10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2013

Commission file number 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 28, 2013 was approximately $22.5 billion. This amount is based on the closing price of the registrant’s Common Stock on the New York Stock Exchange on June 28, 2013. 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 294,564,231 shares of Marathon Petroleum Corporation Common Stock outstanding as of February 14, 2014.

Documents Incorporated By Reference

Portions of the registrant’s proxy statement relating to its 2014 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	24
	Item 1B.	Unresolved Staff Comments	32
	Item 2.	Properties	32
	Item 3.	Legal Proceedings	32
	Item 4.	Mine Safety Disclosures	33
PART II
	Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	34
	Item 6.	Selected Financial Data	35
	Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	36
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	64
	Item 8.	Financial Statements and Supplementary Data	67
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	122
	Item 9A.	Controls and Procedures	122
	Item 9B.	Other Information	122
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	123
	Item 11.	Executive Compensation	123
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	124
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	124
	Item 14.	Principal Accountant Fees and Services	124
PART IV
	Item 15.	Exhibits and Financial Statement Schedules	125
		SIGNATURES	129

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,” “will,” “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, operating costs, 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;

• business strategies, growth opportunities and expected investments, including planned equity investments in pipeline projects;

• expectations regarding the acquisition or divestiture of assets;

• our share repurchase authorizations, 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:

• volatility or degradation in general economic, market, industry or business conditions;

• availability and pricing of 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;

• availability and pricing of 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;

• completion of pipeline projects within the U.S.;

• 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;

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

• the ability to realize the strategic benefits of joint venture 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;

• state and federal environmental, economic, health and safety, energy and other policies and regulations, including the cost of compliance with the Renewable Fuel Standard;

• 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 authorizations;

• 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. We have 126 years of experience in the energy business with roots tracing back to the formation of the Ohio Oil Company in 1887. 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, 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, buyers on the spot market, our Speedway^® business segment and to independent entrepreneurs 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 10 for operating segment and geographic financial information, which is incorporated herein by reference.

Corporate History and Structure

MPC was incorporated in 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.”

Recent Developments

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, four light product terminals, branded-jobber marketing contract assignments for the supply of approximately 1,200 branded sites, a 1,040 megawatt electric cogeneration facility and a 50 thousand barrels per day ("mbpd") allocation of space on the Colonial Pipeline. 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 for time periods prior to the acquisition. See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on the acquisition of these assets.

On August 1, 2013, we acquired from Mitsui & Co. (U.S.A.), Inc. its interests in three ethanol companies for $75 million. Under the purchase agreement, we acquired an additional 24 percent interest in The Andersons Clymers Ethanol LLC ("TACE"), bringing our ownership interest to 60 percent; a 34 percent interest in The Andersons Ethanol Investment LLC ("TAEI"), which holds a 50 percent ownership in The Andersons Marathon Ethanol LLC ("TAME"), bringing our direct and indirect ownership interest in TAME to 67 percent; and a 40 percent interest in The Andersons Albion Ethanol LLC ("TAAE"), which owns an ethanol production facility in Albion, Michigan. On October 1, 2013, our ownership interest in TAAE increased to 43 percent as a result of TAAE acquiring one of the owner's interest. We hold a noncontrolling interest in each of these entities and account for them using the equity method of accounting since the minority owners have substantive participating rights.

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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 percent interest in MPLX, including the two percent 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 assets as of December 31, 2013 consisted of a 56 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 44 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.

On February 27, 2014, we announced that an additional 13 percent of Pipe Line Holdings will be sold to MPLX effective on March 1, 2014 for $310 million. Subsequent to this transaction, MPLX will own a 69 percent general partner interest in Pipe Line Holdings and we will own a 31 percent limited partner interest. MPLX intends to finance this transaction with $40 million of cash on-hand and by borrowing $270 million on its revolving credit agreement.

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, 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 oil, and produce transportation fuels such as gasoline and distillates, specialty chemicals and other refined products.

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 various United States shale oil regions and Canadian crude oil supply sources allows our refineries access to price-advantaged crude oils and lower transportation costs than certain of our competitors. 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.

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* As of December 31, 2013

Extensive Midstream Distribution Networks

Our assets give us extensive flexibility and optionality to respond promptly to dynamic market conditions, including weather-related and marketplace disruptions. 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. 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.

Attractive Growth Opportunities

We believe we have attractive growth opportunities. Over the next three years, we expect to invest approximately $630 million in midstream assets that are part of our Refining & Marketing segment, approximately $2.3 billion in our Pipeline Transportation segment and approximately $925 million to grow our Speedway segment. Our Refining & Marketing segment's midstream investments include increasing our capacity to process condensate from the Utica Shale region at our Canton, Ohio

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and Catlettsburg, Kentucky refineries. Our Pipeline Transportation segment investments include the opportunity to acquire equity interests in two pipeline projects that will transport crude oil from the growing North American hydrocarbon production to our refineries and building a pipeline to connect the Utica Shale production to our Canton refinery.

Our planned Speedway segment investments include constructing new convenience stores and rebuilding existing locations. We also anticipate acquiring high quality stores through opportunistic acquisitions. Part of Speedway's growth strategy is to expand into new contiguous markets, including western Pennsylvania and Tennessee. In addition, we have projects at our refineries to enhance refining margins, expand our export capacity, increase our distillate production and increase our capacity to process condensates and light crude oils.

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 significant 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. We have an extensive portfolio of assets that can potentially be sold to MPLX, providing MPLX with a competitive advantage. As of December 31, 2013, these assets included:

• the remaining 44 percent limited partner interest in Pipe Line Holdings, of which an additional 13 percent is approved to be sold to MPLX effective on March 1, 2014;

• approximately 5,400 miles of crude oil and products pipeline that MPC owns, leases or has ownership interest;

• 64 owned and operated light product terminals with approximately 21 million barrels of storage capacity and 194 loading lanes;

• 19 owned and operated asphalt terminals with approximately 4 million barrels of storage capacity and 68 loading lanes;

• one leased and two non-operated, partially-owned light product terminals;

• 18 owned or leased inland towboats and 200 owned or leased inland barges;

• 2,165 owned or leased railcars;

• 59 million barrels of tank storage capacity at our refineries;

• 25 rail and 24 truck loading racks at our refineries; and

• 7 owned and 11 non-owned docks at our refineries.

We broadly estimate these assets can generate annual earnings before interest, tax, depreciation and amortization of $800 million. We continue to focus resources on growing this portfolio of assets, including investments in the Sandpiper and Southern Access Extension pipeline projects. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information on these pipeline investments.

Future asset sales to MPLX, along with sales of our limited partner interests in MPLX, will be driven by our desired distributable cash flow growth profile as well as strategic needs as they develop over time, including generating funds to support our base dividend, share repurchases and investment activities.

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 1,478 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 5,200 retail outlets operated by independent entrepreneurs in 18 states as of December 31, 2013. In addition, as part of the acquisition of the Galveston Bay Refinery and Related Assets, we have retail marketing contracts where we continue to convert retail outlets 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. Income generated by our 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.

Strong Financial Position

As of December 31, 2013, we had $2.29 billion in cash and cash equivalents and $3.8 billion in unused committed borrowing facilities, excluding MPLX’s credit facility. We also had $3.40 billion of debt at year-end, which represented only 23 percent of our total capitalization. This combination of strong liquidity and manageable leverage provides financial flexibility and allows us to fund our growth projects and to pursue our business strategies.

Our Business Strategies

Achieve and Maintain 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 again in 2013 with a strong performance compared to the industry average. Four of our refineries have earned designation as a U.S. Occupational Safety and Health Administration (“OSHA”) Voluntary Protection Program (“VPP”) Star site. In addition, we remain committed to environmental stewardship by continuing to improve the efficiency of our operations while proactively meeting our regulatory requirements. For example, since taking over the Galveston Bay refinery, we have improved environmental performance by reducing designated environmental incidents by approximately 80 percent compared to 2012.

Grow Higher-Valued, Stable Cash Flow Businesses

We intend to allocate significantly more capital to grow our midstream and retail businesses, which typically have more predictable and stable income and cash flows compared to our refining operations. We believe investors assign a higher value to businesses with stable cash flows. Over the next three years, we expect to invest approximately $630 million in midstream assets that are part of our Refining & Marketing segment, approximately $2.3 billion in our Pipeline Transportation segment and approximately $925 million on growing our Speedway segment. By contrast, our total investment from 2011 through 2013 was $229 million in midstream assets that are part of our Refining & Marketing segment, $566 million in our Pipeline Transportation segment and $800 million in our Speedway segment.

We expect there will be significant investments 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.

We intend to grow Speedway’s sales and profitability by focusing on organic growth through constructing new stores, rebuilding old stores, acquiring high quality stores through opportunistic acquisitions and continuous improvement of existing operations. For example, we have identified numerous opportunities for new convenience stores or store rebuilds in our existing market. In addition, we began expanding Speedway into new contiguous markets of western Pennsylvania and Tennessee in 2013 and are actively acquiring real estate in western Pennsylvania and Tennessee to be in a position to accelerate growth over the next several years. In addition, our industry-leading Speedy Rewards^® customer loyalty program, which has more than 3.7 million active members, provides us with a unique competitive advantage and opportunity to increase our Speedway customer base with existing and new Speedway locations.

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, gasoline and other products as the demand from various markets, such as Latin America and Europe, continues to grow.

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We intend to enhance our margins in the Refining & Marketing segment by increasing our condensate and light crude oil processing capacity, growing our distillate production and expanding our exports. For example, we have projects underway to increase condensate processing capacity at our Canton and Catlettsburg refineries, to increase light crude oil processing capacity at our Robinson, Illinois refinery, to increase distillate production at our Garyville, Louisiana; Galveston Bay and Robinson refineries and to expand the export capacity at our Garyville and Galveston Bay refineries. In addition, we are evaluating a residual fuel hydrocracker project that we expect will increase Garyville's ultra-low-sulfur diesel ("ULSD") production by 28 mbpd and lower feedstock costs. We are also evaluating three projects to increase distillate production at our Galveston Bay refinery. We will continue to evaluate opportunities to expand our existing asset base, with an emphasis on increasing distillate production and export capabilities and opportunities at our Galveston Bay refinery.

Sustain Focus on Shareholder Returns

We intend to continue our focus on the return of capital to shareholders in the form of a strong and growing base dividend, supplemented by share repurchases. We have increased our quarterly dividend by 110 percent since becoming a stand-alone company in June 2011 and our board of directors has authorized share repurchases totaling $6.0 billion. Through open market purchases and two accelerated share repurchase (“ASR”) programs, we repurchased 18 percent of our outstanding common shares since February 2012 for approximately $4.14 billion. After the effects of these repurchases, $1.86 billion of the $6.0 billion total authorization was available for future repurchases as of December 31, 2013.

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 Southeast market presence. As a result of this acquisition, we have retail marketing contracts where we continue to convert retail outlets to the Marathon brand, which puts us in position to take advantage of opportunities with premier jobbers and to significantly expand our brand presence in the Southeast. We also intend to grow Speedway gasoline and distillate sales volumes through internal capital program growth projects and acquisitions that complement our existing store network, including the continuing expansion into Pennsylvania and Tennessee.

Utilize and Enhance 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 enhance our workforce through selective hiring practices and effective training programs on safety, environmental stewardship and other professional and technical skills.

The above discussion contains forward-looking statements with respect to our competitive strengths and business strategies, including our expected investments, share repurchase authorizations, pursuit of potential acquisitions and other growth opportunities as well as the earnings potential of our midstream assets outside of MPLX and the anticipated sale of an additional 13 percent interest in Pipe Line Holdings to MPLX. There can be no assurance that we will be successful, in whole or in part, in carrying out our business strategies, including our expected investments, share repurchase program or pursuit of potential acquisitions and other growth opportunities, or that our midstream assets outside of MPLX will achieve expected earnings or that the anticipated sale of the 13 percent interest in Pipe Line Holdings will occur. Factors that could affect our investments include, but are not limited to, the actual amounts invested, which could differ materially from those estimated, and our success in making such investments. Factors that could affect the share repurchase authorizations and the timing of any repurchases include, but are not limited to, business conditions, availability of liquidity and the market price of our common stock. Factors that could affect the pursuit of potential acquisitions and other growth opportunities 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. Factors that could affect the earnings of our midstream assets outside of MPLX include, but are not limited to, the timing and extent of changes in commodity prices and demand for crude oil, refined products, feedstocks or other hydrocarbon-based products and volatility in and/or degradation of market and industry conditions. Factors that could affect the sale of an additional 13 percent interest in Pipe Line Holdings to MPLX include, but are not limited to, the satisfaction of customary closing conditions. 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.

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Refining & Marketing

Refineries

We currently own and operate seven refineries in the Gulf Coast and Midwest regions of the United States with an aggregate crude oil refining capacity of 1,714 thousand barrels per calender day ("mbpcd"). During 2013, our refineries processed 1,589 mbpd of crude oil and 213 mbpd of other charge and blendstocks. During 2012, our refineries processed 1,195 mbpd of crude oil and 168 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, 2013.

Refinery	Crude Oil Refining Capacity (mbpcd)(a)	Tank Storage Capacity (million barrels)	Number of Tanks
Garyville, Louisiana	522	15.9	76
Galveston Bay, Texas City, Texas	451	16.3	89
Catlettsburg, Kentucky	242	5.6	112
Robinson, Illinois	212	6.7	103
Detroit, Michigan	123	6.4	86
Texas City, Texas	84	4.7	60
Canton, Ohio	80	3.0	75
Total	1,714	58.6	601

^(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, hydrocracking, catalytic reforming, coking, desulfurization and sulfur recovery units. The refineries process a wide variety of light and heavy crude oils purchased from various domestic and foreign suppliers. We produce numerous refined products, ranging from transportation fuels, such as reformulated gasolines, blend-grade gasolines intended for blending with ethanol and ULSD fuel, to heavy fuel oil and asphalt. Additionally, we manufacture aromatics, propane, propylene, cumene and sulfur. See the Refined Product Marketing section for further information about the products we produce.

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.

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 a wide variety of crude oils into gasoline, distillates, fuel-grade coke, polymer-grade propylene, asphalt, propane, slurry and sulfur. The refinery has access to the export market and multiple options to sell refined products into higher value markets. A major 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 an OSHA VPP Star site.

Galveston Bay, Texas City, Texas Refinery. 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 can process a wide variety of crude oils into gasoline, distillates, aromatics, heavy fuel oil, refinery-grade propylene and fuel-grade coke. The refinery has access to the export market and multiple options to sell refined products into higher value markets. 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. Approximately 50 percent of the power generated is used at the refinery, with the remaining electricity being sold into the electricity grid.

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 gasoline, distillates, asphalt, heavy fuel oil, aromatics, propane and refinery-grade propylene.

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Robinson, Illinois Refinery. Our Robinson, Illinois refinery is located in southeastern Illinois. The Robinson refinery processes sweet and sour crude oils into multiple grades of gasoline, distillates, propane, aromatics, slurry and anode-grade coke. 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 sweet and heavy sour crude oils, including Canadian crude oils, into gasoline, distillates, asphalt, fuel-grade coke, chemical-grade propylene, propane, slurry and sulfur. 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 enabled the refinery to process up to an additional 80 mbpd of heavy sour crude oils, including Canadian bitumen blends.

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

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, including crude oil and condensate currently being produced from the Utica Shale, into gasoline, distillates, asphalt, roofing flux, propane and slurry.

As of December 31, 2013, our refineries had 25 rail loading racks and 24 truck loading racks and four of our refineries had a total of seven owned and 11 non-owned docks. Total throughput in 2013 was 80 mbpd for the refinery loading racks and 919 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.

Refined Product Yields

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

Refined Product Yields (mbpd)	2013	2012	2011
Gasoline	921	738	739
Distillates	572	433	433
Propane	37	26	25
Feedstocks and special products	221	109	109
Heavy fuel oil	31	18	21
Asphalt	54	62	56
Total	1,836	1,386	1,383

Crude Oil Supply

We obtain the crude oil we refine through negotiated term contracts and purchases or exchanges on the spot market. Our term contracts generally have market-related pricing provisions. The following table provides information on our sources of crude oil for each of the last three years. The crude oil sourced outside of North America was acquired from various foreign national oil companies, production companies and trading companies.

Sources of Crude Oil Refined (mbpd)	2013	2012	2011
United States	946	649	668
Canada	255	195	177
Middle East and other international	388	351	332
Total	1,589	1,195	1,177

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 condensate and crude oil by truck from the Utica Shale region to our Canton refinery.

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Refined Product Marketing

We believe we are one of the largest wholesale suppliers of gasoline and distillates to resellers and consumers within our 18-state market area. 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 gasoline, distillates and asphalt for export to international customers, primarily out of our Garyville and Galveston Bay refineries. The following table sets forth our refined product sales destined for export by product group for the past three years.

Refined Product Sales Destined for Export (mbpd)	2013	2012	2011
Gasoline	38	1	—
Distillates	173	114	76
Asphalt	6	8	7
Other	1	—	1
Total	218	123	84

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.

Refined Product Sales by Customer Type	2013		2012		2011
Private-brand marketers, commercial and industrial customers, including spot market	75	%	72	%	72	%
Marathon-branded independent entrepreneurs	16	%	17	%	17	%
Speedway® convenience stores	9	%	11	%	11	%

The following table sets forth the approximate number of retail outlets by state where independent entrepreneurs maintain Marathon-branded retail outlets, as of December 31, 2013.

State	Approximate Number of Marathon® Retail Outlets
Alabama	147
Florida	359
Georgia	268
Illinois	373
Indiana	652
Kentucky	594
Maryland	1
Michigan	761
Minnesota	75
Mississippi	10
North Carolina	297
Ohio	870
Pennsylvania	50
South Carolina	126
Tennessee	259
Virginia	136
West Virginia	122
Wisconsin	66
Total	5,166

As of December 31, 2013, we also had branded-jobber marketing contract assignments for retail outlets, primarily in Florida, Mississippi, Tennessee and Alabama, which we acquired as part of the Galveston Bay Refinery and Related Assets acquisition.

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The following table sets forth our refined product sales volumes by product group for each of the last three years.

Refined Product Sales (mbpd)	2013	2012	2011
Gasoline	1,126	916	908
Distillates	615	463	459
Propane	37	27	25
Feedstocks and special products	214	112	111
Heavy fuel oil	29	19	19
Asphalt	54	62	59
Total	2,075	1,599	1,581

Gasoline and Distillates. We sell gasoline, gasoline blendstocks and distillates (including No. 1 and No. 2 fuel oils, jet fuel, kerosene and diesel fuel) to wholesale customers, Marathon-branded independent entrepreneurs and our 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 and gasoline for export to international customers. We sold 59 percent of our gasoline sales volumes and 91 percent of our distillates sales volumes on a wholesale or spot market basis in 2013. 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 were 74 mbpd in 2013, 68 mbpd in 2012 and 70 mbpd in 2011. We sell reformulated gasoline, which is also blended with ethanol, in parts of our marketing territory, including Illinois, Kentucky, Indiana, Wisconsin and Pennsylvania. We also sell biodiesel-blended diesel fuel in 12 states in our marketing area. The future expansion or contraction of our ethanol and biodiesel blending programs will be driven by market economics and government regulations.

We hold interests in ethanol production facilities in Albion, Michigan; Clymers, Indiana and Greenville, Ohio. These plants have a combined ethanol production capacity of 275 million gallons per year and are managed by a co-owner.

Propane. We produce propane at most 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, raffinate, butane, benzene, xylene, molten sulfur, cumene and toluene. 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, Detroit and Galveston Bay 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. Our feedstocks and special products sales increased to 214 mbpd in 2013 from 112 mbpd in 2012 primarily due to our acquisition of the Galveston Bay refinery.

Heavy Fuel Oil. We produce and market heavy residual fuel oil or related components, including slurry, 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 101 mbpcd, which includes asphalt cements, polymer-modified asphalt, emulsified asphalt, industrial asphalts and roofing flux. As of December 31, 2013, we marketed asphalt through 29 owned or third-party 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.

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Terminals

As of December 31, 2013, we owned and operated 64 light product and 19 asphalt terminals. Our light product and asphalt terminals averaged 1,388 mbpd and 26 mbpd of throughput in 2013, 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 60 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, 2013.

Owned and Operated Terminals	Number of Terminals	Tank Storage Capacity (million barrels)	Number of Tanks	Number of Loading Lanes
Light Product Terminals:
Alabama	2	0.4	20	4
Florida	4	2.9	84	22
Georgia	4	0.9	38	9
Illinois	4	1.2	44	14
Indiana	6	2.8	71	17
Kentucky	6	2.3	68	24
Louisiana	1	0.1	8	2
Michigan	9	2.3	87	28
North Carolina	4	1.2	48	13
Ohio	13	3.9	160	33
Pennsylvania	1	0.3	10	2
South Carolina	1	0.4	9	3
Tennessee	4	1.0	42	12
Virginia	1	0.3	12	2
West Virginia	2	0.1	10	2
Wisconsin	2	0.8	19	7
Subtotal light product terminals	64	20.9	730	194
Asphalt Terminals:
Florida	1	0.2	6	3
Illinois	2	0.1	27	6
Indiana	2	0.4	13	6
Kentucky	4	0.6	62	14
Louisiana	1	0.1	11	2
Michigan	1	—	—	8
New York	1	0.1	4	3
Ohio	4	2.0	66	10
Pennsylvania	1	0.5	25	8
Tennessee	2	0.4	46	8
Subtotal asphalt terminals	19	4.4	260	68
Total owned and operated terminals	83	25.3	990	262

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Transportation

As of December 31, 2013, our marine transportation operations included 17 owned and one leased towboat, as well as 184 owned and 16 leased barges that transport refined products and crude oil 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	60	848
25,000 barrels and over	140	4,097
Total	200	4,945
Inland towboats:
Less than 2,000 horsepower	2
2,000 horsepower and over	16
Total	18

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

As of December 31, 2013, we owned 170 transport trucks and 161 trailers with an aggregate capacity of 1.5 million gallons for the movement of refined products and crude oil. In addition, we had 2,138 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	—	763	763	20,000-30,000 gallons
High pressure tank cars	—	1,166	1,166	33,500 gallons
Open-top hoppers	27	209	236	4,000 cubic feet
	27	2,138	2,165

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-branded convenience stores offer a wide variety of merchandise, including prepared foods, beverages and non-food items. Speedway’s Speedy Rewards® loyalty program has been an industry-leading loyalty program since its inception in 2004, with a consistently growing base of more than 3.7 million active members. Due to Speedway’s ability to capture and analyze member-specific transactional data, Speedway is able to offer the Speedy Rewards® members discounts and promotions specific to their buying behavior. We believe Speedy Rewards® is a key reason customers choose Speedway over competitors and it continues to drive significant value for both Speedway and our Speedy Rewards® members.

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. The following table sets forth Speedway merchandise statistics for the past three years.

Speedway Merchandise Statistics	2013			2012			2011
Merchandise sales (in millions)	$	3,135		$	3,058		$	2,924
Merchandise gross margin (in millions)	825			795			719
Merchandise as a percent of total gross margin	65		%	67		%	65		%

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As of December 31, 2013, Speedway had 1,478 convenience stores in nine states, which includes the 2013 expansion into Pennsylvania and Tennessee. The following table sets forth the number of convenience stores by state owned by our Speedway segment as of December 31, 2013.

State	Number of Convenience Stores
Illinois	107
Indiana	305
Kentucky	145
Michigan	302
Ohio	484
Pennsylvania	5
Tennessee	7
West Virginia	59
Wisconsin	64
Total	1,478

Pipeline Transportation

As of December 31, 2013, we owned, leased or had ownership interests in approximately 8,300 miles of crude oil and products pipelines, of which approximately 2,900 miles are owned through our investments in MPLX and Pipe Line Holdings.

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 two percent general partner interest. As of December 31, 2013, MPLX’s assets consisted of a 56 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 44 percent limited partner interest in Pipe Line Holdings.

On February 27, 2014, we announced that an additional 13 percent of Pipe Line Holdings will be sold to MPLX effective on March 1, 2014. MPLX intends to finance the acquisition with cash on-hand and by borrowing on its revolving credit agreement. This will increase MPLX's and reduce our ownership interest in Pipe Line Holdings to 69 percent and 31 percent, respectively.

As of December 31, 2013, 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. The table below sets forth additional detail regarding the pipeline systems and storage assets we owned through Pipe Line Holdings and MPLX as of December 31, 2013.

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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	249	Detroit, Canton
Catlettsburg, KY and Robinson, IL crude system	Patoka, IL	Catlettsburg, KY & Robinson, IL	20"-24"	484	495	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	314	All Midwest refineries
Inactive pipelines				42	N/A
Total				1,004	1,378
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, Galveston Bay
ORPL products system	Various	Various	6"-14"	518	241	Catlettsburg, Canton
Robinson, IL products system(b)	Various	Various	10"-16"	1,173	548	Robinson
Louisville, KY Airport products system	Louisville, KY	Louisville, KY	6"-8"	14	29	Robinson
Inactive pipelines(b)				83	N/A
Total				1,902	1,422
Wood River, IL barge dock (mbpd)					84	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 13 percent of the crude oil and refined product shipments on these common carrier pipelines in 2013, 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)	2013	2012	2011
Crude oil pipelines	1,063	1,029	993
Refined products pipelines	911	980	1,031
Total	1,974	2,009	2,024

^(a)  MPLX predecessor volumes reported in MPLX’s filings include our undivided joint interest crude oil pipeline systems for periods prior to MPLX's initial public offering, 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.

MPC-Retained Assets and Investments

In addition to our ownership interest in Pipe Line Holdings, we retained ownership interests in several crude oil and products pipeline systems and pipeline companies. 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)	2013	2012	2011
Crude oil pipelines	1,280	1,190	1,184
Refined products pipelines	911	980	1,031
Total	2,191	2,170	2,215

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As of December 31, 2013, 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	%	Yes
Maumee	Lima, OH	Samaria, MI	22"	95	26	%	No
Total				730

As of December 31, 2013, 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
North Dakota Pipeline Company LLC(a)	Plentywood, MT	Clearbrook, MN	TBD	TBD	38	%	No
Total				105
Products pipeline companies:
Centennial Pipeline LLC (b)	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)  We own 38 percent of the Class B units in this entity. Upon completion of the Sandpiper project, which is to construct a pipeline running from Beaver Lodge, North Dakota to Superior, Wisconsin and targeted for completion in early 2016, our Class B units will be converted to an approximate 27 percent ownership interest in the Class A units of this entity.

^(b)  Includes 48 miles of inactive pipeline.

We also own 183 miles of private crude oil pipelines and 760 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	34
Woodhaven, MI to Detroit, MI	4"	26	11
Illinois pipeline systems	4"-12"	118	39
Texas pipeline systems	8"	103	45
Ohio pipeline systems	4"-12"	57	32
Inactive pipelines		119	N/A
Total		760	179

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

As of December 31, 2013, we owned or leased 60 private tanks with storage capacity of approximately 6.5 million barrels, which are located along MPLX pipelines.

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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 2013 Worldwide Refinery Survey,” we ranked fourth among U.S. petroleum companies on the basis of U.S. crude oil refining capacity as of December 31, 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 90 companies in the sale of refined products in the spot market; 11 refiners or marketers in the supply of refined products to refiner-branded independent entrepreneurs; and approximately 260 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.

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 independent entrepreneurs and other well-recognized national or regional convenience stores and travel centers, often selling gasoline, diesel fuel and merchandise at 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. estimated such retailers had approximately 13 percent of the U.S. gasoline market in mid-2013.

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 oils, West Texas Intermediate and Light Louisiana Sweet crude oils and other market structure differentials 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 may be 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, 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 until they are finalized.

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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.

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 other 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. In response, several parties sought further review by the U.S. Supreme Court, which heard oral arguments on the challenges in February 2014 with an expected decision by mid-2014. The EPA has proposed New Source Performance Standards for greenhouse gas emissions for new electric utility-generating units and has announced plans to regulate existing and modified units as well. This could impact electric rates for all our operations and could impose new requirements on the combined heat and power unit we operate. It is also likely that the EPA will propose refinery-specific New Source Performance Standards for greenhouse gas emissions sometime in the future. 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 associated with any legislation, regulation, litigation or other action (including compliance costs, potential permitting delays and potential reduced demand for certain refined products made from crude oil), 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.

In 2013, the Obama administration developed the social cost of carbon (“SCC"). The SCC is to be used by the EPA and other federal agencies in regulatory cost-benefit analyses to take into account alleged broad economic consequences associated with changes to emissions of greenhouse gases. The SCC was first issued in 2010, and in 2013, the Obama administration significantly increased the estimate to $36 per ton. In response to the regulated community and Congress’ critiques in how the SCC was developed, the Office of Management and Budget recently announced the opportunity to comment on the SCC. While the impact of a higher SCC in future regulations is not known at this time, it may result in increased costs to our operations.

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 the EPA’s periodic review of that standard. On July 23, 2013, the D.C. Circuit Court of Appeals issued a decision on the 2008 ozone NAAQS lawsuit. The Court upheld the primary standard, but remanded the secondary NAAQS standard to the EPA on the grounds that the EPA had not justified setting the secondary standard at the same level as the primary standard. On remand, the EPA could address the court’s ruling by proposing a separate secondary standard that is more stringent than the primary 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.

The EPA finalized the Boiler and Process Heater Maximum Achievable Control Technology (“Boiler MACT”) in March 2011 with work practice standards that are applicable to refinery and natural gas fired equipment. Subsequently, in January 2013 the EPA made certain revisions to the March 2011 final rule in response to petitions for reconsideration. Currently, litigation is pending in the D.C. Circuit Court on both the 2011 and 2013 rulemakings. We anticipate litigation to continue through 2014. Final financial impacts of the Boiler MACT rule cannot be determined at this time because of the ongoing litigation, which could affect the final rule.

On July 20, 2011, the EPA proposed a rule regarding cooling water intake structures which could affect some of our refineries. The rule would place new requirements on these structures. The EPA has requested and received public comments on the rule as proposed, including comments on the types of structures covered by the rule. Until the rule is issued final, we will not know whether the rule will apply to refinery intakes and the costs of complying with the rule.

In 2014, 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.

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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 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. 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 two 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 convenience stores and other locations 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 (“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 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). New or alternative transportation fuels such as compressed natural gas could also pose a competitive threat to our operations.

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The RFS2 required the total volume of renewable transportation fuels sold or introduced annually in the U.S. to reach 16.55 billion gallons in 2013 and increases to 36.0 billion gallons by 2022. In the near term, the RFS2 will be satisfied primarily with ethanol blended into gasoline. However, vehicle, regulatory and infrastructure constraints could limit the ability to blend significantly more than 10 percent ethanol into gasoline that could be required if the RFS2 standards are not modified. 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, 1.28 billion gallons in 2013, and at least 1.0 billion gallons in 2014 through 2022 (to be determined by the EPA through future rulemaking), and cellulosic biofuel, which was set at 0.5 billion gallons in 2012 and 1.0 billion gallons in 2013, increasing to 16.0 billion gallons by 2022. In 2013, the EPA used its waiver authority under the Clean Air Act to reduce the amount of cellulosic biofuel required under the statute from 1.0 billion gallons to 6 million gallons. Currently, litigation is on-going in the D.C. Circuit Court of Appeals with respect to the EPA’s determination of the 2013 cellulosic biofuel requirement. Subsequently, industry has requested the EPA to use its waiver authority for 2014, requesting reductions for total renewable fuel, advanced biofuels and cellulosic biofuels volumetric obligations.

The EPA has issued a proposed rule for 2014 requirements that is in the comment period. This proposed rule has substantially reduced the RFS requirements from the statutory numbers as follows: total renewables has been reduced from 18.15 to 15.21 billion gallons, the advanced requirement has been reduced from 3.75 to 2.20 billion gallons, the biomass-based diesel requirement has remained flat from 2013 at 1.28 billion gallons, and the cellulosic requirement has been reduced from 1.75 billion to 17 million gallons. If these proposed requirements become final, it will allow the obligated parties to comply in 2014 without needing any substantial volumes of 85 percent ethanol-blended or 15 percent ethanol-blended gasolines and postpone the issues and concerns of having to blend ethanol past the 10 percent ethanol “blendwall” at least for 2014. The future of the RFS still remains undecided and is in need of legislative re-write or repeal to provide a stable business platform for the obligated parties.

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. Additionally, the EPA did not finalize the 2013 RFS2 renewable fuel obligations until August 2013. Therefore, it is uncertain how industry will comply with meeting the advanced biofuels obligation until compliance reports are submitted in June 2014. In 2012 and 2013, the EPA also discovered that 173 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 MPC. The EPA proposed a rule establishing a quality assurance program for RINs purchased to help meet the annual biofuel requirements under the RFS2 program. This rule should be finalized in 2014 and is aimed at reducing the risks that RINs are fraudulently created or sold. We have already instituted internal procedures to help mitigate this risk.

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.

On March 29, 2013, the EPA announced its proposed Tier 3 fuel standards. The proposed Tier 3 fuel standards require, among other things, a lower annual average sulfur level in gasoline to no more than 10 parts per million beginning in calendar year 2017. The EPA is expected to finalize the Tier 3 fuel standards in 2014. Until the rule is finalized and we have developed our compliance plan, we cannot reasonably estimate our compliance cost.

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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 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 29,865 regular employees as of December 31, 2013, which includes approximately 20,185 employees of Speedway.

Certain hourly employees at our Canton, Catlettsburg, 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 2019.

Executive Officers of the Registrant

The executive officers of MPC and their ages as of February 1, 2014, are as follows:

Name	Age	Position with MPC
Gary R. Heminger	60	President and Chief Executive Officer
Pamela K.M. Beall	57	Senior Vice President, Corporate Planning, Government & Public Affairs
Richard D. Bedell	59	Senior Vice President, Refining
Michael G. Braddock	56	Vice President and Controller
Timothy T. Griffith	44	Vice President, Finance and Investor Relations, and Treasurer
John R. Haley	57	Vice President, Tax
Thomas M. Kelley	54	Senior Vice President, Marketing
Anthony R. Kenney	60	President, Speedway LLC
Rodney P. Nichols	61	Senior Vice President, Human Resources and Administrative Services
C. Michael Palmer	60	Senior Vice President, Supply, Distribution and Planning
George P. Shaffner	54	Senior Vice President, Transportation and Logistics
John S. Swearingen	54	Vice President, Health, Environment, Safety & Security
Donald C. Templin	50	Senior Vice President and Chief Financial Officer
Donald W. Wehrly	54	Vice President and Chief Information Officer
J. Michael Wilder	61	Vice President, General Counsel and Secretary

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.

Ms. Beall was appointed senior vice president, Corporate Planning, Government & Public Affairs effective January 1, 2014. Prior to this appointment, Ms. Beall was vice president, Investor Relations and Government & Public Affairs beginning June 30, 2011 and 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.

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Mr. Griffith was appointed vice president, Finance and Investor Relations, and treasurer effective January 1, 2014. Prior to this appointment, Mr. Griffith was vice president of Finance and treasurer beginning August 1, 2011. Mr. Griffith was vice president Investor Relations and treasurer of Smurfit-Stone Container Corporation, a packaging manufacturer, in St. Louis, Missouri, from 2008 to 2011.

Mr. Haley was appointed vice president, Tax effective June 1, 2013. Prior to this appointment, Mr. Haley served as director of Tax beginning in July 2011 and as a tax manager for Marathon Oil Company beginning in 1996.

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. 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.

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.

Garry L. Peiffer, who was executive vice president of Corporate Planning and Investor & Government Relations since June 30, 2011, retired effective January 1, 2014.

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 to the ownership of our common stock.

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 Business

Failure to identify and manage risks inherent to our business could adversely impact our operations, financial condition, results of operations and cash flows.

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. 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. 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. Any overall change in crack spreads will impact our refining and marketing gross margins. Many of the factors influencing a 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 and other feedstocks 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 OPEC to agree to and maintain production controls;

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

• 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 tornadoes;

• 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 we refine them and sell 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 products we produce, which may reduce our revenues, income from operations 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.

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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 interruptions 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, 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 impacted refinery.

Explosions, fires, refinery or pipeline releases or other incidents involving our assets or 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 an incident involving 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.

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 insurance of the types and amounts we desire at reasonable rates.

We rely on the performance of our information technology systems, the failure of which could have an adverse effect on our business, financial condition, results of operations and cash flows.

We are heavily dependent on our information technology systems and network infrastructure and maintain and rely upon certain critical information systems for the effective operation of our business. These information systems include data network and telecommunications, Internet access and our websites, and various computer hardware equipment and software applications, including those that are critical to the safe operation of our business. These systems and infrastructure are subject to damage or interruption from a number of potential sources including natural disasters, software viruses or other malware, power failures, cyber-attacks and other events. We also face various other cyber-security threats, including threats to gain unauthorized access to sensitive information or to render data or systems unusable. To protect against such attempts of unauthorized access or attack, we have implemented infrastructure protection technologies and disaster recovery plans. There can be no guarantee such plans, to the extent they are in place, will be totally effective.

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

We face strong competition in the market for the sale of retail gasoline, diesel fuel 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 financial 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.

The development, availability and marketing of alternative and competing fuels in the retail market could adversely impact our business. We compete with other industries that provide alternative means to satisfy the energy and fuel needs of our consumers. Increased competition from these alternatives as a result of governmental regulations, technological advances and consumer demand could have an impact on pricing and demand for our products and our profitability.

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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, railways 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 the pipelines, railways or vessels to transport crude oil or refined products 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.

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 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.

At December 31, 2013, our total debt obligations for borrowed money and capital lease obligations were $3.4 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.

A decrease in our debt or 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.

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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 Texas City and Detroit refineries are scheduled to expire in March 2015 and January 2019, 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.

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 the U.S. citizens. Among other requirements to establish citizenship, corporations that own such vessels must be owned at least 75 percent 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 are subject to certain continuing contingent liabilities of Marathon Oil relating to taxes and other matters and to potential liabilities 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.

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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 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 its 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 Our Industry

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.

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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 percent below 2005 levels by 2020 remains in effect and was reaffirmed in the President’s 2013 Climate Action Plan. 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 an "endangerment 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 resulted in permitting of greenhouse gas emissions at stationary sources, but as a result of the EPA’s “tailoring rule,” permit applicability was limited to larger sources such as refineries. Legal challenges were filed against these EPA actions. The D.C. Circuit Court of Appeals overruled these challenges. In response, several parties sought further review by the U.S. Supreme Court which heard oral argument on the challenges in February 2014 with an expected decision by mid-2014. Additionally, as part of the EPA’s ongoing regulatory agenda we anticipate refinery-specific New Source Performance Standards may be proposed in late 2014.

In 2013, the Obama administration developed the social cost of carbon ("SCC"). The SCC is to be used by the EPA and other federal agencies in regulatory cost-benefit analyses to take into account alleged broad economic consequences associated with changes to emissions of greenhouse gases. The SCC was first issued in 2010, and in 2013 the Obama administration significantly increased the estimate to $36 per ton. In response to the regulated community and Congress’ critiques in how the SCC was developed, the Office of Management and Budget recently announced the opportunity to comment on the SCC. While the impact of a higher SCC in future regulations is not known at this time, it may result in increased costs to our operations.

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. Governmental regulations encouraging the use of new or alternative fuels could also pose a competitive threat to our operations.

The RFS2 required the total volume of renewable transportation fuels sold or introduced annually in the U.S. to reach 16.55 billion gallons in 2013 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.

On March 29, 2013, the EPA announced its proposed Tier 3 fuel standards. The proposed Tier 3 fuel standards require, among other things, a lower allowable sulfur level in gasoline to no more than 10 parts per million by January 1, 2017. The EPA is expected to finalize this rule in early 2014. Our cost of compliance may be material; however, we will likely not be able to reasonably estimate our compliance costs until we have had time to review the final standards and develop our compliance plans.

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.

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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.

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 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 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.

Compliance with and changes in tax laws could materially and adversely impact our financial condition, results of operations and cash flows.

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 condition, results of operations and cash flows. Additionally, many tax liabilities are subject to periodic audits by taxing authorities, and such audits could subject us to interest and penalties.

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. The market for crude oil and other feedstocks is largely a world market. We are, therefore, subject to the attendant political, geographic and economic risks of such a market. If one or more major supply sources were temporarily or permanently eliminated, 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 gross margins could be adversely affected, materially and adversely impacting our business, financial condition, results of operations and cash flows.

Terrorist attacks aimed at our facilities or that impact our customers or the markets we serve could adversely affect our business.

The U.S. government has issued warnings that energy assets in general, including the nation's refining, pipeline and terminal infrastructure, may be future targets of terrorist organizations. The threat of terrorist attacks has subjected our operations to increased risks. Any future terrorist attacks on our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business. Similarly, any future terrorist attacks that severely disrupt the markets we serve could materially and adversely affect our results of operations, financial position and cash flows.

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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 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.

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, 2013, 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.

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.

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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 provided notice of alleged Clean Air Act violations pertaining to a 2011 audit of our Woodhaven, Michigan facility. We have tentatively agreed to pay a penalty of $23,200 to the EPA and undertake a supplemental safety project of $87,000.

In May 2013, the Michigan Department of Environmental Quality ("MDEQ") issued a Notice of Enforcement to Marathon Petroleum Company LP for alleged violations associated with exceeding various air permit limits. In November 2013, MDEQ issued a Notice of Violation for air permit exceedences that we had self-disclosed to MDEQ in October 2013. We expect to resolve these violations through revisions in the air permit limits. We have agreed to pay a penalty of $99,500 to MDEQ.

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 14, 2014, there were 39,933 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:

	2013						2012
Dollars per share	High Price		Low Price		Dividends		High Price		Low Price		Dividends
Quarter 1	$	92.73	$	60.04	$	0.35	$	45.42	$	30.24	$	0.25
Quarter 2	90.54		69.31		0.35		45.35		33.66		0.25
Quarter 3	76.58		62.51		0.42		56.22		42.60		0.35
Quarter 4	91.95		61.32		0.42		63.44		52.36		0.35
Year	92.73		60.04		1.54		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 25, 2014, our board of directors approved a 42 cent per share dividend, payable March 10, 2014 to stockholders of record at the close of business on February 19, 2014.

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, 2013, 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)
10/01/13-10/31/13	1,467,388	$	64.73	1,466,900	$	2,213,856,758
11/01/13-11/30/13	2,060,258	$	75.25	2,059,500	2,058,882,628
12/01/13-12/31/13	2,353,818	$	85.81	2,352,500	1,857,022,802
Total	5,881,464	$	76.85	5,878,900

^(a)  The amounts in this column include 488, 758 and 1,318 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)  Amounts in this column reflect the weighted average price paid for shares purchased under our share repurchase authorizations and for shares tendered to us in satisfaction of employee tax withholding obligations upon the vesting of restricted stock granted under our stock plans. The weighted average price includes commissions paid to brokers on shares purchased under our share repurchase authorizations.

^(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 January 30, 2013, we announced that our board of directors approved an additional $2.0 billion share repurchase authorization to expire on December 31, 2014. On September 26, 2013, we announced that our board of directors approved an additional $2.0 billion share repurchase authorization through September 30, 2015. As indicated from these three announcements, our board of directors approved $6.0 billion in total share repurchase authorizations since January 1, 2012. As of December 31, 2013, we have purchased a total of $4.14 billion of our common stock under these repurchase authorizations.

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Item 6. Selected Financial Data

Selected financial data for periods subsequent to our June 2011 Spinoff from Marathon Oil were derived from our consolidated financial statements. Selected financial data for periods prior to the Spinoff were derived from the results of the RM&T Business, which represented a combined reporting entity. The following table should be read in conjunction with Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data.

	Year Ended December 31,
(In millions, except per share data)	2013(a)			2012			2011			2010(b)			2009(b)
Statements of Income Data
Revenues	$	100,160		$	82,243		$	78,638		$	62,487		$	45,530
Income from operations	3,425			5,347			3,745			1,011			654
Net income	2,133			3,393			2,389			623			449
Net income attributable to MPC	2,112			3,389			2,389			623			449
Per Share Data(c)
Basic:
Net income attributable to MPC per share	$	6.69		$	9.95		$	6.70		$	1.75		$	1.26
Diluted:
Net income attributable to MPC per share	$	6.64		$	9.89		$	6.67		$	1.74		$	1.25
Dividends per share	$	1.54		$	1.20		$	0.45		—			—
Statements of Cash Flows Data
Net cash provided by operating activities	$	3,405		$	4,492		$	3,309		$	2,217		$	2,455
Additions to property, plant and equipment	(1,206		)	(1,369		)	(1,185		)	(1,217		)	(2,891		)
Dividends paid	(484		)	(407		)	(160		)	—			—

	December 31,
(In millions)	2013(a)		2012		2011		2010		2009(b)
Balance Sheets Data
Total assets	$	28,385	$	27,223	$	25,745	$	23,232	$	21,254
Long-term debt, including capitalized leases(d)	3,396		3,361		3,307		279		254
Long-term debt payable to Marathon Oil and subsidiaries(e)	—		—		—		3,618		2,358

^(a)  On February 1, 2013, we acquired the Galveston Bay Refinery and Related Assets. Data presented subsequent to this acquisition include amounts for these operations.

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

^(c)  The number of weighted average shares for 2013 and 2012 reflect the impacts of shares of common stock repurchased under our share repurchase plans. For comparative purposes and to provide a more meaningful calculation, for basic weighted average shares we assumed the 356 million shares of common stock 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.

^(d)  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.

^(e)  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,” “would,” "will" 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.

Corporate Overview

We are an independent petroleum refining, marketing and transportation company. We currently own and operate seven refineries, all located in the United States, with an aggregate crude oil refining capacity of approximately 1.7 mmbpcd. Our refineries supply refined products to resellers and 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, 2013, we owned, leased or had ownership interests in approximately 8,300 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. 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, 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, buyers on the spot market, our Speedway business segment and to independent entrepreneurs 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.

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

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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. See Item 8. Financial Statements and Supplementary Data – Note 7.

Executive Summary

Net income attributable to MPC was $2.11 billion, or $6.64 per diluted share, in 2013 compared to $3.39 billion, or $9.89 per diluted share, in 2012. The decrease was primarily due to our Refining & Marketing segment, which generated income from operations of $3.21 billion in 2013 compared to $5.10 billion in 2012. The decrease in Refining & Marketing segment income from operations was primarily due to narrower crude oil differentials and lower net product price realizations, partially offset by higher refinery throughput and sales volumes.

Our Speedway segment generated income from operations of $375 million for 2013 compared to $310 million for 2012. The increase was primarily due to higher gasoline and distillate gross margins and a higher merchandise gross margin, partially offset by higher operating expenses related to an increase in the number of convenience stores.

During 2013, Speedway acquired nine convenience stores located in Tennessee, western Indiana and western Pennsylvania, which expanded Speedway's marketing area by two additional states. In 2012, Speedway acquired 97 convenience stores located in Indiana, Ohio and northern Kentucky. These acquisitions support our strategic initiative to increase Speedway segment sales and complement our existing network of assets.

Our Pipeline Transportation segment generated income from operations of $210 million for 2013 compared to $216 million for 2012. The decrease primarily reflects higher operating expenses and depreciation and lower pipeline affiliate income, partially offset by higher transportation revenue. The higher expenses and revenues were primarily attributable to the formation of MPLX.

On February 1, 2013, we acquired from BP the 451,000 barrel per calendar day refinery in Texas City, Texas, three intrastate natural gas liquid pipelines originating at the refinery, four light product terminals, branded-jobber marketing contract assignments for the supply of approximately 1,200 branded sites, a 1,040 megawatt electric cogeneration facility and a 50 mbpd allocation of space on the Colonial Pipeline. We refer to these assets as the “Galveston Bay Refinery and Related Assets.” We paid $1.49 billion for these assets, which included $935 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. These assets are part of our Refining & Marketing and Pipeline Transportation segments. Our financial results and operating statistics for all periods prior to the acquisition do not include amounts for the Galveston Bay Refinery and Related Assets. See Item 8. Financial Statements and Supplementary Data – Note 5 for additional information on the acquisition of these assets.

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 historically traded at a significant discount to light sweet crude oil. We also continued to optimize our refineries in 2013, increasing their combined crude oil refining capacity by 15 mbpcd.

On August 1, 2013, we acquired from Mitsui & Co. (U.S.A.), Inc. its interests in three ethanol companies for $75 million. Under the purchase agreement, we acquired an additional 24 percent interest in TACE, bringing our ownership interest to 60 percent; a 34 percent interest in TAEI, which holds a 50 percent ownership in TAME, bringing our direct and indirect ownership interest in TAME to 67 percent; and a 40 percent interest in TAAE, which owns an ethanol production facility in Albion, Michigan. On October 1, 2013, our ownership interest in TAAE increased to 43 percent as a result of TAAE acquiring one of the owner's interest. We hold a noncontrolling interest in each of these entities and account for them using the equity method of accounting since the minority owners have substantive participating rights.

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 19.9 million common units, which represented the sale by us of a 26.4 percent interest in MPLX. We currently own a 73.6 percent interest in MPLX, including the two percent general partner interest, and we consolidate this entity for financial reporting purposes since we have a controlling financial interest.

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Headquartered in Findlay, Ohio, MPLX’s assets as of December 31, 2013 consist of a 56 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 44 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.

On February 27, 2014, we announced that an additional 13 percent of Pipe Line Holdings will be sold to MPLX effective March 1, 2014 for $310 million. Subsequent to this transaction, MPLX will own a 69 percent general partner interest in Pipe Line Holdings and we will own a 31 percent limited partner interest. MPLX intends to finance this transaction with $40 million of cash on-hand and by borrowing $270 million on its revolving credit agreement.

