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, 2012

Commission file number 001-35054

Marathon Petroleum Corporation

(Exact name of registrant as specified in its charter)

Delaware	27-1284632
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

539 South Main Street, Findlay, OH 45840-3229

(Address of principal executive offices)

(419) 422-2121

(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 $.01	New York Stock Exchange

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

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

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

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

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

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

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

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

The aggregate market value of Common Stock held by non-affiliates as of June 30, 2012 was approximately $15.3 billion. This amount is based on the closing price of the registrant’s Common Stock on the New York Stock Exchange on June 29, 2012. 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 331,433,926 shares of Marathon Petroleum Corporation Common Stock outstanding as of February 15, 2013.

Documents Incorporated By Reference

Portions of the registrant’s proxy statement relating to its 2013 Annual Meeting of Shareholders, 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 PETROLEUM CORPORATION

Unless otherwise stated or the context otherwise indicates, all references in this Annual Report on Form 10-K to “MPC,” “us,” “our,” “we” or “the Company” mean Marathon Petroleum Corporation and its consolidated subsidiaries, and for periods prior to its spinoff from Marathon Oil Corporation, the Refining, Marketing & Transportation Business of Marathon Oil Corporation.

Table of Contents

			Page
PART I
	Item 1.	Business		3
	Item 1A.	Risk Factors		27
	Item 1B.	Unresolved Staff Comments		38
	Item 2.	Properties		38
	Item 3.	Legal Proceedings		38
	Item 4.	Mine Safety Disclosures		39
PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		40
	Item 6.	Selected Financial Data		41
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		42
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk		73
	Item 8.	Financial Statements and Supplementary Data		76
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		134
	Item 9A.	Controls and Procedures		134
	Item 9B.	Other Information		134
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance		135
	Item 11.	Executive Compensation		135
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		136
	Item 13.	Certain Relationships and Related Transactions, and Director Independence		136
	Item 14.	Principal Accounting Fees and Services		137
PART IV
	Item 15.	Exhibits and Financial Statement Schedules		138
		SIGNATURES		142

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. You can identify our forward-looking statements by words such as “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “plan,” “predict,” “project,” “seek,” “target,” “could,” “may,” “should” or “would” or other similar expressions that convey the uncertainty of future events or outcomes. 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 include, but are not limited to, statements that relate to, or statements that are subject to risks, contingencies or uncertainties that relate to:

• future levels of revenues, refining and marketing gross margins, retail gasoline and distillate gross margins, merchandise margins, income from operations, net income or earnings per share;

• anticipated volumes of feedstock, throughput, sales or shipments of refined products;

• anticipated levels of regional, national and worldwide prices of crude oil and refined products;

• anticipated levels of crude oil and refined product inventories;

• future levels of capital, environmental or maintenance expenditures, general and administrative and other expenses;

• the success or timing of completion of ongoing or anticipated capital or maintenance projects;

• expectations regarding the acquisition or divestiture of assets;

• our share repurchase program, including the timing and amounts of any common stock repurchases;

• the effect of restructuring or reorganization of business components;

• the potential effects of judicial or other proceedings on our business, financial condition, results of operations and cash flows; and

• the anticipated effects of actions of third parties such as competitors, or federal, foreign, state or local regulatory authorities, or plaintiffs in litigation.

We have based our forward-looking statements on our current expectations, estimates and projections about our industry and our company. We caution that these statements are not guarantees of future performance and you should not rely unduly on them, as they involve risks, uncertainties, and assumptions that we cannot predict. In addition, we have based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. While our management considers these assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Accordingly, our actual results may differ materially from the future performance that we have expressed or forecast in our forward-looking statements. Differences between actual results and any future performance suggested in our forward-looking statements could result from a variety of factors, including the following:

• changes in general economic, market or business conditions;

• domestic and foreign supplies of crude oil and other feedstocks;

• the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) to agree on and to influence crude oil price and production controls;

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• domestic and foreign supplies of refined products such as gasoline, diesel fuel, jet fuel, home heating oil and petrochemicals;

• foreign imports of refined products;

• refining industry overcapacity or under capacity;

• changes in the cost or availability of third-party vessels, pipelines and other means of transportation for crude oil, feedstocks and refined products;

• the price, availability and acceptance of alternative fuels and alternative-fuel vehicles and laws mandating such fuels or vehicles;

• fluctuations in consumer demand for refined products, including seasonal fluctuations;

• political and economic conditions in nations that consume refined products, including the United States, and in crude oil producing regions, including the Middle East, Africa, Canada and South America;

• actions taken by our competitors, including pricing adjustments, expansion of retail activities, and the expansion and retirement of refining capacity in response to market conditions;

• changes in fuel and utility costs for our facilities;

• failure to realize the benefits projected for capital projects, or cost overruns associated with such projects;

• the ability to successfully implement new assets and growth opportunities;

• accidents or other unscheduled shutdowns affecting our refineries, machinery, pipelines or equipment, or those of our suppliers or customers;

• unusual weather conditions and natural disasters, which can unforeseeably affect the price or availability of crude oil and other feedstocks and refined products;

• acts of war, terrorism or civil unrest that could impair our ability to produce or transport refined products or receive feedstocks;

• legislative or regulatory action, which may adversely affect our business or operations;

• rulings, judgments or settlements and related expenses in litigation or other legal, tax or regulatory matters, including unexpected environmental remediation costs, in excess of any reserves or insurance coverage;

• labor and material shortages;

• the maintenance of satisfactory relationships with labor unions and joint venture partners;

• the ability and willingness of parties with whom we have material relationships to perform their obligations to us;

• the market price of our common stock and its impact on our share repurchase program;

• changes in the credit ratings assigned to our debt securities and trade credit, changes in the availability of unsecured credit and changes affecting the credit markets generally; and

• the other factors described in Item 1A. Risk Factors.

We undertake no obligation to update any forward-looking statements except to the extent required by applicable law.

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PART I

Item 1. Business

Overview

Marathon Petroleum Corporation (“MPC”) was incorporated in Delaware on November 9, 2009 in connection with an internal restructuring of Marathon Oil Corporation (“Marathon Oil”). On May 25, 2011, the Marathon Oil board of directors approved the spinoff of its Refining, Marketing & Transportation Business (“RM&T Business”) into an independent, publicly traded company, MPC, through the distribution of MPC common stock to the stockholders of Marathon Oil common stock. In accordance with a separation and distribution agreement between Marathon Oil and MPC, the distribution of MPC common stock was made on June 30, 2011, with Marathon Oil stockholders receiving one share of MPC common stock for every two shares of Marathon Oil common stock held (the “Spinoff”). Following the Spinoff, Marathon Oil retained no ownership interest in MPC, and each company had separate public ownership, boards of directors and management. All subsidiaries and equity method investments not contributed by Marathon Oil to MPC remained with Marathon Oil and, together with Marathon Oil, are referred to as the “Marathon Oil Companies.” On July 1, 2011, our common stock began trading “regular-way” on the New York Stock Exchange (“NYSE”) under the ticker symbol “MPC”.

We are one of the largest independent petroleum product refiners, marketers and transporters in the United States. Our operations consist of three business segments:

• Refining & Marketing—refines crude oil and other feedstocks at our seven refineries in the Gulf Coast and Midwest regions of the United States (including the recently acquired Galveston Bay refinery), purchases ethanol and refined products for resale and distributes refined products through various means, including barges, terminals and trucks that we own or operate. We sell refined products to wholesale marketing customers domestically and internationally, to buyers on the spot market, to our Speedway business segment and to dealers and jobbers who operate Marathon^® retail outlets;

• Speedway—sells transportation fuels and convenience products in the retail market in the Midwest, primarily through Speedway^® convenience stores; and

• Pipeline Transportation—transports crude oil and other feedstocks to our refineries and other locations, delivers refined products to wholesale and retail market areas and includes the aggregated operations of MPLX LP and MPC’s retained pipeline assets and investments.

See Item 8. Financial Statements and Supplementary Data – Note 11 for operating segment and geographic financial information, which is incorporated herein by reference.

On February 1, 2013, we acquired from BP Products North America Inc. and BP Pipelines (North America) Inc. (collectively, “BP”) the 451,000 barrel per calendar day refinery in Texas City, Texas, three intrastate natural gas liquid pipelines originating at the refinery, an allocation of BP’s Colonial Pipeline Company shipper history, four light product terminals, branded-jobber marketing contract assignments for the supply of approximately 1,200 branded sites and a 1,040 megawatt electric cogeneration facility. We refer to these assets as the “Galveston Bay Refinery and Related Assets”. The operating statistics included in this section do not include these assets. See Item 8. Financial Statements and Supplementary Data – Note 26 for additional information on the acquisition of these assets.

In 2012, we formed MPLX LP (“MPLX”), a master limited partnership, to own, operate, develop and acquire pipelines and other midstream assets related to the transportation and storage of crude oil, refined products and other hydrocarbon-based products. On October 31, 2012, MPLX completed its initial public offering of 19,895,000 common units, which represented the sale by us of a 26.4 percent interest in MPLX. We own a 73.6

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percent interest in MPLX, including the general partner interest, and we consolidate this entity for financial reporting purposes since we have a controlling financial interest. Headquartered in Findlay, Ohio, MPLX’s initial assets consist of a 51 percent general partner interest in MPLX Pipe Line Holdings LP (“Pipe Line Holdings”), which owns a network of common carrier crude oil and product pipeline systems and associated storage assets in the Midwest and Gulf Coast regions of the United States, and a 100 percent interest in a butane storage cavern in West Virginia. We own the remaining 49 percent limited partner interest in Pipe Line Holdings. The operating statistics in this section include 100 percent of these assets for all time periods presented. See Item 8. Financial Statements and Supplementary Data – Note 4 for additional information on MPLX’s initial public offering.

On December 1, 2010, we completed the sale of most of our Minnesota assets. These assets included the 74,000 barrel per calendar day St. Paul Park refinery and associated terminals, 166 convenience stores primarily branded SuperAmerica^® (including six stores in Wisconsin) along with the SuperMom’s^® bakery (a baked goods and sandwich supply operation) and certain associated trademarks, SuperAmerica Franchising LLC, interests in pipeline assets in Minnesota and associated inventories. We refer to these assets as the “Minnesota Assets.” The operating statistics included in this section reflect the exclusion of these assets, except as otherwise indicated. See Item 8. Financial Statements and Supplementary Data – Note 7 for additional information on the disposition of these assets.

Our Competitive Strengths

High Quality Asset Base

We believe we are the largest crude oil refiner in the Midwest and the fourth largest in the United States based on crude oil refining capacity. We own a seven-plant refinery network, including our recently acquired Galveston Bay refinery, with approximately 1.7 million barrels per calendar day (“mmbpcd”) of crude oil throughput capacity. Our refineries process a wide range of crude oils, including heavy and sour crude oils, which can generally be purchased at a discount to sweet crude, and produce transportation fuels such as gasoline and distillates, specialty chemicals and other refined products.

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Strategic Location

The geographic locations of our refineries and our extensive midstream distribution system provide us with strategic advantages. Located in Petroleum Administration for Defense District (“PADD”) II and PADD III, which consist of states in the Midwest and the Gulf Coast regions of the United States, our refineries have the ability to procure crude oil from a variety of supply sources, including domestic, Canadian and other foreign sources, which provides us with flexibility to optimize crude supply costs. For example, geographic proximity to Canadian crude oil supply sources allows our Midwest refineries to incur lower transportation costs than competitors transporting Canadian crude oil to the Gulf Coast for refining. Our refinery locations and midstream distribution system also allow us to access export markets and to serve a broad range of key end-user markets across the United States quickly and cost-effectively.

* As of December 31, 2012. Excludes the Galveston Bay Refinery and Related Assets.

Attractive Growth Opportunities through Internal Projects

We believe we have attractive growth opportunities through internal capital projects. In 2012, we completed a $2.2 billion (excluding capitalized interest) heavy oil upgrading and expansion project at our Detroit, Michigan refinery. The project enables the refinery to process additional heavy, sour crude oils, including Canadian bitumen blends, which have traded at a significant discount to light sweet crude oil, and increased the refinery’s total crude oil refining capacity by approximately 14 thousand barrels per calendar day (“mbpcd”) to 120 mbpcd.

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We plan to evaluate projects that will extract additional value from this major investment at Detroit. At our Garyville, Louisiana refinery, we have initiated projects that we expect will increase our ultra-low-sulfur diesel (“ULSD”) production and expand our gasoline and distillates export capabilities. We also have projects underway at our Robinson, Illinois refinery to increase distillate yields and at our Catlettsburg, Kentucky refinery to improve gas oil recovery and reduce purchased feedstock volumes, thus reducing our feedstock costs. We are also increasing our capacity to process condensate from the Utica Shale region at our Canton, Ohio and Catlettsburg refineries.

Acquisition of Galveston Bay Refinery and Related Assets

Through our February 1, 2013 acquisition of the Galveston Bay Refinery and Related Assets, we added 451 mbpcd of crude oil refining capacity and have diversified and further balanced our network of refining assets. Our refining capacity is now balanced between three market areas, with 646 mbpcd of capacity in the Midwest, 531 mbpcd in Texas and 522 mbpcd in Louisiana. This acquisition provides us with the opportunity to capture synergies across our existing Gulf Coast operations, increases our refining capacity for specialty chemicals and is anticipated to enhance our ability to sell refined products into export markets.

Extensive Midstream Distribution Networks

We believe the relative scale of our transportation and distribution assets and operations distinguishes us from other refining and marketing companies. We currently own, lease or have ownership interests in approximately 8,300 miles of crude oil and products pipelines, including the approximate 100 miles of natural gas liquid pipelines recently acquired with the Galveston Bay Refinery and Related Assets. Through our ownership interests in MPLX and Pipe Line Holdings, we are one of the largest petroleum pipeline companies in the United States on the basis of total volume delivered. We also own one of the largest private domestic fleets of inland petroleum product barges and one of the largest terminal operations in the United States, as well as trucking and rail assets. We operate this system in coordination with our refining and marketing network, which enables us to optimize feedstock and raw material supplies and refined product distribution, and further allows for important economies of scale across our system.

General Partner and Sponsor of MPLX

Our investment in MPLX provides us an efficient vehicle to invest in organic projects and pursue acquisitions of midstream assets. MPLX’s strong liquidity and borrowing capacity provides us a strong foundation to execute our strategy for growing our midstream logistics business. Our role as the general partner allows us to maintain strategic control of the assets so we can continue to optimize our refinery feedstock and distribution networks.

Competitively Positioned Marketing Operations

We are one of the largest wholesale suppliers of gasoline and distillates to resellers within our market area. We have two strong retail brands: Speedway^® and Marathon^®. We believe our 1,464 Speedway^® convenience stores, which we operate through a wholly owned subsidiary, Speedway LLC, comprise the fourth largest chain of company-owned and operated retail gasoline and convenience stores in the United States. The Marathon brand is an established motor fuel brand in the Midwest and Southeast regions of the United States, and was available through approximately 5,000 retail outlets operated by jobbers and dealers in 17 states as of December 31, 2012. In addition, as part of the acquisition of the Galveston Bay Refinery and Related Assets, we were assigned retail marketing contracts for approximately 1,200 branded retail outlets that we are in the process of converting to the Marathon brand. We believe our distribution system allows us to maximize the sales value of our products and minimize cost.

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Established Track Record of Profitability and Diversified Income Stream

We have demonstrated an ability to achieve positive financial results throughout all stages of the refining cycle. We believe our business mix and strategies position us well to continue to achieve competitive financial results. As shown in the following chart, income from operations attributable to the Speedway and Pipeline Transportation segments is less sensitive to business cycles while our Refining & Marketing segment enables us to generate significant income and cash flow when market conditions are more favorable.

Marathon Petroleum Corporation

Segment Income from Operations

Strong Financial Position

As of December 31, 2012, we had $4.86 billion in cash and cash equivalents and $3.0 billion in unused committed credit facilities, excluding MPLX’s credit facility. We also had $3.36 billion of debt at year-end, which represented only 22 percent of our total capitalization. This combination of strong liquidity and manageable leverage allows us to fund our growth projects and to pursue our business strategies.

Our Business Strategies

Achieve Top-Tier Safety and Environmental Performance

We remain committed to operating our assets in a safe and reliable manner and targeting continuous improvement in our safety record across all of our operations. We have a history of safe and reliable operations, which was demonstrated with record employee and contractor safety performance across all our operations in 2012, including a world class safety record for the heavy oil upgrading and expansion project at our Detroit refinery. In addition, we remain committed to environmental stewardship by continuing to improve the efficiency of our operations while proactively meeting our regulatory requirements.

Grow Enterprise Value

We intend to grow our share price through a combination of earnings growth and return of capital to shareholders in the form of strong and growing dividends and sustained share repurchases. We have increased our quarterly dividend by 75 percent since becoming a stand-alone company in June 2011 and our board of directors has authorized share repurchases totaling $4.0 billion. We entered into two accelerated share repurchase (“ASR”) programs for a total of $1.35 billion, through which we repurchased approximately 8 percent of our outstanding common shares in 2012. After the effects of these ASR programs, $2.65 billion of the $4.0 billion total authorization is available for future repurchases.

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Expand Midstream Business through MPLX

We expect there will be significant investment in infrastructure to connect growing North American crude oil production with existing refining assets and to move refined products to wholesale and retail marketing customers. We intend to aggressively participate in this infrastructure build out and MPLX will be the entity through which we expect to grow our midstream business. We intend to increase revenue on the MPLX network of pipeline systems through higher utilization of existing assets, by capitalizing on organic investment opportunities that may arise from the growth of MPC’s operations and from increased third-party activity in MPLX’s areas of operations. Through MPLX, we also plan to pursue acquisitions of midstream assets both within our existing geographic footprint and in new areas.

Deliver Top Quartile Refining Performance

Our refineries are well positioned to benefit from the growing crude oil and condensate production in North America, including the Bakken, Eagle Ford and Utica Shale regions, along with the Canadian oil sands. We are also well positioned to export distillates and other products as the demand continues to grow.

We intend to increase our earnings in the Refining & Marketing segment through organic investments and selective acquisitions, while maintaining financial discipline. For example, we recently completed a $2.2 billion investment (excluding capitalized interest) to upgrade and expand our Detroit refinery. This investment significantly expands our ability to process heavy crude oil at the Detroit refinery from about 20 mbpcd to 100 mbpcd. In February 2013, we closed on the 451 mbpcd Galveston Bay refinery. This acquisition increases our crude oil refining capacity by approximately 36 percent, diversifies the footprint of our refining assets, provides us with the opportunity to increase our export sales, and significantly increases our participation in the chemicals value chain. We will continue to evaluate opportunities to expand our existing asset base, with an emphasis on increasing distillates production and export capabilities.

Increase Assured Sales Volumes at our Marathon Brand and Speedway Locations

We consider assured sales as those sales we make to Marathon brand customers, our Speedway operations and to our wholesale customers with whom we have required minimum volume sales contracts. We believe having assured sales brings ratability to our distribution systems, provides a solid base to enhance our overall supply reliability and allows us to efficiently and effectively optimize our operations between our refineries, our pipelines and our terminals. The Marathon brand has been a consistent vehicle for sales volume growth in existing and contiguous markets. The acquisition of the Galveston Bay Refinery and Related Assets provides us with opportunities to further expand our market presence. Through the assignment of branded-jobber contracts representing approximately 1,200 retail outlets, we are in position to take advantage of opportunities with premier Southeast jobbers and to significantly expand our brand presence in the Southeast. We also intend to grow Speedway gasoline and distillates sales volumes through internal capital program growth projects and acquisitions that complement our existing store network.

Deliver Profitable Speedway Growth

We intend to grow Speedway’s sales and profitability by focusing on continuous improvement of existing operations, organic growth and strategic store acquisition opportunities. For example, the acquisition of 97 convenience stores in 2012 has increased Speedway’s presence in the Midwest. In addition, our industry-leading Speedy Rewards^® customer loyalty program, which has over three million members, provides us with a unique competitive advantage and opportunity to increase our Speedway customer base with existing and new Speedway locations.

Utilize and Expand our High Quality Employee Workforce

We plan to utilize our high quality employee workforce by continuing to leverage our commercial skills. In addition, we plan to expand our workforce through selective hiring practices and effective training programs on safety, environmental stewardship and other professional and technical skills.

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The above discussion contains forward-looking statements with respect to our competitive strengths and business strategies, including our share repurchase program and pursuing potential acquisitions. There can be no assurance that we will be successful, in whole or in part, in pursuing our business strategies, including our share repurchase program or pursuing potential acquisitions. Factors that could affect the share repurchase program and its timing include, but are not limited to, business conditions, availability of liquidity and the market price of our common stock. Factors that could affect pursuing potential acquisitions include, but are not limited to, our ability to implement and realize the benefits and synergies of our strategic initiatives, availability of liquidity, actions taken by competitors, regulatory approvals and operating performance. These factors, among others, could cause actual results to differ materially from those set forth in the forward-looking statements. For additional information on forward-looking statements and risks that can affect our business, see “Disclosures Regarding Forward-Looking Statements” and Item 1A. Risk Factors in this Annual Report on Form 10-K.

Refining & Marketing

Refineries

As of December 31, 2012, we owned and operated six refineries in the Gulf Coast and Midwest regions of the United States with an aggregate crude oil refining capacity of approximately 1.25 mmbpcd. The acquisition of the Galveston Bay refinery on February 1, 2013 increased our crude oil refining capacity to approximately 1.7 mmbpcd. During 2012, our refineries processed 1,195 thousand barrels per day (“mbpd”) of crude oil and 168 mbpd of other charge and blendstocks. During 2011, our refineries processed 1,177 mbpd of crude oil and 181 mbpd of other charge and blendstocks. The table below sets forth the location, crude oil refining capacity, tank storage capacity and number of tanks for each of our refineries as of December 31, 2012.

Refinery	Crude Oil Refining   Capacity (mbpcd) (a)		Tank Shell Capacity (million barrels)		Number of Tanks
Garyville, Louisiana		522		16		75
Catlettsburg, Kentucky		240		6		112
Robinson, Illinois		206		6		103
Detroit, Michigan		120		6		86
Canton, Ohio		80		3		73
Texas City, Texas		80		5		60
Total		1,248		42		509

^(a)  Refining throughput can exceed crude oil capacity due to the processing of other feedstocks in addition to crude oil and the timing of planned turnaround and major maintenance activity.

Our refineries include crude oil atmospheric and vacuum distillation, fluid catalytic cracking, catalytic reforming, desulfurization and sulfur recovery units. The refineries process a wide variety of crude oils and produce numerous refined products, ranging from transportation fuels, such as reformulated gasolines, blend-grade gasolines intended for blending with fuel ethanol and ULSD fuel, to heavy fuel oil and asphalt. Additionally, we manufacture aromatics, propane, propylene, cumene and sulfur. Our refineries are integrated with each other via pipelines, terminals and barges to maximize operating efficiency. The transportation links that connect our refineries allow the movement of intermediate products between refineries to optimize operations, produce higher margin products and utilize our processing capacity efficiently. For example, naphtha may be moved from Texas City to Robinson where excess reforming capacity is available. Also, by shipping intermediate products between facilities during partial refinery shutdowns, we are able to utilize processing capacity that is not directly affected by the shutdown work.

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

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

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

Detroit, Michigan Refinery. Our Detroit, Michigan refinery is located in southwest Detroit. It is the only petroleum refinery currently operating in Michigan. The Detroit refinery processes light sweet and heavy sour crude oils, including Canadian crude oils, into products such as gasoline, distillates, asphalt, propylene, propane, slurry and fuel-grade coke. Our Detroit refinery earned designation as a Michigan VPP Star site in 2010. In the fourth quarter of 2012, we completed a heavy oil upgrading and expansion project that enables the refinery to process up to an additional 80 mbpd of heavy sour crude oils, including Canadian bitumen blends, and increased its total crude oil refining capacity by approximately 14 mbpcd, to 120 mbpcd.

Canton, Ohio Refinery. Our Canton, Ohio refinery is located approximately 60 miles south of Cleveland, Ohio. The Canton refinery processes sweet and sour crude oils into products such as gasoline, distillates, asphalt, roofing flux, propane and slurry.

Texas City, Texas Refinery. Our Texas City, Texas refinery is located on the Texas Gulf Coast approximately 30 miles southeast of Houston, Texas. The refinery processes light sweet crude oil into products such as gasoline, chemical grade propylene, propane, slurry and aromatics. Our Texas City refinery earned designation as an OSHA VPP Star site in 2012.

As of December 31, 2012, our refineries had 24 rail loading racks and 23 truck loading racks and three of our refineries had a total of seven owned and four non-owned docks. Total throughput in 2012 was 75 mbpd for the refinery loading racks and 499 mbpd for the refinery docks.

Planned maintenance activities, or turnarounds, requiring temporary shutdown of certain refinery operating units, are periodically performed at each refinery. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional detail.

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Refined Product Yields

The following table sets forth our refinery production (including the St. Paul Park refinery until December 1, 2010) by product group for each of the last three years.

Refined Product Yields (mbpd)	2012		2011		2010
Gasoline		738		739		726
Distillates		433		433		409
Propane		26		25		24
Feedstocks and special products		109		109		97
Heavy fuel oil		18		21		24
Asphalt		62		56		76
Total		1,386		1,383		1,356

Crude Oil Supply

We obtain the crude oil we refine through negotiated contracts and purchases or exchanges on the spot market. Our crude oil supply contracts are generally term contracts with market-related pricing provisions. The following table provides information on our sources of crude oil for each of the last three years (including the St. Paul Park refinery until December 1, 2010). The crude oil sourced outside of North America was acquired from various foreign national oil companies, production companies and trading companies.

Sources of Crude Oil Refined (mbpd)	2012		2011		2010
United States		649		668		720
Canada		195		177		115
Middle East and other international		351		332		338
Total		1,195		1,177		1,173
Average cost of crude oil throughput (dollars per barrel)		$    102.53		$    102.83		$    78.57

Our refineries receive crude oil and other feedstocks and distribute our refined products through a variety of channels, including pipelines, trucks, railcars, ships and barges. During 2012, we began transporting crude oil by truck from the Utica Shale region to our Canton refinery. As of December 31, 2012, we owned four transport trucks and seven trailers for this purpose.

Refined Product Marketing

We believe we are one of the largest wholesale suppliers of gasoline and distillates to resellers and consumers within our 17-state market area in the Midwest, Gulf Coast and Southeast regions of the United States. Independent retailers, wholesale customers, our Marathon brand jobbers and Speedway brand convenience stores, airlines, transportation companies and utilities comprise the core of our customer base. In addition, we sell distillates, asphalt and gasoline for export to international customers, primarily out of our Garyville refinery. Sales destined for export comprised approximately 25 percent of our distillate sales and 13 percent of our asphalt sales in 2012.

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The following table sets forth, as a percentage of total refined product sales volume, the sales of refined products to our different customer types for the past three years (including the Minnesota Assets until December 1, 2010).

Refined Product Sales by Customer Type	2012		2011		2010
Private-brand marketers, commercial and industrial customers, including spot market		72%		72%		70%
Marathon-branded dealers and jobbers		17%		17%		17%
Speedway® convenience stores		11%		11%		13%

The following table sets forth the approximate number of retail outlets (by state) where dealers and jobbers maintain Marathon-branded retail outlets, as of December 31, 2012.

State	Approximate Number of Marathon® Retail Outlets
Alabama		139
Florida		259
Georgia		256
Illinois		395
Indiana		647
Kentucky		576
Maryland		1
Michigan		778
Minnesota		84
North Carolina		311
Ohio		860
Pennsylvania		40
South Carolina		128
Tennessee		173
Virginia		136
West Virginia		111
Wisconsin		70
Total		4,964

The following table sets forth our refined products sales volumes by product group and our average sales price for each of the last three years (including the Minnesota Assets until December 1, 2010).

Refined Product Sales (mbpd)	2012		2011		2010
Gasoline		916		908		912
Distillates		463		459		434
Propane		27		25		24
Feedstocks and special products		112		111		103
Heavy fuel oil		19		19		23
Asphalt		62		59		77
Total		1,599		1,581		1,573
Average sales price, including consumer excise taxes (dollars per barrel)		$    126.13		$    123.14		$    94.13

Gasoline and Distillates. We sell gasoline, gasoline blendstocks and distillates (including No. 1 and No. 2 fuel oils, kerosene, jet fuel and diesel fuel) to wholesale customers, Marathon-branded jobbers and dealers and our

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Speedway^® convenience stores in the Midwest, Gulf Coast and Southeast regions of the United States and on the spot market. In addition, we sell diesel fuel for export to international customers. We sold 57 percent of our gasoline sales volumes and 89 percent of our distillates sales volumes on a wholesale or spot market basis in 2012. The demand for gasoline and distillates is seasonal in many of our markets, with demand typically at its highest levels during the summer months.

We have blended ethanol into gasoline for more than 20 years and began expanding our blending program in 2007, in part due to federal regulations that require us to use specified volumes of renewable fuels. Ethanol volumes sold in blended gasoline (including the Minnesota Assets until December 1, 2010) were 68 mbpd in 2012, 70 mbpd in 2011 and 68 mbpd in 2010. The future expansion or contraction of our ethanol blending program will be driven by the economics of the ethanol supply and by government regulations. We sell reformulated gasoline, which is also blended with ethanol, in parts of our marketing territory, including Kentucky, Illinois, Indiana, Wisconsin, Pennsylvania and Texas. We also sell biodiesel-blended diesel fuel in Kentucky, West Virginia, Illinois, Ohio, North Carolina, Florida, Virginia, Pennsylvania, Georgia, Minnesota and Tennessee.

We hold a 36 percent interest in an entity that owns and operates a 110-million-gallon-per-year ethanol production facility in Clymers, Indiana. We also own a 50 percent interest in an entity that owns a 110-million-gallon-per-year ethanol production facility in Greenville, Ohio. Both of these facilities are managed by a co-owner.

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

Feedstocks and Special Products. We are a producer and marketer of feedstocks and specialty products. Product availability varies by refinery and includes propylene, cumene, molten sulfur, toluene, benzene, xylene and dilute naphthalene oil. We market all products domestically to customers in the chemical, agricultural and fuel blending industries. In addition, we produce fuel-grade coke at our Garyville and Detroit refineries, which is used for power generation and in miscellaneous industrial applications, and anode-grade coke at our Robinson refinery, which is used to make carbon anodes for the aluminum smelting industry.

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

Asphalt. We have refinery-based asphalt production capacity of up to 98 mbpcd. We market asphalt through 31 owned or leased terminals throughout the Midwest and Southeast. We have a broad customer base, including asphalt-paving contractors, government entities (states, counties, cities and townships) and asphalt roofing shingle manufacturers. We sell asphalt in the domestic and export wholesale markets via rail, barge and vessel. We also produce asphalt cements, polymer modified asphalt, emulsified asphalt and industrial asphalts.

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Refined Product Distribution

As of December 31, 2012, we owned and operated 61 light product and 21 asphalt terminals. The acquisition of the Galveston Bay Refinery and Related Assets on February 1, 2013 increased our number of owned and operated light product terminals to 65. Our light product and asphalt terminals averaged 1,278 mbpd and 31 mbpd of throughput in 2012, respectively. In addition, we distribute refined products through one leased light product terminal, two light product terminals in which we have partial ownership interests but do not operate and approximately 61 third-party light product and 10 third-party asphalt terminals in our market area. The following table sets forth additional details about our owned and operated terminals at December 31, 2012.

Owned and Operated Terminals	Number of Terminals		Tank Shell Capacity (thousand barrels)		Number of Tanks		Number of Loading Lanes
Light Product Terminals:
Alabama		2		404		20		4
Florida		3		1,942		54		17
Georgia		4		896		38		9
Illinois		4		1,165		45		14
Indiana		7		3,021		79		19
Kentucky		6		2,266		64		24
Louisiana		1		89		8		2
Michigan		9		2,191		85		28
North Carolina		2		451		17		6
Ohio		13		4,114		164		33
Pennsylvania		1		336		10		2
South Carolina		1		344		13		3
Tennessee		3		727		29		9
Virginia		1		276		12		2
West Virginia		2		149		10		2
Wisconsin		2		814		20		7
Subtotal light product terminals		61		19,185		668		181
Asphalt Terminals:
Florida		1		254		4		3
Illinois		2		100		9		6
Indiana		3		703		18		9
Kentucky		4		567		34		14
Louisiana		1		52		8		2
Michigan		1		12		2		8
New York		1		112		3		3
Ohio		4		1,919		46		10
Pennsylvania		1		469		14		8
Tennessee		3		951		34		12
Subtotal asphalt terminals		21		5,139		172		75
Total owned and operated terminals		82		24,324		840		256

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As of December 31, 2012, our marine transportation operations included 15 towboats, as well as 177 owned and 14 leased barges that transport refined products on the Ohio, Mississippi and Illinois rivers and their tributaries and inter-coastal waterways. The following table sets forth additional details about our towboats and barges.

Class of Equipment	Number in Class		Capacity (thousand barrels)
Inland tank barges:(a)
Less than 25,000 barrels		61		858
25,000 barrels and over		130		3,784
Total		191		4,642
Inland towboats:
Less than 2000 horsepower		2
2000 horsepower and over		13
Total		15

^(a)  All of our barges are double-hulled.

As of December 31, 2012, we owned 142 transport trucks and 150 trailers with an aggregate capacity of 1.4 million gallons for the movement of refined products. In addition, we had 1,944 leased and 27 owned railcars of various sizes and capacities for movement and storage of refined products. The following table sets forth additional details about our railcars.

	Number of Railcars
Class of Equipment	Owned		Leased		Total		Capacity per Railcar
General service tank cars		-		694		694		20,000-30,000 gallons
High pressure tank cars		-		1,041		1,041		33,500 gallons
Open-top hoppers		27		209		236		4,000 cubic feet
		27		1,944		1,971

Galveston Bay Refinery and Related Assets

Our Galveston Bay refinery, which we acquired on February 1, 2013, is located on the Texas Gulf Coast approximately 30 miles southeast of Houston, Texas. The refinery has a crude oil refining capacity of 451 mbpcd and storage tank shell capacity of approximately 16 million barrels. The refinery can process almost any grade of crude oil into products such as gasoline, distillates, fuel-grade coke, slurry, propylene, propane and aromatics. Our cogeneration facility, which supplies the Galveston Bay refinery, has 1,040 megawatts of electrical production capacity and can produce 4.6 million pounds of steam per hour.

The four light product terminals we acquired are located in Nashville, Tennessee; Charlotte, North Carolina; Selma, North Carolina and Jacksonville, Florida. The terminals have 42 storage tanks with aggregate shell capacity of 2.27 million barrels and 19 loading lanes.

The assignment of branded-jobber contracts represents approximately 1,200 retail outlets, primarily in Florida, Mississippi, Tennessee and Alabama.

Speedway

Our Speedway segment sells gasoline and merchandise through convenience stores that it owns and operates, primarily under the Speedway brand. Diesel fuel is also sold at the vast majority of these convenience stores. Speedway brand convenience stores offer a wide variety of merchandise, such as prepared foods, beverages and non-food items, including a number of private-label items. Speedy Rewards™, an industry-leading customer loyalty program, has achieved significant customer engagement over the years since its introduction in 2004. The average monthly active membership in 2012 was more than three million customers.

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As of December 31, 2012, Speedway had 1,464 convenience stores in seven states. Revenues from sales of merchandise (including sales until December 1, 2010 from convenience stores we sold as part of the Minnesota Assets) totaled $3.06 billion in 2012, $2.92 billion in 2011 and $3.20 billion in 2010. The demand for gasoline is seasonal, with the highest demand usually occurring during the summer driving season. Margins from the sale of merchandise tend to be less volatile than margins from the retail sale of gasoline and diesel fuel.

As of December 31, 2012, the Speedway segment’s convenience stores were located in the following states:

State	Number of Convenience Stores
Illinois		107
Indiana		310
Kentucky		140
Michigan		301
Ohio		483
West Virginia		60
Wisconsin		63
Total		1,464

Harris Interactive’s annual Harris Poll EquiTrend^® brand equity study named Speedway the number one convenience store brand with consumers nationally for 2012 and the number one gasoline brand with consumers for each of the prior three years. For 2011, Speedway was presented with a Convenience Retailing Award from CSP Information Group, Inc., for consumer experience provided by the Speedy Rewards™ program.

Pipeline Transportation

As of December 31, 2012, we owned, leased or had ownership interests in approximately 8,200 miles of crude oil and products pipelines, of which approximately 2,900 miles are owned through our investments in MPLX and Pipe Line Holdings. The acquisition of approximately 100 miles of natural gas liquid pipelines on February 1, 2013 increased the total mile count to approximately 8,300 miles.

MPLX

In 2012, we formed MPLX, a master limited partnership, to own, operate, develop and acquire pipelines and other midstream assets related to the transportation and storage of crude oil, refined products and other hydrocarbon-based products. On October 31, 2012, MPLX completed its initial public offering. We own a 73.6 percent interest in MPLX, including the general partner interest. MPLX’s assets consist of a 51 percent general partner interest in Pipe Line Holdings, which owns common carrier pipeline systems through Marathon Pipe Line LLC (“MPL”) and Ohio River Pipe Line LLC (“ORPL”), and a 100 percent interest in a one million barrel butane storage cavern in West Virginia. In addition, we own the remaining 49 percent limited partner interest in Pipe Line Holdings. As of December 31, 2012, Pipe Line Holdings, through MPL and ORPL, owned or leased and operated 1,004 miles of common carrier crude oil lines and 1,902 miles of common carrier products lines comprising 30 systems located in nine states and four tank farms in Illinois and Indiana with available storage capacity of 3.29 million barrels that is committed to MPC.

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The table below sets forth additional detail regarding the pipeline systems and storage assets we own through Pipe Line Holdings and MPLX as of December 31, 2012.

Pipeline System or Storage Asset	Origin	Destination	Diameter (inches)	Length (miles)		Capacity (a)		Associated MPC refinery
Crude oil pipeline systems (mbpd):
Patoka, IL to Lima, OH crude system	Patoka, IL	Lima, OH	20”-22”		302		290	Detroit, Canton
Catlettsburg, KY and Robinson, IL crude system	Patoka, IL	Catlettsburg, KY & Robinson, IL	20”-24”		484		481	Catlettsburg, Robinson
Detroit, MI crude system (b)	Samaria & Romulus, MI	Detroit, MI	16”		61		320	Detroit
Wood River, IL to Patoka, IL crude system (b)	Wood River & Roxana, IL	Patoka, IL	12”-22”		115		307	All Midwest refineries
Inactive pipelines					42		N/A
Total					1,004		1,398
Products pipeline systems (mbpd):
Garyville, LA products system	Garyville, LA	Zachary, LA	20”-36”		72		389	Garyville
Texas City, TX products system	Texas City, TX	Pasadena, TX	16”-36”		42		215	Texas City
ORPL products system	Various	Various	6”-14”		518		242	Catlettsburg, Canton
Robinson, IL products system (b)	Various	Various	10”-16”		1,173		545	Robinson
Louisville, KY Airport products system	Louisville, KY	Louisville, KY	6”-8”		14		29	Robinson
Inactive pipelines					83		N/A
Total					1,902		1,420
Wood River, IL barge dock (mbpd)							80	Garyville
Storage assets (thousand barrels):
Neal, WV butane cavern (c)							1,000	Catlettsburg
Patoka, IL tank farm							1,386	All Midwest refineries
Wood River, IL tank farm							419	All Midwest refineries
Martinsville, IL tank farm							738	Detroit, Canton
Lebanon, IN tank farm							750	Detroit, Canton
Total							4,293

^(a)  All capacities reflect 100 percent of the pipeline systems’ and barge dock’s average capacity in thousands of barrels per day and 100 percent of the available storage capacity of our butane cavern and tank farms in thousand of barrels. Crude oil capacity is based on light crude oil barrels.

^(b)  Includes pipelines leased from third parties.

^(c)  The Neal, WV butane cavern is 100 percent owned by MPLX.

The Pipe Line Holdings common carrier pipeline network is one of the largest petroleum pipeline systems in the United States, based on total volume delivered. Third parties generated 14 percent of the crude oil and refined product shipments on these common carrier pipelines in 2012, excluding volumes shipped by MPC under joint tariffs with third parties. These common carrier pipelines transported the volumes shown in the following table for each of the last three years.

Pipeline Throughput (mbpd) (a)(b)	2012		2011		2010
Crude oil pipelines		1,029		993		883
Refined products pipelines		980		1,031		968
Total		2,009		2,024		1,851

^(a)  MPLX volumes reported in MPLX’s prospectus related to its initial public offering included our undivided joint interest crude oil pipeline systems, which were not contributed to MPLX. The undivided joint interest volumes are not included above.

^(b)  Volumes represent 100 percent of the throughput through these pipelines.

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MPC-Retained Assets and Investments

In addition to our 49% ownership interest in Pipe Line Holdings, we retained ownership interests in several crude oil and products pipeline systems and pipeline companies. As of December 31, 2012, we owned undivided joint interests in the following common carrier crude oil pipeline systems.

Pipeline System	Origin	Destination	Diameter (inches)	Length (miles)		Ownership Interest			Operated by MPL
Capline	St. James, LA	Patoka, IL	40”		635		33	%	No
Maumee	Lima, OH	Samaria, MI	22”		95		26	%	No
Total					730

MPC consolidated volumes transported through our common carrier pipelines, which include MPLX and our undivided joint interests, are shown in the following table for each of the last three years.

MPC Consolidated Pipeline Throughput (mbpd)	2012		2011		2010
Crude oil pipelines		1,190		1,184		1,204
Refined products pipelines		980		1,031		968
Total		2,170		2,215		2,172

As of December 31, 2012, we had partial ownership interests in the following pipeline companies.

Pipeline Company	Origin	Destination	Diameter (inches)	Length (miles)		Ownership Interest			Operated by MPL
Crude oil pipeline companies:
LOCAP LLC	Clovelly, LA	St. James, LA	48”		57		59	%	No
LOOP LLC	Offshore Gulf of Mexico	Clovelly, LA	48”		48		51	%	No
Total					105
Products pipeline companies:
Centennial Pipeline LLC (a)	Beaumont, TX	Bourbon, IL	24”-26”		795		50	%	Yes
Explorer Pipeline Company	Lake Charles, LA	Hammond, IN	12”-28”		1,883		17	%	No
Muskegon Pipeline LLC	Griffith, IN	Muskegon, MI	10”		170		60	%	Yes
Wolverine Pipe Line Company	Chicago, IL	Bay City & Ferrysburg, MI	6”-18”		743		6	%	No
Total					3,591

^(a)  Includes 48 miles of inactive pipeline.

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We also own 183 miles of private crude oil pipelines and 658 miles of private refined products pipelines that are operated by MPL for the benefit of our Refining & Marketing segment on a cost recovery basis. The following table provides additional information on these assets.

Private Pipeline Systems	Diameter (inches)	Length (miles)		Capacity (mbpd)
Crude oil pipeline systems:
Lima, OH to Canton, OH	12”-16”		153		84
St. James, LA to Garyville, LA	30”		20		620
Other			2		15
Inactive pipelines			8		N/A
Total			183		719
Products pipeline systems:
Robinson, IL to Lima, OH	8”		250		18
Louisville, KY to Lexington, KY (a)	8”		87		37
Woodhaven, MI to Detroit, MI	4”		26		11
Illinois pipeline systems	4”-8”		118		32
Ohio pipeline systems	4”-6”		61		39
Inactive pipelines			116		N/A
Total			658		137

^(a)  We own a 65 percent undivided joint interest in the Louisville, KY to Lexington, KY system.

As of December 31, 2012, we owned 60 private tanks with storage capacity of approximately 6.5 million barrels, which are located along MPLX pipelines.

Galveston Bay Refinery and Related Assets

As part of the February 1, 2013 acquisition of the Galveston Bay Refinery and Related Assets, we acquired approximately 100 miles of natural gas liquid pipelines consisting of three intrastate systems originating at the Galveston Bay refinery. The pipelines are each eight inches in diameter and have a total capacity of approximately 40 mbpd.

Competition, Market Conditions and Seasonality

The downstream petroleum business is highly competitive, particularly with regard to accessing crude oil and other feedstock supply and the marketing of refined products. We compete with a large number of other companies to acquire crude oil for refinery processing and in the distribution and marketing of a full array of petroleum products. Based upon the “The Oil & Gas Journal 2012 Worldwide Refinery Survey” and our acquisition of the Galveston Bay refinery on February 1, 2013, we ranked fourth among U.S. petroleum companies on the basis of U.S. crude oil refining capacity as of February 1, 2013. We compete in four distinct markets for the sale of refined products—wholesale, spot, branded and retail distribution. We believe we compete with about 60 companies in the sale of refined products to wholesale marketing customers, including private-brand marketers and large commercial and industrial consumers; about 80 companies in the sale of refined products in the spot market; 11 refiners or marketers in the supply of refined products to refiner-branded dealers and jobbers; and approximately 250 retailers in the retail sale of refined products. In addition, we compete with producers and marketers in other industries that supply alternative forms of energy and fuels to satisfy the requirements of our industrial, commercial and individual consumers. We do not produce any of the crude oil we refine.

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We also face strong competition for sales of retail gasoline, diesel fuel and merchandise. Our competitors include service stations and convenience stores operated by fully integrated major oil companies and their dealers and jobbers and other well-recognized national or regional convenience stores and travel centers, often selling gasoline, diesel fuel and merchandise at aggressively competitive prices. Non-traditional retailers, such as supermarkets, club stores and mass merchants, have affected the convenience store industry with their entrance into the retail transportation fuel business. Energy Analysts International, Inc. estimates such retailers had 12.4 percent of the U.S. gasoline market in 2012.

Our pipeline transportation operations are highly regulated, which affects the rates that our common carrier pipelines can charge for transportation services and the return we obtain from such pipelines.

Market conditions in the oil and gas industry are cyclical and subject to global economic and political events and new and changing governmental regulations. Our operating results are affected by price changes in crude oil, natural gas and refined products, as well as changes in competitive conditions in the markets we serve. Price differentials between sweet and sour crude oil also affect our operating results.

Demand for gasoline, diesel fuel and asphalt is higher during the spring and summer months than during the winter months in most of our markets, primarily due to seasonal increases in highway traffic and construction. As a result, the operating results for each of our segments for the first and fourth quarters are generally lower than for those in the second and third quarters of each calendar year.

Environmental Matters

Our management is responsible for ensuring that our operating organizations maintain environmental compliance systems that support and foster our compliance with applicable laws and regulations, and for reviewing our overall performance associated with various environmental compliance programs. We also have a Corporate Emergency Response Team, composed primarily of senior management, which oversees our response to any major environmental or other emergency incident involving us or any of our facilities.

We believe it is likely that the scientific and political attention to issues concerning the extent and causes of climate change will continue, with the potential for further regulations that could affect our operations. Currently, various legislative and regulatory measures to address greenhouse gases are in various phases of review, discussion or implementation. The cost to comply with these laws and regulations cannot be estimated at this time, but could be significant. For additional information, see Item 1A. Risk Factors. We estimate and publicly report greenhouse gas emissions from our operations and products we produce. Additionally, we continuously strive to improve operational and energy efficiencies through resource and energy conservation where practicable and cost effective.

Our operations are also subject to numerous other laws and regulations relating to the protection of the environment. These environmental laws and regulations include, among others, the Clean Air Act with respect to air emissions, the Clean Water Act with respect to water discharges, the Resource Conservation and Recovery Act (“RCRA”) with respect to solid and hazardous waste treatment, storage and disposal, the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) with respect to releases and remediation of hazardous substances and the Oil Pollution Act of 1990 (“OPA-90”) with respect to oil pollution and response. In addition, many states where we operate have similar laws. New laws are being enacted and regulations are being adopted by various regulatory agencies on a continuing basis, and the costs of compliance with any new laws and regulations are very difficult to estimate at this time.

For a discussion of environmental capital expenditures and costs of compliance for air, water, solid waste and remediation, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Environmental Matters and Compliance Costs.

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Air

We are subject to substantial requirements in connection with air emissions from our operations. The U.S. Environmental Protection Agency (“EPA”) issued an “endangerment finding” in 2009 that greenhouse gas emissions contribute to air pollution that endangers public health and welfare. Related to this endangerment finding, in April 2010, the EPA finalized a greenhouse gas emissions standard for mobile sources (cars and light duty vehicles). The endangerment finding along with the mobile source standard and the EPA’s determination that greenhouse gases are subject to regulation under the Clean Air Act, and the EPA’s so-called “tailoring rule” led to permitting of larger stationary sources of greenhouse gas emissions, including refineries. Legal challenges filed against these EPA actions were overruled by the D.C. Circuit Court of Appeals, but several parties will seek further review by the U.S. Supreme Court. We also expect refinery-specific New Source Performance Standards will be proposed in 2013. Congress may again consider legislation on greenhouse gas emissions or a carbon tax. Private parties have sued utilities and other emitters of greenhouse gas emissions, but we have not been named in any of those lawsuits. Private-party litigation is also pending against federal and certain state governmental entities seeking additional greenhouse gas emission reductions beyond those currently being undertaken. Although there may be an adverse financial impact (including compliance costs, potential permitting delays and potential reduced demand for certain refined products made from crude oil) associated with any legislation, regulation, litigation or other action, the extent and magnitude of that impact cannot be reasonably estimated due to the uncertainty regarding the additional measures and how they will be implemented.

Of particular significance to our refining operations were EPA Mobile Source Air Toxics II (“MSAT II”) regulations that require reduced benzene levels in refined products. We spent approximately $620 million over a four-year period to complete all MSAT II projects, and all units were in operation as of December 31, 2011.

The EPA has reviewed and has revised or will propose to revise the National Ambient Air Quality Standards (“NAAQS”) for criteria air pollutants. The NAAQS are subject to multiple court challenges, making final compliance plans uncertain. The EPA promulgated a revised ozone standard in March 2008 and commenced a multi-year process to develop the implementing rules required by the Clean Air Act. In 2013, the EPA is expected to propose a stricter ozone standard as part of EPA’s periodic review of that standard. Also, in 2010, the EPA adopted new short-term standards for nitrogen dioxide and sulfur dioxide, and in December 2012 issued a more stringent fine particulate matter (PM 2.5) standard. We cannot reasonably estimate the final financial impact of these proposed and revised NAAQS standards until the standards are finalized, individual state implementing rules are established and judicial challenges are resolved.

In December 2012, the EPA signed final reconsideration amendments to the Boiler and Process Heater Maximum Achievable Control Technology (“Boiler MACT”) rule. This rule had been finalized in March 2011 with work practice standards that are applicable to refinery and natural gas fired equipment. While EPA retained the work practice standards for most refinery equipment, we are currently evaluating the financial impact of the Boiler MACT rule as a result of the reconsideration amendments. Further changes to the rule may occur because of potential litigation.

In 2013, the EPA is expected to propose a Refinery Sector Rule. This rule may require various refinery unit modifications, additional controls, lower emission standards and ambient air monitoring. We cannot reasonably estimate the financial impact of this rule until it is proposed and finalized.

Water

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

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provides for civil penalties and imposes criminal sanctions for violations of its provisions. We have implemented emergency oil response plans for all of our components and facilities covered by OPA-90 and we have established Spill Prevention, Control and Countermeasures plans for all facilities subject to such requirements.

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

Solid Waste

We continue to seek methods to minimize the generation of hazardous wastes in our operations. RCRA establishes standards for the management of solid and hazardous wastes. Besides affecting waste disposal practices, RCRA also addresses the environmental effects of certain past waste disposal operations, the recycling of wastes and the regulation of underground storage tanks (“USTs”) containing regulated substances. We have ongoing RCRA treatment and disposal operations at one of our facilities and primarily utilize offsite third-party treatment and disposal facilities. Ongoing RCRA-related costs, however, are not expected to be material to our results of operations or cash flows.

Remediation

We own or operate, or have owned or operated, certain retail outlets where, during the normal course of operations, releases of refined products from USTs have occurred. Federal and state laws require that contamination caused by such releases at these sites be assessed and remediated to meet applicable standards. The enforcement of the UST regulations under RCRA has been delegated to the states, which administer their own UST programs. Our obligation to remediate such contamination varies, depending on the extent of the releases and the stringency of the laws and regulations of the states in which we operate. A portion of these remediation costs may be recoverable from the appropriate state UST reimbursement funds once the applicable deductibles have been satisfied. We also have ongoing remediation projects at a number of our current and former refinery, terminal and pipeline locations. Penalties or other sanctions may be imposed for noncompliance.

Claims under CERCLA and similar state acts have been raised with respect to the clean-up of various waste disposal and other sites. CERCLA is intended to facilitate the clean-up of hazardous substances without regard to fault. Potentially responsible parties for each site include present and former owners and operators of, transporters to and generators of the hazardous substances at the site. Liability is strict and can be joint and several. Because of various factors including the difficulty of identifying the responsible parties for any particular site, the complexity of determining the relative liability among them, the uncertainty as to the most desirable remediation techniques and the amount of damages and clean-up costs and the time period during which such costs may be incurred, we are unable to reasonably estimate our ultimate cost of compliance with CERCLA; however, we do not believe such costs will be material to our business, financial condition, results of operations or cash flows.

Mileage Standards, Renewable Fuels and Other Fuels Requirements

In 2007, the U.S. Congress passed the Energy Independence and Security Act (“EISA”), which, among other things, set a target of 35 miles per gallon for the combined fleet of cars and light trucks in the United States by model year 2020, and contains a second Renewable Fuel Standard (the “RFS2”). In August 2012, the EPA and the National Highway Traffic Safety Administration jointly adopted regulations that establish average industry

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fleet fuel economy standards for passenger cars and light trucks of up to 41 miles per gallon by model year 2021 and average fleet fuel economy standards of up to 49.7 miles per gallon by model year 2025 (the standards from 2022 to 2025 are the government’s current estimate but will require further rulemaking).

The RFS2 requires 16.55 billion gallons of renewable fuel usage in 2013, increasing to 36.0 billion gallons by 2022. In the near term, the RFS2 will be satisfied primarily with fuel ethanol blended into gasoline. The RFS2 presents production and logistic challenges for both the renewable fuels and petroleum refining and marketing industries. The RFS2 has required, and may in the future continue to require, additional capital expenditures or expenses by us to accommodate increased renewable fuels use.

Within the overall 36.0 billion gallon RFS2, EISA established an advanced biofuel RFS2 volume of 2.0 billion gallons in 2012 increasing to 21.0 billion gallons in 2022. Subsets within the advanced biofuel RFS2 include biomass-based diesel, which was set at 1.0 billion gallons in 2012 and at least 1.0 billion gallons in 2013 through 2022 (to be determined by the EPA through future rulemaking), and cellulosic biofuel, which was set at 0.5 billion gallons in 2012, 1.0 billion gallons in 2013, increasing to 16.0 billion gallons by 2022. The EPA established the 2013 biomass-based diesel requirement at 1.28 billion gallons. The EPA determined that 0.5 billion gallons of cellulosic biofuel would not be produced in 2012, and lowered the requirement to 8.65 million gallons. The American Petroleum Institute challenged the EPA 2012 cellulosic biofuel requirement and the D.C. Circuit Court of Appeals vacated the requirement finding that it was unlawfully determined and remanded it for further determination.

The advanced biofuels programs will present specific challenges in that we may have to enter into arrangements with other parties or purchase credits from the EPA to meet our obligations to use advanced biofuels, including biomass-based diesel and cellulosic biofuel, with potentially uncertain supplies of these new fuels. The advanced requirement for 2012 required a substantial level of Brazilian sugarcane ethanol imports since other sources of advanced renewable fuels were not available. In 2012, the EPA also discovered that 140 million biodiesel Renewable Identification Numbers (“RINs”) used to meet the annual requirement for that fuel had been fraudulently created and sold to unsuspecting third parties, including us.

We made investments in infrastructure capable of expanding biodiesel blending capability to help comply with the biodiesel RFS2 requirement by buying and blending biodiesel into our refined diesel product, and by buying needed biodiesel RINs in the EPA-created biodiesel RINs market.

On October 13, 2010, the EPA issued a partial waiver decision under the Clean Air Act to allow for an increase in the amount of ethanol permitted to be blended into gasoline from 10 percent (“E10”) to 15 percent (“E15”) for 2007 and newer light-duty motor vehicles. On January 21, 2011, the EPA issued a second waiver for the use of E15 in vehicles model year 2001-2006. There are numerous issues, including state and federal regulatory issues, which need to be addressed before E15 can be marketed for use in traditional gasoline engines.

There will be compliance costs and uncertainties regarding how we will comply with the various requirements contained in EISA and related regulations. We may experience a decrease in demand for refined petroleum products due to an increase in combined fleet mileage or due to refined petroleum products being replaced by renewable fuels.

The EPA Tier 3 gasoline rulemaking could potentially lower the allowable sulfur level in gasoline but it may also lower the Reid vapor pressure, and the allowable benzene, aromatics and olefins content of gasoline, while possibly increasing octane requirements. We anticipate a proposed rule will be issued in 2013 and plan to participate in the public comment process.

Trademarks, Patents and Licenses

Our Marathon trademark is material to the conduct of our refining and marketing operations, and our Speedway trademark is material to the conduct of our retail marketing operations. We currently hold a number of U.S. and

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foreign patents and have various pending patent applications. Although in the aggregate our patents and licenses are important to us, we do not regard any single patent or license or group of related patents or licenses as critical or essential to our business as a whole. In general, we depend on our technological capabilities and the application of know-how rather than patents and licenses in the conduct of our operations.

Employees

We had approximately 25,985 regular employees as of December 31, 2012, which includes approximately 18,490 employees of Speedway. Approximately 2,025 employees were added in February 2013 associated with the Galveston Bay Refinery and Related Assets.

Certain hourly employees at our Catlettsburg, Canton, Galveston Bay and Texas City refineries are represented by the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers Union under labor agreements that are due to expire in 2015. The International Brotherhood of Teamsters represents certain hourly employees at our Detroit refinery under a labor agreement that is scheduled to expire in January 2014.

Executive Officers of the Registrant

The executive officers of MPC and their ages as of February 1, 2013, are as follows:

Name	Age	Position with MPC
Gary R. Heminger	59	President and Chief Executive Officer
Pamela K.M. Beall	56	Vice President, Investor Relations and Government & Public Affairs
Richard D. Bedell	58	Senior Vice President, Refining
Michael G. Braddock	55	Vice President and Controller
Timothy T. Griffith	43	Vice President of Finance and Treasurer
Thomas M. Kelley	53	Senior Vice President, Marketing
Anthony R. Kenney	59	President, Speedway LLC
Rodney P. Nichols	60	Senior Vice President, Human Resources and Administrative Services
C. Michael Palmer	59	Senior Vice President, Supply, Distribution and Planning
Garry L. Peiffer	61	Executive Vice President, Corporate Planning and Investor & Government Relations
George P. Shaffner	53	Senior Vice President, Transportation and Logistics
John S. Swearingen	53	Vice President, Health, Environmental, Safety & Security
Donald C. Templin	49	Senior Vice President and Chief Financial Officer
Donald W. Wehrly	53	Vice President and Chief Information Officer
J. Michael Wilder	60	Vice President, General Counsel and Secretary

With the exception of Mr. Griffith and Mr. Templin, all of the executive officers have held responsible management or professional positions with MPC, its affiliates or prior to the Spinoff with Marathon Oil or its affiliates, for more than five years.

Mr. Heminger was appointed president and chief executive officer effective June 30, 2011. Prior to this appointment, Mr. Heminger was president of Marathon Petroleum Company LP (formerly known as Marathon Ashland Petroleum LLC and Marathon Petroleum Company LLC), currently a wholly owned subsidiary of MPC and prior to the Spinoff, a wholly owned subsidiary of Marathon Oil. He assumed responsibility as president of Marathon Petroleum Company LP in September 2001.

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Ms. Beall was appointed vice president, Investor Relations and Government & Public Affairs effective June 30, 2011. Prior to this appointment, Ms. Beall was vice president, Products Supply and Optimization of Marathon Petroleum Company LP beginning in June 2010. She served as vice president of Global Procurement for Marathon Oil Company between 2007 and 2010 and prior to that as organizational vice president, Business Development—Downstream.

Mr. Bedell was appointed senior vice president, Refining effective June 30, 2011. Prior to this appointment, Mr. Bedell served in the same capacity for Marathon Petroleum Company LP beginning in June 2010 and as manager, Louisiana Refining Division beginning in 2001.

Mr. Braddock was appointed vice president and controller effective June 30, 2011. Prior to this appointment, Mr. Braddock was controller of Marathon Petroleum Company LP beginning in 2008 and manager, Internal Audit between 2005 and 2008.

Mr. Griffith was appointed vice president of Finance and treasurer effective August 1, 2011. Prior to this appointment, Mr. Griffith was vice president Investor Relations and treasurer of Smurfit-Stone Container Corporation, a packaging manufacturer, in St. Louis, Missouri, and prior to that was vice president and treasurer of Cooper-Standard Automotive, a global automotive supplier, in Novi, Michigan, from 2006 to 2008.

Mr. Kelley was appointed senior vice president, Marketing effective June 30, 2011. Prior to this appointment, Mr. Kelley served in the same capacity for Marathon Petroleum Company LP beginning in January 2010. Previously, he served as director of Crude Supply and Logistics for Marathon Petroleum Company LP from January 2008, and as a Brand Marketing manager for eight years prior to that.

Mr. Kenney has served as president of Speedway LLC since August 2005.

Mr. Nichols was appointed senior vice president, Human Resources and Administrative Services effective March 2012. Prior to this appointment, Mr. Nichols served as vice president, Human Resources and Administrative Services beginning on June 30, 2011 and served in the same capacity for Marathon Petroleum Company LP beginning in April 1998.

Mr. Palmer was appointed senior vice president, Supply Distribution and Planning effective June 30, 2011. Prior to this appointment, Mr. Palmer served as vice president, Supply Distribution & Planning for Marathon Petroleum Company LP beginning in June 2010. He served as Crude Supply and Logistics director for Marathon Petroleum Company LP beginning in February 2010, and as senior vice president, Oil Sands Operations and Commercial Activities for Marathon Oil Canada Corporation beginning in 2007.

Mr. Peiffer was appointed executive vice president of Corporate Planning and Investor & Government Relations effective June 30, 2011. Prior to this appointment, Mr. Peiffer was senior vice president of Finance and Commercial Services for Marathon Petroleum Company LP beginning in 1998.

Mr. Shaffner was appointed senior vice president, Transportation and Logistics effective June 30, 2011. Prior to this appointment, Mr. Shaffner served in the same capacity for Marathon Petroleum Company LP beginning in June 2010. Previously, Mr. Shaffner served as Michigan Refining Division manager beginning in October 2006.

Mr. Swearingen was appointed vice president of Health, Environmental, Safety & Security effective June 30, 2011. Prior to this appointment, Mr. Swearingen was president of Marathon Pipe Line LLC beginning in 2009 and the Illinois Refining Division manager beginning in November 2001.

Mr. Templin was appointed senior vice president and chief financial officer effective June 30, 2011. Prior to this appointment, Mr. Templin was a partner at PricewaterhouseCoopers LLP, an audit, tax and advisory services provider, with various audit and management responsibilities beginning in 1996.

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Mr. Wehrly was appointed vice president and chief information officer effective June 30, 2011. Prior to this appointment, Mr. Wehrly was the manager of Information Technology Services for Marathon Petroleum Company LP beginning in 2003.

Mr. Wilder was appointed vice president, general counsel and secretary effective June 30, 2011. Prior to this appointment, Mr. Wilder was associate general counsel of Marathon Oil Company beginning in 2010 and general counsel and secretary of Marathon Petroleum Company LP beginning in 1997.

Available Information

General information about MPC, including Corporate Governance Principles and Charters for the Audit Committee, Compensation Committee and Corporate Governance and Nominating Committee, can be found at http://ir.marathonpetroleum.com. In addition, our Code of Business Conduct and Code of Ethics for Senior Financial Officers are also available in this same location.

MPC uses its website, www.marathonpetroleum.com, as a channel for routine distribution of important information, including news releases, analyst presentations, financial information and market data. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after the reports are filed or furnished with the Securities and Exchange Commission. These documents are also available in hard copy, free of charge, by contacting our Investor Relations office. In addition, our website allows investors and other interested persons to sign up to automatically receive email alerts when we post news releases and financial information on our website. Information contained on our website is not incorporated into this Annual Report on Form 10-K or other securities filings.

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Item 1A. Risk Factors

You should carefully consider each of the following risks and all of the other information contained in this Annual Report on Form 10-K in evaluating us and our common stock. Some of these risks relate principally to our business and the industry in which we operate, while others relate principally to our Spinoff from Marathon Oil, the ownership of our common stock and securities markets generally.

Our business, financial condition, results of operations or cash flows could be materially and adversely affected by any of these risks, and, as a result, the trading price of our common stock could decline.

Risks Relating to Our Industry and Our Business

Failure to identify and manage risks inherent in our industry could adversely impact our business.

Our business requires us to identify and manage the risks inherent to the refining, marketing and transportation business in which we operate. Our operations are subject to business interruption due to scheduled refinery turnarounds and to unplanned maintenance or events such as explosions, fires, refinery or pipeline releases or other incidents, severe weather and labor disputes. Such incidents may result in personal injury, loss of life, environmental damage, legal liability and loss of revenue. Failure to identify and manage these risks could result in explosions, fires, refinery or pipeline releases or other incidents resulting in personal injury, loss of life, environmental damage, property damage, legal liability, loss of revenue and substantial fines by governmental authorities.

A substantial or extended decline in refining and marketing gross margins would reduce our operating results and cash flows and could materially and adversely impact our future rate of growth and the carrying value of our assets.

Our operating results, cash flows, future rate of growth and the carrying value of our assets are highly dependent on the margins we realize on our refined products. The measure of the difference between market prices for refined products and crude oil, or crack spread, is commonly used by the industry as a proxy for refining and marketing gross margins. Historically, refining and marketing gross margins have been volatile and we believe they will continue to be volatile in the future. Our margins and cost of producing gasoline and other refined products are influenced by a number of conditions, including the price of crude oil. We do not produce crude oil and must purchase all of the crude oil we refine. The price of crude oil and the price at which we can sell our refined products may fluctuate independently due to a variety of regional and global market conditions. The overall change in crack spreads will impact our refining and marketing gross margins. Many of the factors influencing the change in crack spreads and refining and marketing gross margins are beyond our control. These factors include:

• worldwide and domestic supplies of and demand for crude oil and refined products;

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

• the prices realized for refined products;

• utilization rates of refineries;

• natural gas and electricity supply costs incurred by refineries;

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

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

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• local weather conditions;

• seasonality of demand in our marketing area due to increased highway traffic in the spring and summer months;

• natural disasters such as hurricanes and tornados;

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

• domestic and foreign governmental regulations and taxes; and

• local, regional, national and worldwide economic conditions.

Some of these factors can vary by region and may change quickly, adding to market volatility, while others may have longer-term effects. The longer-term effects of these and other factors on refining and marketing gross margins are uncertain. We purchase our crude oil and other refinery feedstocks weeks before refining them and selling the refined products. Price level changes during the period between purchasing feedstocks and selling the refined products from these feedstocks could have a significant effect on our financial results. We also purchase refined products manufactured by others for resale to our customers. Price changes during the periods between purchasing and reselling those refined products also could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Lower refining and marketing gross margins may reduce the amount of refined product we produce, which may reduce our revenues, operating income and cash flows. Significant reductions in refining and marketing gross margins could require us to reduce our capital expenditures or impair the carrying value of our assets.

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

The profitability of our operations depends largely on the difference between the cost of crude oil and other feedstocks we refine and the selling prices we obtain for refined products. A portion of our crude oil is purchased from various foreign national oil companies, producing companies and trading companies, including suppliers from Canada, the Middle East and various other international locations. We are, therefore, subject to the political, geographic and economic risks attendant to doing business with suppliers located in, and supplies originating from, those areas. If one or more of our major supply sources were eliminated, or if political events disrupted our traditional crude oil supply, we believe adequate alternative supplies of crude oil would be available, but it is possible we would be unable to find alternative sources of supply. If we are unable to obtain adequate crude oil volumes or are able to obtain such volumes only at unfavorable prices, our operations, sales of refined products and refining and marketing margins could be adversely affected, materially and adversely impacting our business, financial condition, results of operations and cash flows.

Worldwide political and economic developments could materially and adversely impact our business, financial condition, results of operations and cash flows.

In addition to impacting crude oil and other feedstock supplies, political and economic factors in global markets could have a material adverse effect on us in other ways. Hostilities in the Middle East or the occurrence or threat of future terrorist attacks could adversely affect the economies of the United States (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 refined products. Additionally, these risks could increase instability in the

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financial and insurance markets and make it more difficult or costly for us to access capital and to obtain the insurance coverage that we consider adequate. Additionally, tax policy, legislative or regulatory action and commercial restrictions could reduce our operating profitability. The U.S. government could prevent or restrict exports of refined products or the conduct of business with certain foreign countries.

Changes in environmental or other laws or regulations may reduce our refining and marketing gross margin and may result in substantial capital expenditures and operating costs that could materially and adversely affect our business, financial condition, results of operations and cash flows.

Various laws and regulations are expected to impose increasingly stringent and costly requirements on our operations, which may reduce our refining and marketing gross margin. Laws and regulations relating to the emission or discharge of materials into the environment, solid and hazardous waste management, pollution prevention, greenhouse gas emissions and characteristics and composition of gasoline and diesel fuels, as well as those relating to public and employee safety and health and to facility security, in particular, are expected to become more stringent. The specific impact of laws and regulations on us and our competitors may vary depending on a number of factors, including the age and location of operating facilities, marketing areas, crude oil and feedstock sources and production processes. We may be required to make expenditures to modify operations, install pollution control equipment, perform site cleanups or curtail operations that could materially and adversely affect our business, financial condition, results of operations and cash flows.

We believe the issue of climate change will likely continue to receive scientific and political attention, with the potential for further laws and regulations that could affect our operations. The U.S. pledge in 2009, as part of the Copenhagen Accord, to reduce greenhouse gas emissions 17% below 2005 levels by 2020, remains in effect. Meetings of the United Nations Climate Change Conference, however, have produced no legally binding emission reduction requirements on the U.S. Also in 2009, the EPA issued a finding that greenhouse gas emissions contribute to air pollution that endangers public health and welfare. Related to the endangerment finding, in April 2010, the EPA finalized a greenhouse gas emission standard for mobile sources (cars and other light duty vehicles). The endangerment finding, the mobile source standard and the EPA’s determination that greenhouse gases are subject to regulation under the Clean Air Act and the EPA’s so-called “tailoring rule” led to permitting of larger stationary sources of greenhouse gas emissions, including refineries. We also expect refinery-specific New Source Performance Standards will be proposed in 2013. Legal challenges were filed against these EPA actions. The D.C. Circuit Court of Appeals overruled these challenges but several parties will seek further review by the U.S. Supreme Court.

In the future, Congress may again consider legislation on greenhouse gas emissions or a carbon tax. Other measures to address greenhouse gas emissions are in various phases of review or implementation in the U.S. These measures include state actions to develop statewide or regional programs to impose emission reductions. Private party litigation is pending against federal and certain state governmental entities seeking additional greenhouse gas emission reductions beyond those currently being undertaken. These actions could result in increased costs to operate and maintain our facilities, capital expenditures to install new emission controls and costs to administer any carbon trading or tax programs implemented. Although uncertain, these developments could increase our costs, reduce the demand for the products we sell and create delays in our obtaining air pollution permits for new or modified facilities.

The EISA, among other things, sets a target of 35 miles per gallon for the combined fleet of cars and light trucks in the U.S. by model year 2020 and contains a second Renewable Fuel Standard commonly referred to as RFS2. In August 2012, the EPA and the National Highway Traffic Safety Administration jointly adopted regulations that establish average industry fleet fuel economy standards for passenger cars and light trucks of up to 41 miles per gallon by model year 2021 and of up to 49.7 miles per gallon by model year 2025 (the standards from 2022 to 2025 are the government’s current estimate but will require further rulemaking). Increases in fuel mileage standards and the increased use of renewable fuels (including ethanol and advanced biofuels) may reduce demand for refined products.

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The RFS2 required the total volume of renewable transportation fuels sold or introduced annually in the U.S. to reach 15.2 billion gallons in 2012 and increases to 36.0 billion gallons by 2022. The RFS2 presents production and logistics challenges for both the renewable fuels and petroleum refining industries, and may continue to require additional capital expenditures or expenses by us to accommodate increased renewable fuels use. The advanced biofuels program, a subset of the RFS2 requirements, creates uncertainties and presents challenges of supply, and may require that we and other refiners and other obligated parties purchase credits from the EPA to meet our obligations.

Tax incentives and other subsidies have also made renewable fuels more competitive with refined products than they otherwise would have been, which may further reduce refined product margins.

The EPA Tier 3 gasoline rulemaking could potentially lower the allowable sulfur level in gasoline, but it may also lower the Reid vapor pressure, and the allowable benzene, aromatics and olefins content of gasoline, while possibly increasing octane requirements. We anticipate a proposed rule will be issued in 2013 and plan to participate in the public comment process.

We have in the past owned or operated, and currently own and operate, convenience stores and other locations with USTs in various states. The operation of USTs poses risks, including soil and groundwater contamination, at our previously or currently operated locations. Such contamination could result in substantial cleanup costs, fines or civil liabilities.

We have in the past and will continue to dispose of various wastes at lawful disposal sites. Environmental laws, including CERCLA, and similar state laws can impose liability for the entire cost of cleanup on any responsible party, without regard to negligence or fault, and impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when performed.

Any failure by us to comply with existing or future laws or regulations could result in the imposition of administrative, civil or criminal penalties, injunctions limiting our operations, investigatory or remedial liabilities or impediments to construction of additional facilities or equipment.

Compliance with and changes in tax laws could materially and adversely impact our financial performance.

We are subject to extensive tax liabilities, including federal and state income taxes and transactional taxes such as excise, sales and use, payroll, franchise, withholding and property taxes. New tax laws and regulations and changes in existing tax laws and regulations could result in increased expenditures by us for tax liabilities in the future and could materially and adversely impact our financial performance. Additionally, many tax liabilities are subject to periodic audits by taxing authorities, and such audits could subject us to interest and penalties.

Competitors that produce their own supply of feedstocks, have more extensive retail outlets or have greater financial resources may have a competitive advantage.

We do not produce any of our crude oil supply. Some of our competitors, however, obtain a significant portion of their crude oil from their own exploration and production activities. Competitors that have their own exploration and production activities may at times be able to offset losses from downstream operations with profits from upstream operations, and may be better positioned to withstand periods of depressed refined product margins or feedstock shortages.

Some of our competitors also have significantly greater financial and other resources than we have. Those competitors may have a greater ability to respond to volatile industry or market conditions, such as shortages of crude oil or other feedstocks or intense price fluctuations.

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The retail market is diverse and highly competitive, and severe competition could adversely impact our business.

We also face strong competition in the market for the sale of retail gasoline, diesel and merchandise. Our competitors include outlets owned or operated by fully integrated major oil companies or their dealers or jobbers, and other well-recognized national or regional retail outlets, often selling gasoline or merchandise at very competitive prices. Several non-traditional retailers such as supermarkets, club stores and mass merchants are in the retail business. These non-traditional gasoline retailers have obtained a significant share of the transportation fuels market and we expect their market share to grow. Because of their diversity, integration of operations, experienced management and greater resources, these companies may be better able to withstand volatile market conditions or levels of low or no profitability in the retail segment of the market. In addition, these retailers may use promotional pricing or discounts, both at the pump and in the store, to encourage in-store merchandise sales. These activities by our competitors could pressure us to offer similar discounts, adversely affecting our profit margins. Additionally, the loss of market share by our convenience stores to these and other retailers relating to either gasoline or merchandise could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Our operations are subject to business interruptions and casualty losses. We do not insure against all such potential losses, and, therefore, our business, financial condition, results of operations and cash flows could be adversely affected by unexpected liabilities and increased costs.

Our operations are subject to business interruption due to scheduled refinery turnarounds and to unplanned events such as explosions, fires, refinery or pipeline releases or other incidents or unplanned maintenance, severe weather and labor disputes. For example, our pipelines provide a nearly-exclusive form of transportation of crude oil to, or refined products from, some of our refineries. In such instances, a prolonged interruption in service of such a pipeline could materially and adversely affect the operations, profitability and cash flows of the connected refinery.

Our operations 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. Damages resulting from a catastrophic occurrence 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 substantial claims or in our being assessed potentially substantial fines by governmental authorities. In addition, our information technology systems and network infrastructure are subject to unauthorized access or attack, which could result in the loss of sensitive business information, systems interruptions or the disruption of our business operations. To protect against such attempts of unauthorized access or attack, we have implemented infrastructure protection technologies and disaster recovery plans. The level of protection and disaster recovery capability varies from site to site, and there can be no guarantee such plans, to the extent they are in place, will be totally effective.

We maintain insurance coverage in amounts we believe to be prudent against many, but not all, potential liabilities arising from operating hazards. Uninsured liabilities arising from operating hazards could reduce the funds available to us for capital and investment spending and could have a material adverse effect on our business, financial condition, results of operations and cash flows. Historically, we also have maintained insurance coverage for physical damage and resulting business interruption to our major facilities, with significant self-insured retentions. In the future, we may not be able to maintain or obtain insurance of the types and amounts we desire at reasonable rates.

As a result of market conditions, premiums and deductibles for certain of our insurance coverage have increased substantially and could escalate further. Certain insurance coverage 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 facilities for windstorms in the Gulf of Mexico region has been reduced.

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We are subject to interruptions of supply and increased costs as a result of our reliance on third-party transportation of crude oil and refined products.

We utilize the services of third parties to transport crude oil and refined products to and from our refineries. In addition to our own operational risks discussed above, we could experience interruptions of supply or increases in costs to deliver refined products to market if the ability of the pipelines or vessels to transport crude oil or refined products is disrupted because of weather events, accidents, governmental regulations or third-party actions. A prolonged disruption of the ability of a pipeline or vessels to transport crude oil or refined product to or from one or more of our refineries could have a material adverse effect on our business, financial condition, results of operations and cash flows.

If foreign ownership of our stock exceeds certain levels, we could be prohibited from operating inland river vessels, which could materially and adversely affect our business, financial condition, results of operations and cash flows.

The Shipping Act of 1916 and Merchant Marine Act of 1920, which we refer to collectively as the Maritime Laws, generally require that vessels engaged in U.S. coastwise trade be owned by U.S. citizens. Among other requirements to establish citizenship, corporations that own such vessels must be owned at least 75% by U.S. citizens. If we fail to maintain compliance with the Maritime Laws, we would be prohibited from operating vessels in the U.S. inland waters. Such a prohibition could materially and adversely affect our business, financial condition, results of operations and cash flows.

We may incur losses to our business as a result of our forward-contract activities and derivative transactions.

We currently use commodity derivative instruments and we expect to enter into these types of transactions in the future. A failure of a futures commission merchant or counterparty to perform would affect these transactions. To the extent the instruments we utilize to manage these exposures are not effective, we may incur losses related to the ineffective portion of the derivative transaction or costs related to moving the derivative positions to another futures commission merchant or counterparty once a failure has occurred.

We have substantial debt obligations, therefore our business, financial condition, results of operations and cash flows could be harmed by a deterioration of our credit profile, a decrease in debt capacity or unsecured commercial credit available to us, or by factors adversely affecting credit markets generally.

On February 1, 2011, we completed the offering of senior notes aggregating $3.0 billion in principal amount. At December 31, 2012, our total debt obligations for borrowed money and capital lease obligations was $3.36 billion. We may incur substantial additional debt obligations in the future.

Our indebtedness may impose various restrictions and covenants on us that could have material adverse consequences, including:

• increasing our vulnerability to changing economic, regulatory and industry conditions;

• limiting our ability to compete and our flexibility in planning for, or reacting to, changes in our business and the industry;

• limiting our ability to pay dividends to our stockholders;

• limiting our ability to borrow additional funds; and

• requiring us to dedicate a substantial portion of our cash flow from operations to payments on our debt, thereby reducing funds available for working capital, capital expenditures, acquisitions and other purposes.

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A decrease in our debt and commercial credit capacity, including unsecured credit extended by third-party suppliers, or a deterioration in our credit profile could increase our costs of borrowing money and/or limit our access to the capital markets and commercial credit, which could materially and adversely affect our business, financial condition, results of operations and cash flows.

