
Shares repurchased	(308)				(308)
Stock-based compensation	4					4
Net income	2,946						2,946
Other comprehensive income (loss)	40							40
Dividends paid	(567)						(567)
Purchase of subsidiary shares from non-controlling interest	7								7
Spin-off of downstream	(8,906)					5	(9,498)	587
Shares issued - stock based compensation					(6,000,000)
Shares repurchased					12,000,000
Ending Balance at Dec. 31, 2011	17,159	0	770	0	(2,716)	6,680	12,788	(370)	7
Shares Ending Balance at Dec. 31, 2011		0
Treasury shares at Dec. 31, 2011					66,000,000
Shares Beginning Balance at Dec. 31, 2011			770,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued - stock based compensation	89				164	75
Shares repurchased	(8)				(8)
Stock-based compensation	22					22
Net income	1,582						1,582
Other comprehensive income (loss)	(63)							(63)
Dividends paid	(480)						(480)
Purchase of subsidiary shares from non-controlling interest	(7)								(7)
Spin-off of downstream	(11)					(11)
Shares issued - stock based compensation					(3,000,000)
Ending Balance at Dec. 31, 2012	18,283	0	770	0	(2,560)	6,616	13,890	(433)
Shares Ending Balance at Dec. 31, 2012		0
Treasury shares at Dec. 31, 2012	63,000,000				63,000,000
Shares Beginning Balance at Dec. 31, 2012			770,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued - stock based compensation	126				170	44
Shares repurchased	(513)	0			(513)
Stock-based compensation	20					20
Net income	1,753						1,753
Other comprehensive income (loss)	183							183
Dividends paid	(508)						(508)
Shares issued - stock based compensation					(4,000,000)
Shares repurchased					14,000,000
Ending Balance at Dec. 31, 2013	19,344	0	770		(2,903)	6,592	15,135	(250)
Shares Ending Balance at Dec. 31, 2013		$ 0

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Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Comprehensive Income [Abstract]
Net income	$ 1,753	$ 1,582	$ 2,946
Postretirement and postemployment plans
Change in actuarial loss and other	296	(97)	16
Income tax benefit (provision) on postretirement and postemployment plans	(112)	35	20
Postretirement and postemployment plans, net of tax	184	(62)	36
Derivative hedges
Net unrecognized gain	1	1	9
Income tax provision on derivative hedges	0	0	(4)
Derivative hedges, net of tax	1	1	5
Foreign currency translation and other
Unrealized gain (loss)	(3)	1	(1)
Income tax benefit (provision) on foreign currency translation and other	1	(3)	0
Foreign currency translation and other, net of tax	(2)	(2)	(1)
Other comprehensive income (loss)	183	(63)	40
Comprehensive income	$ 1,936	$ 1,519	$ 2,986

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Income Taxes

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Income tax provisions (benefits) for continuing operations were:

	2013							2012									2011
(In millions)	Current		Deferred			Total		Current			Deferred			Total			Current			Deferred			Total
Federal	$	63	$	(46	)	$	17	$	(80	)	$	(30	)	$	(110	)	$	(193	)	$	(217	)	$	(410	)
State and local	44		1			45		(23		)	47			24			24			82			106
Foreign	3,290		(15		)	3,275		4,844			(241		)	4,603			3,088			(58		)	3,030
Total	$	3,397	$	(60	)	$	3,337	$	4,741		$	(224	)	$	4,517		$	2,919		$	(193	)	$	2,726

A reconciliation of the federal statutory income tax rate applied to income from continuing operations before income taxes to the provision for income taxes follows:

	2013		2012		2011
Statutory rate applied to income from continuing operations before income taxes	35	%	35	%	35	%
Effects of foreign operations, including foreign tax credits	14		18		6
Change in permanent reinvestment assertion	—		—		5
Adjustments to valuation allowances	18		21		14
Tax law changes	—		—		1
Other	1		—		—
Effective income tax rate on continuing operations	68	%	74	%	61	%

The effective income tax rate is influenced by a variety of factors including the geographic and functional sources of income, the relative magnitude of these sources of income, and foreign currency remeasurement effects. 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 appears in the "Not Allocated to Segments" column of the tables in Note 8.

Effects of foreign operations – The effects of foreign operations on our effective tax rate decreased in 2013 as compared to 2012, primarily due to decreased sales in Libya in 2013 as a result of third-party labor strikes at the Es Sider oil terminal. The effects of foreign operations on our effective tax rate increased in 2012 from 2011, primarily due to the resumption of sales of Libyan production in 2012.

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 recognizing deferred U.S. tax on previously undistributed earnings.

Adjustments to valuation allowances – In 2013, 2012 and 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 those years.

Tax law changes – The U.K. enacted Finance Bill 2013 in July 2013 and Finance Bill 2012 in July 2012, which did not change the rate of corporation tax or the supplementary corporation tax for U.K. ring-fenced activities in the oil and gas sector. As such, this legislation did not have a material impact on our consolidated income tax provision. In July 2011, the U.K. enacted Finance Bill 2011 which increased the rate of the supplementary charge levied on profits from U.K. oil and gas production from 20 percent to 32 percent. As a result of this legislation, we recorded deferred tax expense of $10 million in 2011.

On May 25, 2011, Michigan enacted legislation that replaced the Michigan Business Tax ("MBT") with a corporate income tax ("CIT"), effective January 1, 2012. The CIT legislation eliminated the "book-tax difference deduction" that was provided under the MBT to mitigate the net increase in a taxpayer’s deferred tax liability resulting when Michigan moved from the Single Business Tax, a non-income tax, to the MBT, an income tax, on July 12, 2007. Such a change in the tax law must be recognized in earnings in the period enacted regardless of the effective date. The total effect of tax law changes on deferred tax balances is recorded as income tax expense related to continuing operations in the period the law is enacted, even if a portion of the deferred tax balances relates to discontinued operations. As a result of the new CIT legislation, we recorded deferred tax expense of $32 million in the second quarter of 2011.

Deferred tax assets and liabilities resulted from the following:

	December 31,
(In millions)	2013			2012
Deferred tax assets:
Employee benefits	$	387		$	510
Operating loss carryforwards	284			368
Foreign tax credits	5,730			4,351
Other	98			121
Valuation allowances:
Federal	(2,997		)	(2,067		)
State, net of federal benefit	(67		)	(60		)
Foreign	(149		)	(210		)
Total deferred tax assets	3,286			3,013
Deferred tax liabilities:
Property, plant and equipment	4,018			3,691
Investments in subsidiaries and affiliates	794			840
Other	67			12
Total deferred tax liabilities	4,879			4,543
Net deferred tax liabilities	$	1,593		$	1,530

Tax carryforwards – At December 31, 2013, our operating loss carryforwards included $744 million from Canada which expire in 2026 through 2030 and $128 million from the Kurdistan Region of Iraq that expire in 2016 through 2018. State operating loss carryforwards of $1,503 million expire in 2014 through 2033. Foreign tax credit carryforwards of $3,560 million expire in 2022 through 2023.

Valuation allowances – The estimated realizability of the benefit of foreign tax credits is based on certain estimates concerning future operating conditions (particularly as related to prevailing liquid hydrocarbon, natural gas and synthetic crude oil prices), future financial conditions, income generated from foreign sources and our tax profile in the years that such credits may be claimed. Federal valuation allowances increased $930 million, $1,277 million and $585 million in 2013, 2012 and 2011, because it is more likely than not that we will be unable to realize all U.S. benefits on foreign taxes accrued in those years.

Foreign valuation allowances decreased $61 million in 2013, primarily due the disposal of our Indonesian assets. Foreign valuation allowances increased $16 million and $52 million in 2012 and 2011, primarily due to deferred tax assets generated in the Kurdistan Region of Iraq, Angola and Indonesia.

Net deferred tax liabilities were classified in the consolidated balance sheets as follows:

	December 31,
(In millions)	2013		2012
Assets:
Other current assets	$	53	$	57
Other noncurrent assets	847		849
Liabilities:
Other current liabilities	1		4
Noncurrent deferred tax liabilities	2,492		2,432
Net deferred tax liabilities	$	1,593	$	1,530

We are continuously undergoing examination of our U.S. federal income tax returns by the IRS. Such audits have been completed through the 2009 tax year. We believe adequate provision has been made for federal income taxes and interest which may become payable for years not yet settled. Further, we are routinely involved in U.S. state income tax audits and foreign jurisdiction tax audits. We believe all other audits will be resolved within the amounts paid and/or provided for these liabilities.

As of December 31, 2013, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:

United States(a)	2004-2012
Canada	2008-2012
Equatorial Guinea	2007-2012
Libya	2006-2012
Norway	2008-2012
United Kingdom	2008-2012

^(a)  Includes federal and state jurisdictions.

The following table summarizes the activity in unrecognized tax benefits:

(In millions)	2013			2012			2011
Beginning balance	$	98		$	157		$	103
Additions for tax positions related to the current year	14			—			4
Additions for tax positions of prior years	66			81			87
Reductions for tax positions of prior years	(25		)	(67		)	(29		)
Settlements	(5		)	(72		)	(8		)
Statute of limitations	(2		)	(1		)	—
Ending balance	$	146		$	98		$	157

If the unrecognized tax benefits as of December 31, 2013 were recognized, $98 million would affect our effective income tax rate. There were $11 million of uncertain tax positions as of December 31, 2013 for which it is reasonably possible that the amount of unrecognized tax benefits would significantly increase or decrease during the next twelve months.

Interest and penalties are recorded as part of the tax provision and were $13 million, $4 million and $13 million related to unrecognized tax benefits in 2013, 2012 and 2011. As of December 31, 2013 and 2012, $15 million and $24 million of interest and penalties were accrued related to income taxes.

Pretax income from continuing operations included amounts attributable to foreign sources of $4,874 million, $6,382 million and $4,886 million in 2013, 2012 and 2011.

Undistributed income of certain consolidated foreign subsidiaries at December 31, 2013 amounted to $1,438 million for which no U.S. deferred income tax provision has been recorded because we intend to permanently reinvest such income in our foreign operations. If such income was not permanently reinvested, income tax expense of approximately $503 million would be recorded, not including potential utilization of foreign tax credits.

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Incentive Based Compensation Plans (Details 2) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Number of Shares
Beginning year stock option awards	19,536,965
Granted stock option awards	2,051,386
Exercised stock option awards	(2,718,639)
Canceled stock option awards	(764,825)
End of year stock option awards	18,104,887	19,536,965
Weighted Average Exercise price
Beginning year weighted average exercise price	$ 26.19
Granted weighted average exercise price	$ 33.54	$ 33.52	$ 32.30
Exercises weighted average exercise price	$ 22.36
Canceled weighted average exercise price	$ 34.02
End of year weighted average exercise price	$ 27.27	$ 26.19
Share-based Compensation Arrangement by Share-based Payment Award, Options, Exercises in Period, Total Intrinsic Value	$ 35	$ 40	$ 59

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Defined Benefit Postretirement Plans and Defined Contribution Plan (Details 6) (USD $) In Millions, unless otherwise specified	12 Months Ended							1 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2014 Scenario, Forecast [Member]	Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member]	Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member]	Dec. 31, 2013 Other Postretirement Benefit Plans, Defined Benefit [Member]	Jan. 31, 2014 Subsequent Event [Member] United States Pension Plans of US Entity, Defined Benefit [Member]
Defined Benefit Plan Estimated Future Benefit Payments [Line Items]
2014					$ 96	$ 14	$ 19
2015					94	14	20
2016					95	16	20
2017					96	18	20
2018					92	21	20
2019 through 2023					368	120	98
Defined Benefit Plan, Estimated Future Employer Contributions in Next Fiscal Year				77				11
Cash Contributions Expected To Be Paid From General Assets Unfunded Plan	74
Cash Contributions Expected To Be Paid From General Assets Postretirement Plan	19
Defined Benefit Plan, Information about Plan Assets [Abstract]
Defined Contribution Plan, Cost Recognized	$ 26	$ 25	$ 21

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Document and Entity Information (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Jan. 31, 2014	Jun. 28, 2013
Document and Entity Information [Abstract]
Document Type	10-K
Document Period End Date	Dec. 31, 2013
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2013
Amendment Flag	false
Entity Registrant Name	Marathon Oil Corp
Entity Central Index Key	0000101778
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Well Known Seasoned Issuer	Yes
Entity Common Stock, Shares Outstanding		696,944,638
Entity Public Float			$ 24,462

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Inventories

12 Months Ended

Dec. 31, 2013

Inventory Disclosure [Abstract]

Inventories

Inventories

Inventories are carried at the lower of cost or market value. The LIFO method accounted for 4 percent and 6 percent of total inventory value at December 31, 2013 and 2012. Current acquisition costs were estimated to exceed the LIFO inventory value at December 31, 2013 and 2012 by $32 million and $29 million.