In 2013, we agreed with Enbridge Energy Partners, L.P. ("Enbridge") to serve as an anchor shipper for the Sandpiper pipeline, which will run from Beaver Lodge, North Dakota to Superior, Wisconsin and is targeted to be operational in early 2016. We also agreed to fund 37.5 percent of the construction of the Sandpiper pipeline project, which is currently estimated to cost $2.6 billion, of which approximately $1.0 billion is our share. We made initial contributions of $24 million in 2013. In exchange for our commitment to be an anchor shipper and our investment in the project, we will earn an approximate 27 percent equity interest in Enbridge's North Dakota System when the Sandpiper pipeline is placed into service. Enbridge's North Dakota System currently includes approximately 240 miles of crude oil gathering pipelines connected to a transportation pipeline that is approximately 730 miles long. We will also have the option to increase our ownership interest to approximately 30 percent through additional investments in future system improvements.

In 2012, we agreed to be the anchor shipper on Enbridge Inc.'s proposed Southern Access Extension pipeline, which will run from Flanagan, Ill. to Patoka, Ill. As a result of that commitment, we obtained the option to acquire a 25 percent equity interest in the pipeline. In conjunction with our commitment to the Sandpiper pipeline project, our option for equity interest in the Southern Access Extension pipeline increased an additional 10 percent to a total of 35 percent. The Southern Access Extension pipeline is expected to be operational in 2015 and we estimate our option for equity interest to cost approximately $250 million.

In 2013, we completed projects to develop infrastructure that facilitates transportation of hydrocarbon liquids production from the Utica Shale in eastern Ohio and western Pennsylvania. The project with Harvest Pipeline Company increased our truck unloading capacity by 24,000 barrels per day and a separate project increased our barge loading capacity to up to 50,000 barrels per day at our Wellsville, Ohio terminal.

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 to expire in December 2014. On September 26, 2013, we announced that our board of directors approved an additional $2.0 billion share repurchase authorization through September 2015, resulting in $6.0 billion of total share repurchase authorizations since February 1, 2012. We paid $2.79 billion in 2013 and $1.35 billion in 2012 to repurchase shares. As of December 31, 2013, we had total outstanding repurchase authorizations of $1.86 billion.

As of December 31, 2013, we had cash and cash equivalents of $2.29 billion and no borrowings or letters of credit outstanding under our $2.5 billion revolving credit agreement or $1.3 billion trade receivables securitization facility or MPLX’s $500 million revolving credit agreement.

The above discussion includes forward-looking statements that relate to our expectations with respect to the anticipated sale of an additional 13 percent interest in Pipe Line Holdings to MPLX, the Sandpiper pipeline project, the Southern Access Extension pipeline project and the share repurchase authorizations. Factors that could affect the sale of an additional 13 percent interest in Pipe Line Holdings to MPLX include, but are not limited to, the satisfaction of customary closing conditions. Factors that could affect the Sandpiper and Southern Access Extension pipeline projects include, but are not limited to, availability of materials and labor, unforeseen hazards such as weather conditions, delays in obtaining or conditions imposed by necessary government and third-party approvals and other risks customarily associated with construction projects. Factors that could affect the share repurchase authorizations and the timing of any repurchases 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.

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Overview of Segments

Refining & Marketing

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

Our Refining & 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 and the costs of purchased products. 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. Light Louisiana Sweet crude oil ("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 residual fuel oil) 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 & Marketing gross margin to differ from crack spreads based on sweet crude oil. In general, a larger sweet/sour differential will enhance our Refining & Marketing gross margin.

Historically, West Texas Intermediate crude oil ("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 & Marketing gross margin. Logistical constraints in the U.S. mid-continent markets and other market factors acted to keep the price of WTI from rising with the prices of crude oil produced in other regions. However, the differential between WTI and LLS significantly narrowed during 2013 due to a variety of domestic and international market conditions along with changes in logistical infrastructure. Future crude oil differentials will be dependent on a variety of market and economic factors.

The following table provides sensitivities showing an estimated change in annual net income 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)	$	450
Sweet/sour differential sensitivity(b)(per $1.00/barrel change)	200
LLS-WTI differential sensitivity(c)(per $1.00/barrel change)	85
Natural gas price sensitivity (per $1.00/million British thermal unit change)	125

^(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 & Marketing gross margin is impacted by factors such as:

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

• our refinery yields;

• the selling prices realized for refined products;

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

• the cost of products purchased for resale.

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Refining & Marketing segment income from operations is also affected by changes in refinery direct operating costs, which include turnaround and major maintenance, depreciation and amortization and other manufacturing expenses. 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
2013	Canton, Catlettsburg, Galveston Bay, Garyville and Robinson
2012	Catlettsburg, Detroit, Garyville and Robinson
2011	Canton and Catlettsburg

The table below sets forth the location and daily crude oil refining capacity of each of our refineries at December 31 of each year.

	Crude Oil Refining Capacity (mbpcd)
Refinery	2013	2012	2011
Garyville, Louisiana	522	522	490
Galveston Bay, Texas City, Texas(a)	451	N/A	N/A
Catlettsburg, Kentucky	242	240	233
Robinson, Illinois	212	206	206
Detroit, Michigan	123	120	106
Texas City, Texas	84	80	80
Canton, Ohio	80	80	78
Total	1,714	1,248	1,193

^(a)  We acquired the Galveston Bay refinery on February 1, 2013.

Speedway

Our retail marketing gross margin for gasoline and distillate, 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 distillate 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. Gasoline demand in PADD 2 is estimated to have grown by more than one percent in 2013 after coming in flat in 2012. Strong economic growth in the second half of 2013, lower prices and a rebound in manufacturing activity supported demand. More normal winter temperatures in early 2013, compared to a relatively warm 2012, and a surge in manufacturing contributed to an estimated two percent growth in PADD 2 distillate demand. Market demand increases for gasoline and distillate generally increase the product margin we can realize. The gross margin on merchandise sold at convenience stores historically has been less volatile and has contributed substantially to Speedway's gross margin. Approximately two-thirds of Speedway’s gross margin was derived from merchandise sales in 2013. Speedway's convenience stores offer a wide variety of merchandise, including prepared foods, beverages and non-food items.

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 distillate 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, 2013 and December 31, 2012

Consolidated Results of Operations

(In millions)	2013			2012			Variance
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$	100,152		$	82,235		$	17,917
Sales to related parties	8			8			—
Income from equity method investments	36			26			10
Net gain on disposal of assets	6			177			(171		)
Other income	52			46			6
Total revenues and other income	100,254			82,492			17,762
Costs and expenses:
Cost of revenues (excludes items below)	87,401			68,668			18,733
Purchases from related parties	357			280			77
Consumer excise taxes	6,263			5,709			554
Depreciation and amortization	1,220			995			225
Selling, general and administrative expenses	1,248			1,223			25
Other taxes	340			270			70
Total costs and expenses	96,829			77,145			19,684
Income from operations	3,425			5,347			(1,922		)
Related party net interest and other financial income	—			1			(1		)
Net interest and other financial income (costs)	(179		)	(110		)	(69		)
Income before income taxes	3,246			5,238			(1,992		)
Provision for income taxes	1,113			1,845			(732		)
Net income	2,133			3,393			(1,260		)
Less net income attributable to noncontrolling interests	21			4			17
Net income attributable to MPC	$	2,112		$	3,389		$	(1,277	)

Net income attributable to MPC decreased$1.28 billion in 2013 compared to 2012, primarily due to a decrease in our Refining & Marketing segment income from operations of $1.89 billion in 2013 compared to 2012. The decrease in Refining & Marketing segment income from operations was primarily due to narrower crude oil differentials and lower net product price realizations, partially offset by higher refinery throughput and sales volumes.

Sales and other operating revenues (including consumer excise taxes) increased$17.92 billion in 2013 compared to 2012, primarily due to higher refined product sales volumes, which increased to 2,086 mbpd in 2013 from 1,618 mbpd in 2012. The higher sales volumes are primarily associated with the acquisition of the Galveston Bay refinery in February 2013. This impact was partially offset by a decrease in refined product selling prices.

Income from equity method investments increased$10 million in 2013 compared to 2012, primarily due to an increase in income from our ethanol investments of $34 million, partially offset by a decrease in income from our investment in LOOP LLC ("LOOP") of $17 million. The increase in income from ethanol investments was primarily due to lower corn prices in 2013 compared to 2012 and the acquisition of interests in TAAE, TACE and TAEI in 2013. LOOP experienced lower operating revenues in 2013 compared to 2012 due to changing crude patterns and lower storage revenues.

Net gain on disposal of assets decreased$171 million in 2013 compared to 2012, primarily due to the absence of a $171 million gain recognized in the third quarter of 2012 associated with the settlement agreement with the buyer of our Minnesota assets. See Item 8. Financial Statements and Supplementary Data - Note 6 for additional information on the Minnesota assets sale and subsequent settlement agreement with the buyer.

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Other income increased$6 million in 2013 compared to 2012, primarily due to an increase in sales of RINs and dividends received from a pipeline affiliate, partially offset by the absence of $12 million of dividends received from our preferred equity interest in the buyer of our Minnesota assets during the third quarter of 2012.

Cost of revenues increased$18.73 billion in 2013 compared to 2012, primarily due to an increase in purchased crude oil volumes in the Refining & Marketing segment. Crude oil volumes increased33 percent in 2013 compared to 2012, primarily associated with the Galveston Bay refinery acquired in February 2013.

Purchases from related parties increased$77 million in 2013 compared to 2012, primarily due to higher ethanol volumes purchased from our ethanol investments, partially offset by lower ethanol prices and decreases in purchases from pipeline affiliates, including Centennial Pipeline LLC ("Centennial"), in 2013.

Consumer excise taxes increased$554 million in 2013 compared to 2012, primarily due to an increase in refined product sales volumes related to the Galveston Bay refinery acquired in February 2013.

Depreciation and amortization increased$225 million in 2013 compared to 2012, primarily due to the completion of the heavy oil upgrading and expansion project at our Detroit, Michigan refinery in late 2012 and our acquisition of the Galveston Bay Refinery and Related Assets in February 2013.

Other taxes increased$70 million in 2013 compared to 2012, primarily due to increases in personal property taxes of $41 million, payroll taxes of $21 million and sales and use tax expense of $13 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, the acquisition of the Galveston Bay Refinery and Related Assets and Speedway’s acquisition of 97 convenience stores in 2012.

Net interest and other financial costs increased$69 million in 2013 compared to 2012, primarily reflecting a decrease in capitalized interest in 2013 due to the completion of the Detroit refinery heavy oil upgrading and expansion project in late 2012. We capitalized interest of $28 million in 2013 compared to $101 million in 2012.

Provision for income taxes decreased$732 million in 2013 compared to 2012, primarily due to the $1.99 billiondecrease in income before income taxes in 2013. The effective tax rate of 34 percent in 2013 is less than the U.S. statutory rate of 35 percent primarily due to certain permanent benefit differences, including the domestic manufacturing deduction, partially offset by state and local tax expense. See Item 8. Financial Statements and Supplementary Data – Note 12 for further details.

Segment Results

Revenues are summarized by segment in the following table.

(In millions)	2013			2012
Refining & Marketing	$	94,910		$	76,710
Speedway	14,475			14,243
Pipeline Transportation	537			459
Segment revenues	109,922			91,412
Elimination of intersegment revenues	(9,756		)	(9,167		)
Total revenues	$	100,166		$	82,245
Items included in both revenues and costs:
Consumer excise taxes	$	6,263		$	5,709

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Refining & Marketing segment revenues increased$18.20 billion in 2013 from 2012, primarily due to an increase in refined product sales volumes related to the Galveston Bay refinery acquired in February 2013, partially offset by lower refined product selling prices. The table below shows our Refining & Marketing segment refined product sales volumes and prices.

	2013		2012
Refining & Marketing segment:
Refined product sales volumes (thousands of barrels per day)(a)	2,075		1,599
Average refined product sales prices (dollars per gallon)	$	2.87	$	3.00

^(a)  Includes intersegment sales.

The table below shows the average refined product benchmark prices for our marketing areas.

(Dollars per gallon)	2013		2012
Chicago spot unleaded regular gasoline	$	2.76	$	2.84
Chicago spot ultra-low sulfur diesel	3.01		3.01
USGC spot unleaded regular gasoline	2.69		2.81
USGC spot ultra-low sulfur diesel	2.97		3.05

Refining & Marketing intersegment sales to our Speedway segment were $9.29 billion in 2013 compared to $8.78 billion in 2012, with the increase primarily due to higher sales volume, partially offset by lower selling prices. Intersegment refined product sales volumes were 2.98 billion gallons in 2013 compared to 2.73 billion gallons in 2012, with the increased volumes primarily due to an increase in Speedway’s gasoline and distillate sales volume.

Speedway segment revenues increased$232 million in 2013 compared to 2012, primarily due to higher gasoline and distillate sales volumes, partially offset by lower gasoline and distillate selling prices, which averaged $3.45 per gallon in 2013 compared to $3.54 per gallon in 2012. The Speedway segment also had higher merchandise sales. The increases in gasoline and distillate sales volumes and merchandise sales primarily resulted from the acquisitions of convenience stores in 2013 and 2012.

Pipeline Transportation segment revenue increased$78 million in 2013 compared to 2012, primarily due to higher average tariffs received on the volumes of crude oil and products shipped, higher crude oil throughput volumes and an increase in storage fees and other revenue.

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

(In millions)	2013			2012
Income from operations by segment:
Refining & Marketing	$	3,206		$	5,098
Speedway	375			310
Pipeline Transportation(a)	210			216
Items not allocated to segments:
Corporate and other unallocated items(a)	(271		)	(336		)
Minnesota assets sale settlement gain(b)	—			183
Pension settlement expenses(c)	(95		)	(124		)
Income from operations	3,425			5,347
Net interest and other financial income (costs)(d)	(179		)	(109		)
Income before income taxes	$	3,246		$	5,238

^(a)  Included in the Pipeline Transportation segment for 2013 and 2012 are $20 million and $4 million of corporate overhead costs attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. These expenses are not currently allocated to other segments.

^(b)  See Item 8. Financial Statements and Supplementary Data - Note 6.

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

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

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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)	2013		2012
Chicago LLS 6-3-2-1(a)(b)	$	8.16	$	6.74
USGC LLS 6-3-2-1(a)	6.24		6.67
Blended 6-3-2-1(a)(c)	6.97		6.71
LLS	107.38		111.67
WTI	98.05		94.15
LLS - WTI crude oil differential(a)	9.33		17.52
Sweet/Sour crude differential(a)(d)	8.53		12.47

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

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

^(c)  Blended Chicago/USGC crack spread is 38%/62% in 2013 and 52%/48% in 2012 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 decreased$1.89 billion in 2013 from 2012, primarily due to narrower crude oil differentials and lower net product price realizations, partially offset by higher refinery throughput and sales volumes.

The sweet/sour crude oil differential narrowed by $3.94 per barrel and the LLS-WTI crude oil differential narrowed by $8.19 per barrel in 2013 compared to 2012, which we estimate had negative impacts on segment income of $1.21 billion and $998 million, respectively. We estimate the lower net product price realizations had a negative impact on segment income of $593 million.

Total refinery throughputs increased439 mbpd in 2013 compared to 2012, primarily due to the Galveston Bay refinery, which we acquired on February 1, 2013. We estimate higher refinery throughput volumes had a positive impact of $2.01 billion based on the Chicago and USGC LLS 6-3-2-1 blended crack spread, LLS-WTI crude oil differential and sweet/sour crude oil differential. However, we also had higher refinery direct operating costs primarily due to the addition of the Galveston Bay refinery.

The following table summarizes our refinery throughputs for 2013 and 2012.

	2013	2012
Refinery throughputs (thousands of barrels per day):
Crude oil refined	1,589	1,195
Other charge and blendstocks	213	168
Total	1,802	1,363
Sour crude oil throughput percent	53	53
WTI-priced crude oil throughput percent	21	28

The following table includes certain key operating statistics for the Refining & Marketing segment for 2013 and 2012.

	2013		2012
Refining & Marketing gross margin (dollars per barrel)(a)	$	13.24	$	17.85
Refinery direct operating costs (dollars per barrel):(b)
Planned turnaround and major maintenance	$	1.20	$	1.00
Depreciation and amortization	1.36		1.44
Other manufacturing(c)	4.14		3.15
Total	$	6.70	$	5.59

^(a)  Sales revenue less cost of refinery inputs and purchased products, divided by total refinery throughputs. Starting in the fourth quarter of 2013, direct operating costs are no longer included in the Refining & Marketing gross margin and the gross margin is calculated based on total refinery throughput. The 2012 gross margin has been recalculated to reflect a consistent approach.

^(b)  Per barrel of total refinery throughputs.

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

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Refinery direct operating costs increased$1.11 per barrel of total refinery throughputs in 2013 compared to 2012, which includes an increase in other manufacturing costs of $0.99 per barrel. The increase in other manufacturing costs was primarily attributable to the addition of the Galveston Bay refinery, which had higher operating costs per barrel of throughput than the average of our other six refineries.

We purchase RINs to satisfy a portion of our Renewable Fuel Standard (“RFS2”) compliance. Our cost of purchasing RINs increased to $264 million in 2013 from $105 million in 2012, primarily due to higher ethanol and biomass-based diesel RIN prices.

Speedway segment income from operations increased$65 million in 2013 compared to 2012, primarily due to higher gasoline and distillate gross margins and a higher merchandise gross margin, partially offset by higher operating expenses related to an increase in the number of convenience stores.

The following table includes certain key operating statistics for the Speedway segment for 2013 and 2012.

	2013			2012
Convenience stores at period-end	1,478			1,464
Gasoline & distillate sales (millions of gallons)	3,146			3,027
Gasoline & distillate gross margin (dollars per gallon)(a)	$	0.1441		$	0.1318
Merchandise sales (in millions)	$	3,135		$	3,058
Merchandise gross margin (in millions)	$	825		$	795
Same store gasoline sales volume (period over period)	0.5		%	(0.8		)%
Same store merchandise sales (period over period)(b)	4.3		%	7.0		%

^(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 distillate sales volume.

^(b)  Excludes cigarettes.

Pipeline Transportation segment income from operations decreased$6 million in 2013 compared to 2012. The decrease primarily reflects higher operating expenses and depreciation and lower pipeline affiliate income, partially offset by higher transportation revenue. The higher expenses and revenues were primarily attributable to the formation of MPLX.

Corporate and other unallocated expenses decreased$65 million in 2013 compared to 2012. The decrease was primarily due to lower unallocated employee benefit expenses and lower employee incentive compensation expenses.

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 6 for additional information on the Minnesota assets sale and subsequent settlement with the buyer.

We recorded pretax pension settlement expenses of $95 million in 2013 and $124 million in 2012 resulting from the level of employee lump sum retirement distributions that occurred in 2013 and 2012, respectively.

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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 & Marketing gross margin, which increased to $17.85 per barrel in 2012 from $14.26 per barrel in 2011, partially offset by higher refinery direct operating costs.

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 and sales to Marathon Oil after the Spinoff no longer being classified as related party sales.

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. 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.

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 RINs. 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 6 for additional information on the Minnesota assets sale and subsequent settlement with the buyer.

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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 7 for further discussion of the PFD preferred stock.

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 12 for further details.

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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. The table below shows our Refining & Marketing segment refined product sales volumes and prices.

	2012		2011
Refining & Marketing segment:
Refined product sales volumes (thousands of barrels per day)(a)	1,599		1,581
Average refined product sales prices (dollars per gallon)	$	3.00	$	2.93

^(a) Includes intersegment sales.

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 distillate 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 distillate sales volumes and merchandise sales were primarily due to the acquisition of 97 convenience stores in 2012.

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.

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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)	(336		)	(316		)
Minnesota assets sale settlement gain(b)	183			—
Pension settlement expenses(c)	(124		)	—
Income from operations	5,347			3,745
Net interest and other financial income (costs)(d)	(109		)	(26		)
Income before income taxes	$	5,238		$	3,719

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

^(b)  See Item 8. Financial Statements and Supplementary Data - Note 6.

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

^(d)  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 crude oil differential(a)	17.52		17.26
Sweet/Sour crude oil differential(a)(d)	12.47		9.11

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

^(b)  Calculation utilizes USGC 3% residual fuel oil price as a proxy for Chicago 3% residual fuel oil 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 & Marketing gross margin per barrel, which averaged $17.85 per barrel in 2012 compared to $14.26 per barrel in 2011, partially offset by higher refinery direct operating costs associated with higher planned turnaround and major maintenance expenses and depreciation and amortization expenses. 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 crude oil 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.

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

	2012	2011
Refinery throughputs (thousands of barrels per day):
Crude oil refined	1,195	1,177
Other charge and blendstocks	168	181
Total	1,363	1,358
Sour crude oil throughput percent	53	52
WTI-priced crude oil throughput percent	28	27

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.

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)	$	17.85	$	14.26
Refinery direct operating costs (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

^(a) Sales revenue less cost of refinery inputs and purchased products, divided by total refinery throughputs. Starting in the fourth quarter of 2013, direct operating costs are no longer included in the Refining & Marketing gross margin and the gross margin is calculated based on total refinery throughput. All prior periods presented have been recalculated to reflect a consistent approach.

^(b) Per barrel of total refinery throughputs.

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

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 distillate 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.

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 & distillate sales (millions of gallons)	3,027			2,938
Gasoline & distillate 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
Same store gasoline sales volume (period over period)	(0.8		)%	(1.7		)%
Same store merchandise sales (period over period)(b)	7.0		%	6.7		%

^(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 distillate sales volume.

^(b)  Excludes cigarettes.

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.

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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 6 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.

Liquidity and Capital Resources

Cash Flows

Our cash and cash equivalents balance was $2.29 billion at December 31, 2013 compared to $4.86 billion at December 31, 2012. 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)	2013			2012			2011
Net cash provided by (used in):
Operating activities	$	3,405		$	4,492		$	3,309
Investing activities	(2,756		)	(1,452		)	1,295
Financing activities	(3,217		)	(1,259		)	(1,643		)
Total	$	(2,568	)	$	1,781		$	2,961

Net cash provided by operating activities decreased$1.09 billion in 2013 compared to 2012, primarily due to decreases in net income of $1.26 billion and non-cash income adjustments of $453 million, partially offset by favorable changes in working capital of $626 million compared to 2012. Net cash provided from operating activities increased $1.18 billion in 2012 compared to 2011, primarily due to increases in net income of $1.00 billion and non-cash income adjustments of $620 million, partially offset by unfavorable changes in working capital of $441 million.

For 2013, changes in working capital were a net $198 millionsource of cash, primarily due to an increase in accounts payable and accrued liabilities, partially offset by increases in current receivables and inventory volumes. Accounts payable increased$1.45 billion from year-end 2012, primarily due to higher crude oil payable volumes, and current receivables increased$949 million from year-end 2012, primarily due to higher refined product receivable volumes attributable to an increase in refined product sales volumes. Both of these increases are associated with the Galveston Bay refinery acquired in February 2013. Changes in inventories were a $305 million use of cash in 2013, primarily due to higher refined product and crude oil inventory volumes.

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 current receivables 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 current receivables resulting from increases in crude oil prices and receivable volumes and refined product prices.

Cash flows from investing activities decreased $1.30 billion in 2013 compared to 2012 and decreased $2.75 billion in 2012 compared to 2011. The investing activity is further discussed below.

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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)	2013		2012			2011
Additions to property, plant and equipment	$	1,206	$	1,369		$	1,185
Acquisitions(a)	1,386		180			74
Increase (decrease) in capital accruals	73		(117		)	53
Total capital expenditures	2,665		1,432			1,312
Investments in equity method investees	124		28			11
Total capital expenditures and investments	$	2,789	$	1,460		$	1,323

^(a)  Includes $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, of $1.15 billion plus assumed liabilities of $210 million. The 2012 acquisitions exclude the inventory acquired and liability assumed. See Item 8. Financial Statements and Supplementary Data – Note 5 for further details.

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

(In millions)	2013		2012		2011
Refining & Marketing(a)	$	2,094	$	705	$	900
Speedway(b)	296		340		164
Pipeline Transportation(c)	234		211		121
Corporate and Other(d)	165		204		138
Total	$	2,789	$	1,460	$	1,323

^(a)  Includes $1.29 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Item 8. Financial Statements and Supplementary Data – Note 5.

^(b)  Includes acquisitions of nine convenience stores in 2013, 97 convenience stores in 2012 and 23 convenience stores in 2011.

^(c)  Includes $70 million in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Item 8. Financial Statements and Supplementary Data – Note 5.

^(d)  Includes capitalized interest of $28 million, $101 million and $114 million for 2013, 2012 and 2011, respectively.

The acquisition of the Galveston Bay Refinery and Related Assets comprised 49 percent of our total capital spending in 2013. The Detroit refinery heavy oil upgrading and expansion project, which we completed in 2012, comprised 46 percent and 59 percent (excluding capitalized interest associated with this project) of our Refining & Marketing segment capital spending in 2012 and 2011, respectively.

Cash provided by disposal of assets totaled $16 million, $53 million and $144 million in 2013, 2012 and 2011, respectively. The $53 million of cash from asset disposals in 2012 primarily included proceeds from a settlement 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.

Net investments in related party debt securities was a source of cash of $2.40 billion in 2011. 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 7 for further discussion of our investments in PFD preferred stock.

Net investments were a $74 millionuse of cash in 2013 compared to a $51 millionsource of cash in 2012. The change was primarily due to investments in ethanol affiliates of $75 million and the Sandpiper pipeline project of $24 million in 2013.

Net cash used in financing activities totaled $3.22 billion in 2013, $1.26 billion in 2012 and $1.64 billion in 2011. The net use of cash in 2013 and 2012 was primarily due to the common stock repurchases through open market purchases and our ASR programs and dividend payments, partially offset in 2012 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 our senior notes, revolving credit agreement and trade receivables securitization facility. See Item 8. Financial Statements and Supplementary Data - Note 19 for additional information on our long-term debt.

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Cash used in common stock repurchases totaled $2.79 billion in 2013 and $1.35 billion in 2012 associated with the share repurchase plans authorized by our board of directors. In 2013, we repurchased 36 million common shares through open market repurchases. In 2012, we entered into an $850 million ASR program on February 3, 2012, under which we repurchased 20 million shares, and a $500 million ASR program on November 5, 2012, under which we received eight million shares in 2012 and one million shares in 2013. See Item 8. Financial Statements and Supplementary Data - Note 9 for further discussion of the share repurchase plans.

Cash used in dividend payments totaled $484 million in 2013, $407 million in 2012 and $160 million in 2011. The increases in 2013 and 2012 were primarily due to having a full year of dividend payments in those years compared to 2011 and increases in our base dividend. Dividends per share were $1.54 in 2013, $1.20 in 2012 and $0.45 in 2011. These impacts were partially offset by a decrease in the number of outstanding shares of our common stock as a result of share repurchases in 2013 and 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.

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. The agreements with Marathon Oil and its subsidiaries were terminated in 2011. See Item 8. Financial Statements and Supplementary Data - Note 7 for further discussion of these financing agreements.

Net distributions to Marathon Oil totaled $783 million in 2011. 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.

Derivative Instruments

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

Capital Resources

As of December 31, 2013, we had no borrowings or letters of credit outstanding under our revolving credit agreements or our trade receivables securitization facility and our liquidity totaled $6.09 billion consisting of:

(In millions)	December 31, 2013
Cash and cash equivalents	$	2,292
Revolving credit agreement(a)	2,500
Trade receivables securitization facility	1,300
Total	$	6,092

^(a)  Excludes MPLX’s $500 million revolving credit agreement, which was undrawn as of December 31, 2013.

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.

We have a $2.5 billion unsecured revolving credit agreement ("Credit Agreement") in place with a maturity date of September 14, 2017. 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 our 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, the maturity date may be extended for up to two additional one-year periods subject to the approval of lenders holding greater than 50 percent of the commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the then-effective maturity date.

Borrowings under the Credit Agreement bear interest at either the Adjusted LIBO Rate (as defined in the Credit Agreement) plus a margin or the Alternate Base Rate (as defined in the Credit Agreement) plus a margin. We are charged various fees and expenses in connection with the Credit Agreement, including administrative agent fees, commitment fees on the unused portion of our borrowing capacity and fees related to issued and outstanding letters of credit. The applicable interest rates and certain of the fees fluctuate based on the credit ratings in effect from time to time on our long-term debt.

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The Credit Agreement contains certain representations and warranties, affirmative and restrictive covenants and events of default that we consider to be usual and customary for arrangements of this type, including a financial covenant that requires us to maintain 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 the last day of each fiscal quarter. As of December 31, 2013, we were in compliance with this debt covenant with a ratio of Consolidated Net Debt to Total Capitalization of 0.16 to 1.00. Other covenants, among other things, restrict our ability to incur debt, create liens on our assets or enter into transactions with affiliates. We were also in compliance with these other covenants contained in the Credit Agreement.

MPLX Operations LLC, an affiliate of MPC and wholly-owned subsidiary of MPLX LP, has a $500 million unsecured revolving credit agreement ("MPLX Credit Agreement") in place with a maturity date of October 31, 2017. The MPLX Credit Agreement includes letter of credit issuing capacity of up to $250 million and swingline loan capacity of up to $50 million. The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional $300 million, subject to certain conditions, including the consent of the lenders whose commitments would increase. In addition, the maturity date may be extended up to two additional one-year periods subject to the approval of lenders holding greater than 50 percent of the commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the then-effective maturity date.

Borrowings under the MPLX Credit Agreement bear interest at either the Adjusted LIBO Rate (as defined in the MPLX Credit Agreement) plus a margin, or the Alternate Base Rate (as defined in the MPLX Credit Agreement) plus a margin. MPLX is charged various fees and expenses in connection with the agreement, including administrative agent fees, commitment fees on the unused portion of the borrowing capacity and fees with respect to issued and outstanding letters of credit. The applicable interest rates and certain of the fees fluctuate based on MPLX's 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, or the credit ratings in effect from time to time on MPLX's long-term debt subsequent to the Rating Date (as defined in the MPLX Credit Agreement).

The MPLX Credit Agreement includes certain representations and warranties, affirmative and restrictive covenants and events of default that we consider to be usual and customary for an agreement of this type, including a financial covenant that requires MPLX to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA for the prior four fiscal quarters of no 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, 2013, MPLX was in compliance with this debt covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of 0.1 to 1.0. Other covenants restrict MPLX from incurring debt, creating liens on its assets and entering into transactions with affiliates. MPLX was also in compliance with these other covenants contained in the MPLX Credit Agreement.

On December 18, 2013, we entered into a three-year, $1.3 billion trade receivables securitization facility with a group of financial institutions that act as committed purchasers, conduit purchasers, letter of credit issuers and managing agents under the facility. The facility is evidenced by a Receivables Purchase Agreement and a Second Amended and Restated Receivables Sale Agreement and replaces the previously existing accounts receivable facility that was set to expire on June 30, 2014.

The facility consists of one of our wholly-owned subsidiaries, Marathon Petroleum Company LP (“MPC LP”), selling or contributing on an on-going basis all of its trade receivables (including trade receivables acquired from Marathon Petroleum Trading Canada LLC, a wholly-owned subsidiary of MPC LP), together with all related security and interests in the proceeds thereof, without recourse, to another wholly-owned, bankruptcy-remote special purpose subsidiary, MPC Trade Receivables Company LLC (“TRC”), in exchange for a combination of cash, equity or a subordinated note issued by TRC to MPC LP. TRC, in turn, has the ability to finance its purchase of the receivables from MPC LP by selling undivided ownership interests in qualifying trade receivables, together with all related security and interests in the proceeds thereof, without recourse, to the purchasing group in exchange for cash proceeds. The facility also provides for the issuance of letters of credit of up to an initial amount of $1.25 billion, provided that the aggregate credit exposure of the purchasing group is limited to no more than $1.3 billion at any one time.

To the extent that TRC retains an ownership interest in the receivables it has purchased or received from MPC LP, such interest will be included in our consolidated financial statements solely as a result of the consolidation of the financial statements of TRC with those of MPC. The receivables sold or contributed to TRC are available first and foremost to satisfy claims of the creditors of TRC and are not available to satisfy the claims of creditors of MPC. TRC has granted a security interest in all of its assets to the purchasing group to secure its obligations under the Receivables Purchase Agreement.

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Proceeds from the sale of undivided percentage ownership interests in qualifying receivables under the facility will be reflected as debt on our consolidated balance sheet, none of which was outstanding as of December 31, 2013. We will remain responsible for servicing the receivables sold to the purchasing group. TRC pays floating-rate interest charges and usage fees on amounts outstanding under the facility, if any, and certain other fees related to the administration of the facility and letters of credit that are issued and outstanding under the facility.

The Receivables Purchase Agreement and Second Amended and Restated Receivables Sale Agreement include representations and covenants that we consider usual and customary for arrangements of this type. Trade receivables are subject to customary criteria, limits and reserves before being deemed to qualify for sale by TRC pursuant to the facility. In addition, further purchases of qualified trade receivables under the facility are subject to termination, and TRC may be subject to default fees, upon the occurrence of certain amortization events that are included in the Receivables Purchase Agreement, which we consider to be usual and customary for arrangements of this type.

Our intention is to maintain an investment grade credit profile. As of December 31, 2013, the credit ratings on our senior unsecured debt were at or above investment grade level as follows.

Rating Agency	Rating
Moody’s	Baa2 (positive 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 the Credit Agreement, the MPLX Credit Agreement nor our trade receivables securitization facility contains 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 the Credit Agreement and our 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, impact our ability to purchase crude oil on an unsecured basis and could result in us having to post a letter of credit under an existing transportation services agreement.

Debt-to-Total-Capital Ratio

Our debt-to-total capital ratio (total debt to total debt-plus-equity) was 23 percent and 22 percent at December 31, 2013 and 2012, respectively.

	December 31,
(In millions)	2013			2012
Long-term debt due within one year	$	23		$	19
Long-term debt	3,373			3,342
Total debt	$	3,396		$	3,361
Calculation of debt-to-total capital ratio:
Total debt	$	3,396		$	3,361
Plus equity	11,332			12,105
Total debt plus equity	$	14,728		$	15,466
Debt-to-total capital ratio	23		%	22		%

Capital Requirements

We have a capital and investment budget for 2014 of $2.43 billion, excluding capitalized interest. Additional details related to the 2014 capital and investment budget are discussed in the Capital Budget Outlook section below.

On February 1, 2013, we acquired the Galveston Bay Refinery and Related Assets. Pursuant to the purchase and sale agreement, we may be required to pay BP a contingent earnout of up to an additional $700 million over six years, subject to certain conditions.

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We made contributions to our funded pension plans in late 2013. Therefore, we do not anticipate any additional contributions will be made in 2014.

On January 25, 2014, our board of directors approved a 42 cents per share dividend, payable March 10, 2014 to stockholders of record at the close of business on February 19, 2014.

At the beginning of 2013, we had total outstanding repurchase authorizations of $650 million. On January 30, 2013, we announced that our board of directors approved an additional $2.0 billion share repurchase authorization through December 2014. On September 26, 2013, we announced that our board of directors approved an additional $2.0 billion share repurchase authorization through September 2015. During 2013, the final shares from the $500 million ASR program initiated in 2012 were delivered to us and we paid $2.79 billion to acquire 36 million common shares through open market share repurchases. In addition, at December 31, 2013 we had agreements to acquire additional common shares for $12 million, which were settled in early January 2014. As of December 31, 2013, we had total outstanding repurchase authorizations of $1.86 billion, which expire in September 2015.

We may utilize various methods to effect additional 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 and amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.

The above discussion contains forward-looking statements with respect to share repurchase authorizations. Factors that could affect the share repurchase authorizations and the timing of any repurchases 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, 2013. 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.

(In millions)	Total		2014		2015-2016		2017-2018		Later Years
Long-term debt(a)	$	5,723	$	170	$	1,078	$	269	$	4,206
Capital lease obligations(b)	516		46		92		89		289
Operating lease obligations	969		191		336		201		241
Purchase obligations:(c)
Crude oil, feedstock, refined product and renewable fuel contracts(d)	13,689		12,017		1,005		429		238
Transportation and related contracts	4,016		214		590		777		2,435
Contracts to acquire property, plant and equipment(e)(f)	1,740		551		1,051		138		—
Service, materials and other contracts(g)	1,857		408		500		364		585
Total purchase obligations	21,302		13,190		3,146		1,708		3,258
Other long-term liabilities reported in the consolidated balance sheet(h)	1,141		74		131		279		657
Total contractual cash obligations	$	29,651	$	13,671	$	4,783	$	2,546	$	8,651

^(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)  Capital lease obligations represent future minimum payments. Item 8. Financial Statements and Supplementary Data - Note 24 includes a capital lease assumed as part of the acquisition of the Galveston Bay Refinery and Related Assets, which was originally recorded at fair value.

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

^(d)  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, 2013, has been implemented for contracts with purchase obligations of $4.96 billion.

^(e)  Includes $892 million to fund 37.5 percent of the construction of the Sandpiper pipeline project, as well as other obligations to advance funds to equity method investees.

^(f)  Includes $700 million of contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets. See Item 8. Financial Statements and Supplementary Data - Note 5 for additional information on this acquisition.

^(g)  Primarily 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 2023. See Item 8. Financial Statements and Supplementary Data - Note 22.

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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. Our off-balance sheet arrangements are limited to indemnities and guarantees that are described below. Although these arrangements serve a variety of our business purposes, we are not dependent on them 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.

Capital Budget Outlook

We have a capital and investment budget for 2014 of $2.43 billion, excluding capitalized interest. This represents a 12 percent decrease from our 2013 spending, which is primarily due to the acquisition of the Galveston Bay Refinery and Related Assets in 2013, partially offset by an expected increase in the Pipeline Transportation segment capital spending. 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 Refining & Marketing segment's 2014 capital budget is $1.21 billion, which includes $348 million for midstream assets. The focus of our spending in the Refining & Marketing segment is on processing more condensate and light crude oil, growing distillate production and increasing export volumes. A number of these projects span multiple years.

We have approximately $345 million of capital projects that will allow us to process and handle condensate and light crude oil from the Utica Shale region, of which approximately $225 million has been budgeted for 2014. We have projects to invest in condensate splitters at our Canton and Catlettsburg refineries to allow the refineries to process up to 60 mbpcd of condensate from the Utica Shale region and to increase the light crude oil processing capacity at our Robinson refinery by 30 mbpcd, which will allow it to run 100 percent light crude oil. These projects are expected to be complete in 2014 for our Canton refinery, 2015 for our Catlettsburg refinery and 2016 for our Robinson refinery. In addition, we completed a truck-to-barge crude system project at our Wellsville terminal and are continuing to purchase new barges to allow Utica production to be transported from our Wellsville terminal to our Catlettsburg refinery.

We have approximately $315 million of capital projects that will allow us to increase our diesel production, of which approximately $90 million has been budgeted for 2014. At our Garyville refinery, we completed a project in 2013 to modify one of the crude units to improve distillate recovery, we completed a hydrocracker expansion in the first quarter of 2014 that increased the hydrocracker capacity to 110 mbpcd and we expect to complete a project to expand the distillate hydrotreater by 10 mbpcd in the first quarter of 2015. At our Galveston Bay refinery, we have a hydrocracker project designed to increase our ULSD production by 9 mbpd by shifting yields from gasoline, which we expect to complete in 2015. At our Robinson refinery, we have a similar project to revamp our distillate hydrocracker to improve margins by processing more feedstock at a lower conversion and shifting approximately 5 mbpd of light products to ULSD production. The project is expected to be completed in 2015.

We budgeted $90 million in 2014 and $40 million in 2015 for a front-end engineering and design study for a residual fuel hydrocracker project at our Garyville refinery to increase margins by upgrading residual fuel to ULSD and gas oil. It would use hydrogen produced from low-cost natural gas to increase the liquid volume by approximately ten percent. If we proceed with the project, we expect that it will increase Garyville's ULSD production by 28 mbpd and reduce gas oil purchases by 30 mbpd. If we proceed with this project, we expect to invest $2.2 billion to $2.5 billion and anticipate completion in 2018.

We are also evaluating three potential projects for our Galveston Bay refinery. The first project is to increase its hydrotreating capacity that will enable it to produce 100 percent ULSD. The second project is to build a gas oil hydrocracker and shut down one of the smaller catalytic cracking units in order to shift production from gasoline to ULSD. The third is to revamp the existing crude units for improved fractionation and enhanced distillate recovery.

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

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Speedway

The Speedway segment's 2014 capital budget is $327 million, primarily for new convenience store construction and land acquisitions to expand our markets and remodeling and rebuilding projects to upgrade and enhance our existing facilities. We have identified numerous opportunities for new convenience stores and store rebuilds in our existing markets. In addition, we are actively acquiring real estate in western Pennsylvania and Tennessee to be in a position to accelerate the pace of growth in these new contiguous markets over the next several years. Also included in the capital budget are expenditures for technology, equipment and dispenser upgrades.

Pipeline Transportation

The Pipeline Transportation segment's 2014 capital budget is $760 million, primarily for equity investments in major pipeline projects, new infrastructure and upgrades to replace or enhance our existing facilities.

We agreed to fund 37.5 percent of the construction of the Sandpiper pipeline project and serve as an anchor shipper in exchange for an approximate 27 percent equity interest in Enbridge's North Dakota System when the Sandpiper pipeline is placed into service, which is targeted for early 2016. The project is estimated to cost $2.6 billion, of which approximately $1.0 billion is our share. We will also have the option to increase our ownership interest to approximately 30 percent through additional investments in future system improvements. In addition, we agreed to be the anchor shipper on Enbridge Inc.'s proposed Southern Access Extension pipeline in exchange for the option to acquire a 25 percent equity interest in the pipeline. The project is expected to be operational in 2015. As a result of our commitment to the Sandpiper pipeline project, our option for equity interest in the Southern Access Extension pipeline increased an additional 10 percent to a total of 35 percent. We budgeted approximately $460 million in 2014 and $1.45 billion in total for these equity interests.

In addition, MPLX is planning to construct a $140 million pipeline to connect Utica Shale production in southeastern Ohio to our Canton refinery. The project is called the Cornerstone Pipeline and it is anticipated to be operational in 2016.

Corporate and Other

The remaining 2014 capital budget includes $133 million, primarily related to an expansion project for our corporate headquarters and upgrades to information technology systems. In addition, we project $38 million of capitalized interest associated with various capital projects.

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 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.

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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.

For the period prior to the Spinoff, purchases of crude oil and natural gas from Marathon Oil accounted for five percent of our total cost of revenues and purchases from related parties. 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 7 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.

Our environmental expenditures, including non-regulatory expenditures, for each of the last three years were:

(In millions)	2013		2012		2011
Capital	$	50	$	115	$	167
Compliance:(a)
Operating and maintenance	321		318		354
Remediation(b)	22		24		27
Total	$	393	$	457	$	548

^(a)  Based on the American Petroleum Institute’s definition of environmental expenditures.

^(b)  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.

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Our environmental capital expenditures accounted for two percent, eight percent and 13 percent of capital expenditures in 2013, 2012 and 2011, respectively. Our environmental capital expenditures are expected to approximate $126 million, or five percent, of total capital expenditures in 2014. Predictions beyond 2014 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 $391 million in 2015; 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.

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.

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 17 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 values for acquisitions; and

• recorded values of derivative instruments.

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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 refinery and pipeline throughput volumes are based on internal forecasts prepared by our Refining & Marketing and Pipeline Transportation segments 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, 2013, we had a total of $938 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 2013.

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, 2013, we had $463 million of investments in equity method investments recorded on 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.

Centennial experienced a significant reduction in shipment volumes in the second half of 2011 that has continued through 2013. At December 31, 2013, Centennial was not shipping product. As a result, we continued to evaluate the carrying value of our equity investment in Centennial. We concluded that no impairment was required given our assessment of its fair value based on market participant assumptions for various potential uses and future cash flows of Centennial’s assets. If current business conditions remain unchanged and the owners of Centennial are unable to find an alternative use for the assets, there could be a future impairment of our Centennial interest. As of December 31, 2013, our equity investment in Centennial was $29 million and we had a $42 million guarantee associated with 50 percent of Centennial's outstanding debt. See Item 8. Financial Statements and Supplementary Data – Note 25 for additional information on the debt guarantee.

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The above discussion contains forward-looking statements with respect to the carrying value of our Centennial equity investment. Factors that could affect the carrying value of our Centennial equity investment include, but are not limited to, a change in business conditions, a further decline or improvement in the long-term outlook of the potential uses of Centennial’s assets and the pursuit of different strategic alternatives for such assets. These factors, among others, could cause actual results to differ materially from those set forth in the forward-looking statements.

Acquisitions

In accounting for business combinations, acquired assets and liabilities and contingent consideration are recorded based on estimated fair values as of the date of acquisition. The excess or shortfall of the purchase price when compared to the fair value of the net tangible and identifiable intangible assets acquired, if any, is recorded as goodwill or a bargain purchase gain, respectively. A significant amount of judgment is involved in estimating the individual fair values of property, plant and equipment, intangible assets, contingent consideration and other assets and liabilities. We use all available information to make these fair value determinations and, for certain acquisitions, engage third-party consultants for assistance.

The fair value of assets and liabilities, including contingent consideration, as of the acquisition date are often estimated using a combination of approaches, including the income approach, which requires us to project related future cash inflows and outflows and apply an appropriate discount rate; the cost approach, which requires estimates of replacement costs and depreciation and obsolescence estimates; and the market approach which uses market data and adjusts for entity-specific differences. The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine fair value.

The fair value of the contingent consideration we expect to pay to BP is re-measured each quarter using an income approach, with changes in fair value recorded in cost of revenues. The amount of cash to be paid under the arrangement is based on both a market-based crack spread and refinery throughput volumes for the months during which the contract applies, as well as established thresholds that cap the annual and total payment. We used internal and external forecasts for the crack spread and internal forecasts for refinery throughput volumes and applied an appropriate risk-adjusted discount rate to the range of cash flows indicated by various scenarios to determine the fair value of the arrangement. See Item 8. Financial Statements and Supplementary Data - Note 5 for additional information on our acquisitions. See Item 8. Financial Statements and Supplementary Data - Note 17 for additional information on fair value measurements.

Derivatives

We record all derivative instruments at fair value. All of our commodity derivatives are cleared through exchanges which provide active trading information for identical derivatives and do not require any 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 17. 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 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 have an average rating of Aa or higher by a recognized rating agency and generally 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.

62

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 4.30 percent for our pension plans and 4.95 percent for our other postretirement benefit plans by 0.25 percent would increase pension obligations and other postretirement benefit plan obligations by $39 million and $25 million, respectively, and would increase defined benefit pension expense and other postretirement benefit plan expense by $3 million and $3 million, respectively.

The long-term asset rate of return assumption considers the asset mix of the plans (currently targeted at approximately 62 percent equity securities and 38 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, along with the current and projected plan investments, we reduced the asset rate of return from 7.50 percent to 7.00 percent effective for 2014. We used the 7.50 percent long-term rate of return to determine our 2013 defined benefit pension expense. Decreasing the 7.00 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.

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

There are no accounting standards that have not yet been adopted as of December 31, 2013.

63

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, 2013, 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 17 and 18 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 and 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.

Open Derivative Positions and Sensitivity Analysis

The table below sets forth information relating to our significant open commodity derivative contracts as of December 31, 2013.

	December 31, 2013
	Position	Total Barrels (In thousands)	Weighted Average Price (Per barrel)	Benchmark
Crude Oil(a)
Exchange-traded	Long	10,580	$102.83	CME and ICE Crude(b)(c)
Exchange-traded	Short	(23,900)	$104.99	CME and ICE Crude(b)(c)
Refined Products(a)
Exchange-traded	Long	3,646	$2.96	CME Heating Oil and RBOB(b)(d)
Exchange-traded	Short	(4,175)	$2.94	CME Heating Oil and RBOB(b)(d)

^(a)100 percent of these contracts expire in the first quarter of 2014.

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

^(c) Intercontinental Exchange (“ICE”).

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

64

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, 2013 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%
December 31, 2013
Crude	$	(135	)	$	(338	)	$	143	$	357
Refined products	(4		)	(10		)	8		23

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, 2013 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, 2013, our debt was primarily comprised of the $3.0 billion fixed rate senior notes issued on February 1, 2011.

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, 2013 is provided in the following table.

(In millions)	Fair Value				Incremental Change in Fair Value
Financial assets (liabilities)(a)
Long-term debt(b)	$	(3,306	)	(c)	$	(302	)	(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, 2013.

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

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 2013.

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.

65

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.

66

Item 8. Financial Statements and Supplementary Data

Index

	Page
Management’s Responsibilities for Financial Statements	68
Management’s Report on Internal Control Over Financial Reporting	68
Report of Independent Registered Public Accounting Firm	69
Audited Consolidated Financial Statements:
Consolidated Statements of Income	70
Consolidated Statements of Comprehensive Income	71
Consolidated Balance Sheets	72
Consolidated Statements of Cash Flows	73
Consolidated Statements of Equity / Net Investment	74
Notes to Consolidated Financial Statements	75
Selected Quarterly Financial Data (Unaudited)	118
Supplementary Statistics (Unaudited)	119

67

Management’s Responsibilities for Financial Statements

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
Gary R. Heminger President and Chief Executive Officer	Donald C. Templin Senior Vice President and Chief Financial Officer	Michael G. Braddock Vice President and Controller

Management’s Report on Internal Control over Financial Reporting

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 (1992) 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, 2013.