Historic or current operations could subject us to significant legal liability or restrict our ability to operate.

We currently are defending litigation and anticipate we will be required to defend new litigation in the future. Our operations and those of our predecessors could expose us to litigation and civil claims by private plaintiffs for alleged damages related to contamination of the environment or personal injuries caused by releases of hazardous substances from our facilities, products liability, consumer credit or privacy laws, product pricing or antitrust laws or any other laws or regulations that apply to our operations. While an adverse outcome in most litigation matters would not be expected to be material to us, in class-action litigation large classes of plaintiffs may allege damages relating to extended periods of time or other alleged facts and circumstances that could increase the amount of potential damages. Attorneys general and other government officials may pursue litigation in which they seek to recover civil damages from companies on behalf of a state or its citizens for a variety of claims, including violation of consumer protection and product pricing laws or natural resources damages. We are defending litigation of that type and anticipate that we will be required to defend new litigation of that type in the future. If we are not able to successfully defend such litigation, it may result in liability to our company that could materially and adversely affect our business, financial condition, results of operations and cash flows. We do not have insurance covering all of these potential liabilities. In addition to substantial liability, plaintiffs in litigation may also seek injunctive relief which, if imposed, could have a material adverse effect on our future business, financial condition, results of operations and cash flows.

A portion of our workforce is unionized, and we may face labor disruptions that could materially and adversely affect our business, financial condition, results of operations and cash flows.

Approximately 38 percent of our refining employees are covered by collective bargaining agreements. The contracts for the hourly refinery workers at our Detroit and Texas City refineries are scheduled to expire in January 2014 and March 2015, respectively. The contracts for the hourly refinery workers at our Canton, Catlettsburg and Galveston Bay refineries are each scheduled to expire in January 2015. These contracts may be renewed at an increased cost to us or we may experience work stoppages as a result of labor disagreements.

One of our subsidiaries acts as the general partner of a publicly traded master limited partnership, MPLX, which may involve a greater exposure to legal liability than our historic business operations.

One of our subsidiaries acts as the general partner of MPLX, a publicly traded master limited partnership. Our control of the general partner of MPLX may increase the possibility of claims of breach of fiduciary duties including claims of conflicts of interest related to MPLX. Any liability resulting from such claims could have a material adverse effect on our future business, financial condition, results of operations and cash flows.

Significant transactions, including the Galveston Bay Refinery and Related Assets acquisition, are subject to substantial risks that could adversely affect our business, financial conditions, results of operations and cash flows.

Any significant transaction, including the Galveston Bay Refinery and Related Assets acquisition, involves potential risks, including, among other things:

• the validity of our assumptions about future synergies, revenues, capital expenditures and operating costs;

• an inability to successfully integrate any asset or businesses we acquire;

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• a decrease in our liquidity by using a portion of our available cash or borrowing capacity under our revolving credit agreement to finance transactions;

• a significant increase in our interest expense or financial leverage if we incur additional debt to finance transactions;

• the assumption of unknown environmental and other liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

• the diversion of management’s attention from other business concerns; and

• the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

Risks Relating to our Spinoff from Marathon Oil

We are subject to certain continuing contingent liabilities of Marathon Oil relating to taxes and other matters and to potential liabilities and temporary limitations pursuant to the tax sharing agreement we entered into with Marathon Oil that could materially and adversely affect our business, financial condition, results of operations and cash flows.

Although the Spinoff occurred in mid 2011, certain liabilities of Marathon Oil could become our obligations. For example, under the Internal Revenue Code of 1986 (the “Code”) and related rules and regulations, each corporation that was a member of the Marathon Oil consolidated tax reporting group during any taxable period or portion of any taxable period ending on or before the effective time of the Spinoff is jointly and severally liable for the federal income tax liability of the entire Marathon Oil consolidated tax reporting group for that taxable period. In connection with the Spinoff, we entered into a tax sharing agreement with Marathon Oil that allocates the responsibility for prior period taxes of the Marathon Oil consolidated tax reporting group between us and Marathon Oil. However, if Marathon Oil is unable to pay any prior period taxes for which it is responsible, we could be required to pay the entire amount of such taxes. Other provisions of federal law establish similar liability for other matters, including laws governing tax-qualified pension plans as well as other contingent liabilities.

Also pursuant to the tax sharing agreement, following the Spinoff we are responsible generally for all taxes attributable to us or any of our subsidiaries, whether accruing before, on or after the Spinoff. We also agreed to be responsible for, and indemnify Marathon Oil with respect to, all taxes arising as a result of the Spinoff (or certain internal restructuring transactions) failing to qualify as transactions under Sections 368(a) and 355 of the Code for U.S. federal income tax purposes to the extent such tax liability arises as a result of any breach of any representation, warranty, covenant or other obligation by us or certain affiliates made in connection with the issuance of the private letter ruling relating to the Spinoff or in the tax sharing agreement. In addition, we agreed to indemnify Marathon Oil for specified tax-related liabilities associated with our 2005 acquisition of the minority interest in our refining joint venture from Ashland Inc. Our indemnification obligations to Marathon Oil and its subsidiaries, officers and directors are not limited or subject to any cap. If we are required to indemnify Marathon Oil and its subsidiaries and their respective officers and directors under the tax sharing agreement, we may be subject to substantial liabilities. At this time, we cannot precisely quantify the amount of these liabilities that have been assumed pursuant to the tax sharing agreement and there can be no assurances as to their final amounts. The tax liabilities described in this paragraph could have a material adverse effect on our company.

Under the tax sharing agreement we could be limited for a period of time in our ability to pursue certain strategic or capital raising transactions. In addition, under some circumstances, we could be liable for any adverse tax consequences resulting from engaging in such transactions. Even if the Spinoff’s status as a tax-free distribution under Section 355 of the Code remains intact, the Spinoff may result in significant U.S. federal income tax

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liabilities to Marathon Oil under applicable provisions of the Code if 50 percent or more of Marathon Oil’s stock or our stock is treated as having been acquired, directly or indirectly, by one or more persons as part of a plan that includes the Spinoff. Under those provisions, any acquisitions of Marathon Oil stock or our stock (or similar acquisitions), or any understanding, arrangement or substantial negotiations regarding an acquisition of Marathon Oil stock or our stock (or similar acquisitions), within two years before or after the Spinoff are subject to special scrutiny. The process for determining whether an acquisition triggering those provisions has occurred is complex, inherently factual and subject to interpretation of the facts and circumstances of a particular case. If a direct or indirect acquisition of Marathon Oil stock or our stock resulted in a change in control as contemplated by those provisions, Marathon Oil (but not its stockholders) would recognize a taxable gain.

Under the tax sharing agreement, there are also restrictions on our ability to take actions that could cause the separation to fail to qualify as a tax-free distribution, and we are required to indemnify Marathon Oil against any such tax liabilities attributable to actions taken by or with respect to us or any of our affiliates, or any person that, after the Spinoff, is our affiliate. We may be similarly liable if we breach certain other representations or covenants set forth in the tax sharing agreement. We are also subject to restrictions on our ability to issue shares of our stock without satisfying certain conditions within the tax sharing agreement. As a result of the foregoing, we may be unable to engage in strategic or capital raising transactions that our stockholders might consider favorable, or to structure potential transactions in the manner most favorable to us, without adverse tax consequences, if at all.

The Spinoff could be determined not to qualify as a tax-free transaction, and Marathon Oil and its stockholders could be subject to material amounts of taxes and, in certain circumstances, we could be required to indemnify Marathon Oil for material taxes pursuant to indemnification obligations under the tax sharing agreement.

Marathon Oil received a private letter ruling from the Internal Revenue Service (the “IRS”), to the effect that, among other things, the distribution of shares of MPC common stock in the Spinoff qualifies as tax-free to Marathon Oil, us and Marathon Oil stockholders for U.S. federal income tax purposes under Sections 355 and 368(a) and related provisions of the Code. If the factual assumptions or representations made in the private letter ruling request are inaccurate or incomplete in any material respect, then Marathon Oil would not be able to continue to rely on the ruling. We are not aware of any facts or circumstances that would cause the assumptions or representations that were relied on in the private letter ruling to be inaccurate or incomplete in any material respect. If, notwithstanding receipt of the private letter ruling, the Spinoff were determined not to qualify under Section 355 of the Code, Marathon Oil would be subject to tax as if it had sold its shares of common stock of our company in a taxable sale for their fair market value and would recognize a taxable gain in an amount equal to the excess of the fair market value of such shares over its tax basis in such shares.

With respect to taxes and other liabilities that could be imposed on Marathon Oil in connection with the Spinoff (and certain related transactions) as a result of a final determination that is inconsistent with the anticipated tax consequences as set forth in the private letter ruling, we would be liable to Marathon Oil under the tax sharing agreement for any such taxes or liabilities attributable to actions taken by or with respect to us, any of our affiliates, or any person that, after the Spinoff, is our affiliate. We may be similarly liable if we breach specified representations or covenants set forth in the tax sharing agreement. If we are required to indemnify Marathon Oil for taxes incurred as a result of the Spinoff (or certain related transactions) being taxable to Marathon Oil, it would have a material adverse effect on our business, financial condition, results of operations and cash flows.

We have potential liabilities pursuant to the separation and distribution agreement we entered into with Marathon Oil in connection with the Spinoff that could materially and adversely affect our business, financial condition, results of operations and cash flows.

In connection with the Spinoff, we entered into a separation and distribution agreement with Marathon Oil that provides for, among other things, the principal corporate transactions that were required to affect the Spinoff, certain conditions to the Spinoff and provisions governing the relationship between our company and Marathon

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Oil with respect to and resulting from the Spinoff. Among other things, the separation and distribution agreement provides for indemnification obligations designed to make us financially responsible for substantially all liabilities that may exist relating to our downstream business activities, whether incurred prior to or after the Spinoff, as well as certain obligations of Marathon Oil assumed by us. Our obligations to indemnify Marathon Oil under the circumstances set forth in the separation and distribution agreement could subject us to substantial liabilities. Marathon Oil also agreed to indemnify us for certain liabilities. However, third parties could seek to hold us responsible for any of the liabilities retained by Marathon Oil and there can be no assurance that the indemnity from Marathon Oil will be sufficient to protect us against the full amount of such liabilities, that Marathon Oil will be able to fully satisfy its indemnification obligations or that Marathon Oil’s insurers will cover us for liabilities associated with occurrences prior to the Spinoff. Moreover, even if we ultimately succeed in recovering from Marathon Oil or it insurers any amounts for which we are held liable, we may be temporarily required to bear these losses ourselves. If Marathon Oil is unable to satisfy its indemnification obligations, the underlying liabilities could have a material adverse effect on our business, financial condition, results of operations and cash flows.

Risks Relating to Ownership of Our Common Stock

Provisions in our corporate governance documents could operate to delay or prevent a change in control of our company, dilute the voting power or reduce the value of our capital stock or affect its liquidity.

The existence of some provisions within our restated certificate of incorporation and amended and restated bylaws could discourage, delay or prevent a change in control of us that a stockholder may consider favorable. These include provisions:

• providing that our board of directors fixes the number of members of the board;

• providing for the division of our board of directors into three classes with staggered terms;

• providing that only our board of directors may fill board vacancies;

• limiting who may call special meetings of stockholders;

• prohibiting stockholder action by written consent, thereby requiring stockholder action to be taken at a meeting of the stockholders;

• establishing advance notice requirements for nominations of candidates for election to our board of directors or for proposing matters that can be acted on by stockholders at stockholder meetings;

• establishing supermajority vote requirements for certain amendments to our restated certificate of incorporation and stockholder proposals for amendments to our amended and restated bylaws;

• providing that our directors may only be removed for cause;

• authorizing a large number of shares of common stock that are not yet issued, which would allow our board of directors to issue shares to persons friendly to current management, thereby protecting the continuity of our management, or which could be used to dilute the stock ownership of persons seeking to obtain control of us; and

• authorizing the issuance of “blank check” preferred stock, which could be issued by our board of directors to increase the number of outstanding shares and thwart a takeover attempt.

We believe these provisions protect our stockholders from coercive or otherwise unfair takeover tactics by requiring potential acquirers to negotiate with our board of directors and by providing our board of directors time

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to assess any acquisition proposal, and are not intended to make us immune from takeovers. However, these provisions apply even if the offer may be considered beneficial by some stockholders and could delay or prevent an acquisition that our board of directors determines is not in the best interests of us and our stockholders.

Our restated certificate of incorporation also authorizes us to issue, without the approval of our stockholders, one or more classes or series of preferred stock having such designation, powers, preferences and relative, participating, optional and other special rights, including preferences over our 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 our common stock. For example, we could grant holders of preferred stock the right to elect some number of our board of 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 our common stock.

Finally, to facilitate compliance with the Maritime Laws, our restated certificate of incorporation limits the aggregate percentage ownership by non-U.S. citizens of our common stock or any other class of our capital stock to 23 percent of the outstanding shares. We may prohibit transfers that would cause ownership of our common stock or any other class of our capital stock by non-U.S. citizens to exceed 23 percent. Our restated certificate of incorporation also authorizes us to effect any and all measures necessary or desirable to monitor and limit foreign ownership of our common stock or any other class of our capital stock. These limitations could have an adverse impact on the liquidity of the market for our common stock if holders are unable to transfer shares to non-U.S. citizens due to the limitations on ownership by non-U.S. citizens. Any such limitation on the liquidity of the market for our common stock could adversely impact the market price of our common stock.

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Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The location and general character of our refineries, convenience stores, pipeline systems and other important physical properties have been described by segment under Item 1. Business and are incorporated herein by reference. The plants and facilities have been constructed or acquired over a period of years and vary in age and operating efficiency. In addition, we believe that our properties and facilities are adequate for our operations and that our facilities are adequately maintained. As of December 31, 2012, we were the lessee under a number of cancellable and noncancellable leases for certain properties, including land and building space, office equipment, storage facilities and transportation equipment. See Item 8. Financial Statements and Supplementary Data – Note 24 for additional information regarding our leases.

Item 3. Legal Proceedings

We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. Some of these matters are discussed below.

Litigation

We are a party to a number of lawsuits and other proceedings and cannot predict the outcome of every such matter with certainty. While it is possible that an adverse result in one or more of the lawsuits or proceedings in which we are a defendant could be material to us, based upon current information and our experience as a defendant in other matters, we believe that these lawsuits and proceedings, individually or in the aggregate, will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Kentucky Emergency Pricing Litigation

In May 2007, the Kentucky attorney general filed a lawsuit against us and Marathon Oil in state court in Franklin County, Kentucky for alleged violations of Kentucky’s emergency pricing and consumer protection laws following Hurricanes Katrina and Rita in 2005. The lawsuit alleges that we overcharged customers by $89 million during September and October 2005. The complaint seeks disgorgement of these sums, as well as penalties, under Kentucky’s emergency pricing and consumer protection laws. We are vigorously defending this litigation. We believe that this is the first lawsuit for damages and injunctive relief under the Kentucky emergency pricing laws to progress this far and it contains many novel issues. In May 2011, the Kentucky attorney general amended his complaint to include a request for immediate injunctive relief as well as unspecified damages and penalties related to our wholesale gasoline pricing in April and May 2011 under statewide price controls that were activated by the Kentucky governor on April 26, 2011 and which have since expired. The court denied the attorney general’s request for immediate injunctive relief, and the remainder of the 2011 claims likely will be resolved along with those dating from 2005. If the lawsuit is resolved unfavorably in its entirety, it could materially impact our consolidated results of operations, financial position or cash flows. However, management does not believe the ultimate resolution of this litigation will have a material adverse effect.

Environmental Proceedings

During 2001, we entered into a New Source Review consent decree and settlement of alleged Clean Air Act and other violations with the EPA covering our refineries. The settlement committed us to specific control technologies and implementation schedules for environmental expenditures and improvements to our refineries, which are now complete. We are working with the EPA to terminate the New Source Review consent decree.

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

We have been subject to a pending enforcement matter with the Illinois Environmental Protection Agency (“IEPA”) and the Illinois attorney general’s office since 2002 concerning self-reporting of possible emission exceedences and permitting issues related to storage tanks at the Robinson, Illinois refinery. It is possible the IEPA could seek penalties in excess of $100,000 in connection with this matter.

On January 3, 2013, the Louisiana Department of Environmental Quality (“LDEQ”) issued a consolidated compliance order and notice of potential penalty alleging violations related to self-reported air emission events occurring at our Garyville, Louisiana refinery between the years of 2005 and 2011. It is possible the LDEQ could seek penalties in excess of $100,000 in connection with this matter.

In January 2013, the EPA notified our subsidiary, Marathon Pipe Line LLC, of alleged Clean Air Act violations pertaining to a 2011 audit of our Woodhaven, Michigan facility. The resolution of this matter may result in a penalty in excess of $100,000.

We are involved in a number of other environmental enforcement matters arising in the ordinary course of business. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that the resolution of each of these other matters is not likely to result in a penalty in excess of $100,000 and that collectively, the environmental proceedings described above and these other environmental enforcement matters will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

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

Our common stock is listed on the NYSE and traded under the symbol “MPC”. As of February 15, 2013, there were 41,830 registered holders of our common stock.

The following table reflects intraday high and low sales prices of and dividends declared on our common stock by quarter since July 1, 2011, the date on which our stock began trading “regular-way” on the NYSE:

	2012						2011
Dollars per share	High Price		Low Price		Dividends		High Price		Low Price		Dividends
Quarter 1	$	45.42	$	30.24	$	0.25	$	-	$	-	$	-
Quarter 2		45.35		33.66		0.25		-		-		-
Quarter 3		56.22		42.60		0.35		47.43		26.35		0.20
Quarter 4		63.44		52.36		0.35		39.55		26.61		0.25
Year		63.44		30.24		1.20

Dividends

Our board of directors intends to declare and pay dividends on our common stock based on our financial condition and consolidated results of operations. On January 30, 2013, our board of directors approved a 35 cents per share dividend, payable March 11, 2013 to stockholders of record at the close of business on February 20, 2013.

Dividends on our common stock are limited to our legally available funds.

Issuer Purchases of Equity Securities

The following table sets forth a summary of our purchases during the quarter ended December 31, 2012, of equity securities that are registered by MPC pursuant to Section 12 of the Securities Exchange Act of 1934, as amended:

Period	Total Number of Shares Purchased (a)		Average Price Paid per  Share (b)		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs (c)
10/01/12 - 10/31/12		199	$	55.07		-	$	1,150,000,000
11/01/12 - 11/30/12		7,404,073	$	53.89		7,403,294		650,000,000
12/01/12 - 12/31/12		1,155	$	58.69		-		650,000,000
Total		7,405,427	$	56.60		7,403,294

^(a) The amounts in this column include 199, 779 and 1,155 shares of our common stock delivered by employees to MPC, upon vesting of restricted stock, to satisfy tax withholding requirements in October, November and December, respectively.

^(b) “Average Price Paid per Share” reflects the weighted average price paid for shares tendered to us in satisfaction of employee tax withholding obligations upon the vesting of restricted stock granted under our stock plans. See footnote (c) below for details on the average price paid per share under our accelerated share repurchase, or ASR, program.

^(c) On February 1, 2012, we announced that our board of directors authorized a share repurchase plan, enabling us to purchase up to $2.0 billion of our common stock over a two-year period to expire on January 31, 2014. On February 3, 2012, we entered into an ASR program and paid $850 million to purchase our common stock. We received 20,357,380 shares of our common stock under this program and concluded the program on July 25, 2012. On November 5, 2012, we entered into a second ASR program, representing a second tranche of share repurchases under the share repurchase authorization, and paid $500 million to purchase our common stock. Pursuant to the second ASR program, we received 7,403,294 shares of our common stock on November 5, 2012. On February 5, 2013, an additional 870,947 shares of our common stock were delivered to us, for a total of 8,274,241 repurchased shares, which concluded the second ASR program. Upon final settlement, the average per share cost for all shares purchased under the second ASR program was $60.43. The total value of share repurchases pursuant to the two ASR programs implemented by MPC in 2012 is $1.35 billion, with $650 million remaining under the initial authorization. On January 30, 2013, our board of directors extended the existing $650 million repurchase authorization and approved a new $2.0 billion repurchase authorization, both to expire on December 31, 2014. Consequently, as of January 30, 2013, we had a total outstanding share repurchase authorization of $2.65 billion through December 2014.

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Item 6. Selected Financial Data

	Year Ended December 31,
(In millions, except per share data)	2012			2011			2010 (a)			2009 (a)			2008 (a)
Statements of Income Data
Revenues	$	82,243		$	78,638		$	62,487		$	45,530		$	64,939
Income from operations		5,347			3,745			1,011			654			1,855
Net income		3,393			2,389			623			449			1,215
Net income attributable to MPC		3,389			2,389			623			449			1,215
Per Share Data(b)
Basic:
Net income attributable to MPC per share	$	9.95		$	6.70		$	1.75		$	1.26		$	3.41
Diluted:
Net income attributable to MPC per share	$	9.89		$	6.67		$	1.74		$	1.25		$	3.39
Dividends per share	$	1.20		$	0.45			-			-			-
Statements of Cash Flows Data
Net cash provided by operating activities	$	4,492		$	3,309		$	2,217		$	2,455		$	684
Additions to property, plant and equipment		(1,369	)		(1,185	)		(1,217	)		(2,891	)		(2,787	)
Dividends paid		(407	)		(160	)		-			-			-
	December 31,
(In millions)	2012			2011			2010			2009			2008
Balance Sheets Data
Total assets	$	27,223		$	25,745		$	23,232		$	21,254		$	18,177
Long-term debt, including capitalized leases(c)		3,361			3,307			279			254			182
Long-term debt payable to Marathon Oil and subsidiaries(d)		-			-			3,618			2,358			2,343

^(a)  On December 1, 2010, we disposed of our Minnesota Assets. All periods prior to the disposition include amounts for those operations.

^(b)  The number of weighted average shares for 2012 reflects the impact of shares repurchased under our share repurchase plan. For comparative purposes and to provide a more meaningful calculation, for basic weighted average shares we assumed the 356 million shares distributed to Marathon Oil stockholders in conjunction with the Spinoff were outstanding as of the beginning of each period prior to the Spinoff. In addition, for dilutive weighted average share calculations, we assumed the 358 million dilutive securities outstanding at June 30, 2011 were also outstanding for each period prior to the Spinoff.

^(c)  Includes amounts due within one year. During 2011, we issued $3.0 billion in senior notes, which replaced a portion of the debt payable to Marathon Oil and subsidiaries.

^(d)  Includes amounts due within one year owed to Marathon Oil and subsidiaries, which were repaid prior to the Spinoff.

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

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations includes various forward-looking statements concerning trends or events potentially affecting our business. You can identify our forward-looking statements by words such as “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “plan,” “predict,” “project,” “seek,” “target,” “could,” “may,” “should” or “would” or other similar expressions that convey the uncertainty of future events or outcomes. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in forward-looking statements.

The Spinoff and Basis of Presentation

On May 25, 2011, the Marathon Oil board of directors approved the spinoff of its RM&T Business into an independent, publicly traded company, MPC, through the distribution of MPC common stock to the stockholders of Marathon Oil common stock. In accordance with a separation and distribution agreement between Marathon Oil and MPC, the distribution of MPC common stock was made on June 30, 2011, with Marathon Oil stockholders receiving one share of MPC common stock for every two shares of Marathon Oil common stock held. Following the Spinoff, Marathon Oil retained no ownership interest in MPC, and each company had separate public ownership, boards of directors and management. On July 1, 2011, our common stock began trading “regular-way” on the NYSE under the ticker symbol “MPC”.

Prior to the Spinoff on June 30, 2011, our results of operations and cash flows consisted of the RM&T Business, which represented a combined reporting entity. Subsequent to the Spinoff, our results of operations and cash flows consist of consolidated MPC activities. All significant intercompany transactions and accounts have been eliminated. The consolidated statements of income for periods prior to the Spinoff include expense allocations for certain corporate functions historically performed by the Marathon Oil Companies, including allocations of general corporate expenses related to executive oversight, accounting, treasury, tax, legal, procurement and information technology. Those allocations were based primarily on specific identification, headcount or computer utilization. Our management believes the assumptions underlying the consolidated financial statements, including the assumptions regarding allocating general corporate expenses from the Marathon Oil Companies, are reasonable. However, the consolidated financial statements do not include all of the actual expenses that would have been incurred had we been a stand-alone company during those periods presented prior to the Spinoff and may not reflect our consolidated results of operations and cash flows had we been a stand-alone company during the periods presented. Actual costs that would have been incurred if we had been a stand-alone company would depend on multiple factors, including organizational structure and strategic decisions made in various areas, including information technology and infrastructure. Subsequent to the Spinoff, we are performing these functions using internal resources or services provided by third parties, certain of which were provided by the Marathon Oil Companies during a transition period pursuant to a transition services agreement, which terminated June 30, 2012.

Corporate Overview

We are an independent petroleum refining, marketing and transportation company. As of December 31, 2012, we owned and operated six refineries, all located in the United States, with an aggregate crude oil refining capacity of approximately 1.25 mmbpcd. The acquisition of the Galveston Bay refinery on February 1, 2013 increased our crude oil refining capacity to approximately 1.7 mmbpcd. Our refineries supply refined products to resellers and

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consumers within our market areas, including the Midwest, Gulf Coast and Southeast regions of the United States. We distribute refined products to our customers through one of the largest private domestic fleets of inland petroleum product barges, one of the largest terminal operations in the United States, and a combination of MPC-owned and third-party-owned trucking and rail assets. As of December 31, 2012, we owned, leased or had ownership interests in approximately 8,200 miles of crude oil and refined product pipelines to deliver crude oil to our refineries and other locations and refined products to wholesale and retail market areas. The acquisition of approximately 100 miles of natural gas liquid pipelines on February 1, 2013 increased our pipeline mileage to approximately 8,300 miles. We are one of the largest petroleum pipeline companies in the United States on the basis of total volumes delivered.

Our operations consist of three reportable operating segments: Refining & Marketing; Speedway; and Pipeline Transportation. Each of these segments is organized and managed based upon the nature of the products and services they offer. See Item 1. Business for additional information on our segments.

• Refining & Marketing—refines crude oil and other feedstocks at our seven refineries in the Gulf Coast and Midwest regions of the United States (including the recently acquired Galveston Bay refinery), purchases ethanol and refined products for resale and distributes refined products through various means, including barges, terminals and trucks that we own or operate. We sell refined products to wholesale marketing customers domestically and internationally, to buyers on the spot market, to our Speedway business segment and to dealers and jobbers who operate Marathon^® retail outlets;

• Speedway—sells transportation fuels and convenience products in the retail market in the Midwest, primarily through Speedway^® convenience stores; and

• Pipeline Transportation—transports crude oil and other feedstocks to our refineries and other locations, delivers refined products to wholesale and retail market areas and includes the aggregated operations of MPLX and MPC’s retained pipeline assets and investments.

Net income attributable to MPC was $3.39 billion, or $9.89 per diluted share, in 2012 compared to $2.39 billion, or $6.67 per diluted share, in 2011. The increase was primarily due to our Refining & Marketing segment operations, which generated income from operations of $5.10 billion in 2012 compared to $3.59 billion in 2011. The increase in Refining & Marketing segment income from operations was due to an improved refining and marketing gross margin, which was primarily a result of larger Light Louisiana Sweet crude oil (“LLS”) 6-3-2-1 crack spreads and wider sweet/sour differentials.

In 2012, we completed a $2.2 billion (excluding capitalized interest) heavy oil upgrading and expansion project at our Detroit refinery. This project increased the refinery’s heavy crude oil refining capacity from 20 mbpcd to 100 mbpcd, allowing it to process more heavy, sour crude oils, including Canadian bitumen blends, which have traded at a significant discount to light sweet crude oil. In addition, the project increased the refinery’s total crude oil refining capacity by approximately 14 mbpcd to 120 mbpcd. We also continued to optimize our other refineries in 2012, which includes increasing our Garyville refinery crude oil refining capacity from 490 mbpcd to 522 mbpcd as of December 31, 2012.

Our Speedway segment generated income from operations of $310 million for 2012 compared to $271 million for 2011. The increase in 2012 was primarily due to increases in our merchandise gross margin and our gasoline and distillates gross margin, partially offset by higher expenses associated with an increase in the number of convenience stores.

In 2012, Speedway LLC acquired 10 convenience stores located in the northern Kentucky and southwestern Ohio regions from Road Ranger LLC in exchange for cash and a truck stop location in the Chicago metropolitan area and 87 convenience stores situated throughout Indiana and Ohio from GasAmerica Services, Inc. These acquisitions support our strategic initiative to increase Speedway segment sales and complement our existing network of assets.

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Our Pipeline Transportation segment generated income from operations of $216 million for 2012 compared to $199 million for 2011. The increase primarily reflects higher transportation tariffs, partially offset by higher mechanical integrity expenses and a reduction in income from a pipeline affiliate.

On February 1, 2013, we acquired from BP the 451,000 barrel per calendar day Texas City, Texas refinery, three intrastate natural gas liquid pipelines originating at the refinery, an allocation of BP’s Colonial Pipeline Company shipper history, four light product terminals, branded-jobber marketing contract assignments for the supply of approximately 1,200 branded sites and a 1,040 megawatt electric cogeneration facility. We refer to these assets as the “Galveston Bay Refinery and Related Assets”. The financial results and operating statistics included in this section do not include these assets. See Item 8. Financial Statements and Supplementary Data – Note 26 for additional information on the acquisition of these assets.

In 2012, we formed MPLX, a master limited partnership, to own, operate, develop and acquire pipelines and other midstream assets related to the transportation and storage of crude oil, refined products and other hydrocarbon-based products. On October 31, 2012, MPLX completed its initial public offering of 19,895,000 common units, which represented the sale by us of a 26.4 percent interest in MPLX. We own a 73.6 percent interest in MPLX, including the general partner interest, and we consolidate this entity for financial reporting purposes since we have a controlling financial interest. Headquartered in Findlay, Ohio, MPLX’s initial assets consist of a 51 percent general partner interest in Pipe Line Holdings, which owns a network of common carrier crude oil and product pipeline systems and associated storage assets in the Midwest and Gulf Coast regions of the United States, and a 100 percent interest in a butane storage cavern in West Virginia. We own the remaining 49 percent limited partner interest in Pipe Line Holdings. The financial results and operating statistics in this section include 100 percent of these assets for all time periods presented. See Item 8. Financial Statements and Supplementary Data – Note 4 for additional information on MPLX’s initial public offering.

In 2012, we signed a letter of intent with Harvest Pipeline Company, agreeing to jointly develop infrastructure that will facilitate transportation of hydrocarbon liquids production from the Utica Shale in eastern Ohio and western Pennsylvania. The proposed project is expected to result in up to 24,000 barrels per day of truck unloading capacity and a terminal capable of loading up to 50,000 barrels per day onto barges on the Ohio River at our Wellsville, Ohio asphalt terminal.

In 2012, to increase access to Bakken and Canadian crude oil, we agreed to be the anchor shipper on Enbridge Inc.’s proposed Southern Access Extension pipeline with an option to acquire a 25 percent equity interest in the pipeline. This line will originate in Flanagan, Illinois near Chicago and terminate in Patoka, Illinois, a critical crude storage and blending hub and the origination point for crude supply to our four Midwest refineries.

On February 1, 2012, we announced that our board of directors authorized a share repurchase plan, enabling us to purchase up to $2.0 billion of MPC common stock over a two-year period. We entered into two ASR programs in 2012 to repurchase shares of MPC common stock totaling $1.35 billion. We received 27,760,674 shares under these programs in 2012 and 870,947 shares in February 2013. On January 30, 2013, we announced that our board of directors approved an additional $2.0 billion share repurchase authorization. The board also extended the remaining $650 million share repurchase authorization announced on February 1, 2012, for a total outstanding authorization of $2.65 billion through December 2014.

In 2012, we entered into a five-year revolving credit agreement with an initial borrowing capacity of $2.0 billion and terminated our previous four-year revolving credit agreement. We subsequently amended this agreement to increase the borrowing capacity to $2.5 billion, which became effective in February 2013 in conjunction with the acquisition of the Galveston Bay Refinery and Related Assets. Also in 2012, MPLX Operations LLC, an affiliate of MPC and wholly-owned subsidiary of MPLX, entered into a five-year senior unsecured revolving credit agreement with an initial borrowing loan capacity of $500 million that became effective at the time of MPLX’s initial public offering. The agreement provides MPLX with an independent source of liquidity.

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As of December 31, 2012, we had cash and cash equivalents of $4.86 billion and no borrowings or letters of credit outstanding under MPC’s revolving credit agreement or trade receivables securitization facility or MPLX’s revolving credit agreement.

On December 1, 2010, we completed the sale of the Minnesota Assets. These assets included the 74,000 barrel per calendar day St. Paul Park refinery and associated terminals, 166 convenience stores primarily branded SuperAmerica^® (including six stores in Wisconsin) along with the SuperMom’s bakery and commissary (a baked goods and sandwich supply operation) and certain associated trademarks, SuperAmerica Franchising LLC, interests in pipeline assets in Minnesota and associated inventories. Our financial results and operating statistics for all periods prior to the disposition include amounts for the Minnesota Assets.

The above discussion includes forward-looking statements that relate to our expectations with respect to the proposed project with Harvest Pipeline Company and the share repurchase plan. Factors that could affect the proposed project with Harvest Pipeline Company include, but are not limited to, our ability to reach a definitive agreement with Harvest Pipeline Company and the timing and extent of hydrocarbon liquids production and demand from the Utica Shale. Factors that could affect the share repurchase plan and its timing include, but are not limited to, business conditions, availability of liquidity and the market price of our common stock. These factors, among others, could cause actual results to differ materially from those set forth in the forward-looking statements.

Overview of Segments

Refining & Marketing

Refining & Marketing segment income from operations depends largely on our refining and marketing gross margin and refinery throughputs.

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

Our refineries can process significant amounts of sour crude oil, which typically can be purchased at a discount to sweet crude oil. The amount of this discount, the sweet/sour differential, can vary significantly, causing our refining and marketing gross margin to differ from crack spreads based on sweet crude. In general, a larger sweet/sour differential will enhance our refining and marketing gross margin.

Historically, WTI has traded at prices similar to LLS. During 2012 and 2011, WTI traded at prices significantly less than LLS, which favorably impacted our refining and marketing gross margin. The logistical constraints in the U.S. mid-continent markets have prevented the price of WTI from rising with the prices of crude oil produced in other regions. Future differentials will be dependent on changes made to the logistical infrastructure.

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The following table provides sensitivities showing the estimated change in annual net income, including the impact of the Galveston Bay refinery, due to potential changes in market conditions.

(In millions, after-tax)
LLS 6-3-2-1 crack spread sensitivity (a) (per $1.00/barrel change)	$	425
Sweet/sour differential sensitivity (b) (per $1.00/barrel change)		225
LLS-WTI spread sensitivity (c) (per $1.00/barrel change)		75
Natural gas price sensitivity (per $1.00/million British thermal unit change)		140

^(a)  Weighted 38% Chicago and 62% USGC LLS 6-3-2-1 crack spreads and assumes all other differentials and pricing relationships remain unchanged.

^(b)  LLS (prompt) - [delivered cost of sour crude oil: Arab Light, Kuwait, Maya, Western Canadian Select and Mars].

^(c)  Assumes 20% of crude oil throughput volumes are WTI-based domestic crude oil.

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

• the types of crude oil and other charge and blendstocks processed;

• the selling prices realized for refined products;

• the impact of commodity derivative instruments used to hedge price risk;

• the cost of products purchased for resale; and

• changes in manufacturing costs, which include depreciation and amortization.

Changes in manufacturing costs are primarily driven by the cost of energy used by our refineries, including purchased natural gas, and the level of maintenance costs. Planned major maintenance activities, or turnarounds, requiring temporary shutdown of certain refinery operating units, are periodically performed at each refinery. The following table lists the refineries that had significant planned turnaround and major maintenance activities for each of the last three years.

Year	Refinery
2012	Catlettsburg, Detroit, Garyville and Robinson
2011	Canton and Catlettsburg
2010	Catlettsburg, Detroit, Garyville, Robinson and Texas City

The table below sets forth the location and daily crude oil refining capacity of each of our refineries at December 31 of each year. The acquisition of the Galveston Bay refinery (not shown below) on February 1, 2013 increased our crude oil refining capacity to approximately 1.7 mmbpcd.

	Crude Oil Refining Capacity (mbpcd)
Refinery	2012		2011		2010
Garyville, Louisiana		522		490		464
Catlettsburg, Kentucky		240		233		212
Robinson, Illinois		206		206		206
Detroit, Michigan		120		106		106
Canton, Ohio		80		78		78
Texas City, Texas		80		80		76
Total		1,248		1,193		1,142

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Speedway

Our retail marketing gross margin for gasoline and distillates, which is the price paid by consumers less the cost of refined products, including transportation, consumer excise taxes and bankcard processing fees, impacts the Speedway segment profitability. Numerous factors impact gasoline and distillates demand throughout the year, including local competition, seasonal demand fluctuations, the available wholesale supply, the level of economic activity in our marketing areas and weather conditions. The demand for gasoline in the Midwest region is estimated to have declined by less than half a percent in 2012 after decreasing by more than two percent in 2011. Stronger economic growth supported demand, but was offset by slightly higher prices and increasing vehicle efficiency. Unseasonably warm winter weather early in 2012 contributed to an estimated one percent decline in Midwest distillate demand in 2012, which followed a slight decrease in demand in 2011. Market demand increases for gasoline and distillates generally increase the product margin we can realize. The gross margin on merchandise sold at convenience stores historically has been less volatile. Approximately two-thirds of Speedway’s gross margin was derived from merchandise sales in 2012.

Pipeline Transportation

The profitability of our pipeline transportation operations primarily depends on tariff rates and the volumes shipped through the pipelines. A majority of the crude oil and refined product shipments on our common carrier pipelines serve our Refining & Marketing segment. In 2012, new transportation services agreements were entered into between MPC and MPLX, which resulted in higher tariff rates. The volume of crude oil that we transport is directly affected by the supply of, and refiner demand for, crude oil in the markets served directly by our crude oil pipelines. Key factors in this supply and demand balance are the production levels of crude oil by producers in various regions or fields, the availability and cost of alternative modes of transportation, the volumes of crude oil processed at refineries and refinery and transportation system maintenance levels. The volume of refined products that we transport is directly affected by the production levels of, and user demand for, refined products in the markets served by our refined product pipelines. In most of our markets, demand for gasoline and distillates peaks during the summer driving season, which extends from May through September of each year, and declines during the fall and winter months. As with crude oil, other transportation alternatives and system maintenance levels influence refined product movements.

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Results of Operations

Years Ended December 31, 2012 and December 31, 2011

Consolidated Results of Operations

(In millions)	2012		2011		Variance
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$	82,235	$	78,583	$	3,652
Sales to related parties		8		55		(47)
Income from equity method investments		26		50		(24)
Net gain on disposal of assets		177		12		165
Other income		46		59		(13)
Total revenues and other income		82,492		78,759		3,733
Costs and expenses:
Cost of revenues (excludes items below)		68,668		65,795		2,873
Purchases from related parties		280		1,916		(1,636)
Consumer excise taxes		5,709		5,114		595
Depreciation and amortization		995		891		104
Selling, general and administrative expenses		1,223		1,059		164
Other taxes		270		239		31
Total costs and expenses		77,145		75,014		2,131
Income from operations		5,347		3,745		1,602
Related party net interest and other financial income		1		35		(34)
Net interest and other financial income (costs)		(110)		(61)		(49)
Income before income taxes		5,238		3,719		1,519
Provision for income taxes		1,845		1,330		515
Net income		3,393		2,389		1,004
Less net income attributable to noncontrolling interests		4		-		4
Net income attributable to MPC	$	3,389	$	2,389	$	1,000

Net income attributable to MPC was $1.00 billion higher in 2012 compared to 2011, primarily due to a higher refining and marketing gross margin, which increased to $10.45 per barrel in 2012 from $7.75 per barrel in 2011.

Sales and other operating revenues (including consumer excise taxes) increased $3.65 billion in 2012 compared to 2011, primarily due to increases in refined product selling prices and sales volumes, crude oil and refinery feedstock sales volumes and consumer excise taxes.

Sales to related parties decreased $47 million in 2012 compared to 2011. The decrease resulted from lower refined product volumes sold to Centennial Pipeline LLC (“Centennial”) and sales to Marathon Oil after the Spinoff no longer being classified as related party.

Income from equity method investments decreased $24 million in 2012 compared to 2011. The decrease resulted from an $18 million decrease in income from our ethanol investments and an $8 million decrease in income from our investment in LOOP LLC (“LOOP”). Our ethanol investments experienced lower product margins in 2012, primarily due to lower demand for corn ethanol and higher corn prices, and LOOP experienced higher expenses in 2012 compared to 2011. Additionally, Centennial experienced a significant reduction in shipment volumes in the second half of 2011 that continued in 2012. At December 31, 2012, Centennial was not shipping product. As a result, we continued to evaluate the carrying value of our equity investment in Centennial and concluded that no impairment was required given our assessment of its fair value based on various uses for Centennial’s assets.

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Other income decreased $13 million in 2012 compared to 2011, primarily due to a decrease in income from transition services provided to the buyer of our Minnesota Assets and to Marathon Oil and a decrease in sales of Renewable Identification Numbers. These decreases were partially offset by $12 million of dividend income recognized in 2012 from our preferred equity interest in the buyer of our Minnesota Assets, which was paid in connection with our settlement agreement with the buyer. See Item 8. Financial Statements and Supplementary Data—Note 7 for additional information on the Minnesota Assets sale and subsequent settlement with the buyer.

Cost of revenues increased $2.87 billion in 2012 compared to 2011. The increase was primarily due to higher acquisition costs of crude oil and refined products in the Refining & Marketing segment, which resulted from increased volumes, partially offset by decreased prices. The increase in crude oil volumes was partially due to purchases from Marathon Oil not being classified as related party purchases in periods subsequent to the Spinoff. These impacts were partially offset by decreased acquisition costs of other charge and blendstocks, due to decreased volumes and prices. Crude oil volumes were up 6 percent and refined product volumes were up 8 percent, while other charge and blendstocks volumes were down 7 percent. Crude oil acquisition prices were down 1 percent, charge and blendstock prices were down 6 percent and purchased refined product prices were down 4 percent.

Purchases from related parties decreased $1.64 billion in 2012 compared to 2011. The decrease was primarily due to purchases of crude oil from Marathon Oil after the Spinoff not being classified as related party transactions.

Consumer excise taxes increased $595 million in 2012 compared to 2011, primarily due to the expiration of a federal excise tax credit for blending ethanol and increased excise tax in select states.

Depreciation and amortization increased $104 million in 2012 compared to 2011, primarily due to the completion of the heavy oil upgrading and expansion project at our Detroit refinery and Speedway’s acquisition of 97 convenience stores in 2012.

Selling, general and administrative expenses increased $164 million in 2012 compared to 2011. Employee compensation and benefit expenses comprised $141 million of the increase, which was primarily due to $117 million of higher pension settlement expenses in 2012 and an increase in the number of administrative employees associated with being a stand-alone company for a full year in 2012 compared to half of the year in 2011, partially offset by a decrease in pension expenses associated with a pension plan amendment. See Item 8. Financial Statements and Supplementary Data—Note 22 for additional information on the pension settlements and the pension plan amendment. Contract service expenses increased $52 million primarily due to higher information technology costs, higher refinery-related contract services and contract services associated with the acquisition of the Galveston Bay Refinery and Related Assets. These impacts were partially offset by having no allocations from Marathon Oil subsequent to the Spinoff.

Other taxes increased $31 million in 2012 compared to 2011, primarily due to increases in operating taxes of $11 million, personal property taxes of $8 million, real estate taxes of $7 million and franchise taxes of $6 million. These increases were attributable to a number of factors including the completion of the heavy oil upgrading and expansion project at our Detroit refinery, Speedway’s acquisition of 97 convenience stores and higher feedstock inventory values.

Related party net interest and other financial income decreased $34 million in 2012 compared to 2011, primarily due to our short-term investments in preferred stock of MOC Portfolio Delaware, Inc. (“PFD”), a subsidiary of Marathon Oil, being redeemed prior to the Spinoff. The agreement with PFD was terminated on June 30, 2011. See Item 8. Financial Statements and Supplementary Data—Note 5 for further discussion of the PFD preferred stock.

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Net interest and other financial costs increased $49 million in 2012 compared to 2011, primarily reflecting an increase in interest expense associated with the $3.0 billion senior notes issued in February 2011, a decrease in foreign currency gains and an increase in bank service and other fees. We capitalized third-party interest of $101 million in 2012 compared to $104 million in 2011. The capitalized interest was primarily associated with the Detroit refinery heavy oil upgrading and expansion project.

Provision for income taxes increased $515 million 2012 compared to 2011, primarily due to the $1.52 billion increase in income before income taxes. The effective income tax rate decreased from 36 percent in 2011 to 35 percent in 2012. The 2012 effective income tax rate was favorably impacted by a decrease in adverse tax impacts from state legislation and other permanent benefit differences. For years 2012 and 2011, adverse tax impacts of state legislation were $9 million and $19 million, respectively. The provision for income taxes for periods prior to the Spinoff has been computed as if we were a stand-alone company. See Item 8. Financial Statements and Supplementary Data—Note 13 for further details.

Segment Results

Revenues are summarized by segment in the following table.

(In millions)	2012		2011
Refining & Marketing	$	76,710	$	73,381
Speedway		14,243		13,490
Pipeline Transportation		459		403
Segment revenues		91,412		87,274
Elimination of intersegment revenues		(9,167)		(8,636)
Total revenues	$	82,245	$	78,638
Items included in both revenues and costs:
Consumer excise taxes	$	5,709	$	5,114

Refining & Marketing segment revenues increased $3.33 billion in 2012 from 2011, primarily due to increased refined product selling prices and sales volumes. Our average refined product selling prices were $3.00 per gallon in 2012 compared to $2.93 per gallon in 2011. The table below shows the average refined product benchmark prices for our marketing areas.

(Dollars per gallon)	2012		2011
Chicago spot unleaded regular gasoline	$	2.84	$	2.79
Chicago spot ultra-low sulfur diesel		3.01		2.98
USGC spot unleaded regular gasoline		2.81		2.75
USGC spot ultra-low sulfur diesel		3.05		2.97

Refining & Marketing intersegment sales to our Speedway segment were $8.78 billion in 2012 compared to $8.30 billion in 2011. Intersegment refined product sales volumes were 2.73 billion gallons in 2012 compared to 2.66 billion gallons in 2011, with the increased volumes primarily due to Speedway’s acquisition of 97 convenience stores in 2012.

Speedway segment revenues increased $753 million in 2012 compared to 2011, primarily due to higher gasoline and distillates sales volumes and selling prices, which averaged $3.54 per gallon in 2012 compared to $3.44 per gallon in 2011. The Speedway segment also had higher merchandise sales excluding cigarettes. The increases in gasoline and distillates sales volumes and merchandise sales were primarily due to the acquisition of 97 convenience stores in 2012.

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Pipeline Transportation segment revenue increased $56 million in 2012 compared to 2011, primarily due to higher transportation tariffs resulting from increased tariff rates in 2012 and the startup of a new crude oil pipeline in 2012.

Income before income taxes and income from operations by segment are summarized in the following table.

(In millions)	2012		2011
Income from operations by segment:
Refining & Marketing	$	5,098	$	3,591
Speedway		310		271
Pipeline Transportation (a)		216		199
Items not allocated to segments:
Corporate and other unallocated items (a)(b)		(336)		(316)
Minnesota Assets sale settlement gain (c)		183		—
Pension settlement expenses (a)(d)		(124)		—
Income from operations		5,347		3,745
Net interest and other financial income (costs) (e)		(109)		(26)
Income before income taxes	$	5,238	$	3,719

^(a)  Corporate overhead allocations and pension settlement expenses attributable to MPLX were included in the Pipeline Transportation segment subsequent to MPLX’s October 31, 2012 initial public offering.

^(b)  Corporate and other unallocated items consists primarily of MPC’s corporate administrative expenses, including allocations from Marathon Oil for periods prior to the Spinoff, and costs related to certain non-operating assets.

^(c)  See Item 8. Financial Statements and Supplementary Data - Note 7.

^(d)  See Item 8. Financial Statements and Supplementary Data - Note 22.

^(e)  Includes related party net interest and other financial income.

The following table presents certain market indicators that we believe are helpful in understanding the results of our Refining & Marketing segment’s business.

(Dollars per barrel)	2012		2011
Chicago LLS 6-3-2-1 (a)(b)	$	6.74	$	3.81
USGC LLS 6-3-2-1 (a)		6.67		2.84
Blended 6-3-2-1 (a)(c)		6.71		3.35
LLS		111.67		112.37
WTI		94.15		95.11
LLS - WTI differential (a)		17.52		17.26
Sweet/Sour differential (a)(d)		12.47		9.11

^(a)  All spreads and differentials are measured against prompt LLS.

^(b)  Calculation utilizes USGC 3% Bunker value as a proxy for Chicago residual fuel price.

^(c)  Blended Chicago/USGC crack spread is 52%/48% in 2012 and 53%/47% in 2011 based on MPC’s refining capacity by region in each period.

^(d)  LLS (prompt) - [delivered cost of sour crude oil: Arab Light, Kuwait, Maya, Western Canadian Select and Mars].

Refining & Marketing segment income from operations increased $1.51 billion in 2012 from 2011, primarily due to a higher refining and marketing gross margin per barrel, which averaged $10.45 per barrel in 2012 compared to $7.75 per barrel in 2011. Our realized Refining & Marketing gross margin for 2012 benefited from increases in the Chicago and USGC LLS 6-3-2-1 blended crack spread of $3.36 per barrel and the sweet/sour differential of $3.36 per barrel in 2012, and we estimate these had positive impacts on our Refining & Marketing gross margin of $1.68 billion and $870 million, respectively. These favorable impacts on our Refining & Marketing gross margin for 2012 compared to 2011 were partially offset by higher cost realizations of the actual mix of crude oils we processed compared to market indicators and higher direct operating costs associated with higher planned turnaround and major maintenance expenses and depreciation and amortization expenses.

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The following table summarizes our refinery throughputs for 2012 and 2011.

(mbpd)	2012		2011
Refinery Throughputs:
Crude oil refined		1,195		1,177
Other charge and blendstocks		168		181
Total		1,363		1,358

The increase in crude oil throughput in 2012 compared to 2011 was primarily due to the increased crude oil refining capacities of the Garyville and Catlettsburg refineries and the impacts of the planned turnarounds in 2012 and 2011. The decrease in other charge and blendstocks throughput in 2012 compared to 2011 was primarily due to the planned turnarounds in 2012 and a combination of increased crude oil throughput and feedstock economics at our Garyville refinery in 2012.

Within our refining system, sour crude accounted for 53 percent and 52 percent of our crude oil processed in 2012 and 2011, respectively.

The following table includes certain key operating statistics for the Refining & Marketing segment for 2012 and 2011.

	2012		2011
Refining & Marketing gross margin (Dollars per barrel) (a)	$	10.45	$	7.75
Direct operating costs in Refining & Marketing gross margin (Dollars per barrel): (b)
Planned turnaround and major maintenance	$	1.00	$	0.78
Depreciation and amortization		1.44		1.29
Other manufacturing (c)		3.15		3.16
Total	$	5.59	$	5.23
Refined products sales volumes (mbpd) (d)		1,599		1,581

^(a)  Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation and amortization, divided by Refining & Marketing segment refined product sales volumes.

^(b)  Per barrel of total refinery throughputs.

^(c)  Includes utilities, labor, routine maintenance and other operating costs.

^(d)  Includes intersegment sales.

Speedway segment income from operations increased $39 million in 2012 compared to 2011, primarily due to increases in our merchandise gross margin and our gasoline and distillates gross margin, partially offset by higher expenses attributable to an increase in the number of convenience stores. The increase in the merchandise gross margin was primarily due to margin expansion resulting from higher merchandise and food sales along with an increase in the number of convenience stores.

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The following table includes certain key operating statistics for the Speedway segment for 2012 and 2011.

	2012		2011
Convenience stores at period-end		1,464		1,371
Gasoline & distillates sales (millions of gallons)		3,027		2,938
Gasoline & distillates gross margin (dollars per gallon) (a)	$	0.1318	$	0.1308
Merchandise sales (in millions)	$	3,058	$	2,924
Merchandise gross margin (in millions)	$	795	$	719

^(a)  The price paid by consumers less the cost of refined products, including transportation, consumer excise taxes and bankcard processing fees, divided by gasoline and distillates sales volume.

Same-store gasoline sales volume decreased 0.8 percent in 2012 compared to 2011, while same-store merchandise sales excluding cigarettes increased 7.0 percent for the same period. The primary factor affecting lower same store gasoline sales volume was lower gasoline demand in our market area.

Pipeline Transportation segment income from operations increased $17 million in 2012 from 2011. The increase primarily reflects higher transportation tariffs, partially offset by higher mechanical integrity expenses and a reduction in income from LOOP.

Corporate and other unallocated expenses increased $20 million in 2012 compared to 2011. The increase was primarily due to our administrative units realizing the impact of being a stand-alone company in 2012 compared to expenses incurred prior to the June 30, 2011 Spinoff, partially offset by lower pension expenses associated with a pension plan amendment in the second quarter of 2012.

We recognized a gain of $183 million in 2012 associated with the settlement agreement with the buyer of our Minnesota Assets, which included $86 million of the deferred gain that was recorded when the sale transaction was originally closed. See Item 8. Financial Statements and Supplementary Data - Note 7 for additional information on the Minnesota Assets sale and subsequent settlement with the buyer.

We recorded pretax pension settlement expenses of $124 million in 2012 resulting from the level of employee lump sum retirement distributions that occurred in 2012. See Item 8. Financial Statements and Supplementary Data—Note 22 for additional information on the pension plan amendments.

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Years Ended December 31, 2011 and December 31, 2010

Consolidated Results of Operations

(In millions)	2011		2010		Variance
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$	78,583	$	62,387	$	16,196
Sales to related parties		55		100		(45)
Income from equity method investments		50		70		(20)
Net gain on disposal of assets		12		11		1
Other income		59		37		22
Total revenues and other income		78,759		62,605		16,154
Costs and expenses:
Cost of revenues (excludes items below)		65,795		51,731		14,064
Purchases from related parties		1,916		2,593		(677)
Consumer excise taxes		5,114		5,208		(94)
Depreciation and amortization		891		941		(50)
Selling, general and administrative expenses		1,059		874		185
Other taxes		239		247		(8)
Total costs and expenses		75,014		61,594		13,420
Income from operations		3,745		1,011		2,734
Related party net interest and other financial income		35		24		11
Net interest and other financial income (costs)		(61)		(12)		(49)
Income before income taxes		3,719		1,023		2,696
Provision for income taxes		1,330		400		930
Net income	$	2,389	$	623	$	1,766

Consolidated net income was $1.77 billion higher in 2011 compared to 2010, primarily due to a higher refining and marketing gross margin, which increased to $7.75 per barrel in 2011 from $2.81 per barrel in 2010.

Sales and other operating revenues (including consumer excise taxes) increased $16.20 billion in 2011 compared to 2010, primarily due to higher refined product selling prices.

Sales to related parties decreased $45 million in 2011 compared to 2010. The decrease resulted from sales to Marathon Oil after the Spinoff no longer being classified as related party and lower refined product volumes sold to Centennial, partially offset by higher refined product selling prices.

Income from equity method investments decreased $20 million from 2010 to 2011, primarily due to $12 million of increased losses from our investment in Centennial. Centennial experienced a significant reduction in shipment volumes in the second half of 2011 compared to the corresponding period of 2010. Also, 2010 included $4 million of income from an investment in a pipeline company that was included in the Minnesota Assets disposition.

Other income increased $22 million in 2011 compared with 2010, due primarily to income from transition services provided to the purchaser of the Minnesota Assets and to Marathon Oil.

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Cost of revenues increased $14.06 billion in 2011 from 2010. The increase was primarily the result of higher acquisition costs of crude oil, refinery charge and blendstocks and refined products in the Refining & Marketing segment, largely due to higher market prices. Crude oil acquisition prices were up 31 percent, charge and blendstock prices were up 28 percent and purchased refined product prices were up 40 percent.

Purchases from related parties decreased $677 million in 2011 compared to 2010. The decrease was primarily due to purchases of crude oil from Marathon Oil after the Spinoff not being classified as related party transactions.

Selling, general and administrative expenses increased $185 million in 2011 compared with 2010. Employee compensation and benefits expenses comprised $81 million of the increase, which is partially due to an increase in the number of administrative employees associated with being a stand-alone public company, higher incentive compensation accruals related to 2011 performance and increased pension and postretirement benefit costs. Contract services expenses increased $62 million, primarily due to higher information technology costs associated with being a separate stand-alone company. In addition, bankcard processing fees related to Marathon brand sales increased $41 million, primarily due to higher transportation fuel selling prices. Following the Spinoff, we no longer receive allocated corporate overhead costs from Marathon Oil.

Related party net interest and other financial income increased $11 million in 2011 compared to 2010, primarily reflecting higher average balances of our short-term investments in PFD preferred stock. The agreement with PFD was terminated on June 30, 2011. See Item 8. Financial Statements and Supplementary Data - Note 5 for further discussion of the PFD preferred stock.

Net interest and other financial costs increased $49 million in 2011 compared with 2010, primarily reflecting increased interest expense associated with the $3.0 billion of long-term debt we issued in February 2011. We capitalized third-party interest of $104 million in 2011 compared to $17 million in 2010. See Item 8. Financial Statements and Supplementary Data - Note 20 for further details relating to our debt.

Provision for income taxes increased $930 million from 2010 to 2011, primarily due to the $2.70 billion increase in income before income taxes. The effective income tax rate decreased from 39 percent in 2010 to 36 percent in 2011. The 2011 effective income tax rate was favorably impacted by an increase in income qualifying for the domestic manufacturing deduction and a decrease in the effective tax rate for state taxes. The year 2011 included a $19 million adverse tax impact of state legislative changes, primarily in Michigan, and 2010 included a $26 million adverse tax impact of federal legislative changes. The provision for income taxes for periods prior to the Spinoff has been computed as if we were a stand-alone company. See Item 8. Financial Statements and Supplementary Data - Note 13 for further details.

Segment Results

Revenues are summarized by segment in the following table.

(In millions)	2011		2010
Refining & Marketing	$	73,381	$	57,333
Speedway		13,490		12,494
Pipeline Transportation		403		401
Segment revenues		87,274		70,228
Elimination of intersegment revenues		(8,636)		(7,741)
Total revenues	$	78,638	$	62,487
Items included in both revenues and costs:
Consumer excise taxes	$	5,114	$	5,208

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Refining & Marketing segment revenues increased $16.05 billion in 2011 from 2010, primarily due to increased refined product selling prices. Our average refined product selling prices were $2.93 per gallon in 2011 compared to $2.24 per gallon in 2010. The table below shows the average refined product benchmark prices for our marketing areas.

(Dollars per gallon)	2011		2010
Chicago spot unleaded regular gasoline	$	2.79	$	2.09
Chicago spot ultra-low sulfur diesel		2.98		2.17
USGC spot unleaded regular gasoline		2.75		2.05
USGC spot ultra-low sulfur diesel		2.97		2.16

Refining & Marketing intersegment sales to our Speedway segment were $8.30 billion in 2011 compared to $7.39 billion in 2010. Intersegment refined product sales volumes were 2.66 billion gallons in 2011 compared to 3.11 billion gallons in 2010, with the decreased volumes primarily due to the Minnesota Assets disposition.

Speedway segment revenues increased $996 million from 2010 to 2011, mainly due to higher gasoline and distillates selling prices, which averaged $3.44 per gallon in 2011 compared to $2.70 per gallon in 2010. These impacts were partially offset by decreased gasoline and distillates sales volumes and lower merchandise sales primarily due to the Minnesota Assets disposition in December 2010.

Income before income taxes and income from operations by segment are summarized in the following table.

(In millions)	2011		2010
Income from operations by segment:
Refining & Marketing	$	3,591	$	800
Speedway		271		293
Pipeline Transportation		199		183
Items not allocated to segments:
Corporate and other unallocated items (a)		(316)		(236)
Impairments (b)		-		(29)
Income from operations		3,745		1,011
Net interest and other financial income (costs) (c)		(26)		12
Income before income taxes	$	3,719	$	1,023

^(a)  Corporate and other unallocated items consists primarily of MPC’s corporate administrative expenses, including allocations from Marathon Oil for periods prior to the Spinoff, and costs related to certain non-operating assets.

^(b)  The impairment in 2010 was related to a maleic anhydride plant.

^(c)  Includes related party net interest and other financial income.

The following table presents certain market indicators that we believe are helpful in understanding the results of our Refining & Marketing segment’s business.

(Dollars per barrel)	2011		2010
Chicago LLS 6-3-2-1 (a)(b)	$	3.81	$	3.02
USGC LLS 6-3-2-1 (a)		2.84		2.13
Blended 6-3-2-1 (a)(c)		3.35		2.64
LLS		112.37		82.83
WTI		95.11		79.61
LLS - WTI differential (a)		17.26		3.22
Sweet/Sour differential (a)(d)		9.11		7.57

^(a)  All spreads and differentials are measured against prompt LLS.

^(b)  Calculation utilizes USGC 3% Bunker value as a proxy for Chicago residual fuel price.

^(c)  Blended Chicago/USGC crack spread is 53%/47% in 2011 and 57%/43% in 2010 based on MPC’s refining capacity by region in each period.

^(d)  LLS (prompt) - [delivered cost of sour crude oil: Arab Light, Kuwait, Maya, Western Canadian Select and Mars].

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Refining & Marketing segment income from operations increased $2.79 billion in 2011 from 2010, primarily due to a higher refining and marketing gross margin per barrel, which averaged $7.75 per barrel in 2011 compared to $2.81 per barrel in 2010. Our realized refining and marketing gross margin for 2011 improved from 2010 primarily due to wider differentials between WTI and other light sweet crudes such as LLS, larger LLS 6-3-2-1 crack spreads, and wider sweet/sour differentials. The discount of WTI to LLS increased $14.04 per barrel as a result of logistical constraints in the U.S. mid-continent markets, which prevented the price of WTI from rising with the prices of crudes produced in other regions. We estimate this had a $1.69 billion positive impact on our refining and marketing gross margin. The Chicago and USGC LLS 6-3-2-1 crack spreads increased $0.79 per barrel and $0.71 per barrel, respectively, and we estimate this had a $349 million positive impact on our refining and marketing gross margin. The sweet/sour differential widened $1.54 per barrel and we estimate this had a $277 million positive impact on our refining and marketing gross margin. Within our refining system, sour crude accounted for 52 percent and 54 percent of our crude oil processed in 2011 and 2010, respectively. Direct operating costs declined $248 million from 2010 to 2011, primarily due to a $188 million reduction in planned turnaround and major maintenance costs, which also contributed to the increase in gross margin.

The following table summarizes our refinery throughputs for 2011 and 2010.

(mbpd)	2011		2010
Refinery Throughputs:
Crude oil refined		1,177		1,173
Other charge and blendstocks		181		162
Total		1,358		1,335

Our total refinery throughputs were two percent higher in 2011 compared to 2010, primarily due to improved refinery utilization and decreased turnaround activity in 2011 compared to 2010, primarily at our Garyville refinery, partially offset by the sale of the St. Paul Park refinery in December 2010. Crude oil refined was essentially flat in 2011 compared to 2010, while other charge and blendstock throughputs increased 12 percent over the same period.

The following table includes certain key operating statistics for the Refining & Marketing segment for 2011 and 2010.

	2011		2010
Refining & Marketing gross margin (Dollars per barrel) (a)	$	7.75	$	2.81
Direct operating costs in Refining & Marketing gross margin (Dollars per barrel): (b)
Planned turnaround and major maintenance	$	0.78	$	1.19
Depreciation and amortization		1.29		1.32
Other manufacturing (c)		3.16		3.32
Total	$	5.23	$	5.83
Refined products sales volumes (mbpd) (d)		1,581		1,573

^(a)  Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation and amortization, divided by Refining & Marketing segment refined product sales volumes.

^(b)  Per barrel of total refinery throughputs.

^(c)  Includes utilities, labor, routine maintenance and other operating costs.

^(d)  Includes intersegment sales.

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Speedway segment income from operations decreased $22 million from 2010 to 2011, with $45 million attributable to the sale of 166 convenience stores that were part of the Minnesota Assets disposition in December 2010 and $33 million attributable to increased operating expenses partially due to higher employee costs. These decreases were partially offset by a $30 million increase associated with a higher gasoline and distillates gross margin and a $26 million increase associated with a higher merchandise gross margin. Speedway’s gasoline and distillates gross margin per gallon averaged 13.08 cents in 2011, compared with 12.07 cents in 2010. Gasoline and distillates sales volumes declined in 2011 primarily reflecting the sale of the Minnesota Assets. Merchandise gross margin was $719 million in 2011 compared to $789 million in 2010, also reflecting the Minnesota Assets disposition.

Same-store gasoline sales volume decreased 1.7 percent in 2011 compared to 2010, while same-store merchandise sales excluding cigarettes increased 6.7 percent for the same period. The primary factor affecting same store gasoline sales volume was the higher average retail price of gasoline.

Pipeline Transportation segment income from operations increased $16 million in 2011 from 2010. The increase primarily reflects the absence of non-routine maintenance and impairment expenses incurred in 2010, partially offset by a reduction in income from pipeline equity method investments. Refined product throughput volumes increased seven percent in 2011 compared to 2010, while crude oil throughput volumes decreased two percent in the same period.

Corporate and other unallocated items increased $80 million in 2011 compared to 2010 due to higher information technology, employee benefits and other administrative expenses, partially resulting from costs associated with being a stand-alone company. Following the Spinoff, we no longer receive allocated corporate overhead costs from Marathon Oil.

Impairment expense in 2010 was a $29 million property impairment related to a maleic anhydride plant, which was operated by our Refining & Marketing segment.

Liquidity and Capital Resources

Cash Flows

Our cash and cash equivalents balance was $4.86 billion at December 31, 2012 compared to $3.08 billion at December 31, 2011. Net cash provided by (used in) operating activities, investing activities and financing activities for the past three years is presented in the following table.

(In millions)	2012		2011		2010
Net cash provided by (used in):
Operating activities	$	4,492	$	3,309	$	2,217
Investing activities		(1,452)		1,295		(2,145)
Financing activities		(1,259)		(1,643)		(82)
Total	$	1,781	$	2,961	$	(10)

Net cash provided from operating activities increased $1.18 billion in 2012 compared to 2011, primarily due to higher net income and noncash income adjustments in 2012, partially offset by changes in working capital. Net cash provided from operating activities increased $1.09 billion in 2011 compared to 2010, primarily due to higher net income in 2011, partially offset by changes in working capital and lower deferred income taxes.

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Changes in working capital were a net $428 million use of cash in 2012, primarily due to a decrease in accounts payable and accrued liabilities resulting primarily from reductions in crude oil prices and payable volumes, partially offset by a decrease in accounts receivable resulting primarily from reductions in crude oil prices and receivable volumes. Changes in working capital were a net $13 million source of cash in 2011, primarily due to an increase in accounts payable and accrued liabilities resulting primarily from increases in crude oil prices and payable volumes, partially offset by an increase in accounts receivable resulting primarily from increases in crude oil prices and receivable volumes and refined product prices. Changes in working capital were a net $318 million source of cash in 2010, primarily due to an increase in accounts payable and accrued liabilities resulting primarily from increases in crude oil prices and payable volumes, partially offset by an increase in accounts receivable resulting primarily from increases in crude oil and refined product prices and crude oil receivable volumes.

Cash flows from investing activities decreased $2.75 billion in 2012 compared to 2011 and increased $3.44 billion in 2011 compared to 2010. The investing activity is further discussed below.

The consolidated statements of cash flows exclude changes to the consolidated balance sheets that did not affect cash. A reconciliation of additions to property, plant and equipment to reported total capital expenditures and investments follows for each of the last three years.

(In millions)	2012			2011		2010
Additions to property, plant and equipment	$	1,369		$	1,185	$	1,217
Acquisitions (a)		180			74		-
Increase (decrease) in capital accruals		(117	)		53		(51	)
Total capital expenditures		1,432			1,312		1,166
Investments in equity method investees		28			11		7
Total capital expenditures and investments	$	1,460		$	1,323	$	1,173

^(a)  Excludes inventory acquired and liability assumed in 2012.

Capital expenditures and investments for each of the last three years are summarized by segment below.

(In millions)	2012		2011		2010
Refining & Marketing	$	705	$	900	$	961
Speedway (a)		340		164		84
Pipeline Transportation		211		121		24
Corporate and Other (b)		204		138		104
Total	$	1,460	$	1,323	$	1,173

^(a) Includes acquisitions of 97 convenience stores in 2012 and 23 convenience stores in 2011. See Item 8. Financial Statements and Supplementary Data - Note 6.

^(b) Includes capitalized interest of $101 million, $114 million and $103 million in 2012, 2011 and 2010, respectively.

The Detroit refinery heavy oil upgrading and expansion project, which we completed in 2012, comprised 46 percent, 59 percent and 50 percent (excluding capitalized interest associated with this project) of our Refining & Marketing segment capital spending in 2012, 2011 and 2010, respectively.

Cash used in acquisitions, as presented on the consolidated statements of cash flows, totaled $190 million in 2012 and $74 million in 2011, which relates to the 97 convenience stores Speedway acquired in 2012 and the 23 convenience stores Speedway acquired in 2011.

Cash provided by disposal of assets totaled $53 million, $144 million and $763 million in 2012, 2011 and 2010, respectively. The $53 million of cash from asset disposals in 2012 primarily included proceeds from a settlement

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agreement with the buyer of our Minnesota Assets. The $144 million of cash from asset disposals in 2011 primarily included the collection of a receivable associated with the sale of the Minnesota Assets. In 2010, disposal of assets primarily included proceeds from the original sale of the Minnesota Assets.

Net investments in related party debt securities was a source of cash of $2.40 billion in 2011 and a use of cash of $1.69 billion in 2010. All such activity reflected the net cash flow from redemptions and purchases of PFD preferred stock. Prior to the Spinoff, all investments in PFD preferred stock were redeemed, and the agreement with PFD was terminated. See Item 8. Financial Statements and Supplementary Data - Note 5 for further discussion of our investments in PFD preferred stock.

Net cash used in financing activities totaled $1.26 billion in 2012, $1.64 billion in 2011 and $82 million in 2010. The net use of cash in 2012 was primarily due to the common stock repurchases under our ASR programs and dividend payments, partially offset by proceeds from the issuance of MPLX common units. The use of cash in 2011 was primarily due to the net repayment of debt payable to Marathon Oil and its subsidiaries and net distributions to Marathon Oil, partially offset by cash provided from the issuance of long-term debt. These 2011 activities were undertaken to effect the Spinoff. The year 2011 also included a use of cash of $60 million for debt issuance costs associated with the $3.0 billion of senior notes, our $2.0 billion revolving credit agreement and our $1.0 billion trade receivables securitization facility. See Item 8. Financial Statements and Supplementary Data - Note 20 for additional information on our long-term debt. The net use of cash in 2010 was primarily due to distributions to Marathon Oil, partially offset by net borrowings of debt payable to Marathon Oil.

Cash used in common stock repurchases totaled $1.35 billion in 2012 associated with the share repurchase plan authorized by our board of directors. We entered into an $850 million ASR program on February 3, 2012, under which we repurchased 20,357,380 shares at an average cost of $41.75 per share, and a $500 million ASR program on November 5, 2012, under which we received 7,403,294 shares as of December 31, 2012 and 870,947 shares in February 2013. See Item 8. Financial Statements and Supplementary Data - Note 10 for further discussion of the share repurchase plan.

Cash used in dividend payments increased $247 million in 2012 compared to 2011, primarily due to having a full year of dividend payments in 2012 and a 75 percent increase in our base dividend since July 2011, partially offset by a decrease in the number of outstanding shares of our common stock attributable to the ASR programs. Our quarterly dividend began at 20 cents per common share in July 2011 and has increased to 35 cents per common share as of December 31, 2012.

Cash proceeds from the issuance of MPLX common units was $407 million in 2012, of which $203 million was distributed by MPLX to MPC, in partial consideration of assets we contributed to MPLX and to reimburse us for certain capital expenditures incurred with respect to those assets. The initial public offering represented the sale of a 26.4 percent interest in MPLX. See Item 8. Financial Statements and Supplementary Data - Note 4 for further discussion of MPLX and its initial public offering.

Net borrowings and repayments under our long-term debt payable to Marathon Oil and its subsidiaries was a use of cash of $3.62 billion in 2011 compared with a source of cash of $1.26 billion in 2010. The agreements with Marathon Oil and its subsidiaries were terminated in 2011. See Item 8. Financial Statements and Supplementary Data - Note 5 for further discussion of these financing agreements.

Net distributions to Marathon Oil totaled $783 million in 2011 and $1.33 billion in 2010. The net distribution in 2011 was primarily related to $1.47 billion in net cash distributions paid to Marathon Oil, partially offset by income taxes it incurred on our behalf. The net distribution in 2010 was primarily related to $1.48 billion in cash distributions paid to Marathon Oil.

Derivative Instruments

See Item 7A. Quantitative and Qualitative Disclosures about Market Risk for a discussion of derivative instruments and associated market risk.

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Capital Resources

Our intention is to maintain an investment grade credit profile. As of December 31, 2012, our liquidity totaled $7.86 billion consisting of:

(In millions)	December 31, 2012
Cash and cash equivalents	$	4,860
Revolving credit agreement(a)		2,000
Trade receivables securitization facility		1,000
Total	$	7,860

^(a)  Excludes MPLX’s revolving credit agreement and does not give effect to subsequent increase in capacity to $2.5 billion.

As of December 31, 2012, we had no borrowings or letters of credit outstanding under our revolving credit agreement or our trade receivables securitization facility.

Because of the alternatives available to us, including internally generated cash flow and access to capital markets, we believe that our short-term and long-term liquidity is adequate to fund not only our current operations, but also our near-term and long-term funding requirements, including capital spending programs, the repurchase of shares of our common stock, dividend payments, defined benefit plan contributions, repayment of debt maturities and other amounts that may ultimately be paid in connection with contingencies.

On September 14, 2012, we entered into a five-year revolving credit agreement (the “Credit Agreement”) with a syndicate of lenders and terminated our previous four-year revolving credit agreement. The Credit Agreement was amended on December 20, 2012 to increase the borrowing capacity by $500 million to a total of $2.5 billion. The commitment increase became effective on February 1, 2013 in conjunction with the acquisition of the Galveston Bay Refinery and Related Assets. The Credit Agreement includes letter of credit issuing capacity of up to $2.0 billion and swingline loan capacity of up to $100 million. We may increase the borrowing capacity under the Credit Agreement by up to an additional $500 million, subject to certain conditions including the consent of the lenders whose commitments would be increased. In addition, we may request that the term of the Credit Agreement, which expires on September 14, 2017, be extended for up to two additional one-year periods. Each such extension would be subject to the approval of lenders holding greater than 50 percent of the commitments then outstanding, and the commitment of any lender that does not consent to an extension of the maturity date will be terminated on the then-effective maturity date.

The Credit Agreement contains representations and warranties, affirmative and negative covenants and events of default that we consider usual and customary for an agreement of this type. The financial covenant included in the Credit Agreement requires us to maintain, as of the last day of each fiscal quarter, a ratio of Consolidated Net Debt (as defined in the Credit Agreement) to Total Capitalization (as defined in the Credit Agreement) of no greater than 0.65 to 1.00. As of December 31, 2012, we were in compliance with this debt covenant with a ratio of Consolidated Net Debt to Total Capitalization of -0.1 to 1.00, as well as the other covenants contained in the Credit Agreement. In addition, the Credit Agreement includes limitations on the indebtedness of our subsidiaries, other than subsidiaries that guarantee our obligations under the Credit Agreement and our ability, and the ability of our subsidiaries, to incur liens on property or assets or enter into certain transactions with affiliates.

Borrowings of revolving loans under the Credit Agreement bear interest at either (i) the sum of the Adjusted LIBO Rate (as defined in the Credit Agreement) and a margin ranging between 1.00 percent to 2.00 percent, depending on our credit ratings, or (ii) the sum of the Alternate Base Rate (as defined in the Credit Agreement) and a margin ranging between zero percent to 1.00 percent, depending on our credit ratings. The Credit Agreement also provides for customary fees, including administrative agent fees, annual commitment fees ranging from 0.10 percent to 0.35 percent, depending on our credit ratings, on the unused portion, fees in respect to letters of credit and other fees.

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On September 14, 2012, MPLX Operations LLC, an affiliate of MPC and wholly-owned subsidiary of MPLX, as the borrower, and MPLX, as the parent guarantor, entered into a five-year revolving credit agreement (“MPLX Credit Agreement”) with a syndicate of lenders. The MPLX Credit Agreement became effective following MPLX’s initial public offering and has an initial borrowing capacity of $500 million. MPLX may increase the borrowing capacity under the MPLX Credit Agreement by up to an additional $300 million, subject to certain conditions, including the consent of the lenders whose commitments would be increased. The MPLX Credit Agreement includes letter of credit issuing capacity of up to $250 million and swingline loan capacity of up to $50 million. MPLX may, subject to certain conditions, request that the term of the MPLX Credit Agreement, which expires on October 31, 2017, be extended for up to two additional one-year periods. Each such extension would be subject to the approval of lenders holding greater than 50 percent of the commitments then outstanding, and the commitment of any lender that does not consent to an extension of the maturity date will be terminated on the then-effective maturity date. At December 31, 2012, MPLX had no borrowings or letters of credit outstanding under this agreement.

The MPLX Credit Agreement contains representations and warranties, affirmative and negative covenants and events of default that we consider usual and customary for an agreement of that type. The financial covenant included in the MPLX Credit Agreement requires MPLX to maintain a ratio of Consolidated Total Debt (as defined in the MPLX Credit Agreement) as of the end of each fiscal quarter to Consolidated EBITDA (as defined in the MPLX Credit Agreement) for the prior four fiscal quarters of not greater than 5.0 to 1.0 (or 5.5 to 1.0 during the six-month period following certain acquisitions). As of December 31, 2012, MPLX was in compliance with this debt covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of 0.1 to 1.0, as well as the other covenants contained in the MPLX Credit Agreement.

Borrowings of revolving loans under the MPLX Credit Agreement bear interest at either (i) the sum of the Adjusted LIBO Rate (as defined in the MPLX Credit Agreement) and a margin ranging from 1.00 percent to 2.00 percent or (ii) the sum of the Alternate Base Rate (as defined in the MPLX Credit Agreement) and a margin ranging from zero percent to 1.00 percent. Prior to MPLX receiving a rating from Standard & Poor’s Rating Group or Moody’s Investor Service, Inc. for its Index Debt (as defined in the MPLX Credit Agreement), the margin that is added to the applicable interest rate is based on MPLX’s ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA for the prior four fiscal quarters. Once MPLX receives a rating, the margin added to the applicable interest rate will be based on MPLX’s credit ratings. The MPLX Credit Agreement also provides for customary fees, including administrative agent fees, commitment fees ranging from 0.10 percent to 0.35 percent of the unused portion, depending on MPLX’s ratio of Consolidated Total Debt to Consolidated EBITDA for the prior four fiscal quarters prior to the rating date, or MPLX’s credit ratings subsequent to the rating date, fronting and issuance fees in respect to letters of credit and other fees.

As of December 31, 2012, the credit ratings on our senior unsecured debt were at or above investment grade level as follows.

Rating Agency	Rating
Moody’s	Baa2 (stable outlook)
Standard & Poor’s	BBB (stable outlook)

The ratings reflect the respective views of the rating agencies. Although it is our intention to maintain a credit profile that supports an investment grade rating, there is no assurance that these ratings will continue for any given period of time. The ratings may be revised or withdrawn entirely by the rating agencies if, in their respective judgments, circumstances so warrant.

Neither our Credit Agreement, the MPLX Credit Agreement nor our trade receivables securitization facility contain credit rating triggers that would result in the acceleration of interest, principal or other payments in the event that our credit ratings are downgraded. However, any downgrades of our senior unsecured debt to below investment grade ratings would increase the applicable interest rates, yields and other fees payable under our

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Credit Agreement, the MPLX Credit Agreement and trade receivables securitization facility. In addition, a downgrade of our senior unsecured debt rating to below investment grade levels could, under certain circumstances, decrease the amount of trade receivables that are eligible to be sold under our trade receivables securitization facility and could potentially impact our ability to purchase crude oil on an unsecured basis.