	December 31,
(In millions)	2013		2012
Liquid hydrocarbons, natural gas and bitumen	$	55	$	73
Supplies and other items	309		288
Inventories at cost	$	364	$	361

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Derivatives (Details 3-Fair Value Hedges IS & OCI) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Net interest and other [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in unrealized gain (loss) on hedged item in fair value hedge	$ 13	$ (16)	$ (28)
Loss On Early Extinguishment Of Debt [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in unrealized gain (loss) on hedged item in fair value hedge			(29)
Provision For Income Taxes [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in unrealized gain (loss) on hedged item in fair value hedge	44	1	0
Interest rate [Member] | Net interest and other [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in Unrealized Gain (Loss) on Fair Value Hedging Instruments	(13)	16	28
Interest rate [Member] | Loss On Early Extinguishment Of Debt [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in Unrealized Gain (Loss) on Fair Value Hedging Instruments	0	0	29
Foreign Exchange Contract [Member] | Provision For Income Taxes [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Change in Unrealized Gain (Loss) on Fair Value Hedging Instruments	$ (44)	$ (1)	$ 0

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Defined Benefit Postretirement Plans and Defined Contribution Plan (Details 5) (USD $)																																																																																																																																																																																																																																																																																																																																										12 Months Ended
	Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member]	Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member]	Dec. 31, 2011 United States Pension Plans of US Entity, Defined Benefit [Member]	Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Common Stock [Member]		Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] Common Stock [Member]		Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Preferred Stock [Member]	Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Private Equity Funds [Member]	Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] Private Equity Funds [Member]	Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Real Estate Investment Trusts [Member]	Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] Real Estate Investment Trusts [Member]	Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] Equity Securities, Investment Objective [Domain]	Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Investment Funds Mutual Funds Equity [Member]		Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] Investment Funds Mutual Funds Equity [Member]		Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Equity Funds [Member]		Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] Equity Funds [Member]		Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] US Treasury and Government [Member]	Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] US Treasury and Government [Member]	Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Exchange Traded Funds [Member]	Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] Exchange Traded Funds [Member]	Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Corporate Bond Securities [Member]		Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] Corporate Bond Securities [Member]		Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Municipal Bonds [Member]	Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Foreign Government Debt Securities [Member]	Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] Foreign Government Debt Securities [Member]	Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Private Placement [Member]	Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] Private Placement [Member]	Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Taxable Municipal Bonds [Member]	Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] Taxable Municipal Bonds [Member]	Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Treasury Inflation-Protected Securities [Member]	Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Yankee Bonds [Member]	Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] Yankee Bonds [Member]	Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Commingled funds [Member]		Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] Commingled funds [Member]		Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Fixed Income Funds [Member]		Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] Fixed Income Funds [Member]		Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] Real Estate [Member]		Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] Real Estate [Member]		Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member] MRO Other investments [Member]	Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member] MRO Other investments [Member]	Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member]	Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member]	Dec. 31, 2011 Foreign Pension Plans, Defined Benefit [Member]	Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Common Stock [Member]		Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] Common Stock [Member]		Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Preferred Stock [Member]	Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Private Equity Funds [Member]	Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] Private Equity Funds [Member]	Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Real Estate Investment Trusts [Member]	Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] Real Estate Investment Trusts [Member]	Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] Equity Securities, Investment Objective [Domain]	Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Investment Funds Mutual Funds Equity [Member]		Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] Investment Funds Mutual Funds Equity [Member]		Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Equity Funds [Member]		Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] Equity Funds [Member]		Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] US Treasury and Government [Member]	Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] US Treasury and Government [Member]	Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Exchange Traded Funds [Member]	Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] Exchange Traded Funds [Member]	Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Corporate Bond Securities [Member]		Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] Corporate Bond Securities [Member]		Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Municipal Bonds [Member]	Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Foreign Government Debt Securities [Member]	Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] Foreign Government Debt Securities [Member]	Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Private Placement [Member]	Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] Private Placement [Member]	Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Taxable Municipal Bonds [Member]	Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] Taxable Municipal Bonds [Member]	Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Treasury Inflation-Protected Securities [Member]	Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Yankee Bonds [Member]	Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] Yankee Bonds [Member]	Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Commingled funds [Member]		Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] Commingled funds [Member]		Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Fixed Income Funds [Member]		Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] Fixed Income Funds [Member]		Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] Real Estate [Member]		Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] Real Estate [Member]		Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member] MRO Other investments [Member]	Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member] MRO Other investments [Member]	Dec. 31, 2013 Other Postretirement Benefit Plans, Defined Benefit [Member]	Dec. 31, 2012 Other Postretirement Benefit Plans, Defined Benefit [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Common Stock [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Common Stock [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Preferred Stock [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Private Equity Funds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Private Equity Funds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Real Estate Investment Trusts [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Real Estate Investment Trusts [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Equity Securities, Investment Objective [Domain]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Investment Funds Mutual Funds Equity [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Investment Funds Mutual Funds Equity [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Equity Funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Equity Funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] US Treasury and Government [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] US Treasury and Government [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Exchange Traded Funds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Exchange Traded Funds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Corporate Bond Securities [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Corporate Bond Securities [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Municipal Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Foreign Government Debt Securities [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Foreign Government Debt Securities [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Private Placement [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Private Placement [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Taxable Municipal Bonds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Taxable Municipal Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Treasury Inflation-Protected Securities [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Yankee Bonds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Yankee Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Commingled funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Commingled funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Fixed Income Funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Fixed Income Funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Real Estate [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Real Estate [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] MRO Other investments [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] MRO Other investments [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Common Stock [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Common Stock [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Preferred Stock [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Private Equity Funds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Private Equity Funds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Real Estate Investment Trusts [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Real Estate Investment Trusts [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Equity Securities, Investment Objective [Domain]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Investment Funds Mutual Funds Equity [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Investment Funds Mutual Funds Equity [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Equity Funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Equity Funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] US Treasury and Government [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] US Treasury and Government [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Exchange Traded Funds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Exchange Traded Funds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Corporate Bond Securities [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Corporate Bond Securities [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Municipal Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Foreign Government Debt Securities [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Foreign Government Debt Securities [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Private Placement [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Private Placement [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Taxable Municipal Bonds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Taxable Municipal Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Treasury Inflation-Protected Securities [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Yankee Bonds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Yankee Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Commingled funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Commingled funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Fixed Income Funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Fixed Income Funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Real Estate [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] Real Estate [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] MRO Other investments [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 1 [Member] Foreign Pension Plans, Defined Benefit [Member] MRO Other investments [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Common Stock [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Common Stock [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Preferred Stock [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Private Equity Funds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Private Equity Funds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Real Estate Investment Trusts [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Real Estate Investment Trusts [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Equity Securities, Investment Objective [Domain]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Investment Funds Mutual Funds Equity [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Investment Funds Mutual Funds Equity [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Equity Funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Equity Funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] US Treasury and Government [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] US Treasury and Government [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Exchange Traded Funds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Exchange Traded Funds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Corporate Bond Securities [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Corporate Bond Securities [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Municipal Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Foreign Government Debt Securities [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Foreign Government Debt Securities [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Private Placement [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Private Placement [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Taxable Municipal Bonds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Taxable Municipal Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Treasury Inflation-Protected Securities [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Yankee Bonds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Yankee Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Commingled funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Commingled funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Fixed Income Funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Fixed Income Funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Real Estate [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Real Estate [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] MRO Other investments [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] MRO Other investments [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Common Stock [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Common Stock [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Preferred Stock [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Private Equity Funds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Private Equity Funds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Real Estate Investment Trusts [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Real Estate Investment Trusts [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Equity Securities, Investment Objective [Domain]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Investment Funds Mutual Funds Equity [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Investment Funds Mutual Funds Equity [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Equity Funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Equity Funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] US Treasury and Government [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] US Treasury and Government [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Exchange Traded Funds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Exchange Traded Funds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Corporate Bond Securities [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Corporate Bond Securities [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Municipal Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Foreign Government Debt Securities [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Foreign Government Debt Securities [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Private Placement [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Private Placement [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Taxable Municipal Bonds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Taxable Municipal Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Treasury Inflation-Protected Securities [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Yankee Bonds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Yankee Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Commingled funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Commingled funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Fixed Income Funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Fixed Income Funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Real Estate [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] Real Estate [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] MRO Other investments [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 2 [Member] Foreign Pension Plans, Defined Benefit [Member] MRO Other investments [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Private Equity Funds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Private Equity Funds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Real Estate [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Real Estate [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] MRO Other investments [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] MRO Other investments [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Common Stock [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Common Stock [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Preferred Stock [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Private Equity Funds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Private Equity Funds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Real Estate Investment Trusts [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Real Estate Investment Trusts [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Equity Securities, Investment Objective [Domain]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Investment Funds Mutual Funds Equity [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Investment Funds Mutual Funds Equity [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Equity Funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Equity Funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] US Treasury and Government [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] US Treasury and Government [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Exchange Traded Funds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Exchange Traded Funds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Corporate Bond Securities [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Corporate Bond Securities [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Municipal Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Foreign Government Debt Securities [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Foreign Government Debt Securities [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Private Placement [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Private Placement [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Taxable Municipal Bonds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Taxable Municipal Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Treasury Inflation-Protected Securities [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Yankee Bonds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Yankee Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Commingled funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Commingled funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Fixed Income Funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Fixed Income Funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Real Estate [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] Real Estate [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] MRO Other investments [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] United States Pension Plans of US Entity, Defined Benefit [Member] MRO Other investments [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Cash and Cash Equivalents [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Common Stock [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Common Stock [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Preferred Stock [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Private Equity Funds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Private Equity Funds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Real Estate Investment Trusts [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Real Estate Investment Trusts [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Equity Securities, Investment Objective [Domain]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Investment Funds Mutual Funds Equity [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Investment Funds Mutual Funds Equity [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Equity Funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Equity Funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] US Treasury and Government [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] US Treasury and Government [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Exchange Traded Funds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Exchange Traded Funds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Corporate Bond Securities [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Corporate Bond Securities [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Municipal Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Foreign Government Debt Securities [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Foreign Government Debt Securities [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Private Placement [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Private Placement [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Taxable Municipal Bonds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Taxable Municipal Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Treasury Inflation-Protected Securities [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Yankee Bonds [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Yankee Bonds [Member]	Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Commingled funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Commingled funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Fixed Income Funds [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Fixed Income Funds [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Real Estate [Member]		Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] Real Estate [Member]		Dec. 31, 2013 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] MRO Other investments [Member]	Dec. 31, 2012 Fair Value, Inputs, Level 3 [Member] Foreign Pension Plans, Defined Benefit [Member] MRO Other investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 625,000,000	$ 630,000,000	$ 516,000,000	$ 20,000,000	$ 17,000,000	$ 288,000,000	[1]	$ 312,000,000	[1]	$ 4,000,000	$ 23,000,000	$ 25,000,000	$ 2,000,000	$ 2,000,000	$ 1,000,000	$ 0	[2]	$ 0	[2]	$ 0	[3]	$ 0	[3]	$ 63,000,000	$ 67,000,000	$ 1,000,000	$ 8,000,000	$ 127,000,000	[4]	$ 96,000,000	[4]	$ 1,000,000	$ 7,000,000	$ 5,000,000	$ 21,000,000	$ 18,000,000	$ 13,000,000	$ 14,000,000	$ 1,000,000	$ 3,000,000	$ 2,000,000	$ 17,000,000	[5]	$ 28,000,000	[5]	$ 0	[6]	$ 0	[6]	$ 22,000,000	[7]	$ 23,000,000	[7]	$ 12,000,000	$ 12,000,000	$ 597,000,000	$ 500,000,000	$ 412,000,000	$ 1,000,000	$ 1,000,000	$ 0	[1]	$ 0	[1]	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 219,000,000	[2]	$ 171,000,000	[2]	$ 186,000,000	[3]	$ 152,000,000	[3]	$ 0	$ 0	$ 0	$ 0	$ 0	[4]	$ 0	[4]		$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	[5]	$ 0	[5]	$ 178,000,000	[6]	$ 166,000,000	[6]	$ 0	[7]	$ 0	[7]	$ 13,000,000	$ 10,000,000	$ 0	$ 0	$ 0	$ 378,000,000	$ 405,000,000	$ 19,000,000	$ 16,000,000	$ 288,000,000	[1]	$ 312,000,000	[1]	$ 4,000,000	$ 0	$ 0	$ 2,000,000	$ 2,000,000	$ 0	$ 0	[2]	$ 0	[2]	$ 0	[3]	$ 0	[3]	$ 63,000,000	$ 67,000,000	$ 1,000,000	$ 8,000,000	$ 0	[4]	$ 0	[4]	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 1,000,000	$ 0	$ 0	$ 0	[5]	$ 0	[5]	$ 0	[6]	$ 0	[6]	$ 0	[7]	$ 0	[7]	$ 0	$ 0	$ 220,000,000	$ 172,000,000	$ 1,000,000	$ 1,000,000	$ 0	[1]	$ 0	[1]	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 219,000,000	[2]	$ 171,000,000	[2]	$ 0	[3]	$ 0	[3]	$ 0	$ 0	$ 0	$ 0	$ 0	[4]	$ 0	[4]	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	[5]	$ 0	[5]	$ 0	[6]	$ 0	[6]	$ 0	[7]	$ 0	[7]	$ 0	$ 0	$ 190,000,000	$ 165,000,000	$ 1,000,000	$ 1,000,000	$ 0	[1]	$ 0	[1]	$ 0	$ 0	$ 0	$ 0	$ 0	$ 1,000,000	$ 0	[2]	$ 0	[2]	$ 0	[3]	$ 0	[3]	$ 0	$ 0	$ 0	$ 0	$ 127,000,000	[4]	$ 96,000,000	[4]	$ 1,000,000	$ 7,000,000	$ 5,000,000	$ 21,000,000	$ 18,000,000	$ 13,000,000	$ 14,000,000	$ 0	$ 3,000,000	$ 2,000,000	$ 17,000,000	[5]	$ 28,000,000	[5]	$ 0	[6]	$ 0	[6]	$ 0	[7]	$ 0	[7]	$ 0	$ 0	$ 377,000,000	$ 328,000,000	$ 0	$ 0	$ 0	[1]	$ 0	[1]	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	[2]	$ 0	[2]	$ 186,000,000	[3]	$ 152,000,000	[3]	$ 0	$ 0	$ 0	$ 0	$ 0	[4]	$ 0	[4]	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	[5]	$ 0	[5]	$ 178,000,000	[6]	$ 166,000,000	[6]	$ 0	[7]	$ 0	[7]	$ 13,000,000	$ 10,000,000									$ 57,000,000	$ 60,000,000	$ 0	$ 0	$ 0	[1]	$ 0	[1]	$ 0	$ 23,000,000	$ 25,000,000	$ 0	$ 0	$ 0	$ 0	[2]	$ 0	[2]	$ 0	[3]	$ 0	[3]	$ 0	$ 0	$ 0	$ 0	$ 0	[4]	$ 0	[4]	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	[5]	$ 0	[5]	$ 0	[6]	$ 0	[6]	$ 22,000,000	[7]	$ 23,000,000	[7]	$ 12,000,000	$ 12,000,000	$ 0	$ 0	$ 0	$ 0	$ 0	[1]	$ 0	[1]	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	[2]	$ 0	[2]	$ 0	[3]	$ 0	[3]	$ 0	$ 0	$ 0	$ 0	$ 0	[4]	$ 0	[4]	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	$ 0	[5]	$ 0	[5]	$ 0	[6]	$ 0	[6]	$ 0	[7]	$ 0	[7]	$ 0	$ 0
Change in plan assets:
Beginning balance																																																																																																																																																																																																																																																																																																																																										60,000,000	58,000,000	25,000,000	23,000,000	23,000,000	21,000,000	12,000,000	14,000,000
Actual return on plan assets:
Realized																																																																																																																																																																																																																																																																																																																																										7,000,000	2,000,000	6,000,000	2,000,000	1,000,000	0	0	0
Unrealized																																																																																																																																																																																																																																																																																																																																										0	0	(1,000,000)	1,000,000	1,000,000	1,000,000	0	(2,000,000)
Purchases																																																																																																																																																																																																																																																																																																																																										7,000,000	7,000,000	6,000,000	4,000,000	1,000,000	3,000,000	0	0
Sales																																																																																																																																																																																																																																																																																																																																										(17,000,000)	(7,000,000)	(13,000,000)	(5,000,000)	(4,000,000)	(2,000,000)	0	0
Ending balance																																																																																																																																																																																																																																																																																																																																										$ 57,000,000	$ 60,000,000	$ 23,000,000	$ 25,000,000	$ 22,000,000	$ 23,000,000	$ 12,000,000	$ 12,000,000
Defined Benefit Plan, U.S. and non-U.S. Common Stock in Major Sectors						60.00%										75.00%
Defined Benefit Plan, U.S. and non-U.S. Common Stock in Other Sectors, Percentage						40.00%										25.00%
Defined Benefit Plan, Investments Held in non-U.S. Common Stock in Major Sectors, Percentage																				80.00%
Defined Benefit Plan, Investments Held in non-U.S. Common Stock in Other Sectors, Percentage																				20.00%
Defined Benefit Plan, U.S. and non-U.S. Corporate Bonds in Major Sectors, Percentage																												70.00%														90.00%
Defined Benefit Plan, U.S. and non-U.S. Corporate Bonds in Other Sectors, Percentage																												30.00%														10.00%
Defined Benefit Plan, U.S. and non-U.S. Investments, Government and Corporate Bonds in Major Sectors, Percentage																																														75.00%
Defined Benefit Plan, U.S. and non-U.S. Investments Held in Other Sectors, Percentage																																														25.00%
Defined Benefit Plan, Investments in Property Type and Location, Percentage																																																		70.00%