Management has excluded from its assessment of the Company’s internal control over financial reporting as of December 31, 2013 certain elements of the internal control over financial reporting of the Galveston Bay Refinery and Related Assets that the Company acquired in February 2013. See Note 5 for additional information about the acquisition. Subsequent to the acquisition, the seller provided to the Company under a transition services agreement certain elements of the acquired businesses’ reporting and related functions, processes and systems. Those elements of the acquired businesses’ internal control over financial reporting that were not fully integrated into the Company’s existing internal control over financial reporting during 2013 have been excluded from management’s assessment of the effectiveness of the internal control over financial reporting as of December 31, 2013. The excluded elements represent controls over accounts of approximately 1% of consolidated assets, 1% of consolidated liabilities and 1% of consolidated costs and expenses. We plan to fully integrate the acquired businesses into our internal control over financial reporting in 2014.

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

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

68

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

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

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

As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded certain elements of the internal control over financial reporting of the Galveston Bay Refinery and Related Assets (as defined in Footnote 5) that the Company acquired in February 2013 from its assessment of the Company’s internal control over financial reporting as of December 31, 2013. Subsequent to the acquisition, the seller provided to the Company under a transition services agreement certain elements of the acquired businesses’ reporting and related functions, processes and systems. Those elements of the acquired businesses’ internal control over financial reporting that were not fully integrated into the Company's existing internal control over financial reporting during 2013 have been excluded from management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2013. We have also excluded these elements of the internal control over financial reporting of the acquired businesses from our audit of the Company’s internal control over financial reporting. The excluded elements represent controls over accounts of approximately 1% of consolidated assets, 1% of consolidated liabilities and 1% of the consolidated costs and expenses of the related consolidated financial statement amounts as of and for the year ended December 31, 2013.

/s/PricewaterhouseCoopers LLP

Toledo, Ohio

February 28, 2014

69

Marathon Petroleum Corporation

Consolidated Statements of Income

(In millions, except per share data)	2013			2012			2011
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$	100,152		$	82,235		$	78,583
Sales to related parties	8			8			55
Income from equity method investments	36			26			50
Net gain on disposal of assets	6			177			12
Other income	52			46			59
Total revenues and other income	100,254			82,492			78,759
Costs and expenses:
Cost of revenues (excludes items below)	87,401			68,668			65,795
Purchases from related parties	357			280			1,916
Consumer excise taxes	6,263			5,709			5,114
Depreciation and amortization	1,220			995			891
Selling, general and administrative expenses	1,248			1,223			1,059
Other taxes	340			270			239
Total costs and expenses	96,829			77,145			75,014
Income from operations	3,425			5,347			3,745
Related party net interest and other financial income	—			1			35
Net interest and other financial income (costs)	(179		)	(110		)	(61		)
Income before income taxes	3,246			5,238			3,719
Provision for income taxes	1,113			1,845			1,330
Net income	2,133			3,393			2,389
Less net income attributable to noncontrolling interests	21			4			—
Net income attributable to MPC	$	2,112		$	3,389		$	2,389
Per Share Data (See Note 8)
Basic:
Net income attributable to MPC per share	$	6.69		$	9.95		$	6.70
Weighted average shares outstanding	315			340			356
Diluted:
Net income attributable to MPC per share	$	6.64		$	9.89		$	6.67
Weighted average shares outstanding	317			342			357
Dividends paid	$	1.54		$	1.20		$	0.45

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

70

Marathon Petroleum Corporation

Consolidated Statements of Comprehensive Income

(In millions)	2013			2012		2011
Net income	$	2,133		$	3,393	$	2,389
Other comprehensive income (loss):
Defined benefit postretirement and post-employment plans:
Actuarial changes, net of tax of $174, $47, and ($151)	294			78		(248		)
Prior service costs, net of tax of ($19), $203, and $2	(34		)	337		4
Other, net of tax of $-, $- and $-	—			—		(1		)
Other comprehensive income (loss)	260			415		(245		)
Comprehensive income	2,393			3,808		2,144
Less comprehensive income attributable to noncontrolling interests	21			4		—
Comprehensive income attributable to MPC	$	2,372		$	3,804	$	2,144

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

71

Marathon Petroleum Corporation

Consolidated Balance Sheets

	December 31,
(In millions, except per share data)	2013			2012
Assets
Current assets:
Cash and cash equivalents	$	2,292		$	4,860
Receivables, less allowance for doubtful accounts of $9 and $10	5,559			4,610
Inventories	4,689			3,449
Other current assets	197			110
Total current assets	12,737			13,029
Equity method investments	463			321
Property, plant and equipment, net	13,921			12,643
Goodwill	938			930
Other noncurrent assets	326			300
Total assets	$	28,385		$	27,223
Liabilities
Current liabilities:
Accounts payable	$	8,234		$	6,785
Payroll and benefits payable	406			364
Consumer excise taxes payable	373			325
Accrued taxes	513			598
Long-term debt due within one year	23			19
Other current liabilities	275			112
Total current liabilities	9,824			8,203
Long-term debt	3,373			3,342
Deferred income taxes	2,304			2,050
Defined benefit postretirement plan obligations	771			1,266
Deferred credits and other liabilities	781			257
Total liabilities	17,053			15,118
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 - 362 million and 361 million shares (par value $0.01 per share, 1 billion shares authorized)	4			4
Held in treasury, at cost - 65 million and 28 million shares	(4,155		)	(1,253		)
Additional paid-in capital	9,768			9,527
Retained earnings	5,507			3,880
Accumulated other comprehensive loss	(204		)	(464		)
Total MPC stockholders’ equity	10,920			11,694
Noncontrolling interests	412			411
Total equity	11,332			12,105
Total liabilities and equity	$	28,385		$	27,223

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

72

Marathon Petroleum Corporation

Consolidated Statements of Cash Flows

(In millions)	2013			2012			2011
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	2,133		$	3,393		$	2,389
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	1,220			995			891
Pension and other postretirement benefits, net	(124		)	153			(90		)
Deferred income taxes	23			492			123
Net gain on disposal of assets	(6		)	(177		)	(12		)
Equity method investments, net	(18		)	11			(2		)
Changes in the fair value of derivative instruments	(21		)	59			(57		)
Changes in:
Current receivables	(940		)	851			(1,177		)
Inventories	(305		)	(115		)	(255		)
Current accounts payable and accrued liabilities	1,464			(1,223		)	1,502
All other, net	(21		)	53			(3		)
Net cash provided by operating activities	3,405			4,492			3,309
Investing activities:
Additions to property, plant and equipment	(1,206		)	(1,369		)	(1,185		)
Acquisitions	(1,515		)	(190		)	(74		)
Disposal of assets	16			53			144
Investments in related party debt securities – purchases	—			—			(10,326		)
– redemptions	—			—			12,730
Investments—acquisition, loans and contributions	(151		)	(57		)	(56		)
—redemptions and repayments	77			108			53
All other, net	23			3			9
Net cash provided by (used in) investing activities	(2,756		)	(1,452		)	1,295
Financing activities:
Long-term debt payable to Marathon Oil and subsidiaries – borrowings	—			—			7,748
– repayments	—			—			(11,366		)
Long-term debt – borrowings	—			—			2,989
– repayments	(21		)	(17		)	(12		)
Debt issuance costs	(4		)	(6		)	(60		)
Issuance of common stock	48			108			1
Common stock repurchased	(2,793		)	(1,350		)	—
Dividends paid	(484		)	(407		)	(160		)
Net proceeds from issuance of MPLX LP common units	—			407			—
Distributions to noncontrolling interests	(21		)	—			—
Distributions to Marathon Oil Corporation	—			—			(783		)
Tax settlement with Marathon Oil Corporation	39			—			—
All other, net	19			6			—
Net cash used in financing activities	(3,217		)	(1,259		)	(1,643		)
Net increase (decrease) in cash and cash equivalents	(2,568		)	1,781			2,961
Cash and cash equivalents at beginning of period	4,860			3,079			118
Cash and cash equivalents at end of period	$	2,292		$	4,860		$	3,079

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

73

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, 2010	$	—	$	—		$	—		$	—		$	8,867		$	(623	)	$	—		$	8,244
Net income	—		—			—			1,058			1,331			—			—			2,389
Dividends declared	—		—			—			(160		)	—			—			—			(160		)
Distributions to Marathon Oil Corporation	—		—			—			—			(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 declared	—		—			—			(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
Net income	—		—			—			2,112			—			—			21			2,133
Dividends declared	—		—			—			(485		)	—			—			—			(485		)
Distributions to noncontrolling interests	—		—			—			—			—			—			(21		)	(21		)
Other comprehensive income	—		—			—			—			—			260			—			260
Shares repurchased	—		(2,893		)	100			—			—			—			—			(2,793		)
Shares issued (returned)—stock based compensation	—		(9		)	47			—			—			—			—			38
Stock-based compensation	—		—			55			—			—			—			1			56
Tax settlement with Marathon Oil Corporation	—		—			39			—			—			—			—			39
Balance as of December 31, 2013	$	4	$	(4,155	)	$	9,768		$	5,507		$	—		$	(204	)	$	412		$	11,332

(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	)
Shares repurchased	—	(37	)
Shares issued—stock-based compensation	1	—
Balance as of December 31, 2013	362	(65	)

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

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Notes to Consolidated Financial Statements

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

Description of the Business – As used in this report, the terms "MPC," "we," "us," "the Company" or "our" may refer to Marathon Petroleum Corporation, one or more of its consolidated subsidiaries or all of them taken as a whole.

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”).

See Note 10 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 statement of income for the period 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 period 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 period 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 7.

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 generally 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 and liabilities, except for the excess related to goodwill.

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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 our 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. Rebates to customers are reflected as a reduction of revenue and are accrued for in accounts payable on the consolidated balance sheets.

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 and investments in highly liquid debt instruments with maturities of three months or less.

Restricted cash - Restricted cash consists of cash advances to be used for the operation and maintenance of an operated pipeline system. At December 31, 2013, the amount of restricted cash included in other current assets on the consolidated balance sheets was $7 million.

Accounts receivable and allowance for doubtful accounts – Our receivables primarily consist of customer accounts receivable. The allowance for doubtful accounts is the best estimate of the amount of probable credit losses in customer accounts receivable and is based on historical write-off experience. 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 38 percent and 42 percent of our accounts receivable balances at December 31, 2013 and 2012, 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 100 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, historically, to 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.

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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.

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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 – 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.

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.

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 33 percent of our common stock volatility and 67 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. The fair value of performance unit awards granted to our employees is estimated on the date of grant using a Monte Carlo valuation model.

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.

Renewable fuel identification numbers ("RINs") - We purchase RINs to satisfy a portion of our Renewable Fuel Standard ("RFS2") compliance. We record a short-term intangible asset, included in other current assets on the balance sheet, for RINs owned in excess of our anticipated current period compliance requirements. The asset value is based on the product of the excess RINs as of the balance sheet date, if any, and the average cost of our RINs. We record a current liability, included in other current liabilities on the balance sheet, when we are deficient RINs based on the product of the deficient RINs as of the balance sheet date, if any, and the market price of the RINs at the balance sheet date. The cost of RINs used for compliance is reflected in cost of revenues.Any gains or losses on the sale or expiration of RINs are classified as other income.

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3. Accounting Standards

Recently 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 U.S. generally accepted accounting principles ("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 reclassified 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 was to be applied prospectively for interim and annual periods beginning with the first quarter of 2013. The adoption of this accounting standards update in the first quarter of 2013 did not have an impact on our consolidated results of operations, financial position or cash flows. The new required disclosures are included in Note 21.

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 was effective for annual and interim impairment tests performed in fiscal years beginning after September 15, 2012. Early adoption was permitted. The adoption of this accounting standards update in the first quarter of 2013 did not have an impact on our consolidated results of operations, financial position or cash flows. We perform the annual intangible asset impairment testing in the fourth quarter.

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 was to be applied retrospectively and was effective for interim and annual periods beginning with the first quarter of 2013. The adoption of this accounting standards update in the first quarter of 2013 did not have an impact on our consolidated results of operations, financial position or cash flows. The new required disclosures are included in Note 17.

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. In October 2012, MPLX completed its initial public offering of 19,895,000 common units. Net proceeds to MPLX from the sale of the units were $407 million. We own a 73.6 percent interest in MPLX, including the two percent general partner interest. We consolidate this entity for financial reporting purposes since we have a controlling financial interest, and we record a noncontrolling interest for the interest owned by the public. The initial public offering represented the sale of a 26.4 percent interest in MPLX.

MPLX's initial assets consisted 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. On May 1, 2013, we sold an additional five percent interest in Pipe Line Holdings to MPLX for $100 million, increasing MPLX's ownership interest in Pipe Line Holdings to 56 percent and reducing our ownership to 44 percent.

On February 27, 2014, we announced the sale of an additional 13 percent interest in Pipe Line Holdings to MPLX for $310 million, effective March 1, 2014. Subsequent to this transaction, MPLX will own a 69 percent general partner interest in Pipe Line Holdings and we will own a 31 percent limited partner interest. MPLX intends to finance this transaction with $40 million of cash on-hand and by borrowing $270 million on its revolving credit agreement.

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 nine long-term, fee-based transportation agreements and five long-term, fee-based 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. These agreements range from three to ten years in length, and most automatically renew unless terminated by either party. We believe the terms and conditions under these commercial agreements, as well as the other initial agreements we entered into with MPLX are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services.

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. Any such deficiency payments may then be applied as a credit for volumes transported on the applicable pipeline system in excess of its minimum volume commitment during the following four or eight quarters under the terms of the applicable transportation services agreement. As of December 31, 2013, we had $34 million in volume deficiency credits. 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 are 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, which is 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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5. Acquisitions and Investments

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, four light product terminals, branded-jobber marketing contract assignments for the supply of approximately 1,200 branded sites, a 1,040 megawatt electric cogeneration facility and a 50,000 barrel per day allocation of space on the Colonial Pipeline. We refer to these assets as the “Galveston Bay Refinery and Related Assets.” We paid $1.49 billion for these assets, which included $935 million for inventory. 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 as discussed below. 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.

As of the acquisition date, we recorded a contingent liability of $600 million, representing the preliminary fair value of contingent consideration we expect to pay to BP related to the earnout provision. The fair value of the contingent consideration was estimated using an income approach. The amount of cash to be paid under the arrangement is based on both a market-based crack spread and refinery throughput volumes for the months during which the contract applies, as well as established thresholds that cap the annual and total payment. The earnout payment cannot exceed $200 million per year for the first three years of the arrangement or $250 million per year for the last three years of the arrangement, with the total cumulative payment capped at $700 million over the six-year period. Any excess or shortfall from the annual cap for a current year’s earnout calculation will not affect subsequent years’ calculations. We used internal and external forecasts for the crack spread and internal forecasts for refinery throughput volumes and applied an appropriate risk-adjusted discount rate to the range of cash flows indicated by various scenarios to determine the fair value of the arrangement. The fair value of the contingent consideration is reassessed each quarter, with changes in fair value recorded in cost of revenues. The fair value of the contingent consideration was $625 million at December 31, 2013, which includes $159 million classified as current. See Note 17 for additional information.

The transaction provided for a post-closing adjustment for inventory, which was finalized for $9 million, reducing our total consideration.

The components of the fair value of consideration transferred are as follows:

(In millions)
Cash	$	1,491
Fair value of contingent consideration as of acquisition date	600
Payable to seller	6
Post-closing adjustment	(9		)
Total consideration	$	2,088

During the fourth quarter of 2013, an independent appraisal of the assets acquired and liabilities assumed and other evaluations were completed and finalized. Minor updates to the preliminary fair value measurements of assets acquired and liabilities assumed were made during the second and third quarters of 2013. The following table summarizes the final amounts assigned to the assets acquired and liabilities assumed as of the acquisition date.

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(In millions)
Inventories	$	935
Other current assets	1
Property, plant and equipment, net	1,274
Other noncurrent assets	88
Accounts payable	(12		)
Payroll and benefits payable	(14		)
Long-term debt due within one year(a)	(2		)
Other current liabilities	(6		)
Long-term debt(a)	(58		)
Defined benefit postretirement plan obligations	(43		)
Deferred credits and other liabilities	(75		)
Total	$	2,088

^(a) Represents a capital lease obligation assumed.

Neither goodwill nor a gain from a bargain purchase was recognized in conjunction with the Galveston Bay Refinery and Related Assets acquisition.

Other noncurrent assets consist of a $20 million intangible asset related to customer relationships and a $68 million intangible asset related to prepaid licensed refinery technology agreements. The intangible assets related to customer relationships and prepaid licensed refinery technology agreements are being amortized on a straight-line basis over four and 15 years, respectively. The weighted average life over which these acquired intangibles are being amortized is approximately 13 years.

We recognized $7 million of acquisition-related costs associated with the Galveston Bay Refinery and Related Assets acquisition. These costs were expensed and were included in selling, general and administrative expenses.

Our refineries and related assets are operated as an integrated system. As the information is not available by refinery, it is not practicable to disclose the revenues and net income associated with the acquisition that were included in our consolidated statements of income for 2013.

The following unaudited pro forma financial information presents consolidated results assuming the Galveston Bay Refinery and Related Assets acquisition occurred on January 1, 2012. The pro forma financial information does not give effect to potential synergies that could result from the acquisition and is not necessarily indicative of the results of future operations.

(In millions, except per share data)	2013		2012
Sales and other operating revenues (including consumer excise taxes)	$	102,120	$	104,165
Net income attributable to MPC	2,167		3,625
Net income attributable to MPC per share - basic	$	6.88	$	10.66
Net income attributable to MPC per share - diluted	6.84		10.60

The pro forma information includes adjustments to align accounting policies, an adjustment to depreciation expense to reflect the fair value of property, plant and equipment, increased amortization expense related to identifiable intangible assets and the related income tax effects. The pro forma information reflects revisions made during the second and third quarters of 2013 to the estimated fair values of assets acquired and liabilities assumed.

Acquisitions of Convenience Stores

During 2013, Speedway acquired nine convenience stores located in Tennessee, western Indiana and western Pennsylvania. In connection with these acquisitions, our Speedway segment recorded $8 million of goodwill.

In July 2012, Speedway 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.

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In May 2012, Speedway 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.

In May 2011, Speedway acquired 23 convenience stores in Indiana and Illinois. In connection with this acquisition, our Speedway segment recorded $9 million of goodwill.

The goodwill associated with these acquisitions is deductible for income tax purposes.

These acquisitions support our strategic initiative to increase our Speedway segment sales and profitablity. 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.

Investments in Ethanol Companies

On August 1, 2013, we acquired from Mitsui & Co. (U.S.A.), Inc. its interests in three ethanol companies for $75 million. Under the purchase agreement, we acquired an additional 24 percent interest in The Andersons Clymers Ethanol LLC ("TACE"), bringing our ownership interest to 60 percent; a 34 percent interest in The Andersons Ethanol Investment LLC ("TAEI"), which holds a 50 percent ownership in The Andersons Marathon Ethanol LLC ("TAME"), bringing our direct and indirect ownership interest in TAME to 67 percent; and a 40 percent interest in The Andersons Albion Ethanol LLC ("TAAE"), which owns an ethanol production facility in Albion, Michigan. On October 1, 2013, our ownership interest in TAAE increased to 43 percent as a result of TAAE acquiring one of the owner's interest. We hold a noncontrolling interest in each of these entities and account for them using the equity method of accounting since the minority owners have substantive participating rights.

Investment in Pipeline

During 2013, we made initial contributions of $24 million to acquire an ownership interest in North Dakota Pipeline Company LLC ("North Dakota Pipeline"). These contributions funded 37.5 percent of the construction costs incurred to-date on the Sandpiper pipeline project. In conjunction with our commitment to be an anchor shipper for the Sandpiper pipeline and our investment in the project, we will earn an approximate 27 percent equity interest in Enbridge Energy Partner L.P.'s North Dakota System when the Sandpiper pipeline is placed into service in 2016. We will also have the option to increase our ownership interest to approximately 30 percent through additional investments in future system improvements. We account for our interest in North Dakota Pipeline using the equity method of accounting. See Note 25 for information on future contributions to North Dakota Pipeline.

6. 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) lease 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.

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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.

During 2013, the buyer redeemed the second preferred security for $49 million, which included $4 million of accrued distributions.

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.

7. Related Party Transactions

Our related parties included:

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

• TAAE, in which we have a 43 percent interest, TACE, in which we have a 60 percent noncontrolling interest, and TAME, in which we have a 67 percent direct and indirect noncontrolling interest. These companies each own an ethanol production facility.

• Centennial Pipeline LLC (“Centennial”), in which we have a 50 percent noncontrolling 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.

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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)	2013		2012		2011
Equity method investees:
Centennial	$	—	$	1	$	35
Other equity method investees	8		7		7
Marathon Oil Companies	—		—		13
Total	$	8	$	8	$	55

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 Centennial's pipeline, which are included in other income on the consolidated statements of income, were $1 million in both 2013 and 2012.

Purchases from related parties were as follows:

(In millions)	2013		2012		2011
Equity method investees:
Centennial	$	3	$	7	$	31
LOOP	43		44		66
TAAE	24		—		—
TACE	130		73		46
TAME	131		124		153
Other equity method investees	26		32		30
Marathon Oil Companies	—		—		1,590
Total	$	357	$	280	$	1,916

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 TAAE, TACE and TAME 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 for 2011.

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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)	2013		2012
Centennial	$	1	$	2
TAME	1		—
Total	$	2	$	2

At December 31, 2013, we also had a $2 million long-term receivable from Centennial, which is included in other noncurrent assets on the consolidated balance sheet.

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

	December 31,
(In millions)	2013		2012
LOOP	$	3	$	4
TAAE	2		—
TACE	4		2
TAME	5		5
Other equity method investees	2		2
Total	$	16	$	13

We had a throughput and deficiency agreement with Centennial, which expired on March 31, 2012. During 2012, we impaired our $14 million prepaid tariff with Centennial. For additional information on the impairment, see Note 17.

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. 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. 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 for 2013 and 2012 was not material. Related party net interest and other financial income for 2011 was as follows:

(In millions)	2011
Dividend income:
PFD Preferred Stock	$	35
Interest expense:
PFD revolving credit agreement	3
Marathon Oil loan agreement	5
Interest capitalized	(8		)
Total	—
Related party net interest and other financial income	$	35

We also recorded property, plant and equipment additions related to capitalized interest incurred by Marathon Oil on our behalf of $2 million in 2011, 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 were recorded as non-cash capital contributions or distributions. The net non-cash capital contributions from Marathon Oil were $57 million in 2011.

8. Income per Common Share

We compute basic earnings per share by dividing net income attributable to MPC by the weighted average number of shares of common stock outstanding. Diluted income per share assumes exercise of certain stock based compensation awards, 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 for periods prior to the Spinoff 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 for periods prior to the Spinoff. Excluded from the diluted share calculation are less than one million, approximately two million and approximately four million shares related to stock-based compensation awards in 2013, 2012 and 2011, 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.

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(In millions, except per share data)	2013		2012		2011
Basic earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	2,112	$	3,389	$	2,389
Income allocated to participating securities	4		6		4
Income available to common stockholders - basic	$	2,108	$	3,383	$	2,385
Weighted average common shares outstanding	315		340		356
Basic earnings per share	$	6.69	$	9.95	$	6.70
Diluted earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	2,112	$	3,389	$	2,389
Income allocated to participating securities	4		6		4
Income available to common stockholders - diluted	$	2,108	$	3,383	$	2,385
Weighted average common shares outstanding	315		340		356
Effect of dilutive securities	2		2		1
Weighted average common shares, including dilutive effect	317		342		357
Diluted earnings per share	$	6.64	$	9.89	$	6.67

9. Equity

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 to expire in December 2014. On September 26, 2013, we announced that our board of directors approved an additional $2.0 billion share repurchase authorization through September 2015, resulting in $6.0 billion of total share repurchase authorizations since January 1, 2012. After the effects of the accelerated share repurchase (“ASR”) programs and open market repurchases shown below, $1.86 billion of the amounts authorized by our board of directors remain available for repurchases at December 31, 2013. 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 and amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.

In February 2012 and November 2012, we entered into $850 million and $500 million ASR programs, respectively, to repurchase shares of MPC common stock under the approved share repurchase plan authorized by our board of directors. The total number of shares repurchased under these ASR programs was based generally on the volume-weighted average price of our common stock during the repurchase periods. 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.

Total share repurchases transacted through ASR programs and open market transactions were as follows for the respective periods. There were no shares repurchased in 2011.

(In millions, except per share data)	2013		2012
Number of shares repurchased(a)	37		28
Cash paid for shares repurchased	$	2,793	$	1,350
Effective average cost per delivered share	$	76.14	$	46.73

^(a) Shares repurchased in 2013 includes 1 million shares received under the November 2012 ASR program, which were paid for in 2012.

As of December 31, 2013, the total number of shares we have repurchased cumulatively through the ASR programs and open market repurchases since February 2012 was 65 million shares at an average cost per share of $63.61. The cash paid for shares repurchased during this period was $4.14 billion. In addition, at December 31, 2013, we had agreements to acquire additional common shares for $12 million, which were settled in early January 2014.

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10.    Segment Information

We have three reportable 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, buyers on the spot market, our Speedway segment and to independent entrepreneurs 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.

On February 1, 2013, we acquired the Galveston Bay Refinery and Related Assets, which are part of the Refining & Marketing and Pipeline Transportation segments. Segment information for periods prior to the acquisition does not include amounts for these operations. See Note 5.

Segment income represents income from operations attributable to the reportable 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 reportable segments. In addition, certain items that affect comparability (as determined by the chief operating decision maker) are not allocated to the reportable segments.

(In millions)	Refining & Marketing			Speedway			Pipeline Transportation			Total
Year Ended December 31, 2013
Revenues:
Customer	$	85,608		$	14,471		$	79		$	100,158
Intersegment(a)	9,294			4			458			9,756
Related parties	8			—			—			8
Segment revenues	94,910			14,475			537			109,922
Elimination of intersegment revenues	(9,294		)	(4		)	(458		)	(9,756		)
Total revenues	$	85,616		$	14,471		$	79		$	100,166
Segment income from operations(b)	$	3,206		$	375		$	210		$	3,791
Income from equity method investments	28			—			8			36
Depreciation and amortization(c)	1,011			112			74			1,197
Capital expenditures and investments(d)(e)(f)	2,094			296			234			2,624

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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)(e)	900			164		121			1,185

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

^(b)  Included in the Pipeline Transportation segment for 2013 and 2012 are $20 millionand $4 million of corporate overhead costs attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 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 convenience stores. See Note 5.

^(f)  The Refining & Marketing and Pipeline Transportation segments include $1.29 billion and $70 million, respectively, for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5.

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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)	2013			2012			2011
Segment income from operations	$	3,791		$	5,624		$	4,061
Items not allocated to segments:
Corporate and other unallocated items(a)(b)	(271		)	(336		)	(316		)
Minnesota Assets sale settlement gain(c)	—			183			—
Pension settlement expenses(d)	(95		)	(124		)	—
Net interest and other financial income (costs)(e)	(179		)	(109		)	(26		)
Income before income taxes	$	3,246		$	5,238		$	3,719

^(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 attributable to MPLX were included in the Pipeline Transportation segment subsequent to MPLX’s October 31, 2012 initial public offering.

^(c)  See Note 6.

^(d)  See Note 22.

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

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

(In millions)	2013		2012		2011
Segment capital expenditures and investments	$	2,624	$	1,256	$	1,185
Less: Investments in equity method investees	124		28		11
Plus: Items not allocated to segments:
Capital expenditures not allocated to segments	137		103		24
Capitalized interest	28		101		114
Total capital expenditures(a)(b)	$	2,665	$	1,432	$	1,312

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

^(b)  See Note 20 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)	2013			2012			2011
Total revenues (as reported above)	$	100,166		$	82,245		$	78,638
Plus: Corporate and other unallocated items	(6		)	(2		)	—
Less: Sales to related parties	8			8			55
Sales and other operating revenues (including consumer excise taxes)	$	100,152		$	82,235		$	78,583

Revenues by product line were:

(In millions)	2013		2012		2011
Refined products	$	93,520	$	76,234	$	73,334
Merchandise	3,308		3,229		3,090
Crude oil and refinery feedstocks	2,988		2,514		1,972
Transportation and other	344		266		242
Total revenues	100,160		82,243		78,638
Less: Sales to related parties	8		8		55
Sales and other operating revenues (including consumer excise taxes)	$	100,152	$	82,235	$	78,583

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Revenue from BP p.l.c. included in the Refining & Marketing segment represented 10 percent of our total annual revenues for the year ended December 31, 2013. No single customer accounted for more than 10 percent of annual revenues for the years ended December 31, 2012 and 2011.

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)	2013		2012
Refining & Marketing	$	19,573	$	17,052
Speedway	2,064		1,947
Pipeline Transportation	1,947		1,950
Corporate and Other	4,801		6,274
Total consolidated assets	$	28,385	$	27,223

11. Other Items

Net interest and other financial income (costs) was:

(In millions)	2013			2012			2011
Interest:
Interest income	$	9		$	5		$	3
Interest expense(a)	(195		)	(191		)	(164		)
Interest capitalized(a)	28			101			104
Total net interest	(158		)	(85		)	(57		)
Other:
Net foreign currency gains	—			—			12
Bank service and other fees	(21		)	(25		)	(16		)
Total other	(21		)	(25		)	(4		)
Net interest and other financial income (costs)	$	(179	)	$	(110	)	$	(61	)

^(a)  See Note 7 for information on related party interest expense and capitalized interest.

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12. Income Taxes

Income tax provisions (benefits) were:

	2013							2012							2011
(In millions)	Current		Deferred			Total		Current			Deferred		Total		Current		Deferred			Total
Federal	$	954	$	20		$	974	$	1,185		$	432	$	1,617	$	1,040	$	139		$	1,179
State and local	131		8			139		169			57		226		152		(16		)	136
Foreign	5		(5		)	—		(1		)	3		2		15		—			15
Total	$	1,090	$	23		$	1,113	$	1,353		$	492	$	1,845	$	1,207	$	123		$	1,330

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:

	2013		2012		2011
Statutory rate applied to income before income taxes	35	%	35	%	35	%
State and local income taxes, net of federal income tax effects	3		2		2
Domestic manufacturing deduction	(2	)	(1	)	(1	)
Other	(2	)	(1	)	—
Provision for income taxes	34	%	35	%	36	%

Deferred tax assets and liabilities resulted from the following:

	December 31,
(In millions)	2013		2012
Deferred tax assets:
Employee benefits	$	483	$	585
Environmental	37		35
Other	49		55
Total deferred tax assets	569		675
Deferred tax liabilities:
Property, plant and equipment	2,290		2,225
Inventories	614		610
Investments in subsidiaries and affiliates	267		307
Other	70		29
Total deferred tax liabilities	3,241		3,171
Net deferred tax liabilities	$	2,672	$	2,496

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

	December 31,
(In millions)	2013		2012
Assets:
Other noncurrent assets	$	2	$	—
Liabilities:
Accrued taxes	370		446
Deferred income taxes	2,304		2,050
Net deferred tax liabilities	$	2,672	$	2,496

The ability to realize the benefit of foreign tax credits is based on certain estimates concerning future financial conditions, income generated from foreign sources and our tax profile in the years that such credits may be claimed. A federal valuation allowance was established in 2013 for $2 million due to changes in the expected realizability of foreign tax credits.

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. 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, 2013, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:

United States Federal	2010	-	2012
States	2004	-	2012

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. During 2013, we settled with Marathon Oil our U.S. federal and related state return liabilities for the 2008-2009 tax years, resulting in a reduction in unrecognized tax benefits of $21 million, which are also reflected in the table below as settlements.

During 2013, we settled with Marathon Oil for the 2011 period prior to the spinoff based on filed tax returns and in accordance with the tax sharing agreement, resulting in a $39 million increase to additional paid-in capital.

The following table summarizes the activity in unrecognized tax benefits:

(In millions)	2013			2012			2011
January 1 balance	$	40		$	20		$	14
Additions for tax positions of prior years	30			32			50
Reductions for tax positions of prior years	(25		)	(6		)	—
Settlements	(30		)	(6		)	(44		)
Statute of limitations	(2		)	—			—
December 31 balance	$	13		$	40		$	20

If the unrecognized tax benefits as of December 31, 2013 were recognized, $6 million would affect our effective income tax rate. There were $5 million of uncertain tax positions as of December 31, 2013 for which it is reasonably possible that the amount of unrecognized tax benefits would significantly increase or decrease during the next twelve months.

Interest and penalties related to income taxes are recorded as part of the provision for income taxes. Such interest and penalties were net receipts (expenses) of ($11 million), $1 million and ($5 million) in 2013, 2012 and 2011. As of December 31, 2013 and 2012, $15 million and $9 million of interest and penalties were accrued related to income taxes.

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13. Inventories

	December 31,
(In millions)	2013		2012
Crude oil and refinery feedstocks	$	1,797	$	1,383
Refined products	2,367		1,761
Materials and supplies	425		231
Merchandise	100		74
Total (at cost)	$	4,689	$	3,449

The LIFO method accounted for 90 percent and 93 percent of total inventory value at December 31, 2013 and 2012, respectively. Current acquisition costs were estimated to exceed the LIFO inventory value at December 31, 2013 and 2012 by $4,084 million and $4,511 million, respectively. There were no liquidations of LIFO inventories in 2013 and 2012. Cost of revenues decreased and income from operations increased by $4 million in 2011 as a result of liquidations of LIFO inventories, excluding inventories liquidated in dispositions.

14. Equity Method Investments

	Ownership as of December 31, 2013	December 31,
(In millions)		2013		2012
Centennial	50%	$	29	$	27
LOCAP LLC	59%	24		26
LOOP	51%	214		198
North Dakota Pipeline(a)	38%	24		—
TAAE	43%	29		—
TACE	60%	70		29
TAEI	34%	23		—
TAME(b)	50%	35		27
Other		15		14
Total		$	463	$	321

^(a)  We own a 38 percent interest in the Class B units of this entity. Our Class B units will be converted to an approximate 27 percent ownership interest in the Class A units of this entity upon completion of the Sandpiper pipeline construction project in 2016.

^(b)  Excludes TAEI's investment in TAME.

Summarized financial information for equity method investees is as follows:

(In millions)	2013		2012		2011
Income statement data:
Revenues and other income	$	1,067	$	1,025	$	1,043
Income from operations	87		73		128
Net income	63		47		101
Balance sheet data - December 31:
Current assets	$	339	$	217
Noncurrent assets	1,238		1,163
Current liabilities	145		161
Noncurrent liabilities	618		636

As of December 31, 2013, the carrying value of our equity method investments was $41 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 $55 million of excess related to goodwill.

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Centennial experienced a significant reduction in shipment volumes in the second half of 2011 that has continued through 2013. At December 31, 2013, 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 potential uses of Centennial’s assets. If current business conditions remain unchanged and the owners of Centennial are unable to find an alternative use for the assets, there could be a future impairment of our Centennial interest. As of December 31, 2013, our equity investment in Centennial was $29 million and we had a $42 million guarantee associated with 50 percent of Centennial's outstanding debt. See Note 25 for additional information on the debt guarantee.

Dividends and partnership distributions received from equity method investees (excluding distributions that represented a return of capital previously contributed) were $18 million, $37 million and $48 million in 2013, 2012 and 2011.

15. Property, Plant and Equipment

(In millions)	Estimated Useful Lives	December 31,
		2013		2012
Refining & Marketing	4 - 25 years	$	16,982	$	15,089
Speedway	4 - 15 years	2,344		2,100
Pipeline Transportation	16 - 42 years	1,921		1,747
Corporate and Other	4 - 40 years	546		473
Total		21,793		19,409
Less accumulated depreciation		7,872		6,766
Property, plant and equipment, net		$	13,921	$	12,643

Property, plant and equipment includes gross assets acquired under capital leases of $510 million and $417 million at December 31, 2013 and 2012, with related amounts in accumulated depreciation of $111 million and $79 million at December 31, 2013 and 2012. Property, plant and equipment includes construction in progress of $747 million and $520 million at December 31, 2013 and 2012, which primarily relates to refinery projects.

16. 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 2013 and 2012, and no impairment was required.

The changes in the carrying amount of goodwill for 2013 and 2012 were as follows:

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
2012
Beginning balance	$	551	$	129	$	162	$	842
Acquisitions(a)	—		88		—		88
Ending balance	$	551	$	217	$	162	$	930
2013
Beginning balance	$	551	$	217	$	162	$	930
Acquisitions(a)	—		8		—		8
Ending balance	$	551	$	225	$	162	$	938

^(a)  See Note 5 for information on the acquisitions.

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17. Fair Value Measurements

Fair Values – Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2013 and 2012 by fair value hierarchy level. We have elected to offset the fair value amounts recognized for multiple derivative contracts executed with the same counterparty, including any related cash collateral as shown below; however, fair value amounts by hierarchy level are presented on a gross basis in the following tables.

	December 31, 2013
	Fair Value Hierarchy
(In millions)	Level 1		Level 2		Level 3		Netting and Collateral(a)			Net Carrying Value on Balance Sheet(b)		Collateral Pledged Not Offset
Commodity derivative instruments, assets	$	21	$	—	$	—	$	(21	)	$	—	$	61
Other assets	2		—		—		N/A			2		—
Total assets at fair value	$	23	$	—	$	—	$	(21	)	$	2	$	61
Commodity derivative instruments, liabilities	$	53	$	—	$	—	$	(53	)	$	—	$	—
Contingent consideration, liability(c)	—		—		625		N/A			625		—
Total liabilities at fair value	$	53	$	—	$	625	$	(53	)	$	625	$	—

	December 31, 2012
	Fair Value Hierarchy
(In millions)	Level 1		Level 2		Level 3		Netting and Collateral(a)			Net Carrying Value on Balance Sheet(b)		Collateral Pledged Not Offset
Commodity derivative instruments, assets	$	49	$	—	$	—	$	(49	)	$	—	$	45
Other assets	2		—		—		N/A			2		—
Total assets at fair value	$	51	$	—	$	—	$	(49	)	$	2	$	45
Commodity derivative instruments, liabilities	$	88	$	—	$	—	$	(88	)	$	—	$	—

^(a) Represents the impact of netting assets, liabilities and cash collateral when a legal right of offset exists. As of December 31, 2013 and 2012, cash collateral of $32 million and $39 million, respectively, was netted with mark-to-market derivative liabilities.

^(b) We have no derivative contracts that are subject to master netting arrangements that are reflected gross on the balance sheet.

^(c) Includes $159 million classified as current.

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. Commodity derivatives are covered under master netting agreements with an unconditional right to offset. 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.

The contingent consideration represents the fair value as of December 31, 2013 of the amount we expect to pay to BP related to the earnout provision for the Galveston Bay Refinery and Related Assets acquisition. See Note 5. The fair value of the contingent consideration was estimated using an income approach and is therefore a Level 3 liability. The amount of cash to be paid under the arrangement is based on both a market-based crack spread and refinery throughput volumes for the months during which the contract applies, as well as established thresholds that cap the annual and total payment. The earnout payment cannot exceed $200 million per year for the first three years of the arrangement or $250 million per year for the last three years of the arrangement, with the total cumulative payment capped at $700 million over the six-year period. Any excess or shortfall from the annual cap for a current year’s earnout calculation will not affect subsequent years’ calculations. The fair value calculation used significant unobservable inputs including: (1) an estimate of refinery throughput volumes; (2) a range of internal and external crack spread forecasts from $13 to $18 per barrel; and (3) a range of risk-adjusted discount rates from 5 percent to 10 percent. An increase or decrease in crack spread forecasts or refinery throughput volume expectations will result in a corresponding increase or decrease in the fair value. Increases to the fair value as a result of increasing forecasts for both of these unobservable inputs, however, are limited as the earnout payment is subject to annual thresholds. An increase or decrease in the discount rate will result in a decrease or increase to the fair value, respectively. The fair value of the contingent consideration is reassessed each quarter, with changes in fair value recorded in cost of revenues.

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

(In millions)	2013			2012			2011
Beginning balance	$	—		$	—		$	2,402
Contingent consideration agreement	(600		)	—			—
Total realized and unrealized losses included in net income	(25		)	(2		)	—
Purchases of PFD Preferred Stock(a)	—			—			10,326
Redemptions of PFD Preferred Stock(a)	—			—			(12,730		)
Settlements of derivative instruments	—			2			2
Ending balance	$	(625	)	$	—		$	—

^(a)  For information on PFD Preferred Stock, see Note 7. 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.

We did not hold any Level 3 derivative instruments during 2013 and 2012. Net income for 2011 included unrealized losses of less than $1 million related to Level 3 derivative instruments held during 2011. See Note 18 for the income statement impacts of our derivative instruments. There was an unrealized loss of $25 million in 2013 related to the contingent consideration agreement.

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,
	2013				2012				2011
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Property, plant and equipment, net	$	1	$	8	$	—	$	—	$	—	$	—
Other noncurrent assets	—		—		—		14		—		—

Due to changing market conditions, we assessed one of our light products terminals for impairment. The terminal is operated by our Refining & Marketing segment. We recorded an impairment charge of $8 million for this terminal in 2013. The impairment is included in depreciation and amortization on the consolidated statements of income. The fair value of the terminal was measured using a market approach based on comparable area property values which are Level 3 inputs.

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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Fair Values – Reported

The following table summarizes financial instruments on the basis of their nature, characteristics and risk at December 31, 2013 and 2012, excluding the derivative financial instruments and contingent consideration reported above.

	December 31,
	2013				2012
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial assets:
Investments	$	336	$	14	$	263	$	59
Other	31		30		33		31
Total financial assets	$	367	$	44	$	296	$	90
Financial liabilities:
Long-term debt(a)	$	3,306	$	3,001	$	3,559	$	3,006
Deferred credits and other liabilities	21		21		23		23
Total financial liabilities	$	3,327	$	3,022	$	3,582	$	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, (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.

18. Derivatives

For further information regarding the fair value measurement of derivative instruments, including any effect of master netting agreements or collateral, see Note 17. 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, 2013 and 2012:

	December 31, 2013
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	21	$	53	Other current assets

	December 31, 2012
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	49	$	88	Other current assets

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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	2013		2012			2011
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 for crude oil and refined products as of December 31, 2013.

	Position	Total Barrels (In thousands)
Crude oil(a)
Exchange-traded	Long	10,580
Exchange-traded	Short	(23,900)
Refined Products(a)
Exchange-traded	Long	3,646
Exchange-traded	Short	(4,175)

^(a)100 percent of these contracts expire in the first quarter of 2014.

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

(In millions)	Gain (Loss)
Income Statement Location	2013			2012		2011
Sales and other operating revenues	$	12		$	8	$	(34	)
Other income	—			—		1
Cost of revenues	(180		)	65		182
Total	$	(168	)	$	73	$	149

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19. Debt

Our outstanding borrowings at December 31, 2013 and 2012 consisted of the following:

	December 31,
(In millions)	2013			2012
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 2014-2028	395			355
MPLX Operations LLC revolving credit agreement due 2017	—			—
Trade receivables securitization facility due 2016	—			—
Total	3,395			3,355
Unamortized discount	(10		)	(10		)
Fair value adjustments(a)	11			16
Amounts due within one year	(23		)	(19		)
Total long-term debt due after one year	$	3,373		$	3,342

^(a)  See Notes 17 and 18 for information on interest rate swaps.

The following table shows five years of scheduled debt payments.

(In millions)
2014	$	23
2015	27
2016	777
2017	28
2018	30

There were no borrowings or letters of credit outstanding under the revolving credit agreements or the trade receivable securitization facility at December 31, 2013.

MPC Revolving Credit Agreement- We have a $2.5 billion unsecured revolving credit agreement ("Credit Agreement") in place with a maturity date of September 14, 2017. 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 our 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, the maturity date may be extended for up to two additional one-year periods subject to the approval of lenders holding greater than 50 percent of the commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the then-effective maturity date.

Borrowings under the Credit Agreement bear interest at either the Adjusted LIBO Rate (as defined in the Credit Agreement) plus a margin or the Alternate Base Rate (as defined in the Credit Agreement) plus a margin. We are charged various fees and expenses in connection with the Credit Agreement, including administrative agent fees, commitment fees on the unused portion of our borrowing capacity and fees related to issued and outstanding letters of credit. The applicable interest rates and certain of the fees fluctuate based on the credit ratings in effect from time to time on our long-term debt.

The Credit Agreement contains certain representations and warranties, affirmative and restrictive covenants and events of default that we consider to be usual and customary for arrangements of this type, including a financial covenant that requires us to maintain 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 the last day of each fiscal quarter. Other covenants, among other things, restrict our ability to incur debt, create liens on our assets or enter into transactions with affiliates. As of December 31, 2013, we were in compliance with the covenants contained in the Credit Agreement.

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MPLX Operations LLC Revolving Credit Agreement- MPLX Operations LLC, an affiliate of MPC and wholly-owned subsidiary of MPLX LP, has a $500 million unsecured revolving credit agreement ("MPLX Credit Agreement") in place with a maturity date of October 31, 2017. The MPLX Credit Agreement includes letter of credit issuing capacity of up to $250 million and swingline loan capacity of up to $50 million. The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional $300 million, subject to certain conditions, including the consent of the lenders whose commitments would increase. In addition, the maturity date may be extended up to two additional one-year periods subject to the approval of lenders holding greater than 50 percent of the commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the then-effective maturity date.

Borrowings under the MPLX Credit Agreement bear interest at either the Adjusted LIBO Rate (as defined in the MPLX Credit Agreement) plus a margin, or the Alternate Base Rate (as defined in the MPLX Credit Agreement) plus a margin. MPLX is charged various fees and expenses in connection with the agreement, including administrative agent fees, commitment fees on the unused portion of the borrowing capacity and fees with respect to issued and outstanding letters of credit. The applicable interest rates and certain of the fees fluctuate based on MPLX's 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, or the credit ratings in effect from time to time on MPLX's long-term debt subsequent to the Rating Date (as defined in the MPLX Credit Agreement).

The MPLX Credit Agreement includes certain representations and warranties, affirmative and restrictive covenants and events of default that we consider to be usual and customary for an agreement of this type, including a financial covenant that requires MPLX to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 during the six-month period following certain acquisitions). Other covenants restrict MPLX from incurring debt, creating liens on its assets and entering into transactions with affiliates. As of December 31, 2013, MPLX was in compliance with the covenants contained in the MPLX Credit Agreement.

Trade receivables securitization facility - On December 18, 2013, we entered into a three-year, $1.3 billion trade receivables securitization facility with a group of financial institutions that act as committed purchasers, conduit purchasers, letter of credit issuers and managing agents under the facility. The facility is evidenced by a Receivables Purchase Agreement and a Second Amended and Restated Receivables Sale Agreement and replaces the previously existing accounts receivable facility that was set to expire on June 30, 2014.

The facility consists of one of our wholly-owned subsidiaries, Marathon Petroleum Company LP (“MPC LP”), selling or contributing on an on-going basis all of its trade receivables (including trade receivables acquired from Marathon Petroleum Trading Canada LLC, a wholly-owned subsidiary of MPC LP), together with all related security and interests in the proceeds thereof, without recourse, to another wholly-owned, bankruptcy-remote special purpose subsidiary, MPC Trade Receivables Company LLC (“TRC”), in exchange for a combination of cash, equity or a subordinated note issued by TRC to MPC LP. TRC, in turn, has the ability to finance its purchase of the receivables from MPC LP by selling undivided ownership interests in qualifying trade receivables, together with all related security and interests in the proceeds thereof, without recourse, to the purchasing group in exchange for cash proceeds. The facility also provides for the issuance of letters of credit of up to an initial amount of $1.25 billion, provided that the aggregate credit exposure of the purchasing group is limited to no more than $1.3 billion at any one time.

To the extent that TRC retains an ownership interest in the receivables it has purchased or received from MPC LP, such interest will be included in our consolidated financial statements solely as a result of the consolidation of the financial statements of TRC with those of MPC. The receivables sold or contributed to TRC are available first and foremost to satisfy claims of the creditors of TRC and are not available to satisfy the claims of creditors of MPC. TRC has granted a security interest in all of its assets to the purchasing group to secure its obligations under the Receivables Purchase Agreement.

Proceeds from the sale of undivided percentage ownership interests in qualifying receivables under the facility will be reflected as debt on our consolidated balance sheet, none of which was outstanding as of December 31, 2013. We will remain responsible for servicing the receivables sold to the purchasing group. TRC pays floating-rate interest charges and usage fees on amounts outstanding under the facility, if any, and certain other fees related to the administration of the facility and letters of credit that are issued and outstanding under the facility.

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The Receivables Purchase Agreement and Second Amended and Restated Receivables Sale Agreement include representations and covenants that we consider usual and customary for arrangements of this type. Trade receivables are subject to customary criteria, limits and reserves before being deemed to qualify for sale by TRC pursuant to the facility. In addition, further purchases of qualified trade receivables under the facility are subject to termination, and TRC may be subject to default fees, upon the occurrence of certain amortization events that are included in the Receivables Purchase Agreement, which we consider to be usual and customary for arrangements of this type.

20. Supplemental Cash Flow Information

(In millions)	2013		2012		2011
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	161	$	67	$	5
Net income taxes paid to taxing authorities(a)	1,099		1,211		617
Non-cash investing and financing activities:
Capital lease obligations increase	$	61	$	62	$	26
Property, plant and equipment contributed by Marathon Oil	—		—		81
Property, plant and equipment sold	43		—		—
Preferred equity interest received in contract settlement(b)	—		45		—
Preferred equity interest dividend received in-kind	—		1		—
Acquisitions:
Contingent consideration(c)	600		—		—
Payable to seller(c)	6		—		—
Intangible asset acquired	—		3		—
Liability assumed	—		2		—

^(a)  U.S. 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 tax credits. See Note 25.

^(b)  See Note 6.

^(c)  See Note 5.