Debt-to-Total-Capital Ratio

Our debt-to-total capital ratio (total debt to total debt-plus-equity) was 22 percent and 26 percent at December 31, 2012 and 2011, respectively.

	December 31,
(In millions)	2012		2011
Long-term debt due within one year	$	19	$	15
Long-term debt		3,342		3,292
Total debt	$	3,361	$	3,307
Calculation of debt-to-total capital ratio:
Total debt	$	3,361	$	3,307
Plus equity		12,105		9,505
Total debt plus equity	$	15,466	$	12,812
Debt-to-total capital ratio		22%		26%

Capital Requirements

We have a capital and investment budget for 2013 of $1.62 billion, excluding capitalized interest and the purchase price for the Galveston Bay Refinery and Related Assets. Additional details related to the 2013 capital and investment budget are discussed in the Outlook section below.

On February 1, 2013, we acquired the Galveston Bay Refinery and Related Assets for approximately $598 million plus approximately $900 million for inventory. Pursuant to the purchase and sale agreement, we may also be required to pay BP a contingent earnout of up to an additional $700 million over six years, subject to certain conditions. This acquisition was paid for with cash on hand.

We plan to make contributions of approximately $160 million to our funded pension plans in 2013.

On January 30, 2013, our board of directors approved a 35 cents per share dividend, payable March 11, 2013 to stockholders of record at the close of business on February 20, 2013.

On February 1, 2012, we announced that our board of directors authorized a share repurchase plan, enabling us to purchase up to $2.0 billion of our common stock. On January 30, 2013, our board of directors approved an additional $2.0 billion share repurchase authorization and extended the unused amounts remaining on the February 1, 2012 authorization, with both authorizations ending December 2014. After the effects of the ASR programs described below, $2.65 billion of the $4.0 billion total share repurchase authorization is available. We may utilize various methods to effect the repurchases, which could include open market purchases, negotiated block transactions, ASRs or open market solicitations for shares, some of which may be effected through Rule 10b5-1 plans. The timing of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.

On February 3, 2012, we entered into an $850 million ASR program with a major financial institution as part of this authorization. Under this ASR program, we received 20,357,380 shares of our common stock in 2012, resulting in an average per share cost for these shares of $41.75.

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On November 5, 2012, we entered into a second ASR program for $500 million. Under this ASR program, we received 7,403,294 shares of our common stock in 2012 and 870,947 shares in February 2013, for a total of 8,274,241 repurchased shares, which concluded this ASR program. Upon final settlement, the average per share cost for all shares purchased under this ASR program was $60.43.

These ASR programs are accounted for as treasury stock purchase transactions, reducing the weighted average number of basic and diluted common shares outstanding by the repurchased shares, and as forward contracts indexed to our common stock.

The above discussion of the share repurchase authorization includes forward-looking statements. Factors that could affect the share repurchase plan and its timing include, but are not limited to business conditions, availability of liquidity, and the market price of our common stock. These factors, among others, could cause actual results to differ materially from those set forth in the forward-looking statements.

Contractual Cash Obligations

The table below provides aggregated information on our consolidated obligations to make future payments under existing contracts as of December 31, 2012. The contractual obligations detailed below do not include our contractual obligations to MPLX under various fee-based commercial agreements as these transactions are eliminated in the consolidated financial statements. The contractual obligations detailed below include amounts paid at closing for the Galveston Bay Refinery and Related Assets, but do not include obligations assumed upon closing.

(In millions)	Total		2013		2014-2015		2016-2017		Later Years
Long-term debt (a)	$	5,878	$	169	$	332	$	1,039	$	4,338
Capital lease obligations		546		44		89		87		326
Operating lease obligations		612		151		254		129		78
Purchase obligations: (b)
Crude oil, feedstock, refined product and renewable fuel contracts (c)(d)		11,545		10,302		765		395		83
Transportation and related contracts		1,700		144		267		315		974
Contracts to acquire property, plant and equipment (e)(f)		1,391		834		410		147		-
Service and materials contracts (g)		1,315		355		339		216		405
Total purchase obligations		15,951		11,635		1,781		1,073		1,462
Other long-term liabilities reported in the consolidated balance sheet (h)		1,101		247		274		144		436
Total contractual cash obligations	$	24,088	$	12,246	$	2,730	$	2,472	$	6,640

^(a)  Includes interest payments for our senior notes and commitment and administrative fees for our Credit Agreement, the MPLX Credit Agreement and our trade receivables securitization facility.

^(b)  Includes both short- and long-term purchases obligations.

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^(c)  These contracts include variable price arrangements with estimated prices to be paid primarily based on current market conditions. We are in the process of implementing systems that will allow us to estimate prices based on futures curves, which as of December 31, 2012, has been implemented for contracts with purchase obligations of $1.78 billion.

^(d)  Includes the approximate value of inventories included in the purchase of the Galveston Bay Refinery and Related Assets, which was completed on February 1, 2013. See Item 8. Financial Statements and Supplementary Data - Note 26.

^(e)  Includes approximately $598 million in 2013 for the purchase of the Galveston Bay Refinery and Related Assets and $700 million for the contingent earnout provision. The acquisition was completed on February 1, 2013. See Item 8. Financial Statements and Supplementary Data - Note 26.

^(f)  Includes obligations to advance funds to equity method investees.

^(g)  Includes contracts to purchase services such as utilities, supplies and various other maintenance and operating services.

^(h)  Primarily includes obligations for pension and other postretirement benefits including medical and life insurance, which we have estimated through 2022. See Item 8. Financial Statements and Supplementary Data - Note 22.

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 United States. Although off-balance sheet arrangements serve a variety of our business purposes, we are not dependent on these arrangements to maintain our liquidity and capital resources, and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources.

We have provided various guarantees related to equity method investees. In conjunction with the Spinoff, we entered into various indemnities and guarantees to Marathon Oil. These arrangements are described in Item 8. Financial Statements and Supplementary Data - Note 25.

Outlook

We have a capital and investment budget for 2013 of $1.62 billion, excluding capitalized interest and the purchase price for the Galveston Bay Refinery and Related Assets. This represents a 19 percent increase from our 2012 spending, which is primarily due to increases in the Refining & Marketing segment. The budget includes spending on refining, retail marketing, transportation, logistics and brand marketing projects as well as amounts designated for corporate activities. We continuously evaluate our capital budget and make changes as conditions warrant.

Refining & Marketing

The 2013 capital budget includes $1.02 billion for our Refining & Marketing segment. The Refining & Marketing capital budget includes approximately $400 million for our Galveston Bay Refinery and Related Assets for synergy capital and the continuation of infrastructure investments and other programs begun by the prior owner.

At our Garyville refinery, we have projects underway to optimize diesel and gasoline yields through modifications to the older crude unit, hydrocracker and the distillate hydrotreaters. Total capital spending is estimated at $225 million with projected capital spending of $117 million in 2013. The hydrocracker revamp is expected to be completed in 2014 and the completion of the final phase of the program is expected in 2015.

At our Robinson refinery, we have a $75 million project to revamp our distillate hydrocracker to improve margins by processing more feedstock at a lower conversion and shifting approximately 10 mbpd of other products to diesel production. The amount of capital spending budgeted for this project in 2013 is $15 million. The project is expected to be completed in 2015.

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At our Catlettsburg refinery, we have a $25 million project underway to recover additional volumes of gas oil from the refinery’s residual oil production to be processed in the fluidized catalytic cracker, thus increasing the production of higher valued gasoline and diesel. The amount of capital spending budgeted for this project in 2013 is $9 million. This project is expected to be completed in 2014.

Our Refining & Marketing and Pipeline Transportation segments have approximately $300 million of capital projects that will allow us to process and handle crude oil and condensate from the Utica Shale region, of which approximately $110 million have been budgeted for in 2013. We have projects to invest in condensate splitters at our Canton and Catlettsburg refineries to allow the refineries to process up to 60 mbpd of condensate from the Utica Shale region. In addition, we have a truck-to-barge crude system project at our Wellsville asphalt terminal and expect to purchase new barges to allow Utica production to be transported from our Wellsville terminal to our Catlettsburg refinery.

The remaining budget is primarily allocated to maintaining facilities and meeting regulatory requirements at our refineries.

Speedway

The 2013 capital budget includes $255 million for our Speedway segment, relating to new construction and acquisitions to expand our markets and remodeling and rebuilding projects for existing convenience stores to upgrade and enhance our existing facilities. Also included in the capital budget are expenditures for dispenser, equipment and technology upgrades.

Pipeline Transportation

The 2013 capital budget includes $184 million for our Pipeline Transportation segment, primarily for upgrades to replace or enhance our existing facilities, including our Patoka to Catlettsburg crude oil pipeline upgrade, and new infrastructure.

Corporate and Other

The remaining 2013 capital budget includes $160 million, primarily related to upgrades to information technology systems.

In addition, we expect to record $43 million in capitalized interest, which is 57 percent less than 2012 primarily due to the completion of the Detroit refinery heavy oil upgrading and expansion project.

Our opinions concerning liquidity and capital resources 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 by 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 and capital resources above also contains forward-looking statements regarding expected capital and investment spending, costs for projects under construction, project completion dates and expectations or projections about strategies and goals for growth, upgrades and expansion. The forward-looking statements about our capital and investment budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include prices of and demand for crude oil and refinery feedstocks and refined products, actions of competitors, delays in obtaining necessary third-party approvals, changes in labor, materials, and equipment costs and availability, planned and unplanned outages, the delay of, cancellation of or failure to implement planned capital projects, project cost

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overruns, disruptions or interruptions of our refining operations due to the shortage of skilled labor and unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military response, and other operating and economic considerations.

Transactions with Related Parties

Following completion of the Spinoff on June 30, 2011, Marathon Oil retained no ownership interest in us and is no longer a related party.

Purchases of crude oil and natural gas from Marathon Oil accounted for five percent or less of our total cost of revenues and purchases from related parties for the periods prior to the Spinoff. Related party purchases of crude oil and natural gas from Marathon Oil were at market-based contract prices. The crude oil prices were based on indices that represented market value for time and place of delivery and that were also used in third-party contracts. The natural gas prices equaled the price at which Marathon Oil purchased the natural gas from third parties plus the cost of transportation.

We believe that transactions with related parties, other than certain transactions with Marathon Oil to effect the Spinoff and related to the provision of administrative services, were conducted under terms comparable to those with unrelated parties.

On May 25, 2011, we entered into a separation and distribution agreement and several other agreements with Marathon Oil to effect the Spinoff and to provide a framework for our relationship with Marathon Oil. Because the terms of our separation from Marathon Oil and these agreements were entered into in the context of a related-party transaction, the terms may not be comparable to terms that would be obtained in a transaction between unaffiliated parties. See Item 8. Financial Statements and Supplementary Data—Note 5 for further discussion of activity with related parties.

Environmental Matters and Compliance Costs

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, production processes and whether it is also engaged in the petrochemical business or the marine transportation of crude oil and refined products.

Legislation and regulations pertaining to fuel specifications, 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.

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Our environmental expenditures, based on the American Petroleum Institute’s definition of environmental expenditures, for each of the last three years were:

(In millions)	2012		2011		2010
Capital	$	115	$	167	$	223
Compliance:
Operating and maintenance		318		354		403
Remediation(a)		24		27		20
Total	$	457	$	548	$	646

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

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

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

Our environmental capital expenditures accounted for 8 percent, 13 percent and 19 percent of capital expenditures in 2012, 2011 and 2010, respectively. Our environmental capital expenditures are expected to approximate $41 million, or three percent, of total capital expenditures in 2013. Predictions beyond 2013 can only be broad-based estimates, which have varied, and will continue to vary, due to the ongoing evolution of specific regulatory requirements, the possible imposition of more stringent requirements and the availability of new technologies, among other matters. Based on currently identified projects, we anticipate that environmental capital expenditures will be approximately $86 million in 2014; however, actual expenditures may vary as the number and scope of environmental projects are revised as a result of improved technology or changes in regulatory requirements and could increase if additional projects are identified or additional requirements are imposed.

We spent $620 million from 2008 through 2011 to comply with MSAT II regulations relating to benzene content in refined products. All MSAT II compliance units were in operation in 2011.

For more information on environmental regulations that impact us, or could impact us, see Item 1. Business—Environmental 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 United States (“US GAAP”) 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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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 amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. 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 does 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. We use a market or income approach for recurring fair value measurements and endeavor to use the best information available. See Item 8. Financial Statements and Supplementary Data—Note 18 for disclosures regarding our fair value measurements.

Significant uses of fair value measurements include:

• assessment of impairment of long-lived assets;

• assessment of impairment of goodwill;

• assessment of impairment of equity method investments;

• recorded value of derivative instruments; and

• recorded value of investments in debt and equity securities.

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Impairment Assessments of Long-Lived Assets, Goodwill and Equity Method Investments

Fair value calculated for the purpose of testing our long-lived assets, goodwill and equity method investments for impairment is estimated using the expected present value of 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:

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

• Future volumes.     Our estimates of future pipeline throughput volumes are based on internal forecasts prepared by our Pipeline Transportation segment operations personnel.

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

• Future capital requirements.    These are based on 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.

The need to test for impairment can be based on several indicators, including a significant reduction in prices of or demand for products produced, a poor outlook for profitability, a significant reduction in pipeline throughput volumes, significant reduction in refining margins, other changes to contracts or changes in the regulatory environment in which the asset or equity method investment is located.

Long-lived assets used in operations are assessed for impairment whenever changes in facts and circumstances indicate that the carrying value of the assets may not be recoverable. For purposes of impairment evaluation, long-lived assets must be grouped at the lowest level for which independent cash flows can be identified, which generally is the refinery and associated distribution system level for Refining & Marketing segment assets, site level for Speedway segment convenience stores or the pipeline system level for Pipeline Transportation segment assets. If the sum of the undiscounted estimated pretax cash flows is less than the carrying value of an asset group, fair value is calculated, and the carrying value is written down if greater than the calculated 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. At December 31, 2012, we had a total of $930 million of goodwill recorded on our consolidated balance sheet. The fair value of our reporting units exceeded book value appreciably for each of our reporting units in 2012.

Equity method investments are assessed for impairment whenever factors indicate an other than temporary loss in value. Factors providing evidence of such a loss include the fair value of an investment that is less than its carrying value, absence of an ability to recover the carrying value or the investee’s inability to generate income sufficient to justify our carrying value. At December 31, 2012, we had $321 million of investments in equity method investments recorded in our consolidated balance sheet.

An estimate of the sensitivity to net income resulting from impairment calculations is not practicable, given the numerous assumptions (e.g., pricing, volumes 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.

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Derivatives

We record all derivative instruments at fair value. A large volume of our commodity derivatives are exchange-traded and require few assumptions in arriving at fair value. Fair value estimation for all our derivative instruments is discussed in Item 8. Financial Statements and Supplementary Data - Note 18. Additional information about derivatives and their valuation may be found in Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

Pension and Other Postretirement Benefit Obligations

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

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

• the expected long-term return on plan assets;

• the rate of future increases in compensation levels; and

• health care cost projections.

We develop our demographics and utilize the work of third-party actuaries to assist in the measurement of these obligations. We have selected different discount rates for our funded pension plans and our unfunded retiree health care plans due to the different projected benefit payment patterns. The selected rates are compared to various similar bond indexes for reasonableness. In determining the assumed discount rates, we use 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 Aa 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 and only non-callable bonds are included. Outlier bonds that have a yield to maturity that deviate significantly from the average yield within each maturity grouping are not included. Each issue is required to have at least $250 million par value outstanding.

Of the assumptions used to measure the year-end obligations and estimated annual net periodic benefit cost, the discount rate has the most significant effect on the periodic benefit cost reported for the plans. Decreasing the discount rates of 3.45 percent for our pension plans and 4.05 percent for our other postretirement benefit plans by 0.25 percent would increase pension obligations and other postretirement benefit plan obligations by $85 million and $21 million, respectively, and would increase defined benefit pension expense and other postretirement benefit plan expense by $6 million and $2 million, respectively.

The long-term asset rate of return assumption considers the asset mix of the plans (currently targeted at approximately 75 percent equity securities and 25 percent fixed income securities for the funded pension plans), past performance and other factors. Certain components of the asset mix are modeled with various assumptions regarding inflation and returns. In addition, our long-term asset rate of return assumption is compared to those of other companies and to historical returns for reasonableness. After evaluating activity in the capital markets, we reduced the asset rate of return from 8.50 percent to 7.50 percent effective for 2012. We have also used the 7.50 percent long-term rate of return to determine our 2013 defined benefit pension expense. Decreasing the 7.50 percent asset rate of return assumption by 0.25 percent would increase our defined benefit pension expense by $4 million.

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 22 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 loss reported on the year-end balance sheets.

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Contingent Liabilities

We accrue contingent liabilities for legal actions, claims, litigation, environmental remediation, tax deficiencies related to operating taxes and third-party indemnities for specified tax matters when such contingencies are both probable and estimable. We regularly assess these estimates in consultation with legal counsel to consider resolved and new matters, material developments in court proceedings or settlement discussions, new information obtained as a result of ongoing discovery and past experience in defending and settling similar matters. 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 degree of 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.

We generally record losses related to these types of contingencies as cost of revenues or selling, general and administrative expenses in the consolidated statements of income, except for tax deficiencies unrelated to income taxes, which are recorded as other taxes. For additional information on contingent liabilities, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Environmental Matters and Compliance Costs.

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 February 2013, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update that requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. If the amount reclassified is required under US GAAP to be reclassified to net income in its entirety in the same reporting period, an entity is required to present, either on the face of the financial statements or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income. For other amounts not required to be reclassed in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional detail about those amounts. The accounting standards update is effective prospectively for annual periods beginning after December 15, 2012, and interim periods within those annual periods. Adoption of this accounting standards update in the first quarter of 2013 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

In July 2012, the FASB issued an accounting standards update that gives an entity the option to first assess qualitatively whether it is more likely than not that an indefinite-lived intangible asset is impaired. If, through the qualitative assessment, an entity determines that it is more likely than not that the intangible asset is impaired, the quantitative impairment test must then be performed. The accounting standards update is effective for annual and interim impairment tests performed in fiscal years beginning after September 15, 2012. Early adoption is permitted. Adoption of this accounting standards update in the first quarter of 2013 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

In December 2011, the FASB issued an accounting standards update which was amended in January 2013 that requires disclosure of additional information related to recognized derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are offset or are not offset but are subject to an enforceable netting agreement. The purpose of the requirement is to help users evaluate the effect or potential effect of offsetting and related netting arrangements on an entity’s financial position. The update is to be applied retrospectively and is effective for annual periods that begin on or after January 1, 2013 and interim periods within those annual periods. Adoption of this update is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

General

We are exposed to market risks related to the volatility of crude oil and refined product prices. We employ various strategies, including the use of commodity derivative instruments, to hedge 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. As of December 31, 2012, we did not have any financial derivative instruments to hedge the risks related to interest rate fluctuations; however, we have used them in the past and we continually monitor the market and our exposure and may enter into these agreements again in the future. We are at risk for changes in 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 18 and 19 for more information about the fair value measurement of our derivatives, as well as the amounts recorded in our consolidated balance sheets and statements of income. We do not designate any of our commodity derivative instruments as hedges for accounting purposes.

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. We use a variety of commodity derivative instruments, including futures, forwards, swaps and combinations of options, as part of an overall program to hedge commodity price risk. We also authorize the use of the market knowledge gained from these activities to do a limited amount of trading not directly related to our physical transactions.

We use commodity derivative instruments on crude oil and refined product inventories to hedge price risk associated with inventories above or below last-in, first-out inventory targets. We also use derivative instruments related to the acquisition of foreign-sourced crude oil and ethanol blended with refined petroleum products to hedge price risk associated with market volatility between the time we purchase the product and when we use it in the refinery production process or it is blended. In addition, we may use commodity derivative instruments on fixed price contracts for the sale of refined products to hedge risk by converting the refined product sales to market-based prices. The majority of these derivatives are exchange-traded contracts for crude oil, refined products and ethanol.

We closely monitor and hedge our exposure to market risk on a daily basis in accordance with policies approved by our board of directors. Our positions are monitored daily by a risk control group to ensure compliance with our stated risk management policy.

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Open Derivative Positions and Sensitivity Analysis

The table below sets forth information relating to our significant open commodity derivative contracts as of December 31, 2012.

	December 31, 2012
	Position		Total Barrels (In thousands)			Weighted Average Price (Per barrel)		Benchmark
Crude Oil (a)
Exchange-traded		Long		15,643		$	97.45	CME and ICE  Crude(b)(c)
Exchange-traded		Short		(26,191	)	$	99.41	CME and ICE  Crude(b)(c)
	Position		Total Barrels (In thousands)			Weighted Average Price (Per gallon)		Benchmark
Refined Products (a)
Exchange-traded		Long		2,720		$	2.86	CME Heating Oil and RBOB(b)(d)
Exchange-traded		Short		(3,429	)	$	2.89	CME Heating Oil and RBOB(b)(d)

^(a)  100 percent of these contracts expire in the first quarter of 2013.

^(b)  Chicago Mercantile Exchange (“CME”).

^(c)  Intercontinental Exchange (“ICE”)

^(d)  Reformulated Gasoline Blendstock for Oxygenate Blending (“RBOB”).

Sensitivity analysis of the incremental effects on income from operations (“IFO”) of hypothetical 10 percent and 25 percent increases and decreases in commodity prices for open commodity derivative instruments as of December 31, 2012 is provided in the following table.

	Incremental Change in IFO from a Hypothetical Price Increase of						Incremental Change in IFO from a Hypothetical Price Decrease of
(In millions)	10%			25%			10%		25%
As of December 31, 2012
Crude	$	(96	)	$	(240	)	$	111	$	284
Refined products		(7	)		(18	)		12		37

We remain at risk for possible changes in the market value of commodity derivative instruments; however, such risk should be mitigated by price changes in the underlying physical commodity. Effects of these offsets are not reflected in the above sensitivity analysis.

We evaluate our portfolio of commodity derivative instruments on an ongoing basis and add or revise strategies in anticipation of changes in market conditions and in risk profiles. Changes to the portfolio after December 31, 2012 would cause future IFO effects to differ from those presented above.

Interest Rate Risk

We are impacted by interest rate fluctuations related to our debt obligations. At December 31, 2012, our debt was primarily comprised of the $3.0 billion fixed rate senior notes issued on February 1, 2011.

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Sensitivity analysis of the projected incremental effect of a hypothetical 100-basis-point shift in interest rates on financial assets and liabilities as of December 31, 2012 is provided in the following table.

(In millions)	Fair Value			Incremental Change in Fair Value
Financial assets (liabilities) (a)
Long-term debt (b)	$	(3,559)	(c)	$	364	(d)

^(a)  Fair value of cash and cash equivalents, receivables, 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)  Excludes capital leases.

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

^(d)  Assumes a 100-basis-point decrease in the weighted average yield-to-maturity at December 31, 2012.

At December 31, 2012, 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.

Foreign Currency Exchange Rate Risk

We are impacted by foreign exchange rate fluctuations related to some of our purchases of crude oil denominated in Canadian Dollars. We did not utilize derivatives to hedge our market risk exposure to these foreign exchange rate fluctuations in 2012.

Counterparty Risk

We are also exposed to financial risk in the event of nonperformance by counterparties or futures commission merchants. We regularly review the creditworthiness of counterparties and futures commission merchants and enter into master netting agreements when appropriate.

Forward-Looking Statements

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 crude oil, other refinery feedstocks, refined products and ethanol. 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		77
Management’s Report on Internal Control Over Financial Reporting		77
Report of Independent Registered Public Accounting Firm		78
Audited Consolidated Financial Statements:
Consolidated Statements of Income		79
Consolidated Statements of Comprehensive Income		80
Consolidated Balance Sheets		81
Consolidated Statements of Cash Flows		82
Consolidated Statements of Equity / Net Investment		83
Notes to Consolidated Financial Statements		84
Select Quarterly Financial Data (Unaudited)		131
Supplementary Statistics (Unaudited)		132

76

Management’s Responsibilities for Financial Statements

To the Stockholders of Marathon Petroleum Corporation:

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

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

The board of directors pursues its oversight role in the area of financial reporting and internal control over financial reporting through its Audit 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/ Gary R. Heminger	/s/ Donald C. Templin	/s/ Michael G. Braddock
President and Chief Executive Officer	Senior Vice President and Chief Financial Officer	Vice President and Controller

Management’s Report on Internal Control over Financial Reporting

To the Stockholders of Marathon Petroleum Corporation:

MPC’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Securities Exchange Act of 1934). An evaluation of the design and effectiveness of our internal control over financial reporting, based on the framework 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, MPC’s management concluded that its internal control over financial reporting was effective as of December 31, 2012.

The effectiveness of MPC’s internal control over financial reporting as of December 31, 2012 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.

/s/ Gary R. Heminger	/s/ Donald C. Templin
President and Chief Executive Officer	Senior Vice President and Chief Financial Officer

77

Report of Independent Registered Public Accounting Firm

To the Stockholders of Marathon Petroleum Corporation:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, comprehensive income, equity/net investment, and cash flows present fairly, in all material respects, the financial position of Marathon Petroleum Corporation and its subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company’s internal control over financial reporting based on our audits (which were integrated audits in 2012 and 2011). 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

Toledo, Ohio

February 28, 2013

78

Marathon Petroleum Corporation

Consolidated Statements of Income

(In millions, except per share data)	2012			2011			2010
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$	82,235		$	78,583		$	62,387
Sales to related parties		8			55			100
Income from equity method investments		26			50			70
Net gain on disposal of assets		177			12			11
Other income		46			59			37
Total revenues and other income		82,492			78,759			62,605
Costs and expenses:
Cost of revenues (excludes items below)		68,668			65,795			51,731
Purchases from related parties		280			1,916			2,593
Consumer excise taxes		5,709			5,114			5,208
Depreciation and amortization		995			891			941
Selling, general and administrative expenses		1,223			1,059			874
Other taxes		270			239			247
Total costs and expenses		77,145			75,014			61,594
Income from operations		5,347			3,745			1,011
Related party net interest and other financial income		1			35			24
Net interest and other financial income (costs)		(110	)		(61	)		(12	)
Income before income taxes		5,238			3,719			1,023
Provision for income taxes		1,845			1,330			400
Net income		3,393			2,389			623
Less net income attributable to noncontrolling interests		4			-			-
Net income attributable to MPC	$	3,389		$	2,389		$	623
Per Share Data (See Note 9)
Basic:
Net income attributable to MPC per share	$	9.95		$	6.70		$	1.75
Weighted average shares outstanding		340			356			356
Diluted:
Net income attributable to MPC per share	$	9.89		$	6.67		$	1.74
Weighted average shares outstanding		342			357			358
Dividends paid	$	1.20		$	0.45		$	-

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

79

Marathon Petroleum Corporation

Consolidated Statements of Comprehensive Income

(In millions)	2012		2011			2010
Net income	$	3,393	$	2,389		$	623
Other comprehensive income (loss):
Defined benefit postretirement and post-employment plans:
Actuarial changes, net of tax of $47, ($151) and ($20)		78		(248	)		(108	)
Prior service costs, net of tax of $203, $2 and $3		337		4			5
Other, net of tax of $-, $- and $-		-		(1	)		-
Other comprehensive income (loss)		415		(245	)		(103	)
Comprehensive income		3,808		2,144			520
Less comprehensive income attributable to noncontrolling interests		4		-			-
Comprehensive income attributable to MPC	$	3,804	$	2,144		$	520

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

80

Marathon Petroleum Corporation

Consolidated Balance Sheets

	December 31,
(In millions, except per share data)	2012			2011
Assets
Current assets:
Cash and cash equivalents	$	4,860		$	3,079
Receivables, less allowance for doubtful accounts of $10 and $3		4,610			5,461
Inventories		3,449			3,320
Other current assets		110			141
Total current assets		13,029			12,001
Equity method investments		321			302
Property, plant and equipment, net		12,643			12,228
Goodwill		930			842
Other noncurrent assets		300			372
Total assets	$	27,223		$	25,745
Liabilities
Current liabilities:
Accounts payable	$	6,785		$	8,189
Payroll and benefits payable		364			312
Consumer excise taxes payable		325			337
Accrued taxes		598			558
Long-term debt due within one year		19			15
Other current liabilities		112			180
Total current liabilities		8,203			9,591
Long-term debt		3,342			3,292
Deferred income taxes		2,050			1,310
Defined benefit postretirement plan obligations		1,266			1,783
Deferred credits and other liabilities		257			264
Total liabilities		15,118			16,240
Commitments and contingencies (see Note 25)
Equity
MPC stockholders’ equity:
Preferred stock, no shares issued and outstanding (par value $0.01 per share, 30 million shares authorized)		-			-
Common stock:
Issued - 361 million and 357 million shares (par value $0.01 per share, 1 billion shares authorized)		4			4
Held in treasury, at cost - 28 million shares at December 31, 2012		(1,253	)		-
Additional paid-in capital		9,527			9,482
Retained earnings		3,880			898
Accumulated other comprehensive loss		(464	)		(879	)
Total MPC stockholders’ equity		11,694			9,505
Noncontrolling interests		411			-
Total equity		12,105			9,505
Total liabilities and equity	$	27,223		$	25,745

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

81

Marathon Petroleum Corporation

Consolidated Statements of Cash Flows

(In millions)	2012			2011			2010
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	3,393		$	2,389		$	623
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		995			891			941
Pension and other postretirement benefits, net		153			(90	)		13
Deferred income taxes		492			123			308
Net gain on disposal of assets		(177	)		(12	)		(11	)
Equity method investments, net		11			(2	)		(34	)
Changes in the fair value of derivative instruments		59			(57	)		(16	)
Changes in:
Current receivables		851			(1,177	)		(750	)
Inventories		(115	)		(255	)		(76	)
Current accounts payable and accrued liabilities		(1,223	)		1,502			1,160
All other, net		53			(3	)		59
Net cash provided by operating activities		4,492			3,309			2,217
Investing activities:
Additions to property, plant and equipment		(1,369	)		(1,185	)		(1,217	)
Acquisitions		(190	)		(74	)		-
Disposal of assets		53			144			763
Investments in related party debt securities – purchases		-			(10,326	)		(9,709	)
– redemptions		-			12,730			8,019
Investments – loans and advances		(57	)		(56	)		(45	)
– redemptions and repayments		108			53			44
All other, net		3			9			-
Net cash provided by (used in) investing activities		(1,452	)		1,295			(2,145	)
Financing activities:
Long-term debt payable to Marathon Oil and subsidiaries – borrowings		-			7,748			18,804
– repayments		-			(11,366	)		(17,544	)
Long-term debt – borrowings		-			2,989			-
– repayments		(17	)		(12	)		(12	)
Debt issuance costs		(6	)		(60	)		-
Issuance of common stock		108			1			-
Common stock repurchased		(1,350	)		-			-
Dividends paid		(407	)		(160	)		-
Net proceeds from issuance of MPLX LP common units		407			-			-
Distributions to Marathon Oil		-			(783	)		(1,330	)
All other, net		6			-			-
Net cash used in financing activities		(1,259	)		(1,643	)		(82	)
Net increase (decrease) in cash and cash equivalents		1,781			2,961			(10	)
Cash and cash equivalents at beginning of period		3,079			118			128
Cash and cash equivalents at end of period	$	4,860		$	3,079		$	118

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

82

Marathon Petroleum Corporation

Consolidated Statements of Equity / Net Investment

	MPC Stockholders’ Equity / Net Investment
(In millions)	Common Stock		Treasury Stock			Additional Paid-in Capital			Retained Earnings			Net Investment			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests		Total Equity /Net Investment
Balance as of December 31, 2009	$	-	$	-		$	-		$	-		$	9,692		$	(520	)	$	-	$	9,172
Net income		-		-			-			-			623			-			-		623
Distributions to Marathon Oil		-		-			-			-			(1,448	)		-			-		(1,448	)
Other comprehensive loss		-		-			-			-			-			(103	)		-		(103	)
Balance as of December 31, 2010	$	-	$	-		$	-		$	-		$	8,867		$	(623	)	$	-	$	8,244
Net income		-		-			-			1,058			1,331			-			-		2,389
Dividends paid		-		-			-			(160	)		-			-			-		(160	)
Distributions to Marathon Oil		-		-			-			-			(726	)		(11	)		-		(737	)
Other comprehensive loss		-		-			-			-			-			(245	)		-		(245	)
Shares issued - stock-based compensation		-		-			9			-			-			-			-		9
Stock-based compensation		-		-			5			-			-			-			-		5
Reclassification of net investment to additional paid-in capital		-		-			9,472			-			(9,472	)		-			-		-
Issuance of common stock at spinoff		4		-			(4	)		-			-			-			-		-
Balance as of December 31, 2011	$	4	$	-		$	9,482		$	898		$	-		$	(879	)	$	-	$	9,505
Net income		-		-			-			3,389			-			-			4		3,393
Dividends paid		-		-			-			(407	)		-			-			-		(407	)
Other comprehensive income		-		-			-			-			-			415			-		415
Shares repurchased		-		(1,250	)		(100	)		-			-			-			-		(1,350	)
Shares issued (returned) - stock based compensation		-		(3	)		108			-			-			-			-		105
Stock-based compensation		-		-			46			-			-			-			-		46
Issuance of MPLX LP common units		-		-			-			-			-			-			407		407
Other		-		-			(9	)		-			-			-			-		(9	)
Balance as of December 31, 2012	$	4	$	(1,253)		$	9,527		$	3,880		$	-		$	(464)		$	411	$	12,105
(Shares in millions)	Common Stock		Treasury Stock
Balance as of December 31, 2010		-		-
Shares issued - stock-based compensation		1		-
Issuance of common stock at spinoff		356		-
Balance as of December 31, 2011		357		-
Shares repurchased		-		(28	)
Shares issued - stock-based compensation		4		-
Balance as of December 31, 2012		361		(28	)

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

83

Notes to Consolidated Financial Statements

1. Description of the Business, Spinoff and Basis of Presentation

Description of the Business – Our business consists of refining and marketing, retail marketing and pipeline transportation operations conducted primarily in the Midwest, Gulf Coast and Southeast regions of the United States, through subsidiaries, including Marathon Petroleum Company LP, Speedway LLC and MPLX LP and its subsidiaries (“MPLX”).    Until December 1, 2010, we also had operations in the Upper Great Plains region of the United States.

See Note 11 for additional information about our operations.

Spinoff – On May 25, 2011, the Marathon Oil Corporation (“Marathon Oil”) board of directors approved the spinoff of its Refining, Marketing & Transportation Business (“RM&T Business”) into an independent, publicly traded company, Marathon Petroleum Corporation (“MPC”), through the distribution of MPC common stock to the stockholders of Marathon Oil common stock.    In accordance with a separation and distribution agreement between Marathon Oil and MPC, the distribution of MPC common stock was made on June 30, 2011, with Marathon Oil stockholders receiving one share of MPC common stock for every two shares of Marathon Oil common stock held (the “Spinoff”).    Following the Spinoff, Marathon Oil retained no ownership interest in MPC, and each company had separate public ownership, boards of directors and management.    All subsidiaries and equity method investments not contributed by Marathon Oil to MPC remained with Marathon Oil and, together with Marathon Oil, are referred to as the “Marathon Oil Companies.” On July 1, 2011, our common stock began trading “regular-way” on the New York Stock Exchange under the ticker symbol “MPC”.

Basis of Presentation – Prior to the Spinoff on June 30, 2011, our results of operations and cash flows consisted of the RM&T Business, which represented a combined reporting entity.    Subsequent to the Spinoff, our results of operations and cash flows consist of consolidated MPC activities.    All significant intercompany transactions and accounts have been eliminated.

The consolidated statements of income for periods prior to the Spinoff included expense allocations for certain corporate functions historically performed by the Marathon Oil Companies, including allocations of general corporate expenses related to executive oversight, accounting, treasury, tax, legal, procurement and information technology.    Those allocations were based primarily on specific identification, headcount or computer utilization.    Our management believes the assumptions underlying the consolidated financial statements, including the assumptions regarding allocating general corporate expenses from the Marathon Oil Companies, are reasonable.    However, these consolidated financial statements do not include all of the actual expenses that would have been incurred had we been a stand-alone company during the periods presented prior to the Spinoff and may not reflect our consolidated results of operations and cash flows had we been a stand-alone company during the periods presented.    Actual costs that would have been incurred if we had been a stand-alone company would depend upon multiple factors, including organizational structure and strategic decisions made in various areas, including information technology and infrastructure.    Subsequent to the Spinoff, we are performing these functions using internal resources or services provided by third parties, certain of which were provided by the Marathon Oil Companies during a transition period pursuant to a transition services agreement, which terminated June 30, 2012.    See Note 5.

During 2012, we reclassified certain expenses from selling, general and administrative expenses to cost of revenues, which is consistent with expense classifications for MPLX, MPC’s consolidated subsidiary.    Historical periods were also reclassified to conform to the current year presentation.    This reclassification resulted in an increase in cost of revenues and a decrease in selling, general and administrative expenses of $47 million and $46 million for 2011 and 2010, respectively.

84

2. Summary of Principal Accounting Policies

Principles applied in consolidation – These consolidated financial statements include the accounts of our majority-owned, controlled subsidiaries.    We consolidate MPLX, in which we own a 73.6 percent controlling financial interest, and we record a noncontrolling interest for the 26.4 percent interest owned by the public.

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 shareholders have substantive participating rights in the investee.    Income from equity method investments represents our proportionate share of net income generated by the equity method investees.

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 values 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.

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.

Revenue recognition – Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured.    Costs associated with revenues are recorded in cost of revenues.    Shipping and other transportation costs billed to customers are presented on a gross basis in revenues and cost of revenues.

Rebates from vendors are recognized as a reduction of cost of revenues when the initiating transaction occurs.    Incentives that are derived from contractual provisions are accrued based on past experience and recognized in cost of revenues.

Crude oil and refined product exchanges and matching buy/sell transactions – We enter into exchange contracts and matching buy/sell arrangements whereby we agree to deliver a particular quantity and quality of crude oil or refined products at a specified location and date to a particular counterparty and to receive from the same counterparty the same commodity at a specified location on the same or another specified date.    The exchange receipts and deliveries are nonmonetary transactions, with the exception of associated grade or location differentials that are settled in cash.    The matching buy/sell purchase and sale transactions are settled in cash.    Both exchange and matching buy/sell transactions are accounted for as exchanges of inventory and no revenues are recorded.    The exchange transactions are recognized at the carrying amount of the inventory transferred.

Consumer excise taxes – We are required by various governmental authorities, including countries, states and municipalities, to collect and remit taxes on certain consumer products.    Such taxes are presented on a gross basis in revenues and costs and expenses in the consolidated statements of income.

Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit, reverse repurchase agreements and investments in highly liquid debt instruments with maturities generally of three months or less.

85

Accounts receivable and allowance for doubtful accounts – Our receivables primarily consist of customer accounts receivable, including proprietary credit card receivables.    The allowance for doubtful accounts is the best estimate of the amount of probable credit losses in customer accounts receivable, primarily associated with our proprietary credit card receivables.    We determine the allowance based on historical write-off experience and the volume of proprietary credit card sales.    We review the allowance quarterly and past-due balances over 180 days are reviewed individually for collectability.    All other customer receivables are recorded at the invoiced amounts and generally do not bear interest.    Account balances for these customer receivables are generally charged directly to bad debt expense when it becomes probable the receivable will not be collected.

Approximately 42 percent and 47 percent of our accounts receivable balances at December 31, 2012 and 2011, respectively, are related to sales of crude oil or refinery feedstocks to customers with whom we have master netting agreements.    We have master netting agreements with more than 80 companies engaged in the crude oil or refinery feedstock trading and supply business or the petroleum refining industry.    A master netting agreement generally provides for a once per month net cash settlement of the accounts receivable from and the accounts payable to a particular counterparty.

Inventories – Inventories are carried at the lower of cost or market value.    Cost of inventories is determined primarily under the last-in, first-out (“LIFO”) method.

Derivative instruments – We use derivatives to economically hedge a portion of our exposure to commodity price risk and interest rate risk.    We also have limited authority to use selective derivative instruments that assume market risk.    All derivative instruments are recorded at fair value.    Commodity derivatives are reflected on the consolidated balance sheets on a net basis by futures commission merchant, as they are governed by master netting agreements.    Cash flows related to derivatives used to hedge commodity price risk and interest rate risk are classified in operating activities with the underlying transactions.

Fair value accounting hedges – We used interest rate swaps to hedge our exposure to interest rate risk associated with fixed interest rate debt in our portfolio.    Changes in the fair values of both the hedged item and the related derivative were recognized immediately in net income with an offsetting effect included in the basis of the hedged item.    The net effect was to report in net income the extent to which the accounting hedge was not effective in achieving offsetting changes in fair value.    We terminated our interest rate swap agreements during 2012.    There was a gain on the termination of the agreements, which has been accounted for as an adjustment to our long-term debt balance.    The gain is being amortized over the remaining life of the associated debt, which reduces our interest expense.

Derivatives not designated as accounting hedges –Derivatives that are not designated as accounting hedges may include commodity derivatives used to hedge price risk on (1) inventories, (2) fixed price sales of refined products, (3) the acquisition of foreign-sourced crude oil and (4) the acquisition of ethanol for blending with refined products.    Changes in the fair value of derivatives not designated as accounting hedges are recognized immediately in net income.

Contingent credit features – Our derivative instruments contain no significant contingent credit features.

Concentrations of credit risk – All of our financial instruments, including derivatives, involve elements of credit and market risk.    The most significant portion of our credit risk relates to 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 an assessment of their financial strength and on credit ratings, if available.    Additionally, we limit the level of exposure with any single counterparty.

86

Property, plant and equipment – Property, plant and equipment are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which range from four to 42 years.    Such assets are reviewed for impairment 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.

When items of property, plant and equipment 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.

Interest expense is capitalized for qualifying assets under construction.    Capitalized interest costs are included in property, plant and equipment and are depreciated over the useful life of the related asset.

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.    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, the implied fair value of goodwill is calculated.    The excess, if any, of the book value over the implied fair value of goodwill is charged to net income.

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

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

Asset retirement obligations – The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made.    Conditional asset retirement obligations for removal and disposal of fire-retardant material from certain refining facilities have been recognized.    The fair values recorded for such obligations are based on the most probable current cost projections.    The recorded asset retirement obligations are not material to the consolidated financial statements.

Asset retirement obligations have not been recognized for some assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate.    Such obligations will be recognized in the period when sufficient information becomes available to estimate a range of potential settlement dates.    The asset retirement obligations principally include the removal of underground storage tanks at our owned and some of our leased convenience stores at or near the time of closure and hazardous material disposal and removal or dismantlement requirements associated with the closure of certain refining, terminal and pipeline assets.

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Our practice is to keep our assets in good operating condition through routine repair and maintenance of component parts in the ordinary course of business and by continuing to make improvements based on technological advances.    As a result, we believe that these assets have no expected settlement date for purposes of estimating asset retirement obligations since the dates or ranges of dates upon which we would retire these assets cannot be reasonably estimated at this time.

Income taxes – For periods prior to the Spinoff, our taxable income was included in the consolidated U.S. federal income tax returns of Marathon Oil and in a number of consolidated state income tax returns.    In the accompanying consolidated financial statements, for periods prior to the Spinoff our provision for income taxes was computed as if we were a stand-alone tax-paying entity.

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.    Deferred tax assets are recorded when it is more likely than not that they will be realized.    The realization of deferred tax assets is assessed periodically based on several factors, primarily our expectation to generate sufficient future taxable income.

Stock-based compensation arrangements – The fair value of stock options and stock-settled stock appreciation rights (collectively, “stock option awards”) granted to our employees is estimated on the date of grant using the Black-Scholes option pricing model.    The model employs various assumptions, based on management’s estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the vesting period 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.    The average expected life is based on our historical employee exercise behavior.    The assumption for expected volatility of our stock price reflects a weighting of 25 percent of our common stock volatility and 75 percent of the historical volatility for a selected group of peer companies.

The fair value of restricted stock awards granted to our employees is determined based on the fair market value of our common stock on the date of grant.

Our stock-based compensation expense is recognized based on management’s estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature.    If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods.    Unearned stock-based compensation is charged to equity when restricted stock awards are granted.    Compensation expense is recognized over the vesting period and is adjusted if conditions of the restricted stock award are not met.    For periods prior to the Spinoff, we recorded Marathon Oil stock-based compensation expense as non-cash capital contributions.

3. Accounting Standards

Recently Adopted

In September 2011, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update giving an entity the option to use a qualitative assessment to determine whether or not the entity is required to perform the two step goodwill impairment test.    If, through a qualitative assessment, an entity determines that it is more likely than not that the fair value of a reporting unit is less than the carrying amount, the entity is required to perform the two step goodwill impairment test.    The amendments in the update were effective for annual and interim goodwill testing performed in fiscal years beginning after December 15, 2011.    The adoption of this accounting standards update in the first quarter of 2012 did not have an impact on our consolidated results of operations, financial position or cash flows.    We perform the annual goodwill impairment testing for each of our reporting units in the fourth quarter.

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In June 2011, the FASB amended the reporting standards for comprehensive income to eliminate the option to present the components of other comprehensive income as part of the statement of changes in equity and to require reclassification adjustments from accumulated other comprehensive income to be measured and presented by income statement line item in net income and also in other comprehensive income.    All non-owner changes in 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 other comprehensive income and the total of comprehensive income.    This accounting standards update does not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income.    In December 2011, the FASB issued an accounting standards update to defer the presentation requirements of the reclassification adjustments from accumulated other comprehensive income.    This accounting standards update, as modified, was adopted using the two statement approach in the fourth quarter of 2011 and was applied retrospectively for all prior periods presented.    The adoption of this accounting standards update, as modified, did not have an impact on our consolidated results of operations, financial position or cash flows.    In February 2013, the FASB issued an accounting standards update regarding the presentation requirements of the reclassification adjustments from accumulated other comprehensive income.    See the Not Yet Adopted section for more information.

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. generally accepted accounting principles (“US GAAP”) and International Financial Reporting Standards (“IFRS”).    The amendments change the wording used to describe certain of the US 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.    The amendments were to be applied prospectively and were effective in interim and annual periods beginning with the first quarter of 2012 with early application not permitted.    This accounting standards update was adopted in the first quarter of 2012 and was applied prospectively.    The adoption of these amendments did not have a significant impact on our consolidated results of operations, financial position or cash flows.    The new required disclosures are included in Note 18.

Not Yet Adopted

In February 2013, the FASB issued an accounting standards update that requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component.    If the amount reclassified is required under US GAAP to be reclassified to net income in its entirety in the same reporting period, an entity is required to present, either on the face of the financial statements or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income.    For other amounts not required to be reclassed in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional detail about those amounts.    The accounting standards update is effective prospectively for annual periods beginning after December 15, 2012, and interim periods within those annual periods.    Adoption of this accounting standards update in the first quarter of 2013 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

In July 2012, the FASB issued an accounting standards update that gives an entity the option to first assess qualitatively whether it is more likely than not that an indefinite-lived intangible asset is impaired.    If, through the qualitative assessment, an entity determines that it is more likely than not that the intangible asset is impaired, the quantitative impairment test must then be performed.    The accounting standards update is effective for annual and interim impairment tests performed in fiscal years beginning after September 15, 2012.    Early adoption is permitted.    Adoption of this accounting standards update in the first quarter of 2013 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

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In December 2011, the FASB issued an accounting standards update which was amended in January 2013 that requires disclosure of additional information related to recognized derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are offset or are not offset but are subject to an enforceable netting agreement.    The purpose of the requirement is to help users evaluate the effect or potential effect of offsetting and related netting arrangements on an entity’s financial position.    The update is to be applied retrospectively and is effective for annual periods that begin on or after January 1, 2013 and interim periods within those annual periods.    Adoption of this update is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

4. MPLX LP

MPLX is a publicly traded master limited partnership that was formed by us to own, operate, develop and acquire pipelines and other midstream assets related to the transportation and storage of crude oil, refined products and other hydrocarbon-based products.    Headquartered in Findlay, Ohio, MPLX’s initial assets consist of a 51 percent general partner interest in a network of common carrier crude oil and product pipeline systems and associated storage assets in the Midwest and Gulf Coast regions of the United States and a 100 percent interest in a butane storage cavern in West Virginia.

Initial Public Offering

On October 31, 2012, MPLX completed its initial public offering of 19,895,000 common units at a price to the public of $22.00 per unit, which included 2,595,000 common units purchased by the underwriters through an over-allotment option that was exercised in full by the underwriters.    Net proceeds to MPLX from the sale of the units were $407 million, net of underwriting discounts and commissions, structuring fees and offering expenses (the “Offering Costs”) of $31 million.    MPLX contributed $192 million to MPLX Pipe Line Holdings LP (“Pipe Line Holdings”), a subsidiary of MPLX, which Pipe Line Holdings will retain on behalf of MPLX and us to fund our respective pro rata portions of certain estimated expansion capital expenditures.    MPLX distributed net proceeds to us of $203 million, in partial consideration of assets contributed and to reimburse us for certain capital expenditures incurred with respect to those assets.    MPLX GP LLC, a wholly-owned subsidiary of MPC, serves as the general partner of MPLX.    We own a 73.6 percent interest in MPLX, including the general partner interest, and we consolidate this entity for financial reporting purposes since we have a controlling financial interest.    The initial public offering represented the sale of a 26.4 percent interest in MPLX.

The following table is a reconciliation of proceeds from the initial public offering:

(In millions)
Total proceeds from the initial public offering	$	438
Less: Offering Costs		(31)
Net proceeds from the initial public offering		407
Less: Revolving credit facility origination fees		(2)
Less: Cash retained by MPLX		(10)
Less: Cash contribution to Pipe Line Holdings		(192)
Net proceeds distributed to MPC from the initial public offering	$	203

Commercial Agreements

MPLX generates revenue primarily by charging tariffs for transporting crude oil, refined products and other hydrocarbon-based products through their pipelines and at their barge dock and fees for storing crude oil and products at their storage facilities.    They are also the operator of additional crude oil and product pipelines owned by us and third parties for which they are paid operating fees.    They do not take ownership of the crude oil or products that they transport and store for their customers, and they do not engage in the trading of any commodities.

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We have entered into long-term, fee-based transportation and storage services agreements with MPLX.    Under these agreements, MPLX provides transportation and storage services to us, and we commit to provide MPLX with minimum quarterly throughput and storage volumes of crude oil and products and minimum storage volumes of butane.    We believe the terms and conditions under these commercial agreements, as well as the other initial agreements we entered into with MPLX described below, are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services.

These commercial agreements include:

• three separate 10-year transportation services agreements and one five-year transportation services agreement under which we pay MPLX fees for transporting crude oil on each of their crude oil pipeline systems;

• four separate 10-year transportation services agreements under which we pay MPLX fees for transporting products on each of their product pipeline systems;

• a five-year transportation services agreement under which we pay MPLX fees for handling crude oil and products at their Wood River, Illinois barge dock;

• a 10-year storage services agreement under which we pay MPLX fees for providing storage services at their Neal, West Virginia butane cavern; and

• four separate three-year storage services agreements under which we pay MPLX fees for providing storage services at their tank farms.

All of the transportation services agreements for the crude oil and product pipeline systems (other than our Wood River, Illinois to Patoka, Illinois crude system) automatically renew for up to two additional five-year terms unless terminated by either party.    The transportation services agreements for the Wood River to Patoka crude system and the barge dock automatically renew for up to four additional two-year terms unless terminated by either party.    The butane cavern storage services agreement does not automatically renew.    The storage services agreements for the tank farms automatically renew for additional one-year terms unless terminated by either party.

Under the transportation services agreements, if we fail to transport our minimum throughput volumes during any quarter, then we will pay MPLX a deficiency payment equal to the volume of the deficiency multiplied by the tariff rate then in effect.    If the minimum capacity of the pipeline falls below the level of our commitment at any time or if capacity on the pipeline is required to be allocated among shippers because volume nominations exceed available capacity, depending on the cause of the reduction in capacity, our commitment may be reduced or we will receive a credit for our minimum volume commitment for that period.    In addition to our minimum volume commitment, we are responsible for any loading, handling, transfer and other charges with respect to volumes MPLX transports for us.    If MPLX agrees to make any capital expenditures at our request, we will reimburse MPLX for, or MPLX will have the right in certain circumstances, to file for an increased tariff rate to recover the actual cost of such capital expenditures.    The transportation services agreements include provisions that permit us to suspend, reduce or terminate our obligations under the applicable agreement if certain events occur.    These events include us deciding to permanently or indefinitely suspend refining operations at one or more of our refineries for at least twelve consecutive months and certain force majeure events that would prevent MPLX or us from performing under the applicable agreement.

Under the storage services agreements, MPLX is obligated to make available to us on a firm basis the available storage capacity at the tank farms and butane cavern, and we pay MPLX a per-barrel fee for such storage capacity, regardless of whether we fully utilize the available capacity.    Beginning on January 1, 2014, the storage services agreements will be adjusted based on changes in the producer price index.

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Operating Agreements

At the closing of the initial public offering of MPLX, we entered into an operating services agreement with MPLX under which MPLX operates various pipeline systems owned by us.    In addition, under existing operating service agreements, MPLX continues to operate various pipeline systems owned by us and third parties. Under these operating services agreements MPLX receives an operating fee for operating the assets and is reimbursed for all direct and indirect costs associated with operating the assets. The operating fees under most of these agreements are indexed for inflation. These agreements range from one to five years in length and automatically renew unless terminated by either party.

Management Services Agreements

Prior to the closing of the initial public offering of MPLX, MPLX entered into two management services agreements with us under which MPLX provides certain management services to us with respect to certain of our retained pipeline assets. MPLX receives fixed annual fees under the agreements for providing the required management services, initially in the amount of $0.7 million and thereafter adjusted annually for inflation and based on changes in the scope of management services provided.

Omnibus Agreement

Upon the closing of the initial public offering of MPLX, we entered into an omnibus agreement with MPLX that addresses MPLX’s payment of a fixed annual fee to us for the provision of executive management services and MPLX’s reimbursement to us for the provision of certain general and administrative services to MPLX, as well as our indemnification of MPLX for certain matters, including environmental, title and tax matters.

Employee Services Agreements

Prior to the closing of the initial public offering of MPLX, we entered into two employee services agreements with MPLX under which MPLX reimburses us for the provision of certain operational and management services in support of their pipelines, barge dock, butane cavern and tank farms.

5. Related Party Transactions

During 2012, 2011 and 2010 our related parties included:

• Marathon Oil Companies until June 30, 2011, the effective date of the Spinoff.

• The Andersons Clymers Ethanol LLC (“TACE”), in which we have a 36 percent interest, and The Andersons Marathon Ethanol LLC (“TAME”), in which we have a 50 percent interest. These companies each own an ethanol production facility.

• Centennial Pipeline LLC (“Centennial”), in which we have a 50 percent interest. Centennial owns a refined products pipeline and storage facility.

• LOOP LLC (“LOOP”), in which we have a 51 percent noncontrolling interest. LOOP owns and operates the only U.S. deepwater oil port.

• Other equity method investees.

We believe that transactions with related parties, other than certain administrative transactions with the Marathon Oil Companies to effect the Spinoff and related to the provision of services, were conducted on terms comparable to those with unaffiliated parties. See below for a description of transactions with the Marathon Oil Companies.

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On May 25, 2011, we entered into a separation and distribution agreement and several other agreements with the Marathon Oil Companies to effect the Spinoff and to provide a framework for our relationship with the Marathon Oil Companies. These agreements govern the relationship between us and Marathon Oil subsequent to the completion of the Spinoff and provide for the allocation between us and the Marathon Oil Companies of assets, liabilities and obligations attributable to periods prior to the Spinoff. Because the terms of these agreements were entered into in the context of a related party transaction, the terms may not be comparable to terms that would be obtained in a transaction between unaffiliated parties.

The separation and distribution agreement between us and the Marathon Oil Companies contains the key provisions relating to the separation of our business from Marathon Oil and the distribution of our common stock to Marathon Oil stockholders. The separation and distribution agreement identifies the assets that were transferred or sold, liabilities that were assumed or sold and contracts that were assigned to us by the Marathon Oil Companies or by us to the Marathon Oil Companies in the Spinoff and describes how these transfers, sales, assumptions and assignments occurred. In accordance with the separation and distribution agreement, Marathon Oil determined that our aggregate cash and cash equivalents balance at June 30, 2011 should be approximately $1.625 billion. The separation and distribution agreement also contains provisions regarding the release of liabilities, indemnifications, insurance, nonsolicitation of employees, maintenance of confidentiality, payment of expenses and dispute resolution. See Note 25.

We and Marathon Oil entered into a tax sharing agreement to govern the respective rights, responsibilities and obligations of Marathon Oil and us with respect to taxes and tax benefits, the filing of tax returns, the control of audits, restrictions on us to preserve the tax-free status of the Spinoff and other tax matters.

We and Marathon Oil entered into an employee matters agreement providing that each company has responsibility for our own employees and compensation plans. The employee matters agreement also contains provisions regarding stock-based compensation. See Note 23.

We entered into a transition services agreement with Marathon Oil under which we were providing each other with a variety of administrative services on an as-needed basis for a period of time not to exceed one year following the Spinoff. The charges under these transition service agreements were at cost-based rates that had been negotiated between us and Marathon Oil. Services provided to us by the Marathon Oil Companies included accounting, audit, treasury, tax, legal, information technology, administrative services, procurement of natural gas and health, environmental, safety and security. Services provided by us to the Marathon Oil Companies included legal, human resources, tax, accounting, audit, information technology and health, environmental, safety and security. The transition services agreement terminated on June 30, 2012.

Sales to related parties were as follows:

(In millions)	2012		2011		2010
Equity method investees:
Centennial	$	1	$	35	$	54
Other equity method investees		7		7		7
Marathon Oil Companies		-		13		39
Total	$	8	$	55	$	100

Related party sales to Centennial consist primarily of petroleum products. Related party sales to the Marathon Oil Companies consisted primarily of crude oil, which were based on contractual prices that were market-based, and pipeline operating revenue.

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The fees received for operating pipelines for related parties included in other income on the consolidated statements of income were as follows:

(In millions)	2012		2011		2010
Centennial	$	1	$	-	$	-

Purchases from related parties were as follows:

(In millions)	2012		2011		2010
Equity method investees:
Centennial	$	7	$	31	$	72
LOOP		44		66		35
TAME		124		153		109
TACE		73		46		34
Other equity method investees		32		30		56
Marathon Oil Companies		-		1,590		2,287
Total	$	280	$	1,916	$	2,593

Related party purchases from Centennial consist primarily of refinery feedstocks and refined product transportation costs. Related party purchases from LOOP and other equity method investees consist primarily of crude oil transportation costs. Related party purchases from TAME and TACE consist of ethanol. Related party purchases from the Marathon Oil Companies consisted primarily of crude oil and natural gas, which were recorded at contracted prices that were market-based.

The Marathon Oil Companies performed certain services for us prior to the Spinoff such as executive oversight, accounting, treasury, tax, legal, procurement and information technology services. We also provided certain services to the Marathon Oil Companies prior to the Spinoff, such as legal, human resources and tax services. The two groups of companies charged each other for these shared services based on a rate that was negotiated between them. Where costs incurred by the Marathon Oil Companies on our behalf could not practically be determined by specific utilization, these costs were primarily allocated to us based on headcount or computer utilization. Our management believes those allocations were a reasonable reflection of the utilization of services provided. However, those allocations may not have fully reflected the expenses that would have been incurred had we been a stand-alone company during the periods presented. Net charges from the Marathon Oil Companies for these services reflected within selling, general and administrative expenses in the consolidated statements of income were $26 million and $43 million for 2011 and 2010, respectively.

Receivables from related parties, which are included in receivables, less allowance for doubtful accounts on the consolidated balance sheets, were as follows:

	December 31,
(In millions)	2012		2011
Centennial	$	2	$	1
Other equity method investees		-		1
Total	$	2	$	2

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Payables to related parties, which are included in accounts payable on the consolidated balance sheets, were as follows:

	December 31,
(In millions)		2012		2011
Equity method investees:
Centennial	$	-	$	7
LOOP		4		5
TAME		5		4
TACE		2		2
Other equity method investees		2		2
Total	$	13	$	20

We have a throughput and deficiency agreement with LOOP, which had a prepaid tariff balance of $4 million at December 31, 2011. The prepaid tariff was utilized during 2012. We also had a throughput and deficiency agreement with Centennial, which expired on March 31, 2012. The prepaid balance was $11 million at December 31, 2011. Prepaid tariff balances are reflected in other noncurrent assets on the consolidated balance sheets. During 2012, we impaired our $14 million prepaid tariff with Centennial. For additional information on the impairment, see Note 18.

On July 18, 2007, we entered into a credit agreement with MOC Portfolio Delaware, Inc. (“PFD”), a subsidiary of Marathon Oil, providing for a $2.9 billion revolving credit facility which was scheduled to terminate on May 4, 2012. On October 28, 2010, we amended the credit agreement with PFD to increase the total amount available to $4.4 billion and extended the scheduled termination date to November 1, 2013. During 2011, we borrowed $7.75 billion and repaid $10.32 billion under the credit facility. During 2010, we borrowed $18.80 billion and repaid $17.54 billion under this credit facility. The agreement was terminated on June 30, 2011, and there has been no subsequent activity. For U.S. Dollar loans under this credit facility, the interest rate was the higher of the prime rate or the sum of 0.5 percent, plus the federal funds rate. For Euro Dollar loans under this credit facility, the interest rate was based on LIBOR plus a margin ranging from 0.25 percent to 1.125 percent. The margin varied based on our usage and credit rating.

On July 18, 2007, we entered into a $1.1 billion revenue bonds proceeds subsidiary loan agreement with Marathon Oil to finance a portion of our Garyville, Louisiana refinery major expansion project. Proceeds from the bonds were disbursed by Marathon Oil to us upon our request for reimbursement of expenditures related to the expansion. There were no borrowings in 2011 and 2010. We repaid the $1.05 billion loan balance on February 1, 2011 and the loan was terminated effective April 1, 2011. The loan had an interest rate of 5.125 percent annually.

In 2005, we entered into agreements with PFD to invest our excess cash. Such investments consisted of shares of PFD Redeemable Class A, Series 1 Preferred Stock (“PFD Preferred Stock”). We had the right to redeem all or any portion of the PFD Preferred Stock on any business day at $2,000 per share. Dividends on PFD Preferred Stock were declared and settled daily. All of our investments in PFD Preferred Stock were redeemed prior to the termination of this agreement on June 30, 2011.

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Related party net interest and other financial income was as follows:

(In millions)	2012		2011		2010
Dividend income:
PFD Preferred Stock	$	-	$	35	$	24
Interest income		1		-		-
Interest expense:
PFD revolving credit agreement		-		3		12
Marathon Oil loan agreement		-		5		54
Interest capitalized		-		(8)		(66)
Net interest expense		-		-		-
Related party net interest and other financial income	$	1	$	35	$	24

We also recorded property, plant and equipment additions related to capitalized interest incurred by Marathon Oil on our behalf of $2 million and $20 million in 2011 and 2010, which were reflected as contributions from Marathon Oil.

Certain asset or liability transfers between us and Marathon Oil, including assets and liabilities contributed under the separation and distribution agreement related to the Spinoff, and certain expenses, such as stock-based compensation, incurred by Marathon Oil on our behalf have been recorded as non-cash capital contributions or distributions. The net non-cash capital contributions from (distributions to) Marathon Oil were $57 million and ($118 million) in 2011 and 2010, respectively.

6. Acquisitions

In July 2012, Speedway LLC acquired 10 convenience stores located in the northern Kentucky and southwestern Ohio regions from Road Ranger LLC in exchange for cash and a truck stop location in the Chicago metropolitan area. In connection with this acquisition, our Speedway segment recorded $5 million of goodwill, which is deductible for income tax purposes.

In May 2012, Speedway LLC acquired 87 convenience stores situated throughout Indiana and Ohio from GasAmerica Services, Inc., along with the associated inventory, intangible assets and two parcels of undeveloped real estate. In connection with this acquisition, our Speedway segment recorded $83 million of goodwill, which is deductible for income tax purposes.

In May 2011, Speedway LLC acquired 23 convenience stores in Indiana and Illinois. In connection with this acquisition, our Speedway segment recorded $9 million of goodwill, which is deductible for income tax purposes.

These acquisitions support our strategic initiative to increase our Speedway segment sales. The principal factors contributing to a purchase price resulting in goodwill included the acquired stores complementing our existing network in our Midwest market, access to our refined product transportation systems and the potential for higher merchandise sales.

Assuming these transactions had been made at the beginning of any period presented, the consolidated pro forma results would not be materially different from reported results.

7. Disposition

On December 1, 2010, we completed the sale of most of our Minnesota assets. These assets included the 74,000 barrel per calendar day St. Paul Park refinery and associated terminals, 166 convenience stores primarily branded SuperAmerica^® (including six stores in Wisconsin), along with the SuperMom’s bakery

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(a baked goods and sandwich supply operation) and certain associated trademarks, SuperAmerica Franchising LLC, interests in pipeline assets in Minnesota and associated inventories. We refer to these assets as the “Minnesota Assets.” The refinery and terminal assets were part of our Refining & Marketing segment, the convenience stores and bakery were part of our Speedway segment, and the interests in pipeline assets were part of our Pipeline Transportation segment. This transaction value was approximately $935 million, which included approximately $330 million for inventories. We received $740 million in cash, net of closing costs, but prior to post-closing adjustments. The terms of the sale included (1) a preferred equity interest in the entity that holds the Minnesota Assets with a stated value of $80 million, (2) a maximum $125 million earnout provision payable to us over eight years, (3) a maximum $60 million of margin support payable to the buyer over two years, up to a maximum of $30 million per year, (4) a receivable from the buyer of $107 million which was fully collected in 2011, and (5) guarantees with a maximum exposure of $11 million made by us on behalf of and to the buyer related to a limited number of convenience store sites. As a result of this continuing involvement, the related gain on sale of $89 million was initially deferred.

In July 2012, the buyer of our Minnesota Assets successfully completed an initial public offering (“IPO”). The successful completion of this IPO triggered the provisions in our May 4, 2012 settlement agreement with the buyer to be effective. Under the settlement agreement, we were released from our obligation to pay margin support and the buyer was released from its obligation to pay us under the earnout provision contained in the original sales agreement. Also, the buyer redeemed our $80 million preferred equity interest, paid us $12 million for dividends accrued on our preferred equity interest and paid us $40 million of cash, for total cash receipts of $132 million. In addition, the buyer issued us a new preferred security valued at $45 million. As a result, we recognized income before income taxes of approximately $183 million during 2012, which included $86 million of the deferred gain that was recorded when the sale transaction was originally closed.

We provided transition services to the buyer for approximately thirteen months following the sale. The buyer provided management and operational strategy for the business and we provided personnel to operate and maintain these Minnesota Assets.

8. Variable Interest Entity

As described in Note 7, on December 1, 2010, we completed the sale of the Minnesota Assets. Certain terms of the transaction and the subsequent settlement agreement with the buyer resulted in the creation of variable interests in a variable interest entity (“VIE”) that owns the Minnesota Assets. At December 31, 2012, our variable interests in this VIE included our preferred security, which was reflected at $46 million in other noncurrent assets on our consolidated balance sheet at December 31, 2012, and store lease guarantees of $8 million. Our maximum exposure to loss due to this VIE at December 31, 2012 was $54 million.

We are not the primary beneficiary of this VIE and, therefore, do not consolidate it because we lack the power to control or direct the activities that impact the VIE’s operations and economic performance. Our preferred security does not allow us to appoint any members of the board of managers to the VIE and limits our voting ability to only certain matters. Also, individually and cumulatively, neither of our variable interests expose us to residual returns or expected losses that are significant to the VIE.

9. Income per Common Share

We compute basic earnings per share by dividing net income attributable to MPC shareholders by the weighted average number of shares of common stock outstanding. Diluted income per share assumes exercise of stock options and stock appreciation rights, provided the effect is not anti-dilutive.

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On June 30, 2011, 356,337,127 shares of our common stock were distributed to Marathon Oil stockholders in conjunction with the Spinoff. For comparative purposes, and to provide a more meaningful calculation for weighted average shares, we have assumed this amount to be outstanding as of the beginning of each period prior to the Spinoff presented in the calculation of basic weighted average shares. In addition, for the dilutive weighted average share calculations, we have assumed the dilutive securities outstanding at June 30, 2011 were also outstanding at each of the periods prior to the Spinoff presented. Excluded from the diluted share calculation are approximately two million, four million and four million shares related to stock-based compensation awards in 2012, 2011 and 2010, respectively, as their effect would be anti-dilutive.

MPC grants certain incentive compensation awards to employees and non-employee directors that are considered to be participating securities. Due to the presence of participating securities, we have calculated our earnings per share using the two-class method.

(In millions, except per share data)	2012		2011		2010
Basic earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	3,389	$	2,389	$	623
Income allocated to participating securities		6		4		1
Income available to common stockholders - basic	$	3,383	$	2,385	$	622
Weighted average common shares outstanding		340		356		356
Basic earnings per share	$	9.95	$	6.70	$	1.75
Diluted earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	3,389	$	2,389	$	623
Income allocated to participating securities		6		4		1
Income available to common stockholders - diluted	$	3,383	$	2,385	$	622
Weighted average common shares outstanding		340		356		356
Effect of dilutive securities		2		1		2
Weighted average common shares, including dilutive effect		342		357		358
Diluted earnings per share	$	9.89	$	6.67	$	1.74

10. Equity

Share repurchase plan – On February 1, 2012, we announced that our board of directors authorized a share repurchase plan, enabling us to purchase up to $2.0 billion of MPC common stock over a two-year period. On January 30, 2013, we announced that our board of directors approved an additional $2.0 billion share repurchase authorization. The board also extended the remaining $650 million share repurchase authorization announced on February 1, 2012, for a total outstanding authorization of $2.65 billion through December 2014. We may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, accelerated share repurchases or open market solicitations for shares, some of which may be effected through Rule 10b5-1 plans. The timing of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.

Accelerated share repurchase programs – On February 3, 2012, we entered into an $850 million accelerated share repurchase (“ASR”) program with a major financial institution to repurchase shares of MPC common stock under the approved share repurchase plan authorized by our board of directors. Under this ASR program, we received 17,581,344 shares of our common stock during the first quarter of 2012. On July 25, 2012, an additional 2,776,036 shares were delivered to us, for a total of 20,357,380 repurchased shares, which

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concluded this ASR program. The total number of shares repurchased under this ASR program was based generally on the volume-weighted average price of our common stock during the repurchase period, subject to provisions that set a minimum and maximum number of shares. Upon final settlement, the average per share cost for all shares purchased under this ASR program was $41.75.

On November 5, 2012, we entered into a $500 million ASR program. This ASR was the second tranche of share repurchases under the share repurchase plan authorized by our board of directors. Under this ASR program, we received 7,403,294 shares of common stock during the fourth quarter of 2012. On February 5, 2013, an additional 870,947 shares were delivered to us, for a total of 8,274,241 repurchased shares, which concluded this ASR program. The total number of shares repurchased under this ASR program was based generally on the volume-weighted average price of our common stock during the repurchase period. Upon final settlement, the average per share cost for all shares purchased under this ASR program was $60.43.

The shares repurchased under the ASR programs were accounted for as treasury stock purchase transactions, reducing the weighted average number of basic and diluted common shares outstanding by the shares repurchased, and as forward contracts indexed to our common stock. The forward contracts were accounted for as equity instruments.

11. Segment Information

We have three reportable operating segments: Refining & Marketing; Speedway; and Pipeline Transportation. Each of these segments is organized and managed based upon the nature of the products and services they offer.

• Refining & Marketing – refines crude oil and other feedstocks at our refineries in the Gulf Coast and Midwest regions of the United States, purchases ethanol and refined products for resale and distributes refined products through various means, including barges, terminals and trucks that we own or operate. We sell refined products to wholesale marketing customers domestically and internationally, to buyers on the spot market, to our Speedway segment and to dealers and jobbers who operate Marathon^® retail outlets;

• Speedway – sells transportation fuels and convenience products in retail markets in the Midwest, primarily through Speedway^® convenience stores; and

• Pipeline Transportation – transports crude oil and other feedstocks to our refineries and other locations, delivers refined products to wholesale and retail market areas and includes the aggregated operations of MPLX and MPC’s retained pipeline assets and investments.

As discussed in Note 7, on December 1, 2010, we disposed of the Minnesota Assets, which were part of our Refining & Marketing, Speedway and Pipeline Transportation segments. Segment information for all periods prior to the disposition includes amounts for these operations.

Segment income represents income from operations attributable to the operating segments. Corporate administrative expenses, including those allocated from the Marathon Oil Companies prior to the Spinoff, and costs related to certain non-operating assets are not allocated to the operating segments. In addition, certain items that affect comparability (as determined by the chief operating decision maker) are not allocated to the operating segments.

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(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
Year Ended December 31, 2012
Revenues:
Customer	$	67,921	$	14,239	$	77	$	82,237
Intersegment(a)		8,782		4		381		9,167
Related parties		7		-		1		8
Segment revenues		76,710		14,243		459		91,412
Elimination of intersegment revenues		(8,782)		(4)		(381)		(9,167)
Total revenues	$	67,928	$	14,239	$	78	$	82,245
Segment income from operations(b)	$	5,098	$	310	$	216	$	5,624
Income (loss) from equity method investments		(6)		-		32		26
Depreciation and amortization(c)		804		114		54		972
Capital expenditures and investments(d)(e)		705		340		211		1,256

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
Year Ended December 31, 2011
Revenues:
Customer	$	65,028	$	13,490	$	65	$	78,583
Intersegment(a)		8,301		-		335		8,636
Related parties		52		-		3		55
Segment revenues		73,381		13,490		403		87,274
Elimination of intersegment revenues		(8,301)		-		(335)		(8,636)
Total revenues	$	65,080	$	13,490	$	68	$	78,638
Segment income from operations	$	3,591	$	271	$	199	$	4,061
Income from equity method investments		11		-		39		50
Depreciation and amortization(c)		718		110		45		873
Capital expenditures and investments(d)(f)		900		164		121		1,185

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
Year Ended December 31, 2010
Revenues:
Customer	$	49,844	$	12,494	$	49	$	62,387
Intersegment(a)		7,394		-		347		7,741
Related parties		95		-		5		100
Segment revenues		57,333		12,494		401		70,228
Elimination of intersegment revenues		(7,394)		-		(347)		(7,741)
Total revenues	$	49,939	$	12,494	$	54	$	62,487
Segment income from operations	$	800	$	293	$	183	$	1,276
Income from equity method investments		9		-		61		70
Depreciation and amortization(c)		739		111		62		912
Capital expenditures and investments(d)		961		84		24		1,069

^(a)  Management believes intersegment transactions were conducted under terms comparable to those with unaffiliated parties.

^(b)  Included in the Pipeline Transportation segment are $4 million of corporate overhead costs and pension settlement expenses attributable to MPLX subsequent to MPLX’s October 31, 2012 initial public offering, which were included in items not allocated to segments prior to MPLX’s initial public offering. These expenses are not currently allocated to other segments.

^(c)  Differences between segment totals and MPC totals represent amounts related to unallocated items and are included in “Items not allocated to segments” in the reconciliation below.

^(d)  Capital expenditures include changes in capital accruals.

^(e)  Includes Speedway’s acquisition of 97 convenience stores in 2012.

^(f)  Includes Speedway’s acquisition of 23 convenience stores in 2011.

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The following reconciles segment income from operations to income before income taxes as reported in the consolidated statements of income:

(In millions)	2012			2011			2010
Segment income from operations	$	5,624		$	4,061		$	1,276
Items not allocated to segments:
Corporate and other unallocated items(a)(b)		(336	)		(316	)		(236	)
Minnesota Assets sale settlement gain(c)		183			-			-
Pension settlement expenses(b)(d)		(124	)		-			-
Impairment(e)		-			-			(29	)
Net interest and other financial income (costs)(f)		(109	)		(26	)		12
Income before income taxes	$	5,238		$	3,719		$	1,023

^(a)  Corporate and other unallocated items consists primarily of MPC’s corporate administrative expenses, including allocations from the Marathon Oil Companies for periods prior to the Spinoff and costs related to certain non-operating assets.

^(b)  Corporate overhead costs and pension settlement expenses attributable to MPLX were included in the Pipeline Transportation segment subsequent to MPLX’s October 31, 2012 initial public offering.

^(c)  See Note 7.

^(d)  See Note 22.

^(e)  See Note 18.

^(f)  Includes related party net interest and other financial income.

The following reconciles segment capital expenditures and investments to total capital expenditures:

(In millions)	2012		2011		2010
Segment capital expenditures and investments	$	1,256	$	1,185	$	1,069
Less: Investments in equity method investees		28		11		7
Plus: Items not allocated to segments:
Capital expenditures not allocated to segments		103		24		1
Capitalized interest		101		114		103
Total capital expenditures(a)(b)	$	1,432	$	1,312	$	1,166

^(a)  Capital expenditures include changes in capital accruals.

^(b)  See Note 21 for a reconciliation of total capital expenditures to additions to property, plant and equipment as reported in the consolidated statements of cash flows.

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The following reconciles total revenues to sales and other operating revenues (including consumer excise taxes) as reported in the consolidated statements of income:

(In millions)	2012		2011		2010
Total revenues (as reported above)	$	82,245	$	78,638	$	62,487
Plus: Corporate and other unallocated items		(2)		-		-
Less: Sales to related parties		8		55		100
Sales and other operating revenues (including consumer excise taxes)	$	82,235	$	78,583	$	62,387

Revenues by product line were:

(In millions)	2012		2011		2010
Refined products	$	76,234	$	73,334	$	56,025
Merchandise		3,229		3,090		3,369
Crude oil and refinery feedstocks		2,514		1,972		2,890
Transportation and other		266		242		203
Total revenues		82,243		78,638		62,487
Less: Sales to related parties		8		55		100
Sales and other operating revenues (including consumer excise taxes)	$	82,235	$	78,583	$	62,387

No single customer accounted for more than 10 percent of annual revenues.

We do not have significant operations in foreign countries. Therefore, revenues in foreign countries and long-lived assets located in foreign countries, including property, plant and equipment and investments, are not material to our operations.

Total assets by reportable segment were:

	December 31,
(In millions)	2012		2011
Refining & Marketing	$	17,052	$	17,294
Speedway		1,947		1,597
Pipeline Transportation		1,950		1,556
Corporate and Other		6,274		5,298
Total consolidated assets	$	27,223	$	25,745

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12. Other Items

Net interest and other financial income (costs) was:

(In millions)	2012		2011			2010
Interest:
Interest income	$	5	$	3		$	2
Interest expense(a)		(191)		(164	)		(18)
Interest capitalized(a)		101		104			17
Total interest		(85)		(57	)		1
Other:
Net foreign currency gains (losses)		-		12			(6)
Bank service and other fees		(25)		(16	)		(7)
Total other		(25)		(4	)		(13)
Net interest and other financial income (costs)	$	(110)	$	(61	)	$	(12)

^(a)  See Note 5 for information on related party interest expense and capitalized interest.

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13. Income Taxes

Income tax provisions (benefits) were:

	2012						2011						2010
(In millions)	Current		Deferred		Total		Current		Deferred		Total		Current		Deferred		Total
Federal	$	1,185	$	432	$	1,617	$	1,040	$	139	$	1,179	$	81	$	289	$	370
State and local		169		57		226		152		(16)		136		15		19		34
Foreign		(1)		3		2		15		-		15		(4)		-		(4)
Total	$	1,353	$	492	$	1,845	$	1,207	$	123	$	1,330	$	92	$	308	$	400

The provision for income taxes for periods prior to the Spinoff have been computed as if we were a stand-alone company.