[1] Includes approximately 60 percent of investments held in U.S. and non-U.S. common stocks in the banking, pharmaceuticals, oil and gas, insurance, telecommunications, electric, aerospace/defense, retail, transportation, food processing, semiconductors, and chemicals sectors. The remaining 40 percent of common stock is held in various other sectors.

[2] Includes approximately 75 percent of investments held in U.S. and non-U.S. common stocks in the consumer staples, financial services, health care, energy, basic materials, leisure, and industrial goods and services sectors and 25 percent of investments held among various other sectors. The funds' objective is to outperform their respective benchmark indexes, FTSE ALL Share 5% Capped Index and MSCI World Index, as defined by the investment policy.

[3] Includes approximately 80 percent of investments held in non-U.S. publicly traded common stocks (specifically Asia Pacific, except Japan, and the U.K.) in the financial, consumer staples, information technology, materials, energy, industrials, and telecommunication services sectors and the remaining 20 percent of investments held among various other sectors. The funds' objective is to outperform their respective benchmark indexes, MSCI AC Asia Pacific ex Japan Index, FTSE Small Cap Index, and MSCI Emerging Markets Index, as defined by the investment policy.

[4] Includes approximately 70 percent of U.S. and non-U.S. corporate bonds in the banking and finance, utilities, oil and gas, news/media, and health care sectors. The remaining 30 percent of corporate bonds are in various other sectors.

[5] Includes approximately 90 percent of investments held in U.S. and non-U.S. corporate bonds in the consumer discretionary, financial, industrial, telecommunication services, energy, health care, information technology and materials sectors and 10 percent of investments held among various other sectors.

[6] Includes approximately 75 percent of investments held in U.S. and non-U.S. publicly traded investment grade government and corporate bonds which include gilts, treasuries, financial, corporates, and collateralized asset backed securities and 25 percent of investments held among various other sectors. The funds' objective is to outperform their respective benchmark indexes, as defined by the investment policy.

[7] Includes investments diversified by property type and location. The largest property sector holdings, which represent approximately 70 percent of investments held, are office, hotel, residential, and retail with the greatest percentage of investments made in the U.S. and Asia, which includes the emerging markets of China and India.

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 264	$ 684
Receivables	2,134	2,418
Inventories	364	361
Other current assets	213	299
Total current assets	2,975	3,762
Equity method investments	1,201	1,279
Property, plant and equipment, less accumulated depreciation, depletion and amortization of $21,895 and $19,266	28,145	28,272
Goodwill	499	525
Other noncurrent assets	2,800	1,468
Total assets	35,620	35,306
Current liabilities:
Commercial paper	135	200
Accounts payable	2,206	2,324
Payroll and benefits payable	240	217
Accrued taxes	1,445	1,983
Other current liabilities	239	173
Long-term debt due within one year	68	184
Total current liabilities	4,333	5,081
Long-term debt	6,394	6,512
Deferred tax liabilities	2,492	2,432
Defined benefit postretirement plan obligations	604	856
Asset retirement obligations	2,009	1,749
Deferred credits and other liabilities	444	393
Total liabilities	16,276	17,023
Commitments and contingencies
Stockholders’ Equity
Preferred stock no shares issued or outstanding (no par value, 26 million shares authorized)	0	0
Common stock issued - 770 million and 770 million shares (par value $1 per share, 1.1 billion shares authorized)	770	770
Common stock, securities exchangeable into common stock - no shares issued or outstanding (no par value, 29 million shares authorized)	0	0
Common stock, held in treasury, at cost – 73 million and 63 million shares	(2,903)	(2,560)
Additional paid-in capital	6,592	6,616
Retained earnings	15,135	13,890
Accumulated other comprehensive loss	(250)	(433)
Total stockholders equity	19,344	18,283
Total liabilities and stockholders equity	$ 35,620	$ 35,306

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Acquisitions

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Business Combination Disclosure [Text Block]

Acquisitions

During 2013, 2012 and 2011, our business combinations related to properties acquired by our North America E&P segment in the Eagle Ford in south Texas. The pro forma impact of these transactions, individually and in the aggregate, is not material to our consolidated statements of income for any periods presented.

The fair values of assets acquired and liabilities assumed in each of these business combinations were measured primarily using an income approach, specifically utilizing a discounted cash flow analysis. The estimated fair values were based on significant inputs not observable in the market, and therefore represent Level 3 measurements. Significant inputs included estimated reserve volumes, the expected future production profile, estimated commodity prices and assumptions regarding future operating and development costs. The discount rates used in the discounted cash flow analyses were approximately 10 percent for the 2013 and 2012 transactions and 11 percent for the 2011 transaction.

2013

In July 2013, we acquired 4,800 net undeveloped acres in the Eagle Ford in a transaction valued at $97 million, including carried interest of $23 million. The transaction was accounted for as a business combination, with the entire up-front cash consideration of $74 million allocated to property, plant and equipment at the acquisition date.

2012 & 2011

We acquired approximately 25,000 net acres in the core of the Eagle Ford during 2012. The largest transactions were the acquisitions of Paloma Partners II, LLC, which closed in the second quarter of 2012 for cash consideration of $768 million, and an acquisition of proved and unproved properties that closed in the third quarter of 2012 for cash consideration of $232 million. These transactions were accounted for as business combinations.

During the fourth quarter of 2011, we closed a series of transactions in the Eagle Ford that were accounted for as a business combination. The most significant of these transactions was the acquisition of Hilcorp Resources, LLC. The total cash consideration paid for all the transactions including approximately 167,000 net acres and a gathering system, was $4.5 billion.

The following table summarizes the amounts allocated to the assets acquired and liabilities assumed based upon their fair values at the acquisition dates:

	Closed in Quarter Ended
	June 30,		September 30,		December 31,
(In millions)	2012		2012		2011
Current assets:
Cash	$	8	$	—	$	—
Receivables	22		8		40
Inventories	1		—		4
Other current assets	—		—		30
Total current assets acquired	31		8		74
Property, plant and equipment	822		248		4,501
Other noncurrent assets	—		—		21
Total assets acquired	853		256		4,596
Current liabilities:
Accounts payable	78		23		101
Other current liabilities	—		—		20
Total current liabilities assumed	78		23		121
Asset retirement obligations	7		1		5
Total liabilities assumed	85		24		126
Net assets acquired	$	768	$	232	$	4,470

In addition, during 2011, our North America E&P segment acquired approximately 108,000 net acres in the Eagle Ford for approximately $265 million. These transactions were accounted for as asset acquisitions.

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Variable Interest Entities

12 Months Ended

Dec. 31, 2013

Variable Interest Entities Disclosure [Abstract]

Variable Interest Entities

Variable Interest Entities

The owners of the AOSP, in which we hold a 20 percent undivided interest, contracted with a wholly owned subsidiary of a publicly traded Canadian limited partnership ("Corridor Pipeline") to provide materials transportation capabilities among the Muskeg River and Jackpine mines, the Scotford upgrader and markets in Edmonton. The contract, originally signed in 1999 by a company we acquired, allows each holder of an undivided interest in the AOSP to ship materials in accordance with its undivided interest. Costs under this contract are accrued and recorded on a monthly basis, with a $3 million current liability recorded at December 31, 2013, consistent with December 31, 2012. Under this agreement, the AOSP absorbs all of the operating and capital costs of the pipeline. Currently, no third-party shippers use the pipeline. Should shipments be suspended, by choice or due to force majeure, we remain responsible for the portion of the payments related to our undivided interest for all remaining periods. The contract expires in 2029; however, the shippers can extend its term perpetually. This contract qualifies as a variable interest contractual arrangement and the Corridor Pipeline qualifies as a variable interest entity ("VIE"). We hold a variable interest but are not the primary beneficiary because our shipments are only 20 percent of the total; therefore the Corridor Pipeline is not consolidated by Marathon Oil. Our maximum exposure to loss as a result of our involvement with this VIE is the amount we expect to pay over the contract term, which was $723 million as of December 31, 2013. The liability on our books related to this contract at any given time will reflect amounts due for the immediately previous month’s activity, which is substantially less than the maximum exposure over the contract term. We have not provided financial assistance to Corridor Pipeline and we do not have any guarantees of such assistance in the future.

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Derivatives

12 Months Ended

Dec. 31, 2013

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivatives

Derivatives

For further information regarding the fair value measurement of derivative instruments see Note 15. See Note 1 for discussion of the types of derivatives we use and the reasons for them. All of our interest rate and commodity derivatives are subject to enforceable master netting arrangements or similar agreements under which we may report net amounts. Netting is assessed by counterparty, and as of December 31, 2013 and 2012, there were no offsetting amounts. Positions by contract were all either assets or liabilities. The following tables present the gross fair values of derivative instruments, excluding cash collateral, and the reported net amounts along with where they appear on the consolidated balance sheets as of December 31, 2013 and 2012.

	December 31, 2013
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	8	$	—	$	8	Other noncurrent assets
Foreign currency	2		—		2		Other current assets
Total Designated Hedges	$	10	$	—	$	10

	December 31, 2013
(In millions)	Asset		Liability		Net Liability		Balance Sheet Location
Fair Value Hedges
Foreign currency	$	—	$	4	$	4	Other current liabilities
Total Designated Hedges	$	—	$	4	$	4

	December 31, 2012
(In millions)	Asset		Liability		Net Asset		Balance Sheet Location
Fair Value Hedges
Interest rate	$	21	$	—	$	21	Other noncurrent assets
Foreign currency	18		—		18		Other current assets
Total Designated Hedges	39		—		39
Not Designated as Hedges
Commodity	52		—		52		Other current assets
Total Not Designated as Hedges	52		—		52
Total	$	91	$	—	$	91

Derivatives Designated as Fair Value Hedges

The following table presents by maturity date, information about our interest rate swap agreements as of December 31, 2013, including the weighted average, London Interbank Offer Rate (“LIBOR”)-based, floating rate.

Maturity Dates	Aggregate Notional Amount (in millions)		Weighted Average, LIBOR-Based, Floating Rate
October 1, 2017	$	600	4.65	%
March 15, 2018	$	300	4.50	%

As of December 31, 2012, we had multiple interest rate swap agreements with a total notional amount of $600 million, a weighted average, LIBOR-based, floating rate of 4.70 percent and a maturity date of October 1, 2017.

In connection with debt retirements in February and March 2011, we settled interest rate swaps with a notional amount of $1,450 million. We recorded a $29 million gain, which reduced the loss on early extinguishment of debt.

As of December 31, 2013 and 2012, our foreign currency forwards had an aggregate notional amount of 2,387 million and 3,043 million Norwegian Kroner at weighted average forward rates of 6.060 and 5.780. These forwards hedge our current Norwegian tax liability and those outstanding at December 31, 2013 have settlement dates through June 2014.

The pretax effect of derivative instruments designated as hedges of fair value in our consolidated statements of income are summarized in the table below. There is no ineffectiveness related to the fair value hedges.

		Gain (Loss)
(In millions)	Income Statement Location	2013			2012			2011
Derivative
Interest rate	Net interest and other	$	(13	)	$	16		$	28
Interest rate	Loss on early extinguishment of debt	—			—			29
Foreign currency	Provision for income taxes	(44		)	(1		)	—
Hedged Item
Long-term debt	Net interest and other	$	13		$	(16	)	$	(28	)
Long-term debt	Loss on early extinguishment of debt	—			—			(29		)
Accrued taxes	Provision for income taxes	44			1			—

Derivatives Not Designated as Hedges

In August 2012, we entered into crude oil derivative instruments related to a portion of our forecasted North America E&P crude oil sales. These commodity derivatives were not designated as hedges and had terms that ended in December 2013.

The impact of all commodity derivative instruments not designated as hedges appears in sales and other operating revenues in our consolidated statements of income and were a net loss of $67 million in 2013 and net gains of $70 million and $5 million in 2012 and 2011.

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Equity Method Investments and Related Party Transactions (Notes)

12 Months Ended

Dec. 31, 2013

Equity Method Investments Disclosure [Abstract]

Equity Method Investments and Related Party Transactions

Equity Method Investments and Related Party Transactions

During 2013, 2012 and 2011 only our equity method investees were considered related parties and they included:

•Alba Plant LLC, in which we have a 52 percent noncontrolling interest. Alba Plant LLC processes LPG.

• AMPCO, in which we have a 45 percent interest. AMPCO is engaged in methanol production activity.

• EGHoldings, in which we have a 60 percent noncontrolling interest. EGHoldings is engaged in LNG production activity.