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)	2013		2012			2011
Additions to property, plant and equipment	$	1,206	$	1,369		$	1,185
Acquisitions(a)	1,386		180			74
Increase (decrease) in capital accruals	73		(117		)	53
Total capital expenditures	$	2,665	$	1,432		$	1,312

^(a)  Includes $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, of $1.15 billion plus assumed liabilities of $210 million. The 2012 acquisitions exclude the inventory acquired and liability assumed. See Note 5.

The following is a reconciliation of distributions to Marathon Oil:

(In millions)	2011
Distributions to Marathon Oil per consolidated statements of cash flows	$	(783	)
Non-cash contributions from Marathon Oil(a)	57
Distributions to Marathon Oil per consolidated statements of equity / net investment	$	(726	)

^(a)  See Note 7.

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21. Accumulated Other Comprehensive Loss

The following table shows the changes in accumulated other comprehensive loss by component. Amounts in parentheses indicate debits.

(In millions)	Pension Benefits			Other Benefits			Gain on Cash Flow Hedge		Workers Compensation			Total
Balance as of December 31, 2012	$	(432	)	$	(36	)	$	4	$	—		$	(464	)
Other comprehensive income (loss) before reclassifications	198			(13		)	—		4			189
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit(a)	(45		)	(4		)	—		—			(49		)
– actuarial loss(a)	66			3			—		—			69
– settlement loss(a)	95			—			—		—			95
Other(b)	—			—			—		(1		)	(1		)
Tax expense	(43		)	—			—		—			(43		)
Other comprehensive income (loss)	271			(14		)	—		3			260
Balance as of December 31, 2013	$	(161	)	$	(50	)	$	4	$	3		$	(204	)

^(a) These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 22.

^(b)  This amount was reclassified out of accumulated other comprehensive loss and is included in selling, general and administrative expenses on the consolidated statements of income.

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.

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.

Due to the Galveston Bay Refinery and Related Assets acquisition during 2013, we remeasured certain pension and retiree medical plans resulting in a $122 million decrease in liabilities. The decrease in liabilities was due to a 0.2 percent increase in discount rates and an increase in pension plan asset value from December 31, 2012 to the remeasurement date. The net periodic benefit costs for 2013 reflect these remeasurements. The purchase accounting for the Galveston Bay Refinery and Related Assets acquisition includes a $43 million liability related to retiree medical assumed at the acquisition date. See Note 5.

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 were 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.

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 now 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 $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.

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Obligations and funded status – The accumulated benefit obligation for all defined benefit pension plans was $1,912 million and $2,035 million as of December 31, 2013 and 2012.

The following summarizes our defined benefit pension plans that have accumulated benefit obligations in excess of plan assets.

	December 31,
(In millions)	2013		2012
Projected benefit obligations	$	1,927	$	2,192
Accumulated benefit obligations	1,912		2,035
Fair value of plan assets	1,800		1,478

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)	2013			2012			2013			2012
Change in benefit obligations:
Benefit obligations at January 1	$	2,192		$	2,685		$	591		$	551
Service cost	93			66			25			20
Interest cost	73			94			26			24
Actuarial (gain) loss	(183		)	117			17			53
Benefits paid	(248		)	(233		)	(20		)	(17		)
Liability gain due to curtailment	—			(17		)	—			—
Other(a)	—			(520		)	48			(40		)
Benefit obligations at December 31	1,927			2,192			687			591
Change in plan assets:
Fair value of plan assets at January 1	1,478			1,423			—			—
Actual return on plan assets	241			157			—			—
Employer contributions	329			131			—			—
Benefits paid from plan assets	(248		)	(233		)	—			—
Fair value of plan assets at December 31	1,800			1,478			—			—
Funded status of plans at December 31	$	(127	)	$	(714	)	$	(687	)	$	(591	)
Amounts recognized in the consolidated balance sheets:
Current liabilities	$	(18	)	$	(18	)	$	(25	)	$	(21	)
Noncurrent liabilities	(109		)	(696		)	(662		)	(570		)
Accrued benefit cost	$	(127	)	$	(714	)	$	(687	)	$	(591	)
Pretax amounts recognized in accumulated other comprehensive loss:(b)
Net loss	$	668		$	1,147		$	107		$	93
Prior service credit	(415		)	(460		)	(30		)	(38		)

^(a)  Includes adjustments related to plan amendments in 2013 and 2012. Also, includes adjustments related to the Galveston Bay Refinery and Related Assets acquisition in 2013.

^(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 2013, 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)	2013			2012			2011			2013			2012			2011
Components of net periodic benefit cost:
Service cost	$	93		$	66		$	65		$	25		$	20		$	19
Interest cost	73			94			110			26			24			27
Expected return on plan assets	(107		)	(104		)	(97		)	—			—			—
Amortization – prior service cost (credit)	(45		)	(18		)	6			(4		)	(2		)	—
– actuarial loss	66			93			71			3			2			—
– net settlement/curtailment loss(a)	95			125			8			—			—			—
Net periodic benefit cost(b)	$	175		$	256		$	163		$	50		$	44		$	46
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial (gain) loss	$	(317	)	$	46		$	427		$	17		$	53		$	39
Prior service cost (credit)(c)	—			(520		)	—			4			(40		)	—
Amortization of actuarial loss	(161		)	(218		)	(79		)	(3		)	(2		)	—
Amortization of prior service cost (credit)	45			18			(6		)	4			2			—
Other(d)	—			—			6			—			—			—
Total recognized in other comprehensive loss	$	(433	)	$	(674	)	$	348		$	22		$	13		$	39
Total recognized in net periodic benefit cost and other comprehensive loss	$	(258	)	$	(418	)	$	511		$	72		$	57		$	85

^(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 6.

^(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 plan amendments approved in 2013 and 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 in 2011.

Lump sum payments to employees retiring in 2013, 2012 and 2011 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 2013, 2012 and 2011 related to our cumulative lump sum payments made during those years.

The estimated net gain/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 2014 are $52 million and $46 million. The 2014 net loss amortization is expected to be lower than the 2013 actual amortization primarily as a result of adjustments made to the net loss balance due to settlement accounting in 2013. 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 2014 is $3 million and $4 million, respectively.

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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 2013, 2012 and 2011.

	Pension Benefits						Other Benefits
	2013		2012		2011		2013		2012		2011
Weighted-average assumptions used to determine benefit obligation:
Discount rate	4.30	%	3.45	%	4.30	%	4.95	%	4.05	%	4.65	%
Rate of compensation increase	3.70	%	5.00	%	5.00	%	3.70	%	5.00	%	5.00	%
Weighted-average assumptions used to determine net periodic benefit cost:
Discount rate	3.88	%	4.06	%	4.98	%	4.11	%	4.54	%	5.55	%
Expected long-term return on plan assets(a)	7.50	%	7.50	%	8.50	%	—	%	—	%	—	%
Rate of compensation increase	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%

^(a) Effective January 1, 2014, the expected long-term rate of return on plan assets changed from 7.50 percent to 7.00 percent due to a change in our plan investment strategy.

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,
	2013		2012		2011
Health care cost trend rate assumed for the following year:
Medical:
Pre-65	8.00	%	8.00	%	7.50	%
Post-65(a)	N/A		N/A		7.00	%
Prescription drugs	7.00	%	7.00	%	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		N/A		5.00	%
Prescription drugs	5.00	%	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate:
Medical:
Pre-65	2020		2020		2018
Post-65(a)	N/A		N/A		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	$	5	$	(4	)
Effect on other postretirement benefit obligations	39		(34		)

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) diversify plan investments across asset classes to achieve an optimal balance between risk and return and between income and growth of assets through capital appreciation; and (3) source benefit payments primarily through existing plan assets and anticipated future returns.

The investment goals are implemented to manage the plans' funded status volatility and minimize future cash contributions. The asset allocation strategy will change over time in response to changes primarily in funded status, which is dictated by current and anticipated market conditions, the independent actions of our investment committee, required cash flows to and from the plans and other factors deemed appropriate. Such changes in asset allocation are intended to allocate additional assets to the fixed income asset class should the funded status improve. The fixed income asset class shall be invested in such a manner that its interest rate sensitivity correlates highly with that of the plans' liabilities. Other asset classes are intended to provide additional return with associated higher levels of risk. Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies. At December 31, 2013, the plans’ targeted asset allocation was 62 percent equity, private equity, real estate, and timber securities and 38 percent fixed income securities.

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, 2013 and 2012.

Cash and cash equivalents - For 2013, cash and cash equivalents included a collective fund serving as the investment vehicle for the cash reserves and cash held by third-party investment managers. The collective fund was valued at net asset value ("NAV") on a scheduled basis using a cost approach, and was considered a Level 2 asset. Cash and cash equivalents held by third-party investment managers were valued using a cost approach and were considered Level 2. For 2012, cash and cash equivalents included cash on deposit and an investment in a money market mutual fund that invested mainly in short-term instruments and cash, both of which were valued using a market approach and were considered Level 1. The money market mutual fund was valued at the NAV of shares held.

Equity - Equity investments includes common stock, mutual and pooled funds, public and non-public investment trusts and S&P 500 exchange-traded funds. Common stock investments are valued using a market approach, which are priced daily in active markets and are considered Level 1. Mutual and pooled equity funds are well diversified portfolios, representing a mix of strategies in domestic, international and emerging market strategies. Mutual funds are publicly registered, valued at NAV on a daily basis using a market approach and are considered Level 1 assets. Pooled funds are valued at NAV using a market approach and are considered Level 2 assets. Investments in public trusts and S&P 500 exchange-traded funds are valued using a market approach at the closing price reported in an active market and therefore are 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.

Fixed Income - Fixed income investments include corporate bonds, U.S. dollar treasury bonds and municipal bonds. These securities are priced on observable inputs using a combination of market, income and cost approaches. These securities are considered Level 2 assets. Fixed income also includes a well diversified bond portfolio structured as a pooled fund. This fund is valued at NAV on a daily basis using a combination of market, income and cost approaches. It is considered a Level 2 asset.

Private Equity - Private equity investments include interests in limited partnerships which are valued using information provided by external managers for each individual investment held in the fund. These holdings are considered Level 3.

Real Estate - Real estate investments consist of interests in limited partnerships. These holdings are either appraised or valued using investment manager’s assessment of assets held. These holdings are considered Level 3.

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Other - Other investments include two limited liability companies (“LLCs”) with no public market. The LLCs were formed to acquire timberland in the northwest United States. These holdings are either appraised or valued using investment manager’s assessment of assets held. These holdings are considered Level 3.

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

	December 31, 2013
(In millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	—	$	189	$	—	$	189
Equity:
Common stocks	69		—		—		69
Mutual funds	217		—		—		217
Pooled funds	—		590		—		590
Fixed income:
Corporate	—		356		—		356
Government	—		22		—		22
Pooled funds	—		218		—		218
Private equity	—		—		57		57
Real estate	—		—		60		60
Other	2		—		20		22
Total investments, at fair value	$	288	$	1,375	$	137	$	1,800

	December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	107	$	—	$	—	$	107
Equity:
Exchange-traded funds	166		—		—		166
Investment trusts	17		94		—		111
Pooled funds	—		709		—		709
Fixed income:
Pooled funds	—		258		—		258
Private equity	—		—		56		56
Real estate	—		—		54		54
Other	—		—		17		17
Total investments, at fair value	$	290	$	1,061	$	127	$	1,478

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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:

	2013
(In millions)	Private Equity			Real Estate			Other		Total
Beginning balance	$	56		$	54		$	17	$	127
Actual return on plan assets:
Realized	13			3			—		16
Unrealized	3			10			3		16
Purchases	7			5			—		12
Sales	(22		)	(12		)	—		(34		)
Ending balance	$	57		$	60		$	20	$	137

	2012
(In millions)	Private Equity			Real Estate			Other		Total
Beginning balance	$	55		$	49		$	17	$	121
Actual return on plan assets:
Realized	5			(2		)	—		3
Unrealized	(3		)	2			—		(1		)
Purchases	12			10			—		22
Sales	(13		)	(5		)	—		(18		)
Ending balance	$	56		$	54		$	17	$	127

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. In late 2013, we made pension contributions totaling $161 million. Therefore, we do not anticipate additional contributions will be made in 2014. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are estimated to be approximately $18 million and $26 million in 2014.

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)
2014	$	186	$	26
2015	181		29
2016	177		32
2017	178		34
2018	175		38
2019 through 2023	814		231

^(a)  Effective 2013, as a result of the Patient Protection and Affordable Care Act, 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 $76 million, $60 million and $60 million in 2013, 2012 and 2011.

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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 2013, 2012 and 2011 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 2013 and 2012 is for the plan’s year ended December 31, 2012 and December 31, 2011, 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 2013, 2012 and 2011 contributions. Our portion of the contributions does not make up more than 5 percent of total contributions to the plan.

		Pension Protection Act Zone Status		FIP/RP Status Pending/Implemented	MPC Contributions (In millions)						Surcharge Imposed	Expiration Date of Collective - Bargaining Agreement
Pension Fund	EIN	2013	2012		2013		2012		2011
Central States, Southeast and Southwest Areas Pension Plan(a)	36-6044243	Red	Red	Implemented	$	3	$	4	$	3	No	January 31, 2019

^(a)  This agreement has a minimum contribution requirement of $269 per week per employee for 2014. A total of 257 employees participated in the plan as of December 31, 2013.

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, $5 million and $4 million for 2013, 2012 and 2011.

23. Stock-Based Compensation Plans

Description of the Plans

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 (“MPC 2012 Plan”). The MPC 2012 Plan authorizes the Compensation Committee of our board of directors (“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. 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.

Prior to the 2011 Spinoff, our employees participated in the Marathon Oil Corporation 2007 Incentive Compensation Plan (“2007 Plan”) and the Marathon Oil Corporation 2003 Incentive Compensation Plan (“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 (“MPC 2011 Plan”).

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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.

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 2013 fell under the MPC 2012 Plan. Stock options awarded under the MPC 2011 Plan and the MPC 2012 Plan represent the right to purchase shares of our common stock at its fair market value, which is the closing price of MPC's common stock 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 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 after 2011 to officers are subject to an additional one year holding period after the completion of the three-year requisite service period. Prior to vesting, restricted stock recipients who received grants prior to 2012 have the right to vote such stock and receive dividends at the same time regular shareholders are paid. Restricted stock recipients who received grants in 2012 and after have the right to vote such stock; however, dividends are accrued and will be paid upon vesting. Restricted stock units granted to non-employee directors are considered to vest immediately at the time of the grant for accounting purposes, as they are non-forfeitable, but are not issued until the director’s departure from the board of directors. Restricted stock unit recipients do not have the right to vote such shares 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.

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Performance Units – We grant performance unit awards to certain officer employees. The target value of all performance units is $1.00, with actual payout up to $2.00 per unit (up to 200% of target). Performance units issued prior to 2012 are paid in cash at the end of the 30-month vesting period at an amount per unit determined based on the total shareholder return ("TSR") of MPC common stock compared to the TSR of selected peer companies’ stock. Performance units issued in 2012 and 2013 under the MPC 2011 and MPC 2012 Plans have a 36-month requisite service period. The payout value of these awards will be determined by the relative ranking of the TSR of MPC common stock compared to the TSR of a select group of peer companies, as well as the Standard & Poor's 500 Energy Index fund over four measurement periods. These awards will be settled 25 percent in MPC common stock and 75 percent in cash. The number of shares actually distributed will be determined by dividing 25 percent of the final payout by the closing price of MPC common stock on the day the Committee certifies the final TSR rankings, or the next trading day if the certification is made outside of normal trading hours. The performance units paying out in cash are accounted for as liability awards and those that settle in shares are accounted for as equity awards. The performance units settling in shares had a grant date fair value of $1.12 per unit for 2013 and $1.09 per unit for 2012, as calculated using a Monte Carlo valuation model.

Total Stock-Based Compensation Expense

Total employee stock-based compensation expense was $42 million, $35 million and $28 million in 2013, 2012 and 2011, while the total related income tax benefits were $15 million, $13 million and $11 million, respectively. In 2013, 2012 and in 2011 for the period subsequent to the Spinoff, cash received by MPC upon exercise of stock option awards was $48 million, $108 million and $1 million, respectively. In 2011 for periods prior to the Spinoff, cash received by Marathon Oil upon exercise of stock option awards by MPC employees was $17 million. In 2013, 2012 and in 2011 for the period subsequent to the Spinoff, tax benefits realized by MPC for deductions for stock awards exercised were $18 million, $16 million and less than $1 million, respectively. In 2011 for periods prior to the Spinoff, tax benefits realized by Marathon Oil for deductions for stock awards exercised by MPC employees were $7 million.

Stock Option Awards

The Black Scholes option-pricing model values used to value stock option awards granted 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):

	2013			2012			2011 subsequent to Spinoff			2011 prior to Spinoff
Weighted average exercise price per share	$	84.65		$	42.02		$	36.18		$	51.93
Expected annual dividends per share	$	1.40		$	1.00		$	0.95		$	1.00
Expected life in years	6.0			5.8			5.8			5.3
Expected volatility	40		%	47		%	48		%	40		%
Risk-free interest rate	1.0		%	1.1		%	1.4		%	2.0		%
Weighted average grant date fair value of stock option awards granted	$	27.13		$	14.45		$	13.08		$	16.73

Expected annual dividends per share is estimated using the most recent dividend payment per share as of the grant date. 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 33 percent of our common stock implied volatility and 67 percent of the historical volatility for a selected group of peer companies. 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.

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The following is a summary of our common stock option activity in 2013:

	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, 2012	6,172,194		$	36.17
Granted	408,603		84.65
Exercised	(1,348,938	)	35.48
Forfeited, canceled or expired	(84,022	)	43.97
Outstanding at December 31, 2013	5,147,837		40.08
Vested and expected to vest at December 31, 2013	5,142,351		40.04		6.0	$	266
Exercisable at December 31, 2013	3,674,485		34.63		5.3	210

^(a)  Includes an immaterial number of stock appreciation rights.

The intrinsic value of options exercised by MPC employees during 2013, 2012 and in 2011 for periods subsequent to the Spinoff was $60 million, $37 million and $1 million, respectively. 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 was $18 million.

As of December 31, 2013, unrecognized compensation cost related to stock option awards was $7 million, which is expected to be recognized over a weighted average period of 0.7 years.

Restricted Stock Awards

The following is a summary of restricted stock award activity of our common stock in 2013:

	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, 2012	638,073		$	40.83	359,111		$	31.07
Granted	256,224		87.06		26,399		73.48
RS's Vested/RSU's Issued	(245,116	)	37.95		(431	)	39.53
Forfeited	(25,059	)	58.60		—		—
Outstanding at December 31, 2013	624,122		61.11		385,079		33.96

Of the 385,079 restricted units outstanding, 383,953 are vested and have a weighted average grant date fair value of $33.89. 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
2013	$	20	$	87.06	$	—	$	73.48
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

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As of December 31, 2013, unrecognized compensation cost related to restricted stock awards was $24 million, which is expected to be recognized over a weighted average period of 1.3 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 2013 activity for performance unit awards to be settled in shares:

	Number of Units
Outstanding at December 31, 2012	2,040,000
Granted	1,782,500
Settled	—
Canceled	—
Outstanding at December 31, 2013	3,822,500

The number of shares that would be issued upon target vesting, using the closing price of our common stock on December 31, 2013 would be 41,671 shares.

MPLX Awards

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 phantom units and performance units. Awards granted under the MPLX Plan will be settled with MPLX units. Compensation expense for these awards was not material to our consolidated financial statements for the years ended December 31, 2013 and 2012.

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, 2013, 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
2014	$	51		$	191
2015	52			184
2016	51			152
2017	50			106
2018	49			95
Later years	345			241
Total minimum lease payments	598			$	969
Less imputed interest costs	(203		)
Present value of net minimum lease payments	$	395

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Operating lease rental expense was:

(In millions)	2013		2012		2011
Minimum rental	$	213	$	139	$	123
Contingent rental	—		—		1
Rental expense	$	213	$	139	$	124

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 both December 31, 2013 and 2012, accrued liabilities for remediation totaled $123 million. 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, were $51 million at both December 31, 2013 and December 31, 2012.

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.

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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 financings by assigning certain of their rights under throughput and deficiency agreements that they have entered into with us. 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 follow the terms of the underlying debt obligations, some of which extend through 2037. Our maximum potential undiscounted payments under these agreements for the debt principal totaled $172 million as of December 31, 2013.

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 $42 million as of December 31, 2013.

We hold an interest in a ethanol production facility through our investment in TAME and through our participation as a lender under TAME's revolving credit agreement, have agreed to reimburse the bank for 50 percent of any amounts drawn on a letter of credit that has been issued to secure TAME's 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, 2013.

Marathon Oil indemnifications – In conjunction with the Spinoff, we have entered into arrangements with Marathon Oil providing indemnities and guarantees with recorded values of $2 million as of December 31, 2013, 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 12, 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 $122 million as of December 31, 2013, 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, 2013 and 2012, our contractual commitments to acquire property, plant and equipment and advance funds to equity method investees totaled $1.7 billion and $1.4 billion, respectively. The contractual commitments at December 31, 2013 includes $700 million of contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets and $892 million for contributions to North Dakota Pipeline. The contractual commitments at December 31, 2012 included both the base purchase price and the $700 million contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5.

26. Subsequent Event

On February 3, 2014, we announced that we signed an agreement to purchase a facility in Cincinnati, Ohio from Felda Iffco Sdn Bhd, Malaysia. The plant currently produces several products including biodiesel and glycerin. The capacity of the plant is 4,100 barrels per day. The transaction is expected to close in April 2014.

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Selected Quarterly Financial Data (Unaudited)

	2013								2012
(In millions, except per share data)	1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.		1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.
Revenues	$	23,330	$	25,677	$	26,256	$	24,897	$	20,265	$	20,243	$	21,049	$	20,686
Income from operations	1,156		960		301		1,008		956		1,307		1,895		1,189
Net income	730		599		173		631		596		814		1,224		759
Net income attributable to MPC	725		593		168		626		596		814		1,224		755
Net income attributable to MPC per share:
Basic	$	2.19	$	1.84	$	0.54	$	2.09	$	1.71	$	2.39	$	3.61	$	2.26
Diluted	2.17		1.83		0.54		2.07		1.70		2.38		3.59		2.24
Dividends paid per share	0.35		0.35		0.42		0.42		0.25		0.25		0.35		0.35

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Supplementary Statistics (Unaudited)

(In millions)	2013			2012			2011
Income from Operations by segment
Refining & Marketing	$	3,206		$	5,098		$	3,591
Speedway	375			310			271
Pipeline Transportation(a)	210			216			199
Items not allocated to segments:
Corporate and other unallocated items(a)	(271		)	(336		)	(316		)
Minnesota Assets sale settlement gain	—			183			—
Pension settlement expenses	(95		)	(124		)	—
Income from operations	$	3,425		$	5,347		$	3,745
Capital Expenditures and Investments(b)(c)
Refining & Marketing	$	2,094		$	705		$	900
Speedway(d)	296			340			164
Pipeline Transportation	234			211			121
Corporate and Other(e)	165			204			138
Total	$	2,789		$	1,460		$	1,323

^(a)  Included in the Pipeline Transportation segment for 2013 and 2012 are $20 million and $4 million of corporate overhead costs attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. These expenses are not currently allocated to other segments.

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

^(c)  Includes $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, of $1.15 billion plus assumed liabilities of $210 million. The total consideration amount of $1.15 billion includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 5 to the audited consolidated financial statements.

^(d)  Includes Speedway's acquisitions of convenience stores. See Note 5 to the audited consolidated financial statements.

^(e)  Includes capitalized interest of $28 million, $101 million and $114 million for 2013, 2012 and 2011, respectively.

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Supplementary Statistics (Unaudited)

	2013		2012		2011
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)(a)(b)	2,086		1,618		1,599
Refining & Marketing Operating Statistics(b)
Refining & Marketing Refined Product Sales Volume (thousands of barrels per day)(c)	2,075		1,599		1,581
Refining & Marketing Gross Margin (dollars per barrel)(d)	$	13.24	$	17.85	$	14.26
Crude Oil Capacity Utilization percent(e)	96		100		103
Refinery Throughputs (thousands of barrels per day):(f)
Crude oil refined	1,589		1,195		1,177
Other charge and blendstocks	213		168		181
Total	1,802		1,363		1,358
Sour Crude Oil Throughput percent	53		53		52
WTI-Priced Crude Oil Throughput percent	21		28		27
Refined Product Yields (thousands of barrels per day):(f)
Gasoline	921		738		739
Distillates	572		433		433
Propane	37		26		25
Feedstocks and special products	221		109		109
Heavy fuel oil	31		18		21
Asphalt	54		62		56
Total	1,836		1,386		1,383
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.20	$	1.00	$	0.78
Depreciation and amortization	1.36		1.44		1.29
Other manufacturing(h)	4.14		3.15		3.16
Total	$	6.70	$	5.59	$	5.23
Refining & Marketing Operating Statistics By Region
Gulf Coast:(b)
Refinery Throughputs (thousands of barrels per day):(i)
Crude oil refined	964
Other charge and blendstocks	195
Total	1,159
Sour Crude Oil Throughput percent	65
WTI-Priced Crude Oil Throughput percent	7
Refined Product Yields (thousands of barrels per day):(i)
Gasoline	551
Distillates	365
Propane	23
Feedstocks and special products	215
Heavy fuel oil	19
Asphalt	13
Total	1,186
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.00
Depreciation and amortization	1.09
Other manufacturing(h)	3.98
Total	$	6.07

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Supplementary Statistics (Unaudited)
	2013			2012			2011
Refining & Marketing Operating Statistics By Region
Midwest:
Refinery Throughputs (thousands of barrels per day):(i)
Crude oil refined	625
Other charge and blendstocks	54
Total	679
Sour Crude Oil Throughput percent	35
WTI-Priced Crude Oil Throughput percent	42
Refined Product Yields (thousands of barrels per day):(i)
Gasoline	371
Distillates	207
Propane	14
Feedstocks and special products	41
Heavy fuel oil	12
Asphalt	41
Total	686
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.47
Depreciation and amortization	1.74
Other manufacturing(h)	4.21
Total	$	7.42
Speedway Operating Statistics
Convenience stores at period-end	1,478			1,464			1,371
Gasoline & distillate sales (millions of gallons)	3,146			3,027			2,938
Gasoline & distillate gross margin (dollars per gallon)(j)	$	0.1441		$	0.1318		$	0.1308
Merchandise sales (in millions)	$	3,135		$	3,058		$	2,924
Merchandise gross margin (in millions)	$	825		$	795		$	719
Same store gasoline sales volume (period over period)	0.5		%	(0.8		)%	(1.7		)%
Same store merchandise sales (period over period)(k)	4.3		%	7.0		%	6.7		%
Pipeline Transportation Operating Statistics
Pipeline throughput (thousands of barrels per day):(l)
Crude oil pipelines	1,280			1,190			1,184
Refined products pipelines	911			980			1,031
Total	2,191			2,170			2,215

^(a)  Total average daily volumes of refined product sales to wholesale, branded and retail (Speedway segment) customers.

^(b)  Includes the impact of the Galveston Bay Refinery and Related Assets beginning on the February 1, 2013 acquisition date.

^(c)  Includes intersegment sales.

^(d)  Sales revenue less cost of refinery inputs and purchased products, divided by total refinery throughputs. Starting in the fourth quarter of 2013, direct operating costs are no longer included in the Refining & Marketing gross margin and the gross margin is calculated based on total refinery throughput. All prior periods presented have been recalculated to reflect a consistent approach.

^(e)  Based on calendar day capacity, which is an annual average that includes downtime for planned maintenance and other normal operating activities.

^(f)  Excludes inter-refinery volumes of 36 thousand barrels per day ("mbpd"), 25 mbpd and 28 mbpd for 2013, 2012 and 2011, respectively.

^(g)  Per barrel of total refinery throughputs.

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

⁽ⁱ⁾  Includes inter-refinery transfer volumes.

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

^(k)  Excludes cigarettes.

^(l)  On owned common-carrier pipelines, excluding equity method investments.

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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, 2013, 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, 2013, 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.

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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 III Directors” located under the heading “Proposals of the Board” in our Proxy Statement for the 2014 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 2014 Annual Meeting of Shareholders.

We have adopted a Code of Ethics for Senior Financial Officers. It is available on our website at

http://ir.marathonpetroleum.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 2014 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” located 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 2014 Annual Meeting of Shareholders.

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

Information concerning security ownership of certain beneficial owners and management required by this item is incorporated by reference to the material appearing under the headings “Security Ownership of Certain Beneficial Owners” and “Security Ownership of Directors and Executive Officers” in our Proxy Statement for the 2014 Annual Meeting of Shareholders.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2013 with respect to shares of our common stock that may be issued under the MPC 2012 Plan and the MPC 2011 Plan:

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights(a)	Weighted-average exercise price of outstanding options, warrants and rights(b)		Number of securities remaining available for future issuance under equity compensation plans(c)
Equity compensation plans approved by stockholders	5,600,757	$	40.08	24,259,576
Equity compensation plan not approved by stockholders	—	—		—
Total	5,600,757	N/A		24,259,576

^(a)Includes the following:

1) 5,048,057 stock options granted pursuant to the MPC 2012 Plan and the MPC 2011 Plan and not forfeited, cancelled or expired as of December 31, 2013.

2) 84,279 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, 2013 based on the closing price of our common stock on December 31, 2013 of $91.73 per share. Shares available for issuance under the MPC 2012 Plan and 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 2012 Plan and the MPC 2011 Plan and not forfeited, cancelled or expired as of December 31, 2013 is 99,780.

3) 385,079 restricted stock units granted pursuant to the MPC 2012 Plan and the MPC 2011 Plan for shares unissued and not forfeited, cancelled or expired as of December 31, 2013.

4) 83,342 shares as the maximum potential number of shares that could be issued in settlement of performance units outstanding as of December 31, 2013 pursuant to the MPC 2012 Plan and the MPC 2011 Plan, based on the closing price of our common stock on December 31, 2013 of $91.73 per share. The number of shares reported for this award vehicle may overstate dilution. See Note 23 for more information on performance unit awards granted under the MPC 2012 Plan and the MPC 2011 Plan.

In addition to the awards reported above, 624,122 shares of restricted stock were issued pursuant to the MPC 2012 Plan and the MPC 2011 Plan and were outstanding as of December 31, 2013.

^(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 2012 Plan. All granting authority under the MPC 2011 Plan was revoked following the approval of the MPC 2012 Plan by shareholders on April 25, 2012. No more that 9,662,210 of the shares reported in this column may be issued for awards other than stock options or stock appreciation rights. The number of shares reported in this column assumes 38,864 as the maximum potential number of shares that could be issued pursuant to the MPC 2012 Plan in settlement of performance units outstanding as of December 31, 2013, based on the closing price of our common stock on December 31, 2013, of $91.73 per share. The number of shares assumed for this award vehicle may understate the number of shares available for issuance pursuant to the MPC 2012 Plan. See Note 23 for more information on performance unit awards granted pursuant to the MPC 2012 Plan. 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 2014 Annual Meeting of Shareholders.

Item 14. Principal Accountant 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 2014 Annual Meeting of Shareholders.

124

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 31/2% Senior Notes due 2016, 51/8% Senior Notes due 2021 and 61/2% Senior Notes due 2041 of Marathon Petroleum Corporation	10	4.2	5/26/2011	001-35054
4.3	Form of 31/2% Senior Notes due 2016, 51/8% Senior Notes due 2021 and 61/2% 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

125

Exhibit Number	Exhibit Description		Incorporated by Reference			Filed Herewith	Furnished Herewith
		Form	Exhibit	Filing Date	SEC File No.
10.4	Receivables Purchase Agreement, dated as of December 18, 2013, by and among MPC Trade Receivables Company, LLC, Marathon Petroleum Company LP, The Bank of Tokyo-Mitsubishi UFJ., Ltd., New York Branch, as administrative agent and sole lead arranger, certain committed purchasers and conduit purchasers that are parties thereto from time to time and certain other parties thereto from time to time as managing agents and letter of credit issuers.	8-K	10.1	12/23/2013	001-35054
10.5	Second Amended and Restated Receivables Sale Agreement, dated as of December 18, 2013, by and between Marathon Petroleum Company LP and MPC Trade Receivables Company LLC	8-K	10.2	12/23/2013	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
10.10	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	10-K	10.13	2/28/2013	001-35054
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

126

Exhibit Number	Exhibit Description		Incorporated by Reference			Filed Herewith	Furnished Herewith
		Form	Exhibit	Filing Date	SEC File No.
10.16 *	Marathon Petroleum Corporation Executive Tax, Estate, and Financial Planning Program	10-K	10.14	2/29/2012	001-35054
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	10-K	10.26	2/28/2013	001-35054
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	10-K	10.32	2/28/2013	001-35054
10.33 *	Form of Marathon Petroleum Corporation Performance Unit Award Agreement - 2013-2015 Performance Cycle	10-Q	10.1	5/9/2013	001-35054
10.34 *	Form of Marathon Petroleum Corporation Restricted Stock Award Agreement - Officer	10-Q	10.2	5/9/2013	001-35054
10.35 *	Form of Marathon Petroleum Corporation Nonqualified Stock Option Award Agreement - Officer	10-Q	10.3	5/9/2013	001-35054
10.36 *	MPLX LP - Form of MPC Officer Phantom Unit Award Agreement	10-Q	10.4	5/9/2013	001-35054
10.37 *	MPLX LP - Form of MPC Officer Performance Unit Award Agreement - 2013-2015 Performance Cycle	10-Q	10.5	5/9/2013	001-35054
10.38 *	Amendment to Certain Outstanding MPC Restricted Stock Award Agreements and Performance Unit Award Agreements of Garry L. Peiffer					X

127

Exhibit Number	Exhibit Description		Incorporated by Reference			Filed Herewith	Furnished Herewith
		Form	Exhibit	Filing Date	SEC File No.
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

† 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.

128

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

February 28, 2014	MARATHON PETROLEUM CORPORATION
	By:    /s/ Michael G. Braddock
	Michael G. Braddock                 Vice President and Controller

129

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on February 28, 2014 on behalf of the registrant and in the capacities indicated.

Signature	Title
/s/ Gary R. Heminger	President and Chief Executive Officer and Director (Principal Executive Officer)
Gary R. Heminger
/s/ Donald C. Templin	Senior Vice President and Chief Financial Officer (Principal Financial Officer)
Donald C. Templin
/s/ Michael G. Braddock	Vice President and Controller (Principal Accounting Officer)
Michael G. Braddock
*	Director
Evan Bayh
*	Director
David A. Daberko
*	Director
Steven A. Davis
*	Director
William L. Davis
*	Director
Donna A. James
*	Director
Charles R. Lee
*	Director
James E. Rohr
*	Director
Seth E. Schofield
*
John W. Snow	Director
*	Director
John P. Surma
*	Chairman of the Board and Director
Thomas J. Usher

130

* 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, 2014
Gary R. Heminger                 Attorney-in-Fact

131

EX-10.38

Exhibit 10.38

MARATHON PETROLEUM CORPORATION

Amendment to Certain Outstanding MPC Restricted Stock Award Agreements

and Performance Unit Award Agreement

THIS AMENDMENT is adopted this November 18, 2013, by MARATHON PETROLEUM CORPORATION (herein referred to as the "Corporation" or “MPC”).

W I T N E S S E T H:

WHEREAS: The Corporation previously sponsored the Marathon Petroleum Corporation Second Amended and Restated 2011 Incentive Compensation Plan, which was more recently replaced by the Marathon Petroleum Corporation 2012 Incentive Compensation Plan (collectively, the “Plan”), and per the Plan terms Employee Award Agreements under the Plan may be amended or modified if evidenced in writing and signed by an authorized representative of the Corporation; and

WHEREAS: Garry L. Peiffer, Executive Vice President of Corporate Planning and Investor & Government Relations, has notified the Corporation that he will retire effective January 1, 2014; and

WHEREAS: In light of Mr. Peiffer’s nearly forty years of service to the Corporation and its predecessors and his significant contributions to the spinoff of the Corporation from Marathon Oil Corporation in 2011, the formation and initial public offering of MPLX LP in 2012 and other major business development, information technology and procurement projects, the Corporation wishes to amend all outstanding Employee Award Agreements that evidence the grant of restricted shares of MPC common stock (“Restricted Shares”) to Mr. Peiffer under the Plan (the “Restricted Stock Award Agreements”) to provide for accelerated vesting of all outstanding Restricted Shares upon his retirement in good standing effective on or after January 1, 2014, which such outstanding Restricted Shares are expected to consist of 23,186; and

WHEREAS: The Corporation also wishes to amend the outstanding Employee Award Agreement that evidences the grant to Mr. Peiffer under the Plan of MPC performance units (“Performance Units”) for the performance cycle of January 1, 2012, through December 31, 2014, (the “2012 Performance Unit Award Agreement”) to provide that upon his retirement in good standing effective on or after January 1, 2014, Mr. Peiffer will not receive the pro-rata payout as set forth in Paragraph 6 of the 2012 Performance Unit Award Agreement but will instead remain eligible for the payout ultimately determined in accordance with certain remaining terms of the 2012 Performance Unit Award Agreement; and

WHEREAS: The Corporation has authorized the amendment and modification of the terms of Employee Award Agreements in this manner and Gary R. Heminger is an authorized representative of the Corporation and, as the President and Chief Executive Officer of the Corporation, is the Authorized Officer under the terms of the Plan; and

WHEREAS: This Amendment does not adversely affect the rights of Mr. Peiffer under the Restricted Stock Award Agreements or the 2012 Performance Unit Award Agreement.

NOW THEREFORE:  Effective as of November 18, 2013, each of the Restricted Stock Award Agreements is hereby amended and the following provision shall apply to each such Restricted Stock Award Agreement:

Exhibit 10.38

Notwithstanding any other provision of this Award Agreement to the contrary, all outstanding Restricted Shares shall immediately vest in full upon termination of the Participant’s Employment due to Retirement in good standing effective on or after January 1, 2014; provided, however, that the Participant must be in continuous Employment until January 1, 2014, in order for the Restricted Shares to vest. If the Employment of the Participant is terminated for any reason (including earlier Retirement) other than death or for a “Qualified Termination,” as such term is defined in the MPC Amended and Restated Executive Change in Control Severance Benefits Plan, prior to January 1, 2014, any Restricted Shares that have not vested as of the date of such termination of Employment shall be forfeited to the Corporation.

FURTHER: Effective as of November 18, 2013, the 2012 Performance Unit Award Agreement is hereby amended and Paragraph 6 of the 2012 Performance Unit Award Agreement shall be amended in its entirety to read as follows:

In the event of the Retirement in good standing of the Participant effective on or after January 1, 2014, the Participant’s right to receive the Performance Units shall continue to vest as of the date of Retirement through the end of the Performance Cycle, and the Participant’s Performance Units under this Agreement shall be paid-out based on the performance for the Performance Cycle as determined and certified by the Committee in accordance with Paragraph 2 at the close of the Performance Cycle, and payable for the full Performance Cycle rather than on a pro-rata basis. Such payment shall be made as soon as administratively practical following the Committee’s determination under Paragraph 2, and, in any event, during the calendar year following the close of the Performance Cycle. If, in accordance with the Committee’s determination, the Payout Value is zero, the Participant shall immediately forfeit any and all rights to the Performance Units. Upon the vesting and/or forfeiture of the Performance Units pursuant to this Paragraph and the making of the related payout, if any, the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be satisfied in full. The death of the Participant following Retirement but prior to the close of the Performance Cycle shall have no effect on this Paragraph.

The Restricted Stock Award Agreements and the 2012 Performance Unit Award Agreement are hereby amended in full force and effect as of the date hereof.

[SIGNATURE PAGE TO FOLLOW]

Exhibit 10.38

        IN WITNESS WHEREOF, the undersigned has executed this Amendment as of the day and year first above written.

MARATHON PETROLEUM CORPORATION
By:	/s/ Gary R. Heminger Gary R. Heminger President and Chief Executive Officer

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,
	2013		2012		2011		2010		2009
Portion of rentals representing interest	$	71	$	46	$	41	$	45	$	41
Capitalized interest	28		101		112		83		78
Other interest and fixed charges	167		90		60		1		1
Total fixed charges (A)	$	266	$	237	$	213	$	129	$	120
Earnings-pretax income with applicable adjustments (B)	$	3,518	$	5,423	$	3,848	$	1,063	$	748
Ratio of (B) to (A)	13.2		22.9		18.1		8.2		6.2

EX-21.1

Exhibit 21.1

MARATHON PETROLEUM CORPORATION

LIST OF SUBSIDIARIES

as of December 31, 2013

	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 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 LOOP Holdings 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 LP	Delaware
*	MPLX Terminal and Storage LLC	Delaware
*	Muskegon Pipeline LLC	Delaware

	Niles Properties LLC	Delaware
*	North Dakota Pipeline Company 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
	South Houston Green Power, LLC	Delaware
	Speedway LLC	Delaware
	Speedway Petroleum Corporation	Delaware
	Speedway Prepaid Card LLC	Ohio
	Speedway.com LLC	Delaware
	Starvin Marvin, Inc.	Delaware
*	The Andersons Albion Ethanol LLC	Ohio
*	The Andersons Clymers Ethanol LLC	Ohio
*	The Andersons Ethanol Investment LLC	Ohio
*	The Andersons Marathon Ethanol LLC	Delaware
	Williston Basin Pipe Line 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 Form S-3 (Nos. 333-175289, 333-175287 and 333-175286) and Form S-8 (Nos. 333-181007, 333-175245 and 333-175244) of Marathon Petroleum Corporation of our report dated February 28, 2014 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, Ohio

February 28, 2014

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, 2013 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 26th day of February, 2014.

/s/ Gary R. Heminger	/s/ Donald C. Templin
Gary R. Heminger	Donald C. Templin
President, Chief Executive Officer and Director	Senior Vice President and Chief Financial Officer
(principal executive officer)	(principal financial officer)
/s/ Michael G. Braddock	/s/ Evan Bayh
Michael G. Braddock	Evan Bayh
Vice President and Controller	Director
(principal accounting officer)
/s/ David A. Daberko	/s/ Steven A. Davis
David A. Daberko	Steven A. Davis
Director	Director
/s/ William L. Davis	/s/ Donna A. James
William L. Davis	Donna A. James
Director	Director
/s/ Charles R. Lee	/s/ James E. Rohr
Charles R. Lee	James E. Rohr
Director	Director
/s/ Seth E. Schofield	/s/ John W. Snow
Seth E. Schofield	John W. Snow
Director	Director
/s/ John P. Surma	/s/ Thomas J. Usher
John P. Surma	Thomas J. Usher
Director	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, 2014	/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, 2014	/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, 2013 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, 2014

/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, 2013 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, 2014

/s/ Donald C. Templin

Donald C. Templin

Senior Vice President and Chief Financial Officer

XML

Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

Sales to Related Parties

Sales to related parties were as follows:

(In millions)	2013		2012		2011
Equity method investees:
Centennial	$	—	$	1	$	35
Other equity method investees	8		7		7
Marathon Oil Companies	—		—		13
Total	$	8	$	8	$	55

Purchases From Related Parties

Purchases from related parties were as follows:

(In millions)	2013		2012		2011
Equity method investees:
Centennial	$	3	$	7	$	31
LOOP	43		44		66
TAAE	24		—		—
TACE	130		73		46
TAME	131		124		153
Other equity method investees	26		32		30
Marathon Oil Companies	—		—		1,590
Total	$	357	$	280	$	1,916

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)	2013		2012
Centennial	$	1	$	2
TAME	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)	2013		2012
LOOP	$	3	$	4
TAAE	2		—
TACE	4		2
TAME	5		5
Other equity method investees	2		2
Total	$	16	$	13

Related Party Net Interest and Financial Income

Related party net interest and other financial income for 2013 and 2012 was not material. Related party net interest and other financial income for 2011 was as follows:

(In millions)	2011
Dividend income:
PFD Preferred Stock	$	35
Interest expense:
PFD revolving credit agreement	3
Marathon Oil loan agreement	5
Interest capitalized	(8		)
Total	—
Related party net interest and other financial income	$	35

XML

Selected 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, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Quarterly Financial Data [Abstract]
Revenues	$ 24,897	$ 26,256	$ 25,677	$ 23,330	$ 20,686	$ 21,049	$ 20,243	$ 20,265
Income from operations	1,008	301	960	1,156	1,189	1,895	1,307	956	3,425	5,347	3,745
Net income	631	173	599	730	759	1,224	814	596	2,133	3,393	2,389
Net income attributable to MPC	$ 626	$ 168	$ 593	$ 725	$ 755	$ 1,224	$ 814	$ 596	$ 2,112	$ 3,389	$ 2,389
Net income attributable to MPC per share
Basic (in USD per share)	$ 2.09	$ 0.54	$ 1.84	$ 2.19	$ 2.26	$ 3.61	$ 2.39	$ 1.71	$ 6.69	$ 9.95	$ 6.70
Diluted (in USD per share)	$ 2.07	$ 0.54	$ 1.83	$ 2.17	$ 2.24	$ 3.59	$ 2.38	$ 1.70	$ 6.64	$ 9.89	$ 6.67
Dividends paid per share (in USD per share)	$ 0.42	$ 0.42	$ 0.35	$ 0.35	$ 0.35	$ 0.35	$ 0.25	$ 0.25	$ 1.54	$ 1.20	$ 0.45

XML

Derivatives (Open Commodity Derivative Contracts) (Detail)	12 Months Ended
	Dec. 31, 2013
Crude Oil Exchange-Traded [Member]
Derivative [Line Items]
Percentage of derivative contracts expiring in the period	100.00%
Derivative contract expiration date	Mar. 31, 2014
Crude Oil Exchange-Traded [Member] | Long [Member]
Derivative [Line Items]
Notional Contracts (in thousands of Total Barrels)	10,580,000	[1]
Crude Oil Exchange-Traded [Member] | Short [Member]
Derivative [Line Items]
Notional Contracts (in thousands of Total Barrels)	(23,900,000)	[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, 2014
Refined Products Exchange-Traded [Member] | Long [Member]
Derivative [Line Items]
Notional Contracts (in thousands of Total Barrels)	3,646,000	[1]
Refined Products Exchange-Traded [Member] | Short [Member]
Derivative [Line Items]
Notional Contracts (in thousands of Total Barrels)	(4,175,000)	[1]

[1] of these contracts expire in the first quarter of 2014.

XML

Defined Benefit Pension and Other Postretirement Plans (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

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)	2013		2012
Projected benefit obligations	$	1,927	$	2,192
Accumulated benefit obligations	1,912		2,035
Fair value of plan assets	1,800		1,478

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)	2013			2012			2013			2012
Change in benefit obligations:
Benefit obligations at January 1	$	2,192		$	2,685		$	591		$	551
Service cost	93			66			25			20
Interest cost	73			94			26			24
Actuarial (gain) loss	(183		)	117			17			53
Benefits paid	(248		)	(233		)	(20		)	(17		)
Liability gain due to curtailment	—			(17		)	—			—
Other(a)	—			(520		)	48			(40		)
Benefit obligations at December 31	1,927			2,192			687			591
Change in plan assets:
Fair value of plan assets at January 1	1,478			1,423			—			—
Actual return on plan assets	241			157			—			—
Employer contributions	329			131			—			—
Benefits paid from plan assets	(248		)	(233		)	—			—
Fair value of plan assets at December 31	1,800			1,478			—			—
Funded status of plans at December 31	$	(127	)	$	(714	)	$	(687	)	$	(591	)
Amounts recognized in the consolidated balance sheets:
Current liabilities	$	(18	)	$	(18	)	$	(25	)	$	(21	)
Noncurrent liabilities	(109		)	(696		)	(662		)	(570		)
Accrued benefit cost	$	(127	)	$	(714	)	$	(687	)	$	(591	)
Pretax amounts recognized in accumulated other comprehensive loss:(b)
Net loss	$	668		$	1,147		$	107		$	93
Prior service credit	(415		)	(460		)	(30		)	(38		)

^(a)  Includes adjustments related to plan amendments in 2013 and 2012. Also, includes adjustments related to the Galveston Bay Refinery and Related Assets acquisition in 2013.

^(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 2013, 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)	2013			2012			2011			2013			2012			2011
Components of net periodic benefit cost:
Service cost	$	93		$	66		$	65		$	25		$	20		$	19
Interest cost	73			94			110			26			24			27
Expected return on plan assets	(107		)	(104		)	(97		)	—			—			—
Amortization – prior service cost (credit)	(45		)	(18		)	6			(4		)	(2		)	—
– actuarial loss	66			93			71			3			2			—
– net settlement/curtailment loss(a)	95			125			8			—			—			—
Net periodic benefit cost(b)	$	175		$	256		$	163		$	50		$	44		$	46
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial (gain) loss	$	(317	)	$	46		$	427		$	17		$	53		$	39
Prior service cost (credit)(c)	—			(520		)	—			4			(40		)	—
Amortization of actuarial loss	(161		)	(218		)	(79		)	(3		)	(2		)	—
Amortization of prior service cost (credit)	45			18			(6		)	4			2			—
Other(d)	—			—			6			—			—			—
Total recognized in other comprehensive loss	$	(433	)	$	(674	)	$	348		$	22		$	13		$	39
Total recognized in net periodic benefit cost and other comprehensive loss	$	(258	)	$	(418	)	$	511		$	72		$	57		$	85

^(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 6.

^(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 plan amendments approved in 2013 and 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 in 2011.