A reconciliation of the federal statutory income tax rate (35 percent) applied to income before income taxes to the provision for income taxes follows:

	2012			2011			2010
Statutory rate applied to income before income taxes		35	%		35	%		35	%
State and local income taxes, net of federal income tax effects		2			2			3
Legislation(a)		-			-			2
Domestic manufacturing deduction		(1)			(1)			-
Effect of dividends received deduction		-			-			(1)
Other		(1)			-			-
Provision for income taxes		35	%		36	%		39	%

^(a)  The Patient Protection and Affordable Care Act (“PPACA”) and the Health Care and Education Reconciliation Act of 2010 were signed into law in March 2010. These new laws effectively changed the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “MPDIMA”). Under the MPDIMA, the federal subsidy did not reduce our income tax deduction for the costs of providing such prescription drug plans, nor was it subject to income tax individually. Beginning in 2013, under the 2010 legislation, our income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. As a result, we recorded a charge of $26 million in 2010 for the write-off of deferred tax assets to reflect the change in the tax treatment of the federal subsidy.

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Deferred tax assets and liabilities resulted from the following:

	December 31,
(In millions)	2012		2011
Deferred tax assets:
Employee benefits	$	585	$	820
Other		90		73
Total deferred tax assets		675		893
Deferred tax liabilities:
Property, plant and equipment		2,225		1,936
Inventories		610		610
Investments in subsidiaries and affiliates		307		79
Other		29		25
Total deferred tax liabilities		3,171		2,650
Net deferred tax liabilities	$	2,496	$	1,757

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

	December 31,
(In millions)	2012		2011
Liabilities:
Accrued taxes	$	446	$	447
Deferred income taxes		2,050		1,310
Net deferred tax liabilities	$	2,496	$	1,757

MPC was a new taxpayer beginning in 2011. Prior to 2011, MPC was included in the Marathon Oil federal income tax returns for applicable years. Marathon Petroleum Company LP, a subsidiary of MPC, is continuously undergoing examination of its U.S. federal income tax returns by the Internal Revenue Service. 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. We believe all other audits will be resolved with the amounts paid and/or provided for these liabilities. As of December 31, 2012, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:

United States Federal	2010 - 2011
States	2004 - 2011

As a result of the Spinoff and pursuant to the tax sharing agreement by Marathon Oil and MPC, the unrecognized tax benefits related to MPC operations for which Marathon Oil was the taxpayer remain the responsibility of Marathon Oil and MPC has indemnified Marathon Oil. Before the Spinoff, MPC made a prepayment of a portion of the unrecognized tax benefits to Marathon Oil, which is reflected in the table below as settlements. See Note 25.

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The following table summarizes the activity in unrecognized tax benefits:

(In millions)	2012		2011		2010
January 1 balance	$	20	$	14	$	19
Additions for tax positions of prior years		32		50		7
Reductions for tax positions of prior years		(6)		-		(1)
Settlements		(6)		(44)		(11)
December 31 balance	$	40	$	20	$	14

If the unrecognized tax benefits as of December 31, 2012 were recognized, $20 million would affect our effective income tax rate. There were $29 million of uncertain tax positions as of December 31, 2012 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 related to income taxes are recorded as part of the provision for income taxes. Such interest and penalties were net receipts (expenses) of $1 million, ($5 million) and ($1 million) in 2012, 2011 and 2010. As of December 31, 2012 and 2011, $9 million and $11 million of interest and penalties were accrued related to income taxes.

14. Inventories

	December 31,
(In millions)	2012		2011
Crude oil and refinery feedstocks	$	1,383	$	1,339
Refined products		1,761		1,725
Merchandise		74		65
Supplies and sundry items		231		191
Total (at cost)	$	3,449	$	3,320

The LIFO method accounted for 93 percent and 94 percent of total inventory value at December 31, 2012 and 2011, respectively. Current acquisition costs were estimated to exceed the LIFO inventory value at December 31, 2012 and 2011 by $4,511 million and $5,015 million, respectively. There was no liquidation of LIFO inventories in 2012. Cost of revenues decreased and income from operations increased by $4 million in both 2011 and 2010 as a result of liquidations of LIFO inventories, excluding inventories liquidated in dispositions.

15. Equity Method Investments

	Ownership as of December 31, 2012			December 31,
(In millions)				2012		2011
Centennial		50	%	$	27	$	17
LOCAP LLC		59	%		26		25
LOOP		51	%		198		181
TACE		36	%		29		35
TAME		50	%		27		32
Other					14		12
Total				$	321	$	302

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Summarized financial information for equity method investees is as follows:

(In millions)	2012		2011		2010
Income statement data:
Revenues and other income	$	1,025	$	1,043	$	939
Income from operations		73		128		196
Net income		47		101		170
Balance sheet data - December 31:
Current assets	$	217	$	256
Noncurrent assets		1,163		1,175
Current liabilities		161		126
Noncurrent liabilities		636		690

As of December 31, 2012, the carrying value of our equity method investments was $28 million higher than the underlying net assets of investees. This basis difference is being amortized or accreted into net income over the remaining estimated useful lives of the underlying net assets, except for $49 million of excess related to goodwill.

At December 31, 2012, Centennial was not shipping product; therefore, we evaluated the carrying value of our equity method investment in Centennial and concluded no impairment was required given our assessment of its fair value based on various uses for Centennial’s assets. We will continue to monitor the carrying value of our equity investment in Centennial.

Dividends and partnership distributions received from equity method investees (excluding distributions that represented a return of capital previously contributed) were $37 million, $48 million and $36 million in 2012, 2011 and 2010.

16. Property, Plant and Equipment

(In millions)	Estimated   Useful  Lives		December 31,
			2012		2011
Refining & Marketing		4 - 25 years	$	15,089	$	14,221
Speedway		4 - 15 years		2,100		1,887
Pipeline Transportation		16 -42 years		1,747		1,593
Corporate and Other		4 - 40 years		473		372
Total				19,409		18,073
Less accumulated depreciation				6,766		5,845
Net property, plant and equipment			$	12,643	$	12,228

Property, plant and equipment includes gross assets acquired under capital leases of $417 million and $267 million at December 31, 2012 and 2011, with related amounts in accumulated depreciation of $79 million and $61 million at December 31, 2012 and 2011. Property, plant and equipment includes construction in progress of $520 million and $2,581 million at December 31, 2012 and 2011, which primarily relates to refinery projects.

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17. Goodwill

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

The changes in the carrying amount of goodwill for 2012 and 2011 were as follows:

(In millions)	Refining &     Marketing		Speedway		Pipeline     Transportation		Total
2011
Beginning balance	$	554	$	120	$	163	$	837
Purchase price adjustment		(2)		-		(1)		(3)
Acquisition(a)		-		9		-		9
Disposition		(1)		-		-		(1)
Ending balance	$	551	$	129	$	162	$	842
2012
Beginning balance	$	551	$	129	$	162	$	842
Acquisitions(a)		-		88		-		88
Ending balance	$	551	$	217	$	162	$	930

^(a)  See Note 6 for information on the acquisitions.

18. 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, 2012 and 2011 by fair value hierarchy level.

	December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Commodity derivative instruments, assets	$	49	$	-	$	-	$	84	$	133
Other assets		2		-		-		-		2
Total assets at fair value	$	51	$	-	$	-	$	84	$	135
Commodity derivative instruments, liabilities	$	(88)	$	-	$	-	$	-	$	(88)

	December 31, 2011
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Commodity derivative instruments, assets	$	26	$	1	$	-	$	107	$	134
Interest rate derivative instruments, assets		-		19		-		-		19
Other assets		2		-		-		-		2
Total assets at fair value	$	28	$	20	$	-	$	107	$	155
Commodity derivative instruments, liabilities	$	(45)	$	(1)	$	-	$	-	$	(46)

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Commodity derivatives in Level 1 are exchange-traded contracts for crude oil and refined products measured at fair value with a market approach using the close-of-day settlement prices for the market. Collateral deposits in futures commission merchant accounts covered by master netting agreements related to Level 1 commodity derivatives are classified as Level 1 in the fair value hierarchy.

Commodity derivatives in Level 2 were measured at fair value with a market approach using monthly average close-of-day settlement prices for the market. Interest rate swap derivatives in Level 2 were measured at fair value using prices from Bloomberg L.P. and validated using market value information provided by the counterparties to the transactions.

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

(In millions)	2012		2011		2010
Beginning balance	$	-	$	2,402	$	865
Total realized and unrealized losses included in net income		(2)		-		(1)
Purchases of PFD Preferred Stock (a)		-		10,326		9,709
Redemptions of PFD Preferred Stock (a)		-		(12,730)		(8,019)
Settlements of derivative instruments		2		2		(2)
Distributions to Marathon Oil (b)		-		-		(150)
Ending balance	$	-	$	-	$	2,402

^(a)  For information on PFD Preferred Stock, see Note 5. The fair value of our PFD Preferred Stock investment was measured using an income approach since the securities were not publicly traded; therefore, they were classified as Level 3 in the fair value hierarchy.

^(b)  Due to the January 1, 2010 merger of two non-operating RM&T Business legal entities into Marathon Oil.

There were no unrealized gains or losses recorded in net income for the year ended December 31, 2012 related to Level 3 derivative instruments held during 2012. Net income for 2011 and 2010 included unrealized losses of less than $1 million and $1 million related to Level 3 derivative instruments held during those years. See Note 19 for the income statement impacts of our derivative instruments.

Fair Values – Nonrecurring

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

	Year Ended December 31,
	2012				2011				2010
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for sale	$	-	$	-	$	-	$	-	$	1	$	29
Other noncurrent assets		-		14		-		-		-		-

As a result of changing market conditions and declining throughput volumes, we impaired our Refining & Marketing segment’s prepaid tariff with Centennial by $14 million in 2012. The fair value measurement of the prepaid tariff was based on the income approach utilizing the probability of shipping sufficient volumes on Centennial’s pipeline over the remaining life of the throughput and deficiency credits, which expire March 31, 2014 if not utilized. This measurement is classified as Level 3.

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As a result of changing market conditions, a maleic anhydride supply agreement with a major customer was revised in June 2010. An impairment of $29 million was recorded in 2010 for a plant that manufactured maleic anhydride. The plant was operated by our Refining & Marketing segment. The fair value of the plant was measured using a market approach based upon comparable area land values which are Level 3 inputs.

Fair Values – Reported

The following table summarizes financial instruments on the basis of their nature, characteristics and risk at December 31, 2012 and 2011, excluding the derivative financial instruments reported above.

	December 31,
	2012				2011
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial assets:
Investments	$	263	$	59	$	289	$	93
Other		33		31		31		30
Total financial assets	$	296	$	90	$	320	$	123
Financial liabilities:
Long-term debt (a)	$	3,559	$	3,006	$	3,203	$	3,008
Deferred credits and other liabilities		23		23		21		21
Total financial liabilities	$	3,582	$	3,029	$	3,224	$	3,029

^(a) Excludes capital leases

Our current assets and liabilities include financial instruments, the most significant of which are trade accounts receivable and payables. We believe the carrying values of our current assets and liabilities approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments (e.g., less than 1 percent of our trade receivables and payables are outstanding for greater than 90 days), (2) our investment-grade credit rating and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.

Fair values of our financial assets included in investments and other financial assets and of our financial liabilities included in deferred credits and other liabilities are measured primarily 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. Other financial assets primarily consist of environmental remediation receivables. Deferred credits and other liabilities primarily consist of insurance liabilities and environmental remediation liabilities.

Fair value of long-term debt is measured using a market approach, based upon the average of quotes from major financial institutions and a third-party service for our debt. Because these quotes cannot be independently verified to the market, they are considered Level 3 inputs.

19. Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note 18. See Note 2 for a discussion of the types of derivatives we use and the reasons for them. We do not designate any of our commodity derivative instruments as hedges for accounting purposes. Our interest rate derivative instruments were designated as fair value accounting hedges.

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The following table presents the gross fair values of derivative instruments, excluding cash collateral, and where they appear on the consolidated balance sheets as of December 31, 2012 and 2011:

	December 31, 2012
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	49	$	88	Other current assets
	December 31, 2011
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	26	$	45	Other current assets
Interest rate derivatives		19		-	Other noncurrent assets
Commodity derivatives		1		1	Other current liabilities

Derivatives Designated as Fair Value Accounting Hedges

In 2012, we terminated interest rate swap agreements with a notional amount of $500 million that had been entered into as fair value accounting hedges on our 3.50 percent senior notes due in March 2016. There was a $20 million gain on the termination of the transactions, which has been accounted for as an adjustment to our long-term debt balance. The gain is being amortized over the remaining life of the 3.50 percent senior notes, which reduces our interest expense. The interest rate swaps had no accounting hedge ineffectiveness.

The following table summarizes the pretax effect of derivative instruments designated as accounting hedges of fair value in our consolidated statements of income:

		Gain (Loss)
(In millions)	Income Statement Location	2012		2011		2010
Derivative
Interest rate	Net interest and other financial income (costs)	$	1	$	19	$	-
Hedged Item
Long-term debt	Net interest and other financial income (costs)	$	(1)	$	(19)	$	-

Derivatives not Designated as Accounting Hedges

Derivatives that are not designated as accounting hedges may include commodity derivatives used to hedge price risk on (1) inventories, (2) fixed price sales of refined products, (3) the acquisition of foreign-sourced crude oil and (4) the acquisition of ethanol for blending with refined products.

The table below summarizes open commodity derivative contracts as of December 31, 2012.

	Position		Total Barrels   (In  thousands)
Crude oil(a)
Exchange-traded		Long		15,643
Exchange-traded		Short		(26,191	)
Refined Products(a)
Exchange-traded		Long		2,720
Exchange-traded		Short		(3,429	)

^(a)      100 percent of these contracts expire in the first quarter of 2013.

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The following table summarizes the effect of all commodity derivative instruments in our consolidated statements of income:

(In millions)	Gain (Loss)
Income Statement Location	2012		2011		2010
Sales and other operating revenues	$	8	$	(34)	$	(1)
Other income		-		1		6
Cost of revenues		65		182		(28)
Total	$	73	$	149	$	(23)

20. Debt

Our outstanding borrowings at December 31, 2012 and 2011 consisted of the following:

	December 31,
(In millions)	2012		2011
Marathon Petroleum Corporation:
Revolving credit agreement due 2017	$	-	$	-
3.500% senior notes due March 1, 2016		750		750
5.125% senior notes due March 1, 2021		1,000		1,000
6.500% senior notes due March 1, 2041		1,250		1,250
Consolidated subsidiaries:
Capital lease obligations due 2013-2027		355		299
MPLX Operations LLC revolving credit agreement due 2017		-		-
Trade receivables securitization facility due 2014		-		-
Total		3,355		3,299
Unamortized discount		(10)		(11)
Fair value adjustments (a)		16		19
Amounts due within one year		(19)		(15)
Total long-term debt due after one year	$	3,342	$	3,292

^(a)  See Notes 18 and 19 for information on interest rate swaps.

The following table shows five years of scheduled debt payments.

(In millions)
2013	$	19
2014		21
2015		23
2016		773
2017		25

There were no borrowings or letters of credit outstanding under the revolving credit agreements or the trade receivable securitization facility at December 31, 2012.

MPC Revolving Credit Agreement - On September 14, 2012, we entered into a five-year senior unsecured revolving credit agreement (the “Credit Agreement”) with a syndicate of lenders and terminated our previous four-year revolving credit agreement. The Credit Agreement was amended on December 20, 2012,

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to increase the borrowing capacity by $500 million to a total of $2.5 billion. The commitment increase became effective on February 1, 2013 in conjunction with the acquisition described in Note 26. The Credit Agreement includes letter of credit issuing capacity of up to $2.0 billion and swingline loan capacity of up to $100 million. We may increase the borrowing capacity under the Credit Agreement by up to an additional $500 million, subject to certain conditions including the consent of the lenders whose commitments would be increased. In addition, we may request that the term of the Credit Agreement, which expires on September 14, 2017, be extended for up to two additional one-year periods. Each such extension would be subject to the approval of lenders holding greater than 50 percent of the commitments then outstanding, and the commitment of any lender that does not consent to an extension of the maturity date will be terminated on the then-effective maturity date.

The Credit Agreement contains representations and warranties, affirmative and negative covenants and events of default that we consider usual and customary for an agreement of this type. The financial covenant included in the Credit Agreement requires us to maintain, as of the last day of each fiscal quarter, a ratio of Consolidated Net Debt (as defined in the Credit Agreement) to Total Capitalization (as defined in the Credit Agreement) of no greater than 0.65 to 1.00. In addition, the Credit Agreement includes limitations on the indebtedness of our subsidiaries, other than subsidiaries that guarantee our obligations under the Credit Agreement and our ability, and the ability of our subsidiaries, to incur liens on property or assets or enter into certain transactions with affiliates.

Borrowings of revolving loans under the Credit Agreement bear interest at either (i) the sum of the Adjusted LIBO Rate (as defined in the Credit Agreement) and a margin ranging between 1.00 percent to 2.00 percent, depending on our credit ratings, or (ii) the sum of the Alternate Base Rate (as defined in the Credit Agreement) and a margin ranging between zero percent to 1.00 percent, depending on our credit ratings. The Credit Agreement also provides for customary fees, including administrative agent fees, annual commitment fees ranging from 0.10 percent to 0.35 percent, depending on our credit ratings, on the unused portion, fees in respect to letters of credit and other fees.

During 2012, we expensed $1 million of the deferred financing costs from the previous revolving credit agreement related to lenders who discontinued participation in the revolving credit arrangement. The remaining $22 million of deferred financing costs from the previous revolving credit agreement are being amortized over the life of the new revolving credit agreement.

MPLX Operations LLC Revolving Credit Agreement - On September 14, 2012, MPLX Operations LLC, an affiliate of MPC and wholly-owned subsidiary of MPLX LP, as the borrower, and MPLX, as the parent guarantor, entered into a five-year senior unsecured revolving credit agreement (“MPLX Credit Agreement”) with a syndicate of lenders. The MPLX Credit Agreement became effective following MPLX’s initial public offering and has an initial borrowing capacity of $500 million. MPLX may increase the borrowing capacity under the MPLX Credit Agreement by up to an additional $300 million, subject to certain conditions, including the consent of the lenders whose commitments would be increased. The MPLX Credit Agreement includes letter of credit issuing capacity of up to $250 million and swingline loan capacity of up to $50 million. MPLX may, subject to certain conditions, request that the term of the MPLX Credit Agreement, which expires on October 31, 2017, be extended for up to two additional one-year periods. Each such extension would be subject to the approval of lenders holding greater than 50 percent of the commitments then outstanding, and the commitment of any lender that does not consent to an extension of the maturity date will be terminated on the then-effective maturity date.

The MPLX Credit Agreement contains representations and warranties, affirmative and negative covenants and events of default that we consider usual and customary for an agreement of this type. The financial covenant included in the MPLX Credit Agreement requires MPLX to maintain a ratio of Consolidated Total Debt (as defined in the MPLX Credit Agreement) as of the end of each fiscal quarter to Consolidated EBITDA (as defined in the MPLX Credit Agreement) for the prior four fiscal quarters of not greater than 5.0 to 1.0 (or 5.5 to 1.0 during the six-month period following certain acquisitions).

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Borrowings of revolving loans under the MPLX Credit Agreement bear interest at either (i) the sum of the Adjusted LIBO Rate (as defined in the MPLX Credit Agreement) and a margin ranging from 1.00 percent to 2.00 percent or (ii) the sum of the Alternate Base Rate (as defined in the MPLX Credit Agreement) and a margin ranging from zero percent to 1.00 percent. Prior to MPLX receiving a rating from Standard & Poor’s Rating Group or Moody’s Investor Service, Inc. for its Index Debt (as defined in the MPLX Credit Agreement), the margin that is added to the applicable interest rate is based on MPLX’s ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA for the prior four fiscal quarters. Once MPLX receives a rating, if ever, the margin added to the applicable interest rate will be based on MPLX’s credit ratings. The MPLX Credit Agreement also provides for customary fees, including administrative agent fees, commitment fees ranging from 0.10 percent to 0.35 percent of the unused portion, depending on MPLX’s ratio of Consolidated Total Debt as of the end of the fiscal quarter to Consolidated EBITDA for the prior four fiscal quarters prior to the rating date, or MPLX’s credit ratings subsequent to the rating date, fronting and issuance fees in respect to letters of credit and other fees.

21. Supplemental Cash Flow Information

(In millions)	2012		2011		2010
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	67	$	5	$	-
Income taxes paid to taxing authorities (a)		1,211		617		11
Non-cash investing and financing activities:
Property, plant and equipment contributed by Marathon Oil	$	-	$	81	$	-
Capital lease obligations increase		62		26		32
Preferred equity interest received in asset disposition (b)		-		-		80
Preferred equity interest received in contract settlement (b)		45		-		-
Preferred equity interest dividend received in-kind		1		-		-
Acquisition:
Intangible asset acquired		3		-		-
Liability assumed		2		-		-

^(a)  U.S. federal and most state income taxes, if incurred, were paid by Marathon Oil for periods prior to the Spinoff. The amount for 2012 includes payments of $181 million for 2011 return period income taxes made to Marathon Oil under our tax sharing agreement, and in return we received an equal amount of minimum tax credits. See Note 25.

^(b)  See Note 7.

The consolidated statements of cash flows exclude changes to the consolidated balance sheets that did not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures:

(In millions)	2012		2011		2010
Additions to property, plant and equipment	$	1,369	$	1,185	$	1,217
Acquisitions (a)		180		74		-
Increase (decrease) in capital accruals		(117)		53		(51)
Total capital expenditures	$	1,432	$	1,312	$	1,166

^(a)  Excludes inventory acquired and liability assumed in 2012.

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The following is a reconciliation of contributions from (distributions to) Marathon Oil:

(In millions)	2012		2011		2010
Distributions to Marathon Oil per consolidated statements of cash flows	$	-	$	(783)	$	(1,330)
Non-cash contributions from (distributions to) Marathon Oil		-		57		(118)
Distributions to Marathon Oil per consolidated statements of equity / net investment	$	-	$	(726)	$	(1,448)

See Note 5 for information regarding non-cash contributions from (distributions to) Marathon Oil.

22. Defined Benefit Pension and Other Postretirement Plans

We have noncontributory defined benefit pension plans covering substantially all employees. Benefits under these plans have been based primarily on age, years of service and final average pensionable earnings. The years of service component of this formula was frozen as of December 31, 2009. Benefits for service beginning January 1, 2010 are based on a cash balance formula with an annual percentage of eligible pay credited based upon age and years of service. Eligible Speedway employees accrue benefits under a defined contribution plan for service years beginning January 1, 2010.

On May 17, 2012, we communicated to our employees changes in the defined benefit pension plans for Speedway and the legacy portion of the Marathon Petroleum Retirement Plan effective January 1, 2013. Final average pensionable earnings used to calculate pension benefits under these plans have been fixed as of December 31, 2012. In addition, cap protection was added to limit potential annual lump sum distribution discount rate increases. These plan amendments resulted in an overall decrease in pension liabilities of approximately $537 million, with the offset primarily to other comprehensive income, which was recorded in 2012. The benefit of this liability reduction is being amortized into income through 2024.

We also have other postretirement benefits covering most employees. Health care benefits are provided through comprehensive hospital, surgical and major medical benefit provisions subject to various cost-sharing features. Retiree life insurance benefits are provided to a closed group of retirees. Other postretirement benefits are not funded in advance.

On August 20, 2012, we communicated, to our impacted Medicare eligible retirees, changes in the post-65 medical plan coverage of the Marathon Petroleum Health Plan and the Marathon Petroleum Retiree Health Plan. Effective January 1, 2013, these Medicare eligible participants receive a tax free contribution to a health reimbursement account, which replaces benefits provided under the previous plans. Increases are capped at four percent per year. This plan change resulted in a reduction in retiree medical liabilities of approximately $40 million. This was more than offset by an increase in retiree medical liabilities of approximately $57 million primarily due to a reduction in discount rates as of the remeasurement date. The overall net liability increase and the offset to other comprehensive income were recorded in 2012.

Obligations and funded status – The accumulated benefit obligation for all defined benefit pension plans was $2,035 million and $1,948 million as of December 31, 2012 and 2011.

The following summarizes our defined benefit pension plans that have accumulated benefit obligations in excess of plan assets.

	December 31,
(In millions)	2012		2011
Projected benefit obligations	$	2,192	$	2,685
Accumulated benefit obligations		2,035		1,948
Fair value of plan assets		1,478		1,423

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

	Pension Benefits				Other Benefits
(In millions)	2012		2011		2012		2011
Change in benefit obligations:
Benefit obligations at January 1	$	2,685	$	2,266	$	551	$	483
Service cost		66		65		20		19
Interest cost		94		110		24		27
Actuarial loss		117		384		53		39
Benefits paid		(233)		(178)		(17)		(17)
Liability gain due to curtailment		(17)		(4)		-		-
Other (a)		(520)		42		(40)		-
Benefit obligations at December 31		2,192		2,685		591		551
Change in plan assets:
Fair value of plan assets at January 1		1,423		1,233		-		-
Actual return on plan assets		157		50		-		-
Employer contributions		131		282		-		-
Other(a)		-		36		-		-
Benefits paid from plan assets		(233)		(178)		-		-
Fair value of plan assets at December 31		1,478		1,423		-		-
Funded status of plans at December 31	$	(714)	$	(1,262)	$	(591)	$	(551)
Amounts recognized in the consolidated balance sheets:
Current liabilities	$	(18)	$	(12)	$	(21)	$	(18)
Noncurrent liabilities		(696)		(1,250)		(570)		(533)
Accrued benefit cost	$	(714)	$	(1,262)	$	(591)	$	(551)
Pretax amounts recognized in accumulated other comprehensive loss: (b)
Net loss	$	1,147	$	1,319	$	93	$	42
Prior service cost (credit)		(460)		42		(38)		-

^(a)  Includes adjustments related to plan amendments in 2012. Includes adjustments related to the Spinoff in 2011.

^(b)  Amounts exclude those related to LOOP, an equity method investee with defined benefit pension and postretirement plans for which net losses of $16 million and $2 million were recorded in accumulated other comprehensive loss in 2012, reflecting our 51 percent share.

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

	Pension Benefits						Other Benefits
(In millions)	2012		2011		2010		2012		2011		2010
Components of net periodic benefit cost:
Service cost	$	66	$	65	$	62	$	20	$	19	$	14
Interest cost		94		110		105		24		27		24
Expected return on plan assets		(104)		(97)		(95)		-		-		-
Amortization – prior service cost (credit)		(18)		6		7		(2)		-		1
– actuarial loss (gain)		93		71		51		2		-		(2)
– net settlement/curtailment loss(a)		125		8		13		-		-		-
Net periodic benefit cost(b)	$	256	$	163	$	143	$	44	$	46	$	37
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial loss	$	46	$	427	$	129	$	53	$	39	$	61
Prior service credit(c)		(520)		-		-		(40)		-		-
Amortization of actuarial (loss) gain		(218)		(79)		(64)		(2)		-		2
Amortization of prior service cost (credit)		18		(6)		(7)		2		-		(1)
Other(d)		-		6		-		-		-		-
Total recognized in other comprehensive loss	$	(674)	$	348	$	58	$	13	$	39	$	62
Total recognized in net periodic benefit cost and other comprehensive loss	$	(418)	$	511	$	201	$	57	$	85	$	99

^(a)  A curtailment gain was recorded in 2011 on the Speedway pension plan at the end of the transition services period related to the sale of most of our Minnesota Assets in 2010. See Note 7.

^(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 adjustments due to changes made to the defined pension plans and the post-65 medical plan coverage effective January 1, 2013.

^(d)  Includes adjustments related to the Spinoff.

Lump sum payments to employees retiring in 2012, 2011 and 2010 exceeded the plan’s total service and interest costs expected for those years. Settlement losses are required to be recorded when lump sum payments exceed total service and interest costs. As a result, pension settlement expenses were recorded in 2012, 2011 and 2010 related to our cumulative lump sum payments made during those years.

The estimated net loss and prior service credit for our defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2013 are $89 million and $45 million. The 2013 net loss amortization is expected to be lower than the 2012 actual amortization primarily as a result of adjustments made to the net loss balance due to settlement accounting in 2012. The estimated net loss and 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 2013 is $4 million and $4 million.

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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 2012, 2011 and 2010.

	Pension Benefits						Other Benefits
	2012		2011		2010		2012		2011		2010
Weighted-average assumptions used to determine benefit obligation:
Discount rate		3.45%		4.30%		5.05%		4.05%		4.65%		5.55%
Rate of compensation increase		5.00%		5.00%		5.00%		5.00%		5.00%		5.00%
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate		4.06%		4.98%		5.23%		4.54%		5.55%		6.85%
Expected long-term return on plan assets		7.50%		8.50%		8.50%		-		-		-
Rate of compensation increase		5.00%		5.00%		4.50%		5.00%		5.00%		4.50%

Expected long-term return on plan assets

The overall expected long-term return on plan assets assumption 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 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.

Assumed health care cost trend

The following summarizes the assumed health care cost trend rates.

	December 31,
	2012		2011		2010
Health care cost trend rate assumed for the following year:
Medical:
Pre-65		8.00%		7.50%		7.50%
Post-65(a)		N/A		7.00%		7.00%
Prescription drugs		7.00%		7.50%		7.50%
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(a)		N/A		5.00%		5.00%
Prescription drugs		5.00%		5.00%		5.00%
Year that the rate reaches the ultimate trend rate:
Medical:
Pre-65		2020		2018		2018
Post-65(a)		N/A		2017		2017
Prescription drugs		2018		2018		2018

^(a)  Effective 2013, as a result of changes in the post-65 medical plan coverage of the Marathon Petroleum Health Plan and the Marathon Petroleum Retiree Health Plan, increases are the lower of the trend rate or 4 percent.

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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:

	1-Percentage-		1-Percentage-
(In millions)	Point Increase		Point Decrease
Effect on total of service and interest cost components	$	6	$	5
Effect on other postretirement benefit obligations		32		28

Plan investment policies and strategies

The investment policies for our 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 achievable in the capital markets, which are consistent with the risk parameters set by the plans’ investment committees; and (3) position the portfolios with a long-term investment horizon.

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. The plans’ targeted asset allocation is 75 percent equity securities and 25 percent fixed income securities; however, the asset allocation may be modified in the future as deemed appropriate by management.

The plans’ assets are managed by a third-party investment manager. The investment manager has limited discretion to move away from the target allocations based upon the manager’s judgment as to current confidence or concern regarding the capital markets. Investments are diversified by industry and type, limited by grade and maturity. Limited derivative investments are allowable subject to strict guidelines, such that derivatives may only be written against equity securities in the portfolio. Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies.

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 category at December 31, 2012 and 2011.

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 in the fair value hierarchy. The money market mutual fund is valued at the net asset value (“NAV”) of shares held.

Equity securities – Investments in public investment trusts and S&P 500 exchange-traded funds are valued using a market approach at the closing price reported in an active market and are therefore considered Level 1. Non-public investment trusts are considered Level 2 and are valued using a market approach based on the underlying investments in the trust, which are publicly traded securities. 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.

Pooled funds – Investments in two pooled funds are valued using a market approach at the NAV of units held, but investment opportunities in such funds are limited to the benefit plans of United States Steel Corporation, its subsidiaries and former affiliates. The funds consist of an equity investment portfolio consisting only of short-term instruments and publicly traded equities and a fixed income investment portfolio consisting only of short-term instruments, publicly traded bonds and Rule 144A bonds. These investments are considered Level 2.

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Real estate – Real estate investments consist of interests in commingled funds. The valuation of total fund assets constitutes the sum of all individual investments plus working capital, adjusted for liabilities, currency translation and estimated performance incentives. The real estate investments are considered Level 3.

Other – Other investments include investments in two limited liability companies (“LLCs”) with no public market. The LLCs were formed to acquire timberland in the northwest United States. The values of the LLCs are determined by using appraised values plus net working capital and less any estimated performance incentives. 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, 2012 and 2011.

	December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	107	$	-	$	-	$	107
Equity securities:
Investment trusts		17		94		-		111
Exchange-traded funds		166		-		-		166
Private equity		-		-		56		56
Investment funds:
Pooled funds - equity(a)		-		709		-		709
Pooled funds - fixed income(b)		-		258		-		258
Real estate(c)		-		-		54		54
Other		-		-		17		17
Total investments, at fair value	$	290	$	1,061	$	127	$	1,478
	December 31, 2011
(In millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	205	$	-	$	-	$	205
Equity securities:
Investment trusts		15		81		-		96
Exchange-traded funds		14		-		-		14
Private equity		-		-		55		55
Investment funds:
Pooled funds - equity(a)		-		758		-		758
Pooled funds - fixed income(d)		-		229		-		229
Real estate(e)		-		-		49		49
Other		-		-		17		17
Total investments, at fair value	$	234	$	1,068	$	121	$	1,423

^(a)  Includes approximately 70 percent of investments held in U.S. and non-U.S. publicly traded common stocks in the consumer staples, consumer discretionary, technology, health and energy sectors and the remaining 30 percent of investments held amongst various other sectors.

^(b)  Includes approximately 90 percent of investments held in U.S. and non-U.S. publicly traded investment-grade government and corporate bonds which include treasuries, mortgage-backed securities and industrials, and the remaining 10 percent of investments held amongst various other sectors.

^(c)  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 land with the greatest percentage of investments made in the U.S. and Asia, which includes the emerging markets of China and India.

^(d)  Includes approximately 80 percent of investments held in U.S. and non-U.S. publicly traded investment-grade government and corporate bonds which include treasuries, mortgage-backed securities and industrials, and the remaining 20 percent of investments held amongst various other sectors.

^(e)  Includes investments diversified by property type and location. The largest property sector holdings, which represent approximately 75 percent of investments held, are office, hotel, residential and land 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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The following is a reconciliation of the beginning and ending balances recorded for plan assets classified as Level 3 in the fair value hierarchy:

	2012
(In millions)	Private Equity		Real Estate		Other		Total
Beginning balance	$	55	$	49	$	17	$	121
Actual return on plan assets		2		-		-		2
Purchases		12		10		-		22
Sales		(13)		(5)		-		(18)
Ending balance	$	56	$	54	$	17	$	127
	2011
(In millions)	Private Equity		Real Estate		Other		Total
Beginning balance	$	46	$	37	$	17	$	100
Actual return on plan assets		7		5		-		12
Purchases		10		12		-		22
Sales		(9)		(6)		-		(15)
Other		1		1		-		2
Ending balance	$	55	$	49	$	17	$	121

Cash Flows

Contributions to defined benefit plans – Our funding policy with respect to the pension plans is to contribute amounts necessary to satisfy minimum pension funding requirements, including requirements of the Pension Protection Act of 2006, plus such additional, discretionary, amounts from time to time as determined appropriate by management. We currently estimate that we will contribute approximately $160 million to the plans in 2013. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are estimated to be approximately $18 million and $21 million in 2013.

Estimated future benefit payments – The following gross benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated.

(In millions)	Pension Benefits		Other Benefits (a)
2013	$	208	$	21
2014		206		23
2015		201		26
2016		197		28
2017		195		30
2018 through 2022		871		179

^(a)  Effective 2013, as a result of the PPACA, future Medicare reimbursements will no longer be tax deductible and must be used to reduce the costs of providing Medicare part D equivalent prescription drug benefits to retirees.

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Contributions to defined contribution plans – We also contribute to several defined contribution plans for eligible employees. Contributions to these plans totaled $60 million, $60 million and $54 million in 2012, 2011 and 2010.

Multiemployer Pension Plan

We contribute to one multiemployer defined benefit pension plan under the terms of a collective-bargaining agreement that covers some of our union-represented employees. The risks of participating in this multiemployer plan are different from single-employer plans in the following aspects:

• Assets contributed to the multiemployer plan by one employer may be used to provide benefits to employees of other participating employers.

• If a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining participating employers.

• If we choose to stop participating in the multiemployer plan, we may be required to pay that plan an amount based on the underfunded status of the plan, referred to as a withdrawal liability.

Our participation in this plan for 2012, 2011 and 2010 is outlined in the table below. The “EIN” column provides the Employee Identification Number for the plan. The most recent Pension Protection Act zone status available in 2012 and 2011 is for the plan’s year ended December 31, 2011 and December 31, 2010, respectively. The zone status is based on information that we received from the plan and is certified by the plan’s actuary. Among other factors, plans in the red zone are generally less than 65 percent funded. The “FIP/RP Status Pending/Implemented” column indicates a financial improvement plan or a rehabilitation plan has been implemented. The last column lists the expiration date of the collective-bargaining agreement to which the plan is subject. There have been no significant changes that affect the comparability of 2012, 2011 and 2010 contributions. Our portion of the contributions does not make up more than 5 percent of total contributions to the plan.

Pension Protection

FIP/RP Status

Expiration Date of

Act Zone Status

Pending/

MPC Contributions (In millions)

Surcharge

Collective - Bargaining

Pension Fund

EIN

2012

2011

Implemented

2012

2011

2010

Imposed

Agreement

Central States, Southeast and Southwest Areas Pension Plan (a)

36-6044243

Red

Red

Implemented

$

4

$

3

$

3

No

January 31, 2014

(a) This agreement has a minimum contribution requirement of $259 per week per employee for 2013. A total of 251 employees participated in the plan as of December 31, 2012.

Multiemployer Health and Welfare Plan

We contribute to one multiemployer health and welfare plan that covers both active employees and retirees. Through the health and welfare plan employees receive medical, dental, vision, prescription and disability coverage. Our contributions to this plan totaled $5 million, $4 million and $4 million for 2012, 2011 and 2010.

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23. Stock-Based Compensation Plans

Description of the Plans

Prior to the 2011 Spinoff, our employees participated in the Marathon Oil Corporation 2007 Incentive Compensation Plan (the “2007 Plan”) and the Marathon Oil Corporation 2003 Incentive Compensation Plan (the “2003 Plan”) and received Marathon Oil restricted stock awards and options to purchase shares of Marathon Oil common stock. Effective June 30, 2011, our employees and non-employee directors became eligible to receive equity awards under the Marathon Petroleum Corporation 2011 Second Amended and Restated Incentive Compensation Plan (the “MPC 2011 Plan”). Effective April 26, 2012, our employees and non-employee directors became eligible to receive equity awards under the Marathon Petroleum Corporation 2012 Incentive Compensation Plan (the “MPC 2012 Plan”).

The MPC 2012 Plan authorizes the Compensation Committee of our board of directors (the “Committee”) to grant non-qualified or incentive stock options, stock appreciation rights, stock awards (including restricted stock and restricted stock unit awards), cash awards and performance awards to our employees, non-employee directors and other plan participants. Grants made during 2012 with a grant date prior to the effective date of the MPC 2012 Plan were made under the MPC 2011 Plan. Following the effective date of the MPC 2012 Plan, no new grants were allowed to be issued under the MPC 2011 Plan. Under the MPC 2012 Plan, no more than 25 million shares of our common stock may be delivered and no more than 10 million shares of our common stock may be the subject of awards that are not stock options or stock appreciation rights. In the sole discretion of the Committee, 10 million shares of our common stock may be granted as incentive stock options. Shares issued as a result of awards granted under these plans are funded through the issuance of new MPC common shares.

In connection with the Spinoff, stock compensation awards granted under the 2007 Plan and the 2003 Plan and held by grantees as of June 30, 2011 were adjusted or substituted as follows:

• Vested stock options were adjusted and substituted so that the grantee holds options to purchase both MPC and Marathon Oil common stock.

• Unvested stock option awards held by MPC employees were replaced with substitute awards of options to purchase shares of MPC common stock.

• The adjustment to the Marathon Oil and MPC stock options, when combined, was intended to generally preserve the intrinsic value of each option grant and the ratio of the exercise price to the fair market value of Marathon Oil common stock on June 30, 2011.

• Unvested restricted stock awards were replaced with adjusted, substitute awards for restricted shares or units, as applicable, of MPC common stock. The new awards of restricted stock were intended to generally preserve the intrinsic value of the award determined as of June 30, 2011.

• Vesting periods of awards were unaffected by the adjustment and substitution.

Awards granted in connection with the adjustment and substitution of awards originally issued under the 2007 Plan and the 2003 Plan are a part of the MPC 2011 Plan and reduce the maximum number of shares of MPC common stock available for delivery under the MPC 2011 Plan.

There were 393 MPC employees affected by the adjustment and substitution of awards. The adjustment and substitution of awards did not cause us to recognize incremental compensation expense.

Our wholly-owned subsidiary and the general partner of MPLX, MPLX GP LLC (“MXGP”), maintains a unit-based compensation plan for officers, directors and employees (including any other individual who may be considered an “employee” under a Registration Statement on Form S-8 or any successor form) of MXGP.

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The MPLX 2012 Incentive Compensation Plan (“MPLX Plan”) permits various types of equity awards including but not limited to grants of restricted units, phantom units and performance units. Awards granted during 2012 under the MPLX Plan will be settled with MPLX units.

Stock-based awards under the Plans

We expense all share-based payments to employees and non-employee directors based on the grant date fair value of the awards over the requisite service period, adjusted for estimated forfeitures.

Stock Options - We grant stock options to certain officer and non-officer employees and other plan participants. Stock options previously granted under the 2003 Plan and 2007 Plan remain held by employees, subject to the adjustment and substitution of awards described above. All of the stock options granted in 2012 fell under the MPC 2011 Plan. Stock options awarded under the MPC 2011 Plan and the MPC 2012 Plan represents the right to purchase shares of our common stock at its fair market value on the date of grant. Stock options have a maximum term of ten years from the date they are granted, and vest over a requisite service period of three years. We use the Black Scholes option-pricing model to estimate the fair value of stock options granted, which requires the input of subjective assumptions.

Stock Appreciation Rights (“SARs”) – Prior to 2005, SARs were granted under the 2003 Plan. No SARs have been granted under the 2007 Plan, the MPC 2011 Plan or the MPC 2012 Plan. Similar to stock options, SARs represent the right to receive a payment equal to the excess of the fair market value of shares of MPC or Marathon Oil common stock (in accordance with the adjustment and substitution of awards described above) on the date the right is exercised over the grant price. SARs have a maximum term of ten years from the date they are granted and generally vest over a requisite service period of three or four years. We use the Black Scholes option-pricing model to estimate the fair value of SARs granted, which requires the input of subjective assumptions.

Restricted Stock and Restricted Stock Units – We grant restricted stock and restricted stock units to employees, non-employee directors and other plan participants. Restricted stock and restricted stock units previously granted under the 2003 Plan and the 2007 Plan remain held by employees and non-employee directors, subject to the adjustment and substitution of awards described above. In general, restricted stock and restricted stock units granted to employees vest over a requisite service period of three years. Restricted stock and restricted stock unit awards granted in 2012 to officers are subject to an additional one year holding period after the completion of the three year requisite service period. Prior to vesting, all 2011 restricted stock recipients have the right to vote such stock and receive dividends at the same time regular shareholders are paid. The 2012 restricted stock recipients have the right to vote such stock; however, accrued dividends will only be paid upon vesting. Restricted stock units granted to non-employee directors are considered to vest immediately at the time of the grant, as they are non-forfeitable, but are not issued until the director’s departure from the board of directors. All restricted stock unit recipients do not have the right to vote such stock and receive dividend equivalents. The non-vested shares are not transferable and are held by our transfer agent. The fair values of restricted stock are based on the fair value of our common stock on the grant date.

Performance Units – We grant performance unit awards to certain officer employees. Current performance unit awards vest over a requisite service period of 18, 30 or 36 months. Performance units issued prior to 2012 are paid in cash at the end of the period at an amount per unit determined based on the total shareholder return of MPC common stock compared to the total shareholder return of selected peer companies’ stock over the vesting period. Performance units issued in 2012, under the MPC 2011 Plan, have a per unit payout determined based on the total shareholder return of MPC common stock compared to the total shareholder return of a selected combination of peer companies and index fund shareholder return over an average of four periods during the 36 month requisite service period. These performance units are designed to pay out 75 percent in cash and 25 percent in MPC common stock. The performance units paying out in cash are accounted for as liability awards and are recorded at fair value. The performance units settling in shares are accounted for as equity awards and have a grant date fair value of $1.09 per unit, as calculated using a Monte Carlo valuation model.

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Total Stock-Based Compensation Expense

Total employee stock-based compensation expense was $35 million, $28 million and $16 million in 2012, 2011 and 2010, while the total related income tax benefits were $13 million, $11 million and $6 million, respectively. In 2012 and in 2011 for the period subsequent to the Spinoff, cash received by MPC upon exercise of stock option awards was $108 million and $1 million. In 2011 for periods prior to the Spinoff and 2010, cash received by Marathon Oil upon exercise of stock option awards by MPC employees was $17 million and $5 million. In 2012 and in 2011 for the period subsequent to the Spinoff, tax benefits realized by MPC for deductions for stock awards exercised were $16 million and less than $1 million. In 2011 for periods prior to the Spinoff and 2010, tax benefits realized by Marathon Oil for deductions for stock awards exercised by MPC employees were $7 million and $1 million.

Stock Option Awards

The Black Scholes option-pricing model values used to value stock option awards granted during 2012, 2011 and 2010 were determined based on the following weighted average assumptions (information for periods prior to the Spinoff was based on stock option awards for Marathon Oil common stock):

	2012		2011 subsequent to Spinoff		2011 prior to Spinoff		2010
Weighted average exercise price per share	$	42.02	$	36.18	$	51.93	$	30.12
Expected annual dividends per share	$	1.00	$	0.95	$	1.00	$	0.97
Expected life in years		5.8		5.8		5.3		5.1
Expected volatility		47%		48%		40%		41%
Risk-free interest rate		1.1%		1.4%		2.0%		2.2%
Weighted average grant date fair value of stock option awards granted	$	14.45	$	13.08	$	16.73	$	8.72

The expected life of stock options granted is based on historical data and represents the period of time that options granted are expected to be held prior to exercise. The assumption for expected volatility of our stock price reflects a weighting of 25 percent of our common stock implied volatility and 75 percent of the historical volatility for a selected group of peer companies. Expected annual dividends per share is estimated using the most recent dividend payment per share as of the grant date. The risk-free interest rate for periods within the expected life of the option is based on the U.S. Treasury yield curve in effect at the time of the grant.

The following is a summary of our common stock option activity in 2012:

	Number of     of Shares(a)		Weighted Average     Exercise Price		Weighted Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value     (In millions)
Outstanding at December 31, 2011		9,372,370	$	33.08
Granted		766,543		42.04
Exercised		(3,843,544)		29.71
Forfeited, canceled or expired		(123,175)		38.88
Outstanding at December 31, 2012		6,172,194		36.17
Vested and expected to vest at December 31, 2012		6,137,435		36.14		6.6	$	165
Exercisable at December 31, 2012		3,648,382		34.48		5.4		104

^(a)  Includes an immaterial number of stock appreciation rights.

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The intrinsic value of options exercised by MPC employees during 2012 and in 2011 for periods subsequent to the Spinoff was $37 million and $1 million. The intrinsic value of options to purchase Marathon Oil common stock exercised by MPC employees under the 2007 Plan and 2003 Plan during 2011 for periods prior to the Spinoff and 2010 was $18 million and $2 million.

As of December 31, 2012, unrecognized compensation cost related to stock option awards was $12 million, which is expected to be recognized over a weighted average period of 0.9 years.

Restricted Stock Awards

The following is a summary of restricted stock award activity of our common stock in 2012:

	Shares of Restricted Stock (“RS”)				Restricted Stock Units (“RSU”)
	Number of Shares		Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2011		348,691	$	34.36		319,944	$	29.43
Granted		416,495		43.11		39,462		44.38
RS’s Vested/RSU’s Issued		(115,441)		29.63		(179)		34.02
Forfeited		(11,672)		39.54		(116)		43.44
Outstanding at December 31, 2012		638,073		40.83		359,111		31.07

Of the 359,111 restricted units outstanding, 357,990 are vested and have a weighted average grant date fair value of $31.04. These vested but unissued units are held by our non-employee directors, are non-forfeitable and are issuable upon the director’s departure from our board of directors.

The following is a summary of the values related to restricted stock and restricted stock unit awards held by MPC employees and non-employee directors (information for periods prior to the Spinoff is for restricted stock and restricted stock unit awards of Marathon Oil common stock):

	Restricted Stock				Restricted Stock Units
	Intrinsic Value of Awards Vesting During the Period (In millions)		Weighted Average Grant Date Fair Value of Awards Granted During the Period		Intrinsic Value of Awards Issued During the Period (In millions)		Weighted Average Grant Date Fair Value of Awards Granted During the Period
2012	$	5	$	43.11	$	-	$	44.38
2011 - Subsequent to the Spinoff		1		41.54		-		33.78
2011 - Prior to the Spinoff		3		48.53		-		45.22
2010		3		30.55		-		32.18

As of December 31, 2012, unrecognized compensation cost related to restricted stock awards was $18 million, which is expected to be recognized over a weighted average period of 1.1 years. There was no material unrecognized compensation cost related to restricted stock unit awards.

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Performance Unit Awards

The following table presents a summary of the 2012 activity for performance unit awards to be settled in shares:

	Number of Units
Outstanding at December 31, 2011		-
Granted		2,040,000
Settled		-
Canceled		-
Outstanding at December 31, 2012		2,040,000

24. Leases

We lease a wide variety of facilities and equipment under operating leases, including land and building space, office equipment, storage facilities and transportation equipment. Most long-term leases include renewal options and, in certain leases, purchase options. Future minimum commitments as of December 31, 2012, for capital lease obligations and for operating lease obligations having initial or remaining non-cancelable lease terms in excess of one year are as follows:

(In millions)	Capital Lease Obligations		Operating Lease Obligations
2013	$	44	$	151
2014		44		137
2015		45		117
2016		44		80
2017		43		49
Later years		326		78
Total minimum lease payments		546	$	612
Less imputed interest costs		(191)
Present value of net minimum lease payments	$	355

Operating lease rental expense was:

(In millions)	2012		2011		2010
Minimum rental	$	139	$	123	$	135
Contingent rental		-		1		1
Rental expense	$	139	$	124	$	136

25. Commitments and Contingencies

We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. Some of these matters are discussed below. For matters for which we have not recorded an accrued liability, we are unable to estimate a range of possible loss because the issues involved have not been fully developed through pleadings and discovery. However, the ultimate resolution of some of these contingencies could, individually or in the aggregate, be material.

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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 and certain other locations including presently or formerly owned or operated retail marketing sites. Penalties may be imposed for noncompliance.

At December 31, 2012 and 2011, accrued liabilities for remediation totaled $123 million and $117 million, respectively. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties if any that may be imposed. Receivables for recoverable costs from certain states, under programs to assist companies in clean-up efforts related to underground storage tanks at presently or formerly owned or operated retail marketing sites, was $51 million at both December 31, 2012 and December 31, 2011.

We are involved in a number of environmental enforcement matters arising in the ordinary course of business. While the outcome and impact on us cannot be predicted with certainty, management believes the resolution of these environmental matters will not, individually or collectively, have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Lawsuits – In May 2007, the Kentucky attorney general filed a lawsuit against us and Marathon Oil in state court in Franklin County, Kentucky for alleged violations of Kentucky’s emergency pricing and consumer protection laws following Hurricanes Katrina and Rita in 2005. The lawsuit alleges that we overcharged customers by $89 million during September and October 2005. The complaint seeks disgorgement of these sums, as well as penalties, under Kentucky’s emergency pricing and consumer protection laws. We are vigorously defending this litigation. We believe that this is the first lawsuit for damages and injunctive relief under the Kentucky emergency pricing laws to progress this far and it contains many novel issues. In May 2011, the Kentucky attorney general amended his complaint to include a request for immediate injunctive relief as well as unspecified damages and penalties related to our wholesale gasoline pricing in April and May 2011 under statewide price controls that were activated by the Kentucky governor on April 26, 2011 and which have since expired. The court denied the attorney general’s request for immediate injunctive relief, and the remainder of the 2011 claims likely will be resolved along with those dating from 2005. If the lawsuit is resolved unfavorably in its entirety, it could materially impact our consolidated results of operations, financial position or cash flows. However, management does not believe the ultimate resolution of this litigation will have a material adverse effect.

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

Guarantees – We have provided certain guarantees, direct and indirect, of the indebtedness of other companies. Under the terms of most of these guarantee arrangements, we would be required to perform should the guaranteed party fail to fulfill its obligations under the specified arrangements. In addition to these financial guarantees, we also have various performance guarantees related to specific agreements.

Guarantees related to indebtedness of equity method investees – We hold interests in an offshore oil port, LOOP, and a crude oil pipeline system, LOCAP LLC. Both LOOP and LOCAP LLC have secured various project financings with throughput and deficiency agreements. Under the agreements, we are required to advance funds if the investees are unable to service their debt. Any such advances are considered prepayments of future transportation charges. The duration of the agreements vary but tend to follow the terms of the underlying debt. Our maximum potential undiscounted payments under these agreements for the debt principal totaled $172 million as of December 31, 2012.

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We hold an interest in a refined products pipeline through our investment in Centennial, and have guaranteed the payment of Centennial’s principal, interest and prepayment costs, if applicable, under a Master Shelf Agreement, which is scheduled to expire in 2024. The guarantee arose in order for Centennial to obtain adequate financing. Our maximum potential undiscounted payments under this agreement for debt principal totaled $47 million as of December 31, 2012.

We hold an interest in a ethanol production facility through our investment in TAME, and have guaranteed the repayment of TAME’s tax exempt bond financing through our participation as a lender in the credit agreement under which a letter of credit has been issued to secure repayment of the tax exempt bonds. The credit agreement expires in 2018. Our maximum potential undiscounted payments under this arrangement were $25 million at December 31, 2012.

Marathon Oil indemnifications – In conjunction with the Spinoff, we have entered into arrangements with Marathon Oil providing indemnities and guarantees with recorded values of $7 million as of December 31, 2012, which consist of unrecognized tax benefits related to MPC, its consolidated subsidiaries and the RM&T Business operations prior to the Spinoff which are not already reflected in the unrecognized tax benefits described in Note 13, and other contingent liabilities Marathon Oil may incur related to taxes. Furthermore, the separation and distribution agreement and other agreements with Marathon Oil to effect the Spinoff provide for cross-indemnities between Marathon Oil and us. In general, Marathon Oil is required to indemnify us for any liabilities relating to Marathon Oil’s historical oil and gas exploration and production operations, oil sands mining operations and integrated gas operations, and we are required to indemnify Marathon Oil for any liabilities relating to Marathon Oil’s historical refining, marketing and transportation operations. The terms of these indemnifications are indefinite and the amounts are not capped.

Other guarantees – We have entered into other guarantees with maximum potential undiscounted payments totaling $116 million as of December 31, 2012, which primarily consist of a commitment to contribute cash to an equity method investee for certain catastrophic events, up to $50 million per event, in lieu of procuring insurance coverage, an indemnity to the co-lenders associated with an equity method investee’s credit agreement, and leases of assets containing general lease indemnities and guaranteed residual values.

General guarantees associated with dispositions – 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.

Contractual commitments – At December 31, 2012 and 2011, our contractual commitments to acquire property, plant and equipment and advance funds to equity method investees totaled $1.4 billion and $347 million. The contractual commitments at December 31, 2012 include the February 2013 acquisition of a refinery and related logistics and marketing assets. See Note 26.

26. Subsequent Event

Acquisition of Refinery and Related Logistics and Marketing Assets

On February 1, 2013, we acquired from BP Products North America Inc. and BP Pipelines (North America) Inc. (collectively, “BP”) the 451,000 barrel per calendar day refinery in Texas City, Texas, three intrastate natural gas liquid pipelines originating at the refinery, an allocation of BP’s Colonial Pipeline Company

129

shipper history, four light product terminals, branded-jobber marketing contract assignments for the supply of approximately 1,200 branded sites and a 1,040 megawatt electric cogeneration facility. The base purchase price was approximately $598 million plus inventories valued at approximately $900 million. Pursuant to the purchase and sale agreement, we may also be required to pay to BP a contingent earnout of up to an additional $700 million over six years, subject to certain conditions. These assets complement our current geographic footprint and align with our strategic initiative of growing in existing and contiguous markets to enhance our portfolio. The transaction was funded with cash on hand.

A determination of the acquisition-date fair values of the assets acquired and the liabilities assumed is pending the completion of an independent appraisal and other evaluations.

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Selected Quarterly Financial Data (Unaudited)

	2012								2011
(In millions, except per share data)	1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.		1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.
Revenues	$	20,265	$	20,243	$	21,049	$	20,686	$	17,842	$	20,760	$	20,616	$	19,420
Income (loss) from operations		956		1,307		1,895		1,189		819		1,325		1,759		(158)
Net income (loss)		596		814		1,224		759		529		802		1,133		(75)
Net income (loss) attributable to MPC		596		814		1,224		755		529		802		1,133		(75)
Net income (loss) attributable to MPC per share:(a)
Basic	$	1.71	$	2.39	$	3.61	$	2.26	$	1.49	$	2.25	$	3.18	$	(0.21)
Diluted		1.70		2.38		3.59		2.24		1.48		2.24		3.16		(0.21)
Dividends paid per share		0.25		0.25		0.35		0.35		-		-		0.20		0.25

(a) For comparative purposes, and to provide a more meaningful calculation for weighted average shares, we assumed the shares distributed to Marathon Oil stockholders in conjunction with the Spinoff were outstanding as of the beginning of each period prior to the Spinoff.

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Supplementary Statistics (Unaudited)

(In millions)	2012		2011		2010
Income from Operations by segment
Refining & Marketing	$	5,098	$	3,591	$	800
Speedway		310		271		293
Pipeline Transportation(a)		216		199		183
Items not allocated to segments:
Corporate and other unallocated items(a)		(336)		(316)		(236)
Minnesota Assets sale settlement gain		183		-		-
Pension settlement expenses(a)		(124)		-		-
Impairment		-		-		(29)
Income from operations	$	5,347	$	3,745	$	1,011
Capital Expenditures and Investments(b)
Refining & Marketing	$	705	$	900	$	961
Speedway(c)		340		164		84
Pipeline Transportation		211		121		24
Corporate and Other(d)		204		138		104
Total	$	1,460	$	1,323	$	1,173

^(a)  Included in the Pipeline Transportation segment are $4 million of corporate overhead costs and pension settlement expenses attributable to MPLX subsequent to MPLX’s October 31, 2012 initial public offering, which were included in items not allocated to segments prior to MPLX’s initial public offering. These expenses are not currently allocated to other segments.

^(b) Capital expenditures include changes in capital accruals.

^(c) Includes acquisitions of 97 convenience stores in 2012 and 23 convenience stores in 2011.

^(d)  Includes capitalized interest of $101 million, $114 million and $103 million for 2012, 2011 and 2010.

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Supplementary Statistics (Unaudited)

	2012		2011		2010
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)(a)		1,618		1,599		1,585
Refining & Marketing Operating Statistics
Refinery Throughputs (thousands of barrels per day):
Crude oil refined		1,195		1,177		1,173
Other charge and blendstocks		168		181		162
Total		1,363		1,358		1,335
Crude Oil Capacity Utilization percent(b)		100		103		99
Refined Product Yields (thousands of barrels per day):
Gasoline		738		739		726
Distillates		433		433		409
Propane		26		25		24
Feedstocks and special products		109		109		97
Heavy fuel oil		18		21		24
Asphalt		62		56		76
Total		1,386		1,383		1,356
Refining & Marketing Refined Product Sales Volume (thousands of barrels per day)(c)		1,599		1,581		1,573
Refining & Marketing Gross Margin (dollars per barrel)(d)	$	10.45	$	7.75	$	2.81
Direct Operating Costs in Refining & Marketing Gross Margin (dollars per barrel):(e)
Planned turnaround and major maintenance	$	1.00	$	0.78	$	1.19
Depreciation and amortization		1.44		1.29		1.32
Other manufacturing(f)		3.15		3.16		3.32
Total	$	5.59	$	5.23	$	5.83
Speedway Operating Statistics
Convenience stores at period-end		1,464		1,371		1,358
Gasoline & distillates sales (millions of gallons)		3,027		2,938		3,300
Gasoline & distillates gross margin (dollars per gallon)(g)	$	0.1318	$	0.1308	$	0.1207
Merchandise sales (in millions)	$	3,058	$	2,924	$	3,195
Merchandise gross margin (in millions)	$	795	$	719	$	789
Same store gasoline sales volume (period over period)		-0.8%		-1.7%		3.0%
Same store merchandise sales (period over period)		0.9%		1.1%		4.4%
Same store merchandise sales excluding cigarettes (period over period)		7.0%		6.7%		6.2%
Pipeline Transportation Operating Statistics
Pipeline throughput (thousands of barrels per day)(h):
Crude oil pipelines		1,190		1,184		1,204
Refined products pipelines		980		1,031		968
Total		2,170		2,215		2,172

^(a)  Total average daily volumes of refined product sales to wholesale, branded and retail (Speedway segment) customers.

^(b)  Based on calendar day capacity, which is an annual average that includes downtime for planned maintenance and other normal operating activities.

^(c)  Includes intersegment sales.

^(d)  Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation and amortization, divided by Refining & Marketing segment refined product sales volume.

^(e)  Per barrel of total refinery throughputs.

^(f)  Includes utilities, labor, routine maintenance and other operating costs.

^(g)  The price paid by consumers less the cost of refined products, including transportation, consumer excise taxes and bankcard processing fees, divided by gasoline and distillates sales volume.

^(h)  On owned common-carrier pipelines, excluding equity method investments.

133

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

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934, as amended) was carried out under the supervision and with the participation of our management, including our chief executive officer and chief financial officer. 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, 2012, the end of the period covered by this Annual Report on Form 10-K.

Internal Control over Financial Reporting and Changes in 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, which reports are incorporated herein by reference. During the quarter ended December 31, 2012, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

134

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 sub-heading “Proposal No. 1 - Election of Class II Directors” located under the heading “Proposals of the Board” in our Proxy Statement for the 2013 Annual Meeting of Shareholders. Information concerning our executive officers is included in Part I, Item 1 of this Annual Report on Form 10-K.

Our Board of Directors has established the Audit Committee and determined our “Audit Committee Financial Experts.” The related information required by this item is incorporated by reference to the material appearing under the sub-heading “Audit Committee Financial Expert” located under the heading “The Board of Directors and Corporate Governance” in our Proxy Statement for the 2013 Annual Meeting of Shareholders.

We have adopted a Code of Ethics for Senior Financial Officers. It is available on our website at http://ir.marathonpetroluem .com by selecting “Corporate Governance” and clicking on “Code of Ethics for Senior Financial Officers.”

Section 16(a) Beneficial Ownership Reporting Compliance

Information regarding compliance with Section 16(a) of the Securities Exchange Act of 1934 is set forth under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” in our Proxy Statement for the 2013 Annual Meeting of Shareholders, which is incorporated herein by reference.

Item 11. Executive Compensation

Information required by this item is incorporated by reference to the material appearing under the heading “Executive Compensation;” under the sub-headings “Compensation Committee” and “Compensation Committee Interlocks and Insider Participation” under the heading “The Board of Directors and Corporate Governance;” under the heading “Compensation of Directors;” and under the heading “Compensation Committee Report” in our Proxy Statement for the 2013 Annual Meeting of Shareholders.

135

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 2013 Annual Meeting of Shareholders.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2012 with respect to shares of our common stock that may be issued under the MPC 2011 Plan and the MPC 2012 Plan:

	Column (a)			Column (b)		Column (c)
Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights			Weighted- average exercise price of outstanding options, warrants and rights(b)		Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by stockholders		6,568,196	(a)	$	36.17		24,975,445	(c)
Equity compensation plan not approved by stockholders		-			-		-
Total		6,568,196			N/A		24,975,445

(a) Includes the following:

1) 6,048,973 stock options granted pursuant to the MPC 2011 Plan and not forfeited, cancelled or expired as of December 31, 2012.

2) 95,350 as the net number of shares that could be issued pursuant to the exercise of stock appreciation rights not forfeited, cancelled or expired as of December 31, 2012 based on the closing price of our common stock on December 31, 2012 of $63.00 per share. Shares available for issuance under the MPC 2011 Plan are reduced by the full number of stock appreciation rights exercised, even though the net number of shares issued may be less. The full number of stock appreciation rights granted pursuant to the MPC 2011 Plan and not forfeited, cancelled or expired as of December 31, 2012 is 123,221.

3) 359,111 restricted stock units granted pursuant to the MPC 2011 Plan and the MPC 2012 Plan for shares unissued and not forfeited, cancelled or expired as of December 31, 2012.

4) 64,762 shares as the maximum potential number of shares that could be issued in settlement of performance units outstanding as of December 31, 2012 pursuant to the MPC 2011 Plan based on the closing price of our common stock on December 31, 2012 of $63.00 per share. The number of shares reported in column (a) for this award vehicle may overstate dilution. See Note 23 for more information on performance unit awards granted under the MPC 2011 Plan.

In addition to the awards reported above, 638,073 shares of restricted stock were issued pursuant to the MPC 2011 Plan and the MPC 2012 Plan and were outstanding as of December 31, 2012.

^(b)  Restricted stock, restricted stock units and performance units are not taken into account in the weighted-average exercise price as such awards have no exercise price.

^(c)  Reflects the shares available for issuance pursuant to the MPC 2011 Plan and the MPC 2012 Plan. No more that 9,975,445 of these shares may be issued for awards other than stock options or stock appreciation rights. In addition, shares related to grants made pursuant to the MPC 2012 Plan that are forfeited, cancelled or expire unexercised become immediately available for issuance under the MPC 2012 Plan.

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 Corporate Governance” in our Proxy Statement for the 2013 Annual Meeting of Shareholders.

136

Item 14. Principal Accounting Fees and Services

Information required by this item is incorporated by reference to the material appearing under the heading “Independent Registered Public Accounting Firm’s Fees, Services and Independence” in our Proxy Statement for the 2013 Annual Meeting of Shareholders.

137

PART IV

Item 15. Exhibits and Financial Statement Schedules

A. Documents Filed as Part of the Report

1. Financial Statements (see Part II, Item 8. of this Annual Report on Form 10-K regarding financial statements)

2. Financial Statement Schedules

Financial statement schedules required under SEC rules but not included in this Annual Report on Form 10-K are omitted because they are not applicable or the required information is contained in the consolidated financial statements or notes thereto.

3. Exhibits:

Exhibit Number	Exhibit Description		Incorporated by Reference			Filed Herewith	Furnished Herewith
		Form	Exhibit	Filing Date	SEC File No.
2	Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession
2.1 †	Separation and Distribution Agreement, dated as of May 25, 2011, among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation	10	2.1	5/26/2011	001-35054
2.2 †	Purchase and Sale Agreement, dated as of October 7, 2012, by and among BP Products North America Inc. and BP Pipelines (North America) Inc., as the Sellers and Marathon Petroleum Company LP, as the Buyer	8-K	2.1	10/9/2012	001-35054
3	Articles of Incorporation and Bylaws
3.1	Restated Certificate of Incorporation of Marathon Petroleum Corporation	8-K	3.1	6/22/2011	001-35054
3.2	Amended and Restated Bylaws of Marathon Petroleum Corporation	10-Q	3.2	8/8/2012	001-35054
4	Instruments Defining the Rights of Security Holders, Including Indentures
4.1	Indenture dated as of February 1, 2011 between Marathon Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee	10	4.1	5/26/2011	001-35054
4.2	Form of the terms of the 3 1/2% Senior Notes due 2016, 5 1/8% Senior Notes due 2021 and 6 1/2% Senior Notes due 2041 of Marathon Petroleum Corporation	10	4.2	5/26/2011	001-35054
4.3	Form of 3 1/2% Senior Notes due 2016, 5 1/8% Senior Notes due 2021 and 6 1/2% Senior Notes due 2041 of Marathon Petroleum Corporation (included in Exhibit 4.2 above)	10	4.3	5/26/2011	001-35054
4.4	Registration Rights Agreement among Marathon Petroleum Corporation, Marathon Oil Corporation and Morgan Stanley & Co. Incorporated and J.P. Morgan Securities LLC	10	4.4	5/26/2011	001-35054
10	Material Contracts
10.1	Tax Sharing Agreement dated as of May 25, 2011 by and among Marathon Oil Corporation, Marathon Petroleum Corporation and MPC Investment LLC	10	10.1	5/26/2011	001-35054
10.2	Employee Matters Agreement dated as of May 25, 2011 by and between Marathon Oil Corporation and Marathon Petroleum Corporation	10	10.2	5/26/2011	001-35054
10.3	Amendment to Employee Matters Agreement, dated as of June 30, 2011 by and between Marathon Oil Corporation and Marathon Petroleum Corporation	8-K	10.1	7/1/2011	001-35054

138

Exhibit Number	Exhibit Description		Incorporated by Reference			Filed Herewith	Furnished Herewith
		Form	Exhibit	Filing Date	SEC File No.
10.4	Amended and Restated Receivables Purchase Agreement, dated as of October 1, 2011, by and among Marathon Petroleum Company LP, MPC Trade Receivables Company LLC, JPMorgan Chase Bank, N.A. as Administrative Agent, J.P. Morgan Securities LLC, as Sole Lead Arranger, certain committed purchasers and conduit purchasers that are parties thereto from time to time and other parties thereto from time to time	8-K	10.1	10/6/2011	001-35054
10.5	Amended and Restated Receivables Sale Agreement, dated as of October 1, 2011, by and between Marathon Petroleum Company LP and MPC Trade Receivables Company LLC	8-K	10.2	10/6/2011	001-35054
10.6	Revolving Credit Agreement, dated as of September 14, 2012, by and among MPC, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, each of J.P. Morgan Securities LLC, Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley Senior Funding, Inc., RBS Securities Inc. and UBS Securities LLC, as joint lead arrangers and joint bookrunners, Citigroup Global Markets Inc., as syndication agent, each of Bank of America, N.A., Morgan Stanley Senior Funding, Inc., The Royal Bank of Scotland PLC and USB AG, Stamford Branch, as documentation agents, and several other commercial lending institutions that are parties thereto.	8-K	10.1	9/20/2012	001-35054
10.7	First Amendment, dated December 20, 2012, to the Revolving Credit Agreement, dated as of September 14, 2012, by and among MPC, as borrower, the commercial financial institutions that are lending parties thereto, and JPMorgan Chase Bank, N.A., as administrative agent.	8-K	10.1	12/20/2012	001-35054
10.8	Revolving Credit Agreement, dated as of September 14, 2012, by and among MPLX Operations LLC, as borrower, MPLX LP, as parent guarantor, Citibank, N.A., as administrative agent, each of Citigroup Global Markets Inc., J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Morgan Stanley Senior Funding, Inc., RBS Securities Inc. and UBS Securities LLC, as joint lead arrangers and joint bookrunners, JPMorgan Chase Bank, National Association, as syndication agent, each of Bank of America, N.A., Morgan Stanley Senior Funding, Inc., The Royal Bank of Scotland PLC and USB AG, Stamford Branch, as co-documentation agents, and several other commercial lending institutions that are parties thereto.	8-K	10.2	9/20/2012	001-35054
10.9	Contribution, Conveyance and Assumption Agreement, dated as of October 31, 2012, among MPLX LP, MPLX GP LLC, MPLX Operations LLC, MPC Investment LLC, MPLX Logistics Holdings LLC, Marathon Pipe Line LLC, MPL Investment LLC, MPLX Pipe Line Holdings LP and Ohio River Pipe Line LLC.	8-K	10.1	11/6/2012	001-35054
10.1	Omnibus Agreement, dated as of October 31, 2012, among Marathon Petroleum Corporation, Marathon Petroleum Company LP, MPL Investment LLC, MPLX Operations LLC, MPLX Terminal and Storage LLC, MPLX Pipe Line Holdings LP, Marathon Pipe Line LLC, Ohio River Pipe Line LLC, MPLX LP and MPLX GP LLC.	8-K	10.2	11/6/2012	001-35054
10.11 *	Marathon Petroleum Corporation Second Amended and Restated 2011 Incentive Compensation Plan	S-3	4.3	12/7/2011	333-175286
10.12 *	Marathon Petroleum Corporation Policy for Recoupment of Annual Cash Bonus Amounts	10-K	10.1	2/29/2012	001-35054
10.13 *	Marathon Petroleum Corporation Deferred Compensation Plan for Non-Employee Directors					X
10.14 *	Marathon Petroleum Excess Benefit Plan	10-K	10.12	2/29/2012	001-35054
10.15 *	Marathon Petroleum Amended and Restated Deferred Compensation Plan	10-K	10.13	2/29/2012	001-35054
10.16 *	Marathon Petroleum Corporation Executive Tax, Estate, and Financial Planning Program	10-K	10.14	2/29/2012	001-35054

139

Exhibit Number	Exhibit Description		Incorporated by Reference			Filed Herewith	Furnished Herewith
		Form	Exhibit	Filing Date	SEC File No.
10.17 *	Speedway Excess Benefit Plan	10-K	10.15	2/29/2012	001-35054
10.18 *	Speedway Deferred Compensation Plan	10-K	10.16	2/29/2012	001-35054
10.19 *	Form of Marathon Petroleum Corporation Amended and Restated 2011 Incentive Compensation Plan – Section 16 Officer Restricted Stock Award Agreement (3 year pro rata vesting)	8-K	10.4	7/7/2011	001-35054
10.20 *	Form of Marathon Petroleum Corporation Amended and Restated 2011 Incentive Compensation Plan – Section 16 Officer Restricted Stock Award Agreement (3 year cliff vesting)	8-K	10.5	7/7/2011	001-35054
10.21 *	Form of Marathon Petroleum Corporation Amended and Restated 2011 Incentive Compensation Plan Nonqualified Stock Option Award Agreement – Section 16 Officer	8-K	10.6	7/7/2011	001-35054
10.22 *	Form of Marathon Petroleum Corporation 2011 Incentive Compensation Plan Supplemental Restricted Stock Award Agreement – Section 16 Officer	8-K	10.1	12/7/2011	001-35054
10.23 *	Form of Marathon Petroleum Corporation 2011 Incentive Compensation Plan Supplemental Nonqualified Stock Option Award Agreement – Section 16 Officer	8-K	10.2	12/7/2011	001-35054
10.24 *	Form of Marathon Petroleum Corporation 2011 Incentive Compensation Plan Supplemental Restricted Stock Unit Award Agreement – Non-Employee Director	10-K	10.22	2/29/2012	001-35054
10.25 *	Form of Marathon Petroleum Corporation Amended and Restated 2011 Incentive Compensation Plan – Performance Unit Award Agreement	10-K	10.23	2/29/2012	001-35054
10.26 *	Marathon Petroleum Corporation Amended and Restated Executive Change in Control Severance Benefits Plan					X
10.27 * `	Form of Marathon Petroleum Corporation Performance Unit Award Agreement – 2012-2014 Performance Cycle	10-Q	10.3	5/9/2012	001-35054
10.28 *	Form of Marathon Petroleum Corporation Restricted Stock Award Agreement – Officer	10-Q	10.4	5/9/2012	001-35054
10.29 *	Form of Marathon Petroleum Corporation Nonqualified Stock Option Award Agreement – Officer	10-Q	10.5	5/9/2012	001-35054
10.30 *	Marathon Petroleum Corporation 2012 Incentive Compensation Plan	S-8	4.3	4/27/2012	333-181007
10.31 *	Amended and Restated Marathon Petroleum Annual Cash Bonus Program	10-Q	10.1	11/9/2012	001-35054
10.32 *	MPC Non-Employee Director Phantom Unit Award Policy					X
12.1	Computation of Ratio of Earnings to Fixed Charges					X
14.1	Code of Ethics for Senior Financial Officers	10-K	14.1	2/29/2012	001-35054
21.1	List of Subsidiaries					X
23.1	Consent of Independent Registered Public Accounting Firm					X
24.1	Power of Attorney of directors and officers of Marathon Petroleum Corporation					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 Senior 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 Senior Vice President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350.						X
101.INS  +	XBRL Instance Document.						X
101.SCH +	XBRL Taxonomy Extension Schema.						X
101.PRE +	XBRL Taxonomy Extension Presentation Linkbase.						X
101.CAL +	XBRL Taxonomy Extension Calculation Linkbase.						X
101.DEF +	XBRL Taxonomy Extension Definition Linkbase.						X
101.LAB +	XBRL Taxonomy Extension Label Linkbase.						X

140

† The exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be provided to the Securities and Exchange Commission upon request.

* Indicates management contract or compensatory plan, contract or arrangement in which one or more directors or executive officers of the Registrant may be participants.

+ XBRL (eXtensible Business Reporting Language) information is furnished and not filed or a part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and otherwise is not subject to liability under these sections.

141

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, 2013	MARATHON PETROLEUM CORPORATION
	By:    /s/ Michael G. Braddock
	Michael G. Braddock                 Vice President and Controller

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on February 28, 2013 on behalf of the registrant and in the capacities indicated.

Signature	Title
/s/ Gary R. Heminger Gary R. Heminger	President and Chief Executive Officer and Director (Principal Executive Officer)
* Donald C. Templin	Senior Vice President and Chief Financial Officer (Principal Financial Officer)
/s/ Michael G. Braddock Michael G. Braddock	Vice President and Controller (Principal Accounting Officer)
* Evan Bayh	Director
* David A. Daberko	Director
* William L. Davis	Director
* Donna A. James	Director
* Charles R. Lee	Director
* Seth E. Schofield	Director
John W. Snow	Director
* John P. Surma	Director
* Thomas J. Usher	Chairman of the Board and Director

142

* The undersigned, by signing his name hereto, does sign and execute this report pursuant to the Power of Attorney executed by the above-named directors and officers of the registrant, which is being filed herewith on behalf of such directors and officers.

By:    /s/ Gary R. Heminger	February 28, 2013
Gary R. Heminger                 Attorney-in-Fact

143

EX-10.13

Exhibit 10.13

MARATHON PETROLEUM CORPORATION

DEFERRED COMPENSATION PLAN

FOR NON-EMPLOYEE DIRECTORS

(Amended and Restated effective as of the December 3, 2012)

1. Purpose

The Marathon Petroleum Corporation Deferred Compensation Plan for Non-Employee Directors (the “Plan”) is intended to enable the Corporation to attract and retain non-employee Directors and to enhance the long-term mutuality of interest between such Directors and shareholders of the Corporation.

This document contains the provisions of the Plan effective as the effective time of the spin-off of Marathon Petroleum Corporation from Marathon Oil Corporation and thereafter, and shall apply to Deferred Cash and Stock Accounts, including 409A Benefits and Grandfathered Benefits (as such terms are defined below). In particular, the Plan document shall apply to those stock units and other similar equity awards granted to Participants under the 2011 Incentive Compensation Plan, the 2012 Incentive Compensation Plan, as well as successor or predecessor arrangements, and deferred under this Plan or its predecessor.

With respect to the 409A Benefits, the Plan is intended to conform to the requirements of Code Section 409A and the regulations thereunder, and, in all respects, shall be administered and construed in accordance with such requirements. With respect to the Grandfathered Benefits, the Plan does not represent a material enhancement of the benefits or rights available under the Marathon Oil Corporation Deferred Compensation Plan for Non-Employee Directors on October 3, 2004, which have subsequently been assumed by this Plan in connection with the spin-off of Marathon Petroleum Corporation from Marathon Oil Corporation.

2. Definitions

The following definitions apply to this Plan and to the Deferral Election Forms:

(a) 409A Benefit means that portion of a Participant’s Deferred Cash Account and Deferred Stock Account that was deferred or became vested after December 31, 2004, with earnings and losses attributable thereto pursuant to Sections 5 and 6.

(b) Beneficiary or Beneficiaries means a person or persons or other entity designated on a beneficiary designation form by a Participant as allowed in this Plan to receive Deferred Benefit payments. If there is no valid designation by the Participant, or if the designated Beneficiary or Beneficiaries fail to survive the Participant or otherwise fail to take the Benefit, the Participant’s Beneficiary is the Participant’s surviving spouse or, if there is no surviving spouse, the Participant’s estate. A Participant may use a beneficiary designation form (in the form and manner acceptable to the Committee) to designate one or more Beneficiaries for all of the Participant’s Deferred Benefit; such designations are revocable.

(c) Board means the Board of Directors of Marathon Petroleum Corporation.

(d) Code means the Internal Revenue Code of 1986 as amended, including regulations and other guidance of general applicability promulgated thereunder.

(e) Code Section 409A means, collectively, Section 409A of the Code and any Treasury and Internal Revenue Service regulations and guidance issued thereunder.

(f) Committee means the Corporate Governance and Nominating Committee of the Board or such

other committee of the Board as the Board may designate to administer the Plan. In the event the Committee has delegated any authority or responsibility under the Plan in accordance with Section 12, the term “Committee” where used herein shall also refer to the applicable delegate.

(g) Common Stock means the common stock of the Corporation.