Our equity method investments are summarized in the following table:

	Ownership as of	December 31,
(In millions)	December 31, 2013	2013		2012
EGHoldings	60%	$	748	$	817
Alba Plant LLC	52%	263		264
AMPCO	45%	189		187
Other investments		1		11
Total		$	1,201	$	1,279

Dividends and partnership distributions received from equity method investees (excluding distributions that represented a return of capital previously contributed) were $435 million in 2013, $381 million in 2012 and $509 million in 2011.

Summarized financial information for equity method investees is as follows:

(In millions)	2013		2012		2011
Income data – year:
Revenues and other income	$	1,444	$	1,330	$	1,544
Income from operations	849		755		942
Net income	727		635		820
Balance sheet data – December 31:
Current assets	$	644	$	607
Noncurrent assets	1,590		1,743
Current liabilities	384		395
Noncurrent liabilities	33		29

Revenues from related parties were $55 million, $58 million and $60 million in 2013, 2012 and 2011, with the majority related to EGHoldings in all years. Purchases from related parties were $242 million, $248 million and $250 million in 2013, 2012 and 2011 with the majority related to Alba Plant LLC in all years.

Current receivables from related parties at December 31, 2013 and 2012, approximately split evenly between EGHoldings and AMPCO, were $30 million and $27 million. Payables to related parties were $20 million at December 31, 2013 and 2012, with the majority related to Alba Plant LLC.

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Asset Retirement Obligations (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset Retirement Obligation Beginning Balance	$ 1,783	[1]	$ 1,510
Incurred, including acquisitions	84		150
Settled, including dispositions	(78)		(35)
Accretion expense (included in depreciation, depletion and amortization)	106		91
Revisions to previous estimates	244		150
Held for sale	(43)		(83)
Asset Retirement Obligation Ending Balance	2,096	[1]	1,783	[1]
Asset Retirement Obligation, Current	$ 87		$ 34

[1] Includes asset retirement obligations of $87 million and $34 million classified as short-term at December 31, 2013 and 2012.

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Segment Information

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Segment Information

Segment Information

 Beginning in 2013, we changed our reportable segments and revised our management reporting to better reflect the growing importance of United States unconventional resource plays to our business. All periods presented have been recast to reflect these new segments.

We have three reportable operating segments.  Each of these segments is organized and managed based upon both geographic location and the nature of the products and services it offers:

• North America E&P ("N.A. E&P") – explores for, produces and markets liquid hydrocarbons and natural gas in North America;

• International E&P ("Int'l E&P") – explores for, produces and markets liquid hydrocarbons and natural gas outside of North America and produces and markets products manufactured from natural gas, such as LNG and methanol, in E.G.; and

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

Information regarding assets by segment is not presented because it is not reviewed by the chief operating decision maker (“CODM”).  Segment income represents income from continuing operations excluding certain items not allocated to segments, net of income taxes, attributable to the operating segments. Our corporate and operations support general and administrative costs are not allocated to the operating segments. These costs primarily consist of employment costs (including pension effects), professional services, facilities and other costs associated with corporate and operations support activities, net of associated income tax effects. Unrealized gains or losses on crude oil derivative instruments, certain impairments, gains or losses on dispositions or other items that affect comparability (as determined by the CODM) also are not allocated to operating segments.

In 2013, we entered into agreements to sell our Angola assets; therefore, the Angola operations are reflected as discontinued operations and excluded from the International E&P segment in all periods presented.

As discussed in Note 3, our downstream business was spun-off on June 30, 2011 and has been reported as discontinued operations for 2011.  Sales to MPC previously reported as intersegment revenues are reported as sales and other operating revenues because such sales were expected to continue subsequent to the spin-off.  These sales were $1.4 billion in the first six months of 2011.

2013							Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	5,068	$	5,827	$	1,576	$	(52	)	(c)	$	12,419
Marketing revenues	1,797		267		18		—				2,082
Total revenues	6,865		6,094		1,594		(52		)		14,501
Income from equity method investments	—		427		—		(4		)	(d)	423
Net gain (loss) on disposal of assets and other income	12		50		5		(32		)		35
Production expenses	797		534		1,000		—				2,331
Marketing costs	1,796		258		18		—				2,072
Exploration expenses	725		263		—		—				988
Depreciation, depletion and amortization	1,927		621		218		24				2,790
Impairments	41		—		—		55				96
Other expenses (a)	420		239		66		401				1,126
Taxes other than income	318		7		22		5				352
Net interest and other	—		—		—		274				274
Provision (benefit) for income taxes	324		3,226		69		(282		)		3,337
Segment income/Income from continuing operations	$	529	$	1,423	$	206	$	(565	)		$	1,593
Capital expenditures (b)	$	3,649	$	764	$	286	$	285			$	4,984

^(a)  Includes other operating expenses and general and administrative expenses.

^(b)  Includes accruals.

^(c)  Unrealized gain (loss) on crude oil derivative instruments.

^(d)  EGHoldings impairment (see Note 15).

2012							Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	3,944	$	7,445	$	1,521	$	53		(c)	$	12,963
Marketing revenues	2,451		248		30		—				2,729
Total revenues	6,395		7,693		1,551		53				15,692
Income from equity method investments	2		368		—		—				370
Net gain (loss) on disposal of assets and other income	11		30		4		114				159
Production expenses	706		500		996		—				2,202
Marketing costs	2,444		269		31		—				2,744
Exploration expenses	588		118		—		—				706
Depreciation, depletion and amortization	1,428		787		217		45				2,477
Impairments	11		—		—		360				371
Other expenses (a)	400		200		60		464				1,124
Taxes other than income	226		5		22		(5		)		248
Net interest and other	—		—		—		219				219
Provision (benefit) for income taxes	223		4,552		58		(316		)		4,517
Segment income/Income from continuing operations	$	382	$	1,660	$	171	$	(600	)		$	1,613
Capital expenditures (b)	$	3,988	$	489	$	188	$	466			$	5,131

2011								Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM			to Segments			Total
Sales and other operating revenues	$	3,364	$	5,851	$	1,535		$	—		$	10,750
Marketing revenues	3,614		252		53			—			3,919
Total revenues	6,978		6,103		1,588			—			14,669
Income from equity method investments	20		442		—			—			462
Net gain (loss) on disposal of assets and other income	21		73		(17		)	74			151
Production expenses	545		409		915			82			1,951
Marketing costs	3,598		247		53			—			3,898
Exploration expenses	388		253		—			—			641
Depreciation, depletion and amortization	1,191		828		196			48			2,263
Impairments	12		—		—			298			310
Other expenses (a)	494		191		46			465			1,196
Taxes other than income	182		6		17			(12		)	193
Net interest and loss on early extinguishment of debt	—		—		—			386			386
Provision (benefit) for income taxes	217		2,693		83			(267		)	2,726
Segment income/Income from continuing operations	$	392	$	1,991	$	261		$	(926	)	$	1,718
Capital expenditures (b)	$	2,163	$	544	$	308		$	384		$	3,399

Revenues from external customers are attributed to geographic areas based upon selling location. The following summarizes revenues from external customers by geographic area.

(In millions)	2013		2012		2011
United States	$	6,813	$	6,448	$	6,978
Norway	3,183		3,714		3,563
Canada	1,594		1,551		1,588
Libya(a)	1,106		1,989		216
Other international	1,805		1,990		2,324
Total revenues	$	14,501	$	15,692	$	14,669

^(a)  See Note 13 for discussion of Libya operations.

In 2013, sales to British Petroleum and its affiliates accounted for approximately 11 percent of our total revenues. In 2012, Statoil, the purchaser of the majority of our Libyan crude oil, accounted for approximately 15 percent of our total revenues, while sales to Shell Oil and its affiliates accounted for approximately 12 percent of total revenues. In 2011, our sales to MPC accounted for approximately 18 percent of total revenues.

Revenues by product line were:

(In millions)	2013		2012		2011
Liquid hydrocarbons	$	11,932	$	12,983	$	11,778
Natural gas	937		1,052		1,203
Synthetic crude oil	1,542		1,409		1,442
Other	90		248		246
Total revenues	$	14,501	$	15,692	$	14,669

The following summarizes certain long-lived assets by geographic area, including property, plant and equipment and equity method investments.

	December 31,
(In millions)	2013		2012
United States	$	14,635	$	13,677
Canada	9,794		9,693
Norway	977		987
Equatorial Guinea	1,977		2,081
Other international	1,963		3,113
Total long-lived assets	$	29,346	$	29,551

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Income per Common Share (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Earnings Per Share [Abstract]
Income from continuing operations	$ 1,593	$ 1,613	$ 1,718
Discontinued operations	160	(31)	1,228
Net income	$ 1,753	$ 1,582	$ 2,946
Basic	705	706	710
Effect of dilutive securities	4	4	4
Diluted	709	710	714
Basic:
Income from continuing operations (in dollars per share)	$ 2.26	$ 2.28	$ 2.42
Discontinued operations	$ 0.23	$ (0.04)	$ 1.73
Net income (in dollars per share)	$ 2.49	$ 2.24	$ 4.15
Diluted:
Income from continuing operations (in dollars per share)	$ 2.24	$ 2.27	$ 2.41
Discontinued operations (in dollars per share)	$ 0.23	$ (0.04)	$ 1.72
Net income (in dollars per share)	$ 2.47	$ 2.23	$ 4.13
Antidilutive securities excluded from computation of earnings per share	5	10	7

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Dispositions

12 Months Ended

Dec. 31, 2013

Discontinued Operations and Disposal Groups [Abstract]

Dispositions

Dispositions

2013 - North America E&P

In June 2013, we closed the sale of our interests in the DJ Basin for proceeds of $19 million. A pretax loss of $114 million was recorded in the second quarter of 2013.

In February 2013, we conveyed our interests in the Marcellus natural gas shale play to the operator. A $43 million pretax loss on this transaction was recorded in the first quarter of 2013.

In February 2013, we closed the sale of our interest in the Neptune gas plant, located onshore Louisiana, for proceeds of $166 million. A $98 million pretax gain was recorded in the first quarter of 2013.

In January 2013, we closed the sale of our remaining assets in Alaska, for proceeds of $195 million, subject to a six-month escrow of $50 million which was collected in July 2013. After closing adjustments were made in the second quarter of 2013, the pretax gain on this sale was $55 million.

Assets held for sale in the December 31, 2012 consolidated balance sheet were related to the Neptune gas plant and Alaska dispositions that were pending at that date and included:

(In millions)	December 31, 2012
Other current assets	$	50
Other noncurrent assets	248
Total assets	$	298
Deferred credits and other liabilities	$	83
Total liabilities	$	83

2013 - International E&P

In the fourth quarter of 2013, we transfered our 45 percent working interest and operatorship in the Safen block in the Kurdistan Region of Iraq at a pretax loss of $17 million.

In June and December 2013, we entered into agreements, valued in total at $2.1 billion before closing adjustments, to sell our non-operated 10 percent working interests in the Production Sharing Contracts and Joint Operating Agreements for Angola Blocks 31 and 32. The sale of our interest in Block 31 closed in February 2014 and the sale of our interest in Block 32 is expected to close in the first quarter of 2014. Block 31 is presented as held for sale and Block 32 is reflected as unproved property in property, plant and equipment in the December 31, 2013 consolidated balance sheet (See Note 13 for discussion of the capitalized costs related to suspended wells). Our entire Angola operations are reflected as discontinued operations in the consolidated statements of income and the consolidated statements of cash flows for all periods presented.

Assets held for sale in the December 31, 2013 consolidated balance sheet were related to the Angola Block 31 disposition that was pending at that date and included:

(In millions)	December 31, 2013
Other current assets	$	41
Other noncurrent assets	1,647
Total assets	$	1,688
Other current liabilities	$	25
Deferred credits and other liabilities	43
Total liabilities	$	68

Related amounts reported in discontinued operations for 2013, 2012 and 2011 were as follows:

(In millions)	2013		2012			2011
Revenues applicable to discontinued operations	$	361	$	—		$	—
Pretax income (loss) from discontinued operations	$	247	$	(17	)	$	(17	)

2012 - North America E&P

In the third quarter of 2012, we sold approximately 5,800 net undeveloped acres in the Eagle Ford for proceeds of $9 million. A pretax loss of $18 million was recorded.

In January 2012, we closed on the sale of our interests in several Gulf of Mexico crude oil pipeline systems for proceeds of $206 million. This included our equity method interests in Poseidon Oil Pipeline Company, L.L.C. and Odyssey Pipeline L.L.C., as well as certain other oil pipeline interests, including the Eugene Island pipeline system. A pretax gain of $166 million was recorded.

2012 - International E&P

In May 2012, we executed agreements to relinquish our operatorship of and participating interests in the Bone Bay and Kumawa exploration licenses in Indonesia. As a result, we reported a $36 million pretax loss on disposal of assets. Government ratification of the agreements released us from our obligations and further commitments related to these licenses.

2011 - North America E&P

In December 2011, we sold our 50 percent interest in the Burns Point gas plant, a cryogenic processing plant located in St. Mary Parish, Louisiana, for total consideration of $36 million and a pretax gain of $34 million.

In September 2011, we sold our equity interest in an LNG processing facility in Alaska and a pretax gain on the transaction of $8 million was recorded.

In April 2011, we assigned a 30 percent undivided working interest in approximately 180,000 acres in the Niobrara shale play located within the DJ Basin of southeast Wyoming and northern Colorado for total consideration of $270 million, recording a pretax gain of $37 million. See the discussion of our 2013 disposal of the remaining interest above.

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Income per Common Share

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Income per Common Share

Income per Common Share

Basic income per share is based on the weighted average number of common shares outstanding. Diluted income per share assumes exercise of stock options and stock appreciation rights, provided the effect is not antidilutive.

	2013				2012						2011
(In millions, except per share data)	Basic		Diluted		Basic			Diluted			Basic		Diluted
Income from continuing operations	$	1,593	$	1,593	$	1,613		$	1,613		$	1,718	$	1,718
Discontinued operations	160		160		(31		)	(31		)	1,228		1,228
Net income	$	1,753	$	1,753	$	1,582		$	1,582		$	2,946	$	2,946
Weighted average common shares outstanding	705		705		706			706			710		710
Effect of dilutive securities	—		4		—			4			—		4
Weighted average common shares, including dilutive effect	705		709		706			710			710		714
Per share:
Income from continuing operations	$	2.26	$	2.24	$	2.28		$	2.27		$	2.42	$	2.41
Discontinued operations	$	0.23	$	0.23	$	(0.04	)	$	(0.04	)	$	1.73	$	1.72
Net income	$	2.49	$	2.47	$	2.24		$	2.23		$	4.15	$	4.13

The per share calculations above exclude 5 million, 10 million and 7 million stock options in 2013, 2012 and 2011 that were antidilutive.