Plan Assumptions

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

	Pension Benefits						Other Benefits
	2013		2012		2011		2013		2012		2011
Weighted-average assumptions used to determine benefit obligation:
Discount rate	4.30	%	3.45	%	4.30	%	4.95	%	4.05	%	4.65	%
Rate of compensation increase	3.70	%	5.00	%	5.00	%	3.70	%	5.00	%	5.00	%
Weighted-average assumptions used to determine net periodic benefit cost:
Discount rate	3.88	%	4.06	%	4.98	%	4.11	%	4.54	%	5.55	%
Expected long-term return on plan assets(a)	7.50	%	7.50	%	8.50	%	—	%	—	%	—	%
Rate of compensation increase	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%

^(a) Effective January 1, 2014, the expected long-term rate of return on plan assets changed from 7.50 percent to 7.00 percent due to a change in our plan investment strategy.

Assumed Health Care Cost Trend Rates

The following summarizes the assumed health care cost trend rates.

	December 31,
	2013		2012		2011
Health care cost trend rate assumed for the following year:
Medical:
Pre-65	8.00	%	8.00	%	7.50	%
Post-65(a)	N/A		N/A		7.00	%
Prescription drugs	7.00	%	7.00	%	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		N/A		5.00	%
Prescription drugs	5.00	%	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate:
Medical:
Pre-65	2020		2020		2018
Post-65(a)	N/A		N/A		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

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	$	5	$	(4	)
Effect on other postretirement benefit obligations	39		(34		)

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, 2013 and 2012.

	December 31, 2013
(In millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	—	$	189	$	—	$	189
Equity:
Common stocks	69		—		—		69
Mutual funds	217		—		—		217
Pooled funds	—		590		—		590
Fixed income:
Corporate	—		356		—		356
Government	—		22		—		22
Pooled funds	—		218		—		218
Private equity	—		—		57		57
Real estate	—		—		60		60
Other	2		—		20		22
Total investments, at fair value	$	288	$	1,375	$	137	$	1,800

	December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	107	$	—	$	—	$	107
Equity:
Exchange-traded funds	166		—		—		166
Investment trusts	17		94		—		111
Pooled funds	—		709		—		709
Fixed income:
Pooled funds	—		258		—		258
Private equity	—		—		56		56
Real estate	—		—		54		54
Other	—		—		17		17
Total investments, at fair value	$	290	$	1,061	$	127	$	1,478

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:

	2013
(In millions)	Private Equity			Real Estate			Other		Total
Beginning balance	$	56		$	54		$	17	$	127
Actual return on plan assets:
Realized	13			3			—		16
Unrealized	3			10			3		16
Purchases	7			5			—		12
Sales	(22		)	(12		)	—		(34		)
Ending balance	$	57		$	60		$	20	$	137

	2012
(In millions)	Private Equity			Real Estate			Other		Total
Beginning balance	$	55		$	49		$	17	$	121
Actual return on plan assets:
Realized	5			(2		)	—		3
Unrealized	(3		)	2			—		(1		)
Purchases	12			10			—		22
Sales	(13		)	(5		)	—		(18		)
Ending balance	$	56		$	54		$	17	$	127

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)
2014	$	186	$	26
2015	181		29
2016	177		32
2017	178		34
2018	175		38
2019 through 2023	814		231

^(a)  Effective 2013, as a result of the Patient Protection and Affordable Care Act, 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

		Pension Protection Act Zone Status		FIP/RP Status Pending/Implemented	MPC Contributions (In millions)						Surcharge Imposed	Expiration Date of Collective - Bargaining Agreement
Pension Fund	EIN	2013	2012		2013		2012		2011
Central States, Southeast and Southwest Areas Pension Plan(a)	36-6044243	Red	Red	Implemented	$	3	$	4	$	3	No	January 31, 2019

^(a)  This agreement has a minimum contribution requirement of $269 per week per employee for 2014. A total of 257 employees participated in the plan as of December 31, 2013.

XML

Goodwill (Tables)

12 Months Ended

Dec. 31, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

Changes In Carrying Amount Of Goodwill

The changes in the carrying amount of goodwill for 2013 and 2012 were as follows:

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
2012
Beginning balance	$	551	$	129	$	162	$	842
Acquisitions(a)	—		88		—		88
Ending balance	$	551	$	217	$	162	$	930
2013
Beginning balance	$	551	$	217	$	162	$	930
Acquisitions(a)	—		8		—		8
Ending balance	$	551	$	225	$	162	$	938

^(a)  See Note 5 for information on the acquisitions.

XML

Defined Benefit Pension And Other Postretirement Plans (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 1,912	$ 2,035
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	The asset allocation strategy will change over time in response to changes primarily in funded status, which is dictated by current and anticipated market conditions, the independent actions of our investment committee, required cash flows to and from the plans and other factors deemed appropriate. Such changes in asset allocation are intended to allocate additional assets to the fixed income asset class should the funded status improve. The fixed income asset class shall be invested in such a manner that its interest rate sensitivity correlates highly with that of the plans' liabilities. Other asset classes are intended to provide additional return with associated higher levels of risk.
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	76	60	60
Multiemployer Plans, Pension [Member]
Defined Benefit Plan Disclosure [Line Items]
The Company's contributions to multiemployer plans	3	4	3
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Targeted asset allocation	62.00%
Fixed Income Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Targeted asset allocation	38.00%
Pension And Postretirement Healthcare Plan [Member] | Galveston Bay Refinery And Related Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Decrease in laibilities	(122)
Percentage increase in discount rate	0.20%
Liability related to retiree medical assumed at the acquisition date	43
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Decrease in benefit liabilities		537
Increase in retiree medical liabilities resulting from a reduction in discount rates	183	(117)
Estimated net gain (loss) that will be amortized from accumulated other comprehensive loss in 2014	52
Estimated prior service cost that will be amortized from accumulated other comprehensive loss in 2014	46
Pension Contributions	161
Pension Benefits [Member] | Funded Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plans, estimated future employer contributions in next fiscal year	0
Pension Benefits [Member] | Unfunded Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plans, estimated future employer contributions in next fiscal year	18
Health Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Decrease in benefit liabilities		40
Increase in retiree medical liabilities resulting from a reduction in discount rates		57
Health Plan [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Maximum increase in tax-free contributions to health reimbursement account (in percentage)		4.00%
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
Increase in retiree medical liabilities resulting from a reduction in discount rates	(17)	(53)
Estimated net gain (loss) that will be amortized from accumulated other comprehensive loss in 2014	3
Estimated prior service cost that will be amortized from accumulated other comprehensive loss in 2014	4
Other Benefits [Member] | Unfunded Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plans, estimated future employer contributions in next fiscal year	26
Other Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Multi employer pension plans	There have been no significant changes that affect the comparability of 2013, 2012 and 2011 contributions.
Other Pension Plans [Member] | Multiemployer Plans, Pension [Member]
Defined Benefit Plan Disclosure [Line Items]
Number of multiemployer defined benefit pension or health and welfare plan		1
Other Pension Plans [Member] | Maximum [Member] | Multiemployer Plans, Pension [Member]
Defined Benefit Plan Disclosure [Line Items]
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]
Defined Benefit Plan Disclosure [Line Items]
Number of multiemployer defined benefit pension or health and welfare plan		1
The Company's contributions to multiemployer plans	$ 5	$ 5	$ 4

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Related Party Transactions (Narrative) (Detail) (USD $)	12 Months Ended				3 Months Ended	12 Months Ended								12 Months Ended		0 Months Ended	12 Months Ended			1 Months Ended	12 Months Ended			1 Months Ended			12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Jun. 30, 2011	Mar. 31, 2012 Centennial [Member]	Dec. 31, 2013 Centennial [Member]	Dec. 31, 2012 Centennial [Member]	Dec. 31, 2011 Centennial [Member]	Dec. 31, 2013 LOOP [Member]	Dec. 31, 2013 TAAE [Member]	Oct. 02, 2013 TAAE [Member]	Dec. 31, 2013 TACE [Member]	Dec. 31, 2013 TAME [Member]	Dec. 31, 2011 Marathon Oil Companies [Member]		Feb. 01, 2011 Marathon Oil Companies [Member] Revenue Bonds [Member]	Dec. 31, 2013 Marathon Oil Companies [Member] Revenue Bonds [Member]	Jul. 18, 2007 Marathon Oil Companies [Member] Revenue Bonds [Member]	Dec. 31, 2005 PFD [Member]	Jul. 18, 2007 PFD [Member] Related Party Credit Agreement [Member]	Dec. 31, 2013 PFD [Member] Related Party Credit Agreement [Member]	Dec. 31, 2011 PFD [Member] Related Party Credit Agreement [Member]	Oct. 28, 2010 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]	Dec. 31, 2013 Initial Agreement [Member] PFD [Member] Related Party Credit Agreement [Member]	Dec. 31, 2013 Amended Agreement [Member] PFD [Member] Related Party Credit Agreement [Member]
Related Party Transaction [Line Items]
Equity method investments, Ownership Percentage						50.00%			51.00%	43.00%	43.00%	60.00%	67.00%
Separation and distribution agreement date of Spin off transaction	May 25, 2011
Aggregate cash and cash equivalent balance				$ 1,625,000,000
Maximum duration of agreement for administrative services with former parent (in years)	1 year
Operating pipeline revenue from related parties included in other income						1,000,000	1,000,000	0
Selling, general and administrative expenses from transactions with related party														26,000,000
Long-term receivable from related party						2,000,000
Impairment of prepaid tariff					14,000,000
Line of Credit Facility, Initiation Date																											Jul. 18, 2007	Oct. 28, 2010
Line of Credit Facility, Maximum Borrowing Capacity																				2,900,000,000.0			4,400,000,000.0
Line of credit facility, expiration date																	Apr. 01, 2011				Jun. 30, 2011						May 04, 2012	Nov. 01, 2013
Long-term debt payable to related parties - borrowings	0	0	7,748,000,000																			7,750,000,000
Long-term debt payable to related parties – repayments	0	0	11,366,000,000													1,050,000,000						10,320,000,000
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 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														2,000,000
Other Significant Noncash Transaction, Value of Consideration Received	$ 43,000,000	$ 0	$ 0											$ 57,000,000	[1]

[1] See Note 7.

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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, 2013		Dec. 31, 2012		Dec. 31, 2011
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Amortization of actuarial loss	$ (69)	[1]
Amortization of prior service cost (credit)	49	[1]
Pension Benefits [Member]
Components of net periodic benefit cost:
Service cost	93		66		65
Interest cost	73		94		110
Expected return on plan assets	(107)		(104)		(97)
Amortization - prior service cost (credit)	(45)		(18)		6
Amortization - actuarial loss	66		93		71
Amortization - net settlement/curtailment loss	95	[2]	125	[2]	8	[2]
Net periodic benefit cost	175	[3]	256	[3]	163	[3]
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial (gain) loss	(317)		46		427
Prior service cost (credit)	0	[4]	(520)	[4]	0	[4]
Amortization of actuarial loss	(161)		(218)		(79)
Amortization of prior service cost (credit)	45		18		(6)
Other	0	[5]	0	[5]	6	[5]
Total recognized in other comprehensive loss	(433)		(674)		348
Total recognized in net periodic benefit cost and other comprehensive loss	(258)		(418)		511
Other Benefits [Member]
Components of net periodic benefit cost:
Service cost	25		20		19
Interest cost	26		24		27
Expected return on plan assets	0		0		0
Amortization - prior service cost (credit)	(4)		(2)		0
Amortization - actuarial loss	3		2		0
Amortization - net settlement/curtailment loss	0	[2]	0	[2]	0	[2]
Net periodic benefit cost	50	[3]	44	[3]	46	[3]
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial (gain) loss	17		53		39
Prior service cost (credit)	4	[4]	(40)	[4]	0	[4]
Amortization of actuarial loss	(3)		(2)		0
Amortization of prior service cost (credit)	4		2		0
Other	0	[5]	0	[5]	0	[5]
Total recognized in other comprehensive loss	22		13		39
Total recognized in net periodic benefit cost and other comprehensive loss	$ 72		$ 57		$ 85

[1] These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 22.

[2] 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 6.

[3] Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.

[4] Includes adjustments due to plan amendments approved in 2013 and adjustments due to changes made to the defined pension plans and the post-65 medical plan coverage effective January 1, 2013.

[5] Includes adjustments related to the Spinoff in 2011.

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Stock-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Weighted Average Assumptions Used To Value Stock Options Awards

The Black Scholes option-pricing model values used to value stock option awards granted 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):

	2013			2012			2011 subsequent to Spinoff			2011 prior to Spinoff
Weighted average exercise price per share	$	84.65		$	42.02		$	36.18		$	51.93
Expected annual dividends per share	$	1.40		$	1.00		$	0.95		$	1.00
Expected life in years	6.0			5.8			5.8			5.3
Expected volatility	40		%	47		%	48		%	40		%
Risk-free interest rate	1.0		%	1.1		%	1.4		%	2.0		%
Weighted average grant date fair value of stock option awards granted	$	27.13		$	14.45		$	13.08		$	16.73

Schedule Of Share-Based Compensation MPC Equity Based Stock Option Activity

The following is a summary of our common stock option activity in 2013:

	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, 2012	6,172,194		$	36.17
Granted	408,603		84.65
Exercised	(1,348,938	)	35.48
Forfeited, canceled or expired	(84,022	)	43.97
Outstanding at December 31, 2013	5,147,837		40.08
Vested and expected to vest at December 31, 2013	5,142,351		40.04		6.0	$	266
Exercisable at December 31, 2013	3,674,485		34.63		5.3	210

^(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 2013:

	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, 2012	638,073		$	40.83	359,111		$	31.07
Granted	256,224		87.06		26,399		73.48
RS's Vested/RSU's Issued	(245,116	)	37.95		(431	)	39.53
Forfeited	(25,059	)	58.60		—		—
Outstanding at December 31, 2013	624,122		61.11		385,079		33.96

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
2013	$	20	$	87.06	$	—	$	73.48
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

Schedule Of Performance Unit Awards

The following table presents a summary of the 2013 activity for performance unit awards to be settled in shares:

	Number of Units
Outstanding at December 31, 2012	2,040,000
Granted	1,782,500
Settled	—
Canceled	—
Outstanding at December 31, 2013	3,822,500

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Equity (Narrative) (Detail) (USD $) Share data in Millions, except Per Share data, unless otherwise specified	12 Months Ended			1 Months Ended			12 Months Ended	23 Months Ended		12 Months Ended		12 Months Ended				23 Months Ended	1 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Sep. 26, 2013 Share Repurchase Plan [Member] Common Stock [Member]	Jan. 30, 2013 Share Repurchase Plan [Member] Common Stock [Member]	Feb. 01, 2012 Share Repurchase Plan [Member] Common Stock [Member]	Dec. 31, 2013 Share Repurchase Plan [Member] Common Stock [Member]	Dec. 31, 2013 Share Repurchase Plan [Member] Common Stock [Member]	Feb. 28, 2012 Accelerated Share Repurchase Program February 2012 [Member] Common Stock [Member]	Dec. 31, 2013 Accelerated Share Repurchase Program November 2nd 2012 [Member]	Nov. 30, 2012 Accelerated Share Repurchase Program November 2nd 2012 [Member] Common Stock [Member]	Dec. 31, 2013 Accelerated Share Repurchase Program And Open Market Repurchases [Member]		Dec. 31, 2012 Accelerated Share Repurchase Program And Open Market Repurchases [Member]	Dec. 31, 2011 Accelerated Share Repurchase Program And Open Market Repurchases [Member]	Dec. 31, 2013 Accelerated Share Repurchase Program And Open Market Repurchases [Member]	Jan. 31, 2014 Accelerated Share Repurchase Program And Open Market Repurchases [Member] Repurchase Of Common Stock [Member] Scenario, Forecast [Member]	Feb. 01, 2012 Maximum [Member] Share Repurchase Plan [Member] Common Stock [Member]
Stockholders Equity Note [Line Items]
Stock repurchase plan authorized amount				$ 2,000,000,000	$ 2,000,000,000			$ 6,000,000,000										$ 2,000,000,000
Period for repurchase						2 years
Share repurchase authorization ending date				September 2015	December 2014
Stock repurchase plan remaining authorized amount							1,860,000,000
Repurchase shares of MPC common stock under ASR program									850,000,000		500,000,000
Number of shares repurchased										1		37	[1]	28	0	65
Cash paid for shares repurchased	$ 2,793,000,000	$ 1,350,000,000	$ 0									$ 2,793,000,000		$ 1,350,000,000		$ 4,140,000,000	$ 12,000,000
Effective average cost per delivered share												$ 76.14		$ 46.73		$ 63.61

[1] (a)Shares repurchased in 2013 includes 1 million shares received under the November 2012 ASR program, which were paid for in 2012.

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Fair Value Measurements (Assets And Liabilities Accounted For At Fair Value On Recurring Basis) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013		Dec. 31, 2012
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash collateral	$ 32		$ 39
Liabilities, current	159
Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets	0	[1]	0	[1]
Other assets	2	[1]	2	[1]
Total assets at fair value	2	[1]	2	[1]
Commodity derivative instruments, liabilities	0	[1]	0	[1]
Contingent consideration, liability	625	[1],[2]
Total liabilities at fair value	625	[1]
Level 1 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets	21		49
Other assets	2		2
Total assets at fair value	23		51
Commodity derivative instruments, liabilities	53		88
Contingent consideration, liability	0
Total liabilities at fair value	53
Level 2 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets	0		0
Other assets	0		0
Total assets at fair value	0		0
Commodity derivative instruments, liabilities	0		0
Contingent consideration, liability	0
Total liabilities at fair value	0
Level 3 [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets	0		0
Other assets	0		0
Total assets at fair value	0		0
Commodity derivative instruments, liabilities	0		0
Contingent consideration, liability	625	[2]
Total liabilities at fair value	625
Collateral [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets	(21)	[3]	(49)	[3]
Total assets at fair value	(21)	[3]	(49)	[3]
Commodity derivative instruments, liabilities	(53)	[3]	(88)	[3]
Total liabilities at fair value	(53)	[3]
Collateral Pledged Not Offset [Member] | Fair Value, Measurements, Recurring [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets	61		45
Other assets	0		0
Total assets at fair value	61		45
Commodity derivative instruments, liabilities	0		0
Contingent consideration, liability	0
Total liabilities at fair value	$ 0

[1] We have no derivative contracts that are subject to master netting arrangements that are reflected gross on the balance sheet.

[2] Includes $159 million classified as current.

[3] Represents the impact of netting assets, liabilities and cash collateral when a legal right of offset exists. As of December 31, 2013 and 2012, cash collateral of $32 million and $39 million, respectively, was netted with mark-to-market derivative liabilities.

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Equity Method Investments (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Schedule Of Equity Method Investments

14. Equity Method Investments

	Ownership as of December 31, 2013	December 31,
(In millions)		2013		2012
Centennial	50%	$	29	$	27
LOCAP LLC	59%	24		26
LOOP	51%	214		198
North Dakota Pipeline(a)	38%	24		—
TAAE	43%	29		—
TACE	60%	70		29
TAEI	34%	23		—
TAME(b)	50%	35		27
Other		15		14
Total		$	463	$	321

^(a)  We own a 38 percent interest in the Class B units of this entity. Our Class B units will be converted to an approximate 27 percent ownership interest in the Class A units of this entity upon completion of the Sandpiper pipeline construction project in 2016.

^(b)  Exclu

Summarized Financial Information For Equity Method Investees

Summarized financial information for equity method investees is as follows:

(In millions)	2013		2012		2011
Income statement data:
Revenues and other income	$	1,067	$	1,025	$	1,043
Income from operations	87		73		128
Net income	63		47		101
Balance sheet data - December 31:
Current assets	$	339	$	217
Noncurrent assets	1,238		1,163
Current liabilities	145		161
Noncurrent liabilities	618		636

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Commitments and Contingencies

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 both December 31, 2013 and 2012, accrued liabilities for remediation totaled $123 million. 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, were $51 million at both December 31, 2013 and December 31, 2012.

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 financings by assigning certain of their rights under throughput and deficiency agreements that they have entered into with us. 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 follow the terms of the underlying debt obligations, some of which extend through 2037. Our maximum potential undiscounted payments under these agreements for the debt principal totaled $172 million as of December 31, 2013.

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 $42 million as of December 31, 2013.

We hold an interest in a ethanol production facility through our investment in TAME and through our participation as a lender under TAME's revolving credit agreement, have agreed to reimburse the bank for 50 percent of any amounts drawn on a letter of credit that has been issued to secure TAME's 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, 2013.

Marathon Oil indemnifications – In conjunction with the Spinoff, we have entered into arrangements with Marathon Oil providing indemnities and guarantees with recorded values of $2 million as of December 31, 2013, 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 12, 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 $122 million as of December 31, 2013, 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, 2013 and 2012, our contractual commitments to acquire property, plant and equipment and advance funds to equity method investees totaled $1.7 billion and $1.4 billion, respectively. The contractual commitments at December 31, 2013 includes $700 million of contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets and $892 million for contributions to North Dakota Pipeline. The contractual commitments at December 31, 2012 included both the base purchase price and the $700 million contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5.

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Equity (Share Repurchases Transacted Through ASR Programs and Open Market Transactions) (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended				23 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2013
Stockholders Equity [Line Items]
Cash paid for shares repurchased	$ 2,793		$ 1,350	$ 0
Accelerated Share Repurchase Program November 2nd 2012 [Member]
Stockholders Equity [Line Items]
Number of shares repurchased	1
Accelerated Share Repurchase Program And Open Market Repurchases [Member]
Stockholders Equity [Line Items]
Number of shares repurchased	37	[1]	28	0	65
Cash paid for shares repurchased	$ 2,793		$ 1,350		$ 4,140
Effective average cost per delivered share	$ 76.14		$ 46.73		$ 63.61

[1] (a)Shares repurchased in 2013 includes 1 million shares received under the November 2012 ASR program, which were paid for in 2012.

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Supplemental Cash Flow Information (Reconciliation Of Additions To Property, Plant And Equipment To Total Capital Expenditures) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Schedule of Reconciliation of Additions to Property Plant and Equipment [Line Items]
Additions to property, plant and equipment	$ 1,206,000,000		$ 1,369,000,000		$ 1,185,000,000
Acquisitions	1,386,000,000	[1]	180,000,000	[1]	74,000,000	[1]
Increase (decrease) in capital accruals	73,000,000		(117,000,000)		53,000,000
Total capital expenditures	2,665,000,000		1,432,000,000		1,312,000,000
Galveston Bay Refinery And Related Assets [Member]
Schedule of Reconciliation of Additions to Property Plant and Equipment [Line Items]
Acquisitions	1,360,000,000
Cash paid excluding inventories	1,150,000,000
Assumed liabilities	$ 210,000,000

[1] Includes $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, of $1.15 billion plus assumed liabilities of $210 million. The 2012 acquisitions exclude the inventory acquired and liability assumed. See Note 5.

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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, 2013
Defined Benefit Plan, Effect of One-Percentage Point Change in Assumed Health Care Cost Trend Rates [Abstract]
Effect on total of service and interest cost components, 1-Percentage-Point-Increase	$ 5
Effect on other postretirement benefit obligations, 1-Percentage-Point-Increase	39
Effect on total of service and interest cost components, 1-Percentage-Point Decrease	(4)
Effect on other postretirement benefit obligations, 1-Percentage-Point-Decrease	$ (34)

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Stock-Based Compensation Plans (Weighted Average Assumptions Used To Value Stock Options Awards) (Detail) (Stock Options [Member], USD $)	6 Months Ended	12 Months Ended		6 Months Ended
	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2011 Predecessor [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average exercise price per share	$ 36.18	$ 84.65	$ 42.02	$ 51.93
Expected annual dividends per share	$ 0.95	$ 1.40	$ 1.00	$ 1.00
Expected life in years	5 years 9 months 18 days	6 years	5 years 9 months 18 days	5 years 3 months 18 days
Expected volatility	48.00%	40.00%	47.00%	40.00%
Risk-free interest rate	1.40%	1.00%	1.10%	2.00%
Weighted average grant date fair value of stock option awards granted	$ 13.08	$ 27.13	$ 14.45	$ 16.73

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Related Party Transactions (Receivables From Related Parties) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Current receivables from related parties	$ 2	$ 2
Centennial [Member]
Related Party Transaction [Line Items]
Current receivables from related parties	1	2
TAME [Member]
Related Party Transaction [Line Items]
Current receivables from related parties	$ 1	$ 0

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Income Taxes (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Income Tax Disclosure [Abstract]
Deferred tax assets, valuation allowance	$ 2
Unrecognized tax benefits, increase (decrease)	(21)
Tax settlement with Marathon Oil Corporation	39
Unrecognized tax benefits that would impact effective income tax rate	6
Uncertain tax positions, reasonably possible increase or decrease during the next twelve months	5
Unrecognized tax benefits income tax net penalties and interest (receipts) expenses	11	(1)	5
Interest and penalties accrued	$ 15	$ 9

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Selected Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Schedule Of Quarterly Financial Information

	2013								2012
(In millions, except per share data)	1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.		1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.
Revenues	$	23,330	$	25,677	$	26,256	$	24,897	$	20,265	$	20,243	$	21,049	$	20,686
Income from operations	1,156		960		301		1,008		956		1,307		1,895		1,189
Net income	730		599		173		631		596		814		1,224		759
Net income attributable to MPC	725		593		168		626		596		814		1,224		755
Net income attributable to MPC per share:
Basic	$	2.19	$	1.84	$	0.54	$	2.09	$	1.71	$	2.39	$	3.61	$	2.26
Diluted	2.17		1.83		0.54		2.07		1.70		2.38		3.59		2.24
Dividends paid per share	0.35		0.35		0.42		0.42		0.25		0.25		0.35		0.35

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Derivatives (Classification Of Gross Fair Values Of Derivative Instruments, Excluding Cash Collateral) (Detail) (Commodity Derivatives [Member], Other Current Assets [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Commodity Derivatives [Member] | Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Asset	$ 21	$ 49
Liability	$ 53	$ 88

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Stock-Based Compensation Plans (Summary Of Stock Option Award Activity) (Detail) (Stock Options [Member], USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2013		Dec. 31, 2012
Stock Options [Member]
Number of of Shares
Outstanding at December 31, 2012		6,172,194	[1]
Granted		408,603	[1]
Exercised		(1,348,938)	[1]
Forfeited, canceled or expired		(84,022)	[1]
Outstanding at December 31, 2013		5,147,837	[1]	6,172,194	[1]
Vested and expected to vest at December 31, 2013		5,142,351	[1]
Exercisable at December 31, 2013		3,674,485	[1]
Weighted Average Exercise Price
Outstanding at December 31, 2012 (in USD per share)		$ 36.17
Granted (in USD per share)	$ 36.18	$ 84.65		$ 42.02
Exercised (in USD per share)		$ 35.48
Forfeited, canceled or expired (in USD per share)		$ 43.97
Outstanding at December 31, 2013 (in USD per share)		$ 40.08		$ 36.17
Vested and expected to vest at December 31, 2013 (in USD per share)		$ 40.04
Exercisable at December 31, 2013 (in USD per share)		$ 34.63
Weighted Average Remaining Contractual Term
Vested and expected to vest at December 31, 2013 (in years)		6 years
Exercisable at December 31, 2013 (in years)		5 years 3 months 18 days
Aggregate Intrinsic Value
Vested and expected to vest at December 31, 2013 (in USD)		$ 266
Exercisable at December 31, 2013 (in USD)		$ 210

[1] (a) Includes an immaterial number of stock appreciation rights.

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Income per Common Share (Narrative) (Detail)			12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Stock Based Compensation Award [Member]	Dec. 31, 2012 Stock Based Compensation Award [Member]	Dec. 31, 2011 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, shares distributed	362,000,000	361,000,000				356,337,127
Excluded from diluted share calculation			1,000,000	2,000,000	4,000,000

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Segment Information (Total Assets By Reportable Segment) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	$ 28,385	$ 27,223
Operating Segments [Member] | Refining & Marketing [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	19,573	17,052
Operating Segments [Member] | Speedway [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	2,064	1,947
Operating Segments [Member] | Pipeline Transportation [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	1,947	1,950
Corporate, Non-Segment [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	$ 4,801	$ 6,274

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Segment Information (Income From Operations Attributable To Operating Segments) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Segment Reporting Information [Line Items]
Customer									$ 100,152		$ 82,235		$ 78,583
Related parties									8		8		55
Segment income from operations	1,008	301	960	1,156	1,189	1,895	1,307	956	3,425		5,347		3,745
Income (loss) from equity method investments									36		26		50
Depreciation and amortization									1,220		995		891
Capital expenditures and investments									2,789	[1],[2]	1,460	[1],[2]	1,323	[1],[2]
Acquisitions									1,386	[3]	180	[3]	74	[3]
Galveston Bay Refinery And Related Assets [Member]
Segment Reporting Information [Line Items]
Acquisitions									1,360
Operating Segments [Member]
Segment Reporting Information [Line Items]
Customer									100,158		82,237		78,583
Intersegment									9,756	[4]	9,167	[4]	8,636	[4]
Related parties									8		8		55
Segment revenues									109,922		91,412		87,274
Total revenues									100,166		82,245		78,638
Segment income from operations									3,791	[5]	5,624	[5]	4,061	[5]
Income (loss) from equity method investments									36		26		50
Depreciation and amortization									1,197	[6]	972	[6]	873	[6]
Capital expenditures and investments									2,624	[2],[7],[8]	1,256	[2],[7]	1,185	[2],[7]
Operating Segments [Member] | Refining & Marketing [Member]
Segment Reporting Information [Line Items]
Customer									85,608		67,921		65,028
Intersegment									9,294	[4]	8,782	[4]	8,301	[4]
Related parties									8		7		52
Segment revenues									94,910		76,710		73,381
Total revenues									85,616		67,928		65,080
Segment income from operations									3,206		5,098		3,591
Income (loss) from equity method investments									28		(6)		11
Depreciation and amortization									1,011		804		718
Capital expenditures and investments									2,094	[1],[2],[8]	705	[1],[2]	900	[1],[2]
Operating Segments [Member] | Refining & Marketing [Member] | Galveston Bay Refinery And Related Assets [Member]
Segment Reporting Information [Line Items]
Acquisitions									1,290
Operating Segments [Member] | Speedway [Member]
Segment Reporting Information [Line Items]
Customer									14,471		14,239		13,490
Intersegment									4	[4]	4	[4]	0	[4]
Related parties									0		0		0
Segment revenues									14,475		14,243		13,490
Total revenues									14,471		14,239		13,490
Segment income from operations									375		310		271
Income (loss) from equity method investments									0		0		0
Depreciation and amortization									112		114		110
Capital expenditures and investments									296	[2],[7],[8],[9]	340	[2],[7],[9]	164	[2],[7],[9]
Operating Segments [Member] | Pipeline Transportation [Member]
Segment Reporting Information [Line Items]
Customer									79		77		65
Intersegment									458	[4]	381	[4]	335	[4]
Related parties									0		1		3
Segment revenues									537		459		403
Total revenues									79		78		68
Segment income from operations									210	[5]	216	[5]	199	[5]
Income (loss) from equity method investments									8		32		39
Depreciation and amortization									74		54		45
Capital expenditures and investments									234	[1],[2],[8]	211	[1],[2]	121	[1],[2]
Operating Segments [Member] | Pipeline Transportation [Member] | Galveston Bay Refinery And Related Assets [Member]
Segment Reporting Information [Line Items]
Acquisitions									70
Operating Segments [Member] | Pipeline Transportation [Member] | MPLX LP [Member]
Segment Reporting Information [Line Items]
Cost of Services, Overhead									20		4
Intersegment Eliminations [Member]
Segment Reporting Information [Line Items]
Intersegment									9,756		9,167		8,636
Intersegment Eliminations [Member] | Refining & Marketing [Member]
Segment Reporting Information [Line Items]
Intersegment									9,294		8,782		8,301
Intersegment Eliminations [Member] | Speedway [Member]
Segment Reporting Information [Line Items]
Intersegment									4		4
Intersegment Eliminations [Member] | Pipeline Transportation [Member]
Segment Reporting Information [Line Items]
Intersegment									$ 458		$ 381		$ 335

[1] Includes $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, of $1.15 billion plus assumed liabilities of $210 million. The total consideration amount of $1.15 billion includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 5 to the audited consolidated financial statements.

[2] Capital expenditures include changes in capital accruals.

[3] Includes $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, of $1.15 billion plus assumed liabilities of $210 million. The 2012 acquisitions exclude the inventory acquired and liability assumed. See Note 5.

[4] Management believes intersegment transactions were conducted under terms comparable to those with unaffiliated parties.

[5] Included in the Pipeline Transportation segment for 2013 and 2012 are $20 million and $4 million of corporate overhead costs attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. These expenses are not currently allocated to other segments.

[6] 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.

[7] Includes Speedway’s acquisition of convenience stores. See Note 5.

[8] The Refining & Marketing and Pipeline Transportation segments include $1.29 billion and $70 million, respectively, for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5.

[9] Includes Speedway's acquisitions of convenience stores. See Note 5 to the audited consolidated financial statements.

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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, 2013		Dec. 31, 2012		Dec. 31, 2011
Interest:
Interest income	$ 9		$ 5		$ 3
Interest expense	(195)	[1]	(191)	[1]	(164)	[1]
Interest capitalized	28	[1]	101	[1]	104	[1]
Total interest	(158)		(85)		(57)
Other:
Net foreign currency gains	0		0		12
Bank service and other fees	(21)		(25)		(16)
Total other	(21)		(25)		(4)
Net interest and other financial income (costs)	$ (179)		$ (110)		$ (61)

[1] See Note 7 for information on related party interest expense and capitalized interest.

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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, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Basic earnings per share:
Net income attributable to MPC	$ 626	$ 168	$ 593	$ 725	$ 755	$ 1,224	$ 814	$ 596	$ 2,112	$ 3,389	$ 2,389
Income allocated to participating securities									4	6	4
Income available to common stockholders - basic									2,108	3,383	2,385
Weighted average shares outstanding (in shares)									315	340	356
Basic earnings per share (in USD per share)	$ 2.09	$ 0.54	$ 1.84	$ 2.19	$ 2.26	$ 3.61	$ 2.39	$ 1.71	$ 6.69	$ 9.95	$ 6.70
Diluted earnings per share:
Net income attributable to MPC	626	168	593	725	755	1,224	814	596	2,112	3,389	2,389
Income allocated to participating securities									4	6	4
Income available to common stockholders - diluted									$ 2,108	$ 3,383	$ 2,385
Weighted average shares outstanding (in shares)									315	340	356
Effect of dilutive securities (in shares)									2	2	1
Weighted average common shares, including dilutive effect (in shares)									317	342	357
Diluted earnings per share (in USD per share)	$ 2.07	$ 0.54	$ 1.83	$ 2.17	$ 2.24	$ 3.59	$ 2.38	$ 1.70	$ 6.64	$ 9.89	$ 6.67

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Related Party Transactions (Sales To Related Parties) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Sales to related parties	$ 8	$ 8	$ 55
Marathon Oil Companies [Member]
Related Party Transaction [Line Items]
Sales to related parties	0	0	13
Centennial [Member]
Related Party Transaction [Line Items]
Sales to related parties	0	1	35
Other Equity Method Investees [Member]
Related Party Transaction [Line Items]
Sales to related parties	$ 8	$ 7	$ 7

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Fair Value Measurements

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Fair Value Measurements

Fair Value Measurements

Fair Values – Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2013 and 2012 by fair value hierarchy level. We have elected to offset the fair value amounts recognized for multiple derivative contracts executed with the same counterparty, including any related cash collateral as shown below; however, fair value amounts by hierarchy level are presented on a gross basis in the following tables.

	December 31, 2013
	Fair Value Hierarchy
(In millions)	Level 1		Level 2		Level 3		Netting and Collateral(a)			Net Carrying Value on Balance Sheet(b)		Collateral Pledged Not Offset
Commodity derivative instruments, assets	$	21	$	—	$	—	$	(21	)	$	—	$	61
Other assets	2		—		—		N/A			2		—
Total assets at fair value	$	23	$	—	$	—	$	(21	)	$	2	$	61
Commodity derivative instruments, liabilities	$	53	$	—	$	—	$	(53	)	$	—	$	—
Contingent consideration, liability(c)	—		—		625		N/A			625		—
Total liabilities at fair value	$	53	$	—	$	625	$	(53	)	$	625	$	—

	December 31, 2012
	Fair Value Hierarchy
(In millions)	Level 1		Level 2		Level 3		Netting and Collateral(a)			Net Carrying Value on Balance Sheet(b)		Collateral Pledged Not Offset
Commodity derivative instruments, assets	$	49	$	—	$	—	$	(49	)	$	—	$	45
Other assets	2		—		—		N/A			2		—
Total assets at fair value	$	51	$	—	$	—	$	(49	)	$	2	$	45
Commodity derivative instruments, liabilities	$	88	$	—	$	—	$	(88	)	$	—	$	—

^(a) Represents the impact of netting assets, liabilities and cash collateral when a legal right of offset exists. As of December 31, 2013 and 2012, cash collateral of $32 million and $39 million, respectively, was netted with mark-to-market derivative liabilities.

^(b) We have no derivative contracts that are subject to master netting arrangements that are reflected gross on the balance sheet.

^(c) Includes $159 million classified as current.

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. Commodity derivatives are covered under master netting agreements with an unconditional right to offset. 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.

The contingent consideration represents the fair value as of December 31, 2013 of the amount we expect to pay to BP related to the earnout provision for the Galveston Bay Refinery and Related Assets acquisition. See Note 5. The fair value of the contingent consideration was estimated using an income approach and is therefore a Level 3 liability. The amount of cash to be paid under the arrangement is based on both a market-based crack spread and refinery throughput volumes for the months during which the contract applies, as well as established thresholds that cap the annual and total payment. The earnout payment cannot exceed $200 million per year for the first three years of the arrangement or $250 million per year for the last three years of the arrangement, with the total cumulative payment capped at $700 million over the six-year period. Any excess or shortfall from the annual cap for a current year’s earnout calculation will not affect subsequent years’ calculations. The fair value calculation used significant unobservable inputs including: (1) an estimate of refinery throughput volumes; (2) a range of internal and external crack spread forecasts from $13 to $18 per barrel; and (3) a range of risk-adjusted discount rates from 5 percent to 10 percent. An increase or decrease in crack spread forecasts or refinery throughput volume expectations will result in a corresponding increase or decrease in the fair value. Increases to the fair value as a result of increasing forecasts for both of these unobservable inputs, however, are limited as the earnout payment is subject to annual thresholds. An increase or decrease in the discount rate will result in a decrease or increase to the fair value, respectively. The fair value of the contingent consideration is reassessed each quarter, with changes in fair value recorded in cost of revenues.

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

(In millions)	2013			2012			2011
Beginning balance	$	—		$	—		$	2,402
Contingent consideration agreement	(600		)	—			—
Total realized and unrealized losses included in net income	(25		)	(2		)	—
Purchases of PFD Preferred Stock(a)	—			—			10,326
Redemptions of PFD Preferred Stock(a)	—			—			(12,730		)
Settlements of derivative instruments	—			2			2
Ending balance	$	(625	)	$	—		$	—

^(a)  For information on PFD Preferred Stock, see Note 7. 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.

We did not hold any Level 3 derivative instruments during 2013 and 2012. Net income for 2011 included unrealized losses of less than $1 million related to Level 3 derivative instruments held during 2011. See Note 18 for the income statement impacts of our derivative instruments. There was an unrealized loss of $25 million in 2013 related to the contingent consideration agreement.

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,
	2013				2012				2011
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Property, plant and equipment, net	$	1	$	8	$	—	$	—	$	—	$	—
Other noncurrent assets	—		—		—		14		—		—

Due to changing market conditions, we assessed one of our light products terminals for impairment. The terminal is operated by our Refining & Marketing segment. We recorded an impairment charge of $8 million for this terminal in 2013. The impairment is included in depreciation and amortization on the consolidated statements of income. The fair value of the terminal was measured using a market approach based on comparable area property values which are Level 3 inputs.

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.

Fair Values – Reported

The following table summarizes financial instruments on the basis of their nature, characteristics and risk at December 31, 2013 and 2012, excluding the derivative financial instruments and contingent consideration reported above.

	December 31,
	2013				2012
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial assets:
Investments	$	336	$	14	$	263	$	59
Other	31		30		33		31
Total financial assets	$	367	$	44	$	296	$	90
Financial liabilities:
Long-term debt(a)	$	3,306	$	3,001	$	3,559	$	3,006
Deferred credits and other liabilities	21		21		23		23
Total financial liabilities	$	3,327	$	3,022	$	3,582	$	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, (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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Subsequent Event (Details) (Felda Iffco Sdn Bhd [Member], Subsequent Event [Member])	12 Months Ended
	Dec. 31, 2013	Feb. 03, 2014 BPD
Felda Iffco Sdn Bhd [Member] | Subsequent Event [Member]
Subsequent Event [Line Items]
Plant capacity (in barrels per day)		4,100
Transaction expected close date	April 2014

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Derivatives (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

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, 2013 and 2012:

	December 31, 2013
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	21	$	53	Other current assets

	December 31, 2012
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	49	$	88	Other current assets

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	2013		2012			2011
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 for crude oil and refined products as of December 31, 2013.

	Position	Total Barrels (In thousands)
Crude oil(a)
Exchange-traded	Long	10,580
Exchange-traded	Short	(23,900)
Refined Products(a)
Exchange-traded	Long	3,646
Exchange-traded	Short	(4,175)

^(a)100 percent of these contracts expire in the first quarter of 201

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	2013			2012		2011
Sales and other operating revenues	$	12		$	8	$	(34	)
Other income	—			—		1
Cost of revenues	(180		)	65		182
Total	$	(168	)	$	73	$	149

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Income From Operations Attributable To Operating Segments

(In millions)	Refining & Marketing			Speedway			Pipeline Transportation			Total
Year Ended December 31, 2013
Revenues:
Customer	$	85,608		$	14,471		$	79		$	100,158
Intersegment(a)	9,294			4			458			9,756
Related parties	8			—			—			8
Segment revenues	94,910			14,475			537			109,922
Elimination of intersegment revenues	(9,294		)	(4		)	(458		)	(9,756		)
Total revenues	$	85,616		$	14,471		$	79		$	100,166
Segment income from operations(b)	$	3,206		$	375		$	210		$	3,791
Income from equity method investments	28			—			8			36
Depreciation and amortization(c)	1,011			112			74			1,197
Capital expenditures and investments(d)(e)(f)	2,094			296			234			2,624

(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)(e)	900			164		121			1,185

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

^(b)  Included in the Pipeline Transportation segment for 2013 and 2012 are $20 millionand $4 million of corporate overhead costs attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 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 convenience stores. See Note 5.

^(f)  The Refining & Marketing and Pipeline Transportation segments include $1.29 billion and $70 million, respectively, for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5.

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)	2013			2012			2011
Segment income from operations	$	3,791		$	5,624		$	4,061
Items not allocated to segments:
Corporate and other unallocated items(a)(b)	(271		)	(336		)	(316		)
Minnesota Assets sale settlement gain(c)	—			183			—
Pension settlement expenses(d)	(95		)	(124		)	—
Net interest and other financial income (costs)(e)	(179		)	(109		)	(26		)
Income before income taxes	$	3,246		$	5,238		$	3,719

^(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 attributable to MPLX were included in the Pipeline Transportation segment subsequent to MPLX’s October 31, 2012 initial public offering.

^(c)  See Note 6.

^(d)  See Note 22.

^(e)  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)	2013		2012		2011
Segment capital expenditures and investments	$	2,624	$	1,256	$	1,185
Less: Investments in equity method investees	124		28		11
Plus: Items not allocated to segments:
Capital expenditures not allocated to segments	137		103		24
Capitalized interest	28		101		114
Total capital expenditures(a)(b)	$	2,665	$	1,432	$	1,312

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

^(b)  See Note 20 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)	2013			2012			2011
Total revenues (as reported above)	$	100,166		$	82,245		$	78,638
Plus: Corporate and other unallocated items	(6		)	(2		)	—
Less: Sales to related parties	8			8			55
Sales and other operating revenues (including consumer excise taxes)	$	100,152		$	82,235		$	78,583

Schedule Of Revenues By Product Line

Revenues by product line were:

(In millions)	2013		2012		2011
Refined products	$	93,520	$	76,234	$	73,334
Merchandise	3,308		3,229		3,090
Crude oil and refinery feedstocks	2,988		2,514		1,972
Transportation and other	344		266		242
Total revenues	100,160		82,243		78,638
Less: Sales to related parties	8		8		55
Sales and other operating revenues (including consumer excise taxes)	$	100,152	$	82,235	$	78,583

Total Assets by Reportable Segment

Total assets by reportable segment were:

	December 31,
(In millions)	2013		2012
Refining & Marketing	$	19,573	$	17,052
Speedway	2,064		1,947
Pipeline Transportation	1,947		1,950
Corporate and Other	4,801		6,274
Total consolidated assets	$	28,385	$	27,223

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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, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Interest expense
Interest capitalized			(8)
Related party net interest and other financial income	0	1	35
PFD [Member]
Related Party Transaction [Line Items]
Dividend income, PFD Preferred Stock			35
Interest expense			3
Marathon Oil Companies [Member]
Related Party Transaction [Line Items]
Interest expense			$ 5

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Equity Method Investments (Schedule Of Equity Method Investments) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2013 Centennial [Member]	Dec. 31, 2012 Centennial [Member]	Dec. 31, 2013 LOCAP LLC [Member]	Dec. 31, 2012 LOCAP LLC [Member]	Dec. 31, 2013 LOOP [Member]	Dec. 31, 2012 LOOP [Member]	Dec. 31, 2013 North Dakota Pipeline Class B Units [Member]		Dec. 31, 2012 North Dakota Pipeline Class B Units [Member]	Dec. 31, 2013 TAAE [Member]	Oct. 02, 2013 TAAE [Member]	Dec. 31, 2012 TAAE [Member]	Dec. 31, 2013 TACE [Member]	Dec. 31, 2012 TACE [Member]	Dec. 31, 2013 TAEI [Member]	Dec. 31, 2012 TAEI [Member]	Dec. 31, 2013 TAME [Member]		Dec. 31, 2012 TAME [Member]	Dec. 31, 2013 TAME [Member] Direct Ownership Interest [Member]		Dec. 31, 2013 Other Equity Method Investees [Member]	Dec. 31, 2012 Other Equity Method Investees [Member]	Jan. 02, 2016 North Dakota Pipeline Class A Units [Member] Scenario, Forecast [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments, Ownership Percentage			50.00%		59.00%		51.00%		38.00%	[1]		43.00%	43.00%		60.00%		34.00%		67.00%			50.00%	[2]			27.00%
Equity method investments	$ 463	$ 321	$ 29	$ 27	$ 24	$ 26	$ 214	$ 198	$ 24	[1]	$ 0	$ 29		$ 0	$ 70	$ 29	$ 23	$ 0	$ 35	[2]	$ 27			$ 15	$ 14

[1] We own a 38 percent interest in the Class B units of this entity. Our Class B units will be converted to an approximate 27 percent ownership interest in the Class A units of this entity upon completion of the Sandpiper pipeline construction project in 2016.

[2] Excludes TAEI's investment in TAME.

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Summary Of Principal Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Principles Applied In Consolidation

Principles applied in consolidation – These consolidated financial statements include the accounts of our majority-owned, controlled subsidiaries. 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 generally 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 and liabilities, 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 our 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. Rebates to customers are reflected as a reduction of revenue and are accrued for in accounts payable on the consolidated balance sheets.

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 and investments in highly liquid debt instruments with maturities of three months or less.

Restricted Cash

Restricted cash - Restricted cash consists of cash advances to be used for the operation and maintenance of an operated pipeline system. At December 31, 2013, the amount of restricted cash included in other current assets on the consolidated balance sheets was $7 million.

Accounts Receivable And Allowance For Doubtful Accounts

Accounts receivable and allowance for doubtful accounts – Our receivables primarily consist of customer accounts receivable. The allowance for doubtful accounts is the best estimate of the amount of probable credit losses in customer accounts receivable and is based on historical write-off experience. 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 38 percent and 42 percent of our accounts receivable balances at December 31, 2013 and 2012, 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 100 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, historically, to 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 – 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.

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.

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 33 percent of our common stock volatility and 67 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. The fair value of performance unit awards granted to our employees is estimated on the date of grant using a Monte Carlo valuation model.

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.

Renewable fuel identification numbers (RINs)

Renewable fuel identification numbers ("RINs") - We purchase RINs to satisfy a portion of our Renewable Fuel Standard ("RFS2") compliance. We record a short-term intangible asset, included in other current assets on the balance sheet, for RINs owned in excess of our anticipated current period compliance requirements. The asset value is based on the product of the excess RINs as of the balance sheet date, if any, and the average cost of our RINs. We record a current liability, included in other current liabilities on the balance sheet, when we are deficient RINs based on the product of the deficient RINs as of the balance sheet date, if any, and the market price of the RINs at the balance sheet date. The cost of RINs used for compliance is reflected in cost of revenues.Any gains or losses on the sale or expiration of RINs are classified as other income.

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Summary Of Supplemental Cash Flow Information

(In millions)	2013		2012		2011
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	161	$	67	$	5
Net income taxes paid to taxing authorities(a)	1,099		1,211		617
Non-cash investing and financing activities:
Capital lease obligations increase	$	61	$	62	$	26
Property, plant and equipment contributed by Marathon Oil	—		—		81
Property, plant and equipment sold	43		—		—
Preferred equity interest received in contract settlement(b)	—		45		—
Preferred equity interest dividend received in-kind	—		1		—
Acquisitions:
Contingent consideration(c)	600		—		—
Payable to seller(c)	6		—		—
Intangible asset acquired	—		3		—
Liability assumed	—		2		—

^(a)  U.S. 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 tax credits. See Note 25.

^(b)  See Note 6.

^(c)  See Note 5.