(h) Common Stock Unit means a book-entry unit equal in value to a share of Common Stock. A Participant shall be credited with one Common Stock Unit for each stock unit or hypothetical share of Common Stock granted pursuant to a Director Stock Award (or any successor stock incentive arrangement).

(i) Corporation means Marathon Petroleum Corporation or any successor thereto.

(j) Deferral Election Form means a document designated by the Committee for the purpose of allowing a Participant to elect deferrals under Section 3.

(k) Deferral Year means the calendar year for which a Participant has elected to defer amounts under this Plan.

(l) Deferred Benefit means a Participant’s Deferred Cash Account and Deferred Stock Account under the Plan.

(m) Deferred Cash Account means that bookkeeping record established for each Participant to reflect the status of the Participant’s Deferred Cash Benefit under this Plan. A Deferred Cash Account: (i) is established only for purposes of measuring a Deferred Cash Benefit and not to segregate assets or to identify assets that may or must be used to satisfy a Deferred Cash Benefit; (ii) will be credited with that portion of the Participant’s Retainer Fee deferred as a Deferred Cash Benefit according to a Deferral Election Form; and (iii) will be credited periodically with earnings and losses as provided under Section 5.

(n) Deferred Cash Benefit means the amount of Retainer Fees deferred by a Participant under Section 3.

(o) Deferred Stock Account means that bookkeeping record established for each Participant to reflect the status of the Participant’s Deferred Stock Benefit under this Plan. A Deferred Stock Account is established only for purposes of measuring Common Stock Units and not to segregate assets or to identify assets that may or must be used to satisfy a Deferred Stock Benefit. A Deferred Stock Account will be credited with the Common Stock Units that are awarded to a Participant quarterly, annually or at such other times that awards are made and deferred. A Deferred Stock Account will be credited periodically with additional Common Stock Units that reflect the value of dividends paid on Common Stock pursuant to Section 6.

(p) Deferred Stock Benefit means the number of Common Stock Units that are deferred pursuant to Section 3 or Section 6. In addition to the Common Stock Units granted pursuant to any Director Stock Award, a Participant’s Deferred Stock Benefit shall also include any Common Stock Units granted in connection with the spin-off of Marathon Petroleum Corporation from Marathon Oil Corporation in substitution for common stock units of Marathon Oil Corporation.

(q) Directors means those duly named members of the Board.

(r) Director Stock Award means an award of Common Stock Units pursuant to Section 6 of this Plan, as amended from time to time, or, in the discretion of the Committee, any successor or similar stock incentive award.

(s) Election Date means the date established by this Plan as the date before which a Participant must submit a valid Deferral Election Form to the Committee. For each Deferral Year, the Election Date is December 31 of the preceding calendar year; provided, however, that the Election Date for newly eligible Directors shall be as provided in Section 3(a). Notwithstanding the foregoing, the Committee may set an earlier date as the Election Date for any Deferral Year. All Election Dates shall be established in conformity with Code Section 409A.

(u) Grandfathered Benefit means that portion of a Participant’s Deferred Cash Account and Deferred Stock Account that is exempt from Code Section 409A because it was deferred and vested under the Marathon Oil Corporation Deferred Compensation Plan for Non-Employee Directors as of December 31, 2004, as adjusted to reflect any earnings or losses thereto pursuant to Sections 5 and 6, and in the case of Common Stock Units, to reflect the spin-off of Marathon Petroleum Corporation from Marathon Oil Corporation.

(v) Participant means a Director who is not simultaneously an employee of the Corporation.

(w) Plan means the Marathon Petroleum Corporation Deferred Compensation Plan for Non-Employee Directors.

(x) Quarterly Director Award Date means the first business day of the calendar quarter.

(y) Quarterly Director Stock Award means a grant of Common Stock Units as provided in Section 6(a) of this Plan.

(z) Retainer Fee means that portion of a Participant’s compensation that is fixed and paid without regard to the Participant’s attendance at meetings.

(aa) Separation from Service shall have the same meaning as set forth under Code Section 409A.

(bb) Specified Employee shall have the same meaning as set forth under Code Section 409A and as determined by the Corporation in accordance with its established policy.

3. Deferral Election

A deferral election is valid when a Deferral Election Form is completed, signed by the Participant, and received by the Committee. Deferral elections are governed by the provisions of this section.

(a) No later than each Deferral Year’s Election Date, each Participant may submit a Deferral Election Form to defer until after Separation from Service the receipt of any portion up to 100 percent of the Participant’s Retainer Fee for the Deferral Year in the form of a Deferred Cash Benefit. In the event an individual becomes a Director and is first eligible to participate during a Deferral Year, such Director may submit a Deferral Election Form no later than thirty (30) days following the effective date of the individual’s position as a Director, provided that, to the extent required by Code Section 409A, the Retainer Fee subject to the election shall be prorated in accordance with Code Section 409A.

(b) Common Stock Units awarded pursuant to a Director Stock Award are automatically deferred and accounted for in a Deferred Stock Account and are not subject to any Deferral Election.

(c) If it does so before the last business day preceding the Deferral Year, the Committee may reject or modify any Deferral Election Form for such Deferral Year and the Committee is not required to state a reason for such action. However, the Committee’s rejection or modification of any Deferral Election Form must be based upon action taken without regard to any vote of the Participant whose Deferral Election Form is under consideration, and the Committee’s rejections or modifications must be made on a uniform basis with respect to similarly situated Participants. If the Committee rejects or modifies a Deferral Election Form, the Participant must be paid the Retainer Fee that the Participant is entitled to receive after taking into account the rejected or modified Deferral Election Form.

(d) A Participant may not revoke a Deferral Election Form after the Deferral Year begins. Any writing signed by a Participant expressing an intention to revoke the Participant’s Deferral Election Form before the close of business on the relevant Election Date is a revocation. In the event the Retainer Fee is paid in more than one payment during a Deferral Year, a Participant’s deferral may be taken from such Retainer Fee ratably during the applicable Deferral Year or in any other manner determined by the Committee; provided that such deferrals during the Plan Year, in the aggregate, reflect the Participant’s deferral election in accordance with Code Section 409A.

4. Effect of No Election

For any Participant who does not submit a valid Deferral Election Form to the Committee by the Election Date for a Deferral Year, the Participant’s Deferral Election Form then in effect shall remain effective for the upcoming Deferral Year. Any Participant who does not submit a valid Deferral Election Form by the Election Date and does not have a deferral election then in effect may not defer any part of the Participant’s Retainer Fee for the Deferral Year.

5. Deferred Cash Benefits

(a) The Deferred Cash Account for each Participant will be credited with deemed investment returns as provided in section 5(b). Deferred Cash Benefits are credited to the applicable Participant’s Deferred Cash Account as of the day the Retainer Fees would have been paid but for the deferral.

(b) A Participant may select one or more investment options approved by the Committee for the Participant’s Deferred Cash Benefits, and earnings and loses from such investment options will be credited to the Participant’s Deferred Cash Account at periods determined by the Committee. A Participant may change the investment allocation of the Participant’s Deferred Cash Account at any time.

6. Deferred Equity Benefits

(a) Grant of Common Stock Units

i. Pursuant to paragraphs 8 of the Marathon Petroleum Corporation 2011 and 2012 Incentive Compensation Plans, the Board is authorized to grant Director Stock Awards to the Participants. The terms, conditions and limitations applicable to such Director Stock Awards are to be determined by the Board. Pursuant to Section 12 of this Plan, the Board has delegated its authority to the Committee.

ii. All Participants shall receive Quarterly Director Stock Awards under this Plan.

iii. A Participant who has attained or is expected to attain the applicable mandatory retirement age under the Corporation’s mandatory retirement policy, before the next regularly scheduled annual meeting of the Corporation’s stockholders shall receive a pro-rated Quarterly Director Stock Award for the quarter in which the next regularly scheduled annual meeting of the Corporation’s stockholders will be held. If this Section 3(a)(iii) applies, the Quarterly Stock Award will be pro-rated based on the number of days in the quarter that the Participant shall serve as a Director, including the day on which the annual meeting is held.

iv. Except as provided in Section 3(a)(iii), each Participant shall be granted a Quarterly Director Stock Award equal to a number of unvested Common Stock Units, including fractional Common Stock Units, determined by dividing (i) $37,500 by (ii) the Fair Market Value (as defined in the Marathon Petroleum Corporation 2011 Incentive Compensation Plan or 2012 Incentive Compensation Plan, as applicable) of a share of Common Stock on the date of grant. Alternatively, in any quarter in which a Participant receives a grant of MPLX LP deferred partnership units valued at $3,750 as a component of such Participant’s Non-Employee Director compensation, such Participant shall be granted a Quarterly Director Stock Award equal to a number of unvested Common Stock Units, including fractional Common Stock Units, determined by dividing (i) $33,750 by (ii) the Fair Market Value (as defined in the Marathon Petroleum Corporation 2011 Incentive Compensation Plan or 2012 Incentive Compensation Plan, as applicable) of a share of Common Stock on the date of grant. These grants to all Participants shall automatically be made on the Quarterly Director Award Date.

v. The Common Stock Units granted under this Section 3(a) shall vest in full upon the Participant’s departure from the Board. Each Participant’s Deferred Stock Account will be credited with the number of Common Stock Units granted pursuant to a Quarterly Director Stock Award as of the applicable Quarterly Director Award Date.

(b) Each Common Stock Unit held in a Deferred Stock Account will increase or decrease in value by the same amount and with the same frequency as the fair market value of a share of Common Stock.

(c) Each Deferred Stock Account will be credited on or about each Common Stock dividend payment date with additional Common Stock Units, including fractional units, in a quantity equal to the quotient of the dividends payable on the quantity of shares equal to the number of Common Stock Units in such account divided by the value of a share of Common Stock on the date of that payment as determined in accordance with the manner established by the Committee from time to time.

(d) In the event of a reorganization, recapitalization, stock split, stock dividend, combination of shares, merger, consolidation, rights offering or any other change in the corporate structure, the number and kind of Common Stock Units credited to each Participant’s Deferred Stock Account shall be adjusted accordingly.

(e) Participants who are eligible for a Director Stock Award under this Plan may also receive a portion of their equity compensation in the form of awards of deferred partnership units of MPLX LP under the MPLX LP 2012 Incentive Compensation Plan as determined by the Board of Directors of MPLX GP LLC and subject to the terms and conditions of such MPLX LP plan and any applicable MPLX LP award instruments or policies.

7. Distributions

(a) A Deferred Cash Benefit must be distributed in cash. A Deferred Stock Benefit must be distributed in shares of Common Stock and such distribution will correspond to, and equal to the number of, the Common Stock Units credited to the Participant’s Deferred Stock Account; provided that cash must be paid in lieu of fractional shares of the Common Stock otherwise distributable.

(b) Except as otherwise provided in this Section 7, a Participant’s Deferred Benefit shall be paid in a lump sum on the first day of the calendar month following the expiration of 45 days after the Participant’s Separation from Service for any reason other than death.

(c) In the event of the death of a Participant, the Participant’s Deferred Benefit shall be paid to the Participant’s Beneficiary (or Beneficiaries) in a lump sum in the February of the year following the Participant’s death or if earlier, on the first day of the calendar month following the expiration of 45 days after the Participant’s Separation from Service as described in Section 7(b) (or, in the event of a Separation from Service of a Specified Employee not on account of death, within the 45-day period described in Section 7(d)).

(d) Distribution of the Deferred Benefit of a Participant who the Committee determines is a Specified Employee (other than the Participant’s Grandfathered Benefit) shall commence within the 45-day period following the first of the month following 6 months after Separation from Service (other than a Separation from Service on account of the death of Participant). In the event of a Separation from Service of a Specified Employee on account of death, payment shall be made pursuant to Section 7(c). Payment of a Specified Employee’s Grandfathered Benefit shall be made pursuant to Sections 7(b).

8. Corporation’s Obligation

(a) The Plan is unfunded. A Deferred Benefit is at all times solely a contractual obligation of the Corporation. A Participant and the Participant’s Beneficiaries have no right, title or interest in the Participant’s Deferred Benefit or any claim against them. Except according to section 8(b), the Corporation will not segregate any funds or assets for Deferred Benefits nor issue any notes or security for the payment of any Deferred Benefit.

(b) The Corporation may establish a grantor trust and transfer to that trust shares of the Common Stock or other assets. The governing trust agreement must require a separate account to be established for each electing Participant. The governing trust agreement must also require that all Corporation assets held in trust remain at all times subject to the Corporation’s creditors.

9. Control by Participant

A Participant has no control over the Participant’s Deferred Benefit except according to the Participant’s Deferral Election Form, Distribution Election Form, and Beneficiary Designation Form.

10. Claims Against Participant’s Deferred Benefit

A Deferred Benefit relating to a Participant under this Plan is not subject in any manner to anticipation, alienation, sale, transfer, assignment, pledge, encumbrance, or charge, and any attempt to do so is void. A Deferred Benefit is not subject to attachment or legal process for a Participant’s debts or other obligations. Nothing contained in this Plan gives any Participant any interest, lien or claim against any specific asset of the Corporation. A Participant or the Participant’s Beneficiary has no rights other than as a general creditor. The Plan shall not recognize or give effect to any domestic relations order attempting to alienate, transfer or assign any Deferred Benefits.

11. Amendment or Termination

This Plan may be altered, amended, suspended, or terminated at any time by the Committee, provided that with respect to 409A Benefits such action shall conform to the requirements of Code Section 409A. No future amendment to the Plan shall apply to Grandfathered Benefits to the extent such provision or amendment would constitute a “material modification” within the meaning of Code Section 409A with respect to the Grandfathered Benefits unless such amendment expressly indicates otherwise.

12. Administration

The Committee shall have the full and exclusive power and authority to administer this Plan and to take all actions that are specifically contemplated hereby or are necessary or appropriate in connection with the administration hereof. The Committee shall also have full and exclusive power to interpret this Plan, to adopt such rules, regulations and guidelines for carrying out this Plan as it may deem necessary or proper, and to delegate some or all of its authority or responsibilities under this Plan to any other person or entity. The Committee may correct any defect or supply an omission or reconcile any inconsistency in this Plan in the manner and to the extent the Committee deems necessary or desirable to further the Plan purposes. Any decision of the Committee in the interpretation and administration of this Plan shall lie within its sole and absolute discretion and shall be final, conclusive and binding on all parties concerned.

13. Notices

Notices and elections under this Plan may be in writing or in electronic format. A notice or election is deemed delivered if it is delivered personally or if it is mailed by registered or certified mail or via electronic delivery to the person at the individual’s last known business address or electronic mail address.

14. Waiver

The waiver of a breach of any provision in this Plan does not operate as and may not be construed as a waiver of any later breach.

15. Construction

This Plan is created, adopted, maintained and governed according to the laws of the state of Delaware. Headings and captions are only for convenience; they do not have substantive meaning. If a provision of this Plan is not valid or not enforceable, the validity or enforceability of any other provision is not affected. Use of one gender includes all, and the singular and plural include each other. This Plan is intended to conform to the requirements of Code Section 409A and shall be interpreted accordingly.

16. Effective Date

The original effective date of the Plan is the Distribution Date, as defined in the Separation and Distribution Agreement among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation, dated as of May 25, 2011, as such agreement may be amended. This Plan has been amended and restated effective December 3, 2012.

EX-10.26

Exhibit 10.26

Marathon Petroleum Corporation

Amended and Restated

Executive Change in Control Severance Benefits Plan

(Effective October 31, 2012)

1. Purpose of the Plan.

Marathon Petroleum Corporation and its subsidiaries and affiliates recognize that the contributions of its senior executives to the growth and success of the Corporation (as defined below) are and will continue to be substantial, and the Corporation desires to assure the continued employment of its senior executives. In this connection, the Board of Directors of the Corporation (the “Board”) recognizes that, as is the case with many publicly-held corporations, the possibility of a change in control may exist and that such possibility, and the uncertainty and questions which it may raise among management, may result in the departure or distraction of management personnel to the detriment of the Corporation and its stockholders.

Accordingly, the Board has determined that appropriate steps should be taken to reinforce and encourage the continued attention and dedication of the Corporation’s senior executives to their assigned duties without distraction in the face of potentially disturbing circumstances arising from the possibility of a change in control of the Corporation.

In order to induce senior executives to remain in the employ of the Corporation, the Corporation has established this Marathon Petroleum Corporation Amended and Restated Executive Change in Control Severance Benefits Plan (the “Plan”).

2. Definitions.

As used in the Plan, the following terms shall have the following meanings (and the singular includes the plural, unless the context clearly indicates otherwise):

Administrator: The Compensation Committee of the Board, provided that the Administrator may delegate its authority under this Plan pursuant to such conditions or limitations as the Administrator may establish.

Applicable Event: “Applicable Event” shall mean a Change in Control or a Potential Change in Control.

Cause: “Cause” shall mean a Separation from Service of the Employee by the Corporation upon (i) the willful and continued failure by the Employee to substantially perform the Employee’s duties with the Corporation (other than any such failure resulting from Separation from Service by the Employee for Good Reason or any such failure resulting from the Employee’s incapacity due to physical or mental illness), after a demand for substantial performance is delivered to the Employee that specifically identifies the manner in which the Corporation believes that the Employee has not substantially performed his or her duties, and the Employee has failed to resume substantial performance of his or her duties on a continuous basis within 14 days of receiving such demand, (ii) the willful engaging by the Employee in conduct which is demonstrably and materially injurious to the Corporation, monetarily or otherwise or (iii) the Employee’s conviction of a felony or conviction of a misdemeanor which impairs the Employee’s ability substantially to perform his or her duties with the Corporation. For purposes of Cause, no act, or failure to act, on the Employee’s part shall be deemed “willful” unless done, or omitted to be done, by the Employee not in good faith and without reasonable belief that the action or omission was in the best interest of the Corporation.

Change in Control of the Corporation and Change in Control: A change in control of a nature that would be required to be reported in response to Item 6(e) of Schedule 14A of Regulation 14A promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), whether or not the Corporation is then subject to such reporting requirement; provided, that, without limitation, such a change in control shall be deemed to have occurred if:

(i) any person (as such term is used in Sections 13(d) and 14(d) of the Exchange Act) (a “Person”) is or becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Corporation (not including in the amount of the securities beneficially owned by such person any such securities acquired directly from the Corporation or its affiliates) representing twenty percent (20%) or more of the combined voting power of the Corporation’s then outstanding voting securities; provided, however, that for purposes of this Plan the term “Person” shall not include (A) the Corporation or any of its subsidiaries, (B) a trustee or other fiduciary holding securities under an employee benefit plan of the Corporation or any of its subsidiaries, (C) an underwriter temporarily holding securities pursuant to an offering of such securities, or (D) a corporation owned, directly or indirectly, by the stockholders of the Corporation in substantially the same proportions as their ownership of stock of the Corporation; and provided, further, however, that for purposes of this paragraph (i), there shall be excluded any Person who becomes such a beneficial owner in connection with an Excluded Transaction (as defined in paragraph (iii) below); or

(ii) the following individuals cease for any reason to constitute a majority of the number of directors then serving: individuals who, on the date hereof, constitute the Board and any new director (other than a director whose initial assumption of office is in connection with an actual or threatened election contest including, but not limited to, a consent solicitation, relating to the election of directors of the Corporation) whose appointment or election by the Board or nomination for election by the Corporation’s stockholders was approved or recommended by a vote of at least two-thirds (2/3) of the directors then still in office who either were directors on the date hereof or whose appointment, election or nomination for election was previously so approved or recommended; or

(iii) there is consummated a merger or consolidation of the Corporation or any direct or indirect subsidiary thereof with any other corporation, other than a merger or consolidation (an “Excluded Transaction”) which would result in the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving corporation or any parent thereof) at least fifty (50%) of the combined voting power of the voting securities of the entity surviving the merger or consolidation (or the parent of such surviving entity) immediately after such merger or consolidation, or the stockholders of the Corporation approve a plan of complete liquidation of the Corporation, or there is consummated the sale or other disposition of all or substantially all of the Corporation’s assets.

Notwithstanding the foregoing or any provision of the Plan or the applicable award agreement to the contrary, with respect to any settlement of awards or other distributions under this Plan which would be a payment of deferred compensation within the meaning of Section 409A of the Code with respect to the Employee and which is a settlement or distribution made upon the Employee’s Separation from Service in connection with a Change in Control, the term “Change in Control” under this Plan shall have the same meaning as a change in ownership or change in effective control for purposes of Section 409A of the Code.

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Corporation: Marathon Petroleum Corporation and each related company or business which is part of the same controlled group under Code sections 414(b) or 414(c); provided that where specified by Marathon Petroleum Corporation in accordance with Code section 409A, in applying Code section 1563(a)(1) – (a)(3) for purposes of determining a controlled group of corporations under Code section 414(b) and in applying Treasury Regulation section 1.414(c)-2 for purposes of determining whether trades or businesses are under common control under Code section 414(c), the phrase “at least 50 percent” is used instead of “at least 80 percent.”

Disability or Disabled: The Employee’s incapacity due to physical or mental illness which in the opinion of a licensed physician renders the Employee incapable of performing his or her assigned duties with the Corporation, and shall be deemed to occur on the earlier of (i) the date there is no reasonable expectation the Participant will return to service with the Corporation or (ii) the date the Employee has been absent from the full-time performance of his or her duties with the Corporation for six (6) consecutive months or more.

Effective Date: October 31, 2012.

Employee: Senior executives of the Corporation who are grade 88 or higher.

Good Reason: Without the Employee’s express written consent, the occurrence within two (2) years after a Change in Control of the Corporation, or within two (2) years after and at the request of or as a result of actions by a third party who has taken steps reasonably calculated to effect a Change in Control or after the first day of but during a Potential Change in Control Period, of any one (1) or more of the following:

(i) the assignment to the Employee of duties inconsistent with his or her position immediately prior to the Applicable Event or a reduction or alteration in the nature of the Employee’s position, duties, status or responsibilities from those in effect immediately prior to the Applicable Event;

(ii) a reduction by the Corporation in the Employee’s annualized and monthly or semi-monthly rate of base salary (as increased to incorporate the Employee’s foreign service premium, if any) (“Base Salary”) as in effect immediately prior to the Applicable Event;

(iii) the Corporation’s requiring the Employee to be based at a location in excess of fifty miles from the location where the Employee was based immediately prior to the Applicable Event;

(iv) the failure by the Corporation (a) to continue, substantially as in effect immediately prior to the Applicable Event, all of the Corporation’s employee benefit, incentive compensation, bonus, stock option and stock award plans, programs, policies, practices or arrangements in which the Employee participates (or substantially equivalent successor plans, programs, policies, practices or arrangements) or (b) to continue the Employee’s participation therein on substantially the same basis, both in terms of the amount of benefits provided and the level of the Employee’s participation relative to other participants, as existed immediately prior to the Applicable Event;

(v) the failure of the Corporation to obtain an agreement from any successor to the Corporation to assume and agree to perform this Plan, as contemplated in Section 6 hereof; and

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(vi) any purported Separation from Service by the Corporation of the Employee’s employment that is not effected pursuant to, and satisfying the requirements of, a Notice of Termination, and for purposes of this Plan, no such purported Separation from Service shall be effective.

The Employee’s right to Separate from Service for Good Reason shall not be affected by his or her incapacity due to physical or mental illness. The Employee’s continued employment shall not constitute consent to, or a waiver of rights with respect to, any circumstance constituting Good Reason hereunder. The Employee’s determination of the existence of Good Reason shall be final and conclusive unless such determination is not made in good faith and is made without reasonable belief in the existence of Good Reason.

MPC: Marathon Petroleum Corporation.

Notice of Termination: A written notice which indicates the specific reason(s) relied upon by the Corporation for Separation from Service of an Employee and which sets forth in reasonable detail the facts and circumstances claimed to provide a basis for the Employee’s Separation from Service. Any Separation from Service by the Corporation for Cause or for Disability shall be communicated by Notice of Termination to the Employee, and or any Separation from Service by the Employee for Good Reason shall be communicated by Notice of Termination to the Corporation.

Plan: This plan, effective as of the Effective Date set forth above, and as amended from time to time.

Potential Change in Control of the Corporation and Potential Change in Control: A Potential Change in Control of the Corporation or Potential Change in Control shall be deemed to have occurred, if:

(i) the Corporation enters into an agreement, the consummation of which would result in the occurrence of a Change in Control of the Corporation;

(ii) any Person (including the Corporation) publicly announces an intention to take or to consider taking actions which if consummated would constitute a Change in Control of the Corporation;

(iii) any Person becomes the beneficial owner, directly or indirectly, of securities of the Corporation representing 15% or more of the combined voting power of the Corporation’s then outstanding securities (not including in the amount of the securities beneficially owned by such Person any such securities acquired directly from the Corporation or its affiliates); or

(iv) the Board adopts a resolution to the effect that, for purposes of this Plan, a Potential Change in Control of the Corporation has occurred.

Potential Change in Control Period: The period beginning on the date a Potential Change in Control occurs and ending on the earlier of (i) the date on which a Change in Control occurs or (ii) the date the Board makes a good faith determination that the risk of a Change in Control has terminated.

Qualified Termination: An Employee has a Qualified Termination if he or she Separates from Service within two (2) years after the date of a Change in Control unless such Separation from Service is (i) due to death or Disability, (ii) by the Corporation for Cause, (iii) by the Employee other than for Good Reason or (iv) on or after the date that the Employee attains age 65. If an Employee Separates from Service prior to a Change in Control and such Separation from Service is other than (w) due to death or Disability, (x) by the Corporation for Cause, (y) by the Employee other than for Good Reason or (z) on or

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after the date that the Employee attains age 65, the Employee will be deemed to have a Qualified Termination prior to a Change in Control so long as the Employee reasonably demonstrates that such Separation from Service (I) was at the request of or as a result of actions by a third party who has taken steps reasonably calculated to effect a Change in Control or (II) occurs during a Potential Change in Control Period.

Separation Date: The date that an Employee has a Separation from Service.

Separation from Service or Separate from Service: Separation from Service shall have the same meaning as set forth under Code section 409A with respect to the Corporation.

Severance Benefits: The benefits specified in Section 3(d) hereof that are due to an Employee who has a Qualified Termination.

Speedway: Speedway LLC and its subsidiaries, or, as applicable, any successor(s) to Speedway LLC and its subsidiaries.

3. Compensation Upon Separation from Service or During Disability

a. Disability

During any period following an Applicable Event during which an Employee fails to perform his or her full-time duties with the Corporation as a result of incapacity due to physical or mental illness, such Employee’s total compensation, including Base Salary, bonus and any benefits, will continue unaffected until either such Employee’s Separation Date or such Employee returns to the full-time performance of his or her duties. In the event the Employee returns to the full-time performance of his or her duties prior to a Separation from Service, such Employee shall continue to receive his or her full Base Salary and bonus plus all other amounts to which such Employee is entitled under any compensation or other employee benefit plan of the Corporation without interruption. If an Employee is determined to be Disabled, the Corporation shall promptly cause the Employee to have a Separation from Service due to Disability. In the event of an Employee’s Separation from Service due to Disability, such Employee shall not be entitled to Severance Benefits under this Plan and such Employee’s benefits shall be determined in accordance with the Corporation’s retirement, insurance and other applicable programs and plans then in effect.

b. Separation from Service for Cause or Voluntary Separation from Service for Other Than Good Reason

If an Employee has a Separation from Service by the Corporation for Cause or by the Employee other than for Good Reason, the Corporation shall pay such Employee his or her full Base Salary through the Separation Date at the rate in effect at the time Notice of Termination is given, plus all other amounts to which such Employee is entitled under any compensation or benefit plan of the Corporation at the time such payments are due, and the Corporation shall have no further obligations to such Employee under this Plan.

c. Death

If an Employee has a Separation from Service by reason of his or her death, such Employee’s benefits shall be determined in accordance with the Corporation’s retirement, survivor’s benefits, insurance and other applicable programs and plans then in effect, and such Employee shall not be entitled to Severance Benefits hereunder.

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d. Qualified Termination

If an Employee has a Qualified Termination, he or she shall be entitled to the following Severance Benefits:

(i) Accrued Compensation and Benefits. The Corporation shall provide to the Employee:

(A) the Employee’s Base Salary accrued through the Separation Date to the extent not theretofore provided;

(B) a lump sum cash amount equal to the value of the Employee’s unused vacation days accrued through the Separation Date; and

(C) the Employee’s normal post-termination compensation and benefits under the Corporation’s retirement, insurance and other compensation and benefit plans as in effect immediately prior to the Separation Date, or if more favorable to the Employee, immediately prior to the Applicable Event, which shall be paid at the time or times indicated pursuant to the terms of the plans or arrangements providing for such benefits.

(ii) Lump Sum Severance Payment. The Corporation shall provide to the Employee a severance payment in the form of a cash lump sum distribution equal to the Employee’s Current Annual Compensation (as defined below) multiplied times three (3); provided, however, that if the Employee attains age 65 within three (3) years of the Separation Date, the Employee’s benefit will be limited to a pro rata portion of such benefit based on a fraction equal to the number of full and partial months existing between the Separation Date and the Employee’s sixty-fifth (65^th) birthday divided by thirty-six (36) months. For purposes of this paragraph, the term “Current Annual Compensation” shall mean the sum of:

(A) the Employee’s Base Salary in effect immediately prior to the occurrence of the circumstances giving rise to such Separation from Service or, if higher, immediately prior to the Applicable Event; and

(B) an amount equal to the highest annual bonus awarded to the Employee, if any, under any annual bonus plan of the Corporation or its predecessor in the three (3) years immediately preceding the Separation Date or, if higher, in the three (3) years immediately preceding the Applicable Event.

(iii) Continuation of Welfare Benefits. Subject to the benefits offset described below, the Corporation will arrange to make available to the Employee life and health insurance benefits during the Welfare Continuation Period (as defined below) that are substantially similar to those which the Employee was receiving under a Corporation-sponsored welfare benefit plan immediately prior to the Separation Date or, if more favorable to the Employee, immediately prior to the Applicable Event. These benefits will be provided at a cost to the Employee that is no greater than the amount paid for such benefits by active employees who participate in such Corporation-sponsored welfare benefit plan or, if less, the amount paid for such benefits by the Employee immediately prior to the Applicable Event. The Welfare Continuation Period extends from the Separation Date for a period of thirty-six (36) months, or, if earlier, until the Employee attains age sixty-five (65).

The benefits otherwise receivable by the Employee pursuant to this paragraph (iii) shall be reduced to the extent comparable benefits are actually received by the Employee during the Welfare Continuation Period. For purposes of complying with the terms of this offset, the Employee is obligated to report to the Corporation the amount of any such benefits actually received.

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(iv) Retiree Medical and Life Benefits. The Corporation will arrange to make available to the Employee retiree life and health insurance benefits determined as if under the Corporation’s welfare benefit plans the Employee’s actual participation credit (or continuous service) and actual age as of the Separation Date were increased by the additional three (3) years of service and age provided in paragraph 3(d)(v)(A)(3) below. If eligible for such coverage, the Employee may elect to commence participation in retiree medical benefits coverage at any time following the expiration of the Welfare Continuation Period (or immediately after the Separation Date, if the Employee satisfies the eligibility requirements without taking into consideration the additional three (3) years of service and age).

Such retiree medical and life insurance coverage, if any, will be provided by the entity that is the Employee’s employer as of the Separation Date.

(v) Supplemental Retirement Benefit. In addition to the pension benefits to which the Employee is entitled under the Corporation’s defined benefit pension plans, the Corporation shall provide to the Employee, in the form of a cash lump sum distribution, a benefit (the “Supplemental Retirement Benefit”) equal to the difference between: (A) the lump sum value of the Employee’s Enhanced Pension Benefit (as defined in paragraph (A) below), and (B) the lump sum value of the Employee’s Actual Pension Benefit (as defined in paragraph (B) below). The methods and assumptions that existed under the applicable Corporation pension plan (or plans) immediately prior to the Applicable Event for purposes of determining a lump sum distribution shall be used for purposes of determining the lump sum values in (A) and (B). In determining the Enhanced Pension Benefit and the Actual Pension Benefit, amendments to the MPC Pension Plans, and the Speedway Pension Plans (as each is defined in paragraph 3(d)(v)(B) below) made subsequent to the Applicable Event and on or prior to the Separation Date, if any, shall be disregarded if they adversely affect in any manner the computation of retirement benefits thereunder.

(A) Enhanced Pension Benefit. The amount of the Employee’s Enhanced Pension Benefit shall be equal to the Actual Pension Benefit for which the Employee is eligible under the MPC Pension Plans, and the Speedway Pension Plans as of the Separation Date, as adjusted to incorporate the enhancements outlined in paragraphs (1) through (6) below. The enhancements outlined in this paragraph (A) shall be applied only to the Employee’s benefits under the MPC Pension Plans, or the Speedway Pension Plans in which the Employee was an active participant as of the Separation Date.

(1) Normal Retirement Benefit - Service. For purposes of determining the Employee’s monthly normal retirement benefit payable at normal retirement age, service used in the formula(s) shall be deemed to be equal to the sum of the Employee’s actual service for benefit accrual purposes plus three (3) years. For this purpose, the Employee’s actual service shall be determined as of the Separation Date.

(2) Normal Retirement Benefit - Final Average Pay. For purposes of determining the Employee’s monthly normal retirement benefit payable at normal retirement age, final average pay shall be calculated using the sum of:

I. the Employee’s Base Salary in effect immediately prior to the occurrence of the circumstances giving rise to such Separation from Service or, if higher, immediately prior to the Applicable Event; and

II. if bonus is considered covered compensation under the applicable pension plan, an amount equal to the highest annual bonus awarded to the Employee, if any, under

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any annual bonus plan of the Corporation or its predecessor with respect to the three (3) years immediately preceding the Separation Date or, if higher, the three (3) years immediately preceding the Applicable Event (but not less than the amount of bonus taken into account in the Employee’s Actual Pension Benefit).

Final average pay taken into account for this paragraph shall not be less than the amount of final average pay taken into account in the determination of the Employee’s Actual Pension Benefit.

(3) Early Commencement Factors—Enhanced Service and Age. For purposes of determining the early commencement factors that apply to the Employee’s monthly normal retirement benefit, the Employee’s service and age shall be deemed equal to the Employee’s actual service and age plus three (3) years of service and three (3) years of age, respectively. For this purpose, the Employee’s actual service and actual age shall be determined as of the Separation Date.

(4) Full Vesting. The Employee’s accrued benefits under the MPC Pension Plans and the Speedway Pension Plans shall be deemed to be fully vested or, to the extent not so vested, paid as an additional benefit under this Plan.

(5) Special Speedway Provisions. If the Employee is employed by Speedway on the Separation Date:

I. the additional service credit under paragraph (1) above shall be disregarded for purposes of calculating the accrued benefit under the prior traditional defined benefit plan formula under the Speedway Retirement Plan which is otherwise applicable in determining the Enhanced Pension Benefit, but shall be counted for early retirement eligibility and other purposes; and

II. in calculating the Enhanced Pension Benefit related to the pension equity formula under the Speedway Retirement Plan, the additional service credit under paragraph (1) above shall be disregarded and instead the Employee shall be deemed to have Speedway Retirement Plan benefit accruals for three (3) additional years following the Separation Date. The age and participation service points for each deemed year of accrual shall be calculated based on what the Employee’s actual age and service would have been at the end of each calendar year had the Employee remained employed with Speedway.

(6) Determination of Age—All other purposes. Except as specifically provided otherwise in this paragraph (A), the Employee’s age, as well as the age of the Employee’s spouse, survivor, and/or co-pensioner, used in the determination of the amount of benefits payable under the applicable pension plan shall be determined using the Employee’s age and their actual ages as of the Separation Date.

(B) Actual Pension Benefit. The amount of the Employee’s Actual Pension Benefit is determined as the sum of the monthly pension benefits payable to the Employee as of the Separation Date under the tax-qualified defined benefit pension plans, non-qualified defined benefit excess benefit plans, and non-qualified top-hat or supplemental defined benefit plans sponsored or maintained by the Corporation or Speedway (or any successor plans or similar plans) (the “MPC Pension Plans,” and the “Speedway Pension Plans,” as applicable).

8

(vi) Supplemental Savings Benefit. In addition to the benefits the Employee is entitled to under the Marathon Petroleum Thrift Plan and the related non-qualified supplemental savings plans (“Savings Plans”), the Corporation shall provide to the Employee, in the form of a cash lump sum distribution, a benefit equal to the excess, if any, of:

(A) the amount the Employee would have been entitled to under the Savings Plans determined as if the Employee was fully vested thereunder on the Separation Date, over

(B) the amount the Employee is entitled to under the Savings Plans on the Separation Date.

(vii) Timing. To the extent that payments under this paragraph (d) are not deferred compensation within the meaning of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), and except as otherwise specifically stated herein, the payments provided for in this paragraph (d) shall be made not later than thirty days following the Separation Date. Notwithstanding any provision of the Plan to the contrary, if the Employee is a “specified employee” as determined by the Corporation in accordance with its established policy, any payments of deferred compensation within the meaning of Section 409A of the Code payable to the Employee as a result of the Employee’s Separation from Service (other than as a result of death) which would otherwise be paid within six (6) months of his or her Separation from Service shall be payable on the date that is one (1) day after the earlier of (i) the date that is six (6) months after the Employee’s Separation Date or (ii) the date that otherwise complies with the requirements of Section 409A of the Code. Each payment described herein is hereby designated as a “separate payment” for purposes of Section 409A of the Code.

(e) The Corporation shall also pay to the Employee all legal fees and expenses incurred by the Employee, as such legal fees and expenses are incurred but no later than the end of the calendar year after such fees and expenses were incurred, as a result of Separation from Service (including all such fees and expenses, if any, incurred in contesting or disputing any such Separation from Service or in seeking to obtain or enforce any right or benefit provided by this Plan or in connection with any tax audit or proceeding to the extent attributable to the application of Section 4999 of the Code to any payment or benefit provided hereunder) or otherwise.

(f) Other than as provided in Section 3(d)(iii), the Employee shall not be required to mitigate the amount of any payment provided for in this Section 3 by seeking other employment or otherwise, nor shall the amount of any payment provided for in this Section 3 be reduced by any compensation earned by the Employee as the result of employment by another employer, including self-employment, after the Separation Date, or otherwise.

4. Incentive Awards.

a. General.

This Section 4 shall not delay the vesting of any outstanding options, stock appreciation rights, stock awards and restricted stock awards or cash awards granted to the Employee under any option or incentive plan of the Corporation past the date when such awards would, by their terms have become vested. However, this Section 4 provides for accelerated vesting of awards which, by their terms, would not become vested upon a Qualified Termination. In addition, to the extent required for compliance with the requirements of Code Section 409A, this Section 4 shall delay the settlement of such awards, as set forth in Section 4(e) below, if such awards would have been settled upon a Qualified Termination. Also, notwithstanding anything in this Plan or this Section 4 to the

9

contrary, the provisions of this Section 4 shall not amend or modify any award described herein which was granted prior to the Effective Date of this Plan. With respect to any awards described herein that are granted on and after the Effective Date of this Plan, the terms of this Section 4 regarding vesting and settlement of awards upon a Qualified Termination shall be considered an integral term of such awards but shall not prevent such awards from being distributed upon any earlier distribution event which is provided for under the applicable award agreement or plan.

b. Options, Stock Appreciation Rights, Stock Awards and Cash Awards.

Upon a Qualified Termination all outstanding options, stock appreciation rights, stock awards, and restricted stock awards or cash awards granted to the Employee under any option or incentive plan of the Corporation shall be immediately fully vested and immediately exercisable and shall remain so exercisable throughout their entire original terms, and all stock awards, restricted stock awards, and cash awards shall be immediately vested and, subject to Section 4(e) shall be settled upon vesting.

c. Restricted Stock Units.

Upon a Qualified Termination all outstanding restricted stock unit awards shall be immediately vested. To the extent that immediate settlement of vested outstanding restricted stock units would result in an adverse tax consequence to an Employee under Section 409A of the Code, then outstanding restricted stock units will (subject to Section 4(e)) be settled upon the earliest to occur of (i) the date on which a change in ownership or change in effective control for purposes of Section 409A of the Code occurs and the Employee has a Separation from Service in connection with such change of control, or (ii) the date on which the restricted stock units would have been settled absent a Change in Control.

d. Separation Date Following Potential Change in Control.

If the Employee has a Separation from Service prior to a Change in Control which also constitutes a Qualified Termination, and the Employee is entitled to benefits under Section 3(d), as of the Separation Date all outstanding options and stock appreciation rights shall be immediately fully vested and immediately exercisable and shall remain so exercisable throughout their entire original terms, and all stock awards, restricted stock awards, restricted stock unit awards and cash awards shall be immediately vested and, subject to Section 4(e), shall be settled upon vesting.

e. Settlement of Deferred Compensation Awards.

Notwithstanding any provision of the Plan or the applicable award agreement to the contrary, if the Employee is a “specified employee” as determined by the Corporation in accordance with its established policy, any settlement of awards described in this Section 4 which would be a payment of deferred compensation within the meaning of Section 409A of the Code with respect to the Employee as a result of the Employee’s Separation from Service (other than as a result of death) and which would otherwise be paid within six (6) months of the Employee’s Separation Date shall be payable on the date that is one (1) day after the earlier of (i) the date that is six (6) months after the Employee’s Separation Date or (ii) the date that otherwise complies with the requirements of Section 409A of the Code. In addition, notwithstanding any provision of the Plan or the applicable award agreement to the contrary, any settlement of awards described in this Section 4 which would be a payment of deferred compensation within the meaning of Section 409A of the Code with respect to the Employee and is a settlement as a result of the Employee’s Separation from Service in connection with a Change in Control, the term “Change in Control” under this Plan shall mean a

10

change in ownership or change in effective control for purposes of Section 409A of the Code. Each payment described herein is hereby designated as a “separate payment” for purposes of Section 409A of the Code.

5. Successors; Binding Plan.

a. Successors to the Corporation

The Corporation will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Corporation or of any division or subsidiary thereof employing the Employee to expressly assume and agree to perform this Plan in the same manner and to the same extent that the Corporation would be required to perform it if no such succession had taken place. Failure of the Corporation to obtain such assumption and agreement prior to the effectiveness of any such succession shall be a breach of this Plan and shall entitle the Employee to compensation from the Corporation in the same amount and on the same terms as the Employee would be entitled hereunder if the Employee had a Separation from Service for Good Reason following an Applicable Event, except that for purposes of implementing the foregoing, the date on which any such succession becomes effective shall be deemed the Separation Date.

b. Representatives or Heirs of Employee

This Plan shall inure to the benefit of and be enforceable by the Employee’s personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. If the Employee should die while any amount would still be payable to the Employee hereunder if the Employee had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Plan to the Employee’s devisee, legatee or other designee or, if there is no such designee, to the Employee’s estate.

6. Notice

For the purpose of this Plan, notices and all other communications provided for in the Plan shall be in writing and shall be deemed to have been duly given when delivered or mailed by United States registered mail, return receipt requested, postage prepaid, addressed to the respective addresses set forth on the first page of this Plan.

7. Miscellaneous

No provision of this Plan may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing and signed by the Employee and such officer as may be specifically designated by the Board. The validity, interpretation, construction and performance of this Plan shall be governed by the laws of the State of Delaware.

8. Validity

The invalidity or unenforceability of any provision of this Plan shall not affect the validity or enforceability of any other provision of this Plan, which shall remain in full force and effect.

9. Counterparts

This Plan may be executed in several counterparts, each of which shall be deemed to be an original but all of which together will constitute one (1) and the same instrument.

11

10. Claims and Arbitration

Any dispute or controversy arising under or in connection with this Plan shall be settled exclusively by arbitration in accordance with the rules of the American Arbitration Association then in effect. Judgment may be entered on the arbitrator’s award in any court having jurisdiction; provided, however, that the Employee shall be entitled to seek specific performance of his or her right to be paid until the Separation Date during the pendency of any dispute or controversy arising under or in connection with this Plan. Any such arbitration shall be held in Findlay, Ohio.

11. Plan Amendment and Termination

The Corporation may at any time amend or terminate this Plan, provided that for a period of two (2) years following a Change in Control, the Plan may not be amended in a manner adverse to an Employee with respect to that Change in Control. Any amendment or termination shall be set out in an instrument in writing and executed by an appropriate officer of the Corporation.

12. Entire Plan

Except as specifically modified, waived or discharged in an individual agreement between an Employee and the Corporation which meets the requirements of Section 8 of this Plan, this Plan supersedes any other agreement or understanding between the parties hereto with respect to the issues that are the subject matter of this Plan.

IN WITNESS WHEREOF, Marathon Petroleum Corporation has caused its name to be hereunto subscribed by its Senior Vice President, Human Resources and Administrative Services .

MARATHON PETROLEUM CORPORATION
	/s/ Rodney P. Nichols
By:	Rodney P. Nichols
Its:	Senior Vice President, Human Resources and Administrative Services

12

EX-10.32

Exhibit 10.32

MPLX LP

2012 INCENTIVE COMPENSATION PLAN

MPC NON-EMPLOYEE DIRECTOR PHANTOM UNIT AWARD POLICY

(Adopted effective December 3, 2012)

Pursuant to this Award Policy and the MPLX LP 2012 Incentive Compensation Plan (the “Plan”), MPLX GP LLC, a Delaware limited liability company (the “Company”), the general partner of MPLX LP, a Delaware limited partnership (the “Partnership”), hereby grants to each of the non-employee directors of Marathon Petroleum Corporation (“MPC”), the parent corporation of the Company, serving on the Board of Directors of MPC (each a “Participant”), on the first trading day of each calendar quarter (each a “Grant Date”), that number of Phantom Units determined by dividing ten percent of the total value of the equity component of such Participant’s quarterly MPC non-employee director compensation by the closing market price of a Common Unit of the Partnership as reported on the Consolidated Tape System on the Grant Date. The number of Phantom Units awarded is subject to proration in the event an MPC non-employee director commences service on the MPC Board of Directors other than at the commencement of a calendar quarter and adjustment as provided in the Plan, and the Phantom Units hereby granted are also subject to the following terms and conditions:

1. Relationship to the Plan. The grants of Phantom Units under this Award Policy are subject to all of the terms, conditions and provisions of the Plan and administrative interpretations, if any, that have been adopted by the “Committee,” as such term is defined in the Plan. Except as defined in this Award Policy, capitalized terms shall have the same meanings given to them under the Plan. To the extent any provision of this Award Policy conflicts with the express terms of the Plan, the terms of the Plan shall control and, if necessary, the applicable provisions of this Award Policy shall be hereby deemed amended so as to carry out the purpose and intent of the Plan.

2. Settlement of Phantom Units. The Phantom Units granted under this Award Policy shall be settled in full in the form of a Common Unit of the Partnership for each Phantom Unit subject to this Award Policy upon the earlier of the Participant’s departure from the MPC Board of Directors or the Participant’s death.

3. Dividends and Cash Distributions. During the period of time between the Grant Date and the date the Phantom Units are settled, for any dividends and/or cash distributions paid by the Partnership on outstanding Common Units of the Partnership, the Participant shall be credited with additional Phantom Units, including any fractional Phantom Units, based on the Fair Market Value of a Common Unit of the Partnership on the date such dividend and/or cash distribution is made. Any additional Phantom Units granted pursuant to this Section shall be subject to the same terms and conditions applicable to the Phantom Units to which these dividend and/or cash distributions relate, including, without limitation, the restrictions on transfer, forfeiture, settlement and distribution provisions contained in this Award Policy or the Plan.

4. Issuance of Common Units. During the period of time between the Grant Date and the date the Phantom Units settle, the Phantom Units will be evidenced by a credit to a bookkeeping account evidencing the unfunded and unsecured right of the Participant to receive shares of Common Units, subject to the terms and

1

conditions applicable to the Phantom Units. Upon the settlement date as described in Paragraph 2 above, the Participant’s shall be entitled to receive a number of Common Units of the Partnership equal to the total of the number of Phantom Units granted and any additional Phantom Units credited pursuant to Paragraph 3 above with any fractional Phantom Units remaining settled in cash. Such Common Units shall be issued and registered in the name of the Participant. Subject to the terms of the Plan, all amounts payable to the Participant in respect of the Phantom Units, including the issuance of Common Units of the Partnership pursuant to this Paragraph 4, shall be paid as of the first day of the calendar month following the expiration of 45 days following the settlement date or as soon as reasonably practicable following the settlement date for such Phantom Units, but, in no event, later than March 15^th of the year following the year in which the settlement date for the Phantom Units occurs. The Participant shall not have the right or be entitled to exercise any voting rights, receive cash distributions or dividends or have or be entitled to any rights as a partnership unit holder in respect of the Phantom Units until such time as the Phantom Units have been settled and corresponding Common Units of the Partnership have been issued.

5. Nonassignability. Upon the Participant’s death, the Phantom Units credited to the Participant under this Award shall be transferred to the Participant’s beneficiary as designated under the Marathon Petroleum Deferred Compensation Plan for Non-Employee Directors, or if no such beneficiary designation has been executed by Participant, to the Participant’s estate and upon such transfer settled in Common Units of the Partnership. Otherwise, the Participant may not sell, transfer, assign, pledge or otherwise encumber any portion of the Phantom Units, and any attempt to sell, transfer, assign, pledge, or encumber any portion of the Phantom Units shall have no effect.

6. Nature of the Grant. Under this Award Policy, the Participant is not an employee of the Company, the Partnership or MPC, and this Award of Phantom Units is granted in connection with service as a Non-Employee Director on the MPC Board to the benefit of the Company and the Partnership and should not be considered in any way as compensation for, or relating in any way to, past services for the Company, the Partnership or MPC, or any affiliates or predecessors of any of the foregoing as an employee.

7. Modification of Policy. Any modification of this Award Policy shall be binding only if evidenced by resolution of the Board of the Company, provided that no modification may, without the consent of the Participant, adversely affect the rights of the Participant.

2

EX-12.1

Exhibit 12.1

Marathon Petroleum Corporation

Computation of Ratio of Earnings to Fixed Charges

TOTAL ENTERPRISE BASIS – Unaudited

(In millions)

	For the Years Ended December 31,
	2012		2011		2010		2009		2008
Portion of rentals representing interest	$	46	$	41	$	45	$	41	$	43
Capitalized interest		101		112		83		78		60
Other interest and fixed charges		90		60		1		1		1
Total fixed charges (A)	$	237	$	213	$	129	$	120	$	104
Earnings-pretax income with applicable adjustments (B)	$	5,423	$	3,848	$	1,063	$	748	$	1,986
Ratio of (B) to (A)		22.9		18.1		8.2		6.2		19.1

EX-21.1

Exhibit 21.1

MARATHON PETROLEUM CORPORATION

LIST OF SUBSIDIARIES

as of December 31, 2012

	Name of Subsidiary	Jurisdiction of Organization/Incorporation
	Blanchard Holdings Company LLC		Delaware
	Blanchard Pipe Line Company LLC		Delaware
	Blanchard Refining Company LLC		Delaware
	Blanchard Terminal Company LLC		Delaware
	Bonded Oil Company		Delaware
	Buckeye Assurance Corporation		Vermont
	Catlettsburg Refining, LLC		Delaware
*	Centennial Pipeline LLC		Delaware
*	Explorer Pipeline Company		Delaware
*	Gravcap, Inc.		Delaware
*	Green Bay Terminal Corporation		Wisconsin
*	Guilford County Terminal Company, LLC		North Carolina
	Hardin Assurance Ltd.		Bermuda
	Hardin Street Holdings LLC		Delaware
*	Johnston County Terminal, LLC		Delaware
*	LOCAP LLC		Delaware
*	LOOP LLC		Delaware
	Mannheim Terminal and Warehousing Service Company		Illinois
	Marathon Canada Marketing, Ltd.		Delaware
	Marathon Carbon Management LLC		Delaware
	Marathon Domestic LLC		Delaware
	Marathon Petroleum Company Canada, Ltd.		Alberta
	Marathon Petroleum Company LP		Delaware
	Marathon Petroleum Logistics Services LLC		Delaware
	Marathon Petroleum Service Company		Delaware
	Marathon Petroleum Supply LLC		Delaware
	Marathon Petroleum Trading Canada LLC		Delaware
	Marathon Pipe Line Company		Nevada
	Marathon Pipe Line LLC		Delaware
	Marathon PrePaid Card LLC		Ohio
	Marathon Renewable Fuels Corp.		Delaware
	Marathon Renewable Fuels LLC		Delaware
	Marathon Renewable Supply LLC		Delaware
*	Mascoma Corporation		Delaware
	MPC Investment Fund, Inc.		Delaware
	MPC Investment LLC		Delaware
	MPC Trade Receivables Company LLC		Delaware
	MPL Investment LLC		Delaware
	MPL Louisiana Holdings LLC		Delaware
	MPLX GP LLC		Delaware
	MPLX Logistics Holdings LLC		Delaware
	MPLX LP		Delaware
	MPLX Operations LLC		Delaware
	MPLX Pipe Line Holdings LLC		Delaware
	MPLX Terminal and Storage LLC		Delaware
*	Muskegon Pipeline LLC		Delaware
	NEC Ethanol LLC		Delaware

	Niles Properties LLC	Delaware
*	Northern Tier Holdings LLC	Delaware
	Ohio River Pipe Line LLC	Delaware
*	Oil Insurance Limited	Bermuda
	Oil Spill Response Limited	England & Wales
*	Port Everglades Environmental Corp.	Florida
*	Resource Environmental, L.L.C.	Delaware
	Speedway LLC	Delaware
	Speedway Petroleum Corporation	Delaware
	Speedway Prepaid Card LLC	Ohio
	Speedway.com LLC	Delaware
	Starvin Marvin, Inc.	Delaware
*	The Andersons Clymers Ethanol LLC	Ohio
*	The Andersons Marathon Ethanol LLC	Delaware
*	WIP, LLC	Indiana
*	Wolverine Pipe Line Company	Delaware

* Indicates a company that is not wholly owned directly or indirectly by Marathon Petroleum Corporation

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Forms S-3 (Nos. 333-175289, 333-175287 and 333-175286) and S-8 (Nos. 333-181007, 333-175245 and 333-175244) of Marathon Petroleum Corporation of our report dated February 28, 2013 relating to the financial statements and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.

/s/PricewaterhouseCoopers LLP

Toledo, OH

February 28, 2013

EX-24.1

Exhibit 24.1

POWER OF ATTORNEY

KNOW ALL BY THESE PRESENTS, that each of the undersigned officers and directors of Marathon Petroleum Corporation, a Delaware corporation, hereby constitutes and appoints Gary R. Heminger, Donald C. Templin and Michael G. Braddock, and each of them, as his or her true and lawful attorney or attorneys-in-fact, with full power of substitution and revocation, for each of the undersigned and in the name, place, and stead of each of the undersigned, to sign on behalf of each of the undersigned an Annual Report on Form 10-K for the fiscal year ended December 31, 2012 pursuant to Section 13 of the Securities Exchange Act of 1934 and to sign any and all amendments to such Annual Report, and to file the same, with all exhibits thereto, and other documents in connection therewith including, without limitation, a Form 12b-25 with the Securities and Exchange Commission, granting to said attorney or attorneys-in-fact, and each of them, full power and authority to do so and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as the undersigned might or could do in person, hereby ratifying and confirming all that said attorney or attorneys-in-fact or any of them or their substitute or substitutes may lawfully do or cause to be done by virtue thereof.

This power of attorney may be executed in multiple counterparts, each of which shall be deemed an original with respect to the person executing it.

IN WITNESS WHEREOF, the undersigned have hereunto set their hands as of the 28th day of February, 2013.

/s/ Gary R Heminger Gary R. Heminger President, Chief Executive Officer and Director (principal executive officer)	/s/ Donald C. Templin Donald C. Templin Senior Vice President and Chief Financial Officer (principal financial officer)
/s/ Michael G. Braddock Michael G. Braddock Vice President and Controller (principal accounting officer)	/s/ Evan Bayh Evan Bayh Director
/s/ David A. Daberko David A. Daberko Director	/s/ William L. Davis William L. Davis Director
/s/ Donna A. James Donna A. James Director	/s/ Charles R. Lee Charles R. Lee Director
/s/ Seth E. Schofield Seth E. Schofield Director	John W. Snow Director
/s/ John P. Surma John P. Surma Director	/s/ Thomas J. Usher Thomas J. Usher Chairman of the Board and Director

EX-31.1

Exhibit 31.1

MARATHON PETROLEUM CORPORATION

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

I, Gary R. Heminger, certify that:

1. I have reviewed this report on Form 10-K of Marathon Petroleum 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.

Date: February 28, 2013	/s/ Gary R. Heminger
	Gary R. Heminger
	President and Chief Executive Officer

EX-31.2

Exhibit 31.2

MARATHON PETROLEUM CORPORATION

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

I, Donald C. Templin, certify that:

1. I have reviewed this report on Form 10-K of Marathon Petroleum 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.

Date: February 28, 2013	/s/ Donald C. Templin
	Donald C. Templin
	Senior 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 Petroleum Corporation (the “Company”) on Form 10-K for the period ending December 31, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Gary R. Heminger, 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, 2013

/s/ Gary R. Heminger

Gary R. Heminger

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 Petroleum Corporation (the “Company”) on Form 10-K for the period ending December 31, 2012 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Donald C. Templin, Senior 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, 2013

/s/ Donald C. Templin

Donald C. Templin

Senior Vice President and Chief Financial Officer

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2012

Sales To Related Parties

Sales to related parties were as follows:

(In millions)	2012		2011		2010
Equity method investees:
Centennial	$	1	$	35	$	54
Other equity method investees		7		7		7
Marathon Oil Companies		-		13		39
Total	$	8	$	55	$	100

Fees Received For Operating Pipelines For Related Parties

The fees received for operating pipelines for related parties included in other income on the consolidated statements of income were as follows:

(In millions)	2012		2011		2010
Centennial	$	1	$	-	$	-

Purchases From Related Parties

Purchases from related parties were as follows:

(In millions)	2012		2011		2010
Equity method investees:
Centennial	$	7	$	31	$	72
LOOP		44		66		35
TAME		124		153		109
TACE		73		46		34
Other equity method investees		32		30		56
Marathon Oil Companies		-		1,590		2,287
Total	$	280	$	1,916	$	2,593

Receivables From Related Parties

Receivables from related parties, which are included in receivables, less allowance for doubtful accounts on the consolidated balance sheets, were as follows:

	December 31,
(In millions)	2012		2011
Centennial	$	2	$	1
Other equity method investees		-		1
Total	$	2	$	2

Payables To Related Parties

Payables to related parties, which are included in accounts payable on the consolidated balance sheets, were as follows:

	December 31,
(In millions)		2012		2011
Equity method investees:
Centennial	$	-	$	7
LOOP		4		5
TAME		5		4
TACE		2		2
Other equity method investees		2		2
Total	$	13	$	20

Related Party Net Interest And Other Financial Income

Related party net interest and other financial income was as follows:

(In millions)	2012		2011		2010
Dividend income:
PFD Preferred Stock	$	-	$	35	$	24
Interest income		1		-		-
Interest expense:
PFD revolving credit agreement		-		3		12
Marathon Oil loan agreement		-		5		54
Interest capitalized		-		(8)		(66)
Net interest expense		-		-		-
Related party net interest and other financial income	$	1	$	35	$	24

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Supplemental Cash Flow Information (Reconciliation Of Additions To Property, Plant And Equipment To Total Capital Expenditures) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Supplemental Cash Flow Information [Line Items]
Additions to property, plant and equipment	$ 1,369	$ 1,185	$ 1,217
Acquisitions	180	74
Increase (decrease) in capital accruals	(117)	53	(51)
Total capital expenditures	$ 1,432	$ 1,312	$ 1,166

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Leases (Tables)

12 Months Ended

Dec. 31, 2012

Schedule Of Future Minimum Commitments

Future minimum commitments as of December 31, 2012, for capital lease obligations and for operating lease obligations having initial or remaining non-cancelable lease terms in excess of one year are as follows:

(In millions)	Capital Lease Obligations		Operating Lease Obligations
2013	$	44	$	151
2014		44		137
2015		45		117
2016		44		80
2017		43		49
Later years		326		78
Total minimum lease payments		546	$	612
Less imputed interest costs		(191)
Present value of net minimum lease payments	$	355

Schedule Of Operating Lease Rental Expense

Operating lease rental expense was:

(In millions)	2012		2011		2010
Minimum rental	$	139	$	123	$	135
Contingent rental		-		1		1
Rental expense	$	139	$	124	$	136

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2012

Assets And Liabilities Accounted For At Fair Value On A Recurring Basis

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2012 and 2011 by fair value hierarchy level.

	December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Commodity derivative instruments, assets	$	49	$	-	$	-	$	84	$	133
Other assets		2		-		-		-		2
Total assets at fair value	$	51	$	-	$	-	$	84	$	135
Commodity derivative instruments, liabilities	$	(88)	$	-	$	-	$	-	$	(88)

	December 31, 2011
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Commodity derivative instruments, assets	$	26	$	1	$	-	$	107	$	134
Interest rate derivative instruments, assets		-		19		-		-		19
Other assets		2		-		-		-		2
Total assets at fair value	$	28	$	20	$	-	$	107	$	155
Commodity derivative instruments, liabilities	$	(45)	$	(1)	$	-	$	-	$	(46)

Reconciliation Of Net Beginning And Ending Balances Recorded For Net Assets And Liabilities Classified As Level 3

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

(In millions)	2012		2011		2010
Beginning balance	$	-	$	2,402	$	865
Total realized and unrealized losses included in net income		(2)		-		(1)
Purchases of PFD Preferred Stock (a)		-		10,326		9,709
Redemptions of PFD Preferred Stock (a)		-		(12,730)		(8,019)
Settlements of derivative instruments		2		2		(2)
Distributions to Marathon Oil (b)		-		-		(150)
Ending balance	$	-	$	-	$	2,402

^(a)  For information on PFD Preferred Stock, see Note 5. The fair value of our PFD Preferred Stock investment was measured using an income approach since the securities were not publicly traded; therefore, they were classified as Level 3 in the fair value hierarchy.

^(b)  Due to the January 1, 2010 merger of two non-operating RM&T Business legal entities into Marathon Oil.

Assets Measured At Fair Value On A 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.

	Year Ended December 31,
	2012				2011				2010
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for sale	$	-	$	-	$	-	$	-	$	1	$	29
Other noncurrent assets		-		14		-		-		-		-

Financial Instruments At Fair Value, Excluding Derivative Financial Instruments

The following table summarizes financial instruments on the basis of their nature, characteristics and risk at December 31, 2012 and 2011, excluding the derivative financial instruments reported above.

	December 31,
	2012				2011
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial assets:
Investments	$	263	$	59	$	289	$	93
Other		33		31		31		30
Total financial assets	$	296	$	90	$	320	$	123
Financial liabilities:
Long-term debt (a)	$	3,559	$	3,006	$	3,203	$	3,008
Deferred credits and other liabilities		23		23		21		21
Total financial liabilities	$	3,582	$	3,029	$	3,224	$	3,029

^(a)  Excludes capital leases

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Defined Benefit Pension And Other Postretirement Plans (Fair Values Of Defined Benefit Pension Plan Assets) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	$ 1,478		$ 1,423
Cash And Cash Equivalents [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	107		205
Investment Trusts [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	111		96
Exchange-Traded Funds [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	166		14
Private Equity [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	56		55
Equity Funds [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	709	[1]	758	[1]
Equity Funds [Member] | Consumer Staples, Consumer Discretionary, Technology, Health And Energy Sectors [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Percentage of investments held	70.00%		70.00%
Equity Funds [Member] | Other Sectors [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Percentage of investments held	30.00%		30.00%
Fixed Income Funds [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	258	[2]	229	[3]
Fixed Income Funds [Member] | Other Sectors [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Percentage of investments held	10.00%		20.00%
Fixed Income Funds [Member] | Publicly Traded Investment Grade Government And Corporate Bonds [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Percentage of investments held	90.00%		80.00%
Real Estate [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	54	[4]	49	[5]
Real Estate [Member] | Office, Hotel. Residential And Land [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Percentage of investments held	70.00%		75.00%
Other [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	17		17
Level 1 [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	290		234
Level 1 [Member] | Cash And Cash Equivalents [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	107		205
Level 1 [Member] | Investment Trusts [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	17		15
Level 1 [Member] | Exchange-Traded Funds [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	166		14
Level 1 [Member] | Private Equity [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value
Level 1 [Member] | Equity Funds [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value		[1]		[1]
Level 1 [Member] | Fixed Income Funds [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value		[2]		[3]
Level 1 [Member] | Real Estate [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value		[4]		[5]
Level 1 [Member] | Other [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value
Level 2 [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	1,061		1,068
Level 2 [Member] | Cash And Cash Equivalents [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value
Level 2 [Member] | Investment Trusts [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	94		81
Level 2 [Member] | Exchange-Traded Funds [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value
Level 2 [Member] | Private Equity [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value
Level 2 [Member] | Equity Funds [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	709	[1]	758	[1]
Level 2 [Member] | Fixed Income Funds [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	258	[2]	229	[3]
Level 2 [Member] | Real Estate [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value		[4]		[5]
Level 2 [Member] | Other [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value
Level 3 [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	127		121		100
Level 3 [Member] | Cash And Cash Equivalents [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value
Level 3 [Member] | Investment Trusts [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value
Level 3 [Member] | Exchange-Traded Funds [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value
Level 3 [Member] | Private Equity [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	56		55		46
Level 3 [Member] | Equity Funds [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value		[1]		[1]
Level 3 [Member] | Fixed Income Funds [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value		[2]		[3]
Level 3 [Member] | Real Estate [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	54	[4]	49	[5]	37
Level 3 [Member] | Other [Member]
Allocation Of Plan Assets Fair Value Hierarchy [Line Items]
Plan Asset Investments, at fair value	$ 17		$ 17		$ 17

[1] Includes approximately 70 percent of investments held in U.S. and non-U.S. publicly traded common stocks in the consumer staples, consumer discretionary, technology, health and energy sectors and the remaining 30 percent of investments held amongst various other sectors.

[2] Includes approximately 90 percent of investments held in U.S. and non-U.S. publicly traded investment-grade government and corporate bonds which include treasuries, mortgage-backed securities and industrials, and the remaining 10 percent of investments held amongst various other sectors.

[3] Includes approximately 80 percent of investments held in U.S. and non-U.S. publicly traded investment-grade government and corporate bonds which include treasuries, mortgage-backed securities and industrials, and the remaining 20 percent of investments held amongst various other sectors.

[4] 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 land with the greatest percentage of investments made in the U.S. and Asia, which includes the emerging markets of China and India.

[5] Includes investments diversified by property type and location. The largest property sector holdings, which represent approximately 75 percent of investments held, are office, hotel, residential and land 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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Variable Interest Entity (Narrative) (Detail) (Variable Interest Entity [Member], Minnesota Assets Sale Settlement Gain [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Variable Interest Entities Not Consolidated [Line Items]
Preferred equity interest	$ 46
Maximum exposure to loss	54
Property Lease Guarantee [Member]
Variable Interest Entities Not Consolidated [Line Items]
Store lease guaranteed	$ 8

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Defined Benefit Pension And Other Postretirement Plans (Multi Employer Pension Plan) (Detail) (Multiemployer Plans, Pension [Member], USD $)	12 Months Ended
	Dec. 31, 2012 Employees		Dec. 31, 2011		Dec. 31, 2010
Multiemployer Plans, Pension [Member]
Multiemployer Plans [Line Items]
MPC Contributions	$ 4,000,000	[1]	$ 3,000,000	[1]	$ 3,000,000	[1]
Multiemployer pension plan, minimum contribution requirement per week per employee	$ 259
Number of employees participated in the plan	251

[1] This agreement has a minimum contribution requirement of $259 per week per employee for 2013. A total of 251 employees participated in the plan as of December 31, 2012.

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Selected Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2012

Schedule Of Quarterly Financial Information

	2012								2011
(In millions, except per share data)	1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.		1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.
Revenues	$	20,265	$	20,243	$	21,049	$	20,686	$	17,842	$	20,760	$	20,616	$	19,420
Income (loss) from operations		956		1,307		1,895		1,189		819		1,325		1,759		(158)
Net income (loss)		596		814		1,224		759		529		802		1,133		(75)
Net income (loss) attributable to MPC		596		814		1,224		755		529		802		1,133		(75)
Net income (loss) attributable to MPC per share:(a)
Basic	$	1.71	$	2.39	$	3.61	$	2.26	$	1.49	$	2.25	$	3.18	$	(0.21)
Diluted		1.70		2.38		3.59		2.24		1.48		2.24		3.16		(0.21)
Dividends paid per share		0.25		0.25		0.35		0.35		-		-		0.20		0.25

(a) For comparative purposes, and to provide a more meaningful calculation for weighted average shares, we assumed the shares distributed to Marathon Oil stockholders in conjunction with the Spinoff were outstanding as of the beginning of each period prior to the Spinoff.

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Segment Information (Reconciliation Of Total Revenues To Sales And Other Operating Revenues) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segment Reporting, Revenue Reconciling Item [Line Items]
Total revenues (as reported above)	$ 82,245	$ 78,638	$ 62,487
Plus: Corporate and other unallocated items	(2)
Less: Sales to related parties	8	55	100
Sales and other operating revenues (including consumer excise taxes)	$ 82,235	$ 78,583	$ 62,387

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Derivatives (Narrative) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2012
Notes Payable And Other Payables [Member] | 3.50% Senior Notes Due In March 2016 [Member]
Derivative [Line Items]
Debt instrument, interest rate (in percentage)	3.50%
Maturity period of senior notes	March 2016
Interest Rate Swap [Member]
Derivative [Line Items]
Notional amount of interest rate swap agreements	500,000,000
Hedge agreements	3.50 percent senior notes due in March 2016
Gain on the termination of the transactions	20,000,000
Hedge ineffectiveness of interest rate swaps	0

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2012

Summary Of Property, Plant And Equipment

(In millions)	Estimated   Useful  Lives		December 31,
			2012		2011
Refining & Marketing		4 - 25 years	$	15,089	$	14,221
Speedway		4 - 15 years		2,100		1,887
Pipeline Transportation		16 -42 years		1,747		1,593
Corporate and Other		4 - 40 years		473		372
Total				19,409		18,073
Less accumulated depreciation				6,766		5,845
Net property, plant and equipment			$	12,643	$	12,228

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2012

Commitments and Contingencies

25. Commitments and Contingencies

We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. Some of these matters are discussed below. For matters for which we have not recorded an accrued liability, we are unable to estimate a range of possible loss because the issues involved have not been fully developed through pleadings and discovery. However, the ultimate resolution of some of these contingencies could, individually or in the aggregate, be material.

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 and certain other locations including presently or formerly owned or operated retail marketing sites. Penalties may be imposed for noncompliance.

At December 31, 2012 and 2011, accrued liabilities for remediation totaled $123 million and $117 million, respectively. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties if any that may be imposed. Receivables for recoverable costs from certain states, under programs to assist companies in clean-up efforts related to underground storage tanks at presently or formerly owned or operated retail marketing sites, was $51 million at both December 31, 2012 and December 31, 2011.

We are involved in a number of environmental enforcement matters arising in the ordinary course of business. While the outcome and impact on us cannot be predicted with certainty, management believes the resolution of these environmental matters will not, individually or collectively, have a material adverse effect on our consolidated results of operations, financial position or cash flows.

Lawsuits – In May 2007, the Kentucky attorney general filed a lawsuit against us and Marathon Oil in state court in Franklin County, Kentucky for alleged violations of Kentucky’s emergency pricing and consumer protection laws following Hurricanes Katrina and Rita in 2005. The lawsuit alleges that we overcharged customers by $89 million during September and October 2005. The complaint seeks disgorgement of these sums, as well as penalties, under Kentucky’s emergency pricing and consumer protection laws. We are vigorously defending this litigation. We believe that this is the first lawsuit for damages and injunctive relief under the Kentucky emergency pricing laws to progress this far and it contains many novel issues. In May 2011, the Kentucky attorney general amended his complaint to include a request for immediate injunctive relief as well as unspecified damages and penalties related to our wholesale gasoline pricing in April and May 2011 under statewide price controls that were activated by the Kentucky governor on April 26, 2011 and which have since expired. The court denied the attorney general’s request for immediate injunctive relief, and the remainder of the 2011 claims likely will be resolved along with those dating from 2005. If the lawsuit is resolved unfavorably in its entirety, it could materially impact our consolidated results of operations, financial position or cash flows. However, management does not believe the ultimate resolution of this litigation will have a material adverse effect.

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

Guarantees – We have provided certain guarantees, direct and indirect, of the indebtedness of other companies. Under the terms of most of these guarantee arrangements, we would be required to perform should the guaranteed party fail to fulfill its obligations under the specified arrangements. In addition to these financial guarantees, we also have various performance guarantees related to specific agreements.

Guarantees related to indebtedness of equity method investees – We hold interests in an offshore oil port, LOOP, and a crude oil pipeline system, LOCAP LLC. Both LOOP and LOCAP LLC have secured various project financings with throughput and deficiency agreements. Under the agreements, we are required to advance funds if the investees are unable to service their debt. Any such advances are considered prepayments of future transportation charges. The duration of the agreements vary but tend to follow the terms of the underlying debt. Our maximum potential undiscounted payments under these agreements for the debt principal totaled $172 million as of December 31, 2012.

We hold an interest in a refined products pipeline through our investment in Centennial, and have guaranteed the payment of Centennial’s principal, interest and prepayment costs, if applicable, under a Master Shelf Agreement, which is scheduled to expire in 2024. The guarantee arose in order for Centennial to obtain adequate financing. Our maximum potential undiscounted payments under this agreement for debt principal totaled $47 million as of December 31, 2012.

We hold an interest in a ethanol production facility through our investment in TAME, and have guaranteed the repayment of TAME’s tax exempt bond financing through our participation as a lender in the credit agreement under which a letter of credit has been issued to secure repayment of the tax exempt bonds. The credit agreement expires in 2018. Our maximum potential undiscounted payments under this arrangement were $25 million at December 31, 2012.

Marathon Oil indemnifications – In conjunction with the Spinoff, we have entered into arrangements with Marathon Oil providing indemnities and guarantees with recorded values of $7 million as of December 31, 2012, which consist of unrecognized tax benefits related to MPC, its consolidated subsidiaries and the RM&T Business operations prior to the Spinoff which are not already reflected in the unrecognized tax benefits described in Note 13, and other contingent liabilities Marathon Oil may incur related to taxes. Furthermore, the separation and distribution agreement and other agreements with Marathon Oil to effect the Spinoff provide for cross-indemnities between Marathon Oil and us. In general, Marathon Oil is required to indemnify us for any liabilities relating to Marathon Oil’s historical oil and gas exploration and production operations, oil sands mining operations and integrated gas operations, and we are required to indemnify Marathon Oil for any liabilities relating to Marathon Oil’s historical refining, marketing and transportation operations. The terms of these indemnifications are indefinite and the amounts are not capped.

Other guarantees – We have entered into other guarantees with maximum potential undiscounted payments totaling $116 million as of December 31, 2012, which primarily consist of a commitment to contribute cash to an equity method investee for certain catastrophic events, up to $50 million per event, in lieu of procuring insurance coverage, an indemnity to the co-lenders associated with an equity method investee’s credit agreement, and leases of assets containing general lease indemnities and guaranteed residual values.

General guarantees associated with dispositions – 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.

Contractual commitments – At December 31, 2012 and 2011, our contractual commitments to acquire property, plant and equipment and advance funds to equity method investees totaled $1.4 billion and $347 million. The contractual commitments at December 31, 2012 include the February 2013 acquisition of a refinery and related logistics and marketing assets. See Note 26.

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Segment Information (Schedule Of Revenues By Product Line) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Segment Reporting Information [Line Items]
Total revenues	$ 82,243	$ 78,638	$ 62,487
Less: Sales to related parties	8	55	100
Sales and other operating revenues (including consumer excise taxes)	82,235	78,583	62,387
Refined Products [Member]
Segment Reporting Information [Line Items]
Total revenues	76,234	73,334	56,025
Merchandise [Member]
Segment Reporting Information [Line Items]
Total revenues	3,229	3,090	3,369
Crude Oil And Refinery Feedstocks [Member]
Segment Reporting Information [Line Items]
Total revenues	2,514	1,972	2,890
Transportation And Other [Member]
Segment Reporting Information [Line Items]
Total revenues	$ 266	$ 242	$ 203

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Defined Benefit Pension And Other Postretirement Plans (Summary Of Assumptions Used To Determine Benefit Obligations And Net Periodic Benefit Cost) (Detail)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Pension Benefits [Member]
Weighted-average assumptions used to determine benefit obligation:
Weighted-average assumptions used to determine benefit obligation, Discount rate	3.45%	4.30%	5.05%
Weighted-average assumptions used to determine benefit obligation, Rate of compensation increase	5.00%	5.00%	5.00%
Weighted average assumptions used to determine net periodic benefit cost:
Weighted average assumptions used to determine net periodic benefit cost, Discount rate	4.06%	4.98%	5.23%
Weighted average assumptions used to determine net periodic benefit cost, Expected long-term return on plan assets	7.50%	8.50%	8.50%
Weighted average assumptions used to determine net periodic benefit cost, Rate of compensation increase	5.00%	5.00%	4.50%
Other Benefits [Member]
Weighted-average assumptions used to determine benefit obligation:
Weighted-average assumptions used to determine benefit obligation, Discount rate	4.05%	4.65%	5.55%
Weighted-average assumptions used to determine benefit obligation, Rate of compensation increase	5.00%	5.00%	5.00%
Weighted average assumptions used to determine net periodic benefit cost:
Weighted average assumptions used to determine net periodic benefit cost, Discount rate	4.54%	5.55%	6.85%
Weighted average assumptions used to determine net periodic benefit cost, Expected long-term return on plan assets
Weighted average assumptions used to determine net periodic benefit cost, Rate of compensation increase	5.00%	5.00%	4.50%

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Stock-Based Compensation Plans (Summary Of Stock Option Award Activity) (Detail) (USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted, Weighted-Average Exercise Price (in USD per share)	$ 36.18	$ 42.02
Stock Options [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at December 31, 2011, Number of Shares		9,372,370	[1]
Granted, Number of Shares		766,543	[1]
Options exercised / Stock vested, Number of Shares		(3,843,544)	[1]
Forfeited, canceled or expired, Number of Shares		(123,175)	[1]
Outstanding at December 31, 2012		6,172,194	[1]
Vested and expected to vest at December 31, 2012, Number of Shares		6,137,435	[1]
Exercisable at December 31, 2012, Number of Shares		3,648,382	[1]
Outstanding at December 31, 2011, Weighted-Average Exercise Price (in USD per share)		$ 33.08
Granted, Weighted-Average Exercise Price (in USD per share)		$ 42.04
Exercised, Weighted-Average Exercise Price (in USD per share)		$ 29.71
Forfeited, canceled or expired, Weighted-Average Exercise Price (in USD per share)		$ 38.88
Outstanding at December 31, 2012, Weighted-Average Exercise Price (in USD per share)		$ 36.17
Vested and expected to vest at December 31, 2012, Weighted-Average Exercise Price (in USD per share)		$ 36.14
Exercisable at December 31, 2012, Weighted-Average Exercise Price (in USD per share)		$ 34.48
Vested and expected to vest at December 31, 2012, Weighted-Average Remaining Contractual Term (in years)		6 years 7 months 6 days
Exercisable at December 31, 2012, Weighted-Average Remaining Contractual Term (in years)		5 years 4 months 24 days
Vested and expected to vest at December 31, 2012,Aggregate Intrinsic Value		$ 165
Exercisable at December 31, 2012,Aggregate Intrinsic Value		$ 104

[1] Includes an immaterial number of stock appreciation rights.

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Commitments And Contingencies (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Loss Contingencies [Line Items]
Accrued liabilities for remediation	$ 123	$ 117
Receivables for recoverable costs	51	51
Contractual commitments to acquire property, plant and equipment and advance funds to equity method investees	1,400.0	347.0
Indemnification Agreement [Member] | Marathon Oil Companies [Member]
Loss Contingencies [Line Items]
Guarantee obligation current carrying value	7
Equity Method Investees [Member] | Other Guarantees [Member]
Loss Contingencies [Line Items]
Maximum potential undiscounted payments	116
Guarantee obligations maximum exposure per event	50
Guarantee of Indebtedness of Others [Member] | LOOP and LOCAP LLC [Member] | Financial Guarantee [Member]
Loss Contingencies [Line Items]
Maximum potential undiscounted payments	172
Master Shelf Agreement [Member] | Centennial [Member] | Financial Guarantee [Member]
Loss Contingencies [Line Items]
Maximum potential undiscounted payments	47
Credit agreement expiration date	Dec. 31, 2024
Standby Letters Of Credit [Member] | TAME [Member] | Financial Guarantee [Member]
Loss Contingencies [Line Items]
Maximum potential undiscounted payments	25
Credit agreement expiration date	Dec. 31, 2018
Kentucky Lawsuit [Member] | Pending Or Threatened Litigation [Member] | Emergency Pricing And Consumer Protection Laws [Member]
Loss Contingencies [Line Items]
Alleged amount overcharged from customers	$ 89
Loss contingency, inestimable loss	Management does not believe the ultimate resolution of this litigation will have a material adverse effect.