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Other Items

12 Months Ended

Dec. 31, 2013

Other Items [Abstract]

Other Items

Other Items

Net interest and other

(In millions)	2013			2012			2011
Interest:
Interest income	$	6		$	13		$	12
Interest expense(a)	(307		)	(244		)	(228		)
Income on interest rate swaps	9			7			10
Interest capitalized	21			12			103
Total interest	(271		)	(212		)	(103		)
Other:
Net foreign currency gains	16			4			24
Write off of contingent proceeds	(4		)	—			(7		)
Other	(15		)	(11		)	(21		)
Total other	(3		)	(7		)	(4		)
Net interest and other	$	(274	)	$	(219	)	$	(107	)

^(a)  Excludes $1 million and $10 million paid by United States Steel in2012 and 2011 on assumed debt.

Foreign currency transactions – Aggregate foreign currency gains (losses) were included in the consolidated statements of income as follows:

(In millions)	2013		2012			2011
Net interest and other	$	16	$	4		$	24
Provision for income taxes	105		(80		)	57
Aggregate foreign currency gains (losses)	$	121	$	(76	)	$	81

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Segment Information (Details 4) (USD $) In Billions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2011 Sales [Member] MPC [Member]	Dec. 31, 2012 Sales [Member] Shell Oil [Member]	Dec. 31, 2012 Sales [Member] Statoil [Member]	Dec. 31, 2013 Sales [Member] British Petroleum [Member]
Segment Reporting [Abstract]
Crude oil intersegment sales reclass	$ 1.4
Entity-Wide Revenue, Major Customer, Percent [Line Items]
Entity-Wide Revenue, Major Customer, Percentage		18.00%	12.00%	15.00%	11.00%

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Supplemental Cash Flow Information (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating activities:
Interest paid (net of amounts capitalized)	$ 307	$ 225	$ 268
Income taxes paid to taxing authorities	3,904	4,974	2,893
Commercial paper:
Issuances	10,870	13,880	421
Repayments	(10,935)	(13,680)	(421)
Net commercial paper	(65)	200	0
Noncash investing and financing activities:
Asset retirement costs capitalized, excluding acquisitions	319	257	148
Change in capital expenditure accrual	(9)	187	104
Liabilities Assumed	0	109	126
Asset Retirement Obligation, Liabilities Transferred	92	8	5
Debt payments made by United States Steel	$ 0	$ 20	$ 214

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Income Taxes (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	12 Months Ended
	Jun. 30, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Federal
Current		$ 63	$ (80)	$ (193)
Deferred		(46)	(30)	(217)
Total		17	(110)	(410)
State and local
Current		44	(23)	24
Deferred		1	47	82
Total		45	24	106
Foreign
Current		3,290	4,844	3,088
Deferred		(15)	(241)	(58)
Total		3,275	4,603	3,030
Current Income Tax Expense (Benefit)		3,397	4,741	2,919
Deferred Income Tax Expense (Benefit)		(60)	(224)	(193)
Income Tax Expense (Benefit)		3,337	4,517	2,726
Effective Tax Rate Reconciliation [Abstract]
Statutory rate applied to income from continuing operations before income taxes		35.00%	35.00%	35.00%
Effects of foreign operations, including foreign tax credits		14.00%	18.00%	6.00%
Change in permanent reinvestment assertion		0.00%	0.00%	5.00%
Adjustments to valuation allowances		18.00%	21.00%	14.00%
Tax law changes		0.00%	0.00%	1.00%
Other		1.00%	0.00%	0.00%
Effective income tax rate on continuing operations		68.00%	74.00%	61.00%
Tax Adjustments, Settlements, and Unusual Provisions	716
Foreign Undistributed Earnings	2,046
United States Tax Credit On Foreign Tax	488
Valuation Allowance Deferred Tax Asset Change In Amount Foreign	(228)
United Kingdom Supplemental Oil And Gas Tax Rate Previous				20.00%
United Kingdom Supplemental Oil And Gas Tax Rate Effective March 2011				32.00%
Other Foreign Tax Expense Benefit				10
Other State Tax Expense Benefit	32
Deferred tax assets:
Employee benefits		387	510
Operating loss carryforwards		284	368
Foreign tax credits		5,730	4,351
Other		98	121
Valuation allowances:
Federal		(2,997)	(2,067)
State, net of federal benefit		(67)	(60)
Foreign		(149)	(210)
Total deferred tax assets		3,286	3,013
Deferred tax liabilities:
Property, plant and equipment		4,018	3,691
Investments in subsidiaries and affiliates		794	840
Other		67	12
Total deferred tax liabilities		4,879	4,543
Deferred Tax Liabilities, Net		$ 1,593	$ 1,530

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Segment Information (Details 3) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenue from External Customer [Line Items]
Revenue, Net	$ 14,501	$ 15,692	$ 14,669
Liquid hydrocarbons [Member]
Revenue from External Customer [Line Items]
Revenue, Net	11,932	12,983	11,778
Natural gas [Member]
Revenue from External Customer [Line Items]
Revenue, Net	937	1,052	1,203
Synthetic crude oil [Member]
Revenue from External Customer [Line Items]
Revenue, Net	1,542	1,409	1,442
Miscellaneous other [Member]
Revenue from External Customer [Line Items]
Revenue, Net	$ 90	$ 248	$ 246

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Incentive Based Compensation Plans (Details 1) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	50,000,000
Share Based Compensation Arrangement By Share Based Payment Award Maximum Award For Options Or Stock Appreciation Rights	2.41
Share-based Compensation Arrangement by Share-based Payment Award, Compensation Cost	$ 75	$ 70	$ 65
Employee Service Share-based Compensation, Tax Benefit from Compensation Expense	27	25	23
Proceeds from Stock Options Exercised	58	41	77
Employee Service Share-based Compensation, Tax Benefit Realized from Exercise of Stock Options	$ 36	$ 24	$ 32
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 33.69
Weighted average exercise price per share	$ 33.54	$ 33.52	$ 32.30
Expected annual dividend yield	2.10%	2.20%	2.10%
Expected life in years	6 years 1 month	5 years 6 months	5 years 4 months
Expected volatility	38.00%	41.00%	40.00%
Risk-free interest rate	2.00%	1.00%	0.00%
End of year weighted average grant date fair value of options	$ 10.25	$ 10.86	$ 10.44
Stock Option [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share Based Payment Award, Award Contractual Period	3 years
Stock Option [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share Based Payment Award, Award Contractual Period	10 years
Stock Appreciation Rights (SARs) [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share Based Payment Award, Award Contractual Period	3 years
Stock Appreciation Rights (SARs) [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share Based Payment Award, Award Contractual Period	10 years
Restricted Stock [Member] | Granted Officer [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Restricted Stock [Member] | Non Officer [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share Based Payment Award, Award Annual Vesting Percentage	33.33%
Restricted Stock [Member] | Non Officer [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Common Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years

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Spin-Off (Tables)

12 Months Ended

Dec. 31, 2013

Spin Off Disclosure [Abstract]

Spin Off Discontinued Operations Disclosure

The results of operations of our downstream business have been reported as discontinued operations for 2011. The table below shows selected financial information reported in discontinued operations related to the spin-off.

(In millions)	2011
Revenues applicable to discontinued operations	$	38,602
Pretax income from discontinued operations	$	2,012

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Incentive Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2013

Incentive Based Compensation Plans [Abstract]

Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Weighted Average Grant Date Fair Value

During 2013, 2012 and 2011, we granted stock option awards to both officer and non-officer employees. The weighted average grant date fair value of these awards was based on the following weighted average Black-Scholes assumptions:

	2013		2012		2011
Exercise price per share	$33.54		$33.52		$32.30
Expected annual dividend yield	2.1	%	2.2	%	2.1	%
Expected life in years	6.1		5.5		5.3
Expected volatility	38	%	41	%	40	%
Risk-free interest rate	1.6	%	1.2	%	1.7	%
Weighted average grant date fair value of stock option awards granted	$10.25		$10.86		$10.44

Schedule of Share-based Compensation, Stock Options, Activity

The following is a summary of stock option award activity in 2013.

	Number of Shares	Weighted Average Exercise price
Outstanding at beginning of year	19,536,965	$26.19
Granted	2,051,386	$33.54
Exercised	(2,718,639)	$22.36
Canceled	(764,825)	$34.02
Outstanding at end of year	18,104,887	$27.27

Schedule of Share-based Compensation, Shares Authorized under Stock Option Plans, by Exercise Price Range

The following table presents information related to stock option awards at December 31, 2013.

	Outstanding			Exercisable
Range of Exercise Prices	Number of Shares Under Option	Weighted Average Remaining Contractual Life	Weighted Average Exercise Price	Number of Shares Under Option	Weighted Average Exercise Price
$7.99-12.75	259,164	0.3 years	$10.53	259,164	$10.53
$12.76-16.81	1,937,181	3 years	$15.13	1,937,181	$15.13
$16.82-23.20	4,255,365	5 years	$18.57	4,255,365	$18.57
$23.21-29.24	1,740,398	4 years	$24.59	1,489,683	$24.05
$29.25-36.03	7,541,433	7 years	$33.06	3,967,422	$32.70
$36.04-46.41	2,371,346	3 years	$38.19	2,277,817	$38.26
Total	18,104,887	5 years	$27.27	14,186,632	$25.64

Schedule of Nonvested Restricted Stock Units Activity

The following is a summary of restricted stock award activity in 2013.

	Awards		Weighted Average Grant Date Fair Value
Unvested at beginning of year	4,177,884		$29.02
Granted	2,120,839		$33.69
Vested	(1,713,763	)	$27.78
Forfeited	(553,072	)	$30.58
Unvested at end of year	4,031,888		$31.80

Schedule of Performance Units, Valuation [Table Text Block]

The key assumptions used in the Monte Carlo simulation to determine the December 31, 2013 fair value of stock-based performance units were:

Valuation date stock price	$35.30
Expected annual dividend yield	2.1	%
Expected volatility	26	%
2-Year risk-free interest rate	0.4	%
Fair value of stock-based performance units outstanding	$34.08

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Goodwill (Notes)

12 Months Ended

Dec. 31, 2013

Goodwill Disclosure [Abstract]

Goodwill

Goodwill

Goodwill is tested for impairment on an annual basis, or when events or changes in circumstances indicate the fair value of a reporting unit with goodwill has been reduced below its carrying value. We performed our annual impairment tests during 2013, 2012 and 2011 and no impairment was required. The fair value of each of our reporting units with goodwill exceeded the book value appreciably.

The changes in the carrying amount of goodwill for 2012 were as follows for the Exploration and Production ("E&P") and OSM segments in place for that year:

(In millions)	E&P			OSM			Total
2012
Beginning balance, gross	$	536		$	1,412		$	1,948
Less: accumulated impairments	—			(1,412		)	(1,412		)
Beginning balance, net	536			—			536
Dispositions	(11		)	—			(11		)
Ending balance, net	$	525		$	—		$	525

As discussed in Note 8, beginning in 2013, we changed our reportable segments. Goodwill related to the previously reported E&P segment was allocated between the North America E&P and International E&P segments as of January 1, 2013 based on the relative fair values of those reporting units. The fair values of the reporting units were measured using an income approach based upon internal estimates of future production levels, commodity prices and discount rates, all of which are Level 3 inputs.  Inputs to the fair value measurements included reserve and production estimates made by our reservoir engineers, estimated commodity prices adjusted for quality and location differentials, and forecasted operating expenses. The table below displays the allocated beginning goodwill balances by segment along with changes in the carrying amount of goodwill for 2013:

(In millions)	N.A. E&P			Int'l E&P			OSM			Total
2013
Beginning balance, gross	$	343		$	182		$	1,412		$	1,937
Less: accumulated impairments	—			—			(1,412		)	(1,412		)
Beginning balance, net	343			182			—			525
Dispositions	4		(a)	(30		)	—			(26		)
Ending balance, net	$	347		$	152		$	—		$	499

^(a) Goodwill related to our Alaska disposition was less than the estimate classified as held for sale in 2012.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2013

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

Supplemental Cash Flow Information

(In millions)	2013			2012			2011
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	307		$	225		$	268
Income taxes paid to taxing authorities	3,904			4,974			2,893
Commercial paper:
Issuances	$	10,870		$	13,880		$	421
Repayments	(10,935		)	(13,680		)	(421		)
Net commercial paper	$	(65	)	$	200		$	—
Noncash investing and financing activities, related to continuing operations:
Additions to property, plant and equipment:
Asset retirement costs capitalized, excluding acquisitions	$	319		$	257		$	148
Change in capital expenditure accrual	(9		)	187			104
Liabilities assumed in acquisitions	—			109			126
Asset retirement obligations assumed by buyer	92			8			5
Debt payments made by United States Steel	—			20			214

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Incentive Based Compensation Plans (Details 4-Restricted) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Awards
Beginning year unvested restricted stock	4,177,884
Granted restricted stock	2,120,839
Vested restricted stock	(1,713,763)
Forfeited restricted stock	(553,072)
End of year unvested restricted stock	4,031,888	4,177,884
Weighted Average Grant Date Fair Value
Beginning year weighted average grant date fair value unvested restricted stock	$ 29.02	$ 25.88
Granted restricted stock weighted average grant date fair value restricted stock	$ 33.69
Vested restricted stock weighted average grant date fair value restricted stock	$ 27.78
Forfeited restricted stock weighted average grant date fair value restricted stock	$ 30.58
End of year weighted average grant date fair value unvested restricted stock	$ 31.80	$ 29.02	$ 25.88
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value	$ 59	$ 36	$ 30
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Nonvested Intrinsic Value Amount	$ 96
Share based compensation arrangement by share based payment award equity instruments other than options nonvested weighted average contractual life	2 years