Schedule of Reconciliation of Additions to Property Plant and Equipment [Table Text Block]

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)	2013		2012			2011
Additions to property, plant and equipment	$	1,206	$	1,369		$	1,185
Acquisitions(a)	1,386		180			74
Increase (decrease) in capital accruals	73		(117		)	53
Total capital expenditures	$	2,665	$	1,432		$	1,312

^(a)  Includes $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, of $1.15 billion plus assumed liabilities of $210 million. The 2012 acquisitions exclude the inventory acquired and liability assumed. See Note 5.

Reconciliation Of Contributions From (Distributions To) Marathon Oil

The following is a reconciliation of distributions to Marathon Oil:

(In millions)	2011
Distributions to Marathon Oil per consolidated statements of cash flows	$	(783	)
Non-cash contributions from Marathon Oil(a)	57
Distributions to Marathon Oil per consolidated statements of equity / net investment	$	(726	)

^(a)  See Note 7.

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Acquisitions and Investments (Investments in Ethanol Companies) (Details) (USD $) In Millions, unless otherwise specified							1 Months Ended
	Dec. 31, 2013 TACE [Member]	Dec. 31, 2013 Andersons Ethanol Investment Llc [Member]	Dec. 31, 2013 TAME [Member]	Dec. 31, 2013 TAME [Member] The Andersons Ethanol Investment Llc [Member]	Dec. 31, 2013 TAAE [Member]	Oct. 02, 2013 TAAE [Member]	Aug. 01, 2013 Ethanol Interests From Mitsui [Member] Companies	Aug. 01, 2013 Ethanol Interests From Mitsui [Member] TACE [Member]	Aug. 01, 2013 Ethanol Interests From Mitsui [Member] Andersons Ethanol Investment Llc [Member]	Aug. 01, 2013 Ethanol Interests From Mitsui [Member] TAAE [Member]
Business Acquisition [Line Items]
Number Of Businesses In Which Ownership Interests Acquired							3
Cash paid to acquire equity method investments							$ 75
Percentage acquired								24.00%	34.00%	40.00%
Equity method investments, Ownership Percentage	60.00%	34.00%	67.00%	50.00%	43.00%	43.00%

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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, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative [Member] | Interest Rate Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$ 0	$ 1	$ 19
Hedged Item [Member] | Long-term Debt [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (loss)	$ 0	$ (1)	$ (19)

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MPLX LP (Narrative) (Detail) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended			0 Months Ended	8 Months Ended	0 Months Ended	12 Months Ended											8 Months Ended		6 Months Ended	0 Months Ended		1 Months Ended	12 Months Ended	0 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	May 01, 2013 MPLX Pipe Line Holdings LP [Member]	Dec. 31, 2013 MPLX Pipe Line Holdings LP [Member]	Mar. 01, 2014 MPLX Pipe Line Holdings LP [Member] Subsequent Event [Member]	Dec. 31, 2013 MPLX LP [Member] Commercial Agreements [Member]	Dec. 31, 2013 MPLX LP [Member] Commercial Agreements [Member] Minimum [Member]	Dec. 31, 2013 MPLX LP [Member] Commercial Agreements [Member] Maximum [Member]	Dec. 31, 2013 MPLX LP [Member] Operating Agreements [Member] Minimum [Member]	Dec. 31, 2013 MPLX LP [Member] Operating Agreements [Member] Maximum [Member]	Dec. 31, 2013 MPLX LP [Member] Management Services Agreements [Member] Agreement	Dec. 31, 2013 MPLX LP [Member] Employee Services Agreements [Member] Agreement	Dec. 31, 2013 MPLX LP [Member] Pipeline Transportation [Member] Commercial Agreements [Member] Agreement	Dec. 31, 2013 MPLX LP [Member] Storage Services [Member] Commercial Agreements [Member] Agreement	Dec. 31, 2013 MPLX LP [Member]	Oct. 31, 2012 MPLX LP [Member] Storage Services Butane Cavern [Member]	Dec. 31, 2013 MPLX LP [Member] MPLX Pipe Line Holdings LP [Member]	Dec. 31, 2013 MPLX LP [Member] General Partner [Member]	Apr. 30, 2013 MPLX LP [Member] General Partner [Member] MPLX Pipe Line Holdings LP [Member]	Mar. 01, 2014 MPLX LP [Member] General Partner [Member] MPLX Pipe Line Holdings LP [Member] Subsequent Event [Member]	Dec. 31, 2013 MPLX LP [Member] General Partner and Limited Partner [Member]	Oct. 31, 2012 MPLX LP [Member] IPO [Member]	Dec. 31, 2013 MPLX LP [Member] IPO [Member]	Mar. 01, 2014 Cash and Cash Equivalents [Member] MPLX LP [Member] Subsequent Event [Member]	Mar. 01, 2014 MPLX Revolver [Member] MPLX LP [Member] Subsequent Event [Member]
Noncontrolling Interest [Line Items]
Initial public offering date of MPLX LP																								October 2012
Initial public offering of common units (in number of common units)																							19,895,000
Net proceeds from issuance of MPLX LP common units	$ 0	$ 407	$ 0																				$ 407
MPC's partnership interest in MPLX (in percentage)																73.60%			2.00%			73.60%
Percentage of noncontrolling interest (in percentage)																26.40%
Ownership interest (in percentage)					44.00%													56.00%		51.00%
MPLX's partnership percent indirect interest in assets																	100.00%
Additional interest sold				5.00%		13.00%
Proceeds From Sale Of Ownership Interest In Assets By Company In Affiliate				100		310
Expected ownership interest						31.00%															69.00%
Cash paid for acquisition	1,515	190	74																						40	270
Number of Agreements												2	2	9	5
Duration of Agreements (in years)								3 years	10 years	1 year	5 years
Number of Quarters Following Deficiency Payment Over Which Deficiency Credit May Be Applied							4		8
Volume deficiency credits							$ 34

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Summary Of Property, Plant And Equipment

(In millions)	Estimated Useful Lives	December 31,
		2013		2012
Refining & Marketing	4 - 25 years	$	16,982	$	15,089
Speedway	4 - 15 years	2,344		2,100
Pipeline Transportation	16 - 42 years	1,921		1,747
Corporate and Other	4 - 40 years	546		473
Total		21,793		19,409
Less accumulated depreciation		7,872		6,766
Property, plant and equipment, net		$	13,921	$	12,643

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Description Of The Business, Spinoff And Basis Of Presentation

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Description Of The Business, Spinoff And Basis Of Presentation

Description of the Business, Spinoff and Basis of Presentation

Description of the Business – As used in this report, the terms "MPC," "we," "us," "the Company" or "our" may refer to Marathon Petroleum Corporation, one or more of its consolidated subsidiaries or all of them taken as a whole.

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”).

See Note 10 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 statement of income for the period 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 period 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 period 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 7.

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Leases (Schedule Of Operating Lease Rental Expense) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Leases [Abstract]
Minimum rental	$ 213	$ 139	$ 123
Contingent rental	0	0	1
Rental expense	$ 213	$ 139	$ 124

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Debt (Narrative) (Detail) (USD $)		12 Months Ended					12 Months Ended					12 Months Ended
	Dec. 31, 2013 Trade Receivables Securitization [Member]	Dec. 31, 2013 MPC Revolver [Member] Revolving Credit Facility [Member] Period	Dec. 31, 2013 MPC Revolver [Member] Maximum [Member] Bridge Loan [Member]	Dec. 31, 2013 MPC Revolver [Member] Maximum [Member] Revolving Credit Facility [Member]	Dec. 31, 2013 MPC Revolver [Member] Maximum [Member] Letter of Credit [Member]	Dec. 31, 2013 MPC Revolver [Member] Minimum [Member] Revolving Credit Facility [Member]	Dec. 31, 2013 MPLX Revolver [Member] MPLX Operations LLC [Member] Revolving Credit Facility [Member] Period	Dec. 31, 2013 MPLX Revolver [Member] Maximum [Member] MPLX Operations LLC [Member] Bridge Loan [Member]	Dec. 31, 2013 MPLX Revolver [Member] Maximum [Member] MPLX Operations LLC [Member] Revolving Credit Facility [Member] Period	Dec. 31, 2013 MPLX Revolver [Member] Maximum [Member] MPLX Operations LLC [Member] Letter of Credit [Member]	Dec. 31, 2013 MPLX Revolver [Member] Minimum [Member] MPLX Operations LLC [Member] Revolving Credit Facility [Member]	Dec. 31, 2013 Trade Receivables Securitization [Member]	Dec. 18, 2013 Trade Receivables Securitization [Member]	Dec. 18, 2013 Trade Receivables Securitization [Member] Letter of Credit [Member]	Dec. 18, 2013 Trade Receivables Securitization [Member] Secured Debt [Member]	Dec. 31, 2013 Trade Receivables Securitization [Member] Consolidated Subsidiaries [Member]	Dec. 31, 2012 Trade Receivables Securitization [Member] Consolidated Subsidiaries [Member]
Line of Credit Facility [Line Items]
Trade receivables securitization facility due 2016	$ 0															$ 0	$ 0
Line of Credit Facility, Current Borrowing Capacity			100,000,000	2,500,000,000	2,000,000,000			50,000,000	500,000,000	250,000,000
Line of Credit Facility, Maximum Borrowing Capacity													1,300,000,000	1,250,000,000	1,300,000,000
Line Of Credit Facility Additional Borrowing Capacity				$ 500,000,000					$ 300,000,000
Number Of Renewal Periods		2					2
Line Of Credit Facility Duration Of Renewal Period		1 year					1 year
Lender Holding Percentage Of Outstanding Commitments Needed To Approve Increase In Borrowing Capacity						50.00%					50.00%
Ratio of Indebtedness to Net Capital				0.65
Number Of Prior Quarterly Reporting Periods Covenant									4
Covenant Ratio Debt To Ebitda									5.0
Covenant Ratio Debt To Ebitda Post Acquisition									5.5
Line of Credit Facility, Expiration Date												3 years

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Acquisitions and Investments (Acquisition of Refinery and Related Logistics and Marketing Assets) (Detail) (USD $)	12 Months Ended			1 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Feb. 01, 2013 Galveston Bay Refinery And Related Assets [Member] site Terminal Pipeline BPCD MW BPD	Dec. 31, 2013 Galveston Bay Refinery And Related Assets [Member]	Dec. 31, 2013 Galveston Bay Refinery And Related Assets [Member] Prepaid Licensed Refinery Technology Agreements [Member]	Dec. 31, 2013 Galveston Bay Refinery And Related Assets [Member] Customer Relationships [Member]
Business Acquisition [Line Items]
Refinery capacity (in barrels per calendar day)				451,000
Intrastate natural gas liquid pipelines (in number of pipelines)				3
Number of light product terminals (in number of terminals)				4
Number of branded sites (in number of sites)				1,200
Electric cogeneration capacity, megawatts				1,040
Allocation of space on Colonial Pipeline (in barrels per day)				50,000
Cash paid for acquisition	$ 1,515,000,000	$ 190,000,000	$ 74,000,000		$ 1,491,000,000
Inventories					935,000,000
Maximum earnout provision payable to the company					700,000,000
Term of payment of maximum earnout provision payable to the company, years				6 years
Maximum earnout payment, year one					200,000,000
Maximum earnout payment, year two					200,000,000
Maximum earnout payment, year three					200,000,000
Maximum earnout payment, year four					250,000,000
Maximum earnout payment, year five					250,000,000
Maximum earnout payment, year six					250,000,000
Contingent liability				600,000,000	625,000,000
Contingent liability, current					159,000,000
Post-closing adjustment					9,000,000
Finite-lived intangibles						68,000,000	20,000,000
Intangible asset, useful life						15 years	4 years
Weighted average useful life					13 years
Acquisition related costs					$ 7,000,000

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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, 2013	Dec. 31, 2012	Dec. 31, 2011
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	$ 1,800	$ 1,478
Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	189	107
Equity Investments, Common Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	69
Equity Funds, Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	217
Exchange-Traded Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value		166
Investment Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value		111
Equity Funds, Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	590	709
Fixed Income, Corporate [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	356
Fixed Income, Government [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	22
Fixed Income, Pooled Funds [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	218	258
Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	57	56
Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	60	54
Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	22	17
Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	288	290
Level 1 [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0	107
Level 1 [Member] | Equity Investments, Common Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	69
Level 1 [Member] | Equity Funds, Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	217
Level 1 [Member] | Exchange-Traded Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value		166
Level 1 [Member] | Investment Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value		17
Level 1 [Member] | Equity Funds, Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0	0
Level 1 [Member] | Fixed Income, Corporate [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0
Level 1 [Member] | Fixed Income, Government [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0
Level 1 [Member] | Fixed Income, Pooled Funds [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0	0
Level 1 [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0	0
Level 1 [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0	0
Level 1 [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	2	0
Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	1,375	1,061
Level 2 [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	189	0
Level 2 [Member] | Equity Investments, Common Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0
Level 2 [Member] | Equity Funds, Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0
Level 2 [Member] | Exchange-Traded Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value		0
Level 2 [Member] | Investment Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value		94
Level 2 [Member] | Equity Funds, Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	590	709
Level 2 [Member] | Fixed Income, Corporate [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	356
Level 2 [Member] | Fixed Income, Government [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	22
Level 2 [Member] | Fixed Income, Pooled Funds [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	218	258
Level 2 [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0	0
Level 2 [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0	0
Level 2 [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0	0
Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	137	127	121
Level 3 [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0	0
Level 3 [Member] | Equity Investments, Common Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0
Level 3 [Member] | Equity Funds, Mutual Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0
Level 3 [Member] | Exchange-Traded Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value		0
Level 3 [Member] | Investment Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value		0
Level 3 [Member] | Equity Funds, Pooled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0	0
Level 3 [Member] | Fixed Income, Corporate [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0
Level 3 [Member] | Fixed Income, Government [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0
Level 3 [Member] | Fixed Income, Pooled Funds [Member] [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	0	0
Level 3 [Member] | Private Equity [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	57	56	55
Level 3 [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	60	54	49
Level 3 [Member] | Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Plan Asset Investments, at fair value	$ 20	$ 17	$ 17

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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	6 Months Ended	12 Months Ended		6 Months Ended		12 Months Ended		6 Months Ended
	Dec. 31, 2011 Restricted Stock [Member]	Dec. 31, 2013 Restricted Stock [Member]	Dec. 31, 2012 Restricted Stock [Member]	Jun. 30, 2011 Restricted Stock [Member] Predecessor [Member]	Dec. 31, 2011 Restricted Stock Units [Member]	Dec. 31, 2013 Restricted Stock Units [Member]	Dec. 31, 2012 Restricted Stock Units [Member]	Jun. 30, 2011 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	$ 1	$ 20	$ 5	$ 3	$ 0	$ 0	$ 0	$ 0
Weighted Average Grant Date Fair Value of Awards Granted During the Period (in USD per share)	$ 41.54	$ 87.06	$ 43.11	$ 48.53	$ 33.78	$ 73.48	$ 44.38	$ 45.22

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Other Items (Tables)

12 Months Ended

Dec. 31, 2013

Other Income and Expenses [Abstract]

Net Interest And Other Financial Income (Costs)

Net interest and other financial income (costs) was:

(In millions)	2013			2012			2011
Interest:
Interest income	$	9		$	5		$	3
Interest expense(a)	(195		)	(191		)	(164		)
Interest capitalized(a)	28			101			104
Total net interest	(158		)	(85		)	(57		)
Other:
Net foreign currency gains	—			—			12
Bank service and other fees	(21		)	(25		)	(16		)
Total other	(21		)	(25		)	(4		)
Net interest and other financial income (costs)	$	(179	)	$	(110	)	$	(61	)

^(a)  See Note 7 for information on related party interest expense and capitalized interest.

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Accumulated Other Comprehensive Loss

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss

The following table shows the changes in accumulated other comprehensive loss by component. Amounts in parentheses indicate debits.

(In millions)	Pension Benefits			Other Benefits			Gain on Cash Flow Hedge		Workers Compensation			Total
Balance as of December 31, 2012	$	(432	)	$	(36	)	$	4	$	—		$	(464	)
Other comprehensive income (loss) before reclassifications	198			(13		)	—		4			189
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit(a)	(45		)	(4		)	—		—			(49		)
– actuarial loss(a)	66			3			—		—			69
– settlement loss(a)	95			—			—		—			95
Other(b)	—			—			—		(1		)	(1		)
Tax expense	(43		)	—			—		—			(43		)
Other comprehensive income (loss)	271			(14		)	—		3			260
Balance as of December 31, 2013	$	(161	)	$	(50	)	$	4	$	3		$	(204	)

^(a) These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 22.

^(b)  This amount was reclassified out of accumulated other comprehensive loss and is included in selling, general and administrative expenses on the consolidated statements of income.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Supplemental Cash Flow Information

Supplemental Cash Flow Information

(In millions)	2013		2012		2011
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	161	$	67	$	5
Net income taxes paid to taxing authorities(a)	1,099		1,211		617
Non-cash investing and financing activities:
Capital lease obligations increase	$	61	$	62	$	26
Property, plant and equipment contributed by Marathon Oil	—		—		81
Property, plant and equipment sold	43		—		—
Preferred equity interest received in contract settlement(b)	—		45		—
Preferred equity interest dividend received in-kind	—		1		—
Acquisitions:
Contingent consideration(c)	600		—		—
Payable to seller(c)	6		—		—
Intangible asset acquired	—		3		—
Liability assumed	—		2		—

^(a)  U.S. 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 tax credits. See Note 25.

^(b)  See Note 6.

^(c)  See Note 5.

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)	2013		2012			2011
Additions to property, plant and equipment	$	1,206	$	1,369		$	1,185
Acquisitions(a)	1,386		180			74
Increase (decrease) in capital accruals	73		(117		)	53
Total capital expenditures	$	2,665	$	1,432		$	1,312

^(a)  Includes $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, of $1.15 billion plus assumed liabilities of $210 million. The 2012 acquisitions exclude the inventory acquired and liability assumed. See Note 5.

The following is a reconciliation of distributions to Marathon Oil:

(In millions)	2011
Distributions to Marathon Oil per consolidated statements of cash flows	$	(783	)
Non-cash contributions from Marathon Oil(a)	57
Distributions to Marathon Oil per consolidated statements of equity / net investment	$	(726	)

^(a)  See Note 7.

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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, 2013	Dec. 31, 2012	Dec. 31, 2013 Minimum [Member]	Dec. 31, 2013 Maximum [Member]	Dec. 31, 2013 Corporate, Non-Segment [Member]	Dec. 31, 2012 Corporate, Non-Segment [Member]	Dec. 31, 2013 Corporate, Non-Segment [Member] Minimum [Member]	Dec. 31, 2013 Corporate, Non-Segment [Member] Maximum [Member]	Dec. 31, 2013 Refining & Marketing [Member] Operating Segments [Member]	Dec. 31, 2012 Refining & Marketing [Member] Operating Segments [Member]	Dec. 31, 2013 Refining & Marketing [Member] Operating Segments [Member] Minimum [Member]	Dec. 31, 2013 Refining & Marketing [Member] Operating Segments [Member] Maximum [Member]	Dec. 31, 2013 Speedway [Member] Operating Segments [Member]	Dec. 31, 2012 Speedway [Member] Operating Segments [Member]	Dec. 31, 2013 Speedway [Member] Operating Segments [Member] Minimum [Member]	Dec. 31, 2013 Speedway [Member] Operating Segments [Member] Maximum [Member]	Dec. 31, 2013 Pipeline Transportation [Member] Operating Segments [Member]	Dec. 31, 2012 Pipeline Transportation [Member] Operating Segments [Member]	Dec. 31, 2013 Pipeline Transportation [Member] Operating Segments [Member] Minimum [Member]	Dec. 31, 2013 Pipeline Transportation [Member] Operating Segments [Member] Maximum [Member]
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)			4 years	42 years			4 years	40 years			4 years	25 years			4 years	15 years			16 years	42 years
Property, plant and equipment, gross	$ 21,793	$ 19,409			$ 546	$ 473			$ 16,982	$ 15,089			$ 2,344	$ 2,100			$ 1,921	$ 1,747
Less accumulated depreciation	7,872	6,766
Net property, plant and equipment	$ 13,921	$ 12,643

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Leases (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Schedule Of Future Minimum Commitments

Future minimum commitments as of December 31, 2013, 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
2014	$	51		$	191
2015	52			184
2016	51			152
2017	50			106
2018	49			95
Later years	345			241
Total minimum lease payments	598			$	969
Less imputed interest costs	(203		)
Present value of net minimum lease payments	$	395

Schedule Of Operating Lease Rental Expense

Operating lease rental expense was:

(In millions)	2013		2012		2011
Minimum rental	$	213	$	139	$	123
Contingent rental	—		—		1
Rental expense	$	213	$	139	$	124

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Components Of Income Tax Provisions (Benefits)

Income tax provisions (benefits) were:

	2013							2012							2011
(In millions)	Current		Deferred			Total		Current			Deferred		Total		Current		Deferred			Total
Federal	$	954	$	20		$	974	$	1,185		$	432	$	1,617	$	1,040	$	139		$	1,179
State and local	131		8			139		169			57		226		152		(16		)	136
Foreign	5		(5		)	—		(1		)	3		2		15		—			15
Total	$	1,090	$	23		$	1,113	$	1,353		$	492	$	1,845	$	1,207	$	123		$	1,330

Reconciliation Of Federal Statutory Income Tax Rate

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

	2013		2012		2011
Statutory rate applied to income before income taxes	35	%	35	%	35	%
State and local income taxes, net of federal income tax effects	3		2		2
Domestic manufacturing deduction	(2	)	(1	)	(1	)
Other	(2	)	(1	)	—
Provision for income taxes	34	%	35	%	36	%

Components Of Deferred Tax Assets And Liabilities

Deferred tax assets and liabilities resulted from the following:

	December 31,
(In millions)	2013		2012
Deferred tax assets:
Employee benefits	$	483	$	585
Environmental	37		35
Other	49		55
Total deferred tax assets	569		675
Deferred tax liabilities:
Property, plant and equipment	2,290		2,225
Inventories	614		610
Investments in subsidiaries and affiliates	267		307
Other	70		29
Total deferred tax liabilities	3,241		3,171
Net deferred tax liabilities	$	2,672	$	2,496

Components Of Net Deferred Tax Liabilities Classified In Consolidated Balance Sheets

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

	December 31,
(In millions)	2013		2012
Assets:
Other noncurrent assets	$	2	$	—
Liabilities:
Accrued taxes	370		446
Deferred income taxes	2,304		2,050
Net deferred tax liabilities	$	2,672	$	2,496

Summary Of Income Tax Returns Subject To Examination

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

United States Federal	2010	-	2012
States	2004	-	2012

Summary Of Activity In Unrecognized Tax Benefits

The following table summarizes the activity in unrecognized tax benefits:

(In millions)	2013			2012			2011
January 1 balance	$	40		$	20		$	14
Additions for tax positions of prior years	30			32			50
Reductions for tax positions of prior years	(25		)	(6		)	—
Settlements	(30		)	(6		)	(44		)
Statute of limitations	(2		)	—			—
December 31 balance	$	13		$	40		$	20

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Defined Benefit Pension and Other Postretirement Plans

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Defined Benefit Pension and Other Postretirement Plans

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.

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.

Due to the Galveston Bay Refinery and Related Assets acquisition during 2013, we remeasured certain pension and retiree medical plans resulting in a $122 million decrease in liabilities. The decrease in liabilities was due to a 0.2 percent increase in discount rates and an increase in pension plan asset value from December 31, 2012 to the remeasurement date. The net periodic benefit costs for 2013 reflect these remeasurements. The purchase accounting for the Galveston Bay Refinery and Related Assets acquisition includes a $43 million liability related to retiree medical assumed at the acquisition date. See Note 5.

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 were 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.

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 now 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 $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 $1,912 million and $2,035 million as of December 31, 2013 and 2012.

The following summarizes our defined benefit pension plans that have accumulated benefit obligations in excess of plan assets.

	December 31,
(In millions)	2013		2012
Projected benefit obligations	$	1,927	$	2,192
Accumulated benefit obligations	1,912		2,035
Fair value of plan assets	1,800		1,478

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)	2013			2012			2013			2012
Change in benefit obligations:
Benefit obligations at January 1	$	2,192		$	2,685		$	591		$	551
Service cost	93			66			25			20
Interest cost	73			94			26			24
Actuarial (gain) loss	(183		)	117			17			53
Benefits paid	(248		)	(233		)	(20		)	(17		)
Liability gain due to curtailment	—			(17		)	—			—
Other(a)	—			(520		)	48			(40		)
Benefit obligations at December 31	1,927			2,192			687			591
Change in plan assets:
Fair value of plan assets at January 1	1,478			1,423			—			—
Actual return on plan assets	241			157			—			—
Employer contributions	329			131			—			—
Benefits paid from plan assets	(248		)	(233		)	—			—
Fair value of plan assets at December 31	1,800			1,478			—			—
Funded status of plans at December 31	$	(127	)	$	(714	)	$	(687	)	$	(591	)
Amounts recognized in the consolidated balance sheets:
Current liabilities	$	(18	)	$	(18	)	$	(25	)	$	(21	)
Noncurrent liabilities	(109		)	(696		)	(662		)	(570		)
Accrued benefit cost	$	(127	)	$	(714	)	$	(687	)	$	(591	)
Pretax amounts recognized in accumulated other comprehensive loss:(b)
Net loss	$	668		$	1,147		$	107		$	93
Prior service credit	(415		)	(460		)	(30		)	(38		)

^(a)  Includes adjustments related to plan amendments in 2013 and 2012. Also, includes adjustments related to the Galveston Bay Refinery and Related Assets acquisition in 2013.

^(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 2013, 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)	2013			2012			2011			2013			2012			2011
Components of net periodic benefit cost:
Service cost	$	93		$	66		$	65		$	25		$	20		$	19
Interest cost	73			94			110			26			24			27
Expected return on plan assets	(107		)	(104		)	(97		)	—			—			—
Amortization – prior service cost (credit)	(45		)	(18		)	6			(4		)	(2		)	—
– actuarial loss	66			93			71			3			2			—
– net settlement/curtailment loss(a)	95			125			8			—			—			—
Net periodic benefit cost(b)	$	175		$	256		$	163		$	50		$	44		$	46
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial (gain) loss	$	(317	)	$	46		$	427		$	17		$	53		$	39
Prior service cost (credit)(c)	—			(520		)	—			4			(40		)	—
Amortization of actuarial loss	(161		)	(218		)	(79		)	(3		)	(2		)	—
Amortization of prior service cost (credit)	45			18			(6		)	4			2			—
Other(d)	—			—			6			—			—			—
Total recognized in other comprehensive loss	$	(433	)	$	(674	)	$	348		$	22		$	13		$	39
Total recognized in net periodic benefit cost and other comprehensive loss	$	(258	)	$	(418	)	$	511		$	72		$	57		$	85

^(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 6.

^(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 plan amendments approved in 2013 and 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 in 2011.

Lump sum payments to employees retiring in 2013, 2012 and 2011 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 2013, 2012 and 2011 related to our cumulative lump sum payments made during those years.

The estimated net gain/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 2014 are $52 million and $46 million. The 2014 net loss amortization is expected to be lower than the 2013 actual amortization primarily as a result of adjustments made to the net loss balance due to settlement accounting in 2013. 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 2014 is $3 million and $4 million, respectively.

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

	Pension Benefits						Other Benefits
	2013		2012		2011		2013		2012		2011
Weighted-average assumptions used to determine benefit obligation:
Discount rate	4.30	%	3.45	%	4.30	%	4.95	%	4.05	%	4.65	%
Rate of compensation increase	3.70	%	5.00	%	5.00	%	3.70	%	5.00	%	5.00	%
Weighted-average assumptions used to determine net periodic benefit cost:
Discount rate	3.88	%	4.06	%	4.98	%	4.11	%	4.54	%	5.55	%
Expected long-term return on plan assets(a)	7.50	%	7.50	%	8.50	%	—	%	—	%	—	%
Rate of compensation increase	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%	5.00	%

^(a) Effective January 1, 2014, the expected long-term rate of return on plan assets changed from 7.50 percent to 7.00 percent due to a change in our plan investment strategy.

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,
	2013		2012		2011
Health care cost trend rate assumed for the following year:
Medical:
Pre-65	8.00	%	8.00	%	7.50	%
Post-65(a)	N/A		N/A		7.00	%
Prescription drugs	7.00	%	7.00	%	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		N/A		5.00	%
Prescription drugs	5.00	%	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate:
Medical:
Pre-65	2020		2020		2018
Post-65(a)	N/A		N/A		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	$	5	$	(4	)
Effect on other postretirement benefit obligations	39		(34		)

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) diversify plan investments across asset classes to achieve an optimal balance between risk and return and between income and growth of assets through capital appreciation; and (3) source benefit payments primarily through existing plan assets and anticipated future returns.

The investment goals are implemented to manage the plans' funded status volatility and minimize future cash contributions. The asset allocation strategy will change over time in response to changes primarily in funded status, which is dictated by current and anticipated market conditions, the independent actions of our investment committee, required cash flows to and from the plans and other factors deemed appropriate. Such changes in asset allocation are intended to allocate additional assets to the fixed income asset class should the funded status improve. The fixed income asset class shall be invested in such a manner that its interest rate sensitivity correlates highly with that of the plans' liabilities. Other asset classes are intended to provide additional return with associated higher levels of risk. Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies. At December 31, 2013, the plans’ targeted asset allocation was 62 percent equity, private equity, real estate, and timber securities and 38 percent fixed income securities.

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, 2013 and 2012.

Cash and cash equivalents - For 2013, cash and cash equivalents included a collective fund serving as the investment vehicle for the cash reserves and cash held by third-party investment managers. The collective fund was valued at net asset value ("NAV") on a scheduled basis using a cost approach, and was considered a Level 2 asset. Cash and cash equivalents held by third-party investment managers were valued using a cost approach and were considered Level 2. For 2012, cash and cash equivalents included cash on deposit and an investment in a money market mutual fund that invested mainly in short-term instruments and cash, both of which were valued using a market approach and were considered Level 1. The money market mutual fund was valued at the NAV of shares held.

Equity - Equity investments includes common stock, mutual and pooled funds, public and non-public investment trusts and S&P 500 exchange-traded funds. Common stock investments are valued using a market approach, which are priced daily in active markets and are considered Level 1. Mutual and pooled equity funds are well diversified portfolios, representing a mix of strategies in domestic, international and emerging market strategies. Mutual funds are publicly registered, valued at NAV on a daily basis using a market approach and are considered Level 1 assets. Pooled funds are valued at NAV using a market approach and are considered Level 2 assets. Investments in public trusts and S&P 500 exchange-traded funds are valued using a market approach at the closing price reported in an active market and therefore are 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.

Fixed Income - Fixed income investments include corporate bonds, U.S. dollar treasury bonds and municipal bonds. These securities are priced on observable inputs using a combination of market, income and cost approaches. These securities are considered Level 2 assets. Fixed income also includes a well diversified bond portfolio structured as a pooled fund. This fund is valued at NAV on a daily basis using a combination of market, income and cost approaches. It is considered a Level 2 asset.

Private Equity - Private equity investments include interests in limited partnerships which are valued using information provided by external managers for each individual investment held in the fund. These holdings are considered Level 3.

Real Estate - Real estate investments consist of interests in limited partnerships. These holdings are either appraised or valued using investment manager’s assessment of assets held. These holdings are considered Level 3.

Other - Other investments include two limited liability companies (“LLCs”) with no public market. The LLCs were formed to acquire timberland in the northwest United States. These holdings are either appraised or valued using investment manager’s assessment of assets held. These holdings are considered Level 3.

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

	December 31, 2013
(In millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	—	$	189	$	—	$	189
Equity:
Common stocks	69		—		—		69
Mutual funds	217		—		—		217
Pooled funds	—		590		—		590
Fixed income:
Corporate	—		356		—		356
Government	—		22		—		22
Pooled funds	—		218		—		218
Private equity	—		—		57		57
Real estate	—		—		60		60
Other	2		—		20		22
Total investments, at fair value	$	288	$	1,375	$	137	$	1,800

	December 31, 2012
(In millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	107	$	—	$	—	$	107
Equity:
Exchange-traded funds	166		—		—		166
Investment trusts	17		94		—		111
Pooled funds	—		709		—		709
Fixed income:
Pooled funds	—		258		—		258
Private equity	—		—		56		56
Real estate	—		—		54		54
Other	—		—		17		17
Total investments, at fair value	$	290	$	1,061	$	127	$	1,478

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

	2013
(In millions)	Private Equity			Real Estate			Other		Total
Beginning balance	$	56		$	54		$	17	$	127
Actual return on plan assets:
Realized	13			3			—		16
Unrealized	3			10			3		16
Purchases	7			5			—		12
Sales	(22		)	(12		)	—		(34		)
Ending balance	$	57		$	60		$	20	$	137

	2012
(In millions)	Private Equity			Real Estate			Other		Total
Beginning balance	$	55		$	49		$	17	$	121
Actual return on plan assets:
Realized	5			(2		)	—		3
Unrealized	(3		)	2			—		(1		)
Purchases	12			10			—		22
Sales	(13		)	(5		)	—		(18		)
Ending balance	$	56		$	54		$	17	$	127

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. In late 2013, we made pension contributions totaling $161 million. Therefore, we do not anticipate additional contributions will be made in 2014. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are estimated to be approximately $18 million and $26 million in 2014.

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)
2014	$	186	$	26
2015	181		29
2016	177		32
2017	178		34
2018	175		38
2019 through 2023	814		231

^(a)  Effective 2013, as a result of the Patient Protection and Affordable Care Act, 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 $76 million, $60 million and $60 million in 2013, 2012 and 2011.

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 2013, 2012 and 2011 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 2013 and 2012 is for the plan’s year ended December 31, 2012 and December 31, 2011, 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 2013, 2012 and 2011 contributions. Our portion of the contributions does not make up more than 5 percent of total contributions to the plan.

		Pension Protection Act Zone Status		FIP/RP Status Pending/Implemented	MPC Contributions (In millions)						Surcharge Imposed	Expiration Date of Collective - Bargaining Agreement
Pension Fund	EIN	2013	2012		2013		2012		2011
Central States, Southeast and Southwest Areas Pension Plan(a)	36-6044243	Red	Red	Implemented	$	3	$	4	$	3	No	January 31, 2019

^(a)  This agreement has a minimum contribution requirement of $269 per week per employee for 2014. A total of 257 employees participated in the plan as of December 31, 2013.

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, $5 million and $4 million for 2013, 2012 and 2011.

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Stock-Based Compensation Plans

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Stock-Based Compensation Plans

Stock-Based Compensation Plans

Description of the Plans

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 (“MPC 2012 Plan”). The MPC 2012 Plan authorizes the Compensation Committee of our board of directors (“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. 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.

Prior to the 2011 Spinoff, our employees participated in the Marathon Oil Corporation 2007 Incentive Compensation Plan (“2007 Plan”) and the Marathon Oil Corporation 2003 Incentive Compensation Plan (“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 (“MPC 2011 Plan”).

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.

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 2013 fell under the MPC 2012 Plan. Stock options awarded under the MPC 2011 Plan and the MPC 2012 Plan represent the right to purchase shares of our common stock at its fair market value, which is the closing price of MPC's common stock 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 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 after 2011 to officers are subject to an additional one year holding period after the completion of the three-year requisite service period. Prior to vesting, restricted stock recipients who received grants prior to 2012 have the right to vote such stock and receive dividends at the same time regular shareholders are paid. Restricted stock recipients who received grants in 2012 and after have the right to vote such stock; however, dividends are accrued and will be paid upon vesting. Restricted stock units granted to non-employee directors are considered to vest immediately at the time of the grant for accounting purposes, as they are non-forfeitable, but are not issued until the director’s departure from the board of directors. Restricted stock unit recipients do not have the right to vote such shares 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. The target value of all performance units is $1.00, with actual payout up to $2.00 per unit (up to 200% of target). Performance units issued prior to 2012 are paid in cash at the end of the 30-month vesting period at an amount per unit determined based on the total shareholder return ("TSR") of MPC common stock compared to the TSR of selected peer companies’ stock. Performance units issued in 2012 and 2013 under the MPC 2011 and MPC 2012 Plans have a 36-month requisite service period. The payout value of these awards will be determined by the relative ranking of the TSR of MPC common stock compared to the TSR of a select group of peer companies, as well as the Standard & Poor's 500 Energy Index fund over four measurement periods. These awards will be settled 25 percent in MPC common stock and 75 percent in cash. The number of shares actually distributed will be determined by dividing 25 percent of the final payout by the closing price of MPC common stock on the day the Committee certifies the final TSR rankings, or the next trading day if the certification is made outside of normal trading hours. The performance units paying out in cash are accounted for as liability awards and those that settle in shares are accounted for as equity awards. The performance units settling in shares had a grant date fair value of $1.12 per unit for 2013 and $1.09 per unit for 2012, as calculated using a Monte Carlo valuation model.

Total Stock-Based Compensation Expense

Total employee stock-based compensation expense was $42 million, $35 million and $28 million in 2013, 2012 and 2011, while the total related income tax benefits were $15 million, $13 million and $11 million, respectively. In 2013, 2012 and in 2011 for the period subsequent to the Spinoff, cash received by MPC upon exercise of stock option awards was $48 million, $108 million and $1 million, respectively. In 2011 for periods prior to the Spinoff, cash received by Marathon Oil upon exercise of stock option awards by MPC employees was $17 million. In 2013, 2012 and in 2011 for the period subsequent to the Spinoff, tax benefits realized by MPC for deductions for stock awards exercised were $18 million, $16 million and less than $1 million, respectively. In 2011 for periods prior to the Spinoff, tax benefits realized by Marathon Oil for deductions for stock awards exercised by MPC employees were $7 million.

Stock Option Awards

The Black Scholes option-pricing model values used to value stock option awards granted 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):

	2013			2012			2011 subsequent to Spinoff			2011 prior to Spinoff
Weighted average exercise price per share	$	84.65		$	42.02		$	36.18		$	51.93
Expected annual dividends per share	$	1.40		$	1.00		$	0.95		$	1.00
Expected life in years	6.0			5.8			5.8			5.3
Expected volatility	40		%	47		%	48		%	40		%
Risk-free interest rate	1.0		%	1.1		%	1.4		%	2.0		%
Weighted average grant date fair value of stock option awards granted	$	27.13		$	14.45		$	13.08		$	16.73

Expected annual dividends per share is estimated using the most recent dividend payment per share as of the grant date. 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 33 percent of our common stock implied volatility and 67 percent of the historical volatility for a selected group of peer companies. 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 2013:

	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, 2012	6,172,194		$	36.17
Granted	408,603		84.65
Exercised	(1,348,938	)	35.48
Forfeited, canceled or expired	(84,022	)	43.97
Outstanding at December 31, 2013	5,147,837		40.08
Vested and expected to vest at December 31, 2013	5,142,351		40.04		6.0	$	266
Exercisable at December 31, 2013	3,674,485		34.63		5.3	210

^(a)  Includes an immaterial number of stock appreciation rights.

The intrinsic value of options exercised by MPC employees during 2013, 2012 and in 2011 for periods subsequent to the Spinoff was $60 million, $37 million and $1 million, respectively. 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 was $18 million.

As of December 31, 2013, unrecognized compensation cost related to stock option awards was $7 million, which is expected to be recognized over a weighted average period of 0.7 years.

Restricted Stock Awards

The following is a summary of restricted stock award activity of our common stock in 2013:

	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, 2012	638,073		$	40.83	359,111		$	31.07
Granted	256,224		87.06		26,399		73.48
RS's Vested/RSU's Issued	(245,116	)	37.95		(431	)	39.53
Forfeited	(25,059	)	58.60		—		—
Outstanding at December 31, 2013	624,122		61.11		385,079		33.96

Of the 385,079 restricted units outstanding, 383,953 are vested and have a weighted average grant date fair value of $33.89. 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
2013	$	20	$	87.06	$	—	$	73.48
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

As of December 31, 2013, unrecognized compensation cost related to restricted stock awards was $24 million, which is expected to be recognized over a weighted average period of 1.3 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 2013 activity for performance unit awards to be settled in shares:

	Number of Units
Outstanding at December 31, 2012	2,040,000
Granted	1,782,500
Settled	—
Canceled	—
Outstanding at December 31, 2013	3,822,500

The number of shares that would be issued upon target vesting, using the closing price of our common stock on December 31, 2013 would be 41,671 shares.

MPLX Awards

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 phantom units and performance units. Awards granted under the MPLX Plan will be settled with MPLX units. Compensation expense for these awards was not material to our consolidated financial statements for the years ended December 31, 2013 and 2012.

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Consolidated Statements of Stockholders' Equity / Net Investment (USD $) In Millions, unless otherwise specified	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]
Beginning balance at Dec. 31, 2010	$ 8,244	$ 0	$ 0	$ 0	$ 0	$ 8,867	$ (623)	$ 0
Beginning balance (in shares) at Dec. 31, 2010		0	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	2,389				1,058	1,331		0
Dividends declared	(160)				(160)
Distributions to Marathon Oil Corporation	(737)					(726)	(11)
Other comprehensive loss	(245)						(245)
Shares issued (returned) - stock based compensation	9			9
Stock-based compensation	5			5				0
Reclassification of net investment to additional paid-in capital	0			9,472		(9,472)
Issuance of common stock at spinoff	0	4		(4)
Shares issued - stock-based compensation (in shares)		1
Issuance of common stock at spinoff (in shares)		356
Ending balance at Dec. 31, 2011	9,505	4	0	9,482	898	0	(879)	0
Ending balance (in shares) at Dec. 31, 2011		357	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	3,393				3,389			4
Dividends declared	(407)				(407)
Other comprehensive loss	415						415
Shares repurchased	(1,350)		(1,250)	(100)
Shares issued (returned) - stock based compensation	105		(3)	108
Stock-based compensation	46			46				0
Issuance of MPLX LP common units	407							407
Other	(9)			(9)
Shares repurchased (in shares)			(28)
Shares issued - stock-based compensation (in shares)		4
Ending balance at Dec. 31, 2012	12,105	4	(1,253)	9,527	3,880	0	(464)	411
Ending balance (in shares) at Dec. 31, 2012		361	28
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	2,133				2,112			21
Dividends declared	(485)				(485)
Distributions to noncontrolling interests	(21)							(21)
Other comprehensive loss	260						260
Shares repurchased	(2,793)		(2,893)	100
Shares issued (returned) - stock based compensation	38		(9)	47
Stock-based compensation	56			55				1
Tax settlement with Marathon Oil Corporation	39			39
Shares repurchased (in shares)			(37)
Shares issued - stock-based compensation (in shares)		1
Ending balance at Dec. 31, 2013	$ 11,332	$ 4	$ (4,155)	$ 9,768	$ 5,507	$ 0	$ (204)	$ 412
Ending balance (in shares) at Dec. 31, 2013		362	65

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Leases

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Leases

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, 2013, 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
2014	$	51		$	191
2015	52			184
2016	51			152
2017	50			106
2018	49			95
Later years	345			241
Total minimum lease payments	598			$	969
Less imputed interest costs	(203		)
Present value of net minimum lease payments	$	395

Operating lease rental expense was:

(In millions)	2013		2012		2011
Minimum rental	$	213	$	139	$	123
Contingent rental	—		—		1
Rental expense	$	213	$	139	$	124

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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, 2013		Dec. 31, 2012		Dec. 31, 2011
Reconciliation Of Segment Capital Expenditures And Investments To Total Capital Expenditures [Line Items]
Capital expenditures and investments	$ 2,789	[1],[2]	$ 1,460	[1],[2]	$ 1,323	[1],[2]
Plus: Items not allocated to segments:
Total capital expenditures	2,665	[2],[3]	1,432	[2],[3]	1,312	[2],[3]
Operating Segments [Member]
Reconciliation Of Segment Capital Expenditures And Investments To Total Capital Expenditures [Line Items]
Capital expenditures and investments	2,624	[2],[4],[5]	1,256	[2],[4]	1,185	[2],[4]
Less: Investments in equity method investees	124		28		11
Corporate, Non-Segment [Member]
Reconciliation Of Segment Capital Expenditures And Investments To Total Capital Expenditures [Line Items]
Capital expenditures and investments	165	[2],[6]	204	[2],[6]	138	[2],[6]
Plus: Items not allocated to segments:
Capital expenditures excluding capitalized interest	137		103		24
Interest costs capitalized	$ 28		$ 101		$ 114

[1] Includes $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, of $1.15 billion plus assumed liabilities of $210 million. The total consideration amount of $1.15 billion includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 5 to the audited consolidated financial statements.

[2] Capital expenditures include changes in capital accruals.

[3] See Note 20 for a reconciliation of total capital expenditures to additions to property, plant and equipment as reported in the consolidated statements of cash flows.

[4] Includes Speedway’s acquisition of convenience stores. See Note 5.

[5] The Refining & Marketing and Pipeline Transportation segments include $1.29 billion and $70 million, respectively, for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5.

[6] Includes capitalized interest of $28 million, $101 million and $114 million for 2013, 2012 and 2011, respectively.

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Debt (Outstanding Borrowings) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012
Debt Instrument [Line Items]
Total	$ 3,395		$ 3,355
Unamortized discount	(10)		(10)
Fair value adjustments	11	[1]	16	[1]
Long-term debt due within one year	(23)		(19)
Total long-term debt due after one year	3,373		3,342
MPC Revolver [Member]
Debt Instrument [Line Items]
Borrowings outstanding at period end	0		0
Consolidated Subsidiaries [Member] | Trade Receivables Securitization [Member]
Debt Instrument [Line Items]
Trade receivables securitization facility due 2016	0		0
MPLX Operations LLC [Member] | MPLX Revolver [Member]
Debt Instrument [Line Items]
Borrowings outstanding at period end	0		0
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 2014-2028	$ 395		$ 355
Trade Receivables Securitization [Member] | Consolidated Subsidiaries [Member]
Debt Instrument [Line Items]
Line of credit facility, expiration date	Dec. 31, 2014
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Line of credit facility, expiration date	Sep. 14, 2017
Revolving Credit Facility [Member] | MPLX Operations LLC [Member]
Debt Instrument [Line Items]
Line of credit facility, expiration date	Oct. 31, 2017

[1] See Notes 17 and 18 for information on interest rate swaps.

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Income per Common Share (Tables)

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Summary Of Earnings Per Common Share

(In millions, except per share data)	2013		2012		2011
Basic earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	2,112	$	3,389	$	2,389
Income allocated to participating securities	4		6		4
Income available to common stockholders - basic	$	2,108	$	3,383	$	2,385
Weighted average common shares outstanding	315		340		356
Basic earnings per share	$	6.69	$	9.95	$	6.70
Diluted earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	2,112	$	3,389	$	2,389
Income allocated to participating securities	4		6		4
Income available to common stockholders - diluted	$	2,108	$	3,383	$	2,385
Weighted average common shares outstanding	315		340		356
Effect of dilutive securities	2		2		1
Weighted average common shares, including dilutive effect	317		342		357
Diluted earnings per share	$	6.64	$	9.89	$	6.67

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Accumulated Other Comprehensive Loss (Tables)

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Changes in Accumulated Other Comprehensive Loss by Component

The following table shows the changes in accumulated other comprehensive loss by component. Amounts in parentheses indicate debits.

(In millions)	Pension Benefits			Other Benefits			Gain on Cash Flow Hedge		Workers Compensation			Total
Balance as of December 31, 2012	$	(432	)	$	(36	)	$	4	$	—		$	(464	)
Other comprehensive income (loss) before reclassifications	198			(13		)	—		4			189
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit(a)	(45		)	(4		)	—		—			(49		)
– actuarial loss(a)	66			3			—		—			69
– settlement loss(a)	95			—			—		—			95
Other(b)	—			—			—		(1		)	(1		)
Tax expense	(43		)	—			—		—			(43		)
Other comprehensive income (loss)	271			(14		)	—		3			260
Balance as of December 31, 2013	$	(161	)	$	(50	)	$	4	$	3		$	(204	)

^(a) These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 22.

^(b)  This amount was reclassified out of accumulated other comprehensive loss and is included in selling, general and administrative expenses on the consolidated statements of income.