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Equity (Narrative) (Detail) (Common Stock [Member], USD $)	1 Months Ended	12 Months Ended	1 Months Ended	3 Months Ended		1 Months Ended	3 Months Ended	2 Months Ended	3 Months Ended	12 Months Ended
	Feb. 01, 2012 Share Repurchase Plan [Member] Maximum [Member]	Dec. 31, 2012 Share Repurchase Plan [Member] Maximum [Member]	Jan. 30, 2013 Share Repurchase Plan [Member] Maximum [Member] Subsequent Event [Member]	Dec. 31, 2012 ASR Program November 5, 2012 [Member]	Nov. 05, 2012 ASR Program November 5, 2012 [Member]	Feb. 05, 2013 ASR Program November 5, 2012 [Member] Subsequent Event [Member]	Feb. 05, 2013 ASR Program November 5, 2012 [Member] Subsequent Event [Member]	Jul. 25, 2012 ASR Program February 3, 2012 [Member]	Mar. 31, 2012 ASR Program February 3, 2012 [Member]	Dec. 31, 2012 ASR Program February 3, 2012 [Member]	Feb. 03, 2012 ASR Program February 3, 2012 [Member]
Stockholders Equity Note [Line Items]
Stock repurchase plan authorized amount	$ 2,000,000,000		$ 2,000,000,000
Share repurchase plan period (in years)	2 years
Stock repurchase plan remaining authorized amount		650,000,000	2,650,000,000
Repurchase shares of MPC common stock under ASR program					$ 500,000,000						$ 850,000,000
Shares received under ASR program				7,403,294		870,947	8,274,241	2,776,036	17,581,344	20,357,380
Average per share amount under ASR program (in USD per share)							$ 60.43			$ 41.75

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Inventories (Summary Of Inventories) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Inventories [Line Items]
Crude oil and refinery feedstocks	$ 1,383	$ 1,339
Refined products	1,761	1,725
Merchandise	74	65
Supplies and sundry items	231	191
Total (at cost)	$ 3,449	$ 3,320

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Description Of Business, Spinoff And Basis Of Presentation (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011 Selling, General and Administrative Expenses [Member]	Dec. 31, 2010 Selling, General and Administrative Expenses [Member]	Dec. 31, 2011 Cost Of Revenues [Member]	Dec. 31, 2010 Cost Of Revenues [Member]
Spinoff Description Of Business And Basis Of Presentation [Line Items]
Separation and distribution agreement date of Spin off transaction	May 25, 2011
Distribution of MPC common stock	Jun. 30, 2011
Stock spin off conversion ratio	0.50
Reclassification Adjustments		$ 47	$ 46	$ (47)	$ (46)

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Debt (Schedule Of Debt Payments) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Schedule Of Debt Payments [Line Items]
2013	$ 19
2014	21
2015	23
2016	773
2017	$ 25

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Subsequent Event (Detail) (Subsequent Event [Member], BP [Member], USD $) In Millions, unless otherwise specified	1 Months Ended	12 Months Ended
	Feb. 01, 2013 MW Refinery Terminal site Cogeneration_facility Pipeline BPCD	Dec. 31, 2012
Subsequent Event [Line Items]
Refinery capacity, barrel-per-calendar-day	451,000
Subsequent event, date		Feb. 01, 2013
Intrastate natural gas liquid pipelines (in number of pipelines)	3
Number of branded sites (in number of sites)	1,200
Electric cogeneration capacity, megawatts	1,040
Base purchase price	$ 598
Inventories at current price	900
Number of light product terminals (in number of terminals)	4
Number of refineries acquired (in number of refineries)	1
Number of cogeneration facilities acquired (in number of cogeneration facilities)	1
Contingent Earnout [Member]
Subsequent Event [Line Items]
Contingent earnout	$ 700
Term of payment of maximum earnout provision payable to the company, years	6 years

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Segment Information (Reconciliation Of Segment Income From Operations To Income Before Income Taxes) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income before income taxes	$ 5,238		$ 3,719		$ 1,023
Segment Income From Operations [Member] | Reportable Segment [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income before income taxes	5,624		4,061		1,276
Corporate and Other Unallocated Items [Member] | Items Not Allocated [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income before income taxes	(336)	[1],[2]	(316)	[1],[2]	(236)	[1],[2]
Minnesota Assets Sale Settlement Gain [Member] | Items Not Allocated [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income before income taxes	183	[3]
Pension Settlement Expenses [Member] | Items Not Allocated [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income before income taxes	(124)	[2],[4]
Asset Impairment [Member] | Items Not Allocated [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income before income taxes					(29)	[5]
Net Interest And Other Financial Income (Costs) [Member] | Items Not Allocated [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income before income taxes	$ (109)	[6]	$ (26)	[6]	$ 12	[6]

[1] Corporate and other unallocated items consists primarily of MPC's corporate administrative expenses, including allocations from the Marathon Oil Companies for periods prior to the Spinoff and costs related to certain non-operating assets.

[2] Corporate overhead costs and pension settlement expenses attributable to MPLX were included in the Pipeline Transportation segment subsequent to MPLX's October 31, 2012 initial public offering.

[3] See Note 7.

[4] See Note 22.

[5] See Note 18.

[6] Includes related party net interest and other financial income.

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Income Taxes (Components Of Net Deferred Tax Liabilities Classified In Consolidated Balance Sheets (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Schedule Of Balance Sheet Classification Of Net Deferred Income Tax Assets Liabilities [Line Items]
Accrued taxes	$ 446	$ 447
Deferred income taxes	2,050	1,310
Net deferred tax liabilities	$ 2,496	$ 1,757

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Other Items (Net Interest And Other Financial Income (Costs)) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Other Items Net Interest And Other Financial Income [Line Items]
Interest income	$ 5		$ 3		$ 2
Interest expense	(191)	[1]	(164)	[1]	(18)	[1]
Interest capitalized	101	[1]	104	[1]	17	[1]
Total interest	(85)		(57)		1
Net foreign currency gains (losses)			12		(6)
Bank service and other fees	(25)		(16)		(7)
Total other	(25)		(4)		(13)
Net interest and other financial income (costs)	$ (110)		$ (61)		$ (12)

[1] See Note 5 for information on related party interest expense and capitalized interest.

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Income Taxes (Summary Of Income Tax Returns Subject To Examination) (Detail)	12 Months Ended
	Dec. 31, 2012
Minimum [Member] | United States Federal [Member]
Income Taxes And Tax Related [Line Items]
Tax years	2010
Minimum [Member] | States [Member]
Income Taxes And Tax Related [Line Items]
Tax years	2004
Maximum [Member] | United States Federal [Member]
Income Taxes And Tax Related [Line Items]
Tax years	2011
Maximum [Member] | States [Member]
Income Taxes And Tax Related [Line Items]
Tax years	2011

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Segment Information (Reconciliation Of Segment Capital Expenditures And Investments To Total Capital Expenditures) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Reconciliation Of Segment Capital Expenditures And Investments To Total Capital Expenditures [Line Items]
Capital expenditures and investments	$ 1,460		$ 1,323		$ 1,173
Less: Investments in equity method investees	28		11		7
Plus: Items not allocated to segments:
Total capital expenditures	1,432	[1],[2]	1,312	[1],[2]	1,166	[1],[2]
Capitalized interest	101		114		103
Reportable Segment [Member]
Reconciliation Of Segment Capital Expenditures And Investments To Total Capital Expenditures [Line Items]
Capital expenditures and investments	1,256	[1],[3]	1,185	[1],[4]	1,069	[1]
Items Not Allocated [Member]
Plus: Items not allocated to segments:
Total capital expenditures	103		24		1
Capitalized interest	$ 101		$ 114		$ 103

[1] Capital expenditures include changes in capital accruals.

[2] See Note 21 for a reconciliation of total capital expenditures to additions to property, plant and equipment as reported in the consolidated statements of cash flows.

[3] Includes Speedway's acquisition of 97 convenience stores in 2012.

[4] Includes Speedway's acquisition of 23 convenience stores in 2011.

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Income Per Common Share (Narrative) (Detail)			12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Stock Based Compensation Award [Member]	Dec. 31, 2011 Stock Based Compensation Award [Member]	Dec. 31, 2010 Stock Based Compensation Award [Member]	Jun. 30, 2011 Marathon Oil Companies [Member]
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Common stock distributed	361,000,000	357,000,000				356,337,127
Excluded from diluted share calculation			2,000,000	4,000,000	4,000,000

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Goodwill

12 Months Ended

Dec. 31, 2012

Goodwill

17. Goodwill

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

The changes in the carrying amount of goodwill for 2012 and 2011 were as follows:

(In millions)	Refining &     Marketing		Speedway		Pipeline     Transportation		Total
2011
Beginning balance	$	554	$	120	$	163	$	837
Purchase price adjustment		(2)		-		(1)		(3)
Acquisition(a)		-		9		-		9
Disposition		(1)		-		-		(1)
Ending balance	$	551	$	129	$	162	$	842
2012
Beginning balance	$	551	$	129	$	162	$	842
Acquisitions(a)		-		88		-		88
Ending balance	$	551	$	217	$	162	$	930

^(a)  See Note 6 for information on the acquisitions.

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Debt (Tables)

12 Months Ended

Dec. 31, 2012

Outstanding Borrowings

Our outstanding borrowings at December 31, 2012 and 2011 consisted of the following:

	December 31,
(In millions)	2012		2011
Marathon Petroleum Corporation:
Revolving credit agreement due 2017	$	-	$	-
3.500% senior notes due March 1, 2016		750		750
5.125% senior notes due March 1, 2021		1,000		1,000
6.500% senior notes due March 1, 2041		1,250		1,250
Consolidated subsidiaries:
Capital lease obligations due 2013-2027		355		299
MPLX Operations LLC revolving credit agreement due 2017		-		-
Trade receivables securitization facility due 2014		-		-
Total		3,355		3,299
Unamortized discount		(10)		(11)
Fair value adjustments (a)		16		19
Amounts due within one year		(19)		(15)
Total long-term debt due after one year	$	3,342	$	3,292

^(a)  See Notes 18 and 19 for information on interest rate swaps.

Schedule Of Debt Payments

The following table shows five years of scheduled debt payments.

(In millions)
2013	$	19
2014		21
2015		23
2016		773
2017		25

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Other Items (Tables)

12 Months Ended

Dec. 31, 2012

Net Interest And Other Financial Income (Costs)

Net interest and other financial income (costs) was:

(In millions)	2012		2011		2010
Interest:
Interest income	$	5	$	3	$	2
Interest expense(a)		(191)		(164)		(18)
Interest capitalized(a)		101		104		17
Total interest		(85)		(57)		1
Other:
Net foreign currency gains (losses)		-		12		(6)
Bank service and other fees		(25)		(16)		(7)
Total other		(25)		(4)		(13)
Net interest and other financial income (costs)	$	(110)	$	(61)	$	(12)

^(a)  See Note 5 for information on related party interest expense and capitalized interest.

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Segment Information (Income From Operations Attributable To Operating Segments) (Detail) (USD $) In Millions, unless otherwise specified	1 Months Ended	3 Months Ended								12 Months Ended
	May 31, 2011 Store	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Segment Reporting Information [Line Items]
Customer		$ 20,686	$ 21,049	$ 20,243	$ 20,265	$ 19,420	$ 20,616	$ 20,760	$ 17,842
Related parties										8		55		100
Total revenues										82,245		78,638		62,487
Income from operations										5,347		3,745		1,011
Income (loss) from equity method investments										26		50		70
Capital expenditures and investments										1,460		1,323		1,173
Number of convenience stores acquired	23
Reportable Segment [Member]
Segment Reporting Information [Line Items]
Customer										82,237		78,583		62,387
Elimination of intersegment revenues										9,167	[1]	8,636	[1]	7,741	[1]
Related parties										8		55		100
Segment revenues										91,412		87,274		70,228
Total revenues										82,245		78,638		62,487
Income from operations										5,624	[2]	4,061		1,276
Income (loss) from equity method investments										26		50		70
Depreciation and amortization										972	[3]	873	[3]	912	[3]
Capital expenditures and investments										1,256	[4],[5]	1,185	[4],[6]	1,069	[4]
Number of convenience stores acquired										97		23
Reportable Segment [Member] | Elimination [Member]
Segment Reporting Information [Line Items]
Elimination of intersegment revenues										9,167		8,636		7,741
Reportable Segment [Member] | Refining & Marketing [Member]
Segment Reporting Information [Line Items]
Customer										67,921		65,028		49,844
Elimination of intersegment revenues										8,782	[1]	8,301	[1]	7,394	[1]
Related parties										7		52		95
Segment revenues										76,710		73,381		57,333
Total revenues										67,928		65,080		49,939
Income from operations										5,098	[2]	3,591		800
Income (loss) from equity method investments										(6)		11		9
Depreciation and amortization										804	[3]	718	[3]	739	[3]
Capital expenditures and investments										705	[4],[5]	900	[4],[6]	961	[4]
Reportable Segment [Member] | Refining & Marketing [Member] | Elimination [Member]
Segment Reporting Information [Line Items]
Elimination of intersegment revenues										8,782		8,301		7,394
Reportable Segment [Member] | Speedway [Member]
Segment Reporting Information [Line Items]
Customer										14,239		13,490		12,494
Elimination of intersegment revenues										4	[1]
Segment revenues										14,243		13,490		12,494
Total revenues										14,239		13,490		12,494
Income from operations										310	[2]	271		293
Depreciation and amortization										114	[3]	110	[3]	111	[3]
Capital expenditures and investments										340	[4],[5],[7]	164	[4],[6],[7]	84	[4],[7]
Number of convenience stores acquired										97		23
Reportable Segment [Member] | Speedway [Member] | Elimination [Member]
Segment Reporting Information [Line Items]
Elimination of intersegment revenues										4
Reportable Segment [Member] | Pipeline Transportation [Member]
Segment Reporting Information [Line Items]
Customer										77		65		49
Elimination of intersegment revenues										381	[1]	335	[1]	347	[1]
Related parties										1		3		5
Segment revenues										459		403		401
Total revenues										78		68		54
Income from operations										216	[2]	199	[2]	183	[2]
Income (loss) from equity method investments										32		39		61
Depreciation and amortization										54	[3]	45	[3]	62	[3]
Capital expenditures and investments										211	[4],[5]	121	[4],[6]	24	[4]
Reportable Segment [Member] | Pipeline Transportation [Member] | Elimination [Member]
Segment Reporting Information [Line Items]
Elimination of intersegment revenues										381		335		347
Corporate Overhead Costs and Pension Settlement Expenses [Member] | Pipeline Transportation [Member] | MPLX LP [Member]
Segment Reporting Information [Line Items]
Income from operations										$ 4

[1] Management believes intersegment transactions were conducted under terms comparable to those with unaffiliated parties.

[2] Included in the Pipeline Transportation segment are $4 million of corporate overhead costs and pension settlement expenses attributable to MPLX subsequent to MPLX's October 31, 2012 initial public offering, which were included in items not allocated to segments prior to MPLX's initial public offering. These expenses are not currently allocated to other segments.

[3] Differences between segment totals and MPC totals represent amounts related to unallocated items and are included in "Items not allocated to segments" in the reconciliation below.

[4] Capital expenditures include changes in capital accruals.

[5] Includes Speedway's acquisition of 97 convenience stores in 2012.

[6] Includes Speedway's acquisition of 23 convenience stores in 2011.

[7] Includes acquisitions of 97 convenience stores in 2012 and 23 convenience stores in 2011.

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Goodwill (Changes In Carrying Amount Of Goodwill) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011
Goodwill [Line Items]
Beginning balance	$ 842		$ 837
Purchase price adjustment			(3)
Acquisition	88	[1]	9	[1]
Disposition			(1)
Ending balance	930		842
Refining & Marketing [Member]
Goodwill [Line Items]
Beginning balance			554
Purchase price adjustment			(2)
Disposition			(1)
Ending balance	551		551
Speedway [Member]
Goodwill [Line Items]
Beginning balance	129		120
Acquisition	88	[1]	9	[1]
Ending balance	217		129
Pipeline Transportation [Member]
Goodwill [Line Items]
Beginning balance			163
Purchase price adjustment			(1)
Ending balance	$ 162		$ 162

[1] See Note 6 for information on the acquisitions.

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Summary Of Principal Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2012

Principles Applied In Consolidation

Principles applied in consolidation – These consolidated financial statements include the accounts of our majority-owned, controlled subsidiaries.    We consolidate MPLX, in which we own a 73.6 percent controlling financial interest, and we record a noncontrolling interest for the 26.4 percent interest owned by the public.

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 shareholders have substantive participating rights in the investee.    Income from equity method investments represents our proportionate share of net income generated by the equity method investees.

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 values 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.

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.

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.    Costs associated with revenues are recorded in cost of revenues.    Shipping and other transportation costs billed to customers are presented on a gross basis in revenues and cost of revenues.

Rebates from vendors are recognized as a reduction of cost of revenues when the initiating transaction occurs.    Incentives that are derived from contractual provisions are accrued based on past experience and recognized in cost of revenues.

Crude Oil And Refined Product Exchanges And Matching Buy/Sell Transactions

Crude oil and refined product exchanges and matching buy/sell transactions – We enter into exchange contracts and matching buy/sell arrangements whereby we agree to deliver a particular quantity and quality of crude oil or refined products at a specified location and date to a particular counterparty and to receive from the same counterparty the same commodity at a specified location on the same or another specified date.    The exchange receipts and deliveries are nonmonetary transactions, with the exception of associated grade or location differentials that are settled in cash.    The matching buy/sell purchase and sale transactions are settled in cash.    Both exchange and matching buy/sell transactions are accounted for as exchanges of inventory and no revenues are recorded.    The exchange transactions are recognized at the carrying amount of the inventory transferred.

Consumer Excise Taxes

Consumer excise taxes – We are required by various governmental authorities, including countries, states and municipalities, to collect and remit taxes on certain consumer products.    Such taxes are presented on a gross basis in revenues and costs and expenses in the consolidated statements of income.

Cash And Cash Equivalents

Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit, reverse repurchase agreements and investments in highly liquid debt instruments with maturities generally of three months or less.

Accounts Receivable And Allowance For Doubtful Accounts

Accounts receivable and allowance for doubtful accounts – Our receivables primarily consist of customer accounts receivable, including proprietary credit card receivables.    The allowance for doubtful accounts is the best estimate of the amount of probable credit losses in customer accounts receivable, primarily associated with our proprietary credit card receivables.    We determine the allowance based on historical write-off experience and the volume of proprietary credit card sales.    We review the allowance quarterly and past-due balances over 180 days are reviewed individually for collectability.    All other customer receivables are recorded at the invoiced amounts and generally do not bear interest.    Account balances for these customer receivables are generally charged directly to bad debt expense when it becomes probable the receivable will not be collected.

Approximately 42 percent and 47 percent of our accounts receivable balances at December 31, 2012 and 2011, respectively, are related to sales of crude oil or refinery feedstocks to customers with whom we have master netting agreements.    We have master netting agreements with more than 80 companies engaged in the crude oil or refinery feedstock trading and supply business or the petroleum refining industry.    A master netting agreement generally provides for a once per month net cash settlement of the accounts receivable from and the accounts payable to a particular counterparty.

Inventories

Inventories – Inventories are carried at the lower of cost or market value.    Cost of inventories is determined primarily under the last-in, first-out (“LIFO”) method.

Derivative Instruments

Derivative instruments – We use derivatives to economically hedge a portion of our exposure to commodity price risk and interest rate risk.    We also have limited authority to use selective derivative instruments that assume market risk.    All derivative instruments are recorded at fair value.    Commodity derivatives are reflected on the consolidated balance sheets on a net basis by futures commission merchant, as they are governed by master netting agreements.    Cash flows related to derivatives used to hedge commodity price risk and interest rate risk are classified in operating activities with the underlying transactions.

Fair value accounting hedges – We used interest rate swaps to hedge our exposure to interest rate risk associated with fixed interest rate debt in our portfolio.    Changes in the fair values of both the hedged item and the related derivative were recognized immediately in net income with an offsetting effect included in the basis of the hedged item.    The net effect was to report in net income the extent to which the accounting hedge was not effective in achieving offsetting changes in fair value.    We terminated our interest rate swap agreements during 2012.    There was a gain on the termination of the agreements, which has been accounted for as an adjustment to our long-term debt balance.    The gain is being amortized over the remaining life of the associated debt, which reduces our interest expense.

Derivatives not designated as accounting hedges –Derivatives that are not designated as accounting hedges may include commodity derivatives used to hedge price risk on (1) inventories, (2) fixed price sales of refined products, (3) the acquisition of foreign-sourced crude oil and (4) the acquisition of ethanol for blending with refined products.    Changes in the fair value of derivatives not designated as accounting hedges are recognized immediately in net income.

Contingent credit features – Our derivative instruments contain no significant contingent credit features.

Concentrations of credit risk – All of our financial instruments, including derivatives, involve elements of credit and market risk.    The most significant portion of our credit risk relates to 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 an assessment of their financial strength and on credit ratings, if available.    Additionally, we limit the level of exposure with any single counterparty.

Property, Plant And Equipment

Property, plant and equipment – Property, plant and equipment are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which range from four to 42 years.    Such assets are reviewed for impairment 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.

When items of property, plant and equipment 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.

Interest expense is capitalized for qualifying assets under construction.    Capitalized interest costs are included in property, plant and equipment and are depreciated over the useful life of the related asset.

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.    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, the implied fair value of goodwill is calculated.    The excess, if any, of the book value over the implied fair value of goodwill is charged to net income.

Major Maintenance Activities

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

Environmental Costs

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

Asset Retirement Obligations

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.    Conditional asset retirement obligations for removal and disposal of fire-retardant material from certain refining facilities have been recognized.    The fair values recorded for such obligations are based on the most probable current cost projections.    The recorded asset retirement obligations are not material to the consolidated financial statements.

Asset retirement obligations have not been recognized for some assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate.    Such obligations will be recognized in the period when sufficient information becomes available to estimate a range of potential settlement dates.    The asset retirement obligations principally include the removal of underground storage tanks at our owned and some of our leased convenience stores at or near the time of closure and hazardous material disposal and removal or dismantlement requirements associated with the closure of certain refining, terminal and pipeline assets.

Our practice is to keep our assets in good operating condition through routine repair and maintenance of component parts in the ordinary course of business and by continuing to make improvements based on technological advances.    As a result, we believe that these assets have no expected settlement date for purposes of estimating asset retirement obligations since the dates or ranges of dates upon which we would retire these assets cannot be reasonably estimated at this time.

Income Taxes

Income taxes – For periods prior to the Spinoff, our taxable income was included in the consolidated U.S. federal income tax returns of Marathon Oil and in a number of consolidated state income tax returns.    In the accompanying consolidated financial statements, for periods prior to the Spinoff our provision for income taxes was computed as if we were a stand-alone tax-paying entity.

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.    Deferred tax assets are recorded when it is more likely than not that they will be realized.    The realization of deferred tax assets is assessed periodically based on several factors, primarily our expectation to generate sufficient future taxable income.

Stock-Based Compensation Arrangements

Stock-based compensation arrangements – The fair value of stock options and stock-settled stock appreciation rights (collectively, “stock option awards”) granted to our employees is estimated on the date of grant using the Black-Scholes option pricing model.    The model employs various assumptions, based on management’s estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the vesting period 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.    The average expected life is based on our historical employee exercise behavior.    The assumption for expected volatility of our stock price reflects a weighting of 25 percent of our common stock volatility and 75 percent of the historical volatility for a selected group of peer companies.

The fair value of restricted stock awards granted to our employees is determined based on the fair market value of our common stock on the date of grant.

Our stock-based compensation expense is recognized based on management’s estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature.    If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods.    Unearned stock-based compensation is charged to equity when restricted stock awards are granted.    Compensation expense is recognized over the vesting period and is adjusted if conditions of the restricted stock award are not met.    For periods prior to the Spinoff, we recorded Marathon Oil stock-based compensation expense as non-cash capital contributions.

Recently Adopted

Recently Adopted

In September 2011, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update giving an entity the option to use a qualitative assessment to determine whether or not the entity is required to perform the two step goodwill impairment test.    If, through a qualitative assessment, an entity determines that it is more likely than not that the fair value of a reporting unit is less than the carrying amount, the entity is required to perform the two step goodwill impairment test.    The amendments in the update were effective for annual and interim goodwill testing performed in fiscal years beginning after December 15, 2011.    The adoption of this accounting standards update in the first quarter of 2012 did not have an impact on our consolidated results of operations, financial position or cash flows.    We perform the annual goodwill impairment testing for each of our reporting units in the fourth quarter.

In June 2011, the FASB amended the reporting standards for comprehensive income to eliminate the option to present the components of other comprehensive income as part of the statement of changes in equity and to require reclassification adjustments from accumulated other comprehensive income to be measured and presented by income statement line item in net income and also in other comprehensive income.    All non-owner changes in 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 other comprehensive income and the total of comprehensive income.    This accounting standards update does not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income.    In December 2011, the FASB issued an accounting standards update to defer the presentation requirements of the reclassification adjustments from accumulated other comprehensive income.    This accounting standards update, as modified, was adopted using the two statement approach in the fourth quarter of 2011 and was applied retrospectively for all prior periods presented.    The adoption of this accounting standards update, as modified, did not have an impact on our consolidated results of operations, financial position or cash flows.    In February 2013, the FASB issued an accounting standards update regarding the presentation requirements of the reclassification adjustments from accumulated other comprehensive income.    See the Not Yet Adopted section for more information.

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. generally accepted accounting principles (“US GAAP”) and International Financial Reporting Standards (“IFRS”).    The amendments change the wording used to describe certain of the US 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.    The amendments were to be applied prospectively and were effective in interim and annual periods beginning with the first quarter of 2012 with early application not permitted.    This accounting standards update was adopted in the first quarter of 2012 and was applied prospectively.    The adoption of these amendments did not have a significant impact on our consolidated results of operations, financial position or cash flows.    The new required disclosures are included in Note 18.

Not Yet Adopted

Not Yet Adopted

In February 2013, the FASB issued an accounting standards update that requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component.    If the amount reclassified is required under US GAAP to be reclassified to net income in its entirety in the same reporting period, an entity is required to present, either on the face of the financial statements or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income.    For other amounts not required to be reclassed in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional detail about those amounts.    The accounting standards update is effective prospectively for annual periods beginning after December 15, 2012, and interim periods within those annual periods.    Adoption of this accounting standards update in the first quarter of 2013 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

In July 2012, the FASB issued an accounting standards update that gives an entity the option to first assess qualitatively whether it is more likely than not that an indefinite-lived intangible asset is impaired.    If, through the qualitative assessment, an entity determines that it is more likely than not that the intangible asset is impaired, the quantitative impairment test must then be performed.    The accounting standards update is effective for annual and interim impairment tests performed in fiscal years beginning after September 15, 2012.    Early adoption is permitted.    Adoption of this accounting standards update in the first quarter of 2013 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

In December 2011, the FASB issued an accounting standards update which was amended in January 2013 that requires disclosure of additional information related to recognized derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are offset or are not offset but are subject to an enforceable netting agreement.    The purpose of the requirement is to help users evaluate the effect or potential effect of offsetting and related netting arrangements on an entity’s financial position.    The update is to be applied retrospectively and is effective for annual periods that begin on or after January 1, 2013 and interim periods within those annual periods.    Adoption of this update is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

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Defined Benefit Pension and Other Postretirement Plans (Tables)

12 Months Ended

Dec. 31, 2012

Summary Of Defined Benefit Plans With Accumulated Benefit Obligations In Excess Of Plan Assets

The following summarizes our defined benefit pension plans that have accumulated benefit obligations in excess of plan assets.

	December 31,
(In millions)	2012		2011
Projected benefit obligations	$	2,192	$	2,685
Accumulated benefit obligations		2,035		1,948
Fair value of plan assets		1,478		1,423

Summary Of Projected Benefit Obligations And Funded Status For Defined Benefit Pension And Other Postretirement Plans

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

	Pension Benefits				Other Benefits
(In millions)	2012		2011		2012		2011
Change in benefit obligations:
Benefit obligations at January 1	$	2,685	$	2,266	$	551	$	483
Service cost		66		65		20		19
Interest cost		94		110		24		27
Actuarial loss		117		384		53		39
Benefits paid		(233)		(178)		(17)		(17)
Liability gain due to curtailment		(17)		(4)		-		-
Other(a)		(520)		42		(40)		-
Benefit obligations at December 31		2,192		2,685		591		551
Change in plan assets:
Fair value of plan assets at January 1		1,423		1,233		-		-
Actual return on plan assets		157		50		-		-
Employer contributions		131		282		-		-
Other(a)		-		36		-		-
Benefits paid from plan assets		(233)		(178)		-		-
Fair value of plan assets at December 31		1,478		1,423		-		-
Funded status of plans at December 31	$	(714)	$	(1,262)	$	(591)	$	(551)
Amounts recognized in the consolidated balance sheets:
Current liabilities	$	(18)	$	(12)	$	(21)	$	(18)
Noncurrent liabilities		(696)		(1,250)		(570)		(533)
Accrued benefit cost	$	(714)	$	(1,262)	$	(591)	$	(551)
Pretax amounts recognized in accumulated other comprehensive loss: (b)
Net loss	$	1,147	$	1,319	$	93	$	42
Prior service cost (credit)		(460)		42		(38)		-

^(a)  Includes adjustments related to plan amendments in 2012. Includes adjustments related to the Spinoff in 2011.

^(b)  Amounts exclude those related to LOOP, an equity method investee with defined benefit pension and postretirement plans for which net losses of $16 million and $2 million were recorded in accumulated other comprehensive loss in 2012, reflecting our 51 percent share.

Components Of Net Periodic Benefit Cost And Other Comprehensive Loss

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

	Pension Benefits						Other Benefits
(In millions)	2012		2011		2010		2012		2011		2010
Components of net periodic benefit cost:
Service cost	$	66	$	65	$	62	$	20	$	19	$	14
Interest cost		94		110		105		24		27		24
Expected return on plan assets		(104)		(97)		(95)		-		-		-
Amortization – prior service cost (credit)		(18)		6		7		(2)		-		1
– actuarial loss (gain)		93		71		51		2		-		(2)
– net settlement/curtailment loss(a)		125		8		13		-		-		-
Net periodic benefit cost(b)	$	256	$	163	$	143	$	44	$	46	$	37
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial loss	$	46	$	427	$	129	$	53	$	39	$	61
Prior service credit(c)		(520)		-		-		(40)		-		-
Amortization of actuarial (loss) gain		(218)		(79)		(64)		(2)		-		2
Amortization of prior service cost (credit)		18		(6)		(7)		2		-		(1)
Other(d)		-		6		-		-		-		-
Total recognized in other comprehensive loss	$	(674)	$	348	$	58	$	13	$	39	$	62
Total recognized in net periodic benefit cost and other comprehensive loss	$	(418)	$	511	$	201	$	57	$	85	$	99

^(a)  A curtailment gain was recorded in 2011 on the Speedway pension plan at the end of the transition services period related to the sale of most of our Minnesota Assets in 2010. See Note 7.

^(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 adjustments due to changes made to the defined pension plans and the post-65 medical plan coverage effective January 1, 2013.

^(d)  Includes adjustments related to the Spinoff.

Summary Of Assumptions Used To Determine Benefit Obligations And Net Periodic Benefit Cost

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 2012, 2011 and 2010.

	Pension Benefits						Other Benefits
	2012		2011		2010		2012		2011		2010
Weighted-average assumptions used to determine benefit obligation:
Discount rate		3.45%		4.30%		5.05%		4.05%		4.65%		5.55%
Rate of compensation increase		5.00%		5.00%		5.00%		5.00%		5.00%		5.00%
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate		4.06%		4.98%		5.23%		4.54%		5.55%		6.85%
Expected long-term return on plan assets		7.50%		8.50%		8.50%		-		-		-
Rate of compensation increase		5.00%		5.00%		4.50%		5.00%		5.00%		4.50%

Summary Assumed Health Care Cost Trend Rates

The following summarizes the assumed health care cost trend rates.

	December 31,
	2012		2011		2010
Health care cost trend rate assumed for the following year:
Medical:
Pre-65		8.00%		7.50%		7.50%
Post-65(a)		N/A		7.00%		7.00%
Prescription drugs		7.00%		7.50%		7.50%
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(a)		N/A		5.00%		5.00%
Prescription drugs		5.00%		5.00%		5.00%
Year that the rate reaches the ultimate trend rate:
Medical:
Pre-65		2020		2018		2018
Post-65(a)		N/A		2017		2017
Prescription drugs		2018		2018		2018

^(a)  Effective 2013, as a result of changes in the post-65 medical plan coverage of the Marathon Petroleum Health Plan and the Marathon Petroleum Retiree Health Plan, increases are the lower of the trend rate or 4 Percent.

Effects Of One Percentage Point Change In Assumed Health Care Cost Trend Rates

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:

	1-Percentage-		1-Percentage-
(In millions)	Point Increase		Point Decrease
Effect on total of service and interest cost components	$	6	$	5
Effect on other postretirement benefit obligations		32		28

Fair Values Of Defined Benefit Pension Plan 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, 2012 and 2011.

	December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	107	$	-	$	-	$	107
Equity securities:
Investment trusts		17		94		-		111
Exchange-traded funds		166		-		-		166
Private equity		-		-		56		56
Investment funds:
Pooled funds - equity(a)		-		709		-		709
Pooled funds - fixed income(b)		-		258		-		258
Real estate(c)		-		-		54		54
Other		-		-		17		17
Total investments, at fair value	$	290	$	1,061	$	127	$	1,478
	December 31, 2011
(In millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	205	$	-	$	-	$	205
Equity securities:
Investment trusts		15		81		-		96
Exchange-traded funds		14		-		-		14
Private equity		-		-		55		55
Investment funds:
Pooled funds - equity(a)		-		758		-		758
Pooled funds - fixed income(d)		-		229		-		229
Real estate(e)		-		-		49		49
Other		-		-		17		17
Total investments, at fair value	$	234	$	1,068	$	121	$	1,423

^(a)  Includes approximately 70 percent of investments held in U.S. and non-U.S. publicly traded common stocks in the consumer staples, consumer discretionary, technology, health and energy sectors and the remaining 30 percent of investments held amongst various other sectors.

^(b)  Includes approximately 90 percent of investments held in U.S. and non-U.S. publicly traded investment-grade government and corporate bonds which include treasuries, mortgage-backed securities and industrials, and the remaining 10 percent of investments held amongst various other sectors.

^(c)  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 land with the greatest percentage of investments made in the U.S. and Asia, which includes the emerging markets of China and India.

^(d)  Includes approximately 80 percent of investments held in U.S. and non-U.S. publicly traded investment-grade government and corporate bonds which include treasuries, mortgage-backed securities and industrials, and the remaining 20 percent of investments held amongst various other sectors.

^(e)  Includes investments diversified by property type and location. The largest property sector holdings, which represent approximately 75 percent of investments held, are office, hotel, residential and land with the greatest percentage of investments made in the U.S. and Asia, which includes the emerging markets of China and India.

Reconciliation Of Beginning And Ending Balances Of Plan Assets Classified As Level 3

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

	2012
(In millions)	Private Equity		Real Estate		Other		Total
Beginning balance	$	55	$	49	$	17	$	121
Actual return on plan assets		2		-		-		2
Purchases		12		10		-		22
Sales		(13)		(5)		-		(18)
Ending balance	$	56	$	54	$	17	$	127
	2011
(In millions)	Private Equity		Real Estate		Other		Total
Beginning balance	$	46	$	37	$	17	$	100
Actual return on plan assets		7		5		-		12
Purchases		10		12		-		22
Sales		(9)		(6)		-		(15)
Other		1		1		-		2
Ending balance	$	55	$	49	$	17	$	121

Estimated Future Benefit Payment

Estimated future benefit payments – The following gross benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated.

(In millions)	Pension Benefits		Other Benefits (a)
2013	$	208	$	21
2014		206		23
2015		201		26
2016		197		28
2017		195		30
2018 through 2022		871		179

^(a)  Effective 2013, as a result of the PPACA, future Medicare reimbursements will no longer be tax deductible and must be used to reduce the costs of providing Medicare part D equivalent prescription drug benefits to retirees.

Multi Employer Pension Plan

Total contributions to the plan.

Pension Protection

FIP/RP Status

Expiration Date of

Act Zone Status

Pending/

MPC Contributions (In millions)

Surcharge

Collective - Bargaining

Pension Fund

EIN

2012

2011

Implemented

2012

2011

2010

Imposed

Agreement

Central States, Southeast and Southwest Areas Pension Plan (a)

36-6044243

Red

Red

Implemented

$

4

$

3

$

3

No

January 31, 2014

(a) This agreement has a minimum contribution requirement of $259 per week per employee for 2013. A total of 251 employees participated in the plan as of December 31, 2012.

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Related Party Transactions (Related Party Net Interest And Other Financial Income) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Related Party Transaction [Line Items]
Interest income	$ 1
Interest capitalized		(8)	(66)
Interest expense
Related party net interest and other financial income	1	35	24
PFD [Member]
Related Party Transaction [Line Items]
Dividend income, PFD Preferred Stock		35	24
Interest expense		3	12
Marathon Oil Companies [Member]
Related Party Transaction [Line Items]
Interest expense		$ 5	$ 54

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Supplemental Cash Flow Information (Summary Of Supplemental Cash Flow Information) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$ 67		$ 5
Income taxes paid to taxing authorities	1,211	[1]	617	[1]	11	[1]
Non-cash investing and financing activities:
Property, plant and equipment contributed by Marathon Oil			81
Capital lease obligations increase	62		26		32
Preferred equity interest received in asset disposition					80	[2]
Preferred equity interest received in contract settlement	45	[2]
Preferred equity interest dividend received in-kind	1
Acquisition:
Intangible asset acquired	3
Liability assumed	2
Income taxes paid to Marathon Oil under tax sharing agreement	$ 181

[1] U.S. federal and most state income taxes, if incurred, were paid by Marathon Oil for periods prior to the Spinoff. The amount for 2012 includes payments of $181 million for 2011 return period income taxes made to Marathon Oil under our tax sharing agreement, and in return we received an equal amount of minimum tax credits. See Note 25.

[2] See Note 7.

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Related Party Transactions (Narrative) (Detail) (USD $)	12 Months Ended										3 Months Ended	12 Months Ended			12 Months Ended			12 Months Ended		0 Months Ended	12 Months Ended		12 Months Ended			12 Months Ended			12 Months Ended		1 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Jun. 30, 2011	Dec. 31, 2012 TACE [Member]	Dec. 31, 2011 TACE [Member]	Dec. 31, 2010 TACE [Member]	Dec. 31, 2012 TAME [Member]	Dec. 31, 2011 TAME [Member]	Dec. 31, 2010 TAME [Member]	Mar. 31, 2012 Centennial [Member]	Dec. 31, 2012 Centennial [Member]	Dec. 31, 2011 Centennial [Member]	Dec. 31, 2010 Centennial [Member]	Dec. 31, 2012 LOOP [Member]	Dec. 31, 2011 LOOP [Member]	Dec. 31, 2010 LOOP [Member]	Dec. 31, 2011 Marathon Oil Companies [Member]	Dec. 31, 2010 Marathon Oil Companies [Member]	Feb. 01, 2011 Marathon Oil Companies [Member] Revenue Bonds [Member]	Dec. 31, 2012 Marathon Oil Companies [Member] Revenue Bonds [Member]	Jul. 18, 2007 Marathon Oil Companies [Member] Revenue Bonds [Member]	Dec. 31, 2011 PFD [Member]	Dec. 31, 2010 PFD [Member]	Dec. 31, 2005 PFD [Member]	Dec. 31, 2012 PFD [Member] Related Party Credit Agreement [Member]	Oct. 28, 2010 PFD [Member] Related Party Credit Agreement [Member]	Jul. 18, 2007 PFD [Member] Related Party Credit Agreement [Member]	Dec. 31, 2012 PFD [Member] Initial Agreement [Member] Related Party Credit Agreement [Member]	Dec. 31, 2012 PFD [Member] Amended Agreement [Member] Related Party Credit Agreement [Member]	Jul. 18, 2007 PFD [Member] Related Party Credit Agreement [Member]	Jul. 18, 2007 PFD [Member] Euro Dollar Denominated Loans [Member] Related Party Credit Agreement [Member]	Jul. 18, 2007 PFD [Member] Euro Dollar Denominated Loans [Member] Minimum [Member] Related Party Credit Agreement [Member]	Jul. 18, 2007 PFD [Member] Euro Dollar Denominated Loans [Member] Maximum [Member] Related Party Credit Agreement [Member]
Related Party Transaction [Line Items]
Equity method investments, ownership percentage					36.00%	36.00%	36.00%	50.00%	50.00%	50.00%		50.00%	50.00%	50.00%	51.00%	51.00%	51.00%
Separation and distribution agreement date of Spinoff	May 25, 2011
Aggregate cash and cash equivalent				$ 1,625,000,000
Maximum duration of agreement for administrative services with former parent (in years)	1 year
Selling, general and administrative expenses	1,223,000,000	1,059,000,000	874,000,000															26,000,000	43,000,000
Prepaid tariff													11,000,000		0	4,000,000
Reductions in other assets amount											11,000,000				4,000,000
Impairment of other noncurrent assets												14,000,000
Credit facility, amount																											4,400,000,000	2,900,000,000
Credit agreement termination date																					Apr. 01, 2011					Jun. 30, 2011			May 04, 2012	Nov. 01, 2013
Long-term debt payable to related parties - borrowings		7,748,000,000	18,804,000,000																				7,750,000,000	18,800,000,000
Long-term debt payable to related parties - repayments		11,366,000,000	17,544,000,000																	1,050,000,000			10,320,000,000	17,540,000,000
Credit agreement initiation date																					Jul. 18, 2007								Jul. 18, 2007	Oct. 28, 2010
Interest rate, description																															Higher of the prime rate or the sum of 0.5 percent, plus the federal funds rate	LIBOR plus a margin ranging from 0.25 percent to 1.125 percent
Debt instrument, description of variable rate basis																															Federal Funds Rate	LIBOR
Debt instrument basis spread on variable rate																															0.50%		0.25%	1.125%
Debt instrument amount																						1,100,000,000
Loan Agreement interest Rate																						5.125%
Preferred stock redemption price (in USD per share)																									$ 2,000
Property, plant and equipment additions related to capitalized interest incurred by Marathon Oil on behalf of the company	101,000,000	114,000,000	103,000,000															2,000,000	20,000,000
Net non-cash capital distributions to Marathon Oil																		$ 57,000,000	$ (118,000,000)

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Goodwill (Tables)

12 Months Ended

Dec. 31, 2012

Changes In Carrying Amount Of Goodwill

The changes in the carrying amount of goodwill for 2012 and 2011 were as follows:

(In millions)	Refining &     Marketing		Speedway		Pipeline     Transportation		Total
2011
Beginning balance	$	554	$	120	$	163	$	837
Purchase price adjustment		(2)		-		(1)		(3)
Acquisition(a)		-		9		-		9
Disposition		(1)		-		-		(1)
Ending balance	$	551	$	129	$	162	$	842
2012
Beginning balance	$	551	$	129	$	162	$	842
Acquisitions(a)		-		88		-		88
Ending balance	$	551	$	217	$	162	$	930

^(a)  See Note 6 for information on the acquisitions.

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Description Of The Business, Spinoff And Basis Of Presentation

12 Months Ended

Dec. 31, 2012

Description Of The Business, Spinoff And Basis Of Presentation

1. Description of the Business, Spinoff and Basis of Presentation

Description of the Business – Our business consists of refining and marketing, retail marketing and pipeline transportation operations conducted primarily in the Midwest, Gulf Coast and Southeast regions of the United States, through subsidiaries, including Marathon Petroleum Company LP, Speedway LLC and MPLX LP and its subsidiaries (“MPLX”).    Until December 1, 2010, we also had operations in the Upper Great Plains region of the United States.

See Note 11 for additional information about our operations.

Spinoff – On May 25, 2011, the Marathon Oil Corporation (“Marathon Oil”) board of directors approved the spinoff of its Refining, Marketing & Transportation Business (“RM&T Business”) into an independent, publicly traded company, Marathon Petroleum Corporation (“MPC”), through the distribution of MPC common stock to the stockholders of Marathon Oil common stock.    In accordance with a separation and distribution agreement between Marathon Oil and MPC, the distribution of MPC common stock was made on June 30, 2011, with Marathon Oil stockholders receiving one share of MPC common stock for every two shares of Marathon Oil common stock held (the “Spinoff”).    Following the Spinoff, Marathon Oil retained no ownership interest in MPC, and each company had separate public ownership, boards of directors and management.    All subsidiaries and equity method investments not contributed by Marathon Oil to MPC remained with Marathon Oil and, together with Marathon Oil, are referred to as the “Marathon Oil Companies.” On July 1, 2011, our common stock began trading “regular-way” on the New York Stock Exchange under the ticker symbol “MPC”.

Basis of Presentation – Prior to the Spinoff on June 30, 2011, our results of operations and cash flows consisted of the RM&T Business, which represented a combined reporting entity.    Subsequent to the Spinoff, our results of operations and cash flows consist of consolidated MPC activities.    All significant intercompany transactions and accounts have been eliminated.

The consolidated statements of income for periods prior to the Spinoff included expense allocations for certain corporate functions historically performed by the Marathon Oil Companies, including allocations of general corporate expenses related to executive oversight, accounting, treasury, tax, legal, procurement and information technology.    Those allocations were based primarily on specific identification, headcount or computer utilization.    Our management believes the assumptions underlying the consolidated financial statements, including the assumptions regarding allocating general corporate expenses from the Marathon Oil Companies, are reasonable.    However, these consolidated financial statements do not include all of the actual expenses that would have been incurred had we been a stand-alone company during the periods presented prior to the Spinoff and may not reflect our consolidated results of operations and cash flows had we been a stand-alone company during the periods presented.    Actual costs that would have been incurred if we had been a stand-alone company would depend upon multiple factors, including organizational structure and strategic decisions made in various areas, including information technology and infrastructure.    Subsequent to the Spinoff, we are performing these functions using internal resources or services provided by third parties, certain of which were provided by the Marathon Oil Companies during a transition period pursuant to a transition services agreement, which terminated June 30, 2012.    See Note 5.

During 2012, we reclassified certain expenses from selling, general and administrative expenses to cost of revenues, which is consistent with expense classifications for MPLX, MPC’s consolidated subsidiary.    Historical periods were also reclassified to conform to the current year presentation.    This reclassification resulted in an increase in cost of revenues and a decrease in selling, general and administrative expenses of $47 million and $46 million for 2011 and 2010, respectively.

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Defined Benefit Pension And Other Postretirement Plans (Summary Of Projected Benefit Obligations And Funded Status For Defined Benefit Pension And Other Postretirement Plans) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Change in plan assets:
Fair value of plan assets at December 31	$ 1,478		$ 1,423
Amounts recognized in the consolidated balance sheets:
Noncurrent liabilities	(1,266)		(1,783)
LOOP [Member]
Pretax amounts recognized in accumulated other comprehensive loss:
Net loss	16		2
Equity method investments, ownership percentage	51.00%
Pension Benefits [Member]
Change in benefit obligations:
Benefit obligations at January 1	2,685		2,266
Service cost	66		65		62
Interest cost	94		110		105
Actuarial loss	117		384
Benefits paid	(233)		(178)
Liability gain due to curtailment	(17)		(4)
Other	(520)	[1]	42	[1]
Benefit obligations at December 31	2,192		2,685		2,266
Change in plan assets:
Fair value of plan assets at January 1	1,423		1,233
Actual return on plan assets	157		50
Employer contributions	131		282
Other			36	[1]
Benefits paid	(233)		(178)
Benefits paid from plan assets
Fair value of plan assets at December 31	1,478		1,423		1,233
Funded status of plans at December 31	(714)		(1,262)
Amounts recognized in the consolidated balance sheets:
Current liabilities	(18)		(12)
Noncurrent liabilities	(696)		(1,250)
Accrued benefit cost	(714)		(1,262)
Pretax amounts recognized in accumulated other comprehensive loss:
Net loss	1,147	[2]	1,319	[2]
Prior service cost (credit)	(460)	[2]	42	[2]
Other Benefits [Member]
Change in benefit obligations:
Benefit obligations at January 1	551		483
Service cost	20		19		14
Interest cost	24		27		24
Actuarial loss	53		39
Benefits paid	(17)		(17)
Liability gain due to curtailment
Other	(40)	[1]
Benefit obligations at December 31	591		551		483
Change in plan assets:
Fair value of plan assets at January 1
Actual return on plan assets
Employer contributions
Other		[1]		[1]
Benefits paid	(17)		(17)
Benefits paid from plan assets
Fair value of plan assets at December 31
Funded status of plans at December 31	(591)		(551)
Amounts recognized in the consolidated balance sheets:
Current liabilities	(21)		(18)
Noncurrent liabilities	(570)		(533)
Accrued benefit cost	(591)		(551)
Pretax amounts recognized in accumulated other comprehensive loss:
Net loss	93	[2]	42	[2]
Prior service cost (credit)	$ (38)	[2]

[1] Includes adjustments related to plan amendments in 2012. Includes adjustments related to the Spinoff in 2011.

[2] Amounts exclude those related to LOOP, an equity method investee with defined benefit pension and postretirement plans for which net losses of $16 million and $2 million were recorded in accumulated other comprehensive loss in 2012, reflecting our 51 percent share.

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Related Party Transactions (Sales To Related Parties) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Related Party Transaction [Line Items]
Sales to related parties	$ 8	$ 55	$ 100
Centennial [Member]
Related Party Transaction [Line Items]
Sales to related parties	1	35	54
Other Equity Method Investees [Member]
Related Party Transaction [Line Items]
Sales to related parties	7	7	7
Marathon Oil Companies [Member]
Related Party Transaction [Line Items]
Sales to related parties		$ 13	$ 39

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Stock-Based Compensation Plans (Summary Of Restricted Stock Award Activity) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Restricted Stock [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at December 31, 2011,Number of Shares/Units	348,691
Granted,Number of Shares/Units	416,495
RS's Vested/RSU's Issued, Number of Shares/Units	(115,441)
Forfeited,Number of Shares/Units	(11,672)
Outstanding at December 31, 2012,Number of Shares/Units	638,073	348,691
Outstanding at December 31, 2011,Weighted-Average Grant Date Fair Value (in USD per share)	$ 34.36
Granted,Weighted-Average Grant Date Fair Value (in USD per share)	$ 43.11	$ 41.54
RS's Vested/RSU's Issued,Weighted-Average Grant Date Fair Value (in USD per share)	$ 29.63
Forfeited,Weighted-Average Grant Date Fair Value (in USD per share)	$ 39.54
Outstanding at December 31, 2012,Weighted-Average Grant Date Fair Value (in USD per share)	$ 40.83	$ 34.36
Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at December 31, 2011,Number of Shares/Units	319,944
Granted,Number of Shares/Units	39,462
RS's Vested/RSU's Issued, Number of Shares/Units	(179)
Forfeited,Number of Shares/Units	(116)
Outstanding at December 31, 2012,Number of Shares/Units	359,111	319,944
Outstanding at December 31, 2011,Weighted-Average Grant Date Fair Value (in USD per share)	$ 29.43
Granted,Weighted-Average Grant Date Fair Value (in USD per share)	$ 44.38	$ 33.78
RS's Vested/RSU's Issued,Weighted-Average Grant Date Fair Value (in USD per share)	$ 34.02
Forfeited,Weighted-Average Grant Date Fair Value (in USD per share)	$ 43.44
Outstanding at December 31, 2012,Weighted-Average Grant Date Fair Value (in USD per share)	$ 31.07	$ 29.43

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Supplementary Statistics (Supplementary Statistics) (Detail) (USD $) In Millions, unless otherwise specified	1 Months Ended	12 Months Ended
	May 31, 2011 Store	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Supplementary Statistics [Line Items]
Income from operations		$ 5,347		$ 3,745		$ 1,011
Capital expenditures and investments		1,460		1,323		1,173
Number of convenience stores acquired	23
Capitalized interest		101		114		103
Reportable Segment [Member]
Supplementary Statistics [Line Items]
Income from operations		5,624	[1]	4,061		1,276
Capital expenditures and investments		1,256	[2],[3]	1,185	[2],[4]	1,069	[2]
Number of convenience stores acquired		97		23
Items Not Allocated [Member]
Supplementary Statistics [Line Items]
Capitalized interest		101		114		103
Refining & Marketing [Member] | Reportable Segment [Member]
Supplementary Statistics [Line Items]
Income from operations		5,098	[1]	3,591		800
Capital expenditures and investments		705	[2],[3]	900	[2],[4]	961	[2]
Speedway [Member] | Reportable Segment [Member]
Supplementary Statistics [Line Items]
Income from operations		310	[1]	271		293
Capital expenditures and investments		340	[2],[3],[5]	164	[2],[4],[5]	84	[2],[5]
Number of convenience stores acquired		97		23
Pipeline Transportation [Member] | Reportable Segment [Member]
Supplementary Statistics [Line Items]
Income from operations		216	[1]	199	[1]	183	[1]
Capital expenditures and investments		211	[2],[3]	121	[2],[4]	24	[2]
Segment overhead and pension settlement expenses		4
Corporate and Other Unallocated Items [Member] | Items Not Allocated [Member]
Supplementary Statistics [Line Items]
Income from operations		(336)	[1]	(316)	[1]	(236)	[1]
Capital expenditures and investments		204	[2],[6]	138	[2],[6]	104	[2],[6]
Minnesota Assets Sale Settlement Gain [Member] | Items Not Allocated [Member]
Supplementary Statistics [Line Items]
Income from operations		183
Pension Settlement Expenses [Member] | Items Not Allocated [Member]
Supplementary Statistics [Line Items]
Income from operations		(124)	[1]
Asset Impairment [Member] | Items Not Allocated [Member]
Supplementary Statistics [Line Items]
Income from operations						$ (29)

[1] Included in the Pipeline Transportation segment are $4 million of corporate overhead costs and pension settlement expenses attributable to MPLX subsequent to MPLX's October 31, 2012 initial public offering, which were included in items not allocated to segments prior to MPLX's initial public offering. These expenses are not currently allocated to other segments.

[2] Capital expenditures include changes in capital accruals.

[3] Includes Speedway's acquisition of 97 convenience stores in 2012.

[4] Includes Speedway's acquisition of 23 convenience stores in 2011.

[5] Includes acquisitions of 97 convenience stores in 2012 and 23 convenience stores in 2011.

[6] Includes capitalized interest of $101 million, $114 million and $103 million for 2012, 2011 and 2010.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2012

Components Of Income Tax Provisions (Benefits)

	2012						2011						2010
(In millions)	Current		Deferred		Total		Current		Deferred		Total		Current		Deferred		Total
Federal	$	1,185	$	432	$	1,617	$	1,040	$	139	$	1,179	$	81	$	289	$	370
State and local		169		57		226		152		(16)		136		15		19		34
Foreign		(1)		3		2		15		-		15		(4)		-		(4)
Total	$	1,353	$	492	$	1,845	$	1,207	$	123	$	1,330	$	92	$	308	$	400

Reconciliation Of Federal Statutory Income Tax Rate

	2012			2011			2010
Statutory rate applied to income before income taxes		35	%		35	%		35	%
State and local income taxes, net of federal income tax effects		2			2			3
Legislation(a)		-			-			2
Domestic manufacturing deduction		(1)			(1)			-
Effect of dividends received deduction		-			-			(1)
Other		(1)			-			-
Provision for income taxes		35	%		36	%		39	%

^(a)  The Patient Protection and Affordable Care Act (“PPACA”) and the Health Care and Education Reconciliation Act of 2010 were signed into law in March 2010. These new laws effectively changed the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “MPDIMA”). Under the MPDIMA, the federal subsidy did not reduce our income tax deduction for the costs of providing such prescription drug plans, nor was it subject to income tax individually. Beginning in 2013, under the 2010 legislation, our income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. As a result, we recorded a charge of $26 million in 2010 for the write-off of deferred tax assets to reflect the change in the tax treatment of the federal subsidy.

Components Of Deferred Tax Assets And Liabilities

	December 31,
(In millions)	2012		2011
Deferred tax assets:
Employee benefits	$	585	$	820
Other		90		73
Total deferred tax assets		675		893
Deferred tax liabilities:
Property, plant and equipment		2,225		1,936
Inventories		610		610
Investments in subsidiaries and affiliates		307		79
Other		29		25
Total deferred tax liabilities		3,171		2,650
Net deferred tax liabilities	$	2,496	$	1,757

Components Of Net Deferred Tax Liabilities Classified In Consolidated Balance Sheets

	December 31,
(In millions)	2012		2011
Liabilities:
Accrued taxes	$	446	$	447
Deferred income taxes		2,050		1,310
Net deferred tax liabilities	$	2,496	$	1,757

Summary Of Income Tax Returns Subject To Examination

United States Federal	2010 - 2011
States	2004 - 2011

Summary Of Activity In Unrecognized Tax Benefits

(In millions)	2012		2011		2010
January 1 balance	$	20	$	14	$	19
Additions for tax positions of prior years		32		50		7
Reductions for tax positions of prior years		(6)		-		(1)
Settlements		(6)		(44)		(11)
December 31 balance	$	40	$	20	$	14

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2012

Supplemental Cash Flow Information

21. Supplemental Cash Flow Information

(In millions)	2012		2011		2010
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	67	$	5	$	-
Income taxes paid to taxing authorities (a)		1,211		617		11
Non-cash investing and financing activities:
Property, plant and equipment contributed by Marathon Oil	$	-	$	81	$	-
Capital lease obligations increase		62		26		32
Preferred equity interest received in asset disposition (b)		-		-		80
Preferred equity interest received in contract settlement (b)		45		-		-
Preferred equity interest dividend received in-kind		1		-		-
Acquisition:
Intangible asset acquired		3		-		-
Liability assumed		2		-		-

^(a)  U.S. federal and most state income taxes, if incurred, were paid by Marathon Oil for periods prior to the Spinoff. The amount for 2012 includes payments of $181 million for 2011 return period income taxes made to Marathon Oil under our tax sharing agreement, and in return we received an equal amount of minimum tax credits. See Note 25.

^(b)  See Note 7.

The consolidated statements of cash flows exclude changes to the consolidated balance sheets that did not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures:

(In millions)	2012		2011		2010
Additions to property, plant and equipment	$	1,369	$	1,185	$	1,217
Acquisitions (a)		180		74		-
Increase (decrease) in capital accruals		(117)		53		(51)
Total capital expenditures	$	1,432	$	1,312	$	1,166

^(a)  Excludes inventory acquired and liability assumed in 2012.

The following is a reconciliation of contributions from (distributions to) Marathon Oil:

(In millions)	2012		2011		2010
Distributions to Marathon Oil per consolidated statements of cash flows	$	-	$	(783)	$	(1,330)
Non-cash contributions from (distributions to) Marathon Oil		-		57		(118)
Distributions to Marathon Oil per consolidated statements of equity / net investment	$	-	$	(726)	$	(1,448)

See Note 5 for information regarding non-cash contributions from (distributions to) Marathon Oil.

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Debt

12 Months Ended

Dec. 31, 2012

Debt

20. Debt

Our outstanding borrowings at December 31, 2012 and 2011 consisted of the following:

	December 31,
(In millions)	2012		2011
Marathon Petroleum Corporation:
Revolving credit agreement due 2017	$	-	$	-
3.500% senior notes due March 1, 2016		750		750
5.125% senior notes due March 1, 2021		1,000		1,000
6.500% senior notes due March 1, 2041		1,250		1,250
Consolidated subsidiaries:
Capital lease obligations due 2013-2027		355		299
MPLX Operations LLC revolving credit agreement due 2017		-		-
Trade receivables securitization facility due 2014		-		-
Total		3,355		3,299
Unamortized discount		(10)		(11)
Fair value adjustments (a)		16		19
Amounts due within one year		(19)		(15)
Total long-term debt due after one year	$	3,342	$	3,292

^(a)  See Notes 18 and 19 for information on interest rate swaps.

The following table shows five years of scheduled debt payments.

(In millions)
2013	$	19
2014		21
2015		23
2016		773
2017		25

There were no borrowings or letters of credit outstanding under the revolving credit agreements or the trade receivable securitization facility at December 31, 2012.

MPC Revolving Credit Agreement - On September 14, 2012, we entered into a five-year senior unsecured revolving credit agreement (the “Credit Agreement”) with a syndicate of lenders and terminated our previous four-year revolving credit agreement. The Credit Agreement was amended on December 20, 2012, to increase the borrowing capacity by $500 million to a total of $2.5 billion. The commitment increase became effective on February 1, 2013 in conjunction with the acquisition described in Note 26. The Credit Agreement includes letter of credit issuing capacity of up to $2.0 billion and swingline loan capacity of up to $100 million. We may increase the borrowing capacity under the Credit Agreement by up to an additional $500 million, subject to certain conditions including the consent of the lenders whose commitments would be increased. In addition, we may request that the term of the Credit Agreement, which expires on September 14, 2017, be extended for up to two additional one-year periods. Each such extension would be subject to the approval of lenders holding greater than 50 percent of the commitments then outstanding, and the commitment of any lender that does not consent to an extension of the maturity date will be terminated on the then-effective maturity date.

The Credit Agreement contains representations and warranties, affirmative and negative covenants and events of default that we consider usual and customary for an agreement of this type. The financial covenant included in the Credit Agreement requires us to maintain, as of the last day of each fiscal quarter, a ratio of Consolidated Net Debt (as defined in the Credit Agreement) to Total Capitalization (as defined in the Credit Agreement) of no greater than 0.65 to 1.00. In addition, the Credit Agreement includes limitations on the indebtedness of our subsidiaries, other than subsidiaries that guarantee our obligations under the Credit Agreement and our ability, and the ability of our subsidiaries, to incur liens on property or assets or enter into certain transactions with affiliates.

Borrowings of revolving loans under the Credit Agreement bear interest at either (i) the sum of the Adjusted LIBO Rate (as defined in the Credit Agreement) and a margin ranging between 1.00 percent to 2.00 percent, depending on our credit ratings, or (ii) the sum of the Alternate Base Rate (as defined in the Credit Agreement)and a margin ranging between zero percent to 1.00 percent, depending on our credit ratings. The Credit Agreement also provides for customary fees, including administrative agent fees, annual commitment fees ranging from 0.10 percent to 0.35 percent, depending on our credit ratings, on the unused portion, fees in respect to letters of credit and other fees.

During 2012, we expensed $1 million of the deferred financing costs from the previous revolving credit agreement related to lenders who discontinued participation in the revolving credit arrangement. The remaining $22 million of deferred financing costs from the previous revolving credit agreement are being amortized over the life of the new revolving credit agreement.

MPLX Operations LLC Revolving Credit Agreement - On September 14, 2012, MPLX Operations LLC, an affiliate of MPC and wholly-owned subsidiary of MPLX LP, as the borrower, and MPLX, as the parent guarantor, entered into a five-year senior unsecured revolving credit agreement (“MPLX Credit Agreement”) with a syndicate of lenders. The MPLX Credit Agreement became effective following MPLX’s initial public offering and has an initial borrowing capacity of $500 million. MPLX may increase the borrowing capacity under the MPLX Credit Agreement by up to an additional $300 million, subject to certain conditions, including the consent of the lenders whose commitments would be increased. The MPLX Credit Agreement includes letter of credit issuing capacity of up to $250 million and swingline loan capacity of up to $50 million. MPLX may, subject to certain conditions, request that the term of the MPLX Credit Agreement, which expires on October 31, 2017, be extended for up to two additional one-year periods. Each such extension would be subject to the approval of lenders holding greater than 50 percent of the commitments then outstanding, and the commitment of any lender that does not consent to an extension of the maturity date will be terminated on the then-effective maturity date.

The MPLX Credit Agreement contains representations and warranties, affirmative and negative covenants and events of default that we consider usual and customary for an agreement of this type. The financial covenant included in the MPLX Credit Agreement requires MPLX to maintain a ratio of Consolidated Total Debt (as defined in the MPLX Credit Agreement) as of the end of each fiscal quarter to Consolidated EBITDA (as defined in the MPLX Credit Agreement) for the prior four fiscal quarters of not greater than 5.0 to 1.0 (or 5.5 to 1.0 during the six-month period following certain acquisitions).

Borrowings of revolving loans under the MPLX Credit Agreement bear interest at either (i) the sum of the Adjusted LIBO Rate (as defined in the MPLX Credit Agreement) and a margin ranging from 1.00 percent to 2.00 percent or (ii) the sum of the Alternate Base Rate (as defined in the MPLX Credit Agreement) and a margin ranging from zero percent to 1.00 percent. Prior to MPLX receiving a rating from Standard & Poor’s Rating Group or Moody’s Investor Service, Inc. for its Index Debt (as defined in the MPLX Credit Agreement), the margin that is added to the applicable interest rate is based on MPLX’s ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA for the prior four fiscal quarters. Once MPLX receives a rating, if ever, the margin added to the applicable interest rate will be based on MPLX’s credit ratings. The MPLX Credit Agreement also provides for customary fees, including administrative agent fees, commitment fees ranging from 0.10 percent to 0.35 percent of the unused portion, depending on MPLX’s ratio of Consolidated Total Debt as of the end of the fiscal quarter to Consolidated EBITDA for the prior four fiscal quarters prior to the rating date, or MPLX’s credit ratings subsequent to the rating date, fronting and issuance fees in respect to letters of credit and other fees.

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Fair Value Measurements (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized gains or losses included in net income	$ 0	$ 1	$ 1
Maximum [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percent of trade receivables and payables with balances outstanding greater than 90 days	1.00%
Centennial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of other noncurrent assets	14
Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of other noncurrent assets	14
Impairment charges on long-lived assets			29
Fair Value, Measurements, Nonrecurring [Member] | Centennial [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment of other noncurrent assets	$ 14

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Supplementary Statistics (Tables)

12 Months Ended

Dec. 31, 2012

Supplementary Statistics

Supplementary Statistics (Unaudited)

(In millions)	2012		2011		2010
Income from Operations by segment
Refining & Marketing	$	5,098	$	3,591	$	800
Speedway		310		271		293
Pipeline Transportation(a)		216		199		183
Items not allocated to segments:
Corporate and other unallocated items(a)		(336)		(316)		(236)
Minnesota Assets sale settlement gain		183		-		-
Pension settlement expenses(a)		(124)		-		-
Impairment		-		-		(29)
Income from operations	$	5,347	$	3,745	$	1,011
Capital Expenditures and Investments(b)
Refining & Marketing	$	705	$	900	$	961
Speedway(c)		340		164		84
Pipeline Transportation		211		121		24
Corporate and Other(d)		204		138		104
Total	$	1,460	$	1,323	$	1,173

^(a)  Included in the Pipeline Transportation segment are $4 million of corporate overhead costs and pension settlement expenses attributable to MPLX subsequent to MPLX’s October 31, 2012 initial public offering, which were included in items not allocated to segments prior to MPLX’s initial public offering. These expenses are not currently allocated to other segments.

^(b) Capital expenditures include changes in capital accruals.

^(c) Includes acquisitions of 97 convenience stores in 2012 and 23 convenience stores in 2011.

^(d)  Includes capitalized interest of $101 million, $114 million and $103 million for 2012, 2011 and 2010.

Operating Statistics

Supplementary Statistics (Unaudited)

	2012		2011		2010
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)(a)		1,618		1,599		1,585
Refining & Marketing Operating Statistics
Refinery Throughputs (thousands of barrels per day):
Crude oil refined		1,195		1,177		1,173
Other charge and blendstocks		168		181		162
Total		1,363		1,358		1,335
Crude Oil Capacity Utilization percent(b)		100		103		99
Refined Product Yields (thousands of barrels per day):
Gasoline		738		739		726
Distillates		433		433		409
Propane		26		25		24
Feedstocks and special products		109		109		97
Heavy fuel oil		18		21		24
Asphalt		62		56		76
Total		1,386		1,383		1,356
Refining & Marketing Refined Product Sales Volume (thousands of barrels per day)(c)		1,599		1,581		1,573
Refining & Marketing Gross Margin (dollars per barrel)(d)	$	10.45	$	7.75	$	2.81
Direct Operating Costs in Refining & Marketing Gross Margin (dollars per barrel):(e)
Planned turnaround and major maintenance	$	1.00	$	0.78	$	1.19
Depreciation and amortization		1.44		1.29		1.32
Other manufacturing(f)		3.15		3.16		3.32
Total	$	5.59	$	5.23	$	5.83
Speedway Operating Statistics
Convenience stores at period-end		1,464		1,371		1,358
Gasoline & distillates sales (millions of gallons)		3,027		2,938		3,300
Gasoline & distillates gross margin (dollars per gallon)(g)	$	0.1318	$	0.1308	$	0.1207
Merchandise sales (in millions)	$	3,058	$	2,924	$	3,195
Merchandise gross margin (in millions)	$	795	$	719	$	789
Same store gasoline sales volume (period over period)		-0.8%		-1.7%		3.0%
Same store merchandise sales (period over period)		0.9%		1.1%		4.4%
Same store merchandise sales excluding cigarettes (period over period)		7.0%		6.7%		6.2%
Pipeline Transportation Operating Statistics
Pipeline throughput (thousands of barrels per day)(h):
Crude oil pipelines		1,190		1,184		1,204
Refined products pipelines		980		1,031		968
Total		2,170		2,215		2,172

^(a)  Total average daily volumes of refined product sales to wholesale, branded and retail (Speedway segment) customers.

^(b)  Based on calendar day capacity, which is an annual average that includes downtime for planned maintenance and other normal operating activities.

^(c)  Includes intersegment sales.

^(d)  Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation and amortization, divided by Refining & Marketing segment refined product sales volume.

^(e)  Per barrel of total refinery throughputs.

^(f)  Includes utilities, labor, routine maintenance and other operating costs.

^(g)  The price paid by consumers less the cost of refined products, including transportation, consumer excise taxes and bankcard processing fees, divided by gasoline and distillates sales volume.

^(h)  On owned common-carrier pipelines, excluding equity method investments.

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Inventories (Tables)

12 Months Ended

Dec. 31, 2012

Summary Of Inventories

	December 31,
(In millions)	2012		2011
Crude oil and refinery feedstocks	$	1,383	$	1,339
Refined products		1,761		1,725
Merchandise		74		65
Supplies and sundry items		231		191
Total (at cost)	$	3,449	$	3,320

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Defined Benefit Pension and Other Postretirement Plans

12 Months Ended

Dec. 31, 2012

Defined Benefit Pension and Other Postretirement Plans

22. Defined Benefit Pension and Other Postretirement Plans

We have noncontributory defined benefit pension plans covering substantially all employees. Benefits under these plans have been based primarily on age, years of service and final average pensionable earnings. The years of service component of this formula was frozen as of December 31, 2009. Benefits for service beginning January 1, 2010 are based on a cash balance formula with an annual percentage of eligible pay credited based upon age and years of service. Eligible Speedway employees accrue benefits under a defined contribution plan for service years beginning January 1, 2010.

On May 17, 2012, we communicated to our employees changes in the defined benefit pension plans for Speedway and the legacy portion of the Marathon Petroleum Retirement Plan effective January 1, 2013. Final average pensionable earnings used to calculate pension benefits under these plans have been fixed as of December 31, 2012. In addition, cap protection was added to limit potential annual lump sum distribution discount rate increases. These plan amendments resulted in an overall decrease in pension liabilities of approximately $537 million, with the offset primarily to other comprehensive income, which was recorded in 2012. The benefit of this liability reduction is being amortized into income through 2024.

We also have other postretirement benefits covering most employees. Health care benefits are provided through comprehensive hospital, surgical and major medical benefit provisions subject to various cost-sharing features. Retiree life insurance benefits are provided to a closed group of retirees. Other postretirement benefits are not funded in advance.

On August 20, 2012, we communicated, to our impacted Medicare eligible retirees, changes in the post-65 medical plan coverage of the Marathon Petroleum Health Plan and the Marathon Petroleum Retiree Health Plan. Effective January 1, 2013, these Medicare eligible participants receive a tax free contribution to a health reimbursement account, which replaces benefits provided under the previous plans. Increases are capped at four percent per year. This plan change resulted in a reduction in retiree medical liabilities of approximately $40 million. This was more than offset by an increase in retiree medical liabilities of approximately $57 million primarily due to a reduction in discount rates as of the remeasurement date. The overall net liability increase and the offset to other comprehensive income were recorded in 2012.

Obligations and funded status – The accumulated benefit obligation for all defined benefit pension plans was $2,035 million and $1,948 million as of December 31, 2012 and 2011.

The following summarizes our defined benefit pension plans that have accumulated benefit obligations in excess of plan assets.

	December 31,
(In millions)	2012		2011
Projected benefit obligations	$	2,192	$	2,685
Accumulated benefit obligations		2,035		1,948
Fair value of plan assets		1,478		1,423

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

	Pension Benefits				Other Benefits
(In millions)	2012		2011		2012		2011
Change in benefit obligations:
Benefit obligations at January 1	$	2,685	$	2,266	$	551	$	483
Service cost		66		65		20		19
Interest cost		94		110		24		27
Actuarial loss		117		384		53		39
Benefits paid		(233)		(178)		(17)		(17)
Liability gain due to curtailment		(17)		(4)		-		-
Other (a)		(520)		42		(40)		-
Benefit obligations at December 31		2,192		2,685		591		551
Change in plan assets:
Fair value of plan assets at January 1		1,423		1,233		-		-
Actual return on plan assets		157		50		-		-
Employer contributions		131		282		-		-
Other(a)		-		36		-		-
Benefits paid from plan assets		(233)		(178)		-		-
Fair value of plan assets at December 31		1,478		1,423		-		-
Funded status of plans at December 31	$	(714)	$	(1,262)	$	(591)	$	(551)
Amounts recognized in the consolidated balance sheets:
Current liabilities	$	(18)	$	(12)	$	(21)	$	(18)
Noncurrent liabilities		(696)		(1,250)		(570)		(533)
Accrued benefit cost	$	(714)	$	(1,262)	$	(591)	$	(551)
Pretax amounts recognized in accumulated other comprehensive loss: (b)
Net loss	$	1,147	$	1,319	$	93	$	42
Prior service cost (credit)		(460)		42		(38)		-

^(a)  Includes adjustments related to plan amendments in 2012. Includes adjustments related to the Spinoff in 2011.

^(b)  Amounts exclude those related to LOOP, an equity method investee with defined benefit pension and postretirement plans for which net losses of $16 million and $2 million were recorded in accumulated other comprehensive loss in 2012, reflecting our 51 percent share.

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

	Pension Benefits						Other Benefits
(In millions)	2012		2011		2010		2012		2011		2010
Components of net periodic benefit cost:
Service cost	$	66	$	65	$	62	$	20	$	19	$	14
Interest cost		94		110		105		24		27		24
Expected return on plan assets		(104)		(97)		(95)		-		-		-
Amortization – prior service cost (credit)		(18)		6		7		(2)		-		1
– actuarial loss (gain)		93		71		51		2		-		(2)
– net settlement/curtailment loss(a)		125		8		13		-		-		-
Net periodic benefit cost(b)	$	256	$	163	$	143	$	44	$	46	$	37
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial loss	$	46	$	427	$	129	$	53	$	39	$	61
Prior service credit(c)		(520)		-		-		(40)		-		-
Amortization of actuarial (loss) gain		(218)		(79)		(64)		(2)		-		2
Amortization of prior service cost (credit)		18		(6)		(7)		2		-		(1)
Other(d)		-		6		-		-		-		-
Total recognized in other comprehensive loss	$	(674)	$	348	$	58	$	13	$	39	$	62
Total recognized in net periodic benefit cost and other comprehensive loss	$	(418)	$	511	$	201	$	57	$	85	$	99

^(a)  A curtailment gain was recorded in 2011 on the Speedway pension plan at the end of the transition services period related to the sale of most of our Minnesota Assets in 2010. See Note 7.

^(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 adjustments due to changes made to the defined pension plans and the post-65 medical plan coverage effective January 1, 2013.

^(d)  Includes adjustments related to the Spinoff.

Lump sum payments to employees retiring in 2012, 2011 and 2010 exceeded the plan’s total service and interest costs expected for those years. Settlement losses are required to be recorded when lump sum payments exceed total service and interest costs. As a result, pension settlement expenses were recorded in 2012, 2011 and 2010 related to our cumulative lump sum payments made during those years.

The estimated net loss and prior service credit for our defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2013 are $89 million and $45 million. The 2013 net loss amortization is expected to be lower than the 2012 actual amortization primarily as a result of adjustments made to the net loss balance due to settlement accounting in 2012. The estimated net loss and 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 2013 is $4 million and $4 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 2012, 2011 and 2010.

	Pension Benefits						Other Benefits
	2012		2011		2010		2012		2011		2010
Weighted-average assumptions used to determine benefit obligation:
Discount rate		3.45%		4.30%		5.05%		4.05%		4.65%		5.55%
Rate of compensation increase		5.00%		5.00%		5.00%		5.00%		5.00%		5.00%
Weighted average assumptions used to determine net periodic benefit cost:
Discount rate		4.06%		4.98%		5.23%		4.54%		5.55%		6.85%
Expected long-term return on plan assets		7.50%		8.50%		8.50%		-		-		-
Rate of compensation increase		5.00%		5.00%		4.50%		5.00%		5.00%		4.50%

Expected long-term return on plan assets

The overall expected long-term return on plan assets assumption 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 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.

Assumed health care cost trend

The following summarizes the assumed health care cost trend rates.

	December 31,
	2012		2011		2010
Health care cost trend rate assumed for the following year:
Medical:
Pre-65		8.00%		7.50%		7.50%
Post-65(a)		N/A		7.00%		7.00%
Prescription drugs		7.00%		7.50%		7.50%
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(a)		N/A		5.00%		5.00%
Prescription drugs		5.00%		5.00%		5.00%
Year that the rate reaches the ultimate trend rate:
Medical:
Pre-65		2020		2018		2018
Post-65(a)		N/A		2017		2017
Prescription drugs		2018		2018		2018

^(a)  Effective 2013, as a result of changes in the post-65 medical plan coverage of the Marathon Petroleum Health Plan and the Marathon Petroleum Retiree Health Plan, increases are the lower of the trend rate or 4 percent.

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:

	1-Percentage-		1-Percentage-
(In millions)	Point Increase		Point Decrease
Effect on total of service and interest cost components	$	6	$	5
Effect on other postretirement benefit obligations		32		28

Plan investment policies and strategies

The investment policies for our 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 achievable in the capital markets, which are consistent with the risk parameters set by the plans’ investment committees; and (3) position the portfolios with a long-term investment horizon.

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. The plans’ targeted asset allocation is 75 percent equity securities and 25 percent fixed income securities; however, the asset allocation may be modified in the future as deemed appropriate by management.

The plans’ assets are managed by a third-party investment manager. The investment manager has limited discretion to move away from the target allocations based upon the manager’s judgment as to current confidence or concern regarding the capital markets. Investments are diversified by industry and type, limited by grade and maturity. Limited derivative investments are allowable subject to strict guidelines, such that derivatives may only be written against equity securities in the portfolio. Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies.

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 category at December 31, 2012 and 2011.

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 in the fair value hierarchy. The money market mutual fund is valued at the net asset value (“NAV”) of shares held.

Equity securities – Investments in public investment trusts and S&P 500 exchange-traded funds are valued using a market approach at the closing price reported in an active market and are therefore considered Level 1. Non-public investment trusts are considered Level 2 and are valued using a market approach based on the underlying investments in the trust, which are publicly traded securities. 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.