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2013

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

(In millions)	2013			2012			2011
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	307		$	225		$	268
Income taxes paid to taxing authorities	3,904			4,974			2,893
Commercial paper:
Issuances	$	10,870		$	13,880		$	421
Repayments	(10,935		)	(13,680		)	(421		)
Net commercial paper	$	(65	)	$	200		$	—
Noncash investing and financing activities, related to continuing operations:
Additions to property, plant and equipment:
Asset retirement costs capitalized, excluding acquisitions	$	319		$	257		$	148
Change in capital expenditure accrual	(9		)	187			104
Liabilities assumed in acquisitions	—			109			126
Asset retirement obligations assumed by buyer	92			8			5
Debt payments made by United States Steel	—			20			214

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Inventories (Tables)

12 Months Ended

Dec. 31, 2013

Inventory Disclosure [Abstract]

Schedule of Inventory, Current

	December 31,
(In millions)	2013		2012
Liquid hydrocarbons, natural gas and bitumen	$	55	$	73
Supplies and other items	309		288
Inventories at cost	$	364	$	361

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Consolidated Balance Sheets Parentheticals (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Consolidated Balance Sheets Parenthetical [Abstract]
Less accumulated depreciation, depletion and amortization	$ (21,895)	$ (19,266)
Preferred stock, no par value	$ 0	$ 0
Preferred stock, shares authorized	26,000,000	26,000,000
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Common stock, par value per share	$ 1	$ 1
Common stock, shares authorized	1,100,000,000	1,100,000,000
Common stock, shares issued	770,000,000	770,000,000
Common stock, securities exchangeable no par value	$ 0	$ 0
Common stock, securities exchangeable shares authorized	29,000,000	29,000,000
Common stock, securities exchangeable shares issued	0	0
Common stock, securities exchangeable shares outstanding	0	0
Held in treasury, shares	73,000,000	63,000,000

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Defined Benefit Postretirement Plans and Defined Contribution Plan (Details 3)	12 Months Ended										0 Months Ended
	Dec. 31, 2013 United States Pension Plans of US Entity, Defined Benefit [Member]		Dec. 31, 2012 United States Pension Plans of US Entity, Defined Benefit [Member]	Dec. 31, 2011 United States Pension Plans of US Entity, Defined Benefit [Member]	Dec. 31, 2013 Foreign Pension Plans, Defined Benefit [Member]	Dec. 31, 2012 Foreign Pension Plans, Defined Benefit [Member]	Dec. 31, 2011 Foreign Pension Plans, Defined Benefit [Member]	Dec. 31, 2013 Other Postretirement Benefit Plans, Defined Benefit [Member]	Dec. 31, 2012 Other Postretirement Benefit Plans, Defined Benefit [Member]	Dec. 31, 2011 Other Postretirement Benefit Plans, Defined Benefit [Member]	Jan. 02, 2014 Subsequent Event [Member] United States Pension Plans of US Entity, Defined Benefit [Member]
Weighted average assumptions used to determine benefit obligation:
Discount rate	4.28%		3.44%	4.45%	4.60%	4.40%	4.70%	4.85%	4.06%	4.90%
Rate of compensation increase	5.00%		5.00%	5.00%	4.90%	4.50%	4.30%	5.00%	5.00%	5.00%
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate	3.79%		4.21%	5.05%	4.40%	4.70%	5.40%	4.06%	4.90%	5.55%
Expected long-term return on plan assets	7.25%	[1]	7.75%	8.50%	4.90%	5.20%	5.86%	0.00%	0.00%	0.00%	6.75%
Rate of compensation increase	5.00%		5.00%	5.00%	4.50%	4.30%	5.10%	5.00%	5.00%	5.00%

[1] Effective January 1, 2014, the expected long-term return on U.S. plan assets was changed from 7.25 percent to 6.75 percent.

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Spin-Off

12 Months Ended

Dec. 31, 2013

Spin Off Disclosure [Abstract]

Spin-off of Downstream Business

Spin-off of 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. On June 30, 2011, stockholders of record as of 5:00 p.m. Eastern Daylight Savings time on June 27, 2011 (the "Record Date") received one common share of MPC stock for every two common shares of Marathon stock held as of the Record Date.

In order to effect the spin-off and govern our relationship with MPC after the spin-off, we entered into a Separation and Distribution Agreement, a Tax Sharing Agreement and an Employee Matters Agreement. The Separation and Distribution Agreement governed the separation of the downstream business, the distribution of MPC’s shares of common stock to our stockholders, transfer of assets and intellectual property, and other matters related to our relationship with MPC. The Separation and Distribution Agreement provides for cross-indemnities between Marathon Oil and MPC. In general, we have agreed to indemnify MPC for any liabilities relating to our historical exploration and production and oil sands mining operations, and MPC has agreed to indemnify us for any liabilities relating to the historical downstream operations.

The Tax Sharing Agreement governs the respective rights, responsibilities and obligations of Marathon Oil and MPC with respect to taxes and tax benefits, the filing of tax returns, the control of audits and other tax matters. In addition, the Tax Sharing Agreement reflects each company’s rights and obligations related to taxes that are attributable to periods prior to and including the separation date and taxes resulting from transactions effected in connection with the separation. In general, under the Tax Sharing Agreement, Marathon Oil is responsible for all U.S. federal, state, local and foreign income taxes attributable to Marathon Oil or any of its subsidiaries for any tax period that begins after the date of the spin-off, and MPC is responsible for all taxes attributable to it or its subsidiaries, whether accruing before, on or after the spin-off. The Tax Sharing Agreement contains covenants intended to protect the tax-free status of the spin-off. These covenants may restrict the ability of Marathon Oil and MPC to pursue strategic or other transactions that otherwise could maximize the values of their respective businesses and may discourage or delay a change of control of either company.

The Employee Matters Agreement contains provisions concerning benefit protection for employees who became MPC employees prior to December 31, 2011, treatment of holders of Marathon stock options, stock appreciation rights, restricted stock and restricted stock units, and cooperation between Marathon Oil and MPC in the sharing of employee information and maintenance of confidentiality. Unvested equity-based compensation awards were converted to awards of the entity where the employee holding them worked post-separation. For vested equity-based compensation awards, employees received both Marathon Oil and MPC awards.

The results of operations of our downstream business have been reported as discontinued operations for 2011. The table below shows selected financial information reported in discontinued operations related to the spin-off.

(In millions)	2011
Revenues applicable to discontinued operations	$	38,602
Pretax income from discontinued operations	$	2,012

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Acquisitions (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended			3 Months Ended	1 Months Ended	3 Months Ended	12 Months Ended	3 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jun. 30, 2012 Eagle Ford Paloma [Member] acre	Jul. 31, 2013 Eagle Ford [Member] acres	Sep. 30, 2012 Eagle Ford [Member]	Dec. 31, 2011 Eagle Ford [Member] acre	Dec. 31, 2011 Hilcorp Eagle Ford [Member] acre
Business Acquisition [Line Items]
Fair Value Inputs, Discount Rate				10.00%	10.00%			11.00%
Gas and oil acreages undeveloped and developed net				25,000	4,800		108,000	167,000
Business Combination, Consideration Transferred [Abstract]
Payments to Acquire Businesses, Net of Cash Acquired	$ 74	$ 1,033	$ 4,470	$ 768	$ 97	$ 232	$ 265	$ 4,500
Business Combination, Consideration Transferred, Other					23
Business Combination, Consideration Transferred					74
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents				8		0		0
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables				22		8		40
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory				1		0		4
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other				0		0		30
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets				31		8		74
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment				822		248		4,501
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets				0		0		21
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets				853		256		4,596
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Accounts Payable				78		23		101
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other				0		0		20
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities				78		23		121
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities,Asset Retirement Obligations				7		1		5
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities				85		24		126
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net				$ 768		$ 232		$ 4,470

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Debt (Details 1) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Debt Instrument [Line Items]
Unamortized Discount	$ (9)		$ (11)
Other Long-term Debt, Noncurrent	6,446	[1]	6,664	[1]
Fair value adjustments	(25)	[2]	(43)	[2]
Amounts due within one year	(68)		(184)
Total long-term debt due after one year	6,394		6,512
Debt Immediately Due If Change In Control	236
Senior Unsecured Notes Due 2013 [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	0		114
Debt Instrument, Interest Rate, Stated Percentage	9.125%
Senior Unsecured Notes Due 2015 [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	1,000	[3]	1,000	[3]
Debt Instrument, Interest Rate, Stated Percentage	0.90%	[3]
Senior Unsecured Notes Due 2017 [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	682	[3]	682	[3]
Debt Instrument, Interest Rate, Stated Percentage	6.00%	[3]
Senior Unsecured Notes Due 2018 [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	854	[3]	854	[3]
Debt Instrument, Interest Rate, Stated Percentage	5.90%	[3]
Senior Unsecured Notes Due 2019 [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	228	[3]	228	[3]
Debt Instrument, Interest Rate, Stated Percentage	7.50%	[3]
Senior Unsecured Notes Due 2022 [A] [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	1,000	[3]	1,000	[3]
Debt Instrument, Interest Rate, Stated Percentage	2.80%	[3]
Senior Unsecured Notes Due 2022 [B] [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	32		32
Debt Instrument, Interest Rate, Stated Percentage	9.375%
Series A Notes Due 2022 [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	3		3
Senior Unsecured Notes Due 2023 [A] [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	70		70
Debt Instrument, Interest Rate, Stated Percentage	8.50%
Senior Unsecured Notes Due 2023 [B] [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	131		131
Debt Instrument, Interest Rate, Stated Percentage	8.125%
Senior Unsecured Notes Due 2032 [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	550	[3]	550	[3]
Debt Instrument, Interest Rate, Stated Percentage	6.80%	[3]
Senior Unsecured Notes Due 2037 [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	750		750
Debt Instrument, Interest Rate, Stated Percentage	6.60%
Capital Lease Obligation of Consolidated Subsidiary due 2014 - 2049 [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	10		11
Promissory Note Due 2014 - 2015 [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	136		204
Debt Instrument, Interest Rate, Stated Percentage	4.55%
Obligation Relating To Revenue Bonds Due 2037 [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	1,000		1,000
Debt Instrument, Interest Rate, Stated Percentage	5.125%
Other Obligations [Member]
Debt Instrument [Line Items]
Other Long-term Debt, Noncurrent	$ 0		$ 35

[1] In the event of a change in control, as defined in the related agreements, debt obligations totaling $236 million at December 31, 2013, may be declared immediately due and payable.

[2] See Notes 15 and 16 for information on interest rate swaps.

[3] These notes contain a make-whole provision allowing us the right to repay the debt at a premium to market price.

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Inventories (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Inventory Disclosure [Abstract]
Liquid hydrocarbons, natural gas and bitumen	$ 55	$ 73
Supplies and sundry items	309	288
Inventories at cost	364	361
Percentage of LIFO Inventory	4.00%	6.00%
Excess of Replacement or Current Costs over Stated LIFO Value	$ 32	$ 29

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Defined Benefit Postretirement Plans and Defined Contribution Plan (Notes)

12 Months Ended

Dec. 31, 2013

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]

Defined Benefit Postretirement Plans and Defined Contribution Plan

Defined Benefit Postretirement Plans and Defined Contribution Plan

We have noncontributory defined benefit pension plans covering substantially all domestic employees as well as international employees located in Norway and the U.K. Benefits under these plans are based on plan provisions specific to each plan.

We also have defined benefit plans for other postretirement benefits covering our U.S. employees. Health care benefits are provided through comprehensive hospital, surgical and major medical benefit provisions subject to various cost-sharing features. Life insurance benefits are provided to certain retiree beneficiaries. Other postretirement benefits are not funded in advance.

Obligations and funded status– The accumulated benefit obligation for all defined benefit pension plans was $1,359 million and $1,442 million as of December 31, 2013 and 2012.    

As of December 31, 2013, our U.S. plans had accumulated benefit obligations in excess of plan assets, and as of December 31, 2012, our U.S. plans and our international ("Int'l") plans had accumulated benefit obligations in excess of plan assets. Summary information for these defined benefit pension plans follows.

	December 31,
	2013			2012
(In millions)	U.S.			U.S.			Int’l
Projected benefit obligation	$	(933	)	$	(1,146	)	$	(565	)
Accumulated benefit obligation	(791		)	(937		)	(505		)
Fair value of plan assets	625			630			500

The following summarizes the obligations and funded status for our defined benefit pension and other postretirement plans.

	Pension Benefits
	2013						2012						Other Benefits
(In millions)	U.S.			Int’l			U.S.			Int’l			2013			2012
Change in benefit obligations:
Beginning balance	$	1,146		$	565		$	986		$	465		$	311		$	301
Service cost	33			22			31			19			4			4
Interest cost	40			24			42			22			12			14
Actuarial loss (gain)	(140		)	40			196			49			(31		)	8
Foreign currency exchange rate changes	—			11			—			25			—			—
Benefits paid	(146		)	(13		)	(109		)	(15		)	(17		)	(16		)
Ending balance	$	933		$	649		$	1,146		$	565		$	279		$	311
Change in fair value of plan assets:
Beginning balance	$	630		$	500		$	516		$	412		$	—		$	—
Actual return on plan assets	65			74			66			57			—			—
Employer contributions	76			23			157			24			—			—
Foreign currency exchange rate changes	—			13			—			22			—			—
Benefits paid	(146		)	(13		)	(109		)	(15		)	—			—
Ending balance	$	625		$	597		$	630		$	500		$	—		$	—
Funded status of plans at December 31	$	(308	)	$	(52	)	$	(516	)	$	(65	)	$	(279	)	$	(311	)
Amounts recognized in the consolidated balance sheets:
Current liabilities	(16		)	—			(17		)	—			(19		)	(19		)
Noncurrent liabilities	(292		)	(52		)	(499		)	(65		)	(260		)	(292		)
Accrued benefit cost	$	(308	)	$	(52	)	$	(516	)	$	(65	)	$	(279	)	$	(311	)
Pretax amounts in accumulated other comprehensive loss:
Net loss (gain)	$	262		$	59		$	511		$	74		$	(8	)	$	23
Prior service cost (credit)	15			9			21			10			(5		)	(11		)

Components of net periodic benefit cost and other comprehensive (income) loss – The following summarizes the net periodic benefit costs and the amounts recognized as other comprehensive (income) loss for our defined benefit pension and other postretirement plans.