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Related Party Transactions (Purchases From Related Parties) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	$ 357	$ 280	$ 1,916
Marathon Oil Companies [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	0	0	1,590
Centennial [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	3	7	31
LOOP [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	43	44	66
TAAE [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	24	0	0
TACE [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	130	73	46
TAME [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	131	124	153
Other Equity Method Investees [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Purchases from Related Party	$ 26	$ 32	$ 30

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Consolidated Statements of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$ 100,152	$ 82,235	$ 78,583
Sales to related parties	8	8	55
Income from equity method investments	36	26	50
Net gain on disposal of assets	6	177	12
Other income	52	46	59
Total revenues and other income	100,254	82,492	78,759
Costs and expenses:
Cost of revenues (excludes items below)	87,401	68,668	65,795
Purchases from related parties	357	280	1,916
Consumer excise taxes	6,263	5,709	5,114
Depreciation and amortization	1,220	995	891
Selling, general and administrative expenses	1,248	1,223	1,059
Other taxes	340	270	239
Total costs and expenses	96,829	77,145	75,014
Income from operations	3,425	5,347	3,745
Related party net interest and other financial income	0	1	35
Net interest and other financial income (costs)	(179)	(110)	(61)
Income before income taxes	3,246	5,238	3,719
Provision for income taxes	1,113	1,845	1,330
Net income	2,133	3,393	2,389
Less net income attributable to noncontrolling interests	21	4	0
Net income attributable to MPC	$ 2,112	$ 3,389	$ 2,389
Basic:
Net income attributable to MPC per share (in USD per share)	$ 6.69	$ 9.95	$ 6.70
Weighted average shares outstanding (in shares)	315	340	356
Diluted:
Net income attributable to MPC per share (in USD per share)	$ 6.64	$ 9.89	$ 6.67
Weighted average shares outstanding (in shares)	317	342	357
Dividends paid (in USD per share)	$ 1.54	$ 1.20	$ 0.45

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Inventories (Tables)

12 Months Ended

Dec. 31, 2013

Inventory Disclosure [Abstract]

Summary Of Inventories

	December 31,
(In millions)	2013		2012
Crude oil and refinery feedstocks	$	1,797	$	1,383
Refined products	2,367		1,761
Materials and supplies	425		231
Merchandise	100		74
Total (at cost)	$	4,689	$	3,449

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Inventories (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Inventory Disclosure [Abstract]
Total inventory LIFO percentage	90.00%	93.00%
Excess of replacement or current costs over stated LIFO value	$ 4,084	$ 4,511
Impact on revenues and costs as a result of LIFO liquidations	$ 0	$ 0	$ 4

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Stock-Based Compensation Plans (Summary Of Restricted Stock Award Activity) (Detail) (USD $)	6 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock [Member]
Number of Shares
Outstanding December 31, 2012		638,073
Granted		256,224
RS's Vested/RSU's Issued		(245,116)
Forfeited		(25,059)
Outstanding December 31, 2013		624,122	638,073
Weighted Average Grant Date Fair Value
Outstanding at December 31, 2012		$ 40.83
Granted (in USD per share)	$ 41.54	$ 87.06	$ 43.11
RS's Vested/RSU's Issued (in USD per share)		$ 37.95
Forfeited (in USD per share)		$ 58.60
Outstanding at December 31, 2013		$ 61.11	$ 40.83
Restricted Stock Units [Member]
Number of Shares
Outstanding December 31, 2012		359,111
Granted		26,399
RS's Vested/RSU's Issued		(431)
Forfeited		0
Outstanding December 31, 2013		385,079	359,111
Weighted Average Grant Date Fair Value
Outstanding at December 31, 2012		$ 31.07
Granted (in USD per share)	$ 33.78	$ 73.48	$ 44.38
RS's Vested/RSU's Issued (in USD per share)		$ 39.53
Forfeited (in USD per share)		$ 0.00
Outstanding at December 31, 2013		$ 33.96	$ 31.07

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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, 2013	Dec. 31, 2012	Dec. 31, 2011
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ (168)	$ 73	$ 149
Sales And Other Operating Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	12	8	(34)
Other Income [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	0	0	1
Cost Of Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ (180)	$ 65	$ 182

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Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Statement of Financial Position [Abstract]
Receivables, allowance for doubtful accounts	$ 9	$ 10
Preferred stock, shares issued	0	0
Preferred stock, shares outstanding	0	0
Preferred stock, par value (in USD per share)	$ 0.01
Preferred stock, shares authorized	30,000,000
Common stock, shares issued	362,000,000	361,000,000
Common stock, par value (in USD per share)	$ 0.01
Common stock, shares authorized	1,000,000,000
Treasury stock, shares	65,000,000	28,000,000

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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, 2013	Dec. 31, 2012	Dec. 31, 2011
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
January 1 balance	$ 40	$ 20	$ 14
Additions for tax positions of prior years	30	32	50
Reductions for tax positions of prior years	(25)	(6)	0
Settlements	(30)	(6)	(44)
Statute of limitations	(2)	0	0
December 31 balance	$ 13	$ 40	$ 20

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Leases (Schedule Of Future Minimum Commitments) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Capital Lease Obligations, 2014	$ 51
Capital Lease Obligations, 2015	52
Capital Lease Obligations, 2016	51
Capital Lease Obligations, 2017	50
Capital Lease Obligations, 2018	49
Capital Lease Obligations, Later years	345
Total minimum capital lease payments	598
Less imputed interest costs	(203)
Present value of net minimum lease payments	395
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Operating Lease Obligations, 2014	191
Operating Lease Obligations, 2015	184
Operating Lease Obligations, 2016	152
Operating Lease Obligations, 2017	106
Operating Lease Obligations, 2018	95
Operating Lease Obligations, Later years	241
Total minimum operating lease payments	$ 969

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Commitments And Contingencies (Detail) (USD $)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Loss Contingencies [Line Items]
Accrued liabilities for remediation	$ 123,000,000	$ 123,000,000
Receivables for recoverable costs	51,000,000	51,000,000
Contractual commitments to acquire property, plant and equipment and advance funds to equity method investees	1,700,000,000	1,400,000,000
Galveston Bay Refinery And Related Assets [Member]
Loss Contingencies [Line Items]
Maximum earnout provision payable to the company	700,000,000
Indemnification Agreement [Member] | Marathon Oil Companies [Member]
Loss Contingencies [Line Items]
Guarantee obligation current carrying value	2,000,000
Equity Method Investees [Member] | Other Guarantees [Member]
Loss Contingencies [Line Items]
Maximum potential undiscounted payments	122,000,000
Guarantee obligations maximum exposure per event	50,000,000
North Dakota Pipeline [Member]
Loss Contingencies [Line Items]
Contractual commitments to acquire property, plant and equipment and advance funds to equity method investees	892,000,000
Guarantee of Indebtedness of Others [Member] | LOOP and LOCAP LLC [Member] | Financial Guarantee [Member]
Loss Contingencies [Line Items]
Line of credit facility, expiration date	Dec. 31, 2037
Maximum potential undiscounted payments	172,000,000
Master Shelf Agreement [Member] | Centennial [Member] | Financial Guarantee [Member]
Loss Contingencies [Line Items]
Line of credit facility, expiration date	Dec. 31, 2024
Maximum potential undiscounted payments	42,000,000
Standby Letters Of Credit [Member] | TAME [Member] | Financial Guarantee [Member]
Loss Contingencies [Line Items]
Line of credit facility, expiration date	Dec. 31, 2018
Maximum potential undiscounted payments	25,000,000
Reimbursement percent	50.00%
Emergency Pricing And Consumer Protection Laws [Member] | Pending Or Threatened Litigation [Member]
Loss Contingencies [Line Items]
Alleged amount overcharged from customers	$ 89,000,000
Emergency Pricing And Consumer Protection Laws [Member] | Pending Or Threatened Litigation [Member] | Kentucky Lawsuit [Member]
Loss Contingencies [Line Items]
Loss contingency, inestimable loss	However, management does not believe the ultimate resolution of this litigation will have a material adverse effect.

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Description Of Business, Spinoff And Basis Of Presentation (Detail)	12 Months Ended
	Dec. 31, 2013
Accounting Policies [Abstract]
Separation and distribution agreement date of Spin off transaction	May 25, 2011
Distribution of MPC common stock	Jun. 30, 2011

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Equity Method Investments (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Equity Method Investments [Line Items]
Equity method investment difference between carrying amount and underlying equity	$ 41
Equity method investment difference between carrying amount and underlying equity, portion related to goodwill which is not being amortized	55
Equity method investments	463	321
Dividends and partnership distributions received from equity method investees	18	37	48
Centennial [Member]
Schedule of Equity Method Investments [Line Items]
Equity method investments	29	27
Percent of debt outstanding	50.00%
Centennial [Member] | Financial Guarantee [Member] | Master Shelf Agreement [Member]
Schedule of Equity Method Investments [Line Items]
Guarantees with a maximum exposure	$ 42

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Selected Quarterly Financial Data

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Selected Quarterly Financial Data

Selected Quarterly Financial Data (Unaudited)

	2013								2012
(In millions, except per share data)	1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.		1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.
Revenues	$	23,330	$	25,677	$	26,256	$	24,897	$	20,265	$	20,243	$	21,049	$	20,686
Income from operations	1,156		960		301		1,008		956		1,307		1,895		1,189
Net income	730		599		173		631		596		814		1,224		759
Net income attributable to MPC	725		593		168		626		596		814		1,224		755
Net income attributable to MPC per share:
Basic	$	2.19	$	1.84	$	0.54	$	2.09	$	1.71	$	2.39	$	3.61	$	2.26
Diluted	2.17		1.83		0.54		2.07		1.70		2.38		3.59		2.24
Dividends paid per share	0.35		0.35		0.42		0.42		0.25		0.25		0.35		0.35

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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, 2013 Employees	Dec. 31, 2012	Dec. 31, 2011
Multiemployer Plans, Pension [Member]
Multiemployer Plans [Line Items]
MPC Contributions	$ 3,000,000	$ 4,000,000	$ 3,000,000
Multiemployer pension plan, minimum contribution requirement per week per employee	$ 269
Number of employees participated in the plan	257

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Acquisitions and Investments (Schedule of Acquisition Related Pro Forma Financial Information) (Details) (Galveston Bay Refinery And Related Assets [Member], USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Galveston Bay Refinery And Related Assets [Member]
Business Acquisition [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ 102,120	$ 104,165
Net income attributable to MPC	$ 2,167	$ 3,625
Net income attributable to MPC per share - basic (USD per share)	$ 6.88	$ 10.66
Net income attributable to MPC per share - diluted (USD per share)	$ 6.84	$ 10.60

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Equity Method Investments

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Equity Method Investments

Equity Method Investments

	Ownership as of December 31, 2013	December 31,
(In millions)		2013		2012
Centennial	50%	$	29	$	27
LOCAP LLC	59%	24		26
LOOP	51%	214		198
North Dakota Pipeline(a)	38%	24		—
TAAE	43%	29		—
TACE	60%	70		29
TAEI	34%	23		—
TAME(b)	50%	35		27
Other		15		14
Total		$	463	$	321

^(a)  We own a 38 percent interest in the Class B units of this entity. Our Class B units will be converted to an approximate 27 percent ownership interest in the Class A units of this entity upon completion of the Sandpiper pipeline construction project in 2016.

^(b)  Excludes TAEI's investment in TAME.

Summarized financial information for equity method investees is as follows:

(In millions)	2013		2012		2011
Income statement data:
Revenues and other income	$	1,067	$	1,025	$	1,043
Income from operations	87		73		128
Net income	63		47		101
Balance sheet data - December 31:
Current assets	$	339	$	217
Noncurrent assets	1,238		1,163
Current liabilities	145		161
Noncurrent liabilities	618		636

As of December 31, 2013, the carrying value of our equity method investments was $41 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 $55 million of excess related to goodwill.

Centennial experienced a significant reduction in shipment volumes in the second half of 2011 that has continued through 2013. At December 31, 2013, 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 potential uses of Centennial’s assets. If current business conditions remain unchanged and the owners of Centennial are unable to find an alternative use for the assets, there could be a future impairment of our Centennial interest. As of December 31, 2013, our equity investment in Centennial was $29 million and we had a $42 million guarantee associated with 50 percent of Centennial's outstanding debt. See Note 25 for additional information on the debt guarantee.

Dividends and partnership distributions received from equity method investees (excluding distributions that represented a return of capital previously contributed) were $18 million, $37 million and $48 million in 2013, 2012 and 2011.

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Supplementary Statistics

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Supplementary Statistics

Supplementary Statistics (Unaudited)

(In millions)	2013			2012			2011
Income from Operations by segment
Refining & Marketing	$	3,206		$	5,098		$	3,591
Speedway	375			310			271
Pipeline Transportation(a)	210			216			199
Items not allocated to segments:
Corporate and other unallocated items(a)	(271		)	(336		)	(316		)
Minnesota Assets sale settlement gain	—			183			—
Pension settlement expenses	(95		)	(124		)	—
Income from operations	$	3,425		$	5,347		$	3,745
Capital Expenditures and Investments(b)(c)
Refining & Marketing	$	2,094		$	705		$	900
Speedway(d)	296			340			164
Pipeline Transportation	234			211			121
Corporate and Other(e)	165			204			138
Total	$	2,789		$	1,460		$	1,323

^(a)  Included in the Pipeline Transportation segment for 2013 and 2012 are $20 million and $4 million of corporate overhead costs attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. These expenses are not currently allocated to other segments.

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

^(c)  Includes $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, of $1.15 billion plus assumed liabilities of $210 million. The total consideration amount of $1.15 billion includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 5 to the audited consolidated financial statements.

^(d)  Includes Speedway's acquisitions of convenience stores. See Note 5 to the audited consolidated financial statements.

^(e)  Includes capitalized interest of $28 million, $101 million and $114 million for 2013, 2012 and 2011, respectively.

Supplementary Statistics (Unaudited)

	2013		2012		2011
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)(a)(b)	2,086		1,618		1,599
Refining & Marketing Operating Statistics(b)
Refining & Marketing Refined Product Sales Volume (thousands of barrels per day)(c)	2,075		1,599		1,581
Refining & Marketing Gross Margin (dollars per barrel)(d)	$	13.24	$	17.85	$	14.26
Crude Oil Capacity Utilization percent(e)	96		100		103
Refinery Throughputs (thousands of barrels per day):(f)
Crude oil refined	1,589		1,195		1,177
Other charge and blendstocks	213		168		181
Total	1,802		1,363		1,358
Sour Crude Oil Throughput percent	53		53		52
WTI-Priced Crude Oil Throughput percent	21		28		27
Refined Product Yields (thousands of barrels per day):(f)
Gasoline	921		738		739
Distillates	572		433		433
Propane	37		26		25
Feedstocks and special products	221		109		109
Heavy fuel oil	31		18		21
Asphalt	54		62		56
Total	1,836		1,386		1,383
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.20	$	1.00	$	0.78
Depreciation and amortization	1.36		1.44		1.29
Other manufacturing(h)	4.14		3.15		3.16
Total	$	6.70	$	5.59	$	5.23
Refining & Marketing Operating Statistics By Region
Gulf Coast:(b)
Refinery Throughputs (thousands of barrels per day):(i)
Crude oil refined	964
Other charge and blendstocks	195
Total	1,159
Sour Crude Oil Throughput percent	65
WTI-Priced Crude Oil Throughput percent	7
Refined Product Yields (thousands of barrels per day):(i)
Gasoline	551
Distillates	365
Propane	23
Feedstocks and special products	215
Heavy fuel oil	19
Asphalt	13
Total	1,186
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.00
Depreciation and amortization	1.09
Other manufacturing(h)	3.98
Total	$	6.07

Supplementary Statistics (Unaudited)
	2013			2012			2011
Refining & Marketing Operating Statistics By Region
Midwest:
Refinery Throughputs (thousands of barrels per day):(i)
Crude oil refined	625
Other charge and blendstocks	54
Total	679
Sour Crude Oil Throughput percent	35
WTI-Priced Crude Oil Throughput percent	42
Refined Product Yields (thousands of barrels per day):(i)
Gasoline	371
Distillates	207
Propane	14
Feedstocks and special products	41
Heavy fuel oil	12
Asphalt	41
Total	686
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.47
Depreciation and amortization	1.74
Other manufacturing(h)	4.21
Total	$	7.42
Speedway Operating Statistics
Convenience stores at period-end	1,478			1,464			1,371
Gasoline & distillate sales (millions of gallons)	3,146			3,027			2,938
Gasoline & distillate gross margin (dollars per gallon)(j)	$	0.1441		$	0.1318		$	0.1308
Merchandise sales (in millions)	$	3,135		$	3,058		$	2,924
Merchandise gross margin (in millions)	$	825		$	795		$	719
Same store gasoline sales volume (period over period)	0.5		%	(0.8		)%	(1.7		)%
Same store merchandise sales (period over period)(k)	4.3		%	7.0		%	6.7		%
Pipeline Transportation Operating Statistics
Pipeline throughput (thousands of barrels per day):(l)
Crude oil pipelines	1,280			1,190			1,184
Refined products pipelines	911			980			1,031
Total	2,191			2,170			2,215

^(a)  Total average daily volumes of refined product sales to wholesale, branded and retail (Speedway segment) customers.

^(b)  Includes the impact of the Galveston Bay Refinery and Related Assets beginning on the February 1, 2013 acquisition date.

^(c)  Includes intersegment sales.

^(d)  Sales revenue less cost of refinery inputs and purchased products, divided by total refinery throughputs. Starting in the fourth quarter of 2013, direct operating costs are no longer included in the Refining & Marketing gross margin and the gross margin is calculated based on total refinery throughput. All prior periods presented have been recalculated to reflect a consistent approach.

^(e)  Based on calendar day capacity, which is an annual average that includes downtime for planned maintenance and other normal operating activities.

^(f)  Excludes inter-refinery volumes of 36 thousand barrels per day ("mbpd"), 25 mbpd and 28 mbpd for 2013, 2012 and 2011, respectively.

^(g)  Per barrel of total refinery throughputs.

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

⁽ⁱ⁾  Includes inter-refinery transfer volumes.

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

^(k)  Excludes cigarettes.

^(l)  On owned common-carrier pipelines, excluding equity method investments.

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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, 2013	Dec. 31, 2012	Dec. 31, 2011
Income statement data:
Revenues and other income	$ 1,067	$ 1,025	$ 1,043
Income from operations	87	73	128
Net income	63	47	101
Balance sheet data - December 31:
Current assets	339	217
Noncurrent assets	1,238	1,163
Current liabilities	145	161
Noncurrent liabilities	$ 618	$ 636

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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, 2013		Dec. 31, 2012		Dec. 31, 2011
Change in plan assets:
Fair value of plan assets at December 31	$ 1,800		$ 1,478
Amounts recognized in the consolidated balance sheets:
Noncurrent liabilities	(771)		(1,266)
LOOP [Member]
Pretax amounts recognized in accumulated other comprehensive loss:
Equity method investments, Ownership Percentage	51.00%
LOOP [Member]
Pretax amounts recognized in accumulated other comprehensive loss:
Equity method investments, Ownership Percentage	51.00%
Pension Benefits [Member]
Change in benefit obligations:
Benefit obligations at January 1	2,192		2,685
Service cost	93		66		65
Interest cost	73		94		110
Actuarial (gain) loss	(183)		117
Liability gain due to curtailment	0		(17)
Other	0	[1]	(520)	[1]
Benefit obligations at December 31	1,927		2,192		2,685
Change in plan assets:
Fair value of plan assets at January 1	1,478		1,423
Actual return on plan assets	241		157
Employer contributions	329		131
Benefits paid	(248)		(233)
Fair value of plan assets at December 31	1,800		1,478		1,423
Funded status of plans at December 31	(127)		(714)
Amounts recognized in the consolidated balance sheets:
Current liabilities	(18)		(18)
Noncurrent liabilities	(109)		(696)
Accrued benefit cost	(127)		(714)
Pretax amounts recognized in accumulated other comprehensive loss:
Net loss	668	[2]	1,147	[2]
Prior service cost (credit)	(415)	[2]	(460)	[2]
Pension Benefits [Member] | LOOP [Member]
Pretax amounts recognized in accumulated other comprehensive loss:
Net loss	16	[2]
Other Benefits [Member]
Change in benefit obligations:
Benefit obligations at January 1	591		551
Service cost	25		20		19
Interest cost	26		24		27
Actuarial (gain) loss	17		53
Liability gain due to curtailment	0		0
Other	48	[1]	(40)	[1]
Benefit obligations at December 31	687		591		551
Change in plan assets:
Benefits paid	(20)		(17)
Funded status of plans at December 31	(687)		(591)
Amounts recognized in the consolidated balance sheets:
Current liabilities	(25)		(21)
Noncurrent liabilities	(662)		(570)
Accrued benefit cost	(687)		(591)
Pretax amounts recognized in accumulated other comprehensive loss:
Net loss	107	[2]	93	[2]
Prior service cost (credit)	(30)	[2]	(38)	[2]
Other Benefits [Member] | LOOP [Member]
Pretax amounts recognized in accumulated other comprehensive loss:
Net loss	$ 2	[2]

[1] Includes adjustments related to plan amendments in 2013 and 2012. Also, includes adjustments related to the Galveston Bay Refinery and Related Assets acquisition in 2013.

[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 2013, reflecting our 51 percent share.

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Goodwill

12 Months Ended

Dec. 31, 2013

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill

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 2013 and 2012, and no impairment was required.

The changes in the carrying amount of goodwill for 2013 and 2012 were as follows:

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
2012
Beginning balance	$	551	$	129	$	162	$	842
Acquisitions(a)	—		88		—		88
Ending balance	$	551	$	217	$	162	$	930
2013
Beginning balance	$	551	$	217	$	162	$	930
Acquisitions(a)	—		8		—		8
Ending balance	$	551	$	225	$	162	$	938

^(a)  See Note 5 for information on the acquisitions.

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Acquisitions and Investments (Investment in Pipeline) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013 North Dakota Pipeline [Member]	Jan. 02, 2016 North Dakota Pipeline Class A Units [Member] Scenario, Forecast [Member]	Jan. 02, 2016 North Dakota Pipeline Class A Units [Member] Scenario, Forecast [Member] Maximum [Member]
Schedule of Equity Method Investments [Line Items]
Cash paid to acquire equity method investments	$ 24
Equity method investments, Ownership Percentage	37.50%	27.00%	30.00%

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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, 2013		Dec. 31, 2012
Fair Value [Member]
Financial assets:
Investments	$ 336		$ 263
Other	31		33
Total financial assets	367		296
Financial liabilities:
Long-term debt	3,306	[1]	3,559	[1]
Deferred credits and other liabilities	21		23
Total financial liabilities	3,327		3,582
Carrying Value [Member]
Financial assets:
Investments	14		59
Other	30		31
Total financial assets	44		90
Financial liabilities:
Long-term debt	3,001	[1]	3,006	[1]
Deferred credits and other liabilities	21		23
Total financial liabilities	$ 3,022		$ 3,029

[1] Excludes capital leases

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating activities:
Net income	$ 2,133	$ 3,393	$ 2,389
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	1,220	995	891
Pension and other postretirement benefits, net	(124)	153	(90)
Deferred income taxes	23	492	123
Net gain on disposal of assets	(6)	(177)	(12)
Equity method investments, net	(18)	11	(2)
Changes in the fair value of derivative instruments	(21)	59	(57)
Changes in:
Current receivables	(940)	851	(1,177)
Inventories	(305)	(115)	(255)
Current accounts payable and accrued liabilities	1,464	(1,223)	1,502
All other, net	(21)	53	(3)
Net cash provided by operating activities	3,405	4,492	3,309
Investing activities:
Additions to property, plant and equipment	(1,206)	(1,369)	(1,185)
Acquisitions	(1,515)	(190)	(74)
Disposal of assets	16	53	144
Investments in related party debt securities – purchases	0	0	(10,326)
Investments in related party debt securities – redemptions	0	0	12,730
Investments—acquisition, loans and contributions	(151)	(57)	(56)
Investments—redemptions and repayments	77	108	53
All other, net	23	3	9
Net cash provided by (used in) investing activities	(2,756)	(1,452)	1,295
Financing activities:
Long-term debt payable to Marathon Oil and subsidiaries – borrowings	0	0	7,748
Long-term debt payable to Marathon Oil and subsidiaries – repayments	0	0	(11,366)
Long-term debt – borrowings	0	0	2,989
Long-term debt – repayments	(21)	(17)	(12)
Debt issuance costs	(4)	(6)	(60)
Issuance of common stock	48	108	1
Common stock repurchased	(2,793)	(1,350)	0
Dividends paid	(484)	(407)	(160)
Net proceeds from issuance of MPLX LP common units	0	407	0
Distributions to noncontrolling interests	(21)	0	0
Distributions to Marathon Oil Corporation	0	0	(783)
Tax settlement with Marathon Oil Corporation	39	0	0
All other, net	19	6	0
Net cash used in financing activities	(3,217)	(1,259)	(1,643)
Net increase (decrease) in cash and cash equivalents	(2,568)	1,781	2,961
Cash and cash equivalents at beginning of period	4,860	3,079	118
Cash and cash equivalents at end of period	$ 2,292	$ 4,860	$ 3,079

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Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Comprehensive Income [Abstract]
Net income	$ 2,133	$ 3,393	$ 2,389
Defined benefit postretirement and post-employment plans:
Actuarial changes, net of tax of $174, $47, and ($151)	294	78	(248)
Prior service costs, net of tax of ($19), $203, and $2	(34)	337	4
Other, net of tax of $-, $- and $-	0	0	(1)
Other comprehensive income (loss)	260	415	(245)
Comprehensive income	2,393	3,808	2,144
Less comprehensive income attributable to noncontrolling interests	21	4	0
Comprehensive income attributable to MPC	$ 2,372	$ 3,804	$ 2,144

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Equity

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Equity

Equity

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 to expire in December 2014. On September 26, 2013, we announced that our board of directors approved an additional $2.0 billion share repurchase authorization through September 2015, resulting in $6.0 billion of total share repurchase authorizations since January 1, 2012. After the effects of the accelerated share repurchase (“ASR”) programs and open market repurchases shown below, $1.86 billion of the amounts authorized by our board of directors remain available for repurchases at December 31, 2013. 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 and amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.

In February 2012 and November 2012, we entered into $850 million and $500 million ASR programs, respectively, to repurchase shares of MPC common stock under the approved share repurchase plan authorized by our board of directors. The total number of shares repurchased under these ASR programs was based generally on the volume-weighted average price of our common stock during the repurchase periods. 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.

Total share repurchases transacted through ASR programs and open market transactions were as follows for the respective periods. There were no shares repurchased in 2011.

(In millions, except per share data)	2013		2012
Number of shares repurchased(a)	37		28
Cash paid for shares repurchased	$	2,793	$	1,350
Effective average cost per delivered share	$	76.14	$	46.73

^(a) Shares repurchased in 2013 includes 1 million shares received under the November 2012 ASR program, which were paid for in 2012.

As of December 31, 2013, the total number of shares we have repurchased cumulatively through the ASR programs and open market repurchases since February 2012 was 65 million shares at an average cost per share of $63.61. The cash paid for shares repurchased during this period was $4.14 billion. In addition, at December 31, 2013, we had agreements to acquire additional common shares for $12 million, which were settled in early January 2014.

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Goodwill (Changes In Carrying Amount Of Goodwill) (Detail) (USD $) In Millions, unless otherwise specified	1 Months Ended						12 Months Ended
	Jul. 31, 2012		May 31, 2012		May 31, 2011		Dec. 31, 2013		Dec. 31, 2012
Goodwill [Line Items]
Beginning Balance							$ 930		$ 842
Acquisitions							8	[1]	88	[1]
Ending Balance							938		930
Refining & Marketing [Member]
Goodwill [Line Items]
Beginning Balance							551		551
Acquisitions							0		0
Ending Balance							551		551
Speedway [Member]
Goodwill [Line Items]
Beginning Balance							217		129
Acquisitions	5	[1]	83	[1]	9	[1]	8	[1]	88	[1]
Ending Balance							225		217
Pipeline Transportation [Member]
Goodwill [Line Items]
Beginning Balance							162		162
Acquisitions							0		0
Ending Balance							$ 162		$ 162

[1] See Note 5 for information on the acquisitions.

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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 Tax Examination [Line Items]
Tax years	2010
Minimum [Member] | States [Member]
Income Tax Examination [Line Items]
Tax years	2004
Maximum [Member] | United States Federal [Member]
Income Tax Examination [Line Items]
Tax years	2012
Maximum [Member] | States [Member]
Income Tax Examination [Line Items]
Tax years	2012

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Income Taxes (Components Of Deferred Tax Assets And Liabilities) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Deferred tax assets:
Employee benefits	$ 483	$ 585
Environmental	37	35
Other	49	55
Total deferred tax assets	569	675
Deferred tax liabilities:
Property, plant and equipment	2,290	2,225
Inventories	614	610
Investments in subsidiaries and affiliates	267	307
Other	70	29
Total deferred tax liabilities	3,241	3,171
Net deferred tax liabilities	$ 2,672	$ 2,496

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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, 2013	Dec. 31, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Projected benefit obligations	$ 1,927	$ 2,192
Accumulated benefit obligations	1,912	2,035
Fair value of plan assets	$ 1,800	$ 1,478

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Stock-Based Compensation Plans (Narrative) (Detail) (USD $)	6 Months Ended	12 Months Ended			6 Months Ended	12 Months Ended							6 Months Ended	12 Months Ended		6 Months Ended	12 Months Ended			6 Months Ended			12 Months Ended	6 Months Ended	12 Months Ended		6 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2011 Stock Options [Member]	Dec. 31, 2013 Stock Options [Member]	Dec. 31, 2012 Stock Options [Member]	Dec. 31, 2013 Stock Appreciation Rights (SARs) [Member]	Dec. 31, 2013 Restricted Stock Awards and Restricted Stock Units [Member]	Dec. 31, 2013 Performance Units [Member]	Dec. 31, 2013 Performance Unit Awards [Member]	Dec. 31, 2012 Performance Unit Awards [Member]	Dec. 31, 2011 Restricted Stock [Member]	Dec. 31, 2013 Restricted Stock [Member]	Dec. 31, 2012 Restricted Stock [Member]	Dec. 31, 2011 Restricted Stock Units [Member]	Dec. 31, 2013 Restricted Stock Units [Member]	Dec. 31, 2012 Restricted Stock Units [Member]	Dec. 31, 2013 Restricted Stock Units [Member] Non-Employee Directors [Member]	Jun. 30, 2011 Predecessor [Member]	Jun. 30, 2011 Predecessor [Member] Restricted Stock [Member]	Jun. 30, 2011 Predecessor [Member] Restricted Stock Units [Member]	Dec. 31, 2013 MPC 2007 and 2003 Plans [Member] Employees	Jun. 30, 2011 MPC 2007 and 2003 Plans [Member] Predecessor [Member] Stock Options [Member]	Dec. 31, 2013 MPC 2011 Plan [Member] Performance Units [Member]	Dec. 31, 2013 MPC 2012 and 2011 Plans [Member] Performance Units [Member]	Dec. 31, 2011 Maximum [Member]	Dec. 31, 2013 Maximum [Member] Stock Options [Member]	Dec. 31, 2013 Maximum [Member] Stock Appreciation Rights (SARs) [Member]	Dec. 31, 2013 Maximum [Member] Performance Units [Member]	Dec. 31, 2013 Maximum [Member] MPC 2012 Plan [Member]	Dec. 31, 2013 Maximum [Member] MPC 2012 Plan [Member] Awards Other Than Stock Options Or Stock Appreciation Rights [Member]	Dec. 31, 2013 Maximum [Member] MPC 2012 Plan [Member] Stock Options [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							3 years	3 years	3 years																30 months	36 months
Restricted stock and restricted stock unit awards granted in 2012, additional holding period									1 year
Target payout										$ 1.00
Actual payout																														$ 2.00
Target payout percentage																														200.00%
Pay-out percentage in MPC common stock (in percentage)																										25.00%
Pay-out percentage in cash (in percentage)																										75.00%
Grant date fair value											$ 1.12	$ 1.09	$ 41.54	$ 87.06	$ 43.11	$ 33.78	$ 73.48	$ 44.38			$ 48.53	$ 45.22
Total employee stock-based compensation expense		$ 42,000,000	$ 35,000,000	$ 28,000,000
Total related income tax benefits		15,000,000	13,000,000	11,000,000
Cash received upon exercise of stock option awards	1,000,000	48,000,000	108,000,000																	17,000,000
Tax benefits realized by MPC for deductions for stock awards exercised		18,000,000	16,000,000																	7,000,000							1,000,000
Share-based compensation arrangement by share-based payment award fair value assumptions expected volatility rate - Company stock weighting		33.00%				33.00%
Share-based compensation arrangement by share-based payment award fair value assumptions expected volatility rate - Peer stock weighting		67.00%				67.00%
Intrinsic value of options exercised					1,000,000	60,000,000	37,000,000																	18,000,000
Unrecognized compensation cost						7,000,000								24,000,000			0
Weighted average recognition period, in years						8 months 12 days								1 year 3 months 18 days
Restricted units outstanding																	385,079
Restricted units vested																			383,953
Weighted average fair value, vested																			$ 33.89
Shares issued in period											41,671

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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, 2013	Dec. 31, 2012	Dec. 31, 2011
Supplemental Cash Flow Information [Line Items]
Distributions to Marathon Oil per consolidated statements of cash flows	$ 0	$ 0	$ (783)
Non-cash contributions from Marathon Oil(a)	43	0	0
Distributions to Marathon Oil per consolidated statements of equity / net investment			(726)
Marathon Oil Companies [Member]
Supplemental Cash Flow Information [Line Items]
Non-cash contributions from Marathon Oil(a)			$ 57	[1]

[1] See Note 7.

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Document and Entity Information (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Feb. 14, 2014	Jun. 28, 2013
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2013
Document Fiscal Year Focus	2013
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		294,564,231
Entity Public Float			$ 22.5

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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						1 Months Ended		12 Months Ended
	Dec. 31, 2013 Pension Benefits [Member]		Dec. 31, 2012 Pension Benefits [Member]		Dec. 31, 2011 Pension Benefits [Member]		Jan. 31, 2014 Pension Benefits [Member] Scenario, Forecast [Member]		Dec. 31, 2013 Other Benefits [Member]		Dec. 31, 2012 Other Benefits [Member]		Dec. 31, 2011 Other Benefits [Member]
Weighted-average assumptions used to determine benefit obligation:
Weighted-average assumptions used to determine benefit obligation, Discount rate	4.30%		3.45%		4.30%				4.95%		4.05%		4.65%
Weighted-average assumptions used to determine benefit obligation, Rate of compensation increase	3.70%		5.00%		5.00%				3.70%		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	3.88%		4.06%		4.98%				4.11%		4.54%		5.55%
Weighted average assumptions used to determine net periodic benefit cost, Expected long-term return on plan assets	7.50%	[1]	7.50%	[1]	8.50%	[1]	7.00%	[1]	0.00%	[1]	0.00%	[1]	0.00%	[1]
Weighted average assumptions used to determine net periodic benefit cost, Rate of compensation increase	5.00%		5.00%		5.00%				5.00%		5.00%		5.00%

[1] Effective January 1, 2014, the expected long-term rate of return on plan assets changed from 7.50 percent to 7.00 percent

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Segment Information

12 Months Ended

Dec. 31, 2013

Segment Reporting [Abstract]

Segment Information

Segment Information

We have three reportable 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, buyers on the spot market, our Speedway segment and to independent entrepreneurs 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.

On February 1, 2013, we acquired the Galveston Bay Refinery and Related Assets, which are part of the Refining & Marketing and Pipeline Transportation segments. Segment information for periods prior to the acquisition does not include amounts for these operations. See Note 5.

Segment income represents income from operations attributable to the reportable 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 reportable segments. In addition, certain items that affect comparability (as determined by the chief operating decision maker) are not allocated to the reportable segments.

(In millions)	Refining & Marketing			Speedway			Pipeline Transportation			Total
Year Ended December 31, 2013
Revenues:
Customer	$	85,608		$	14,471		$	79		$	100,158
Intersegment(a)	9,294			4			458			9,756
Related parties	8			—			—			8
Segment revenues	94,910			14,475			537			109,922
Elimination of intersegment revenues	(9,294		)	(4		)	(458		)	(9,756		)
Total revenues	$	85,616		$	14,471		$	79		$	100,166
Segment income from operations(b)	$	3,206		$	375		$	210		$	3,791
Income from equity method investments	28			—			8			36
Depreciation and amortization(c)	1,011			112			74			1,197
Capital expenditures and investments(d)(e)(f)	2,094			296			234			2,624

(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)(e)	900			164		121			1,185

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

^(b)  Included in the Pipeline Transportation segment for 2013 and 2012 are $20 millionand $4 million of corporate overhead costs attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 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 convenience stores. See Note 5.

^(f)  The Refining & Marketing and Pipeline Transportation segments include $1.29 billion and $70 million, respectively, for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5.

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

(In millions)	2013			2012			2011
Segment income from operations	$	3,791		$	5,624		$	4,061
Items not allocated to segments:
Corporate and other unallocated items(a)(b)	(271		)	(336		)	(316		)
Minnesota Assets sale settlement gain(c)	—			183			—
Pension settlement expenses(d)	(95		)	(124		)	—
Net interest and other financial income (costs)(e)	(179		)	(109		)	(26		)
Income before income taxes	$	3,246		$	5,238		$	3,719

^(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 attributable to MPLX were included in the Pipeline Transportation segment subsequent to MPLX’s October 31, 2012 initial public offering.

^(c)  See Note 6.

^(d)  See Note 22.

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

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

(In millions)	2013		2012		2011
Segment capital expenditures and investments	$	2,624	$	1,256	$	1,185
Less: Investments in equity method investees	124		28		11
Plus: Items not allocated to segments:
Capital expenditures not allocated to segments	137		103		24
Capitalized interest	28		101		114
Total capital expenditures(a)(b)	$	2,665	$	1,432	$	1,312

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

^(b)  See Note 20 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)	2013			2012			2011
Total revenues (as reported above)	$	100,166		$	82,245		$	78,638
Plus: Corporate and other unallocated items	(6		)	(2		)	—
Less: Sales to related parties	8			8			55
Sales and other operating revenues (including consumer excise taxes)	$	100,152		$	82,235		$	78,583

Revenues by product line were:

(In millions)	2013		2012		2011
Refined products	$	93,520	$	76,234	$	73,334
Merchandise	3,308		3,229		3,090
Crude oil and refinery feedstocks	2,988		2,514		1,972
Transportation and other	344		266		242
Total revenues	100,160		82,243		78,638
Less: Sales to related parties	8		8		55
Sales and other operating revenues (including consumer excise taxes)	$	100,152	$	82,235	$	78,583

Revenue from BP p.l.c. included in the Refining & Marketing segment represented 10 percent of our total annual revenues for the year ended December 31, 2013. No single customer accounted for more than 10 percent of annual revenues for the years ended December 31, 2012 and 2011.

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)	2013		2012
Refining & Marketing	$	19,573	$	17,052
Speedway	2,064		1,947
Pipeline Transportation	1,947		1,950
Corporate and Other	4,801		6,274
Total consolidated assets	$	28,385	$	27,223

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Segment Information (Narrative) (Detail)	12 Months Ended
	Dec. 31, 2013 Segment	Dec. 31, 2013 BP plc [Member]	Dec. 31, 2012 None [Member] Maximum [Member]	Dec. 31, 2011 None [Member] Maximum [Member]
Segment Reporting Information [Line Items]
Number of reportable segments	3
Percent of annual revenues		10.00%	10.00%	10.00%

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Income Taxes (Reconciliation Of Federal Statutory Income Tax Rate) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Effective Income Tax Rate Reconciliation, Percent [Abstract]
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	3.00%	2.00%	2.00%
Domestic manufacturing deduction	(2.00%)	(1.00%)	(1.00%)
Other	(2.00%)	(1.00%)	0.00%
Provision for income taxes	34.00%	35.00%	36.00%

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Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Statement of Comprehensive Income [Abstract]
Actuarial changes, tax	$ 174	$ 47	$ (151)
Prior service cost, tax	(19)	203	2
Other, tax	$ 0	$ 0	$ 0

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MPLX LP

12 Months Ended

Dec. 31, 2013

Noncontrolling Interest [Abstract]

MPLX LP

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. In October 2012, MPLX completed its initial public offering of 19,895,000 common units. Net proceeds to MPLX from the sale of the units were $407 million. We own a 73.6 percent interest in MPLX, including the two percent general partner interest. We consolidate this entity for financial reporting purposes since we have a controlling financial interest, and we record a noncontrolling interest for the interest owned by the public. The initial public offering represented the sale of a 26.4 percent interest in MPLX.

MPLX's initial assets consisted 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. On May 1, 2013, we sold an additional five percent interest in Pipe Line Holdings to MPLX for $100 million, increasing MPLX's ownership interest in Pipe Line Holdings to 56 percent and reducing our ownership to 44 percent.

On February 27, 2014, we announced the sale of an additional 13 percent interest in Pipe Line Holdings to MPLX for $310 million, effective March 1, 2014. Subsequent to this transaction, MPLX will own a 69 percent general partner interest in Pipe Line Holdings and we will own a 31 percent limited partner interest. MPLX intends to finance this transaction with $40 million of cash on-hand and by borrowing $270 million on its revolving credit agreement.

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 nine long-term, fee-based transportation agreements and five long-term, fee-based 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. These agreements range from three to ten years in length, and most automatically renew unless terminated by either party. We believe the terms and conditions under these commercial agreements, as well as the other initial agreements we entered into with MPLX are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services.

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. Any such deficiency payments may then be applied as a credit for volumes transported on the applicable pipeline system in excess of its minimum volume commitment during the following four or eight quarters under the terms of the applicable transportation services agreement. As of December 31, 2013, we had $34 million in volume deficiency credits. 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 are 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, which is 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, 2013

Accounting Changes and Error Corrections [Abstract]

Accounting Standards

Accounting Standards

Recently 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 U.S. generally accepted accounting principles ("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 reclassified 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 was to be applied prospectively for interim and annual periods beginning with the first quarter of 2013. The adoption of this accounting standards update in the first quarter of 2013 did not have an impact on our consolidated results of operations, financial position or cash flows. The new required disclosures are included in Note 21.

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 was effective for annual and interim impairment tests performed in fiscal years beginning after September 15, 2012. Early adoption was permitted. The adoption of this accounting standards update in the first quarter of 2013 did not have an impact on our consolidated results of operations, financial position or cash flows. We perform the annual intangible asset impairment testing in the fourth quarter.

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 was to be applied retrospectively and was effective for interim and annual periods beginning with the first quarter of 2013. The adoption of this accounting standards update in the first quarter of 2013 did not have an impact on our consolidated results of operations, financial position or cash flows. The new required disclosures are included in Note 17.

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Supplementary Statistics (Operating Statistics) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013 BPD		Dec. 31, 2012 BPD		Dec. 31, 2011 BPD
Operating Statistics [Line Items ]
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)	2,086,000	[1],[2]	1,618,000	[1],[2]	1,599,000	[1],[2]
Refining & Marketing [Member]
Operating Statistics [Line Items ]
Refining & Marketing Refined Product Sales Volume (thousands of barrels per day)	2,075,000	[2],[3]	1,599,000	[2],[3]	1,581,000	[2],[3]
Refining & Marketing Gross Margin (dollars per barrel)	13.24	[2],[4]	17.85	[2],[4]	14.26	[2],[4]
Crude Oil Capacity Utilization percent	96.00%	[2],[5]	100.00%	[2],[5]	103.00%	[2],[5]
Refinery Throughputs (thousands of barrels per day):
Total	1,802,000	[2],[6]	1,363,000	[2],[6]	1,358,000	[2],[6]
Sour Crude Oil Throughput percent	53.00%	[2]	53.00%	[2]	52.00%	[2]
WTI-Priced Crude Oil Throughput percent	21.00%	[2]	28.00%	[2]	27.00%	[2]
Refined Product Yields (thousands of barrels per day):
Total	1,836,000	[2],[6]	1,386,000	[2],[6]	1,383,000	[2],[6]
Refinery Direct Operating Costs in Refining & Marketing Gross Margin (dollars per barrel): [Abstract]
Turnaround Maintenance And Engineered Project Expenses Per Barrel	1.20	[2],[7]	1.00	[2],[7]	0.78	[2],[7]
Depreciation and amortization	1.36	[2],[7]	1.44	[2],[7]	1.29	[2],[7]
Other Manufacturing Costs Per Barrel	4.14	[2],[7],[8]	3.15	[2],[7],[8]	3.16	[2],[7],[8]
Total	6.70	[2],[7]	5.59	[2],[7]	5.23	[2],[7]
Pipeline throughput (thousands of barrels per day)(h):
Inter-refinery transfers	36,000		25,000		28,000
Refining & Marketing [Member] | Gulf Coast [Member]
Refinery Throughputs (thousands of barrels per day):
Total	1,159,000	[2],[9]
Sour Crude Oil Throughput percent	65.00%	[2]
WTI-Priced Crude Oil Throughput percent	7.00%	[2]
Refined Product Yields (thousands of barrels per day):
Total	1,186,000	[2],[9]
Refinery Direct Operating Costs in Refining & Marketing Gross Margin (dollars per barrel): [Abstract]
Turnaround Maintenance And Engineered Project Expenses Per Barrel	1.00	[2],[7]
Depreciation and amortization	1.09	[2],[7]
Other Manufacturing Costs Per Barrel	3.98	[2],[7],[8]
Total	6.07	[2],[7]
Refining & Marketing [Member] | Midwest [Member]
Refinery Throughputs (thousands of barrels per day):
Total	679,000	[9]
Sour Crude Oil Throughput percent	35.00%
WTI-Priced Crude Oil Throughput percent	42.00%
Refined Product Yields (thousands of barrels per day):
Total	686,000	[9]
Refinery Direct Operating Costs in Refining & Marketing Gross Margin (dollars per barrel): [Abstract]
Turnaround Maintenance And Engineered Project Expenses Per Barrel	1.47	[7]
Depreciation and amortization	1.74	[7]
Other Manufacturing Costs Per Barrel	4.21	[7],[8]
Total	7.42	[7]
Refining & Marketing [Member] | Crude Oil [Member]
Refinery Throughputs (thousands of barrels per day):
Total	1,589,000	[2],[6]	1,195,000	[2],[6]	1,177,000	[2],[6]
Refining & Marketing [Member] | Crude Oil [Member] | Gulf Coast [Member]
Refinery Throughputs (thousands of barrels per day):
Total	964,000	[2],[9]
Refining & Marketing [Member] | Crude Oil [Member] | Midwest [Member]
Refinery Throughputs (thousands of barrels per day):
Total	625,000	[9]
Refining & Marketing [Member] | OtherChargeAndBlendstock [Member]
Refinery Throughputs (thousands of barrels per day):
Total	213,000	[2],[6]	168,000	[2],[6]	181,000	[2],[6]
Refining & Marketing [Member] | OtherChargeAndBlendstock [Member] | Gulf Coast [Member]
Refinery Throughputs (thousands of barrels per day):
Total	195,000	[2],[9]
Refining & Marketing [Member] | OtherChargeAndBlendstock [Member] | Midwest [Member]
Refinery Throughputs (thousands of barrels per day):
Total	54,000	[9]
Refining & Marketing [Member] | Gasoline [Member]
Refined Product Yields (thousands of barrels per day):
Total	921,000	[2],[6]	738,000	[2],[6]	739,000	[2],[6]
Refining & Marketing [Member] | Gasoline [Member] | Gulf Coast [Member]
Refined Product Yields (thousands of barrels per day):
Total	551,000	[2],[9]
Refining & Marketing [Member] | Gasoline [Member] | Midwest [Member]
Refined Product Yields (thousands of barrels per day):
Total	371,000	[9]
Refining & Marketing [Member] | Distillates [Member]
Refined Product Yields (thousands of barrels per day):
Total	572,000	[2],[6]	433,000	[2],[6]	433,000	[2],[6]
Refining & Marketing [Member] | Distillates [Member] | Gulf Coast [Member]
Refined Product Yields (thousands of barrels per day):
Total	365,000	[2],[9]
Refining & Marketing [Member] | Distillates [Member] | Midwest [Member]
Refined Product Yields (thousands of barrels per day):
Total	207,000	[9]
Refining & Marketing [Member] | Propane [Member]
Refined Product Yields (thousands of barrels per day):
Total	37,000	[2],[6]	26,000	[2],[6]	25,000	[2],[6]
Refining & Marketing [Member] | Propane [Member] | Gulf Coast [Member]
Refined Product Yields (thousands of barrels per day):
Total	23,000	[2],[9]
Refining & Marketing [Member] | Propane [Member] | Midwest [Member]
Refined Product Yields (thousands of barrels per day):
Total	14,000	[9]
Refining & Marketing [Member] | Feedstocks and Special Products [Member]
Refined Product Yields (thousands of barrels per day):
Total	221,000	[2],[6]	109,000	[2],[6]	109,000	[2],[6]
Refining & Marketing [Member] | Feedstocks and Special Products [Member] | Gulf Coast [Member]
Refined Product Yields (thousands of barrels per day):
Total	215,000	[2],[9]
Refining & Marketing [Member] | Feedstocks and Special Products [Member] | Midwest [Member]
Refined Product Yields (thousands of barrels per day):
Total	41,000	[9]
Refining & Marketing [Member] | Heavy Fuel Oil [Member]
Refined Product Yields (thousands of barrels per day):
Total	31,000	[2],[6]	18,000	[2],[6]	21,000	[2],[6]
Refining & Marketing [Member] | Heavy Fuel Oil [Member] | Gulf Coast [Member]
Refined Product Yields (thousands of barrels per day):
Total	19,000	[2],[9]
Refining & Marketing [Member] | Heavy Fuel Oil [Member] | Midwest [Member]
Refined Product Yields (thousands of barrels per day):
Total	12,000	[9]
Refining & Marketing [Member] | Asphalt [Member]
Refined Product Yields (thousands of barrels per day):
Total	54,000	[2],[6]	62,000	[2],[6]	56,000	[2],[6]
Refining & Marketing [Member] | Asphalt [Member] | Gulf Coast [Member]
Refined Product Yields (thousands of barrels per day):
Total	13,000	[2],[9]
Refining & Marketing [Member] | Asphalt [Member] | Midwest [Member]
Refined Product Yields (thousands of barrels per day):
Total	41,000	[9]
Speedway [Member]
Refinery Direct Operating Costs in Refining & Marketing Gross Margin (dollars per barrel): [Abstract]
Convenience stores at period-end (in number of stores)	1,478		1,464		1,371
Gasoline And Distillate Sales (in millions of gallons)	3,146,000,000		3,027,000,000		2,938,000,000
Gasoline And Distillate Gross Margin (in dollars per gallon)	0.1441	[10]	0.1318	[10]	0.1308	[10]
Merchandise sales (in millions)	$ 3,135		$ 3,058		$ 2,924
Merchandise gross margin (in millions)	$ 825		$ 795		$ 719
Same store gasoline sales volume percentage (period over period)	0.50%		(0.80%)		(1.70%)
Same store merchandise sales excluding cigarettes percentage (period over period)	4.30%	[11]	7.00%	[11]	6.70%	[11]
Pipeline Transportation [Member]
Pipeline throughput (thousands of barrels per day)(h):
Total	2,191,000	[12]	2,170,000	[12]	2,215,000	[12]
Pipeline Transportation [Member] | Crude Oil Pipelines [Member]
Pipeline throughput (thousands of barrels per day)(h):
Total	1,280,000	[12]	1,190,000	[12]	1,184,000	[12]
Pipeline Transportation [Member] | Refined Products Pipelines [Member]
Pipeline throughput (thousands of barrels per day)(h):
Total	911,000	[12]	980,000	[12]	1,031,000	[12]

[1] Total average daily volumes of refined product sales to wholesale, branded and retail (Speedway segment) customers.