Pooled funds – Investments in two pooled funds are valued using a market approach at the NAV of units held, but investment opportunities in such funds are limited to the benefit plans of United States Steel Corporation, its subsidiaries and former affiliates. The funds consist of an equity investment portfolio consisting only of short-term instruments and publicly traded equities and a fixed income investment portfolio consisting only of short-term instruments, publicly traded bonds and Rule 144A bonds. These investments are considered Level 2.

Real estate – Real estate investments consist of interests in commingled funds. The valuation of total fund assets constitutes the sum of all individual investments plus working capital, adjusted for liabilities, currency translation and estimated performance incentives. The real estate investments are considered Level 3.

Other – Other investments include investments in two limited liability companies (“LLCs”) with no public market. The LLCs were formed to acquire timberland in the northwest United States. The values of the LLCs are determined by using appraised values plus net working capital and less any estimated performance incentives. 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, 2012 and 2011.

	December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	107	$	-	$	-	$	107
Equity securities:
Investment trusts		17		94		-		111
Exchange-traded funds		166		-		-		166
Private equity		-		-		56		56
Investment funds:
Pooled funds - equity(a)		-		709		-		709
Pooled funds - fixed income(b)		-		258		-		258
Real estate(c)		-		-		54		54
Other		-		-		17		17
Total investments, at fair value	$	290	$	1,061	$	127	$	1,478
	December 31, 2011
(In millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	205	$	-	$	-	$	205
Equity securities:
Investment trusts		15		81		-		96
Exchange-traded funds		14		-		-		14
Private equity		-		-		55		55
Investment funds:
Pooled funds - equity(a)		-		758		-		758
Pooled funds - fixed income(d)		-		229		-		229
Real estate(e)		-		-		49		49
Other		-		-		17		17
Total investments, at fair value	$	234	$	1,068	$	121	$	1,423

^(a)  Includes approximately 70 percent of investments held in U.S. and non-U.S. publicly traded common stocks in the consumer staples, consumer discretionary, technology, health and energy sectors and the remaining 30 percent of investments held amongst various other sectors.

^(b)  Includes approximately 90 percent of investments held in U.S. and non-U.S. publicly traded investment-grade government and corporate bonds which include treasuries, mortgage-backed securities and industrials, and the remaining 10 percent of investments held amongst various other sectors.

^(c)  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 land with the greatest percentage of investments made in the U.S. and Asia, which includes the emerging markets of China and India.

^(d)  Includes approximately 80 percent of investments held in U.S. and non-U.S. publicly traded investment-grade government and corporate bonds which include treasuries, mortgage-backed securities and industrials, and the remaining 20 percent of investments held amongst various other sectors.

^(e)  Includes investments diversified by property type and location. The largest property sector holdings, which represent approximately 75 percent of investments held, are office, hotel, residential and land 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:

	2012
(In millions)	Private Equity		Real Estate		Other		Total
Beginning balance	$	55	$	49	$	17	$	121
Actual return on plan assets		2		-		-		2
Purchases		12		10		-		22
Sales		(13)		(5)		-		(18)
Ending balance	$	56	$	54	$	17	$	127
	2011
(In millions)	Private Equity		Real Estate		Other		Total
Beginning balance	$	46	$	37	$	17	$	100
Actual return on plan assets		7		5		-		12
Purchases		10		12		-		22
Sales		(9)		(6)		-		(15)
Other		1		1		-		2
Ending balance	$	55	$	49	$	17	$	121

Cash Flows

Contributions to defined benefit plans – Our funding policy with respect to the pension plans is to contribute amounts necessary to satisfy minimum pension funding requirements, including requirements of the Pension Protection Act of 2006, plus such additional, discretionary, amounts from time to time as determined appropriate by management. We currently estimate that we will contribute approximately $160 million to the plans in 2013. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are estimated to be approximately $18 million and $21 million in 2013.

Estimated future benefit payments – The following gross benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated.

(In millions)	Pension Benefits		Other Benefits (a)
2013	$	208	$	21
2014		206		23
2015		201		26
2016		197		28
2017		195		30
2018 through 2022		871		179

^(a)  Effective 2013, as a result of the PPACA, future Medicare reimbursements will no longer be tax deductible and must be used to reduce the costs of providing Medicare part D equivalent prescription drug benefits to retirees.

Contributions to defined contribution plans – We also contribute to several defined contribution plans for eligible employees. Contributions to these plans totaled $60 million, $60 million and $54 million in 2012, 2011 and 2010.

Multiemployer Pension Plan

We contribute to one multiemployer defined benefit pension plan under the terms of a collective-bargaining agreement that covers some of our union-represented employees. The risks of participating in this multiemployer plan are different from single-employer plans in the following aspects:

• Assets contributed to the multiemployer plan by one employer may be used to provide benefits to employees of other participating employers.

• If a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining participating employers.

• If we choose to stop participating in the multiemployer plan, we may be required to pay that plan an amount based on the underfunded status of the plan, referred to as a withdrawal liability.

Our participation in this plan for 2012, 2011 and 2010 is outlined in the table below. The “EIN” column provides the Employee Identification Number for the plan. The most recent Pension Protection Act zone status available in 2012 and 2011 is for the plan’s year ended December 31, 2011 and December 31, 2010, respectively. The zone status is based on information that we received from the plan and is certified by the plan’s actuary. Among other factors, plans in the red zone are generally less than 65 percent funded. The “FIP/RP Status Pending/Implemented” column indicates a financial improvement plan or a rehabilitation plan has been implemented. The last column lists the expiration date of the collective-bargaining agreement to which the plan is subject. There have been no significant changes that affect the comparability of 2012, 2011 and 2010 contributions. Our portion of the contributions does not make up more than 5 percent of total contributions to the plan.

Pension Protection

FIP/RP Status

Expiration Date of

Act Zone Status

Pending/

MPC Contributions (In millions)

Surcharge

Collective - Bargaining

Pension Fund

EIN

2012

2011

Implemented

2012

2011

2010

Imposed

Agreement

Central States, Southeast and Southwest Areas Pension Plan (a)

36-6044243

Red

Red

Implemented

$

4

$

3

$

3

No

January 31, 2014

(a) This agreement has a minimum contribution requirement of $259 per week per employee for 2013. A total of 251 employees participated in the plan as of December 31, 2012.

Multiemployer Health and Welfare Plan

We contribute to one multiemployer health and welfare plan that covers both active employees and retirees. Through the health and welfare plan employees receive medical, dental, vision, prescription and disability coverage. Our contributions to this plan totaled $5 million, $4 million and $4 million for 2012, 2011 and 2010.

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Stock-Based Compensation Plans

12 Months Ended

Dec. 31, 2012

Stock-Based Compensation Plans

23. Stock-Based Compensation Plans

Description of the Plans

Prior to the 2011 Spinoff, our employees participated in the Marathon Oil Corporation 2007 Incentive Compensation Plan (the “2007 Plan”) and the Marathon Oil Corporation 2003 Incentive Compensation Plan (the “2003 Plan”) and received Marathon Oil restricted stock awards and options to purchase shares of Marathon Oil common stock. Effective June 30, 2011, our employees and non-employee directors became eligible to receive equity awards under the Marathon Petroleum Corporation 2011 Second Amended and Restated Incentive Compensation Plan (the “MPC 2011 Plan”). Effective April 26, 2012, our employees and non-employee directors became eligible to receive equity awards under the Marathon Petroleum Corporation 2012 Incentive Compensation Plan (the “MPC 2012 Plan”).

The MPC 2012 Plan authorizes the Compensation Committee of our board of directors (the “Committee”) to grant non-qualified or incentive stock options, stock appreciation rights, stock awards (including restricted stock and restricted stock unit awards), cash awards and performance awards to our employees, non-employee directors and other plan participants. Grants made during 2012 with a grant date prior to the effective date of the MPC 2012 Plan were made under the MPC 2011 Plan. Following the effective date of the MPC 2012 Plan, no new grants were allowed to be issued under the MPC 2011 Plan. Under the MPC 2012 Plan, no more than 25 million shares of our common stock may be delivered and no more than 10 million shares of our common stock may be the subject of awards that are not stock options or stock appreciation rights. In the sole discretion of the Committee, 10 million shares of our common stock may be granted as incentive stock options. Shares issued as a result of awards granted under these plans are funded through the issuance of new MPC common shares.

In connection with the Spinoff, stock compensation awards granted under the 2007 Plan and the 2003 Plan and held by grantees as of June 30, 2011 were adjusted or substituted as follows:

• Vested stock options were adjusted and substituted so that the grantee holds options to purchase both MPC and Marathon Oil common stock.

• Unvested stock option awards held by MPC employees were replaced with substitute awards of options to purchase shares of MPC common stock.

• The adjustment to the Marathon Oil and MPC stock options, when combined, was intended to generally preserve the intrinsic value of each option grant and the ratio of the exercise price to the fair market value of Marathon Oil common stock on June 30, 2011.

• Unvested restricted stock awards were replaced with adjusted, substitute awards for restricted shares or units, as applicable, of MPC common stock. The new awards of restricted stock were intended to generally preserve the intrinsic value of the award determined as of June 30, 2011.

• Vesting periods of awards were unaffected by the adjustment and substitution.

Awards granted in connection with the adjustment and substitution of awards originally issued under the 2007 Plan and the 2003 Plan are a part of the MPC 2011 Plan and reduce the maximum number of shares of MPC common stock available for delivery under the MPC 2011 Plan.

There were 393 MPC employees affected by the adjustment and substitution of awards. The adjustment and substitution of awards did not cause us to recognize incremental compensation expense.

Our wholly-owned subsidiary and the general partner of MPLX, MPLX GP LLC (“MXGP”), maintains a unit-based compensation plan for officers, directors and employees (including any other individual who may be considered an “employee” under a Registration Statement on Form S-8 or any successor form) of MXGP. The MPLX 2012 Incentive Compensation Plan (“MPLX Plan”) permits various types of equity awards including but not limited to grants of restricted units, phantom units and performance units. Awards granted during 2012 under the MPLX Plan will be settled with MPLX units.

Stock-based awards under the Plans

We expense all share-based payments to employees and non-employee directors based on the grant date fair value of the awards over the requisite service period, adjusted for estimated forfeitures.

Stock Options - We grant stock options to certain officer and non-officer employees and other plan participants. Stock options previously granted under the 2003 Plan and 2007 Plan remain held by employees, subject to the adjustment and substitution of awards described above. All of the stock options granted in 2012 fell under the MPC 2011 Plan. Stock options awarded under the MPC 2011 Plan and the MPC 2012 Plan represents the right to purchase shares of our common stock at its fair market value on the date of grant. Stock options have a maximum term of ten years from the date they are granted, and vest over a requisite service period of three years. We use the Black Scholes option-pricing model to estimate the fair value of stock options granted, which requires the input of subjective assumptions.

Stock Appreciation Rights (“SARs”) – Prior to 2005, SARs were granted under the 2003 Plan. No SARs have been granted under the 2007 Plan, the MPC 2011 Plan or the MPC 2012 Plan. Similar to stock options, SARs represent the right to receive a payment equal to the excess of the fair market value of shares of MPC or Marathon Oil common stock (in accordance with the adjustment and substitution of awards described above) on the date the right is exercised over the grant price. SARs have a maximum term of ten years from the date they are granted and generally vest over a requisite service period of three or four years. We use the Black Scholes option-pricing model to estimate the fair value of SARs granted, which requires the input of subjective assumptions.

Restricted Stock and Restricted Stock Units – We grant restricted stock and restricted stock units to employees, non-employee directors and other plan participants. Restricted stock and restricted stock units previously granted under the 2003 Plan and the 2007 Plan remain held by employees and non-employee directors, subject to the adjustment and substitution of awards described above. In general, restricted stock and restricted stock units granted to employees vest over a requisite service period of three years. Restricted stock and restricted stock unit awards granted in 2012 to officers are subject to an additional one year holding period after the completion of the three year requisite service period. Prior to vesting, all 2011 restricted stock recipients have the right to vote such stock and receive dividends at the same time regular shareholders are paid. The 2012 restricted stock recipients have the right to vote such stock; however, accrued dividends will only be paid upon vesting. Restricted stock units granted to non-employee directors are considered to vest immediately at the time of the grant, as they are non-forfeitable, but are not issued until the director’s departure from the board of directors. All restricted stock unit recipients do not have the right to vote such stock and receive dividend equivalents. The non-vested shares are not transferable and are held by our transfer agent. The fair values of restricted stock are based on the fair value of our common stock on the grant date.

Performance Units – We grant performance unit awards to certain officer employees. Current performance unit awards vest over a requisite service period of 18, 30 or 36 months. Performance units issued prior to 2012 are paid in cash at the end of the period at an amount per unit determined based on the total shareholder return of MPC common stock compared to the total shareholder return of selected peer companies’ stock over the vesting period. Performance units issued in 2012, under the MPC 2011 Plan, have a per unit payout determined based on the total shareholder return of MPC common stock compared to the total shareholder return of a selected combination of peer companies and index fund shareholder return over an average of four periods during the 36 month requisite service period. These performance units are designed to pay out 75 percent in cash and 25 percent in MPC common stock. The performance units paying out in cash are accounted for as liability awards and are recorded at fair value. The performance units settling in shares are accounted for as equity awards and have a grant date fair value of $1.09 per unit, as calculated using a Monte Carlo valuation model.

Total Stock-Based Compensation Expense

Total employee stock-based compensation expense was $35 million, $28 million and $16 million in 2012, 2011 and 2010, while the total related income tax benefits were $13 million, $11 million and $6 million, respectively. In 2012 and in 2011 for the period subsequent to the Spinoff, cash received by MPC upon exercise of stock option awards was $108 million and $1 million. In 2011 for periods prior to the Spinoff and 2010, cash received by Marathon Oil upon exercise of stock option awards by MPC employees was $17 million and $5 million. In 2012 and in 2011 for the period subsequent to the Spinoff, tax benefits realized by MPC for deductions for stock awards exercised were $16 million and less than $1 million. In 2011 for periods prior to the Spinoff and 2010, tax benefits realized by Marathon Oil for deductions for stock awards exercised by MPC employees were $7 million and $1 million.

Stock Option Awards

The Black Scholes option-pricing model values used to value stock option awards granted during 2012, 2011 and 2010 were determined based on the following weighted average assumptions (information for periods prior to the Spinoff was based on stock option awards for Marathon Oil common stock):

	2012		2011 subsequent to Spinoff		2011 prior to Spinoff		2010
Weighted average exercise price per share	$	42.02	$	36.18	$	51.93	$	30.12
Expected annual dividends per share	$	1.00	$	0.95	$	1.00	$	0.97
Expected life in years		5.8		5.8		5.3		5.1
Expected volatility		47%		48%		40%		41%
Risk-free interest rate		1.1%		1.4%		2.0%		2.2%
Weighted average grant date fair value of stock option awards granted	$	14.45	$	13.08	$	16.73	$	8.72

The expected life of stock options granted is based on historical data and represents the period of time that options granted are expected to be held prior to exercise. The assumption for expected volatility of our stock price reflects a weighting of 25 percent of our common stock implied volatility and 75 percent of the historical volatility for a selected group of peer companies. Expected annual dividends per share is estimated using the most recent dividend payment per share as of the grant date. The risk-free interest rate for periods within the expected life of the option is based on the U.S. Treasury yield curve in effect at the time of the grant.

The following is a summary of our common stock option activity in 2012:

	Number of     of Shares(a)		Weighted Average     Exercise Price		Weighted Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value     (In millions)
Outstanding at December 31, 2011		9,372,370	$	33.08
Granted		766,543		42.04
Exercised		(3,843,544)		29.71
Forfeited, canceled or expired		(123,175)		38.88
Outstanding at December 31, 2012		6,172,194		36.17
Vested and expected to vest at December 31, 2012		6,137,435		36.14		6.6	$	165
Exercisable at December 31, 2012		3,648,382		34.48		5.4		104

^(a)  Includes an immaterial number of stock appreciation rights.

The intrinsic value of options exercised by MPC employees during 2012 and in 2011 for periods subsequent to the Spinoff was $37 million and $1 million. The intrinsic value of options to purchase Marathon Oil common stock exercised by MPC employees under the 2007 Plan and 2003 Plan during 2011 for periods prior to the Spinoff and 2010 was $18 million and $2 million.

As of December 31, 2012, unrecognized compensation cost related to stock option awards was $12 million, which is expected to be recognized over a weighted average period of 0.9 years.

Restricted Stock Awards

The following is a summary of restricted stock award activity of our common stock in 2012:

	Shares of Restricted Stock (“RS”)				Restricted Stock Units (“RSU”)
	Number of Shares		Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2011		348,691	$	34.36		319,944	$	29.43
Granted		416,495		43.11		39,462		44.38
RS’s Vested/RSU’s Issued		(115,441)		29.63		(179)		34.02
Forfeited		(11,672)		39.54		(116)		43.44
Outstanding at December 31, 2012		638,073		40.83		359,111		31.07

Of the 359,111 restricted units outstanding, 357,990 are vested and have a weighted average grant date fair value of $31.04. These vested but unissued units are held by our non-employee directors, are non-forfeitable and are issuable upon the director’s departure from our board of directors.

The following is a summary of the values related to restricted stock and restricted stock unit awards held by MPC employees and non-employee directors (information for periods prior to the Spinoff is for restricted stock and restricted stock unit awards of Marathon Oil common stock):

	Restricted Stock				Restricted Stock Units
	Intrinsic Value of Awards Vesting During the Period (In millions)		Weighted Average Grant Date Fair Value of Awards Granted During the Period		Intrinsic Value of Awards Issued During the Period (In millions)		Weighted Average Grant Date Fair Value of Awards Granted During the Period
2012	$	5	$	43.11	$	-	$	44.38
2011 - Subsequent to the Spinoff		1		41.54		-		33.78
2011 - Prior to the Spinoff		3		48.53		-		45.22
2010		3		30.55		-		32.18

As of December 31, 2012, unrecognized compensation cost related to restricted stock awards was $18 million, which is expected to be recognized over a weighted average period of 1.1 years. There was no material unrecognized compensation cost related to restricted stock unit awards.

Performance Unit Awards

The following table presents a summary of the 2012 activity for performance unit awards to be settled in shares:

	Number of Units
Outstanding at December 31, 2011		-
Granted		2,040,000
Settled		-
Canceled		-
Outstanding at December 31, 2012		2,040,000

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Consolidated Statements of Stockholders' Equity / Net Investment (USD $) In Millions	Total	Common Stock [Member]	Treasury Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Net Investment [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Noncontrolling Interests [Member]
Balance at Dec. 31, 2009	$ 9,172					$ 9,692	$ (520)
Net income	623					623
Distributions to Marathon Oil	(1,448)					(1,448)
Other comprehensive income (loss)	(103)						(103)
Balance at Dec. 31, 2010	8,244					8,867	(623)
Balance (in shares) at Dec. 31, 2010
Net income	2,389				1,058	1,331
Dividends paid	(160)				(160)
Distributions to Marathon Oil	(737)					(726)	(11)
Other comprehensive income (loss)	(245)						(245)
Shares issued (returned) - stock based compensation	9			9
Stock-based compensation	5			5
Reclassification of net investment to additional paid-in capital				9,472		(9,472)
Issuance of common stock at spinoff		4		(4)
Shares issued - stock-based compensation (in shares)		1
Issuance of common stock at spinoff (in shares)		356
Balance at Dec. 31, 2011	9,505	4		9,482	898		(879)
Balance (in shares) at Dec. 31, 2011		357
Shares repurchased (in shares)			(28)
Net income	3,393				3,389			4
Dividends paid	(407)				(407)
Other comprehensive income (loss)	415						415
Shares repurchased	(1,350)		(1,250)	(100)
Shares issued (returned) - stock based compensation	105		(3)	108
Stock-based compensation	46			46
Issuance of MPLX LP common units	407							407
Other	(9)			(9)
Shares issued - stock-based compensation (in shares)		4
Balance at Dec. 31, 2012	$ 12,105	$ 4	$ (1,253)	$ 9,527	$ 3,880		$ (464)	$ 411
Balance (in shares) at Dec. 31, 2012		361	(28)

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Leases

12 Months Ended

Dec. 31, 2012

Leases

24. Leases

We lease a wide variety of facilities and equipment under operating leases, including land and building space, office equipment, storage facilities and transportation equipment. Most long-term leases include renewal options and, in certain leases, purchase options. Future minimum commitments as of December 31, 2012, for capital lease obligations and for operating lease obligations having initial or remaining non-cancelable lease terms in excess of one year are as follows:

(In millions)	Capital Lease Obligations		Operating Lease Obligations
2013	$	44	$	151
2014		44		137
2015		45		117
2016		44		80
2017		43		49
Later years		326		78
Total minimum lease payments		546	$	612
Less imputed interest costs		(191)
Present value of net minimum lease payments	$	355

Operating lease rental expense was:

(In millions)	2012		2011		2010
Minimum rental	$	139	$	123	$	135
Contingent rental		-		1		1
Rental expense	$	139	$	124	$	136

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Income Taxes (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Tax Disclosure [Line Items]
Federal statutory income tax rate	35.00%	35.00%	35.00%
Unrecognized tax benefits that would impact effective income tax rate	$ 20
Uncertain tax positions, reasonably possible increase or decrease during the next twelve months	29
Interest and penalties net expenses	1	5	1
Interest and penalties accrued	$ 9	$ 11

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Defined Benefit Pension And Other Postretirement Plans (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Accumulated benefit obligation	$ 2,035		$ 1,948
Defined benefit plan investment goals	The overall expected long-term return on plan assets assumption 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 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.
Defined benefit plan diversification	Investments are diversified by industry and type, limited by grade and maturity
Defined benefit plan derivative use	Limited derivative investments are allowable subject to strict guidelines, such that derivatives may only be written against equity securities in the portfolio
Plan investment policies and strategies	Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies
Contributions to defined contribution plans	60		60		54
Equity Securities [Member]
Targeted asset allocation	75.00%
Fixed Income Securities [Member]
Targeted asset allocation	25.00%
Funded Pension Plans [Member]
Expected contributions to defined benefit plans	160
Unfunded Pension Plans [Member]
Expected contributions to defined benefit plans	18
Unfunded Postretirement Plans [Member]
Expected contributions to defined benefit plans	21
Multiemployer Plans, Pension [Member]
The Company's contributions to multiemployer plans	4	[1]	3	[1]	3	[1]
Pension Benefits [Member]
Decrease in benefit liabilities	537
Increase in retiree medical liabilities resulting from a reduction in discount rates	(117)		(384)
Estimated prior service cost that will be amortized from accumulated other comprehensive loss in 2013	89
Estimated net gain (loss) that will be amortized from accumulated other comprehensive loss in 2013	45
Health Plan [Member]
Decrease in benefit liabilities	40
Increase in retiree medical liabilities resulting from a reduction in discount rates	57
Health Plan [Member] | Maximum [Member]
Maximum increase in tax-free contributions to health reimbursement account (in percentage)	4.00%
Other Benefits [Member]
Increase in retiree medical liabilities resulting from a reduction in discount rates	(53)		(39)
Estimated prior service cost that will be amortized from accumulated other comprehensive loss in 2013	4
Estimated net gain (loss) that will be amortized from accumulated other comprehensive loss in 2013	4
Other Pension Plans [Member] | Multiemployer Plans, Pension [Member]
Number of multiemployer defined benefit pension or health and welfare plan	1
Multi employer pension plans	There have been no significant changes that affect the comparability of 2012, 2011 and 2010 contributions.
Other Pension Plans [Member] | Multiemployer Plans, Pension [Member] | Maximum [Member]
Funded percentage of plans in red zone	65.00%
Marathon Petroleum's contributions as a percentage of total contributions to the multi-employer pension plan, maximum	5.00%
Health Plans [Member] | Multiemployer Health And Welfare Plan [Member]
Number of multiemployer defined benefit pension or health and welfare plan	1
The Company's contributions to multiemployer plans	$ 5		$ 4		$ 4

[1] This agreement has a minimum contribution requirement of $259 per week per employee for 2013. A total of 251 employees participated in the plan as of December 31, 2012.

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Income per Common Share (Tables)

12 Months Ended

Dec. 31, 2012

Summary Of Earnings Per Common Share

(In millions, except per share data)	2012		2011		2010
Basic earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	3,389	$	2,389	$	623
Income allocated to participating securities		6		4		1
Income available to common stockholders - basic	$	3,383	$	2,385	$	622
Weighted average common shares outstanding		340		356		356
Basic earnings per share	$	9.95	$	6.70	$	1.75
Diluted earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	3,389	$	2,389	$	623
Income allocated to participating securities		6		4		1
Income available to common stockholders - diluted	$	3,383	$	2,385	$	622
Weighted average common shares outstanding		340		356		356
Effect of dilutive securities		2		1		2
Weighted average common shares, including dilutive effect		342		357		358
Diluted earnings per share	$	9.89	$	6.67	$	1.74

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Stock-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2012

Weighted Average Assumptions Used To Value Stock Options Awards

The Black Scholes option-pricing model values used to value stock option awards granted during 2012, 2011 and 2010 were determined based on the following weighted average assumptions (information for periods prior to the Spinoff was based on stock option awards for Marathon Oil common stock):

	2012		2011 subsequent to Spinoff		2011 prior to Spinoff		2010
Weighted average exercise price per share	$	42.02	$	36.18	$	51.93	$	30.12
Expected annual dividends per share	$	1.00	$	0.95	$	1.00	$	0.97
Expected life in years		5.8		5.8		5.3		5.1
Expected volatility		47%		48%		40%		41%
Risk-free interest rate		1.1%		1.4%		2.0%		2.2%
Weighted average grant date fair value of stock option awards granted	$	14.45	$	13.08	$	16.73	$	8.72

Schedule Of Share-Based Compensation MPC Equity Based Stock Option Activity

The following is a summary of our common stock option activity in 2012:

	Number of     of Shares(a)		Weighted Average     Exercise Price		Weighted Average Remaining Contractual Term (in years)		Aggregate Intrinsic Value     (In millions)
Outstanding at December 31, 2011		9,372,370	$	33.08
Granted		766,543		42.04
Exercised		(3,843,544)		29.71
Forfeited, canceled or expired		(123,175)		38.88
Outstanding at December 31, 2012		6,172,194		36.17
Vested and expected to vest at December 31, 2012		6,137,435		36.14		6.6	$	165
Exercisable at December 31, 2012		3,648,382		34.48		5.4		104

^(a)  Includes an immaterial number of stock appreciation rights.

Summary Of Restricted Stock Award Activity

The following is a summary of restricted stock award activity of our common stock in 2012:

	Shares of Restricted Stock (“RS”)				Restricted Stock Units (“RSU”)
	Number of Shares		Weighted Average Grant Date Fair Value		Number of Units		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2011		348,691	$	34.36		319,944	$	29.43
Granted		416,495		43.11		39,462		44.38
RS’s Vested/RSU’s Issued		(115,441)		29.63		(179)		34.02
Forfeited		(11,672)		39.54		(116)		43.44
Outstanding at December 31, 2012		638,073		40.83		359,111		31.07

Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity, Vested And Unvested

The following is a summary of the values related to restricted stock and restricted stock unit awards held by MPC employees and non-employee directors (information for periods prior to the Spinoff is for restricted stock and restricted stock unit awards of Marathon Oil common stock):

	Restricted Stock				Restricted Stock Units
	Intrinsic Value of Awards Vesting During the Period (In millions)		Weighted Average Grant Date Fair Value of Awards Granted During the Period		Intrinsic Value of Awards Issued During the Period (In millions)		Weighted Average Grant Date Fair Value of Awards Granted During the Period
2012	$	5	$	43.11	$	-	$	44.38
2011 - Subsequent to the Spinoff		1		41.54		-		33.78
2011 - Prior to the Spinoff		3		48.53		-		45.22
2010		3		30.55		-		32.18

Schedule Of Performance Unit Awards

The following table presents a summary of the 2012 activity for performance unit awards to be settled in shares:

	Number of Units
Outstanding at December 31, 2011		-
Granted		2,040,000
Settled		-
Canceled		-
Outstanding at December 31, 2012		2,040,000

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Income Per Common Share (Summary Of Earnings Per Common Share) (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended																12 Months Ended
	Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2011		Sep. 30, 2011		Jun. 30, 2011		Mar. 31, 2011		Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Earnings Per Share Basic And Diluted [Line Items]
Net income attributable to MPC	$ 755		$ 1,224		$ 814		$ 596		$ (75)		$ 1,133		$ 802		$ 529		$ 3,389	$ 2,389	$ 623
Weighted average common shares outstanding (in shares)																	340	356	356
Basic earnings per share (in USD per share)	$ 2.26	[1]	$ 3.61	[1]	$ 2.39	[1]	$ 1.71	[1]	$ (0.21)	[1]	$ 3.18	[1]	$ 2.25	[1]	$ 1.49	[1]	$ 9.95	$ 6.70	$ 1.75
Weighted average common shares, including dilutive effect																	342	357	358
Diluted earnings per share (in USD per share)	$ 2.24	[1]	$ 3.59	[1]	$ 2.38	[1]	$ 1.70	[1]	$ (0.21)	[1]	$ 3.16	[1]	$ 2.24	[1]	$ 1.48	[1]	$ 9.89	$ 6.67	$ 1.74
Basic [Member]
Earnings Per Share Basic And Diluted [Line Items]
Net income attributable to MPC																	3,389	2,389	623
Income allocated to participating securities																	6	4	1
Income available to common stockholders - basic																	3,383	2,385	622
Weighted average common shares outstanding (in shares)																	340	356	356
Basic earnings per share (in USD per share)																	$ 9.95	$ 6.70	$ 1.75
Diluted [Member]
Earnings Per Share Basic And Diluted [Line Items]
Net income attributable to MPC																	3,389	2,389	623
Income allocated to participating securities																	6	4	1
Income available to common stockholders - diluted																	$ 3,383	$ 2,385	$ 622
Weighted average common shares outstanding (in shares)																	340	356	356
Effect of dilutive securities (in shares)																	2	1	2
Weighted average common shares, including dilutive effect																	342	357	358
Diluted earnings per share (in USD per share)																	$ 9.89	$ 6.67	$ 1.74

[1] For comparative purposes, and to provide a more meaningful calculation for weighted average shares, we assumed the shares distributed to Marathon Oil stockholders in conjunction with the Spinoff were outstanding as of the beginning of each period prior to the Spinoff.

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Consolidated Statements of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$ 82,235	$ 78,583	$ 62,387
Sales to related parties	8	55	100
Income from equity method investments	26	50	70
Net gain on disposal of assets	177	12	11
Other income	46	59	37
Total revenues and other income	82,492	78,759	62,605
Costs and expenses:
Cost of revenues (excludes items below)	68,668	65,795	51,731
Purchases from related parties	280	1,916	2,593
Consumer excise taxes	5,709	5,114	5,208
Depreciation and amortization	995	891	941
Selling, general and administrative expenses	1,223	1,059	874
Other taxes	270	239	247
Total costs and expenses	77,145	75,014	61,594
Income from operations	5,347	3,745	1,011
Related party net interest and other financial income	1	35	24
Net interest and other financial income (costs)	(110)	(61)	(12)
Income before income taxes	5,238	3,719	1,023
Provision for income taxes	1,845	1,330	400
Net income	3,393	2,389	623
Less net income attributable to noncontrolling interests	4
Net income attributable to MPC	$ 3,389	$ 2,389	$ 623
Basic
Net income attributable to MPC per share (in USD per share)	$ 9.95	$ 6.70	$ 1.75
Weighted average shares outstanding (in shares)	340	356	356
Diluted:
Net income attributable to MPC per share (in USD per share)	$ 9.89	$ 6.67	$ 1.74
Weighted average shares outstanding (in shares)	342	357	358
Dividends paid (in USD per share)	$ 1.20	$ 0.45

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Equity Method Investments (Tables)

12 Months Ended

Dec. 31, 2012

Schedule Of Equity Method Investments

	Ownership as of December 31, 2012			December 31,
(In millions)				2012		2011
Centennial		50	%	$	27	$	17
LOCAP LLC		59	%		26		25
LOOP		51	%		198		181
TACE		36	%		29		35
TAME		50	%		27		32
Other					14		12
Total				$	321	$	302

Summarized Financial Information For Equity Method Investees

(In millions)	2012		2011		2010
Income statement data:
Revenues and other income	$	1,025	$	1,043	$	939
Income from operations		73		128		196
Net income		47		101		170
Balance sheet data - December 31:
Current assets	$	217	$	256
Noncurrent assets		1,163		1,175
Current liabilities		161		126
Noncurrent liabilities		636		690

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Goodwill (Narrative) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Goodwill [Line Items]
Amount of required impairment	$ 0	$ 0

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Select Quarterly Financial Data (Schedule Of Quarterly Financial Information) (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended																12 Months Ended
	Dec. 31, 2012		Sep. 30, 2012		Jun. 30, 2012		Mar. 31, 2012		Dec. 31, 2011		Sep. 30, 2011		Jun. 30, 2011		Mar. 31, 2011		Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Quarterly Financial Data [Line Items]
Revenues	$ 20,686		$ 21,049		$ 20,243		$ 20,265		$ 19,420		$ 20,616		$ 20,760		$ 17,842
Income (loss) from operations	1,189		1,895		1,307		956		(158)		1,759		1,325		819
Net income (loss)	759		1,224		814		596		(75)		1,133		802		529		3,393	2,389	623
Net income (loss) attributable to MPC	$ 755		$ 1,224		$ 814		$ 596		$ (75)		$ 1,133		$ 802		$ 529		$ 3,389	$ 2,389	$ 623
Net income (loss) attributable to MPC per share, Basic (in USD per share)	$ 2.26	[1]	$ 3.61	[1]	$ 2.39	[1]	$ 1.71	[1]	$ (0.21)	[1]	$ 3.18	[1]	$ 2.25	[1]	$ 1.49	[1]	$ 9.95	$ 6.70	$ 1.75
Net income (loss) attributable to MPC per share, Diluted (in USD per share)	$ 2.24	[1]	$ 3.59	[1]	$ 2.38	[1]	$ 1.70	[1]	$ (0.21)	[1]	$ 3.16	[1]	$ 2.24	[1]	$ 1.48	[1]	$ 9.89	$ 6.67	$ 1.74
Dividends paid per share (in USD per share)	$ 0.35		$ 0.35		$ 0.25		$ 0.25		$ 0.25		$ 0.20		$ 0.00		$ 0.00		$ 1.20	$ 0.45

[1] For comparative purposes, and to provide a more meaningful calculation for weighted average shares, we assumed the shares distributed to Marathon Oil stockholders in conjunction with the Spinoff were outstanding as of the beginning of each period prior to the Spinoff.

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Supplemental Cash Flow Information (Reconciliation Of Contributions From (Distributions To) Marathon Oil) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Supplemental Cash Flow Information [Line Items]
Distributions to Marathon Oil per consolidated statements of cash flows		$ (783)	$ (1,330)
Non-cash contributions from (distributions to) Marathon Oil		57	(118)
Distributions to Marathon Oil per consolidated statements of equity / net investment		$ (726)	$ (1,448)

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Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Receivables, allowance for doubtful accounts	$ 10	$ 3
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Preferred stock, par value (in USD per share)	$ 0.01	$ 0.01
Preferred stock, shares authorized	30,000,000	30,000,000
Common stock, shares issued	361,000,000	357,000,000
Common stock, par value (in USD per share)	$ 0.01	$ 0.01
Common stock, shares authorized	1,000,000,000	1,000,000,000
Treasury stock, shares	28,000,000

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Property, Plant And Equipment (Summary Of Property, Plant And Equipment) (Detail) (USD $) In Millions, unless otherwise specified			12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended				12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2012 Minimum [Member]	Dec. 31, 2012 Maximum [Member]	Dec. 31, 2012 Refining & Marketing [Member]	Dec. 31, 2011 Refining & Marketing [Member]	Dec. 31, 2012 Refining & Marketing [Member] Minimum [Member]	Dec. 31, 2012 Refining & Marketing [Member] Maximum [Member]	Dec. 31, 2012 Speedway [Member]	Dec. 31, 2011 Speedway [Member]	Dec. 31, 2012 Speedway [Member] Minimum [Member]	Dec. 31, 2012 Speedway [Member] Maximum [Member]	Dec. 31, 2012 Pipeline Transportation [Member]	Dec. 31, 2011 Pipeline Transportation [Member]	Dec. 31, 2012 Pipeline Transportation [Member] Minimum [Member]	Dec. 31, 2012 Pipeline Transportation [Member] Maximum [Member]	Dec. 31, 2012 Corporate And Other [Member]	Dec. 31, 2011 Corporate And Other [Member]	Dec. 31, 2012 Corporate And Other [Member] Minimum [Member]	Dec. 31, 2012 Corporate And Other [Member] Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment,Estimated Useful Lives			4 years	42 years			4 years	25 years			4 years	15 years			16 years	42 years			4 years	40 years
Total	$ 19,409	$ 18,073			$ 15,089	$ 14,221			$ 2,100	$ 1,887			$ 1,747	$ 1,593			$ 473	$ 372
Less accumulated depreciation	6,766	5,845
Net property, plant and equipment	$ 12,643	$ 12,228

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MPLX LP (Narrative) (Detail) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended	1 Months Ended				1 Months Ended		10 Months Ended		1 Months Ended		12 Months Ended				12 Months Ended			12 Months Ended
	Dec. 31, 2012	Oct. 31, 2012 MPLX LP [Member]	Oct. 31, 2012 MPLX LP [Member] Pipe Line Holdings [Member]	Dec. 31, 2012 MPLX LP [Member] General Partner and Limited Partner [Member]	Oct. 31, 2012 MPLX LP [Member] Operating Agreements [Member] Agreement	Oct. 31, 2012 MPLX LP [Member] Operating Agreements [Member] Minimum [Member]	Oct. 31, 2012 MPLX LP [Member] Operating Agreements [Member] Maximum [Member]	Oct. 31, 2012 MPLX LP [Member] Management Services Agreements [Member] Agreement	Oct. 31, 2012 MPLX LP [Member] Employee Services Agreements [Member] Agreement	Oct. 31, 2012 MPLX LP [Member] IPO [Member]	Oct. 31, 2012 MPLX LP [Member] IPO [Member] Underwriters [Member]	Dec. 31, 2012 MPLX LP [Member] Crude Oil [Member] Commercial Agreements [Member] 10-Year Transportation Services Agreement [Member] Agreement	Dec. 31, 2012 MPLX LP [Member] Crude Oil [Member] Commercial Agreements [Member] 5-Year Transportation Services Agreement [Member] Agreement	Dec. 31, 2012 MPLX LP [Member] Product pipeline systems [Member] Commercial Agreements [Member] 10-Year Transportation Services Agreement [Member] Agreement	Dec. 31, 2012 MPLX LP [Member] Handling Crude Oil [Member] Commercial Agreements [Member]	Dec. 31, 2012 MPLX LP [Member] Handling Crude Oil [Member] Commercial Agreements [Member] 5-Year Transportation Services Agreement [Member] Agreement	Dec. 31, 2012 MPLX LP [Member] Storage Services [Member] Commercial Agreements [Member] 10-Year Transportation Services Agreement [Member] Agreement	Dec. 31, 2012 MPLX LP [Member] Storage Services Tank Farm [Member] Commercial Agreements [Member]	Dec. 31, 2012 MPLX LP [Member] Storage Services Tank Farm [Member] Commercial Agreements [Member] 10-Year Transportation Services Agreement [Member] Agreement	Dec. 31, 2012 MPLX LP [Member] Crude Oil And Product Pipeline [Member] Commercial Agreements [Member]	Dec. 31, 2012 MPLX LP [Member] Noncontrolling Interests [Member]	Oct. 31, 2012 MPLX LP [Member] Midwest And Gulf Coast [Member]	Oct. 31, 2012 MPLX LP [Member] West Virginia [Member]	Dec. 31, 2012 MPLX LP [Member] General Partner and Limited Partner [Member]
Business Acquisition Actual Revenue And Pre Tax Income Loss [Line Items]
MPLX's partnership percent indirect interest in assets																						51.00%	100.00%
Initial public offering of common units (in number of common units)										19,895,000	2,595,000
Initial public offering date of MPLX LP		October 31, 2012
Price of common unit (in USD per common unit)		$ 22.00
Net proceeds to MPLX from the sale of the units	$ 407	$ 407
Offering costs		31
Contribution made by MPLX to Pipe Line Holdings		192	192
Net proceeds distributed by MPLX to MPC		203
MPC's partnership interest in MPLX (in percentage)				73.60%																				73.60%
Public ownership interest percentage in MPLX																					26.40%
Duration of Agreements (in years)						1 year	5 years					10 years	5 years	10 years		5 years	10 years		3 years
Number of Agreements					1			2	2			3	1	4		1	1		4
Description of agreement, renewal terms															Renew for up to four additional two-year terms unless terminated by either party			Automatically renew for additional one-year terms unless terminated by either party		Renew for up to two additional five-year terms unless terminated by either party
Fee for management services provided								$ 0.7

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Fair Value Measurements (Reconciliation Of Net Beginning And Ending Balances Recorded For Net Assets And Liabilities Classified As Level 3) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011		Dec. 31, 2010
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Beginning balance		$ 2,402		$ 865
Total realized and unrealized losses included in net income	(2)			(1)
Purchases of PFD Preferred Stock		10,326	[1]	9,709	[1]
Redemptions of PFD Preferred Stock		(12,730)	[1]	(8,019)	[1]
Settlements of derivative instruments	2	2		(2)
Distributions to Marathon Oil				(150)	[2]
Ending balance				$ 2,402

[1] For information on PFD Preferred Stock, see Note 5. The fair value of our PFD Preferred Stock investment was measured using an income approach since the securities were not publicly traded; therefore, they were classified as Level 3 in the fair value hierarchy.

[2] Due to the January 1, 2010 merger of two non-operating RM&T Business legal entities into Marathon Oil.

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Selected Quarterly Financial Data

12 Months Ended

Dec. 31, 2012

Selected Quarterly Financial Data

Selected Quarterly Financial Data (Unaudited)

	2012								2011
(In millions, except per share data)	1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.		1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.
Revenues	$	20,265	$	20,243	$	21,049	$	20,686	$	17,842	$	20,760	$	20,616	$	19,420
Income (loss) from operations		956		1,307		1,895		1,189		819		1,325		1,759		(158)
Net income (loss)		596		814		1,224		759		529		802		1,133		(75)
Net income (loss) attributable to MPC		596		814		1,224		755		529		802		1,133		(75)
Net income (loss) attributable to MPC per share:(a)
Basic	$	1.71	$	2.39	$	3.61	$	2.26	$	1.49	$	2.25	$	3.18	$	(0.21)
Diluted		1.70		2.38		3.59		2.24		1.48		2.24		3.16		(0.21)
Dividends paid per share		0.25		0.25		0.35		0.35		-		-		0.20		0.25

(a) For comparative purposes, and to provide a more meaningful calculation for weighted average shares, we assumed the shares distributed to Marathon Oil stockholders in conjunction with the Spinoff were outstanding as of the beginning of each period prior to the Spinoff.

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Leases (Schedule Of Future Minimum Commitments) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Operating Leased Assets [Line Items]
Capital Lease Obligations, 2013	$ 44
Capital Lease Obligations, 2014	44
Capital Lease Obligations, 2015	45
Capital Lease Obligations, 2016	44
Capital Lease Obligations, 2017	43
Capital Lease Obligations, Later years	326
Total minimum capital lease payments	546
Less imputed interest costs	(191)
Present value of net minimum lease payments	355
Operating Lease Obligations, 2013	151
Operating Lease Obligations, 2014	137
Operating Lease Obligations, 2015	117
Operating Lease Obligations, 2016	80
Operating Lease Obligations, 2017	49
Operating Lease Obligations, Later years	78
Total minimum operating lease payments	$ 612

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Related Party Transactions (Receivables From Related Parties) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Current receivables from related parties	$ 2	$ 2
Centennial [Member]
Related Party Transaction [Line Items]
Current receivables from related parties	2	1
Other Equity Method Investees [Member]
Related Party Transaction [Line Items]
Current receivables from related parties		$ 1

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Inventories

12 Months Ended

Dec. 31, 2012

Inventories

14. Inventories

	December 31,
(In millions)	2012		2011
Crude oil and refinery feedstocks	$	1,383	$	1,339
Refined products		1,761		1,725
Merchandise		74		65
Supplies and sundry items		231		191
Total (at cost)	$	3,449	$	3,320

The LIFO method accounted for 93 percent and 94 percent of total inventory value at December 31, 2012 and 2011, respectively. Current acquisition costs were estimated to exceed the LIFO inventory value at December 31, 2012 and 2011 by $4,511 million and $5,015 million, respectively. There was no liquidation of LIFO inventories in 2012. Cost of revenues decreased and income from operations increased by $4 million in both 2011 and 2010 as a result of liquidations of LIFO inventories, excluding inventories liquidated in dispositions.

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Supplementary Statistics

12 Months Ended

Dec. 31, 2012

Supplementary Statistics

Supplementary Statistics (Unaudited)

(In millions)	2012		2011		2010
Income from Operations by segment
Refining & Marketing	$	5,098	$	3,591	$	800
Speedway		310		271		293
Pipeline Transportation(a)		216		199		183
Items not allocated to segments:
Corporate and other unallocated items(a)		(336)		(316)		(236)
Minnesota Assets sale settlement gain		183		-		-
Pension settlement expenses(a)		(124)		-		-
Impairment		-		-		(29)
Income from operations	$	5,347	$	3,745	$	1,011
Capital Expenditures and Investments(b)
Refining & Marketing	$	705	$	900	$	961
Speedway(c)		340		164		84
Pipeline Transportation		211		121		24
Corporate and Other(d)		204		138		104
Total	$	1,460	$	1,323	$	1,173

^(a)  Included in the Pipeline Transportation segment are $4 million of corporate overhead costs and pension settlement expenses attributable to MPLX subsequent to MPLX’s October 31, 2012 initial public offering, which were included in items not allocated to segments prior to MPLX’s initial public offering. These expenses are not currently allocated to other segments.

^(b) Capital expenditures include changes in capital accruals.

^(c) Includes acquisitions of 97 convenience stores in 2012 and 23 convenience stores in 2011.

^(d)  Includes capitalized interest of $101 million, $114 million and $103 million for 2012, 2011 and 2010.

Supplementary Statistics (Unaudited)

	2012		2011		2010
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)(a)		1,618		1,599		1,585
Refining & Marketing Operating Statistics
Refinery Throughputs (thousands of barrels per day):
Crude oil refined		1,195		1,177		1,173
Other charge and blendstocks		168		181		162
Total		1,363		1,358		1,335
Crude Oil Capacity Utilization percent(b)		100		103		99
Refined Product Yields (thousands of barrels per day):
Gasoline		738		739		726
Distillates		433		433		409
Propane		26		25		24
Feedstocks and special products		109		109		97
Heavy fuel oil		18		21		24
Asphalt		62		56		76
Total		1,386		1,383		1,356
Refining & Marketing Refined Product Sales Volume (thousands of barrels per day)(c)		1,599		1,581		1,573
Refining & Marketing Gross Margin (dollars per barrel)(d)	$	10.45	$	7.75	$	2.81
Direct Operating Costs in Refining & Marketing Gross Margin (dollars per barrel):(e)
Planned turnaround and major maintenance	$	1.00	$	0.78	$	1.19
Depreciation and amortization		1.44		1.29		1.32
Other manufacturing(f)		3.15		3.16		3.32
Total	$	5.59	$	5.23	$	5.83
Speedway Operating Statistics
Convenience stores at period-end		1,464		1,371		1,358
Gasoline & distillates sales (millions of gallons)		3,027		2,938		3,300
Gasoline & distillates gross margin (dollars per gallon)(g)	$	0.1318	$	0.1308	$	0.1207
Merchandise sales (in millions)	$	3,058	$	2,924	$	3,195
Merchandise gross margin (in millions)	$	795	$	719	$	789
Same store gasoline sales volume (period over period)		-0.8%		-1.7%		3.0%
Same store merchandise sales (period over period)		0.9%		1.1%		4.4%
Same store merchandise sales excluding cigarettes (period over period)		7.0%		6.7%		6.2%
Pipeline Transportation Operating Statistics
Pipeline throughput (thousands of barrels per day)(h):
Crude oil pipelines		1,190		1,184		1,204
Refined products pipelines		980		1,031		968
Total		2,170		2,215		2,172

^(a)  Total average daily volumes of refined product sales to wholesale, branded and retail (Speedway segment) customers.

^(b)  Based on calendar day capacity, which is an annual average that includes downtime for planned maintenance and other normal operating activities.

^(c)  Includes intersegment sales.

^(d)  Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation and amortization, divided by Refining & Marketing segment refined product sales volume.

^(e)  Per barrel of total refinery throughputs.

^(f)  Includes utilities, labor, routine maintenance and other operating costs.

^(g)  The price paid by consumers less the cost of refined products, including transportation, consumer excise taxes and bankcard processing fees, divided by gasoline and distillates sales volume.

^(h)  On owned common-carrier pipelines, excluding equity method investments.

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Fair Value Measurements (Assets And Liabilities Accounted For At Fair Value On Recurring Basis) (Detail) (Fair Value, Measurements, Recurring [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other assets	$ 2	$ 2
Total assets at fair value	135	155
Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	133	134
Commodity derivative instruments, liabilities	(88)	(46)
Interest Rate Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets		19
Level 1 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other assets	2	2
Total assets at fair value	51	28
Level 1 [Member] | Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	49	26
Commodity derivative instruments, liabilities	(88)	(45)
Level 1 [Member] | Interest Rate Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets
Level 2 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other assets
Total assets at fair value		20
Level 2 [Member] | Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets		1
Commodity derivative instruments, liabilities		(1)
Level 2 [Member] | Interest Rate Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets		19
Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other assets
Total assets at fair value
Level 3 [Member] | Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets
Commodity derivative instruments, liabilities
Level 3 [Member] | Interest Rate Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets
Collateral [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other assets
Total assets at fair value	84	107
Collateral [Member] | Commodity Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets	84	107
Commodity derivative instruments, liabilities
Collateral [Member] | Interest Rate Derivatives [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Derivative instruments, assets

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Defined Benefit Pension And Other Postretirement Plans (Estimated Future Benefit Payments) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012
Pension Benefits [Member]
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2013	$ 208
2014	206
2015	201
2016	197
2017	195
2018 through 2022	871
Other Benefits [Member]
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2013	21	[1]
2014	23	[1]
2015	26	[1]
2016	28	[1]
2017	30	[1]
2018 through 2022	$ 179	[1]

[1] Effective 2013, as a result of the PPACA, future Medicare reimbursements will no longer be tax deductible and must be used to reduce the costs of providing Medicare part D equivalent prescription drug benefits to retirees.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2012

Property, Plant and Equipment

16. Property, Plant and Equipment

(In millions)	Estimated   Useful  Lives		December 31,
			2012		2011
Refining & Marketing		4 - 25 years	$	15,089	$	14,221
Speedway		4 - 15 years		2,100		1,887
Pipeline Transportation		16 -42 years		1,747		1,593
Corporate and Other		4 - 40 years		473		372
Total				19,409		18,073
Less accumulated depreciation				6,766		5,845
Net property, plant and equipment			$	12,643	$	12,228

Property, plant and equipment includes gross assets acquired under capital leases of $417 million and $267 million at December 31, 2012 and 2011, with related amounts in accumulated depreciation of $79 million and $61 million at December 31, 2012 and 2011. Property, plant and equipment includes construction in progress of $520 million and $2,581 million at December 31, 2012 and 2011, which primarily relates to refinery projects.

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Acquisitions (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	1 Months Ended
	May 31, 2011 Store	May 31, 2012 Gas America Services Inc [Member] Store Parcels	Jul. 31, 2012 Road Ranger Llc [Member] Store
Business Acquisition [Line Items]
Number of convenience stores acquired	23	87	10
Acquisition of goodwill	$ 9	$ 83	$ 5
Number of undeveloped real estate parcels acquired for future development		2

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Debt (Outstanding Borrowings) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011
Debt Instrument [Line Items]
Total	$ 3,355		$ 3,299
Unamortized discount	(10)		(11)
Fair value adjustments	16	[1]	19	[1]
Amounts due within one year	(19)		(15)
Total long-term debt due after one year	3,342		3,292
Revolving Credit Agreement Due 2017 [Member]
Debt Instrument [Line Items]
Borrowings outstanding at period end
Line of credit facility, expiration date	Sep. 14, 2017
MPLX Operations LLC [Member] | Revolving Credit Agreement Due 2017 [Member]
Debt Instrument [Line Items]
Borrowings outstanding at period end
Line of credit facility, expiration date	Oct. 31, 2017
Senior Notes [Member] | 3.500% Senior Notes Due March 1, 2016 [Member]
Debt Instrument [Line Items]
Senior notes	750		750
Debt instrument, interest rate	3.50%
Debt instrument, maturity date	Mar. 01, 2016
Senior Notes [Member] | 5.125% Senior Notes Due March 1, 2021 [Member]
Debt Instrument [Line Items]
Senior notes	1,000		1,000
Debt instrument, interest rate	5.125%
Debt instrument, maturity date	Mar. 01, 2021
Senior Notes [Member] | 6.500% Senior Notes Due March 1, 2041 [Member]
Debt Instrument [Line Items]
Senior notes	1,250		1,250
Debt instrument, interest rate	6.50%
Debt instrument, maturity date	Mar. 01, 2041
Capital Lease Obligations [Member] | Consolidated Subsidiaries [Member]
Debt Instrument [Line Items]
Capital lease obligations due 2013-2027	355		299
Debt instrument maturity year, start	Jan. 01, 2013
Debt instrument maturity year, end	Jun. 30, 2027
Trade Receivables Securitization [Member] | Consolidated Subsidiaries [Member]
Debt Instrument [Line Items]
Trade receivables securitization facility Due 2014
Line of credit facility, expiration date	Dec. 31, 2014

[1] See Notes 18 and 19 for information on interest rate swaps.

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Increase (decrease) in cash and cash equivalents Operating activities:
Net income	$ 3,393	$ 2,389	$ 623
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	995	891	941
Pension and other postretirement benefits, net	153	(90)	13
Deferred income taxes	492	123	308
Net gain on disposal of assets	(177)	(12)	(11)
Equity method investments, net	11	(2)	(34)
Changes in the fair value of derivative instruments	59	(57)	(16)
Changes in:
Current receivables	851	(1,177)	(750)
Inventories	(115)	(255)	(76)
Current accounts payable and accrued liabilities	(1,223)	1,502	1,160
All other, net	53	(3)	59
Net cash provided by operating activities	4,492	3,309	2,217
Investing activities:
Additions to property, plant and equipment	(1,369)	(1,185)	(1,217)
Acquisitions	(190)	(74)
Disposal of assets	53	144	763
Investments in related party debt securities - purchases		(10,326)	(9,709)
Investments in related party debt securities - redemptions		12,730	8,019
Investments - loans and advances	(57)	(56)	(45)
Investments - redemptions and repayments	108	53	44
All other, net	3	9
Net cash provided by (used in) investing activities	(1,452)	1,295	(2,145)
Financing activities:
Long-term debt payable to Marathon Oil and subsidiaries - borrowings		7,748	18,804
Long-term debt payable to Marathon Oil and subsidiaries - repayments		(11,366)	(17,544)
Long-term debt - borrowings		2,989
Long-term debt - repayments	(17)	(12)	(12)
Debt issuance costs	(6)	(60)
Net proceeds from issuance of common stock	108	1
Common stock repurchased	(1,350)
Dividends paid	(407)	(160)
Net proceeds from issuance of MPLX LP common units	407
Distributions to Marathon Oil		(783)	(1,330)
All other, net	6
Net cash used in financing activities	(1,259)	(1,643)	(82)
Net increase (decrease) in cash and cash equivalents	1,781	2,961	(10)
Cash and cash equivalents at beginning of period	3,079	118	128
Cash and cash equivalents at end of period	$ 4,860	$ 3,079	$ 118

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Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Net income	$ 3,393	$ 2,389	$ 623
Other comprehensive income (loss):
Actuarial changes, net of tax of $47, ($151) and ($20)	78	(248)	(108)
Prior service costs, net of tax of $203, $2 and $3	337	4	5
Other, net of tax of $-, $- and $-		(1)
Other comprehensive income (loss)	415	(245)	(103)
Comprehensive income	3,808	2,144	520
Less comprehensive income attributable to noncontrolling interests	4
Comprehensive income attributable to MPC	$ 3,804	$ 2,144	$ 520

XML

Income per Common Share

12 Months Ended

Dec. 31, 2012

Income per Common Share

9. Income per Common Share

We compute basic earnings per share by dividing net income attributable to MPC shareholders by the weighted average number of shares of common stock outstanding. Diluted income per share assumes exercise of stock options and stock appreciation rights, provided the effect is not anti-dilutive.

On June 30, 2011, 356,337,127 shares of our common stock were distributed to Marathon Oil stockholders in conjunction with the Spinoff. For comparative purposes, and to provide a more meaningful calculation for weighted average shares, we have assumed this amount to be outstanding as of the beginning of each period prior to the Spinoff presented in the calculation of basic weighted average shares. In addition, for the dilutive weighted average share calculations, we have assumed the dilutive securities outstanding at June 30, 2011 were also outstanding at each of the periods prior to the Spinoff presented. Excluded from the diluted share calculation are approximately two million, four million and four million shares related to stock-based compensation awards in 2012, 2011 and 2010, respectively, as their effect would be anti-dilutive.

MPC grants certain incentive compensation awards to employees and non-employee directors that are considered to be participating securities. Due to the presence of participating securities, we have calculated our earnings per share using the two-class method.

(In millions, except per share data)	2012		2011		2010
Basic earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	3,389	$	2,389	$	623
Income allocated to participating securities		6		4		1
Income available to common stockholders - basic	$	3,383	$	2,385	$	622
Weighted average common shares outstanding		340		356		356
Basic earnings per share	$	9.95	$	6.70	$	1.75
Diluted earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	3,389	$	2,389	$	623
Income allocated to participating securities		6		4		1
Income available to common stockholders - diluted	$	3,383	$	2,385	$	622
Weighted average common shares outstanding		340		356		356
Effect of dilutive securities		2		1		2
Weighted average common shares, including dilutive effect		342		357		358
Diluted earnings per share	$	9.89	$	6.67	$	1.74

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Derivatives (Classification Of Gross Fair Values Of Derivative Instruments, Excluding Cash Collateral) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Commodity Derivatives [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Asset	$ 49	$ 26
Liability	88	45
Commodity Derivatives [Member] | Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Asset		1
Liability		1
Interest Rate Derivatives [Member] | Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Asset		$ 19

XML

Equity Method Investments (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule of Equity Method Investments [Line Items]
Equity method investment difference between carrying amount and underlying equity	$ 28
Equity method investment difference between carrying amount and underlying equity, portion related to goodwill which is not being amortized	49
Dividends and partnership distributions received from equity method investees	$ 37	$ 48	$ 36

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Equity Method Investments (Schedule Of Equity Method Investments) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 321	$ 302
Centennial [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	50.00%	50.00%	50.00%
Equity method investments	27	17
LOCAP LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	59.00%
Equity method investments	26	25
LOOP [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	51.00%	51.00%	51.00%
Equity method investments	198	181
TACE [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	36.00%	36.00%	36.00%
Equity method investments	29	35
TAME [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	50.00%	50.00%	50.00%
Equity method investments	27	32
Other Equity Method Investees [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 14	$ 12

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Defined Benefit Pension And Other Postretirement Plans (Reconciliation Of Beginning And Ending Balances Of Plan Assets Classified As Level 3) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011
Fair Value Significant Unobservable Inputs [Line Items]
Fair value of plan assets at December 31	$ 1,478		$ 1,423
Level 3 [Member]
Fair Value Significant Unobservable Inputs [Line Items]
Fair value of plan assets at January 1	121		100
Actual return on plan assets	2		12
Purchases	22		22
Sales	(18)		(15)
Other			2
Fair value of plan assets at December 31	127		121
Private Equity [Member]
Fair Value Significant Unobservable Inputs [Line Items]
Fair value of plan assets at December 31	56		55
Private Equity [Member] | Level 3 [Member]
Fair Value Significant Unobservable Inputs [Line Items]
Fair value of plan assets at January 1	55		46
Actual return on plan assets	2		7
Purchases	12		10
Sales	(13)		(9)
Other			1
Fair value of plan assets at December 31	56		55
Real Estate [Member]
Fair Value Significant Unobservable Inputs [Line Items]
Fair value of plan assets at December 31	54	[1]	49	[2]
Real Estate [Member] | Level 3 [Member]
Fair Value Significant Unobservable Inputs [Line Items]
Fair value of plan assets at January 1	49	[2]	37
Actual return on plan assets			5
Purchases	10		12
Sales	(5)		(6)
Other			1
Fair value of plan assets at December 31	54	[1]	49	[2]
Other [Member]
Fair Value Significant Unobservable Inputs [Line Items]
Fair value of plan assets at December 31	17		17
Other [Member] | Level 3 [Member]
Fair Value Significant Unobservable Inputs [Line Items]
Fair value of plan assets at January 1	17		17
Actual return on plan assets
Purchases
Sales
Other
Fair value of plan assets at December 31	$ 17		$ 17

[1] 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 land with the greatest percentage of investments made in the U.S. and Asia, which includes the emerging markets of China and India.

[2] Includes investments diversified by property type and location. The largest property sector holdings, which represent approximately 75 percent of investments held, are office, hotel, residential and land 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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Leases (Schedule Of Operating Lease Rental Expense) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Leases Disclosure [Line Items]
Minimum rental	$ 139	$ 123	$ 135
Contingent rental		1	1
Rental expense	$ 139	$ 124	$ 136

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Defined Benefit Pension And Other Postretirement Plans (Summarizes Assumed Health Care Cost Trend Rates) (Detail)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011		Dec. 31, 2010
Medical, Pre-65 [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for the following year	8.00%	7.50%		7.50%
Rate to which the cost trend rate is assumed to decline	5.00%	5.00%		5.00%
Year that the rate reaches the ultimate trend rate	2020	2018		2018
Medical, Post-65 [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for the following year	4.00%	7.00%	[1]	7.00%	[1]
Rate to which the cost trend rate is assumed to decline		5.00%	[1]	5.00%	[1]
Year that the rate reaches the ultimate trend rate		2017	[1]	2017	[1]
Prescription Drugs [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for the following year	7.00%	7.50%		7.50%
Rate to which the cost trend rate is assumed to decline	5.00%	5.00%		5.00%
Year that the rate reaches the ultimate trend rate	2018	2018		2018

[1] Effective 2013, as a result of changes in the post-65 medical plan coverage of the Marathon Petroleum Health Plan and the Marathon Petroleum Retiree Health Plan, increases are the lower of the trend rate or 4%.

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Document and Entity Information (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Feb. 15, 2013	Jun. 30, 2012
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2012
Document Fiscal Year Focus	2012
Document Fiscal Period Focus	FY
Trading Symbol	MPC
Entity Registrant Name	Marathon Petroleum Corp
Entity Central Index Key	0001510295
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		331,433,926
Entity Public Float			$ 15.3

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Stock-Based Compensation Plans (Narrative) (Detail) (USD $)	6 Months Ended	12 Months Ended								12 Months Ended	6 Months Ended	12 Months Ended		6 Months Ended	12 Months Ended		6 Months Ended		12 Months Ended					12 Months Ended
	Dec. 31, 2011	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Performance Units [Member]	Dec. 31, 2012 Stock Option [Member]	Dec. 31, 2012 Restricted Stock Units [Member]	Dec. 31, 2011 Restricted Stock Units [Member]	Dec. 31, 2012 Restricted Stock Units [Member] Non-Employee Directors [Member]	Dec. 31, 2012 Stock Options [Member]	Jun. 30, 2011 Predecessor [Member] Restricted Stock Units [Member]	Dec. 31, 2010 Predecessor [Member] Restricted Stock Units [Member]	Dec. 31, 2012 MPC 2007 and 2003 Plans [Member] Employees	Jun. 30, 2011 MPC 2007 and 2003 Plans [Member] Predecessor [Member]	Dec. 31, 2010 MPC 2007 and 2003 Plans [Member] Predecessor [Member]	Dec. 31, 2012 MPC 2011 Plan [Member] Performance Units [Member]	Dec. 31, 2011 Maximum [Member]	Dec. 31, 2012 Maximum [Member] Stock Appreciation Rights (SARs) [Member]	Dec. 31, 2012 Maximum [Member] Performance Units [Member]	Dec. 31, 2012 Maximum [Member] Stock Option [Member]	Dec. 31, 2012 Maximum [Member] MPC 2012 Plan [Member]	Dec. 31, 2012 Maximum [Member] MPC 2012 Plan [Member] Awards Other Than Stock Options Or Stock Appreciation Rights [Member]	Dec. 31, 2012 Maximum [Member] MPC 2012 Plan [Member] Employee Stock Option [Member]	Dec. 31, 2012 Average Minimum [Member] Stock Appreciation Rights (SARs) [Member]	Dec. 31, 2012 Average Maximum [Member] Stock Appreciation Rights (SARs) [Member]	Dec. 31, 2012 Minimum [Member] MPC 2011 Plan [Member] Performance Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of common stock authorized to be delivered under the compensation plan																					25,000,000	10,000,000	10,000,000
Number of employees affected by adjustment and substitution of awards													393
Stock options maximum term, in years																		10 years		10 years
Vesting period of awards					30 months	3 years	3 years									36 months			36 months					3 years	4 years	18 months
Restricted stock and restricted stock unit awards granted in 2012, additional holding period							1 year
Pay-out percentage in cash (in percentage)																75.00%
Pay-out percentage in MPC common stock (in percentage)																25.00%
Average requisite service period																Four
Grant date fair value							$ 44.38	$ 33.78			$ 45.22	$ 32.18				$ 1.09
Total employee stock-based compensation expense		$ 35,000,000	$ 28,000,000	$ 16,000,000
Total related income tax benefits		13,000,000	11,000,000	6,000,000
Cash received upon exercise of stock option awards	1,000,000	108,000,000												17,000,000	5,000,000
Tax benefits realized by MPC for deductions for stock awards exercised		16,000,000												7,000,000	1,000,000		1,000,000
Share-based compensation arrangement by share-based payment award fair value assumptions expected volatility rate - Company stock weighting (in percentage)		25.00%								25.00%
Share-based compensation arrangement by share-based payment award fair value assumptions expected volatility rate - Peer stock weighting (in percentage)		75.00%								75.00%
Intrinsic value of options exercised	1,000,000	37,000,000												18,000,000	2,000,000
Unrecognized compensation cost		12,000,000				0	18,000,000
Weighted average recognition period, in years						10 months 24 days	1 year 1 month 6 days
Restricted units outstanding							359,111
Restricted units vested									357,990
Weighted average fair value, vested									$ 31.04

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Equity

12 Months Ended

Dec. 31, 2012

Equity

10. Equity

Share repurchase plan – On February 1, 2012, we announced that our board of directors authorized a share repurchase plan, enabling us to purchase up to $2.0 billion of MPC common stock over a two-year period. On January 30, 2013, we announced that our board of directors approved an additional $2.0 billion share repurchase authorization. The board also extended the remaining $650 million share repurchase authorization announced on February 1, 2012, for a total outstanding authorization of $2.65 billion through December 2014. We may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, accelerated share repurchases or open market solicitations for shares, some of which may be effected through Rule 10b5-1 plans. The timing of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.

Accelerated share repurchase programs – On February 3, 2012, we entered into an $850 million accelerated share repurchase (“ASR”) program with a major financial institution to repurchase shares of MPC common stock under the approved share repurchase plan authorized by our board of directors. Under this ASR program, we received 17,581,344 shares of our common stock during the first quarter of 2012. On July 25, 2012, an additional 2,776,036 shares were delivered to us, for a total of 20,357,380 repurchased shares, which concluded this ASR program. The total number of shares repurchased under this ASR program was based generally on the volume-weighted average price of our common stock during the repurchase period, subject to provisions that set a minimum and maximum number of shares. Upon final settlement, the average per share cost for all shares purchased under this ASR program was $41.75.

On November 5, 2012, we entered into a $500 million ASR program. This ASR was the second tranche of share repurchases under the share repurchase plan authorized by our board of directors. Under this ASR program, we received 7,403,294 shares of common stock during the fourth quarter of 2012. On February 5, 2013, an additional 870,947 shares were delivered to us, for a total of 8,274,241 repurchased shares, which concluded this ASR program. The total number of shares repurchased under this ASR program was based generally on the volume-weighted average price of our common stock during the repurchase period. Upon final settlement, the average per share cost for all shares purchased under this ASR program was $60.43.

The shares repurchased under the ASR programs were accounted for as treasury stock purchase transactions, reducing the weighted average number of basic and diluted common shares outstanding by the shares repurchased, and as forward contracts indexed to our common stock. The forward contracts were accounted for as equity instruments.

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Segment Information (Total Assets By Reportable Segment) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	$ 27,223	$ 25,745
Reportable Segment [Member] | Refining & Marketing [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	17,052	17,294
Reportable Segment [Member] | Speedway [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	1,947	1,597
Reportable Segment [Member] | Pipeline Transportation [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	1,950	1,556
Items Not Allocated [Member] | Corporate And Other [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	$ 6,274	$ 5,298

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Inventories (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012
Inventories Net [Line Items]
Total inventory LIFO percentage	94.00%		93.00%
Excess of replacement or current costs over stated LIFO value	$ 5,015		$ 4,511
Decrease in cost of revenues resulting from liquidations of LIFO inventories	$ 4	$ 4

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Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Actuarial changes, tax	$ 47	$ (151)	$ (20)
Prior service costs, tax	203	2	3
Other, tax	$ 0	$ 0	$ 0

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MPLX LP

12 Months Ended

Dec. 31, 2012

MPLX LP

4. MPLX LP

MPLX is a publicly traded master limited partnership that was formed by us to own, operate, develop and acquire pipelines and other midstream assets related to the transportation and storage of crude oil, refined products and other hydrocarbon-based products.    Headquartered in Findlay, Ohio, MPLX’s initial assets consist of a 51 percent general partner interest in a network of common carrier crude oil and product pipeline systems and associated storage assets in the Midwest and Gulf Coast regions of the United States and a 100 percent interest in a butane storage cavern in West Virginia.

Initial Public Offering

On October 31, 2012, MPLX completed its initial public offering of 19,895,000 common units at a price to the public of $22.00 per unit, which included 2,595,000 common units purchased by the underwriters through an over-allotment option that was exercised in full by the underwriters.    Net proceeds to MPLX from the sale of the units were $407 million, net of underwriting discounts and commissions, structuring fees and offering expenses (the “Offering Costs”) of $31 million.    MPLX contributed $192 million to MPLX Pipe Line Holdings LP (“Pipe Line Holdings”), a subsidiary of MPLX, which Pipe Line Holdings will retain on behalf of MPLX and us to fund our respective pro rata portions of certain estimated expansion capital expenditures.    MPLX distributed net proceeds to us of $203 million, in partial consideration of assets contributed and to reimburse us for certain capital expenditures incurred with respect to those assets.    MPLX GP LLC, a wholly-owned subsidiary of MPC, serves as the general partner of MPLX.    We own a 73.6 percent interest in MPLX, including the general partner interest, and we consolidate this entity for financial reporting purposes since we have a controlling financial interest.    The initial public offering represented the sale of a 26.4 percent interest in MPLX.

The following table is a reconciliation of proceeds from the initial public offering:

(In millions)
Total proceeds from the initial public offering	$	438
Less: Offering Costs		(31)
Net proceeds from the initial public offering		407
Less: Revolving credit facility origination fees		(2)
Less: Cash retained by MPLX		(10)
Less: Cash contribution to Pipe Line Holdings		(192)
Net proceeds distributed to MPC from the initial public offering	$	203

Commercial Agreements

MPLX generates revenue primarily by charging tariffs for transporting crude oil, refined products and other hydrocarbon-based products through their pipelines and at their barge dock and fees for storing crude oil and products at their storage facilities.    They are also the operator of additional crude oil and product pipelines owned by us and third parties for which they are paid operating fees.    They do not take ownership of the crude oil or products that they transport and store for their customers, and they do not engage in the trading of any commodities.

We have entered into long-term, fee-based transportation and storage services agreements with MPLX.    Under these agreements, MPLX provides transportation and storage services to us, and we commit to provide MPLX with minimum quarterly throughput and storage volumes of crude oil and products and minimum storage volumes of butane.    We believe the terms and conditions under these commercial agreements, as well as the other initial agreements we entered into with MPLX described below, are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services.

These commercial agreements include:

• three separate 10-year transportation services agreements and one five-year transportation services agreement under which we pay MPLX fees for transporting crude oil on each of their crude oil pipeline systems;

• four separate 10-year transportation services agreements under which we pay MPLX fees for transporting products on each of their product pipeline systems;

• a five-year transportation services agreement under which we pay MPLX fees for handling crude oil and products at their Wood River, Illinois barge dock;

• a 10-year storage services agreement under which we pay MPLX fees for providing storage services at their Neal, West Virginia butane cavern; and

• four separate three-year storage services agreements under which we pay MPLX fees for providing storage services at their tank farms.

All of the transportation services agreements for the crude oil and product pipeline systems (other than our Wood River, Illinois to Patoka, Illinois crude system) automatically renew for up to two additional five-year terms unless terminated by either party.    The transportation services agreements for the Wood River to Patoka crude system and the barge dock automatically renew for up to four additional two-year terms unless terminated by either party.    The butane cavern storage services agreement does not automatically renew.    The storage services agreements for the tank farms automatically renew for additional one-year terms unless terminated by either party.

Under the transportation services agreements, if we fail to transport our minimum throughput volumes during any quarter, then we will pay MPLX a deficiency payment equal to the volume of the deficiency multiplied by the tariff rate then in effect.    If the minimum capacity of the pipeline falls below the level of our commitment at any time or if capacity on the pipeline is required to be allocated among shippers because volume nominations exceed available capacity, depending on the cause of the reduction in capacity, our commitment may be reduced or we will receive a credit for our minimum volume commitment for that period.    In addition to our minimum volume commitment, we are responsible for any loading, handling, transfer and other charges with respect to volumes MPLX transports for us.    If MPLX agrees to make any capital expenditures at our request, we will reimburse MPLX for, or MPLX will have the right in certain circumstances, to file for an increased tariff rate to recover the actual cost of such capital expenditures.    The transportation services agreements include provisions that permit us to suspend, reduce or terminate our obligations under the applicable agreement if certain events occur.    These events include us deciding to permanently or indefinitely suspend refining operations at one or more of our refineries for at least twelve consecutive months and certain force majeure events that would prevent MPLX or us from performing under the applicable agreement.

Under the storage services agreements, MPLX is obligated to make available to us on a firm basis the available storage capacity at the tank farms and butane cavern, and we pay MPLX a per-barrel fee for such storage capacity, regardless of whether we fully utilize the available capacity.    Beginning on January 1, 2014, the storage services agreements will be adjusted based on changes in the producer price index.

Operating Agreements

At the closing of the initial public offering of MPLX, we entered into an operating services agreement with MPLX under which MPLX operates various pipeline systems owned by us.    In addition, under existing operating service agreements, MPLX continues to operate various pipeline systems owned by us and third parties. Under these operating services agreements MPLX receives an operating fee for operating the assets and is reimbursed for all direct and indirect costs associated with operating the assets. The operating fees under most of these agreements are indexed for inflation. These agreements range from one to five years in length and automatically renew unless terminated by either party.

Management Services Agreements

Prior to the closing of the initial public offering of MPLX, MPLX entered into two management services agreements with us under which MPLX provides certain management services to us with respect to certain of our retained pipeline assets. MPLX receives fixed annual fees under the agreements for providing the required management services, initially in the amount of $0.7 million and thereafter adjusted annually for inflation and based on changes in the scope of management services provided.

Omnibus Agreement

Upon the closing of the initial public offering of MPLX, we entered into an omnibus agreement with MPLX that addresses MPLX’s payment of a fixed annual fee to us for the provision of executive management services and MPLX’s reimbursement to us for the provision of certain general and administrative services to MPLX, as well as our indemnification of MPLX for certain matters, including environmental, title and tax matters.

Employee Services Agreements

Prior to the closing of the initial public offering of MPLX, we entered into two employee services agreements with MPLX under which MPLX reimburses us for the provision of certain operational and management services in support of their pipelines, barge dock, butane cavern and tank farms.

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Accounting Standards

12 Months Ended

Dec. 31, 2012

Accounting Standards

3. Accounting Standards

Recently Adopted

In September 2011, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update giving an entity the option to use a qualitative assessment to determine whether or not the entity is required to perform the two step goodwill impairment test.    If, through a qualitative assessment, an entity determines that it is more likely than not that the fair value of a reporting unit is less than the carrying amount, the entity is required to perform the two step goodwill impairment test.    The amendments in the update were effective for annual and interim goodwill testing performed in fiscal years beginning after December 15, 2011.    The adoption of this accounting standards update in the first quarter of 2012 did not have an impact on our consolidated results of operations, financial position or cash flows.    We perform the annual goodwill impairment testing for each of our reporting units in the fourth quarter.

In June 2011, the FASB amended the reporting standards for comprehensive income to eliminate the option to present the components of other comprehensive income as part of the statement of changes in equity and to require reclassification adjustments from accumulated other comprehensive income to be measured and presented by income statement line item in net income and also in other comprehensive income.    All non-owner changes in 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 other comprehensive income and the total of comprehensive income.    This accounting standards update does not change the items that must be reported in other comprehensive income or when an item of other comprehensive income must be reclassified to net income.    In December 2011, the FASB issued an accounting standards update to defer the presentation requirements of the reclassification adjustments from accumulated other comprehensive income.    This accounting standards update, as modified, was adopted using the two statement approach in the fourth quarter of 2011 and was applied retrospectively for all prior periods presented.    The adoption of this accounting standards update, as modified, did not have an impact on our consolidated results of operations, financial position or cash flows.    In February 2013, the FASB issued an accounting standards update regarding the presentation requirements of the reclassification adjustments from accumulated other comprehensive income.    See the Not Yet Adopted section for more information.

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. generally accepted accounting principles (“US GAAP”) and International Financial Reporting Standards (“IFRS”).    The amendments change the wording used to describe certain of the US 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.    The amendments were to be applied prospectively and were effective in interim and annual periods beginning with the first quarter of 2012 with early application not permitted.    This accounting standards update was adopted in the first quarter of 2012 and was applied prospectively.    The adoption of these amendments did not have a significant impact on our consolidated results of operations, financial position or cash flows.    The new required disclosures are included in Note 18.

Not Yet Adopted

In February 2013, the FASB issued an accounting standards update that requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component.    If the amount reclassified is required under US GAAP to be reclassified to net income in its entirety in the same reporting period, an entity is required to present, either on the face of the financial statements or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income.    For other amounts not required to be reclassed in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional detail about those amounts.    The accounting standards update is effective prospectively for annual periods beginning after December 15, 2012, and interim periods within those annual periods.    Adoption of this accounting standards update in the first quarter of 2013 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

In July 2012, the FASB issued an accounting standards update that gives an entity the option to first assess qualitatively whether it is more likely than not that an indefinite-lived intangible asset is impaired.    If, through the qualitative assessment, an entity determines that it is more likely than not that the intangible asset is impaired, the quantitative impairment test must then be performed.    The accounting standards update is effective for annual and interim impairment tests performed in fiscal years beginning after September 15, 2012.    Early adoption is permitted.    Adoption of this accounting standards update in the first quarter of 2013 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

In December 2011, the FASB issued an accounting standards update which was amended in January 2013 that requires disclosure of additional information related to recognized derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are offset or are not offset but are subject to an enforceable netting agreement.    The purpose of the requirement is to help users evaluate the effect or potential effect of offsetting and related netting arrangements on an entity’s financial position.    The update is to be applied retrospectively and is effective for annual periods that begin on or after January 1, 2013 and interim periods within those annual periods.    Adoption of this update is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

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Equity Method Investments

12 Months Ended

Dec. 31, 2012

Equity Method Investments

15. Equity Method Investments

	Ownership as of December 31, 2012			December 31,
(In millions)				2012		2011
Centennial		50	%	$	27	$	17
LOCAP LLC		59	%		26		25
LOOP		51	%		198		181
TACE		36	%		29		35
TAME		50	%		27		32
Other					14		12
Total				$	321	$	302

Summarized financial information for equity method investees is as follows:

(In millions)	2012		2011		2010
Income statement data:
Revenues and other income	$	1,025	$	1,043	$	939
Income from operations		73		128		196
Net income		47		101		170
Balance sheet data - December 31:
Current assets	$	217	$	256
Noncurrent assets		1,163		1,175
Current liabilities		161		126
Noncurrent liabilities		636		690

As of December 31, 2012, the carrying value of our equity method investments was $28 million higher than the underlying net assets of investees. This basis difference is being amortized or accreted into net income over the remaining estimated useful lives of the underlying net assets, except for $49 million of excess related to goodwill.