	Pension Benefits
	2013						2012						2011						Other Benefits
(In millions)	U.S.			Int’l			U.S.			Int’l			U.S.			Int’l			2013			2012			2011
Components of net periodic benefit cost:
Service cost	$	33		$	22		$	31		$	19		$	28		$	19		$	4		$	4		$	4
Interest cost	40			24			42			22			44			22			12			14			16
Expected return on plan assets	(43		)	(24		)	(43		)	(22		)	(43		)	(23		)	—			—			—
Amortization:
- prior service cost (credit)	6			1			7			1			6			—			(6		)	(7		)	(7		)
- actuarial loss	43			4			48			4			47			2			—			—			—
Net settlement loss(a)	45			—			45			—			30			—			—			—			—
Net periodic benefit cost(b)	$	124		$	27		$	130		$	24		$	112		$	20		$	10		$	11		$	13
Other changes in plan assets and benefit obligations recognized in other comprehensive (income) loss (pretax):
Actuarial loss (gain)	$	(161	)	$	(11	)	$	172		$	15		$	97		$	24		$	(31	)	$	7		$	1
Amortization of actuarial (loss) gain	(88		)	(4		)	(93		)	(4		)	(77		)	(2		)	—			—			—
Prior service cost (credit)	—			—			—			1			—			(11		)	—			—			—
Amortization of prior service credit (cost)	(6		)	(1		)	(7		)	(1		)	(6		)	—			6			7			7
Spin-off downstream business (c)	—			—			—			—			(24		)	—			—			—			—
Total recognized in other comprehensive (income) loss	$	(255	)	$	(16	)	$	72		$	11		$	(10	)	$	11		$	(25	)	$	14		$	8
Total recognized in net periodic benefit cost and other comprehensive (income) loss	$	(131	)	$	11		$	202		$	35		$	102		$	31		$	(15	)	$	25		$	21

^(a)  Settlement losses are recorded when lump sum payments from a plan in a period exceed the plan’s total service and interest costs for the period. Such settlements occurred in one or more of our U.S. plans in 2013, 2012 and 2011.

^(b)  Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.

^(c)  Includes net inter-company transfers of (gains)/losses due to the spin-off of the downstream business.

The estimated net loss and prior service cost for our defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2014 are $24 million and $6 million. The estimated prior service credit for our other defined benefit postretirement plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2014 is $5 million.

Plan assumptions – The following summarizes the assumptions used to determine the benefit obligations at December 31, and net periodic benefit cost for the defined benefit pension and other postretirement plans for 2013, 2012 and 2011.

	Pension Benefits
	2013					2012				2011				Other Benefits
(In millions)	U.S.			Int’l		U.S.		Int’l		U.S.		Int’l		2013		2012		2011
Weighted average assumptions used to determine benefit obligation:
Discount rate	4.28	%		4.60	%	3.44	%	4.40	%	4.45	%	4.70	%	4.85	%	4.06	%	4.90	%
Rate of compensation increase	5.00	%		4.90	%	5.00	%	4.50	%	5.00	%	4.30	%	5.00	%	5.00	%	5.00	%
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate	3.79	%		4.40	%	4.21	%	4.70	%	5.05	%	5.40	%	4.06	%	4.90	%	5.55	%
Expected long-term return on plan assets	7.25	%	(a)	4.90	%	7.75	%	5.20	%	8.50	%	5.86	%	—		—		—
Rate of compensation increase	5.00	%		4.50	%	5.00	%	4.30	%	5.00	%	5.10	%	5.00	%	5.00	%	5.00	%

^(a) Effective January 1, 2014, the expected long-term return on U.S. plan assets was changed from 7.25 percent to 6.75 percent.

Expected long-term return on plan assets

U.S. plan – The expected long-term return on plan assets assumption for our U.S. funded plan is determined based on an asset rate-of-return modeling tool developed by a third-party investment group. The tool utilizes underlying assumptions based on actual returns by asset category and inflation and takes into account our U.S. pension plan’s asset allocation to derive an expected long-term rate of return on those assets. Capital market assumptions reflect the long-term capital market outlook. The assumptions for equity and fixed income investments are developed using a building-block approach, reflecting observable inflation information and interest rate information available in the fixed income markets. Long-term assumptions for other asset categories are based on historical results, current market characteristics and the professional judgment of our internal and external investment teams.

International plans – To determine the expected long-term return on plan assets assumption for our international plans, we consider the current level of expected returns on risk-free investments (primarily government bonds), the historical levels of the risk premiums associated with the other applicable asset categories and the expectations for future returns of each asset class. The expected return for each asset category is then weighted based on the actual asset allocation in our international pension plans to develop the overall expected long-term return on plan assets assumption.

Assumed health care cost trend rates

	2013		2012		2011
Health care cost trend rate assumed for the following year:
Medical
Pre-65	7.50	%	8.00	%	7.50	%
Post-65	6.50	%	7.00	%	7.00	%
Prescription drugs	7.00	%	7.00	%	7.50	%
EGWP subsidy(a)	8.70	%	7.50	%	n/a
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):
Medical
Pre-65	5.00	%	5.00	%	5.00	%
Post-65	5.00	%	5.00	%	5.00	%
Prescription drugs	5.00	%	5.00	%	5.00	%
EGWP subsidy(a)	5.00	%	5.00	%	n/a
Year that the rate reaches the ultimate trend rate:
Medical
Pre-65	2020		2020		2018
Post-65	2020		2018		2017
Prescription drugs	2020		2018		2018
EGWP subsidy(a)	2020		2020		n/a

^(a)  An employee group waiver plan ("EGWP") is a group Medicare Part D prescription drug plan. Effective January 1, 2013, we implemented the EGWP as a result of the Patient Protection and Affordable Care Act, which ended tax-free status of retiree drug subsidy programs but increased federal funding to Part D prescription drug plans.

Assumed health care cost trend rates have a significant effect on the amounts reported for defined benefit retiree health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:

(In millions)	1-Percentage- Point Increase		1-Percentage- Point Decrease
Effect on total of service and interest cost components	$	2	$	(2	)
Effect on other postretirement benefit obligations	$	30	$	(25	)

Plan investment policies and strategies – The investment policies for our U.S. and international pension plan assets reflect the funded status of the plans and expectations regarding our future ability to make further contributions. Long-term investment goals are to: (1) manage the assets in accordance with the legal requirements of all applicable laws; (2) produce investment returns which meet or exceed the rates of return achievable in the capital markets while maintaining the risk parameters set by the plans’ investment committees and protecting the assets from any erosion of purchasing power; and (3) position the portfolios with a long-term risk/return orientation.

U.S. plan – Historical performance and future expectations suggest that common stocks will provide higher total investment returns than fixed income securities over a long-term investment horizon. Short-term investments are utilized for pension payments, expenses, and other liquidity needs. However, to reduce volatility in returns and to better match the plan’s liabilities over time, as the plan’s funded ratio (as defined by the investment policy) improves, the allocation to equity securities will decrease while the amount allocated to fixed income securities will increase. As such, the plan’s current targeted asset allocation is comprised of 55 percent equity securities and high-yield bonds and 45 percent other fixed income securities.

The plan's assets are managed by a third-party investment manager. The investment manager is limited to pursuing the investment strategies regarding asset mix and purchases and sales of securities within the parameters defined in the investment policy guidelines and investment management agreement. Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies.

International plans – Our international plans’ target asset allocation is comprised of 70 percent equity securities and 30 percent fixed income securities. The plan assets are invested in eleven separate portfolios, mainly pooled fund vehicles, managed by several professional investment managers. Investments are diversified by industry and type, limited by grade and maturity. The use of derivatives by the investment managers is permitted, subject to strict guidelines. The investment managers' performance is measured independently by a third-party asset servicing consulting firm. Overall, investment performance and risk is measured and monitored on an ongoing basis through quarterly investment portfolio reviews and periodic asset and liability studies.

Fair value measurements – Plan assets are measured at fair value. The following provides a description of the valuation techniques employed for each major plan asset class at December 31, 2013 and 2012.

Cash and cash equivalents – Cash and cash equivalents include cash on deposit and an investment in a money market mutual fund that invests mainly in short-term instruments and cash, both of which are valued using a market approach and are considered Level 1. The money market mutual fund is valued at the net asset value ("NAV") of shares held. Cash and cash equivalents also include a cash reserve account (a collective short-term investment fund) that is valued using an income approach and is considered Level 2. The underlying assets are usually short-term bonds, discount notes, and commercial paper.

Equity securities – Investments in common stock, preferred stock, and real estate investment trusts ("REIT") are valued using a market approach at the closing price reported in an active market and are therefore considered Level 1. The non-public investment trust is valued using a market approach based on the underlying investments in the trust, which are publicly-traded securities, and is considered Level 2. Private equity investments include interests in limited partnerships which are valued based on the sum of the estimated fair values of the investments held by each partnership, determined using a combination of market, income and cost approaches, plus working capital, adjusted for liabilities, currency translation and estimated performance incentives. These private equity investments are considered Level 3.

Mutual funds – Investments in mutual funds are valued using a market approach. The shares or units held are traded on the public exchanges and such prices are Level 1 inputs.

Pooled funds – Investments in pooled funds are valued using a market approach at the NAV of units held, but investment opportunities in such funds are limited to institutional investors on the behalf of defined benefit plans. The various funds consist of either an equity or fixed income investment portfolio with underlying investments held in U.S. and non-U.S. securities. Nearly all of the underlying investments are publicly-traded. The majority of the pooled funds are benchmarked against a relative public index. These are considered Level 2.

Fixed income securities – Fixed income securities are valued using a market approach. U.S. treasury notes and exchange traded funds are valued at the closing price reported in an active market, and are considered Level 1. Treasury inflation-protected securities ("TIPS") are valued at the daily closing price reported in an active market. TIPS prices exclude adjustment factors for inflation and are considered Level 1. Corporate bonds, non-U.S. government bonds, private placements, and yankee bonds are valued using calculated yield curves created by models that incorporate factors such as interest rate, benchmark quotes, trade data, dealer quotes, primary and secondary market spread activity, and other market information and are considered Level 2. Taxable municipal bonds are valued using calculated yield curves considering market factors such as benchmark issues, trades, trading spreads between similar issuers or creditors, historical trading spreads over widely accepted market benchmarks, and verified bid information. These assets are considered Level 2. Municipal bonds are valued by an evaluation of terms and conditions of the security and considering market factors such as benchmark curves, trades, bid price or spreads, two-sided markets, and quotes. These assets are considered Level 2. The investment in the commingled fund is valued using the NAV of units held, and is considered Level 2. The commingled fund consists mostly of high-yield U.S. and non-U.S. corporate bonds. Investment opportunities in this fund are limited to qualified retirement plans and their plan participants. The investment objective of the portfolio is to provide long-term total return in excess of the Barclays U.S. High Yield Bond Index.

Real estate – Real estate investments are valued using a combination of the income and market approaches that is based on discounted cash flows, comparable sales, outside appraisals, price per square foot or some combination thereof and therefore are considered Level 3.

Other – Other investments are composed of an investment in an unallocated annuity contract, an investment contract with an international insurance carrier, and investments in two limited liability companies (“LLCs") with no public market. The LLCs were formed to acquire timberland in the northwest and other properties. The investment in an unallocated annuity contract is valued using a market approach based on the experience of the assets held in an insurer’s general account. The majority of the general account is invested in a well-diversified portfolio of high-quality fixed income securities, primarily consisting of investment-grade bonds. Investment income is allocated among pension plans participating in the general account based on the investment year method. Under this method, a record of the book value of assets held is maintained in subdivisions according to the calendar year in which the funds are invested. The earnings rate for each of these calendar year subdivisions varies from year to year, reflecting the actual earnings on the assets attributed to that year. Due to the lack of transparency in the use of investment year subdivisions, this asset is considered Level 3. The insurance carrier contract is funded by premiums paid annually by the participating plans and the funds are invested by the insurance carrier in portfolios with different risk profiles (low, medium, high) that can be elected by clients. The majority of the underlying investments consists of a well-diversified mix of non-U.S. publicly traded equity securities valued at the closing price reported in an active market and fixed income securities valued using calculated yield curves. This asset is considered Level 2. The values of the LLCs are determined using a cost approach based on historical cost less depletion for timber previously harvested. These assets are considered Level 3.

The following tables present the fair values of our defined benefit pension plans’ assets, by level within the fair value hierarchy, as of December 31, 2013 and 2012.

	December 31, 2013
(In millions)	Level 1				Level 2				Level 3				Total
	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l		U.S.		Int’l
Cash and cash equivalents	$	19	$	1	$	1	$	—	$	—	$	—	$	20	$	1
Equity securities:
Common stock(a)	288		—		—		—		—		—		288		—
Preferred stock	4		—		—		—		—		—		4		—
Private equity	—		—		—		—		23		—		23		—
REIT	2		—		—		—		—		—		2		—
Mutual funds(b)	—		219		—		—		—		—		—		219
Pooled funds(c)	—		—		—		186		—		—		—		186
Fixed income securities:
U.S. treasury notes	63		—		—		—		—		—		63		—
Exchange traded funds	1		—		—		—		—		—		1		—
Corporate bonds(d)	—		—		127		—		—		—		127		—
Municipal bonds	—		—		1		—		—		—		1
Non-U.S. government bonds	—		—		7		—		—		—		7		—
Private placements	—		—		21		—		—		—		21		—
Taxable municipal bonds	—		—		13		—		—		—		13		—
Treasury inflation-protected securities	1		—		—		—		—		—		1		—
Yankee bonds	—		—		3		—		—		—		3		—
Commingled fund(e)	—		—		17		—		—		—		17		—
Pooled funds(f)	—		—		—		178		—		—		—		178
Real estate(g)	—		—		—		—		22		—		22		—
Other	—		—		—		13		12		—		12		13
Total investments, at fair value	$	378	$	220	$	190	$	377	$	57	$	—	$	625	$	597

	December 31, 2012
(In millions)	Level 1				Level 2				Level 3				Total
	U.S.		Int’l		U.S.		Int’l		U.S.		Int’l		U.S.		Int’l
Cash and cash equivalents	$	16	$	1	$	1	$	—	$	—	$	—	$	17	$	1
Equity securities:
Common stock(a)	312		—		—		—		—		—		312		—
Private equity	—		—		—		—		25		—		25		—
REIT	2		—		—		—		—		—		2		—
Investment trust	—		—		1		—		—		—		1		—
Mutual funds(b)	—		171		—		—		—		—		—		171
Pooled funds(c)	—		—		—		152		—		—		—		152
Fixed income securities:
U.S. treasury notes	67		—		—		—		—		—		67		—
Exchange traded funds	8		—		—		—		—		—		8		—
Corporate bonds(d)	—		—		96		—		—		—		96		—
Non-U.S. government bonds	—		—		5		—		—		—		5		—
Private placements	—		—		18		—		—		—		18		—
Taxable municipal bonds	—		—		14		—		—		—		14		—
Yankee bonds	—		—		2		—		—		—		2		—
Commingled fund(e)	—		—		28		—		—		—		28		—
Pooled funds(f)	—		—		—		166		—		—		—		166
Real estate(g)	—		—		—		—		23		—		23		—
Other	—		—		—		10		12		—		12		10
Total investments, at fair value	$	405	$	172	$	165	$	328	$	60	$	—	$	630	$	500

^(a)  Includes approximately 60 percent of investments held in U.S. and non-U.S. common stocks in the banking, pharmaceuticals, oil and gas, insurance, telecommunications, electric, aerospace/defense, retail, transportation, food processing, semiconductors, and chemicals sectors. The remaining 40 percent of common stock is held in various other sectors.