At December 31, 2012, Centennial was not shipping product; therefore, we evaluated the carrying value of our equity method investment in Centennial and concluded no impairment was required given our assessment of its fair value based on various uses for Centennial’s assets. We will continue to monitor the carrying value of our equity investment in Centennial.

Dividends and partnership distributions received from equity method investees (excluding distributions that represented a return of capital previously contributed) were $37 million, $48 million and $36 million in 2012, 2011 and 2010.

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Segment Information

12 Months Ended

Dec. 31, 2012

Segment Information

11. Segment Information

We have three reportable operating segments: Refining & Marketing; Speedway; and Pipeline Transportation. Each of these segments is organized and managed based upon the nature of the products and services they offer.

• Refining & Marketing – refines crude oil and other feedstocks at our refineries in the Gulf Coast and Midwest regions of the United States, purchases ethanol and refined products for resale and distributes refined products through various means, including barges, terminals and trucks that we own or operate. We sell refined products to wholesale marketing customers domestically and internationally, to buyers on the spot market, to our Speedway segment and to dealers and jobbers who operate Marathon^® retail outlets;

• Speedway – sells transportation fuels and convenience products in retail markets in the Midwest, primarily through Speedway^® convenience stores; and

• Pipeline Transportation – transports crude oil and other feedstocks to our refineries and other locations, delivers refined products to wholesale and retail market areas and includes the aggregated operations of MPLX and MPC’s retained pipeline assets and investments.

As discussed in Note 7, on December 1, 2010, we disposed of the Minnesota Assets, which were part of our Refining & Marketing, Speedway and Pipeline Transportation segments. Segment information for all periods prior to the disposition includes amounts for these operations.

Segment income represents income from operations attributable to the operating segments. Corporate administrative expenses, including those allocated from the Marathon Oil Companies prior to the Spinoff, and costs related to certain non-operating assets are not allocated to the operating segments. In addition, certain items that affect comparability (as determined by the chief operating decision maker) are not allocated to the operating segments.

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
Year Ended December 31, 2012
Revenues:
Customer	$	67,921	$	14,239	$	77	$	82,237
Intersegment(a)		8,782		4		381		9,167
Related parties		7		-		1		8
Segment revenues		76,710		14,243		459		91,412
Elimination of intersegment revenues		(8,782)		(4)		(381)		(9,167)
Total revenues	$	67,928	$	14,239	$	78	$	82,245
Segment income from operations(b)	$	5,098	$	310	$	216	$	5,624
Income (loss) from equity method investments		(6)		-		32		26
Depreciation and amortization(c)		804		114		54		972
Capital expenditures and investments(d)(e)		705		340		211		1,256

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
Year Ended December 31, 2011
Revenues:
Customer	$	65,028	$	13,490	$	65	$	78,583
Intersegment(a)		8,301		-		335		8,636
Related parties		52		-		3		55
Segment revenues		73,381		13,490		403		87,274
Elimination of intersegment revenues		(8,301)		-		(335)		(8,636)
Total revenues	$	65,080	$	13,490	$	68	$	78,638
Segment income from operations	$	3,591	$	271	$	199	$	4,061
Income from equity method investments		11		-		39		50
Depreciation and amortization(c)		718		110		45		873
Capital expenditures and investments(d)(f)		900		164		121		1,185

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
Year Ended December 31, 2010
Revenues:
Customer	$	49,844	$	12,494	$	49	$	62,387
Intersegment(a)		7,394		-		347		7,741
Related parties		95		-		5		100
Segment revenues		57,333		12,494		401		70,228
Elimination of intersegment revenues		(7,394)		-		(347)		(7,741)
Total revenues	$	49,939	$	12,494	$	54	$	62,487
Segment income from operations	$	800	$	293	$	183	$	1,276
Income from equity method investments		9		-		61		70
Depreciation and amortization(c)		739		111		62		912
Capital expenditures and investments(d)		961		84		24		1,069

^(a)  Management believes intersegment transactions were conducted under terms comparable to those with unaffiliated parties.

^(b)  Included in the Pipeline Transportation segment are $4 million of corporate overhead costs and pension settlement expenses attributable to MPLX subsequent to MPLX’s October 31, 2012 initial public offering, which were included in items not allocated to segments prior to MPLX’s initial public offering. These expenses are not currently allocated to other segments.

^(c)  Differences between segment totals and MPC totals represent amounts related to unallocated items and are included in “Items not allocated to segments” in the reconciliation below.

^(d)  Capital expenditures include changes in capital accruals.

^(e)  Includes Speedway’s acquisition of 97 convenience stores in 2012.

^(f)  Includes Speedway’s acquisition of 23 convenience stores in 2011.

The following reconciles segment income from operations to income before income taxes as reported in the consolidated statements of income:

(In millions)	2012			2011			2010
Segment income from operations	$	5,624		$	4,061		$	1,276
Items not allocated to segments:
Corporate and other unallocated items(a)(b)		(336	)		(316	)		(236	)
Minnesota Assets sale settlement gain(c)		183			-			-
Pension settlement expenses(b)(d)		(124	)		-			-
Impairment(e)		-			-			(29	)
Net interest and other financial income (costs)(f)		(109	)		(26	)		12
Income before income taxes	$	5,238		$	3,719		$	1,023

^(a)  Corporate and other unallocated items consists primarily of MPC’s corporate administrative expenses, including allocations from the Marathon Oil Companies for periods prior to the Spinoff and costs related to certain non-operating assets.

^(b)  Corporate overhead costs and pension settlement expenses attributable to MPLX were included in the Pipeline Transportation segment subsequent to MPLX’s October 31, 2012 initial public offering.

^(c)  See Note 7.

^(d)  See Note 22.

^(e)  See Note 18.

^(f)  Includes related party net interest and other financial income.

The following reconciles segment capital expenditures and investments to total capital expenditures:

(In millions)	2012		2011		2010
Segment capital expenditures and investments	$	1,256	$	1,185	$	1,069
Less: Investments in equity method investees		28		11		7
Plus: Items not allocated to segments:
Capital expenditures not allocated to segments		103		24		1
Capitalized interest		101		114		103
Total capital expenditures(a)(b)	$	1,432	$	1,312	$	1,166

^(a)  Capital expenditures include changes in capital accruals.

^(b)  See Note 21 for a reconciliation of total capital expenditures to additions to property, plant and equipment as reported in the consolidated statements of cash flows.

The following reconciles total revenues to sales and other operating revenues (including consumer excise taxes) as reported in the consolidated statements of income:

(In millions)	2012		2011		2010
Total revenues (as reported above)	$	82,245	$	78,638	$	62,487
Plus: Corporate and other unallocated items		(2)		-		-
Less: Sales to related parties		8		55		100
Sales and other operating revenues (including consumer excise taxes)	$	82,235	$	78,583	$	62,387

Revenues by product line were:

(In millions)	2012		2011		2010
Refined products	$	76,234	$	73,334	$	56,025
Merchandise		3,229		3,090		3,369
Crude oil and refinery feedstocks		2,514		1,972		2,890
Transportation and other		266		242		203
Total revenues		82,243		78,638		62,487
Less: Sales to related parties		8		55		100
Sales and other operating revenues (including consumer excise taxes)	$	82,235	$	78,583	$	62,387

No single customer accounted for more than 10 percent of annual revenues.

We do not have significant operations in foreign countries. Therefore, revenues in foreign countries and long-lived assets located in foreign countries, including property, plant and equipment and investments, are not material to our operations.

Total assets by reportable segment were:

	December 31,
(In millions)	2012		2011
Refining & Marketing	$	17,052	$	17,294
Speedway		1,947		1,597
Pipeline Transportation		1,950		1,556
Corporate and Other		6,274		5,298
Total consolidated assets	$	27,223	$	25,745

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Income Taxes (Reconciliation Of Federal Statutory Income Tax Rate) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Schedule Of Effective Income Tax Rate Reconciliation [Line Items]
Statutory rate applied to income before income taxes	35.00%	35.00%	35.00%
State and local income taxes, net of federal income tax effects	2.00%	2.00%	3.00%
Legislation			2.00%	[1]
Domestic manufacturing deduction	(1.00%)	(1.00%)
Effect of dividends received deduction			(1.00%)
Other	(1.00%)
Provision for income taxes	35.00%	36.00%	39.00%
Charge for write-off of deferred tax assets due to change in tax treatment of federal subsidy			$ 26

[1] The Patient Protection and Affordable Care Act ("PPACA") and the Health Care and Education Reconciliation Act of 2010 were signed into law in March 2010. These new laws effectively changed the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the "MPDIMA"). Under the MPDIMA, the federal subsidy did not reduce our income tax deduction for the costs of providing such prescription drug plans, nor was it subject to income tax individually. Beginning in 2013, under the 2010 legislation, our income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. As a result, we recorded a charge of $26 million in 2010 for the write-off of deferred tax assets to reflect the change in the tax treatment of the federal subsidy.

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Disposition

12 Months Ended

Dec. 31, 2012

Disposition

7. Disposition

On December 1, 2010, we completed the sale of most of our Minnesota assets. These assets included the 74,000 barrel per calendar day St. Paul Park refinery and associated terminals, 166 convenience stores primarily branded SuperAmerica^® (including six stores in Wisconsin), along with the SuperMom’s bakery (a baked goods and sandwich supply operation) and certain associated trademarks, SuperAmerica Franchising LLC, interests in pipeline assets in Minnesota and associated inventories. We refer to these assets as the “Minnesota Assets.” The refinery and terminal assets were part of our Refining & Marketing segment, the convenience stores and bakery were part of our Speedway segment, and the interests in pipeline assets were part of our Pipeline Transportation segment. This transaction value was approximately $935 million, which included approximately $330 million for inventories. We received $740 million in cash, net of closing costs, but prior to post-closing adjustments. The terms of the sale included (1) a preferred equity interest in the entity that holds the Minnesota Assets with a stated value of $80 million, (2) a maximum $125 million earnout provision payable to us over eight years, (3) a maximum $60 million of margin support payable to the buyer over two years, up to a maximum of $30 million per year, (4) a receivable from the buyer of $107 million which was fully collected in 2011, and (5) guarantees with a maximum exposure of $11 million made by us on behalf of and to the buyer related to a limited number of convenience store sites. As a result of this continuing involvement, the related gain on sale of $89 million was initially deferred.

In July 2012, the buyer of our Minnesota Assets successfully completed an initial public offering (“IPO”). The successful completion of this IPO triggered the provisions in our May 4, 2012 settlement agreement with the buyer to be effective. Under the settlement agreement, we were released from our obligation to pay margin support and the buyer was released from its obligation to pay us under the earnout provision contained in the original sales agreement. Also, the buyer redeemed our $80 million preferred equity interest, paid us $12 million for dividends accrued on our preferred equity interest and paid us $40 million of cash, for total cash receipts of $132 million. In addition, the buyer issued us a new preferred security valued at $45 million. As a result, we recognized income before income taxes of approximately $183 million during 2012, which included $86 million of the deferred gain that was recorded when the sale transaction was originally closed.

We provided transition services to the buyer for approximately thirteen months following the sale. The buyer provided management and operational strategy for the business and we provided personnel to operate and maintain these Minnesota Assets.

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MPLX LP (Summary Of Reconciliation Of Proceeds From Initial Public Offering) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended		1 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Oct. 31, 2012 MPLX LP [Member]
Business Acquisition Actual Revenue And Pre Tax Income Loss [Line Items]
Total proceeds from the initial public offering			$ 438
Less: Offering Costs			(31)
Net proceeds from the initial public offering	407		407
Less: Revolving credit facility origination fees	(6)	(60)	(2)
Less: Cash retained by MPLX			(10)
Less: Cash contribution to Pipe Line Holdings			(192)
Net proceeds distributed to MPC from the initial public offering			$ 203

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Debt (Narrative) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2012
Revolving Credit Agreement Due 2017 [Member]
Line of Credit Facility [Line Items]
Letters of credit outstanding	$ 0
Credit facility agreement date	Sep. 14, 2012
Credit facility agreement amendment date	Dec. 20, 2012
Credit facility agreement effective date of amendment	Feb. 01, 2013
Term of senior unsecured revolving credit agreement (in years)	5 years
Line of credit, maximum borrowing capacity with increase from amendment	2,500,000,000
Increase in borrowing capacity due to amendment	500,000,000
Line of credit, additional borrowing capacity	500,000,000
Credit Agreement, expiry date	Sep. 14, 2017
Minimum percentage of lenders required to approve extension of credit agreement	50.00%
Line of credit facility, number of renewal periods	2
Line of credit facility, duration of renewal period	1 year
Deferred financing costs from the previous revolving credit agreement, that were expensed in the current period	1,000,000
Financing costs to be amortized over the life of the new revolving credit agreement	22,000,000
Revolving Credit Agreement Due 2017 [Member] | MPLX Operations LLC [Member]
Line of Credit Facility [Line Items]
Letters of credit outstanding	0
Credit facility agreement date	Sep. 14, 2012
Term of senior unsecured revolving credit agreement (in years)	5 years
Line of credit, additional borrowing capacity	300,000,000
Line of credit, current borrowing capacity	500,000,000
Credit Agreement, expiry date	Oct. 31, 2017
Minimum percentage of lenders required to approve extension of credit agreement	50.00%
Line of credit facility, number of renewal periods	2
Line of credit facility, duration of renewal period	1 year
Revolving Credit Agreement Due 2017 [Member] | LIBOR Adjustment [Member]
Line of Credit Facility [Line Items]
Debt Instrument Description of Variable Rate Basis	Adjusted LIBO Rate (as defined in the Credit Agreement)
Revolving Credit Agreement Due 2017 [Member] | LIBOR Adjustment [Member] | MPLX Operations LLC [Member]
Line of Credit Facility [Line Items]
Debt Instrument Description of Variable Rate Basis	Adjusted LIBO Rate (as defined in the MPLX Credit Agreement)
Revolving Credit Agreement Due 2017 [Member] | Alternate Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument Description of Variable Rate Basis	Alternate Base Rate (as defined in the Credit Agreement)
Revolving Credit Agreement Due 2017 [Member] | Alternate Base Rate [Member] | MPLX Operations LLC [Member]
Line of Credit Facility [Line Items]
Debt Instrument Description of Variable Rate Basis	Alternate Base Rate (as defined in the MPLX Credit Agreement)
Revolving Credit Agreement Due 2017 [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Covenant of ratio of consolidated net debt to total capitalization (in percentage)	0.65
Commitment fees on unused capacity (in percentage)	0.35%
Revolving Credit Agreement Due 2017 [Member] | Maximum [Member] | MPLX Operations LLC [Member]
Line of Credit Facility [Line Items]
Commitment fees on unused capacity (in percentage)	0.35%
Covenant of ratio of consolidated total debt to consolidated EBITDA (in ratio)	5.0
Covenant of ratio of consolidated total debt to consolidated EBITDA following certain acquisitions (in ratio)	5.5
Number of prior quarterly reporting periods used in determining compliance with covenant of ratio of consolidated total debt to consolidated EBITDA	4
Revolving Credit Agreement Due 2017 [Member] | Maximum [Member] | LIBOR Adjustment [Member]
Line of Credit Facility [Line Items]
Margin added to optimal reference rate (in percentage)	2.00%
Revolving Credit Agreement Due 2017 [Member] | Maximum [Member] | LIBOR Adjustment [Member] | MPLX Operations LLC [Member]
Line of Credit Facility [Line Items]
Margin added to optimal reference rate (in percentage)	2.00%
Revolving Credit Agreement Due 2017 [Member] | Maximum [Member] | Alternate Base Rate [Member]
Line of Credit Facility [Line Items]
Margin added to optimal reference rate (in percentage)	1.00%
Revolving Credit Agreement Due 2017 [Member] | Maximum [Member] | Alternate Base Rate [Member] | MPLX Operations LLC [Member]
Line of Credit Facility [Line Items]
Margin added to optimal reference rate (in percentage)	1.00%
Revolving Credit Agreement Due 2017 [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Commitment fees on unused capacity (in percentage)	0.10%
Revolving Credit Agreement Due 2017 [Member] | Minimum [Member] | MPLX Operations LLC [Member]
Line of Credit Facility [Line Items]
Commitment fees on unused capacity (in percentage)	0.10%
Revolving Credit Agreement Due 2017 [Member] | Minimum [Member] | LIBOR Adjustment [Member]
Line of Credit Facility [Line Items]
Margin added to optimal reference rate (in percentage)	1.00%
Revolving Credit Agreement Due 2017 [Member] | Minimum [Member] | LIBOR Adjustment [Member] | MPLX Operations LLC [Member]
Line of Credit Facility [Line Items]
Margin added to optimal reference rate (in percentage)	1.00%
Revolving Credit Agreement Due 2017 [Member] | Minimum [Member] | Alternate Base Rate [Member]
Line of Credit Facility [Line Items]
Margin added to optimal reference rate (in percentage)	0.00%
Revolving Credit Agreement Due 2017 [Member] | Minimum [Member] | Alternate Base Rate [Member] | MPLX Operations LLC [Member]
Line of Credit Facility [Line Items]
Margin added to optimal reference rate (in percentage)	0.00%
Trade Receivables Securitization [Member]
Line of Credit Facility [Line Items]
Letters of credit outstanding	0
Letters Of Credit [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of credit, current borrowing capacity	2,000,000,000
Letters Of Credit [Member] | Maximum [Member] | MPLX Operations LLC [Member]
Line of Credit Facility [Line Items]
Line of credit, current borrowing capacity	250,000,000
Swingline Loans [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of credit, current borrowing capacity	100,000,000
Swingline Loans [Member] | Maximum [Member] | MPLX Operations LLC [Member]
Line of Credit Facility [Line Items]
Line of credit, current borrowing capacity	$ 50,000,000

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Related Party Transactions

12 Months Ended

Dec. 31, 2012

Related Party Transactions

5. Related Party Transactions

During 2012, 2011 and 2010 our related parties included:

• Marathon Oil Companies until June 30, 2011, the effective date of the Spinoff.

• The Andersons Clymers Ethanol LLC (“TACE”), in which we have a 36 percent interest, and The Andersons Marathon Ethanol LLC (“TAME”), in which we have a 50 percent interest. These companies each own an ethanol production facility.

• Centennial Pipeline LLC (“Centennial”), in which we have a 50 percent interest. Centennial owns a refined products pipeline and storage facility.

• LOOP LLC (“LOOP”), in which we have a 51 percent noncontrolling interest. LOOP owns and operates the only U.S. deepwater oil port.

• Other equity method investees.

We believe that transactions with related parties, other than certain administrative transactions with the Marathon Oil Companies to effect the Spinoff and related to the provision of services, were conducted on terms comparable to those with unaffiliated parties. See below for a description of transactions with the Marathon Oil Companies.

On May 25, 2011, we entered into a separation and distribution agreement and several other agreements with the Marathon Oil Companies to effect the Spinoff and to provide a framework for our relationship with the Marathon Oil Companies. These agreements govern the relationship between us and Marathon Oil subsequent to the completion of the Spinoff and provide for the allocation between us and the Marathon Oil Companies of assets, liabilities and obligations attributable to periods prior to the Spinoff. Because the terms of these agreements were entered into in the context of a related party transaction, the terms may not be comparable to terms that would be obtained in a transaction between unaffiliated parties.

The separation and distribution agreement between us and the Marathon Oil Companies contains the key provisions relating to the separation of our business from Marathon Oil and the distribution of our common stock to Marathon Oil stockholders. The separation and distribution agreement identifies the assets that were transferred or sold, liabilities that were assumed or sold and contracts that were assigned to us by the Marathon Oil Companies or by us to the Marathon Oil Companies in the Spinoff and describes how these transfers, sales, assumptions and assignments occurred. In accordance with the separation and distribution agreement, Marathon Oil determined that our aggregate cash and cash equivalents balance at June 30, 2011 should be approximately $1.625 billion. The separation and distribution agreement also contains provisions regarding the release of liabilities, indemnifications, insurance, nonsolicitation of employees, maintenance of confidentiality, payment of expenses and dispute resolution. See Note 25.

We and Marathon Oil entered into a tax sharing agreement to govern the respective rights, responsibilities and obligations of Marathon Oil and us with respect to taxes and tax benefits, the filing of tax returns, the control of audits, restrictions on us to preserve the tax-free status of the Spinoff and other tax matters.

We and Marathon Oil entered into an employee matters agreement providing that each company has responsibility for our own employees and compensation plans. The employee matters agreement also contains provisions regarding stock-based compensation. See Note 23.

We entered into a transition services agreement with Marathon Oil under which we were providing each other with a variety of administrative services on an as-needed basis for a period of time not to exceed one year following the Spinoff. The charges under these transition service agreements were at cost-based rates that had been negotiated between us and Marathon Oil. Services provided to us by the Marathon Oil Companies included accounting, audit, treasury, tax, legal, information technology, administrative services, procurement of natural gas and health, environmental, safety and security. Services provided by us to the Marathon Oil Companies included legal, human resources, tax, accounting, audit, information technology and health, environmental, safety and security. The transition services agreement terminated on June 30, 2012.

Sales to related parties were as follows:

(In millions)	2012		2011		2010
Equity method investees:
Centennial	$	1	$	35	$	54
Other equity method investees		7		7		7
Marathon Oil Companies		-		13		39
Total	$	8	$	55	$	100

Related party sales to Centennial consist primarily of petroleum products. Related party sales to the Marathon Oil Companies consisted primarily of crude oil, which were based on contractual prices that were market-based, and pipeline operating revenue.

The fees received for operating pipelines for related parties included in other income on the consolidated statements of income were as follows:

(In millions)	2012		2011		2010
Centennial	$	1	$	-	$	-

Purchases from related parties were as follows:

(In millions)	2012		2011		2010
Equity method investees:
Centennial	$	7	$	31	$	72
LOOP		44		66		35
TAME		124		153		109
TACE		73		46		34
Other equity method investees		32		30		56
Marathon Oil Companies		-		1,590		2,287
Total	$	280	$	1,916	$	2,593

Related party purchases from Centennial consist primarily of refinery feedstocks and refined product transportation costs. Related party purchases from LOOP and other equity method investees consist primarily of crude oil transportation costs. Related party purchases from TAME and TACE consist of ethanol. Related party purchases from the Marathon Oil Companies consisted primarily of crude oil and natural gas, which were recorded at contracted prices that were market-based.

The Marathon Oil Companies performed certain services for us prior to the Spinoff such as executive oversight, accounting, treasury, tax, legal, procurement and information technology services. We also provided certain services to the Marathon Oil Companies prior to the Spinoff, such as legal, human resources and tax services. The two groups of companies charged each other for these shared services based on a rate that was negotiated between them. Where costs incurred by the Marathon Oil Companies on our behalf could not practically be determined by specific utilization, these costs were primarily allocated to us based on headcount or computer utilization. Our management believes those allocations were a reasonable reflection of the utilization of services provided. However, those allocations may not have fully reflected the expenses that would have been incurred had we been a stand-alone company during the periods presented. Net charges from the Marathon Oil Companies for these services reflected within selling, general and administrative expenses in the consolidated statements of income were $26 million and $43 million for 2011 and 2010, respectively.

Receivables from related parties, which are included in receivables, less allowance for doubtful accounts on the consolidated balance sheets, were as follows:

	December 31,
(In millions)	2012		2011
Centennial	$	2	$	1
Other equity method investees		-		1
Total	$	2	$	2

Payables to related parties, which are included in accounts payable on the consolidated balance sheets, were as follows:

	December 31,
(In millions)		2012		2011
Equity method investees:
Centennial	$	-	$	7
LOOP		4		5
TAME		5		4
TACE		2		2
Other equity method investees		2		2
Total	$	13	$	20

We have a throughput and deficiency agreement with LOOP, which had a prepaid tariff balance of $4 million at December 31, 2011. The prepaid tariff was utilized during 2012. We also had a throughput and deficiency agreement with Centennial, which expired on March 31, 2012. The prepaid balance was $11 million at December 31, 2011. Prepaid tariff balances are reflected in other noncurrent assets on the consolidated balance sheets. During 2012, we impaired our $14 million prepaid tariff with Centennial. For additional information on the impairment, see Note 18.

On July 18, 2007, we entered into a credit agreement with MOC Portfolio Delaware, Inc. (“PFD”), a subsidiary of Marathon Oil, providing for a $2.9 billion revolving credit facility which was scheduled to terminate on May 4, 2012. On October 28, 2010, we amended the credit agreement with PFD to increase the total amount available to $4.4 billion and extended the scheduled termination date to November 1, 2013. During 2011, we borrowed $7.75 billion and repaid $10.32 billion under the credit facility. During 2010, we borrowed $18.80 billion and repaid $17.54 billion under this credit facility. The agreement was terminated on June 30, 2011, and there has been no subsequent activity. For U.S. Dollar loans under this credit facility, the interest rate was the higher of the prime rate or the sum of 0.5 percent, plus the federal funds rate. For Euro Dollar loans under this credit facility, the interest rate was based on LIBOR plus a margin ranging from 0.25 percent to 1.125 percent. The margin varied based on our usage and credit rating.

On July 18, 2007, we entered into a $1.1 billion revenue bonds proceeds subsidiary loan agreement with Marathon Oil to finance a portion of our Garyville, Louisiana refinery major expansion project. Proceeds from the bonds were disbursed by Marathon Oil to us upon our request for reimbursement of expenditures related to the expansion. There were no borrowings in 2011 and 2010. We repaid the $1.05 billion loan balance on February 1, 2011 and the loan was terminated effective April 1, 2011. The loan had an interest rate of 5.125 percent annually.

In 2005, we entered into agreements with PFD to invest our excess cash. Such investments consisted of shares of PFD Redeemable Class A, Series 1 Preferred Stock (“PFD Preferred Stock”). We had the right to redeem all or any portion of the PFD Preferred Stock on any business day at $2,000 per share. Dividends on PFD Preferred Stock were declared and settled daily. All of our investments in PFD Preferred Stock were redeemed prior to the termination of this agreement on June 30, 2011.

Related party net interest and other financial income was as follows:

(In millions)	2012		2011		2010
Dividend income:
PFD Preferred Stock	$	-	$	35	$	24
Interest income		1		-		-
Interest expense:
PFD revolving credit agreement		-		3		12
Marathon Oil loan agreement		-		5		54
Interest capitalized		-		(8)		(66)
Net interest expense		-		-		-
Related party net interest and other financial income	$	1	$	35	$	24

We also recorded property, plant and equipment additions related to capitalized interest incurred by Marathon Oil on our behalf of $2 million and $20 million in 2011 and 2010, which were reflected as contributions from Marathon Oil.

Certain asset or liability transfers between us and Marathon Oil, including assets and liabilities contributed under the separation and distribution agreement related to the Spinoff, and certain expenses, such as stock-based compensation, incurred by Marathon Oil on our behalf have been recorded as non-cash capital contributions or distributions. The net non-cash capital contributions from (distributions to) Marathon Oil were $57 million and ($118 million) in 2011 and 2010, respectively.

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Acquisitions

12 Months Ended

Dec. 31, 2012

Acquisitions

6. Acquisitions

In July 2012, Speedway LLC acquired 10 convenience stores located in the northern Kentucky and southwestern Ohio regions from Road Ranger LLC in exchange for cash and a truck stop location in the Chicago metropolitan area. In connection with this acquisition, our Speedway segment recorded $5 million of goodwill, which is deductible for income tax purposes.

In May 2012, Speedway LLC acquired 87 convenience stores situated throughout Indiana and Ohio from GasAmerica Services, Inc., along with the associated inventory, intangible assets and two parcels of undeveloped real estate. In connection with this acquisition, our Speedway segment recorded $83 million of goodwill, which is deductible for income tax purposes.

In May 2011, Speedway LLC acquired 23 convenience stores in Indiana and Illinois. In connection with this acquisition, our Speedway segment recorded $9 million of goodwill, which is deductible for income tax purposes.

These acquisitions support our strategic initiative to increase our Speedway segment sales. The principal factors contributing to a purchase price resulting in goodwill included the acquired stores complementing our existing network in our Midwest market, access to our refined product transportation systems and the potential for higher merchandise sales.

Assuming these transactions had been made at the beginning of any period presented, the consolidated pro forma results would not be materially different from reported results.

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Supplementary Statistics (Operating Statistics) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012 MBPD		Dec. 31, 2011 MBPD		Dec. 31, 2010 MBPD
Operating Statistics [Line Items ]
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)	1,618	[1]	1,599	[1]	1,585	[1]
Refining & Marketing [Member]
Refinery Throughputs (thousands of barrels per day):
Crude oil refined	1,195		1,177		1,173
Other charge and blendstocks	168		181		162
Total	1,363		1,358		1,335
Crude Oil Capacity Utilization percent	100.00%	[2]	103.00%	[2]	99.00%	[2]
Refined Product Yields (thousands of barrels per day):
Gasoline	738		739		726
Distillates	433		433		409
Propane	26		25		24
Feedstocks and special products	109		109		97
Heavy fuel oil	18		21		24
Asphalt	62		56		76
Total	1,386		1,383		1,356
Refining & Marketing Refined Product Sales Volume (thousands of barrels per day)	1,599	[3]	1,581	[3]	1,573	[3]
Refining & Marketing Gross Margin (dollars per barrel)	10.45	[4]	7.75	[4]	2.81	[4]
Planned turnaround and major maintenance	1.00	[5]	0.78	[5]	1.19	[5]
Depreciation and amortization	1.44		1.29		1.32
Other manufacturing	3.15	[6]	3.16	[6]	3.32	[6]
Total	5.59		5.23		5.83
Speedway [Member]
Refined Product Yields (thousands of barrels per day):
Convenience stores at period-end	1,464		1,371		1,358
Gasoline & distillates sales (millions of gallons)	3,027		2,938		3,300
Gasoline & distillates gross margin (dollars per gallon)	0.1318	[7]	0.1308	[7]	0.1207	[7]
Merchandise sales (in millions)	3,058		2,924		3,195
Merchandise gross margin (in millions)	795		719		789
Same store gasoline sales volume (period over period)	(0.80%)		(1.70%)		3.00%
Same store merchandise sales (period over period)	0.90%		1.10%		4.40%
Same store merchandise sales excluding cigarettes (period over period)	7.00%		6.70%		6.20%
Pipeline Transportation [Member]
Pipeline throughput (thousands of barrels per day)(h):
Crude oil pipelines	1,190	[8]	1,184	[8]	1,204	[8]
Refined products pipelines	980	[8]	1,031	[8]	968	[8]
Total	2,170	[8]	2,215	[8]	2,172	[8]

[1] Total average daily volumes of refined product sales to wholesale, branded and retail (Speedway segment) customers.

[2] Based on calendar day capacity, which is an annual average that includes downtime for planned maintenance and other normal operating activities.

[3] Includes intersegment sales.

[4] Sales revenue less cost of refinery inputs, purchased products and manufacturing expenses, including depreciation and amortization, divided by Refining & Marketing segment refined product sales volume.

[5] Per barrel of total refinery throughputs.

[6] Includes utilities, labor, routine maintenance and other operating costs.

[7] The price paid by consumers less the cost of refined products, including transportation, consumer excise taxes and bankcard processing fees, divided by gasoline and distillates sales volume.

[8] On owned common-carrier pipelines, excluding equity method investments.

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Variable Interest Entity

12 Months Ended

Dec. 31, 2012

Variable Interest Entity

8. Variable Interest Entity

As described in Note 7, on December 1, 2010, we completed the sale of the Minnesota Assets. Certain terms of the transaction and the subsequent settlement agreement with the buyer resulted in the creation of variable interests in a variable interest entity (“VIE”) that owns the Minnesota Assets. At December 31, 2012, our variable interests in this VIE included our preferred security, which was reflected at $46 million in other noncurrent assets on our consolidated balance sheet at December 31, 2012, and store lease guarantees of $8 million. Our maximum exposure to loss due to this VIE at December 31, 2012 was $54 million.

We are not the primary beneficiary of this VIE and, therefore, do not consolidate it because we lack the power to control or direct the activities that impact the VIE’s operations and economic performance. Our preferred security does not allow us to appoint any members of the board of managers to the VIE and limits our voting ability to only certain matters. Also, individually and cumulatively, neither of our variable interests expose us to residual returns or expected losses that are significant to the VIE.

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Related Party Transactions (Purchases From Related Parties) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Related Party Transaction [Line Items]
Purchases from related parties	$ 280	$ 1,916	$ 2,593
Marathon Oil Companies [Member]
Related Party Transaction [Line Items]
Purchases from related parties		1,590	2,287
Centennial [Member]
Related Party Transaction [Line Items]
Purchases from related parties	7	31	72
LOOP [Member]
Related Party Transaction [Line Items]
Purchases from related parties	44	66	35
TAME [Member]
Related Party Transaction [Line Items]
Purchases from related parties	124	153	109
TACE [Member]
Related Party Transaction [Line Items]
Purchases from related parties	73	46	34
Other Equity Method Investees [Member]
Related Party Transaction [Line Items]
Purchases from related parties	$ 32	$ 30	$ 56

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Defined Benefit Pension And Other Postretirement Plans (Effects Of One Percentage Point Change In Assumed Health Care Cost Trend Rates) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Schedule Of Effect Of One Percentage Point Change In Assumed Health Care Cost Trend Rates [Line Items]
Effect on total of service and interest cost components, 1-Percentage-Point-Increase	$ 6
Effect on other postretirement benefit obligations, 1-Percentage-Point-Increase	32
Effect on total of service and interest cost components, 1-Percentage-Point Decrease	5
Effect on other postretirement benefit obligations, 1-Percentage-Point-Decrease	$ 28

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Income Taxes (Components Of Deferred Tax Assets And Liabilities) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Deferred tax assets:
Employee benefits	$ 585	$ 820
Other	90	73
Total deferred tax assets	675	893
Deferred tax liabilities:
Property, plant and equipment	2,225	1,936
Inventories	610	610
Investments in subsidiaries and affiliates	307	79
Other	29	25
Total deferred tax liabilities	3,171	2,650
Net deferred tax liabilities	$ 2,496	$ 1,757

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Related Party Transactions (Payables To Related Parties) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Payables to related parties	$ 13	$ 20
Centennial [Member]
Related Party Transaction [Line Items]
Payables to related parties		7
LOOP [Member]
Related Party Transaction [Line Items]
Payables to related parties	4	5
TAME [Member]
Related Party Transaction [Line Items]
Payables to related parties	5	4
TACE [Member]
Related Party Transaction [Line Items]
Payables to related parties	2	2
Other Equity Method Investees [Member]
Related Party Transaction [Line Items]
Payables to related parties	$ 2	$ 2

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Fair Value Measurements (Financial Instruments At Fair Value, Excluding Derivative Financial Instruments) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012		Dec. 31, 2011
Carrying Value [Member]
Financial assets:
Investments	$ 59		$ 93
Other	31		30
Total financial assets	90		123
Financial liabilities:
Long-term debt	3,006	[1]	3,008	[1]
Deferred credits and other liabilities	23		21
Total financial liabilities	3,029		3,029
Fair Value [Member]
Financial assets:
Investments	263		289
Other	33		31
Total financial assets	296		320
Financial liabilities:
Long-term debt	3,559	[1]	3,203	[1]
Deferred credits and other liabilities	23		21
Total financial liabilities	$ 3,582		$ 3,224

[1] Excludes capital leases.

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Related Party Transactions (Fees Received For Operating Pipelines For Related Parties) (Detail) (Centennial [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Centennial [Member]
Related Party Transaction [Line Items]
Operating pipeline revenue from related parties included in other income	$ 1

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Equity Method Investments (Summarized Financial Information For Equity Method Investees) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income statement data:
Revenues and other income	$ 1,025	$ 1,043	$ 939
Income from operations	73	128	196
Net income	47	101	170
Balance sheet data - December 31:
Current assets	217	256
Noncurrent assets	1,163	1,175
Current liabilities	161	126
Noncurrent liabilities	$ 636	$ 690

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Stock-Based Compensation Plans (Summary Of Values Related To Vested And Unvested Restricted Stock Awards) (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended		6 Months Ended	12 Months Ended			6 Months Ended	12 Months Ended
	Dec. 31, 2012 Restricted Stock [Member]	Dec. 31, 2011 Restricted Stock [Member]	Jun. 30, 2011 Restricted Stock [Member] Predecessor [Member]	Dec. 31, 2010 Restricted Stock [Member] Predecessor [Member]	Dec. 31, 2012 Restricted Stock Units [Member]	Dec. 31, 2011 Restricted Stock Units [Member]	Jun. 30, 2011 Restricted Stock Units [Member] Predecessor [Member]	Dec. 31, 2010 Restricted Stock Units [Member] Predecessor [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic Value of Awards Vesting During the Period	$ 5	$ 1	$ 3	$ 3
Weighted Average Grant Date Fair Value of Awards Granted During the Period	$ 43.11	$ 41.54	$ 48.53	$ 30.55	$ 44.38	$ 33.78	$ 45.22	$ 32.18

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Subsequent Event

12 Months Ended

Dec. 31, 2012

Subsequent Event

26. Subsequent Event

Acquisition of Refinery and Related Logistics and Marketing Assets

On February 1, 2013, we acquired from BP Products North America Inc. and BP Pipelines (North America) Inc. (collectively, “BP”) the 451,000 barrel per calendar day refinery in Texas City, Texas, three intrastate natural gas liquid pipelines originating at the refinery, an allocation of BP’s Colonial Pipeline Company shipper history, four light product terminals, branded-jobber marketing contract assignments for the supply of approximately 1,200 branded sites and a 1,040 megawatt electric cogeneration facility. The base purchase price was approximately $598 million plus inventories valued at approximately $900 million. Pursuant to the purchase and sale agreement, we may also be required to pay to BP a contingent earnout of up to an additional $700 million over six years, subject to certain conditions. These assets complement our current geographic footprint and align with our strategic initiative of growing in existing and contiguous markets to enhance our portfolio. The transaction was funded with cash on hand.

A determination of the acquisition-date fair values of the assets acquired and the liabilities assumed is pending the completion of an independent appraisal and other evaluations.

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2012

Summary Of Supplemental Cash Flow Information

(In millions)	2012		2011		2010
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	67	$	5	$	-
Income taxes paid to taxing authorities (a)		1,211		617		11
Non-cash investing and financing activities:
Property, plant and equipment contributed by Marathon Oil	$	-	$	81	$	-
Capital lease obligations increase		62		26		32
Preferred equity interest received in asset disposition (b)		-		-		80
Preferred equity interest received in contract settlement (b)		45		-		-
Preferred equity interest dividend received in-kind		1		-		-
Acquisition:
Intangible asset acquired		3		-		-
Liability assumed		2		-		-

^(a)  U.S. federal and most state income taxes, if incurred, were paid by Marathon Oil for periods prior to the Spinoff. The amount for 2012 includes payments of $181 million for 2011 return period income taxes made to Marathon Oil under our tax sharing agreement, and in return we received an equal amount of minimum tax credits. See Note 25.

^(b)  See Note 7.

Reconciliation Of Additions To Property, Plant And Equipment To Total Capital Expenditures

The consolidated statements of cash flows exclude changes to the consolidated balance sheets that did not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures:

(In millions)	2012		2011		2010
Additions to property, plant and equipment	$	1,369	$	1,185	$	1,217
Acquisitions (a)		180		74		-
Increase (decrease) in capital accruals		(117)		53		(51)
Total capital expenditures	$	1,432	$	1,312	$	1,166

^(a)  Excludes inventory acquired and liability assumed in 2012.

Reconciliation Of Contributions From (Distributions To) Marathon Oil

The following is a reconciliation of contributions from (distributions to) Marathon Oil:

(In millions)	2012		2011		2010
Distributions to Marathon Oil per consolidated statements of cash flows	$	-	$	(783)	$	(1,330)
Non-cash contributions from (distributions to) Marathon Oil		-		57		(118)
Distributions to Marathon Oil per consolidated statements of equity / net investment	$	-	$	(726)	$	(1,448)

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Income Taxes

12 Months Ended

Dec. 31, 2012

Income Taxes

13. Income Taxes

Income tax provisions (benefits) were:

	2012						2011						2010
(In millions)	Current		Deferred		Total		Current		Deferred		Total		Current		Deferred		Total
Federal	$	1,185	$	432	$	1,617	$	1,040	$	139	$	1,179	$	81	$	289	$	370
State and local		169		57		226		152		(16)		136		15		19		34
Foreign		(1)		3		2		15		-		15		(4)		-		(4)
Total	$	1,353	$	492	$	1,845	$	1,207	$	123	$	1,330	$	92	$	308	$	400

The provision for income taxes for periods prior to the Spinoff have been computed as if we were a stand-alone company.

A reconciliation of the federal statutory income tax rate (35 percent) applied to income before income taxes to the provision for income taxes follows:

	2012			2011			2010
Statutory rate applied to income before income taxes		35	%		35	%		35	%
State and local income taxes, net of federal income tax effects		2			2			3
Legislation(a)		-			-			2
Domestic manufacturing deduction		(1)			(1)			-
Effect of dividends received deduction		-			-			(1)
Other		(1)			-			-
Provision for income taxes		35	%		36	%		39	%

^(a)  The Patient Protection and Affordable Care Act (“PPACA”) and the Health Care and Education Reconciliation Act of 2010 were signed into law in March 2010. These new laws effectively changed the tax treatment of federal subsidies paid to sponsors of retiree health benefit plans that provide prescription drug benefits that are at least actuarially equivalent to the corresponding benefits provided under Medicare Part D. The federal subsidy paid to employers was introduced as part of the Medicare Prescription Drug, Improvement, and Modernization Act of 2003 (the “MPDIMA”). Under the MPDIMA, the federal subsidy did not reduce our income tax deduction for the costs of providing such prescription drug plans, nor was it subject to income tax individually. Beginning in 2013, under the 2010 legislation, our income tax deduction for the costs of providing Medicare Part D-equivalent prescription drug benefits to retirees will be reduced by the amount of the federal subsidy. As a result, we recorded a charge of $26 million in 2010 for the write-off of deferred tax assets to reflect the change in the tax treatment of the federal subsidy.

Deferred tax assets and liabilities resulted from the following:

	December 31,
(In millions)	2012		2011
Deferred tax assets:
Employee benefits	$	585	$	820
Other		90		73
Total deferred tax assets		675		893
Deferred tax liabilities:
Property, plant and equipment		2,225		1,936
Inventories		610		610
Investments in subsidiaries and affiliates		307		79
Other		29		25
Total deferred tax liabilities		3,171		2,650
Net deferred tax liabilities	$	2,496	$	1,757

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

	December 31,
(In millions)	2012		2011
Liabilities:
Accrued taxes	$	446	$	447
Deferred income taxes		2,050		1,310
Net deferred tax liabilities	$	2,496	$	1,757

MPC was a new taxpayer beginning in 2011. Prior to 2011, MPC was included in the Marathon Oil federal income tax returns for applicable years. Marathon Petroleum Company LP, a subsidiary of MPC, is continuously undergoing examination of its U.S. federal income tax returns by the Internal Revenue Service. 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. We believe all other audits will be resolved with the amounts paid and/or provided for these liabilities. As of December 31, 2012, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:

United States Federal	2010 - 2011
States	2004 - 2011

As a result of the Spinoff and pursuant to the tax sharing agreement by Marathon Oil and MPC, the unrecognized tax benefits related to MPC operations for which Marathon Oil was the taxpayer remain the responsibility of Marathon Oil and MPC has indemnified Marathon Oil. Before the Spinoff, MPC made a prepayment of a portion of the unrecognized tax benefits to Marathon Oil, which is reflected in the table below as settlements. See Note 25.

The following table summarizes the activity in unrecognized tax benefits:

(In millions)	2012		2011		2010
January 1 balance	$	20	$	14	$	19
Additions for tax positions of prior years		32		50		7
Reductions for tax positions of prior years		(6)		-		(1)
Settlements		(6)		(44)		(11)
December 31 balance	$	40	$	20	$	14

If the unrecognized tax benefits as of December 31, 2012 were recognized, $20 million would affect our effective income tax rate. There were $29 million of uncertain tax positions as of December 31, 2012 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 related to income taxes are recorded as part of the provision for income taxes. Such interest and penalties were net receipts (expenses) of $1 million, ($5 million) and ($1 million) in 2012, 2011 and 2010. As of December 31, 2012 and 2011, $9 million and $11 million of interest and penalties were accrued related to income taxes.

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Defined Benefit Pension And Other Postretirement Plans (Summary Of Defined Benefit Plans With Accumulated Benefit Obligations In Excess Of Plan Assets) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Pension Plan With Accumulated Benefit Obligation In Excess Of Fair Value Of Plan Assets [Line Items]
Projected benefit obligations	$ 2,192	$ 2,685
Accumulated benefit obligations	2,035	1,948
Fair value of plan assets	$ 1,478	$ 1,423

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Fair Value Measurements

12 Months Ended

Dec. 31, 2012

Fair Value Measurements

18. 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, 2012 and 2011 by fair value hierarchy level.

	December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Commodity derivative instruments, assets	$	49	$	-	$	-	$	84	$	133
Other assets		2		-		-		-		2
Total assets at fair value	$	51	$	-	$	-	$	84	$	135
Commodity derivative instruments, liabilities	$	(88)	$	-	$	-	$	-	$	(88)

	December 31, 2011
(In millions)	Level 1		Level 2		Level 3		Collateral		Total
Commodity derivative instruments, assets	$	26	$	1	$	-	$	107	$	134
Interest rate derivative instruments, assets		-		19		-		-		19
Other assets		2		-		-		-		2
Total assets at fair value	$	28	$	20	$	-	$	107	$	155
Commodity derivative instruments, liabilities	$	(45)	$	(1)	$	-	$	-	$	(46)

Commodity derivatives in Level 1 are exchange-traded contracts for crude oil and refined products measured at fair value with a market approach using the close-of-day settlement prices for the market. Collateral deposits in futures commission merchant accounts covered by master netting agreements related to Level 1 commodity derivatives are classified as Level 1 in the fair value hierarchy.

Commodity derivatives in Level 2 were measured at fair value with a market approach using monthly average close-of-day settlement prices for the market. Interest rate swap derivatives in Level 2 were measured at fair value using prices from Bloomberg L.P. and validated using market value information provided by the counterparties to the transactions.

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

(In millions)	2012		2011		2010
Beginning balance	$	-	$	2,402	$	865
Total realized and unrealized losses included in net income		(2)		-		(1)
Purchases of PFD Preferred Stock (a)		-		10,326		9,709
Redemptions of PFD Preferred Stock (a)		-		(12,730)		(8,019)
Settlements of derivative instruments		2		2		(2)
Distributions to Marathon Oil (b)		-		-		(150)
Ending balance	$	-	$	-	$	2,402

^(a)  For information on PFD Preferred Stock, see Note 5. The fair value of our PFD Preferred Stock investment was measured using an income approach since the securities were not publicly traded; therefore, they were classified as Level 3 in the fair value hierarchy.

^(b)  Due to the January 1, 2010 merger of two non-operating RM&T Business legal entities into Marathon Oil.

There were no unrealized gains or losses recorded in net income for the year ended December 31, 2012 related to Level 3 derivative instruments held during 2012. Net income for 2011 and 2010 included unrealized losses of less than $1 million and $1 million related to Level 3 derivative instruments held during those years. See Note 19 for the income statement impacts of our derivative instruments.

Fair Values – Nonrecurring

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

	Year Ended December 31,
	2012				2011				2010
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Long-lived assets held for sale	$	-	$	-	$	-	$	-	$	1	$	29
Other noncurrent assets		-		14		-		-		-		-

As a result of changing market conditions and declining throughput volumes, we impaired our Refining & Marketing segment’s prepaid tariff with Centennial by $14 million in 2012. The fair value measurement of the prepaid tariff was based on the income approach utilizing the probability of shipping sufficient volumes on Centennial’s pipeline over the remaining life of the throughput and deficiency credits, which expire March 31, 2014 if not utilized. This measurement is classified as Level 3.

As a result of changing market conditions, a maleic anhydride supply agreement with a major customer was revised in June 2010. An impairment of $29 million was recorded in 2010 for a plant that manufactured maleic anhydride. The plant was operated by our Refining & Marketing segment. The fair value of the plant was measured using a market approach based upon comparable area land values which are Level 3 inputs.

Fair Values – Reported

The following table summarizes financial instruments on the basis of their nature, characteristics and risk at December 31, 2012 and 2011, excluding the derivative financial instruments reported above.

	December 31,
	2012				2011
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial assets:
Investments	$	263	$	59	$	289	$	93
Other		33		31		31		30
Total financial assets	$	296	$	90	$	320	$	123
Financial liabilities:
Long-term debt (a)	$	3,559	$	3,006	$	3,203	$	3,008
Deferred credits and other liabilities		23		23		21		21
Total financial liabilities	$	3,582	$	3,029	$	3,224	$	3,029

^(a) Excludes capital leases

Our current assets and liabilities include financial instruments, the most significant of which are trade accounts receivable and payables. We believe the carrying values of our current assets and liabilities approximate fair value. Our fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments (e.g., less than 1 percent of our trade receivables and payables are outstanding for greater than 90 days), (2) our investment-grade credit rating and (3) our historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk.

Fair values of our financial assets included in investments and other financial assets and of our financial liabilities included in deferred credits and other liabilities are measured primarily 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. Other financial assets primarily consist of environmental remediation receivables. Deferred credits and other liabilities primarily consist of insurance liabilities and environmental remediation liabilities.

Fair value of long-term debt is measured using a market approach, based upon the average of quotes from major financial institutions and a third-party service for our debt. Because these quotes cannot be independently verified to the market, they are considered Level 3 inputs.

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Property, Plant And Equipment (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 19,409	$ 18,073
Property, plant and equipment, accumulated depreciation	6,766	5,845
Assets Held Under Capital Leases [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	417	267
Property, plant and equipment, accumulated depreciation	79	61
Construction In Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 520	$ 2,581

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Derivatives (Tables)

12 Months Ended

Dec. 31, 2012

Classification Of Gross Fair Values Of Derivative Instruments, Excluding Cash Collateral

The following table presents the gross fair values of derivative instruments, excluding cash collateral, and where they appear on the consolidated balance sheets as of December 31, 2012 and 2011:

	December 31, 2012
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	49	$	88	Other current assets
	December 31, 2011
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	26	$	45	Other current assets
Interest rate derivatives		19		-	Other noncurrent assets
Commodity derivatives		1		1	Other current liabilities

Pretax Effect Of Derivative Instruments Designated As Accounting Hedges Of Fair Value

The following table summarizes the pretax effect of derivative instruments designated as accounting hedges of fair value in our consolidated statements of income:

		Gain (Loss)
(In millions)	Income Statement Location	2012		2011		2010
Derivative
Interest rate	Net interest and other financial income (costs)	$	1	$	19	$	-
Hedged Item
Long-term debt	Net interest and other financial income (costs)	$	(1)	$	(19)	$	-

Open Commodity Derivative Contracts

The table below summarizes open commodity derivative contracts as of December 31, 2012.

	Position		Total Barrels   (In  thousands)
Crude oil(a)
Exchange-traded		Long		15,643
Exchange-traded		Short		(26,191	)
Refined Products(a)
Exchange-traded		Long		2,720
Exchange-traded		Short		(3,429	)

^(a)      100 percent of these contracts expire in the first quarter of 2013.

Effect Of Commodity Derivative Instruments In Statements Of Income

The following table summarizes the effect of all commodity derivative instruments in our consolidated statements of income:

(In millions)	Gain (Loss)
Income Statement Location	2012		2011		2010
Sales and other operating revenues	$	8	$	(34)	$	(1)
Other income		-		1		6
Cost of revenues		65		182		(28)
Total	$	73	$	149	$	(23)

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Derivatives (Pretax Effect Of Derivative Instruments Designated As Accounting Hedges Of Fair Value) (Detail) (Net Interest And Other Financial Income Costs [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Derivative [Member] | Interest Rate Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$ 1	$ 19
Hedged Item [Member] | Long-term Debt [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$ (1)	$ (19)

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2012

Income From Operations Attributable To Operating Segments

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
Year Ended December 31, 2012
Revenues:
Customer	$	67,921	$	14,239	$	77	$	82,237
Intersegment(a)		8,782		4		381		9,167
Related parties		7		-		1		8
Segment revenues		76,710		14,243		459		91,412
Elimination of intersegment revenues		(8,782)		(4)		(381)		(9,167)
Total revenues	$	67,928	$	14,239	$	78	$	82,245
Segment income from operations(b)	$	5,098	$	310	$	216	$	5,624
Income (loss) from equity method investments		(6)		-		32		26
Depreciation and amortization(c)		804		114		54		972
Capital expenditures and investments(d)(e)		705		340		211		1,256

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
Year Ended December 31, 2011
Revenues:
Customer	$	65,028	$	13,490	$	65	$	78,583
Intersegment(a)		8,301		-		335		8,636
Related parties		52		-		3		55
Segment revenues		73,381		13,490		403		87,274
Elimination of intersegment revenues		(8,301)		-		(335)		(8,636)
Total revenues	$	65,080	$	13,490	$	68	$	78,638
Segment income from operations	$	3,591	$	271	$	199	$	4,061
Income from equity method investments		11		-		39		50
Depreciation and amortization(c)		718		110		45		873
Capital expenditures and investments(d)(f)		900		164		121		1,185

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
Year Ended December 31, 2010
Revenues:
Customer	$	49,844	$	12,494	$	49	$	62,387
Intersegment(a)		7,394		-		347		7,741
Related parties		95		-		5		100
Segment revenues		57,333		12,494		401		70,228
Elimination of intersegment revenues		(7,394)		-		(347)		(7,741)
Total revenues	$	49,939	$	12,494	$	54	$	62,487
Segment income from operations	$	800	$	293	$	183	$	1,276
Income from equity method investments		9		-		61		70
Depreciation and amortization(c)		739		111		62		912
Capital expenditures and investments(d)		961		84		24		1,069

^(a)  Management believes intersegment transactions were conducted under terms comparable to those with unaffiliated parties.

^(b)  Included in the Pipeline Transportation segment are $4 million of corporate overhead costs and pension settlement expenses attributable to MPLX subsequent to MPLX’s October 31, 2012 initial public offering, which were included in items not allocated to segments prior to MPLX’s initial public offering. These expenses are not currently allocated to other segments.

^(c)  Differences between segment totals and MPC totals represent amounts related to unallocated items and are included in “Items not allocated to segments” in the reconciliation below.

^(d)  Capital expenditures include changes in capital accruals.

^(e)  Includes Speedway’s acquisition of 97 convenience stores in 2012.

^(f)  Includes Speedway’s acquisition of 23 convenience stores in 2011.

Reconciliation Of Segment Income From Operations To Income Before Income Taxes

The following reconciles segment income from operations to income before income taxes as reported in the consolidated statements of income:

(In millions)	2012			2011			2010
Segment income from operations	$	5,624		$	4,061		$	1,276
Items not allocated to segments:
Corporate and other unallocated items(a)(b)		(336	)		(316	)		(236	)
Minnesota Assets sale settlement gain(c)		183			-			-
Pension settlement expenses(b)(d)		(124	)		-			-
Impairment(e)		-			-			(29	)
Net interest and other financial income (costs)(f)		(109	)		(26	)		12
Income before income taxes	$	5,238		$	3,719		$	1,023

^(a)  Corporate and other unallocated items consists primarily of MPC’s corporate administrative expenses, including allocations from the Marathon Oil Companies for periods prior to the Spinoff and costs related to certain non-operating assets.

^(b)  Corporate overhead costs and pension settlement expenses attributable to MPLX were included in the Pipeline Transportation segment subsequent to MPLX’s October 31, 2012 initial public offering.

^(c)  See Note 7.

^(d)  See Note 22.

^(e)  See Note 18.

^(f)  Includes related party net interest and other financial income.

Reconciliation Of Segment Capital Expenditures And Investments To Total Capital Expenditures

The following reconciles segment capital expenditures and investments to total capital expenditures:

(In millions)	2012		2011		2010
Segment capital expenditures and investments	$	1,256	$	1,185	$	1,069
Less: Investments in equity method investees		28		11		7
Plus: Items not allocated to segments:
Capital expenditures not allocated to segments		103		24		1
Capitalized interest		101		114		103
Total capital expenditures(a)(b)	$	1,432	$	1,312	$	1,166

^(a)  Capital expenditures include changes in capital accruals.

^(b)  See Note 21 for a reconciliation of total capital expenditures to additions to property, plant and equipment as reported in the consolidated statements of cash flows.

Reconciliation Of Total Revenues To Sales And Other Operating Revenues

The following reconciles total revenues to sales and other operating revenues (including consumer excise taxes) as reported in the consolidated statements of income:

(In millions)	2012		2011		2010
Total revenues (as reported above)	$	82,245	$	78,638	$	62,487
Plus: Corporate and other unallocated items		(2)		-		-
Less: Sales to related parties		8		55		100
Sales and other operating revenues (including consumer excise taxes)	$	82,235	$	78,583	$	62,387

Schedule Of Revenues By Product Line

Revenues by product line were:

(In millions)	2012		2011		2010
Refined products	$	76,234	$	73,334	$	56,025
Merchandise		3,229		3,090		3,369
Crude oil and refinery feedstocks		2,514		1,972		2,890
Transportation and other		266		242		203
Total revenues		82,243		78,638		62,487
Less: Sales to related parties		8		55		100
Sales and other operating revenues (including consumer excise taxes)	$	82,235	$	78,583	$	62,387

Total Assets by Reportable Segment

Total assets by reportable segment were:

	December 31,
(In millions)	2012		2011
Refining & Marketing	$	17,052	$	17,294
Speedway		1,947		1,597
Pipeline Transportation		1,950		1,556
Corporate and Other		6,274		5,298
Total consolidated assets	$	27,223	$	25,745

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Derivatives (Effect Of Commodity Derivative Instruments In Statements Of Income) (Detail) (Commodity Derivatives [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ 73	$ 149	$ (23)
Sales And Other Operating Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	8	(34)	(1)
Other Income [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)		1	6
Cost Of Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ 65	$ 182	$ (28)

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2012	Dec. 31, 2011
Assets
Cash and cash equivalents	$ 4,860	$ 3,079
Receivables, less allowance for doubtful accounts of $10 and $3	4,610	5,461
Inventories	3,449	3,320
Other current assets	110	141
Total current assets	13,029	12,001
Equity method investments	321	302
Property, plant and equipment, net	12,643	12,228
Goodwill	930	842
Other noncurrent assets	300	372
Total assets	27,223	25,745
Liabilities
Accounts payable	6,785	8,189
Payroll and benefits payable	364	312
Consumer excise taxes payable	325	337
Accrued taxes	598	558
Long-term debt due within one year	19	15
Other current liabilities	112	180
Total current liabilities	8,203	9,591
Long-term debt	3,342	3,292
Deferred income taxes	2,050	1,310
Defined benefit postretirement plan obligations	1,266	1,783
Deferred credits and other liabilities	257	264
Total liabilities	15,118	16,240
Commitments and contingencies (see Note 25)
Equity
Preferred stock, no shares issued and outstanding (par value $0.01 per share, 30 million shares authorized)
Common stock: Issued - 361 million and 357 million shares (par value $0.01 per share, 1 billion shares authorized)	4	4
Held in treasury, at cost - 28 million shares at December 31, 2012	(1,253)
Additional paid-in capital	9,527	9,482
Retained earnings	3,880	898
Accumulated other comprehensive loss	(464)	(879)
Total MPC stockholders' equity	11,694	9,505
Noncontrolling interests	411
Total equity	12,105	9,505
Total liabilities and equity	$ 27,223	$ 25,745

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Income Taxes (Summary Of Activity In Unrecognized Tax Benefits) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Tax Contingency [Line Items]
January 1 balance	$ 20	$ 14	$ 19
Additions for tax positions of prior years	32	50	7
Reductions for tax positions of prior years	(6)		(1)
Settlements	(6)	(44)	(11)
December 31 balance	$ 40	$ 20	$ 14

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Summary Of Principal Accounting Policies

12 Months Ended

Dec. 31, 2012

Summary Of Principal Accounting Policies

2. Summary of Principal Accounting Policies

Principles applied in consolidation – These consolidated financial statements include the accounts of our majority-owned, controlled subsidiaries.    We consolidate MPLX, in which we own a 73.6 percent controlling financial interest, and we record a noncontrolling interest for the 26.4 percent interest owned by the public.

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 shareholders have substantive participating rights in the investee.    Income from equity method investments represents our proportionate share of net income generated by the equity method investees.

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 values 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.

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.

Revenue recognition – Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured.    Costs associated with revenues are recorded in cost of revenues.    Shipping and other transportation costs billed to customers are presented on a gross basis in revenues and cost of revenues.

Rebates from vendors are recognized as a reduction of cost of revenues when the initiating transaction occurs.    Incentives that are derived from contractual provisions are accrued based on past experience and recognized in cost of revenues.

Crude oil and refined product exchanges and matching buy/sell transactions – We enter into exchange contracts and matching buy/sell arrangements whereby we agree to deliver a particular quantity and quality of crude oil or refined products at a specified location and date to a particular counterparty and to receive from the same counterparty the same commodity at a specified location on the same or another specified date.    The exchange receipts and deliveries are nonmonetary transactions, with the exception of associated grade or location differentials that are settled in cash.    The matching buy/sell purchase and sale transactions are settled in cash.    Both exchange and matching buy/sell transactions are accounted for as exchanges of inventory and no revenues are recorded.    The exchange transactions are recognized at the carrying amount of the inventory transferred.

Consumer excise taxes – We are required by various governmental authorities, including countries, states and municipalities, to collect and remit taxes on certain consumer products.    Such taxes are presented on a gross basis in revenues and costs and expenses in the consolidated statements of income.

Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit, reverse repurchase agreements and investments in highly liquid debt instruments with maturities generally of three months or less.

Accounts receivable and allowance for doubtful accounts – Our receivables primarily consist of customer accounts receivable, including proprietary credit card receivables.    The allowance for doubtful accounts is the best estimate of the amount of probable credit losses in customer accounts receivable, primarily associated with our proprietary credit card receivables.    We determine the allowance based on historical write-off experience and the volume of proprietary credit card sales.    We review the allowance quarterly and past-due balances over 180 days are reviewed individually for collectability.    All other customer receivables are recorded at the invoiced amounts and generally do not bear interest.    Account balances for these customer receivables are generally charged directly to bad debt expense when it becomes probable the receivable will not be collected.

Approximately 42 percent and 47 percent of our accounts receivable balances at December 31, 2012 and 2011, respectively, are related to sales of crude oil or refinery feedstocks to customers with whom we have master netting agreements.    We have master netting agreements with more than 80 companies engaged in the crude oil or refinery feedstock trading and supply business or the petroleum refining industry.    A master netting agreement generally provides for a once per month net cash settlement of the accounts receivable from and the accounts payable to a particular counterparty.

Inventories – Inventories are carried at the lower of cost or market value.    Cost of inventories is determined primarily under the last-in, first-out (“LIFO”) method.

Derivative instruments – We use derivatives to economically hedge a portion of our exposure to commodity price risk and interest rate risk.    We also have limited authority to use selective derivative instruments that assume market risk.    All derivative instruments are recorded at fair value.    Commodity derivatives are reflected on the consolidated balance sheets on a net basis by futures commission merchant, as they are governed by master netting agreements.    Cash flows related to derivatives used to hedge commodity price risk and interest rate risk are classified in operating activities with the underlying transactions.

Fair value accounting hedges – We used interest rate swaps to hedge our exposure to interest rate risk associated with fixed interest rate debt in our portfolio.    Changes in the fair values of both the hedged item and the related derivative were recognized immediately in net income with an offsetting effect included in the basis of the hedged item.    The net effect was to report in net income the extent to which the accounting hedge was not effective in achieving offsetting changes in fair value.    We terminated our interest rate swap agreements during 2012.    There was a gain on the termination of the agreements, which has been accounted for as an adjustment to our long-term debt balance.    The gain is being amortized over the remaining life of the associated debt, which reduces our interest expense.

Derivatives not designated as accounting hedges –Derivatives that are not designated as accounting hedges may include commodity derivatives used to hedge price risk on (1) inventories, (2) fixed price sales of refined products, (3) the acquisition of foreign-sourced crude oil and (4) the acquisition of ethanol for blending with refined products.    Changes in the fair value of derivatives not designated as accounting hedges are recognized immediately in net income.

Contingent credit features – Our derivative instruments contain no significant contingent credit features.

Concentrations of credit risk – All of our financial instruments, including derivatives, involve elements of credit and market risk.    The most significant portion of our credit risk relates to 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 an assessment of their financial strength and on credit ratings, if available.    Additionally, we limit the level of exposure with any single counterparty.

Property, plant and equipment – Property, plant and equipment are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which range from four to 42 years.    Such assets are reviewed for impairment 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.

When items of property, plant and equipment 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.

Interest expense is capitalized for qualifying assets under construction.    Capitalized interest costs are included in property, plant and equipment and are depreciated over the useful life of the related asset.

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.    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, the implied fair value of goodwill is calculated.    The excess, if any, of the book value over the implied fair value of goodwill is charged to net income.

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

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

Asset retirement obligations – The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made.    Conditional asset retirement obligations for removal and disposal of fire-retardant material from certain refining facilities have been recognized.    The fair values recorded for such obligations are based on the most probable current cost projections.    The recorded asset retirement obligations are not material to the consolidated financial statements.

Asset retirement obligations have not been recognized for some assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate.    Such obligations will be recognized in the period when sufficient information becomes available to estimate a range of potential settlement dates.    The asset retirement obligations principally include the removal of underground storage tanks at our owned and some of our leased convenience stores at or near the time of closure and hazardous material disposal and removal or dismantlement requirements associated with the closure of certain refining, terminal and pipeline assets.

Our practice is to keep our assets in good operating condition through routine repair and maintenance of component parts in the ordinary course of business and by continuing to make improvements based on technological advances.    As a result, we believe that these assets have no expected settlement date for purposes of estimating asset retirement obligations since the dates or ranges of dates upon which we would retire these assets cannot be reasonably estimated at this time.

Income taxes – For periods prior to the Spinoff, our taxable income was included in the consolidated U.S. federal income tax returns of Marathon Oil and in a number of consolidated state income tax returns.    In the accompanying consolidated financial statements, for periods prior to the Spinoff our provision for income taxes was computed as if we were a stand-alone tax-paying entity.

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.    Deferred tax assets are recorded when it is more likely than not that they will be realized.    The realization of deferred tax assets is assessed periodically based on several factors, primarily our expectation to generate sufficient future taxable income.

Stock-based compensation arrangements – The fair value of stock options and stock-settled stock appreciation rights (collectively, “stock option awards”) granted to our employees is estimated on the date of grant using the Black-Scholes option pricing model.    The model employs various assumptions, based on management’s estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the vesting period 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.    The average expected life is based on our historical employee exercise behavior.    The assumption for expected volatility of our stock price reflects a weighting of 25 percent of our common stock volatility and 75 percent of the historical volatility for a selected group of peer companies.

The fair value of restricted stock awards granted to our employees is determined based on the fair market value of our common stock on the date of grant.

Our stock-based compensation expense is recognized based on management’s estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature.    If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods.    Unearned stock-based compensation is charged to equity when restricted stock awards are granted.    Compensation expense is recognized over the vesting period and is adjusted if conditions of the restricted stock award are not met.    For periods prior to the Spinoff, we recorded Marathon Oil stock-based compensation expense as non-cash capital contributions.

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Summary Of Principal Accounting Policies (Detail)	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011
Summary Of Principal Accounting Policies [Line Items]
Accounts receivable number of days past-due evaluated for doubtful accounts	180 days
Number of companies engaged in crude oil or refinery feedstock trading agreement	80
Share-based compensation arrangement by share-based payment award fair value assumptions expected volatility rate - Company stock weighting (in percentage)	25.00%
Share-based compensation arrangement by share-based payment award fair value assumptions expected volatility rate - Peer stock weighting (in percentage)	75.00%
MPLX LP [Member] | Noncontrolling Interests [Member]
Summary Of Principal Accounting Policies [Line Items]
Percentage of noncontrolling interest (in percentage)	26.40%
MPLX LP [Member] | General Partner and Limited Partner [Member]
Summary Of Principal Accounting Policies [Line Items]
MPC's partnership interest in MPLX (in percentage)	73.60%
Accounts Receivable With Master Netting Arrangements [Member] | Customer Concentration Risk [Member]
Summary Of Principal Accounting Policies [Line Items]
Percentage of accounts receivable related to sales of crude oil refinery feed stocks to customers with master netting agreements	42.00%	47.00%
Minimum [Member]
Summary Of Principal Accounting Policies [Line Items]
Estimated useful lives	4 years
Maximum [Member]
Summary Of Principal Accounting Policies [Line Items]
Estimated useful lives	42 years

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Income Taxes (Components Of Income Tax Provisions (Benefits)) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Income Taxes [Line Items]
Federal, Current	$ 1,185	$ 1,040	$ 81
State and local, Current	169	152	15
Foreign, Current	(1)	15	(4)
Current income tax provisions	1,353	1,207	92
Federal, Deferred	432	139	289
State and local, Deferred	57	(16)	19
Foreign, Deferred	3
Deferred Income tax provisions	492	123	308
Federal Income tax provisions (benefits)	1,617	1,179	370
State and local Income tax provisions (benefits)	226	136	34
Foreign Income tax provisions (benefits)	2	15	(4)
Income tax provisions (benefits)	$ 1,845	$ 1,330	$ 400

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Derivatives (Open Commodity Derivative Contracts) (Detail)	12 Months Ended
	Dec. 31, 2012
Crude Oil Exchange-Traded [Member]
Derivative [Line Items]
Percentage of derivative contracts expiring in the period	100.00%
Derivative contract expiration date	Mar. 31, 2013
Crude Oil Exchange-Traded [Member] | Long [Member]
Derivative [Line Items]
Notional Contracts (in thousands of Total Barrels)	15,643,000	[1]
Crude Oil Exchange-Traded [Member] | Short [Member]
Derivative [Line Items]
Notional Contracts (in thousands of Total Barrels)	(26,191,000)	[1]
Refined Products Exchange-Traded [Member]
Derivative [Line Items]
Percentage of derivative contracts expiring in the period	100.00%
Derivative contract expiration date	Mar. 31, 2013
Refined Products Exchange-Traded [Member] | Long [Member]
Derivative [Line Items]
Notional Contracts (in thousands of Total Barrels)	2,720,000	[1]
Refined Products Exchange-Traded [Member] | Short [Member]
Derivative [Line Items]
Notional Contracts (in thousands of Total Barrels)	(3,429,000)	[1]

[1] 100 percent of these contracts expire in the first quarter of 2013.

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Disposition (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended					1 Months Ended		12 Months Ended		1 Months Ended			1 Months Ended
	Dec. 31, 2012		Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2012 Variable Interest Entity [Member]	Jul. 31, 2012 Variable Interest Entity [Member] Minnesota Assets Sale Settlement Gain [Member]	Dec. 01, 2010 Variable Interest Entity [Member] Minnesota Assets Sale Settlement Gain [Member] BPD	Dec. 31, 2012 Variable Interest Entity [Member] Minnesota Assets Sale Settlement Gain [Member]	Dec. 31, 2011 Variable Interest Entity [Member] Minnesota Assets Sale Settlement Gain [Member]	Dec. 01, 2010 Variable Interest Entity [Member] Minnesota Assets Sale Settlement Gain [Member] Maximum [Member]	Dec. 01, 2010 Variable Interest Entity [Member] Super America [Member] Store	Dec. 01, 2010 Variable Interest Entity [Member] Wisconsin [Member] Store	Dec. 01, 2010 Scenario, Forecast [Member] Variable Interest Entity [Member] Minnesota Assets Sale Settlement Gain [Member] Maximum [Member]
Dispositions Of Assets [Line Items]
Refinery capacity, barrel-per-day							74,000
Number of convenience stores disposed											166	6
Approximate transaction value							$ 935
Sale of assets, value of inventory							330
Cash proceeds, total						132	740
Preferred equity interest							80
Maximum provision payable amount, total													125
Maximum provision payable amount, years										8 years
Margin support payable to the buyer, maximum										60
Margin support payable to the buyer, years										2 years
Margin support payable to the buyer, per year													30
Receivable due from buyer									107
Guarantees with a maximum exposure							11
Deferred gain from sale							89	86
Buyer redeemed preferred equity interest	53		144	763		80
Cash proceeds, dividends on preferred equity interest						12
Cash proceeds, distribution from VIE's offering						40
Preferred equity interest	45	[1]				45
Income before income taxes recognized by the company as a result of the Minnesota Assets' successful IPO								$ 183
Transition services following disposal, term (in number of months)					13 months

[1] See Note 7.

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Derivatives

12 Months Ended

Dec. 31, 2012

Derivatives

19. Derivatives

For further information regarding the fair value measurement of derivative instruments, see Note 18. See Note 2 for a discussion of the types of derivatives we use and the reasons for them. We do not designate any of our commodity derivative instruments as hedges for accounting purposes. Our interest rate derivative instruments were designated as fair value accounting hedges.

The following table presents the gross fair values of derivative instruments, excluding cash collateral, and where they appear on the consolidated balance sheets as of December 31, 2012 and 2011:

	December 31, 2012
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	49	$	88	Other current assets
	December 31, 2011
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	26	$	45	Other current assets
Interest rate derivatives		19		-	Other noncurrent assets
Commodity derivatives		1		1	Other current liabilities

Derivatives Designated as Fair Value Accounting Hedges

In 2012, we terminated interest rate swap agreements with a notional amount of $500 million that had been entered into as fair value accounting hedges on our 3.50 percent senior notes due in March 2016. There was a $20 million gain on the termination of the transactions, which has been accounted for as an adjustment to our long-term debt balance. The gain is being amortized over the remaining life of the 3.50 percent senior notes, which reduces our interest expense. The interest rate swaps had no accounting hedge ineffectiveness.

The following table summarizes the pretax effect of derivative instruments designated as accounting hedges of fair value in our consolidated statements of income:

		Gain (Loss)
(In millions)	Income Statement Location	2012		2011		2010
Derivative
Interest rate	Net interest and other financial income (costs)	$	1	$	19	$	-
Hedged Item
Long-term debt	Net interest and other financial income (costs)	$	(1)	$	(19)	$	-

Derivatives not Designated as Accounting Hedges

Derivatives that are not designated as accounting hedges may include commodity derivatives used to hedge price risk on (1) inventories, (2) fixed price sales of refined products, (3) the acquisition of foreign-sourced crude oil and (4) the acquisition of ethanol for blending with refined products.

The table below summarizes open commodity derivative contracts as of December 31, 2012.

	Position		Total Barrels   (In  thousands)
Crude oil(a)
Exchange-traded		Long		15,643
Exchange-traded		Short		(26,191	)
Refined Products(a)
Exchange-traded		Long		2,720
Exchange-traded		Short		(3,429	)

^(a)      100 percent of these contracts expire in the first quarter of 2013.

The following table summarizes the effect of all commodity derivative instruments in our consolidated statements of income:

(In millions)	Gain (Loss)
Income Statement Location	2012		2011		2010
Sales and other operating revenues	$	8	$	(34)	$	(1)
Other income		-		1		6
Cost of revenues		65		182		(28)
Total	$	73	$	149	$	(23)

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Defined Benefit Pension And Other Postretirement Plans (Components Of Net Periodic Benefit Cost And Other Comprehensive Loss) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012		Dec. 31, 2011		Dec. 31, 2010
Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	$ 66		$ 65		$ 62
Interest cost	94		110		105
Expected return on plan assets	(104)		(97)		(95)
Amortization - prior service cost (credit)	(18)		6		7
Amortization - actuarial loss	93		71		51
Amortization - net settlement/curtailment loss	125	[1]	8	[1]	13	[1]
Net periodic benefit cost	256	[2]	163	[2]	143	[2]
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial loss	46		427		129
Prior service credit	(520)	[3]
Amortization of actuarial (loss) gain	(218)		(79)		(64)
Amortization of prior service cost (credit)	18		(6)		(7)
Other			6	[4]
Total recognized in other comprehensive loss	(674)		348		58
Total recognized in net periodic benefit cost and other comprehensive loss	(418)		511		201
Other Benefits [Member]
Components of net periodic benefit cost:
Service cost	20		19		14
Interest cost	24		27		24
Amortization - prior service cost (credit)	(2)				1
Amortization - actuarial loss	2				(2)
Net periodic benefit cost	44	[2]	46	[2]	37	[2]
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial loss	53		39		61
Prior service credit	(40)	[3]
Amortization of actuarial (loss) gain	(2)				2
Amortization of prior service cost (credit)	2				(1)
Total recognized in other comprehensive loss	13		39		62
Total recognized in net periodic benefit cost and other comprehensive loss	$ 57		$ 85		$ 99

[1] A curtailment gain was recorded in 2011 on the Speedway pension plan at the end of the transition services period related to the sale of most of our Minnesota Assets in 2010. See Note 7.

[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 adjustments due to changes made to the defined pension plans and the post-65 medical plan coverage effective January 1, 2013.

[4] Includes adjustments related to the Spinoff.

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Stock-Based Compensation Plans (Summary Of Performance Unit Awards) (Detail) (Performance Unit Awards [Member])	12 Months Ended
	Dec. 31, 2012
Performance Unit Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding at December 31, 2011
Granted	2,040,000
Settled
Canceled
Outstanding at December 31, 2012	2,040,000

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Stock-Based Compensation Plans (Weighted Average Assumptions Used To Value Stock Options Awards) (Detail) (USD $)	6 Months Ended	12 Months Ended	6 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2012	Jun. 30, 2011 Predecessor [Member]	Dec. 31, 2010 Predecessor [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average exercise price per share	$ 36.18	$ 42.02	$ 51.93	$ 30.12
Expected annual dividends per share	$ 0.95	$ 1.00	$ 1.00	$ 0.97
Expected life in years	5 years 9 months 18 days	5 years 9 months 18 days	5 years 3 months 18 days	5 years 1 month 6 days
Expected volatility	48.00%	47.00%	40.00%	41.00%
Risk-free interest rate	1.40%	1.10%	2.00%	2.20%
Weighted average grant date fair value of stock option awards granted	$ 13.08	$ 14.45	$ 16.73	$ 8.72

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Segment Information (Narrative) (Detail)	12 Months Ended
	Dec. 31, 2012 Segment	Dec. 31, 2010
Schedule Of Assets By Segment [Line Items]
Number of reportable segments	3
Disposal date of Minnesota Assets		Dec. 01, 2010
None [Member]
Schedule Of Assets By Segment [Line Items]
Percent of annual revenues	10.00%

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MPLX LP (Tables)

12 Months Ended

Dec. 31, 2012

Summary Of Reconciliation Of Proceeds From Initial Public Offering

The following table is a reconciliation of proceeds from the initial public offering:

(In millions)
Total proceeds from the initial public offering	$	438
Less: Offering Costs		(31)
Net proceeds from the initial public offering		407
Less: Revolving credit facility origination fees		(2)
Less: Cash retained by MPLX		(10)
Less: Cash contribution to Pipe Line Holdings		(192)
Net proceeds distributed to MPC from the initial public offering	$	203

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Other Items

12 Months Ended

Dec. 31, 2012

Other Items

12. Other Items

Net interest and other financial income (costs) was:

(In millions)	2012		2011		2010
Interest:
Interest income	$	5	$	3	$	2
Interest expense(a)		(191)		(164)		(18)
Interest capitalized(a)		101		104		17
Total interest		(85)		(57)		1
Other:
Net foreign currency gains (losses)		-		12		(6)
Bank service and other fees		(25)		(16)		(7)
Total other		(25)		(4)		(13)
Net interest and other financial income (costs)	$	(110)	$	(61)	$	(12)

^(a)  See Note 5 for information on related party interest expense and capitalized interest.

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Fair Value Measurements (Assets Measured At Fair Value On Nonrecurring Basis) (Detail) (Fair Value, Measurements, Nonrecurring [Member], USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-lived assets held for sale, Fair Value			$ 1
Long-lived assets held for sale, Impairment			29
Other noncurrent assets, Fair Value
Other noncurrent assets, Impairment	$ 14