^(b)  Includes approximately 75 percent of investments held in U.S. and non-U.S. common stocks in the consumer staples, financial services, health care, energy, basic materials, leisure, and industrial goods and services sectors and 25 percent of investments held among various other sectors. The funds' objective is to outperform their respective benchmark indexes, FTSE ALL Share 5% Capped Index and MSCI World Index, as defined by the investment policy.

^(c)  Includes approximately 80 percent of investments held in non-U.S. publicly traded common stocks (specifically Asia Pacific, except Japan, and the U.K.) in the financial, consumer staples, information technology, materials, energy, industrials, and telecommunication services sectors and the remaining 20 percent of investments held among various other sectors. The funds' objective is to outperform their respective benchmark indexes, MSCI AC Asia Pacific ex Japan Index, FTSE Small Cap Index, and MSCI Emerging Markets Index, as defined by the investment policy.

^(d)  Includes approximately 70 percent of U.S. and non-U.S. corporate bonds in the banking and finance, utilities, oil and gas, news/media, and health care sectors. The remaining 30 percent of corporate bonds are in various other sectors.

^(e)  Includes approximately 90 percent of investments held in U.S. and non-U.S. corporate bonds in the consumer discretionary, financial, industrial, telecommunication services, energy, health care, information technology and materials sectors and 10 percent of investments held among various other sectors.

^(f)  Includes approximately 75 percent of investments held in U.S. and non-U.S. publicly traded investment grade government and corporate bonds which include gilts, treasuries, financial, corporates, and collateralized asset backed securities and 25 percent of investments held among various other sectors. The funds' objective is to outperform their respective benchmark indexes, as defined by the investment policy.

^(g)  Includes investments diversified by property type and location. The largest property sector holdings, which represent approximately 70 percent of investments held, are office, hotel, residential, and retail with the greatest percentage of investments made in the U.S. and Asia, which includes the emerging markets of China and India.

The following is a reconciliation of the beginning and ending balances recorded for plan assets classified as Level 3 in the fair value hierarchy.

	2013
(In millions)	Private Equity			Real Estate			Other		Total
Beginning balance	$	25		$	23		$	12	$	60
Actual return on plan assets:
Realized gain	6			1			—		7
Unrealized gain (loss)	(1		)	1			—		—
Purchases	6			1			—		7
Sales	(13		)	(4		)	—		(17		)
Ending balance	$	23		$	22		$	12	$	57

	2012
(In millions)	Private Equity			Real Estate			Other			Total
Beginning balance	$	23		$	21		$	14		$	58
Actual return on plan assets:
Realized gain	2			—			—			2
Unrealized gain (loss)	1			1			(2		)	—
Purchases	4			3			—			7
Sales	(5		)	(2		)	—			(7		)
Ending balance	$	25		$	23		$	12		$	60

Cash flows

Estimated future benefit payments – The following gross benefit payments, which were estimated based on actuarial assumptions applied at December 31, 2013 and reflect expected future services, as appropriate, are to be paid in the years indicated.

	Pension Benefits				Other Benefits
(In millions)	U.S.		Int’l
2014(a)	$	96	$	14	$	19
2015	94		14		20
2016	95		16		20
2017	96		18		20
2018	92		21		20
2019 through 2023	368		120		98

^(a)  Primarily as a result of retirements effective January 1, 2014, actual 2014 U.S. gross benefit payments will exceed the actuarial estimate above, including approximately $163 million which will be paid during the first quarter of 2014.

Contributions to defined benefit plans – We expect to make contributions to the funded pension plans of up to $77 million in 2014, and $11 million of that amount was paid in January 2014. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are expected to be approximately $74 million and $19 million in 2014.

Contributions to defined contribution plan – We contribute to a defined contribution plan for eligible employees. Contributions to this plan totaled $26 million, $25 million and $21 million in 2013, 2012 and 2011.

XML

Goodwill (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Goodwill [Line Items]
Beginning balance, gross			$ 1,937	$ 1,948
Less: accumulated impairment			(1,412)	(1,412)
Goodwill [Roll Forward]
Beginning balance, net	525		536
Dispositions	(26)		(11)
Ending balance, net	499		525
North America Exploration and Production [Member]
Goodwill [Line Items]
Beginning balance, gross			343
Less: accumulated impairment			0
Goodwill [Roll Forward]
Beginning balance, net	343
Dispositions	4	[1]
Ending balance, net	347
International Exploration and Production [Member]
Goodwill [Line Items]
Beginning balance, gross			182
Less: accumulated impairment			0
Goodwill [Roll Forward]
Beginning balance, net	182
Dispositions	(30)
Ending balance, net	152
Exploration and Production Segment [Member]
Goodwill [Line Items]
Beginning balance, gross				536
Less: accumulated impairment				0
Goodwill [Roll Forward]
Beginning balance, net			536
Dispositions			(11)
Ending balance, net			525
Oil Sands Mining Segment [Member]
Goodwill [Line Items]
Beginning balance, gross			1,412	1,412
Less: accumulated impairment			(1,412)	(1,412)
Goodwill [Roll Forward]
Beginning balance, net	0		0
Dispositions	0		0
Ending balance, net	$ 0		$ 0

[1] Goodwill related to our Alaska disposition was less than the estimate classified as held for sale in 2012.

XML

Segment Information (Tables)

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

2013							Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	5,068	$	5,827	$	1,576	$	(52	)	(c)	$	12,419
Marketing revenues	1,797		267		18		—				2,082
Total revenues	6,865		6,094		1,594		(52		)		14,501
Income from equity method investments	—		427		—		(4		)	(d)	423
Net gain (loss) on disposal of assets and other income	12		50		5		(32		)		35
Production expenses	797		534		1,000		—				2,331
Marketing costs	1,796		258		18		—				2,072
Exploration expenses	725		263		—		—				988
Depreciation, depletion and amortization	1,927		621		218		24				2,790
Impairments	41		—		—		55				96
Other expenses (a)	420		239		66		401				1,126
Taxes other than income	318		7		22		5				352
Net interest and other	—		—		—		274				274
Provision (benefit) for income taxes	324		3,226		69		(282		)		3,337
Segment income/Income from continuing operations	$	529	$	1,423	$	206	$	(565	)		$	1,593
Capital expenditures (b)	$	3,649	$	764	$	286	$	285			$	4,984

^(a)  Includes other operating expenses and general and administrative expenses.

^(b)  Includes accruals.

^(c)  Unrealized gain (loss) on crude oil derivative instruments.

^(d)  EGHoldings impairment (see Note 15).

2012							Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM		to Segments				Total
Sales and other operating revenues	$	3,944	$	7,445	$	1,521	$	53		(c)	$	12,963
Marketing revenues	2,451		248		30		—				2,729
Total revenues	6,395		7,693		1,551		53				15,692
Income from equity method investments	2		368		—		—				370
Net gain (loss) on disposal of assets and other income	11		30		4		114				159
Production expenses	706		500		996		—				2,202
Marketing costs	2,444		269		31		—				2,744
Exploration expenses	588		118		—		—				706
Depreciation, depletion and amortization	1,428		787		217		45				2,477
Impairments	11		—		—		360				371
Other expenses (a)	400		200		60		464				1,124
Taxes other than income	226		5		22		(5		)		248
Net interest and other	—		—		—		219				219
Provision (benefit) for income taxes	223		4,552		58		(316		)		4,517
Segment income/Income from continuing operations	$	382	$	1,660	$	171	$	(600	)		$	1,613
Capital expenditures (b)	$	3,988	$	489	$	188	$	466			$	5,131

2011								Not Allocated
(In millions)	N.A. E&P		Int'l E&P		OSM			to Segments			Total
Sales and other operating revenues	$	3,364	$	5,851	$	1,535		$	—		$	10,750
Marketing revenues	3,614		252		53			—			3,919
Total revenues	6,978		6,103		1,588			—			14,669
Income from equity method investments	20		442		—			—			462
Net gain (loss) on disposal of assets and other income	21		73		(17		)	74			151
Production expenses	545		409		915			82			1,951
Marketing costs	3,598		247		53			—			3,898
Exploration expenses	388		253		—			—			641
Depreciation, depletion and amortization	1,191		828		196			48			2,263
Impairments	12		—		—			298			310
Other expenses (a)	494		191		46			465			1,196
Taxes other than income	182		6		17			(12		)	193
Net interest and loss on early extinguishment of debt	—		—		—			386			386
Provision (benefit) for income taxes	217		2,693		83			(267		)	2,726
Segment income/Income from continuing operations	$	392	$	1,991	$	261		$	(926	)	$	1,718
Capital expenditures (b)	$	2,163	$	544	$	308		$	384		$	3,399

Schedule of Revenue from External Customers Attributed to Foreign Countries by Geographic Area

The following summarizes revenues from external customers by geographic area.

(In millions)	2013		2012		2011
United States	$	6,813	$	6,448	$	6,978
Norway	3,183		3,714		3,563
Canada	1,594		1,551		1,588
Libya(a)	1,106		1,989		216
Other international	1,805		1,990		2,324
Total revenues	$	14,501	$	15,692	$	14,669

^(a)  See Note 13 for discussion of Libya operations.

Revenue from External Customers by Products and Services

Revenues by product line were:

(In millions)	2013		2012		2011
Liquid hydrocarbons	$	11,932	$	12,983	$	11,778
Natural gas	937		1,052		1,203
Synthetic crude oil	1,542		1,409		1,442
Other	90		248		246
Total revenues	$	14,501	$	15,692	$	14,669

Schedule of Disclosure on Geographic Areas, Long-Lived Assets in Individual Foreign Countries by Country

The following summarizes certain long-lived assets by geographic area, including property, plant and equipment and equity method investments.

	December 31,
(In millions)	2013		2012
United States	$	14,635	$	13,677
Canada	9,794		9,693
Norway	977		987
Equatorial Guinea	1,977		2,081
Other international	1,963		3,113
Total long-lived assets	$	29,346	$	29,551

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

	December 31,
(In millions)	2013			2012
North America E&P	$	26,755		$	23,748
International E&P	12,428			13,214
Oil Sands Mining	10,436			10,127
Corporate	421			449
Total property, plant and equipment	50,040			47,538
Less accumulated depreciation, depletion and amortization	(21,895		)	(19,266		)
Net property, plant and equipment	$	28,145		$	28,272

During the third quarter of 2013, our Libya production operations were impacted by third-party labor strikes at the Es Sider oil terminal. We have had no oil liftings in Libya since July 2013. Uncertainty around production and sales levels from Libya have existed since the first quarter of 2011 when production operations were suspended until the fourth quarter of that year.  We and our partners in the Waha concessions continue to assess the condition of our assets in Libya and uncertainty around production and sales levels remains. As of December 31, 2013, our net property, plant and equipment investment in Libya is approximately $761 million and total proved reserves (unaudited) in Libya are 249 mmboe.

Deferred exploratory well costs were as follows:

	December 31,
(In millions)	2013			2012			2011
Amounts capitalized less than one year after completion of drilling	$	512		$	388		$	482
Amounts capitalized greater than one year after completion of drilling	281			229			222
Total deferred exploratory well costs	$	793		$	617		$	704
Number of projects with costs capitalized greater than one year after
completion of drilling	7			6			5
	December 31,
(In millions)	2013			2012			2011
Beginning balance	$	617		$	704		$	657
Additions	746			699			625
Dry well expense	(147		)	(111		)	(223		)
Transfers to development	(414		)	(629		)	(279		)
Dispositions	(9		)	(46		)	(76		)
Ending balance	$	793		$	617		$	704

Exploratory well costs capitalized greater than one year after completion of drilling as of December 31, 2013 are summarized by geographical area below:

(In millions)
Angola	$	153
Norway	70
E.G.	22
Canada	36
Total	$	281

Well costs that have been suspended for longer than one year are associated with seven projects. Management believes these projects with suspended exploratory drilling costs exhibit sufficient quantities of hydrocarbons to justify potential development.

Angola – Exploration on Angola Block 31 began in 2004, with costs accumulating through 2009. Exploration on Angola Block 32 began in 2011, with costs accumulating through 2013. In June and December 2013, we entered into agreements to sell our non-operated working interests in Angola Blocks 31 and 32 (see Note 6).

Norway – Three offshore Norway projects had costs incurred from 2009 through 2011. The development plan for Boyla was approved by the Norwegian government in October 2012. This will tie-back to the Alvheim FPSO and development drilling is planned in 2014, with first production expected in early 2015. Development options are being evaluated for the Caterpillar and Viper projects.

E.G. – The Corona well on Block D offshore E.G. was drilled in 2004, and we acquired an additional interest in the well in 2012. We plan to develop Block D through a unitization with the Alba field, which is currently being negotiated.

Canada – Exploration began on our Canadian in-situ assets at Birchwood in 2010 with costs accumulating through 2011. In 2012, we submitted a regulatory application for a proposed 12 mbbld SAGD demonstration project.  We expect to receive regulatory approval for this project by the end of 2014.  Upon receiving this approval, we will further evaluate our development plans.