[2] Includes the impact of the Galveston Bay Refinery and Related Assets beginning on the February 1, 2013 acquisition date.

[3] Includes intersegment sales.

[4] Sales revenue less cost of refinery inputs and purchased products, divided by total refinery throughputs. Starting in the fourth quarter of 2013, direct operating costs are no longer included in the Refining & Marketing gross margin and the gross margin is calculated based on total refinery throughput. All prior periods presented have been recalculated to reflect a consistent approach.

[5] Based on calendar day capacity, which is an annual average that includes downtime for planned maintenance and other normal operating activities.

[6] Excludes inter-refinery volumes of 36 thousand barrels per day ("mbpd"), 25 mbpd and 28 mbpd for 2013, 2012 and 2011, respectively

[7] Per barrel of total refinery throughputs.

[8] Includes utilities, labor, routine maintenance and other operating costs.

[9] Includes inter-refinery transfer volumes.

[10] The price paid by consumers less the cost of refined products, including transportation, consumer excise taxes and bankcard processing fees, divided by gasoline and distillate sales volume.

[11] Excludes cigarettes.

[12] On owned common-carrier pipelines, excluding equity method investments.

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2013

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

(In millions)	Estimated Useful Lives	December 31,
		2013		2012
Refining & Marketing	4 - 25 years	$	16,982	$	15,089
Speedway	4 - 15 years	2,344		2,100
Pipeline Transportation	16 - 42 years	1,921		1,747
Corporate and Other	4 - 40 years	546		473
Total		21,793		19,409
Less accumulated depreciation		7,872		6,766
Property, plant and equipment, net		$	13,921	$	12,643

Property, plant and equipment includes gross assets acquired under capital leases of $510 million and $417 million at December 31, 2013 and 2012, with related amounts in accumulated depreciation of $111 million and $79 million at December 31, 2013 and 2012. Property, plant and equipment includes construction in progress of $747 million and $520 million at December 31, 2013 and 2012, which primarily relates to refinery projects.

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Other Items

12 Months Ended

Dec. 31, 2013

Other Income and Expenses [Abstract]

Other Items

Other Items

Net interest and other financial income (costs) was:

(In millions)	2013			2012			2011
Interest:
Interest income	$	9		$	5		$	3
Interest expense(a)	(195		)	(191		)	(164		)
Interest capitalized(a)	28			101			104
Total net interest	(158		)	(85		)	(57		)
Other:
Net foreign currency gains	—			—			12
Bank service and other fees	(21		)	(25		)	(16		)
Total other	(21		)	(25		)	(4		)
Net interest and other financial income (costs)	$	(179	)	$	(110	)	$	(61	)

^(a)  See Note 7 for information on related party interest expense and capitalized interest.

XML

Segment Information (Reconciliation Of Total Revenues To Sales And Other Operating Revenues) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ 100,152	$ 82,235	$ 78,583
Less: Sales to related parties	8	8	55
Operating Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Total revenues (as reported above)	100,166	82,245	78,638
Sales and other operating revenues (including consumer excise taxes)	100,158	82,237	78,583
Less: Sales to related parties	8	8	55
Corporate, Non-Segment [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ (6)	$ (2)	$ 0

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Related Party Transactions

12 Months Ended

Dec. 31, 2013

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

Our related parties included:

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

• TAAE, in which we have a 43 percent interest, TACE, in which we have a 60 percent noncontrolling interest, and TAME, in which we have a 67 percent direct and indirect noncontrolling interest. These companies each own an ethanol production facility.

• Centennial Pipeline LLC (“Centennial”), in which we have a 50 percent noncontrolling 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)	2013		2012		2011
Equity method investees:
Centennial	$	—	$	1	$	35
Other equity method investees	8		7		7
Marathon Oil Companies	—		—		13
Total	$	8	$	8	$	55

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 Centennial's pipeline, which are included in other income on the consolidated statements of income, were $1 million in both 2013 and 2012.

Purchases from related parties were as follows:

(In millions)	2013		2012		2011
Equity method investees:
Centennial	$	3	$	7	$	31
LOOP	43		44		66
TAAE	24		—		—
TACE	130		73		46
TAME	131		124		153
Other equity method investees	26		32		30
Marathon Oil Companies	—		—		1,590
Total	$	357	$	280	$	1,916

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 TAAE, TACE and TAME 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 for 2011.

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)	2013		2012
Centennial	$	1	$	2
TAME	1		—
Total	$	2	$	2

At December 31, 2013, we also had a $2 million long-term receivable from Centennial, which is included in other noncurrent assets on the consolidated balance sheet.

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

	December 31,
(In millions)	2013		2012
LOOP	$	3	$	4
TAAE	2		—
TACE	4		2
TAME	5		5
Other equity method investees	2		2
Total	$	16	$	13

We had a throughput and deficiency agreement with Centennial, which expired on March 31, 2012. During 2012, we impaired our $14 million prepaid tariff with Centennial. For additional information on the impairment, see Note 17.

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. 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. 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 for 2013 and 2012 was not material. Related party net interest and other financial income for 2011 was as follows:

(In millions)	2011
Dividend income:
PFD Preferred Stock	$	35
Interest expense:
PFD revolving credit agreement	3
Marathon Oil loan agreement	5
Interest capitalized	(8		)
Total	—
Related party net interest and other financial income	$	35

We also recorded property, plant and equipment additions related to capitalized interest incurred by Marathon Oil on our behalf of $2 million in 2011, 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 were recorded as non-cash capital contributions or distributions. The net non-cash capital contributions from Marathon Oil were $57 million in 2011.

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Summary Of Principal Accounting Policies (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Summary Of Principal Accounting Policies [Line Items]
Restricted Cash and Cash Equivalents	$ 7
Accounts receivable number of days past-due evaluated for doubtful accounts	180 days
Share-based compensation arrangement by share-based payment award fair value assumptions expected volatility rate - Company stock weighting (in percentage)	33.00%
Share-based compensation arrangement by share-based payment award fair value assumptions expected volatility rate - Peer stock weighting (in percentage)	67.00%
Minimum [Member]
Summary Of Principal Accounting Policies [Line Items]
Number of companies engaged in crude oil or refinery feedstock trading agreement	100
Estimated useful lives (in years)	4 years
Maximum [Member]
Summary Of Principal Accounting Policies [Line Items]
Estimated useful lives (in years)	42 years
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	38.00%	42.00%
MPLX LP [Member]
Summary Of Principal Accounting Policies [Line Items]
MPC's partnership interest in MPLX (in percentage)	73.60%
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%

XML

Derivatives (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Mar. 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
Hedge agreements	3.50 percent senior notes due in March 2016
Gain on the termination of the transactions		20
Hedge ineffectiveness of interest rate swaps		$ 0

XML

Acquisitions and Investments

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Acquisitions and Investments

Acquisitions and Investments

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, four light product terminals, branded-jobber marketing contract assignments for the supply of approximately 1,200 branded sites, a 1,040 megawatt electric cogeneration facility and a 50,000 barrel per day allocation of space on the Colonial Pipeline. We refer to these assets as the “Galveston Bay Refinery and Related Assets.” We paid $1.49 billion for these assets, which included $935 million for inventory. 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 as discussed below. 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.

As of the acquisition date, we recorded a contingent liability of $600 million, representing the preliminary fair value of contingent consideration we expect to pay to BP related to the earnout provision. The fair value of the contingent consideration was estimated using an income approach. The amount of cash to be paid under the arrangement is based on both a market-based crack spread and refinery throughput volumes for the months during which the contract applies, as well as established thresholds that cap the annual and total payment. The earnout payment cannot exceed $200 million per year for the first three years of the arrangement or $250 million per year for the last three years of the arrangement, with the total cumulative payment capped at $700 million over the six-year period. Any excess or shortfall from the annual cap for a current year’s earnout calculation will not affect subsequent years’ calculations. We used internal and external forecasts for the crack spread and internal forecasts for refinery throughput volumes and applied an appropriate risk-adjusted discount rate to the range of cash flows indicated by various scenarios to determine the fair value of the arrangement. The fair value of the contingent consideration is reassessed each quarter, with changes in fair value recorded in cost of revenues. The fair value of the contingent consideration was $625 million at December 31, 2013, which includes $159 million classified as current. See Note 17 for additional information.

The transaction provided for a post-closing adjustment for inventory, which was finalized for $9 million, reducing our total consideration.

The components of the fair value of consideration transferred are as follows:

(In millions)
Cash	$	1,491
Fair value of contingent consideration as of acquisition date	600
Payable to seller	6
Post-closing adjustment	(9		)
Total consideration	$	2,088

During the fourth quarter of 2013, an independent appraisal of the assets acquired and liabilities assumed and other evaluations were completed and finalized. Minor updates to the preliminary fair value measurements of assets acquired and liabilities assumed were made during the second and third quarters of 2013. The following table summarizes the final amounts assigned to the assets acquired and liabilities assumed as of the acquisition date.

(In millions)
Inventories	$	935
Other current assets	1
Property, plant and equipment, net	1,274
Other noncurrent assets	88
Accounts payable	(12		)
Payroll and benefits payable	(14		)
Long-term debt due within one year(a)	(2		)
Other current liabilities	(6		)
Long-term debt(a)	(58		)
Defined benefit postretirement plan obligations	(43		)
Deferred credits and other liabilities	(75		)
Total	$	2,088

^(a) Represents a capital lease obligation assumed.

Neither goodwill nor a gain from a bargain purchase was recognized in conjunction with the Galveston Bay Refinery and Related Assets acquisition.

Other noncurrent assets consist of a $20 million intangible asset related to customer relationships and a $68 million intangible asset related to prepaid licensed refinery technology agreements. The intangible assets related to customer relationships and prepaid licensed refinery technology agreements are being amortized on a straight-line basis over four and 15 years, respectively. The weighted average life over which these acquired intangibles are being amortized is approximately 13 years.

We recognized $7 million of acquisition-related costs associated with the Galveston Bay Refinery and Related Assets acquisition. These costs were expensed and were included in selling, general and administrative expenses.

Our refineries and related assets are operated as an integrated system. As the information is not available by refinery, it is not practicable to disclose the revenues and net income associated with the acquisition that were included in our consolidated statements of income for 2013.

The following unaudited pro forma financial information presents consolidated results assuming the Galveston Bay Refinery and Related Assets acquisition occurred on January 1, 2012. The pro forma financial information does not give effect to potential synergies that could result from the acquisition and is not necessarily indicative of the results of future operations.

(In millions, except per share data)	2013		2012
Sales and other operating revenues (including consumer excise taxes)	$	102,120	$	104,165
Net income attributable to MPC	2,167		3,625
Net income attributable to MPC per share - basic	$	6.88	$	10.66
Net income attributable to MPC per share - diluted	6.84		10.60

The pro forma information includes adjustments to align accounting policies, an adjustment to depreciation expense to reflect the fair value of property, plant and equipment, increased amortization expense related to identifiable intangible assets and the related income tax effects. The pro forma information reflects revisions made during the second and third quarters of 2013 to the estimated fair values of assets acquired and liabilities assumed.

Acquisitions of Convenience Stores

During 2013, Speedway acquired nine convenience stores located in Tennessee, western Indiana and western Pennsylvania. In connection with these acquisitions, our Speedway segment recorded $8 million of goodwill.

In July 2012, Speedway 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.

In May 2012, Speedway 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.

In May 2011, Speedway acquired 23 convenience stores in Indiana and Illinois. In connection with this acquisition, our Speedway segment recorded $9 million of goodwill.

The goodwill associated with these acquisitions is deductible for income tax purposes.

These acquisitions support our strategic initiative to increase our Speedway segment sales and profitablity. 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.

Investments in Ethanol Companies

On August 1, 2013, we acquired from Mitsui & Co. (U.S.A.), Inc. its interests in three ethanol companies for $75 million. Under the purchase agreement, we acquired an additional 24 percent interest in The Andersons Clymers Ethanol LLC ("TACE"), bringing our ownership interest to 60 percent; a 34 percent interest in The Andersons Ethanol Investment LLC ("TAEI"), which holds a 50 percent ownership in The Andersons Marathon Ethanol LLC ("TAME"), bringing our direct and indirect ownership interest in TAME to 67 percent; and a 40 percent interest in The Andersons Albion Ethanol LLC ("TAAE"), which owns an ethanol production facility in Albion, Michigan. On October 1, 2013, our ownership interest in TAAE increased to 43 percent as a result of TAAE acquiring one of the owner's interest. We hold a noncontrolling interest in each of these entities and account for them using the equity method of accounting since the minority owners have substantive participating rights.

Investment in Pipeline

During 2013, we made initial contributions of $24 million to acquire an ownership interest in North Dakota Pipeline Company LLC ("North Dakota Pipeline"). These contributions funded 37.5 percent of the construction costs incurred to-date on the Sandpiper pipeline project. In conjunction with our commitment to be an anchor shipper for the Sandpiper pipeline and our investment in the project, we will earn an approximate 27 percent equity interest in Enbridge Energy Partner L.P.'s North Dakota System when the Sandpiper pipeline is placed into service in 2016. We will also have the option to increase our ownership interest to approximately 30 percent through additional investments in future system improvements. We account for our interest in North Dakota Pipeline using the equity method of accounting. See Note 25 for information on future contributions to North Dakota Pipeline.

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Disposition

12 Months Ended

Dec. 31, 2013

Discontinued Operations and Disposal Groups [Abstract]

Disposition

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) lease 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.

During 2013, the buyer redeemed the second preferred security for $49 million, which included $4 million of accrued distributions.

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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Stock-Based Compensation Plans (Summary Of Performance Unit Awards) (Detail) (Performance Unit Awards [Member])	12 Months Ended
	Dec. 31, 2013
Performance Unit Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding December 31, 2012	2,040,000
Granted	1,782,500
Settled	0
Canceled	0
Outstanding December 31, 2013	3,822,500

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Income per Common Share

12 Months Ended

Dec. 31, 2013

Earnings Per Share [Abstract]

Income per Common Share

Income per Common Share

We compute basic earnings per share by dividing net income attributable to MPC by the weighted average number of shares of common stock outstanding. Diluted income per share assumes exercise of certain stock based compensation awards, 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 for periods prior to the Spinoff 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 for periods prior to the Spinoff. Excluded from the diluted share calculation are less than one million, approximately two million and approximately four million shares related to stock-based compensation awards in 2013, 2012 and 2011, 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)	2013		2012		2011
Basic earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	2,112	$	3,389	$	2,389
Income allocated to participating securities	4		6		4
Income available to common stockholders - basic	$	2,108	$	3,383	$	2,385
Weighted average common shares outstanding	315		340		356
Basic earnings per share	$	6.69	$	9.95	$	6.70
Diluted earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	2,112	$	3,389	$	2,389
Income allocated to participating securities	4		6		4
Income available to common stockholders - diluted	$	2,108	$	3,383	$	2,385
Weighted average common shares outstanding	315		340		356
Effect of dilutive securities	2		2		1
Weighted average common shares, including dilutive effect	317		342		357
Diluted earnings per share	$	6.64	$	9.89	$	6.67

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Acquisitions and Investments (Estimated Fair Values of Assets Acquired and Liabilities Assumed) (Details) (Galveston Bay Refinery And Related Assets [Member], USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Galveston Bay Refinery And Related Assets [Member]
Business Acquisition [Line Items]
Inventories	$ 935
Other current assets	1
Property, plant and equipment, net	1,274
Other noncurrent assets	88
Accounts payable	(12)
Payroll and benefits payable	(14)
Long-term debt due within one year	(2)	[1]
Other current liabilities	(6)
Long-term debt	(58)	[1]
Defined benefit postretirement plan obligations	(43)
Deferred credits and other liabilities	(75)
Total	$ 2,088

[1] Represents a capital lease obligation assumed

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Accumulated Other Comprehensive Loss (Changes in Accumulated Other Comprehensive Loss by Component) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance as of December 31, 2012	$ (464)
Other comprehensive income (loss) before reclassifications	189
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit	(49)	[1]
Amortization– actuarial loss	69	[1]
Amortization– settlement loss	95	[1]
Other	(1)	[2]
Tax expense	(43)
Other comprehensive income (loss)	260		415	(245)
Balance as of December 31, 2013	(204)		(464)
Pension Benefits [Member]
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit	(45)		(18)	6
Amortization– actuarial loss	161		218	79
Other Benefits [Member]
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit	(4)		(2)	0
Amortization– actuarial loss	3		2	0
Accumulated Defined Benefit Plans Adjustment [Member] | Pension Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance as of December 31, 2012	(432)
Other comprehensive income (loss) before reclassifications	198
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit	(45)	[1]
Amortization– actuarial loss	66	[1]
Amortization– settlement loss	95	[1]
Tax expense	(43)
Other comprehensive income (loss)	271
Balance as of December 31, 2013	(161)
Accumulated Defined Benefit Plans Adjustment [Member] | Other Benefits [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance as of December 31, 2012	(36)
Other comprehensive income (loss) before reclassifications	(13)
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit	(4)	[1]
Amortization– actuarial loss	3	[1]
Amortization– settlement loss	0	[1]
Tax expense	0
Other comprehensive income (loss)	(14)
Balance as of December 31, 2013	(50)
Gain Cash Flow Hedge [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance as of December 31, 2012	4
Other comprehensive income (loss) before reclassifications	0
Amounts reclassified from accumulated other comprehensive loss:
Tax expense	0
Other comprehensive income (loss)	0
Balance as of December 31, 2013	4
Workers Compensation [Member]
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Balance as of December 31, 2012	0
Other comprehensive income (loss) before reclassifications	4
Amounts reclassified from accumulated other comprehensive loss:
Other	(1)	[2]
Tax expense	0
Other comprehensive income (loss)	3
Balance as of December 31, 2013	$ 3

[1] These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 22.

[2] This amount was reclassified out of accumulated other comprehensive loss and is included in selling, general and administrative expenses on the consolidated statements of income.

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Segment Information (Schedule Of Revenues By Product Line) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
Total revenues	$ 100,160	$ 82,243	$ 78,638
Less: Sales to related parties	8	8	55
Sales and other operating revenues (including consumer excise taxes)	100,152	82,235	78,583
Refined Products [Member]
Segment Reporting Information [Line Items]
Total revenues	93,520	76,234	73,334
Merchandise [Member]
Segment Reporting Information [Line Items]
Total revenues	3,308	3,229	3,090
Crude Oil And Refinery Feedstocks [Member]
Segment Reporting Information [Line Items]
Total revenues	2,988	2,514	1,972
Transportation And Other [Member]
Segment Reporting Information [Line Items]
Total revenues	$ 344	$ 266	$ 242

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Acquisitions and Investments (Acquisitions of Convenience Stores) (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended						12 Months Ended
	Jul. 31, 2012 Store		May 31, 2012 Parcels Store		May 31, 2011 Store		Dec. 31, 2013 Store		Dec. 31, 2012
Business Acquisition [Line Items]
Goodwill, Acquired During Period							$ 8	[1]	$ 88	[1]
Speedway [Member]
Business Acquisition [Line Items]
Number of convenience stores acquired	10		87		23		9
Goodwill, Acquired During Period	$ 5	[1]	$ 83	[1]	$ 9	[1]	$ 8	[1]	$ 88	[1]
Number of undeveloped real estate parcels acquired for future development			2

[1] See Note 5 for information on the acquisitions.

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Goodwill (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012
Goodwill and Intangible Assets Disclosure [Abstract]
Amount of required impairment	$ 0	$ 0

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Acquisitions and Investments (Fair Value of Consideration Transferred) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2011
Business Acquisition [Line Items]
Cash	$ 1,515		$ 190	$ 74
Fair value of contingent consideration as of acquisition date	600	[1]	0	0
Payable to seller	6	[1]	0	0
Galveston Bay Refinery And Related Assets [Member]
Business Acquisition [Line Items]
Cash	1,491
Fair value of contingent consideration as of acquisition date	600
Payable to seller	6
Post-closing adjustment	(9)
Total consideration	$ 2,088

[1] See Note 5.

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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, 2013	Dec. 31, 2012
Assets
Other noncurrent assets	$ 2	$ 0
Liabilities
Accrued taxes	370	446
Deferred income taxes	2,304	2,050
Net deferred tax liabilities	$ 2,672	$ 2,496

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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, 2013	Dec. 31, 2012
Actual return on plan assets:
Fair value of plan assets at December 31	$ 1,800	$ 1,478
Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	127	121
Actual return on plan assets:
Net realized gains/(losses)	16	3
Net unrealized gains/(losses)	16	(1)
Purchases	12	22
Sales	(34)	(18)
Fair value of plan assets at December 31	137	127
Private Equity [Member]
Actual return on plan assets:
Fair value of plan assets at December 31	57	56
Private Equity [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	56	55
Actual return on plan assets:
Net realized gains/(losses)	13	5
Net unrealized gains/(losses)	3	(3)
Purchases	7	12
Sales	(22)	(13)
Fair value of plan assets at December 31	57	56
Real Estate [Member]
Actual return on plan assets:
Fair value of plan assets at December 31	60	54
Real Estate [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	54	49
Actual return on plan assets:
Net realized gains/(losses)	3	(2)
Net unrealized gains/(losses)	10	2
Purchases	5	10
Sales	(12)	(5)
Fair value of plan assets at December 31	60	54
Other [Member]
Actual return on plan assets:
Fair value of plan assets at December 31	22	17
Other [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	17	17
Actual return on plan assets:
Net realized gains/(losses)	0	0
Net unrealized gains/(losses)	3	0
Purchases	0	0
Sales	0	0
Fair value of plan assets at December 31	$ 20	$ 17

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Subsequent Event

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Subsequent Event

Subsequent Event

On February 3, 2014, we announced that we signed an agreement to purchase a facility in Cincinnati, Ohio from Felda Iffco Sdn Bhd, Malaysia. The plant currently produces several products including biodiesel and glycerin. The capacity of the plant is 4,100 barrels per day. The transaction is expected to close in April 2014.

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Supplementary Statistics (Supplementary Statistics) (Detail) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Supplementary Statistics [Line Items]
Income from operations	$ 1,008,000,000	$ 301,000,000	$ 960,000,000	$ 1,156,000,000	$ 1,189,000,000	$ 1,895,000,000	$ 1,307,000,000	$ 956,000,000	$ 3,425,000,000		$ 5,347,000,000		$ 3,745,000,000
Minnesota Assets sale settlement gain									6,000,000		177,000,000		12,000,000
Capital expenditures and investments									2,789,000,000	[1],[2]	1,460,000,000	[1],[2]	1,323,000,000	[1],[2]
Acquisitions									1,386,000,000	[3]	180,000,000	[3]	74,000,000	[3]
Fair value of contingent consideration as of acquisition date									600,000,000	[4]	0		0
Galveston Bay Refinery And Related Assets [Member]
Supplementary Statistics [Line Items]
Acquisitions									1,360,000,000
Cash paid excluding inventories									1,150,000,000
Assumed liabilities	210,000,000								210,000,000
Fair value of contingent consideration as of acquisition date									600,000,000
Operating Segments [Member]
Supplementary Statistics [Line Items]
Income from operations									3,791,000,000	[5]	5,624,000,000	[5]	4,061,000,000	[5]
Capital expenditures and investments									2,624,000,000	[2],[6],[7]	1,256,000,000	[2],[6]	1,185,000,000	[2],[6]
Operating Segments [Member] | Refining & Marketing [Member]
Supplementary Statistics [Line Items]
Income from operations									3,206,000,000		5,098,000,000		3,591,000,000
Capital expenditures and investments									2,094,000,000	[1],[2],[7]	705,000,000	[1],[2]	900,000,000	[1],[2]
Operating Segments [Member] | Refining & Marketing [Member] | Galveston Bay Refinery And Related Assets [Member]
Supplementary Statistics [Line Items]
Acquisitions									1,290,000,000
Operating Segments [Member] | Speedway [Member]
Supplementary Statistics [Line Items]
Income from operations									375,000,000		310,000,000		271,000,000
Capital expenditures and investments									296,000,000	[2],[6],[7],[8]	340,000,000	[2],[6],[8]	164,000,000	[2],[6],[8]
Operating Segments [Member] | Pipeline Transportation [Member]
Supplementary Statistics [Line Items]
Income from operations									210,000,000	[5]	216,000,000	[5]	199,000,000	[5]
Capital expenditures and investments									234,000,000	[1],[2],[7]	211,000,000	[1],[2]	121,000,000	[1],[2]
Operating Segments [Member] | Pipeline Transportation [Member] | Galveston Bay Refinery And Related Assets [Member]
Supplementary Statistics [Line Items]
Acquisitions									70,000,000
Operating Segments [Member] | Pipeline Transportation [Member] | MPLX LP [Member]
Supplementary Statistics [Line Items]
Cost of Services, Overhead									20,000,000		4,000,000
Corporate, Non-Segment [Member]
Supplementary Statistics [Line Items]
Income from operations									(271,000,000)	[10],[5],[9]	(336,000,000)	[10],[5],[9]	(316,000,000)	[10],[5],[9]
Capital expenditures and investments									165,000,000	[11],[2]	204,000,000	[11],[2]	138,000,000	[11],[2]
Interest costs capitalized									28,000,000		101,000,000		114,000,000
Segment Reconciling Items [Member]
Supplementary Statistics [Line Items]
Minnesota Assets sale settlement gain									0		183,000,000	[12]	0
Pension settlement expenses									$ (95,000,000)	[13]	$ (124,000,000)	[13]	$ 0	[13]

[1] Includes $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, of $1.15 billion plus assumed liabilities of $210 million. The total consideration amount of $1.15 billion includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 5 to the audited consolidated financial statements.

[2] Capital expenditures include changes in capital accruals.

[3] Includes $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, of $1.15 billion plus assumed liabilities of $210 million. The 2012 acquisitions exclude the inventory acquired and liability assumed. See Note 5.

[4] See Note 5.

[5] Included in the Pipeline Transportation segment for 2013 and 2012 are $20 million and $4 million of corporate overhead costs attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. These expenses are not currently allocated to other segments.

[6] Includes Speedway’s acquisition of convenience stores. See Note 5.

[7] The Refining & Marketing and Pipeline Transportation segments include $1.29 billion and $70 million, respectively, for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5.

[8] Includes Speedway's acquisitions of convenience stores. See Note 5 to the audited consolidated financial statements.

[9] Corporate overhead costs attributable to MPLX were included in the Pipeline Transportation segment subsequent to MPLX’s October 31, 2012 initial public offering.

[10] 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.

[11] Includes capitalized interest of $28 million, $101 million and $114 million for 2013, 2012 and 2011, respectively.

[12] See Note 6.

[13] See Note 22.

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Debt (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Outstanding Borrowings

Our outstanding borrowings at December 31, 2013 and 2012 consisted of the following:

	December 31,
(In millions)	2013			2012
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 2014-2028	395			355
MPLX Operations LLC revolving credit agreement due 2017	—			—
Trade receivables securitization facility due 2016	—			—
Total	3,395			3,355
Unamortized discount	(10		)	(10		)
Fair value adjustments(a)	11			16
Amounts due within one year	(23		)	(19		)
Total long-term debt due after one year	$	3,373		$	3,342

^(a)  See Notes 17 and 18 for information on interest rate swaps.

Schedule Of Debt Payments

The following table shows five years of scheduled debt payments.

(In millions)
2014	$	23
2015	27
2016	777
2017	28
2018	30

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Inventories

12 Months Ended

Dec. 31, 2013

Inventory Disclosure [Abstract]

Inventories

Inventories

	December 31,
(In millions)	2013		2012
Crude oil and refinery feedstocks	$	1,797	$	1,383
Refined products	2,367		1,761
Materials and supplies	425		231
Merchandise	100		74
Total (at cost)	$	4,689	$	3,449

The LIFO method accounted for 90 percent and 93 percent of total inventory value at December 31, 2013 and 2012, respectively. Current acquisition costs were estimated to exceed the LIFO inventory value at December 31, 2013 and 2012 by $4,084 million and $4,511 million, respectively. There were no liquidations of LIFO inventories in 2013 and 2012. Cost of revenues decreased and income from operations increased by $4 million in 2011 as a result of liquidations of LIFO inventories, excluding inventories liquidated in dispositions.

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Debt (Schedule Of Debt Payments) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Maturities of Long-term Debt [Abstract]
2014	$ 23
2015	27
2016	777
2017	28
2018	$ 30

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Derivatives

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Derivatives

Derivatives

For further information regarding the fair value measurement of derivative instruments, including any effect of master netting agreements or collateral, see Note 17. 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, 2013 and 2012:

	December 31, 2013
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	21	$	53	Other current assets

	December 31, 2012
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	49	$	88	Other current assets

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	2013		2012			2011
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 for crude oil and refined products as of December 31, 2013.

	Position	Total Barrels (In thousands)
Crude oil(a)
Exchange-traded	Long	10,580
Exchange-traded	Short	(23,900)
Refined Products(a)
Exchange-traded	Long	3,646
Exchange-traded	Short	(4,175)

^(a)100 percent of these contracts expire in the first quarter of 2014.

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

(In millions)	Gain (Loss)
Income Statement Location	2013			2012		2011
Sales and other operating revenues	$	12		$	8	$	(34	)
Other income	—			—		1
Cost of revenues	(180		)	65		182
Total	$	(168	)	$	73	$	149

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Inventories (Summary Of Inventories) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Inventory Disclosure [Abstract]
Crude oil and refinery feedstocks	$ 1,797	$ 1,383
Refined products	2,367	1,761
Materials and supplies	425	231
Merchandise	100	74
Total (at cost)	$ 4,689	$ 3,449

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

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, 2013 and 2012 by fair value hierarchy level. We have elected to offset the fair value amounts recognized for multiple derivative contracts executed with the same counterparty, including any related cash collateral as shown below; however, fair value amounts by hierarchy level are presented on a gross basis in the following tables.

	December 31, 2013
	Fair Value Hierarchy
(In millions)	Level 1		Level 2		Level 3		Netting and Collateral(a)			Net Carrying Value on Balance Sheet(b)		Collateral Pledged Not Offset
Commodity derivative instruments, assets	$	21	$	—	$	—	$	(21	)	$	—	$	61
Other assets	2		—		—		N/A			2		—
Total assets at fair value	$	23	$	—	$	—	$	(21	)	$	2	$	61
Commodity derivative instruments, liabilities	$	53	$	—	$	—	$	(53	)	$	—	$	—
Contingent consideration, liability(c)	—		—		625		N/A			625		—
Total liabilities at fair value	$	53	$	—	$	625	$	(53	)	$	625	$	—

	December 31, 2012
	Fair Value Hierarchy
(In millions)	Level 1		Level 2		Level 3		Netting and Collateral(a)			Net Carrying Value on Balance Sheet(b)		Collateral Pledged Not Offset
Commodity derivative instruments, assets	$	49	$	—	$	—	$	(49	)	$	—	$	45
Other assets	2		—		—		N/A			2		—
Total assets at fair value	$	51	$	—	$	—	$	(49	)	$	2	$	45
Commodity derivative instruments, liabilities	$	88	$	—	$	—	$	(88	)	$	—	$	—

^(a) Represents the impact of netting assets, liabilities and cash collateral when a legal right of offset exists. As of December 31, 2013 and 2012, cash collateral of $32 million and $39 million, respectively, was netted with mark-to-market derivative liabilities.

^(b) We have no derivative contracts that are subject to master netting arrangements that are reflected gross on the balance sheet.

^(c) Includes $159 million classified as current.

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/(liabilities) classified as Level 3 in the fair value hierarchy.

(In millions)	2013			2012			2011
Beginning balance	$	—		$	—		$	2,402
Contingent consideration agreement	(600		)	—			—
Total realized and unrealized losses included in net income	(25		)	(2		)	—
Purchases of PFD Preferred Stock(a)	—			—			10,326
Redemptions of PFD Preferred Stock(a)	—			—			(12,730		)
Settlements of derivative instruments	—			2			2
Ending balance	$	(625	)	$	—		$	—

^(a)  For information on PFD Preferred Stock, see Note 7. 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.

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,
	2013				2012				2011
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Property, plant and equipment, net	$	1	$	8	$	—	$	—	$	—	$	—
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, 2013 and 2012, excluding the derivative financial instruments and contingent consideration reported above.

	December 31,
	2013				2012
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial assets:
Investments	$	336	$	14	$	263	$	59
Other	31		30		33		31
Total financial assets	$	367	$	44	$	296	$	90
Financial liabilities:
Long-term debt(a)	$	3,306	$	3,001	$	3,559	$	3,006
Deferred credits and other liabilities	21		21		23		23
Total financial liabilities	$	3,327	$	3,022	$	3,582	$	3,029

^(a)  Excludes capital leases

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Fair Value Measurements (Narrative) (Detail) (USD $)	3 Months Ended	12 Months Ended									12 Months Ended
	Mar. 31, 2012 Centennial [Member]	Dec. 31, 2013 Fair Value, Measurements, Nonrecurring [Member]	Dec. 31, 2012 Fair Value, Measurements, Nonrecurring [Member]	Dec. 31, 2011 Fair Value, Measurements, Nonrecurring [Member]	Dec. 31, 2012 Fair Value, Measurements, Nonrecurring [Member] Centennial [Member]	Dec. 31, 2013 Derivative [Member] Fair Value, Measurements, Recurring [Member]	Dec. 31, 2012 Derivative [Member] Fair Value, Measurements, Recurring [Member]	Dec. 31, 2011 Derivative [Member] Fair Value, Measurements, Recurring [Member]	Dec. 31, 2013 Contingent Consideration [Member] Fair Value, Measurements, Recurring [Member]	Dec. 31, 2013 Galveston Bay Refinery And Related Assets [Member]	Dec. 31, 2013 Galveston Bay Refinery And Related Assets [Member] Fair Value, Measurements, Recurring [Member] Minimum [Member]	Dec. 31, 2013 Galveston Bay Refinery And Related Assets [Member] Fair Value, Measurements, Recurring [Member] Maximum [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Maximum earnout payment, year one										$ 200,000,000
Maximum earnout payment, year two										200,000,000
Maximum earnout payment, year three										200,000,000
Maximum earnout payment, year four										250,000,000
Maximum earnout payment, year five										250,000,000
Maximum earnout payment, year six										250,000,000
Maximum earnout provision payable to the company										700,000,000
Fair Value Measurement With Unobservable Inputs Internal And External Crack Spread Forecasts1											13	18
Discount rate											5.00%	10.00%
Unrealized losses included in net income						0	0	1,000,000	25,000,000
Impairment charge		8,000,000	0	0
Impairment of prepaid tariff	$ 14,000,000	$ 0	$ 14,000,000	$ 0	$ 14,000,000

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Equity (Tables)

12 Months Ended

Dec. 31, 2013

Equity [Abstract]

Share Repurchases Transacted Through ASR Programs and Open Market Transactions

Total share repurchases transacted through ASR programs and open market transactions were as follows for the respective periods. There were no shares repurchased in 2011.

(In millions, except per share data)	2013		2012
Number of shares repurchased(a)	37		28
Cash paid for shares repurchased	$	2,793	$	1,350
Effective average cost per delivered share	$	76.14	$	46.73

^(a) Shares repurchased in 2013 includes 1 million shares received under the November 2012 ASR program, which were paid for in 2012.

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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, 2013	Dec. 31, 2012	Dec. 31, 2011
Fair Value, Measurements, Nonrecurring [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, plant and equipment, net, Fair Value	$ 1	$ 0	$ 0
Property, plant and equipment, net, Impairment	8	0	0
Other noncurrent assets, Fair Value	0	0	0
Other noncurrent assets, Impairment	$ 0	$ 14	$ 0

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Current assets:
Cash and cash equivalents	$ 2,292	$ 4,860
Receivables, less allowance for doubtful accounts of $9 and $10	5,559	4,610
Inventories	4,689	3,449
Other current assets	197	110
Total current assets	12,737	13,029
Equity method investments	463	321
Property, plant and equipment, net	13,921	12,643
Goodwill	938	930
Other noncurrent assets	326	300
Total assets	28,385	27,223
Current liabilities:
Accounts payable	8,234	6,785
Payroll and benefits payable	406	364
Consumer excise taxes payable	373	325
Accrued taxes	513	598
Long-term debt due within one year	23	19
Other current liabilities	275	112
Total current liabilities	9,824	8,203
Long-term debt	3,373	3,342
Deferred income taxes	2,304	2,050
Defined benefit postretirement plan obligations	771	1,266
Deferred credits and other liabilities	781	257
Total liabilities	17,053	15,118
Commitments and contingencies (see Note 25)
MPC stockholders’ equity:
Preferred stock, no shares issued and outstanding (par value $0.01 per share, 30 million shares authorized)	0	0
Common stock:
Issued - 362 million and 361 million shares (par value $0.01 per share, 1 billion shares authorized)	4	4
Held in treasury, at cost - 65 million and 28 million shares	(4,155)	(1,253)
Additional paid-in capital	9,768	9,527
Retained earnings	5,507	3,880
Accumulated other comprehensive loss	(204)	(464)
Total MPC stockholders’ equity	10,920	11,694
Noncontrolling interests	412	411
Total equity	11,332	12,105
Total liabilities and equity	$ 28,385	$ 27,223

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Income Taxes (Components Of Income Tax Provisions (Benefits)) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Current
Federal	$ 954	$ 1,185	$ 1,040
State and local	131	169	152
Foreign	5	(1)	15
Total	1,090	1,353	1,207
Deferred
Federal	20	432	139
State and local	8	57	(16)
Foreign	(5)	3	0
Total	23	492	123
Federal	974	1,617	1,179
State and local	139	226	136
Foreign	0	2	15
Total	$ 1,113	$ 1,845	$ 1,330

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Summary Of Principal Accounting Policies

12 Months Ended

Dec. 31, 2013

Accounting Policies [Abstract]

Summary Of Principal Accounting Policies

Summary of Principal Accounting Policies

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 generally 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 and liabilities, 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 our 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. Rebates to customers are reflected as a reduction of revenue and are accrued for in accounts payable on the consolidated balance sheets.

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 and investments in highly liquid debt instruments with maturities of three months or less.

Restricted cash - Restricted cash consists of cash advances to be used for the operation and maintenance of an operated pipeline system. At December 31, 2013, the amount of restricted cash included in other current assets on the consolidated balance sheets was $7 million.

Accounts receivable and allowance for doubtful accounts – Our receivables primarily consist of customer accounts receivable. The allowance for doubtful accounts is the best estimate of the amount of probable credit losses in customer accounts receivable and is based on historical write-off experience. 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 38 percent and 42 percent of our accounts receivable balances at December 31, 2013 and 2012, 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 100 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, historically, to 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 – 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.

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.

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 33 percent of our common stock volatility and 67 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. The fair value of performance unit awards granted to our employees is estimated on the date of grant using a Monte Carlo valuation model.

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.

Renewable fuel identification numbers ("RINs") - We purchase RINs to satisfy a portion of our Renewable Fuel Standard ("RFS2") compliance. We record a short-term intangible asset, included in other current assets on the balance sheet, for RINs owned in excess of our anticipated current period compliance requirements. The asset value is based on the product of the excess RINs as of the balance sheet date, if any, and the average cost of our RINs. We record a current liability, included in other current liabilities on the balance sheet, when we are deficient RINs based on the product of the deficient RINs as of the balance sheet date, if any, and the market price of the RINs at the balance sheet date. The cost of RINs used for compliance is reflected in cost of revenues.Any gains or losses on the sale or expiration of RINs are classified as other income.

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Supplementary Statistics (Tables)

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Supplementary Statistics

(In millions)	2013			2012			2011
Income from Operations by segment
Refining & Marketing	$	3,206		$	5,098		$	3,591
Speedway	375			310			271
Pipeline Transportation(a)	210			216			199
Items not allocated to segments:
Corporate and other unallocated items(a)	(271		)	(336		)	(316		)
Minnesota Assets sale settlement gain	—			183			—
Pension settlement expenses	(95		)	(124		)	—
Income from operations	$	3,425		$	5,347		$	3,745
Capital Expenditures and Investments(b)(c)
Refining & Marketing	$	2,094		$	705		$	900
Speedway(d)	296			340			164
Pipeline Transportation	234			211			121
Corporate and Other(e)	165			204			138
Total	$	2,789		$	1,460		$	1,323

^(a)  Included in the Pipeline Transportation segment for 2013 and 2012 are $20 million and $4 million of corporate overhead costs attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. These expenses are not currently allocated to other segments.

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

^(c)  Includes $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, of $1.15 billion plus assumed liabilities of $210 million. The total consideration amount of $1.15 billion includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 5 to the audited consolidated financial statements.

^(d)  Includes Speedway's acquisitions of convenience stores. See Note 5 to the audited consolidated financial statements.

^(e)  Includes capitalized interest of $28 million, $101 million and $114 million for 2013, 2012 and 2011, respectively.

Operating Statistics

	2013		2012		2011
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)(a)(b)	2,086		1,618		1,599
Refining & Marketing Operating Statistics(b)
Refining & Marketing Refined Product Sales Volume (thousands of barrels per day)(c)	2,075		1,599		1,581
Refining & Marketing Gross Margin (dollars per barrel)(d)	$	13.24	$	17.85	$	14.26
Crude Oil Capacity Utilization percent(e)	96		100		103
Refinery Throughputs (thousands of barrels per day):(f)
Crude oil refined	1,589		1,195		1,177
Other charge and blendstocks	213		168		181
Total	1,802		1,363		1,358
Sour Crude Oil Throughput percent	53		53		52
WTI-Priced Crude Oil Throughput percent	21		28		27
Refined Product Yields (thousands of barrels per day):(f)
Gasoline	921		738		739
Distillates	572		433		433
Propane	37		26		25
Feedstocks and special products	221		109		109
Heavy fuel oil	31		18		21
Asphalt	54		62		56
Total	1,836		1,386		1,383
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.20	$	1.00	$	0.78
Depreciation and amortization	1.36		1.44		1.29
Other manufacturing(h)	4.14		3.15		3.16
Total	$	6.70	$	5.59	$	5.23
Refining & Marketing Operating Statistics By Region
Gulf Coast:(b)
Refinery Throughputs (thousands of barrels per day):(i)
Crude oil refined	964
Other charge and blendstocks	195
Total	1,159
Sour Crude Oil Throughput percent	65
WTI-Priced Crude Oil Throughput percent	7
Refined Product Yields (thousands of barrels per day):(i)
Gasoline	551
Distillates	365
Propane	23
Feedstocks and special products	215
Heavy fuel oil	19
Asphalt	13
Total	1,186
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.00
Depreciation and amortization	1.09
Other manufacturing(h)	3.98
Total	$	6.07

Supplementary Statistics (Unaudited)
	2013			2012			2011
Refining & Marketing Operating Statistics By Region
Midwest:
Refinery Throughputs (thousands of barrels per day):(i)
Crude oil refined	625
Other charge and blendstocks	54
Total	679
Sour Crude Oil Throughput percent	35
WTI-Priced Crude Oil Throughput percent	42
Refined Product Yields (thousands of barrels per day):(i)
Gasoline	371
Distillates	207
Propane	14
Feedstocks and special products	41
Heavy fuel oil	12
Asphalt	41
Total	686
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.47
Depreciation and amortization	1.74
Other manufacturing(h)	4.21
Total	$	7.42
Speedway Operating Statistics
Convenience stores at period-end	1,478			1,464			1,371
Gasoline & distillate sales (millions of gallons)	3,146			3,027			2,938
Gasoline & distillate gross margin (dollars per gallon)(j)	$	0.1441		$	0.1318		$	0.1308
Merchandise sales (in millions)	$	3,135		$	3,058		$	2,924
Merchandise gross margin (in millions)	$	825		$	795		$	719
Same store gasoline sales volume (period over period)	0.5		%	(0.8		)%	(1.7		)%
Same store merchandise sales (period over period)(k)	4.3		%	7.0		%	6.7		%
Pipeline Transportation Operating Statistics
Pipeline throughput (thousands of barrels per day):(l)
Crude oil pipelines	1,280			1,190			1,184
Refined products pipelines	911			980			1,031
Total	2,191			2,170			2,215

^(a)  Total average daily volumes of refined product sales to wholesale, branded and retail (Speedway segment) customers.

^(b)  Includes the impact of the Galveston Bay Refinery and Related Assets beginning on the February 1, 2013 acquisition date.

^(c)  Includes intersegment sales.

^(d)  Sales revenue less cost of refinery inputs and purchased products, divided by total refinery throughputs. Starting in the fourth quarter of 2013, direct operating costs are no longer included in the Refining & Marketing gross margin and the gross margin is calculated based on total refinery throughput. All prior periods presented have been recalculated to reflect a consistent approach.

^(e)  Based on calendar day capacity, which is an annual average that includes downtime for planned maintenance and other normal operating activities.

^(f)  Excludes inter-refinery volumes of 36 thousand barrels per day ("mbpd"), 25 mbpd and 28 mbpd for 2013, 2012 and 2011, respectively.

^(g)  Per barrel of total refinery throughputs.

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

⁽ⁱ⁾  Includes inter-refinery transfer volumes.

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

^(k)  Excludes cigarettes.

^(l)  On owned common-carrier pipelines, excluding equity method investments.

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Segment Information (Reconciliation Of Segment Income From Operations To Income Before Income Taxes) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2013		Dec. 31, 2012		Dec. 31, 2011
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income from operations	$ 1,008	$ 301	$ 960	$ 1,156	$ 1,189	$ 1,895	$ 1,307	$ 956	$ 3,425		$ 5,347		$ 3,745
Minnesota Assets sale settlement gain									6		177		12
Nonoperating income (expense) including related party activity									(179)	[1]	(109)	[1]	(26)	[1]
Income before income taxes									3,246		5,238		3,719
Operating Segments [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income from operations									3,791	[2]	5,624	[2]	4,061	[2]
Corporate, Non-Segment [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income from operations									(271)	[2],[3],[4]	(336)	[2],[3],[4]	(316)	[2],[3],[4]
Segment Reconciling Items [Member]
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Minnesota Assets sale settlement gain									0		183	[5]	0
Pension settlement expenses									$ (95)	[6]	$ (124)	[6]	$ 0	[6]

[1] Includes related party net interest and other financial income.

[2] Included in the Pipeline Transportation segment for 2013 and 2012 are $20 million and $4 million of corporate overhead costs attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. These expenses are not currently allocated to other segments.

[3] Corporate overhead costs attributable to MPLX were included in the Pipeline Transportation segment subsequent to MPLX’s October 31, 2012 initial public offering.

[4] 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.

[5] See Note 6.

[6] See Note 22.

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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, 2013		Dec. 31, 2012		Dec. 31, 2011
Fair Value, Assets and Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation [Abstract]
Beginning balance	$ 0		$ 0		$ 2,402
Contingent consideration agreement	(600)		0		0
Total realized and unrealized losses included in net income	(25)		(2)		0
Purchases of PFD Preferred Stock	0	[1]	0	[1]	10,326	[1]
Redemptions of PFD Preferred Stock	0	[1]	0	[1]	(12,730)	[1]
Settlements of derivative instruments	0		2		2
Ending balance	$ (625)		$ 0		$ 0

[1] For information on PFD Preferred Stock, see Note 7. 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.

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Disposition (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended						0 Months Ended	12 Months Ended	1 Months Ended	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012		Dec. 31, 2011	Dec. 01, 2010 Super America [Member] Store	Dec. 01, 2010 Wisconsin [Member] Store	Dec. 01, 2010 Minnesota Assets Sale Settlement Gain [Member] BPD	Dec. 31, 2011 Minnesota Assets Sale Settlement Gain [Member]	Jul. 31, 2012 Minnesota Assets Sale Settlement Gain [Member] Variable Interest Entity [Member]	Dec. 31, 2013 Minnesota Assets Sale Settlement Gain [Member] Variable Interest Entity [Member]	Dec. 31, 2012 Minnesota Assets Sale Settlement Gain [Member] Variable Interest Entity [Member]	Dec. 01, 2010 Minnesota Assets Sale Settlement Gain [Member] Variable Interest Entity [Member]	Dec. 01, 2010 Minnesota Assets Sale Settlement Gain [Member] Variable Interest Entity [Member] Maximum [Member]
Dispositions Of Assets [Line Items]
Refinery capacity (in barrels per calendar day)							74,000
Number of convenience stores disposed					166	6
Approximate transaction value							$ 935
Sale of assets, value of inventory							330
Cash proceeds, total							740		132
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
Buyer redeemed preferred equity interest	16	53		144					80	49
Cash proceeds, dividends on preferred equity interest									12	4
Cash proceeds, distribution from VIE's offering									40
Preferred equity interest	0	45	[1]	0					45
Income before income taxes recognized by the company as a result of the Minnesota Assets' successful IPO											183
Disposal Group, Amortization of Deferred Gain on Disposal										$ 86
Transition services following disposal, term (in number of months)	13 months

[1] See Note 6.

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Debt

12 Months Ended

Dec. 31, 2013

Text Block [Abstract]

Debt

Debt

Our outstanding borrowings at December 31, 2013 and 2012 consisted of the following:

	December 31,
(In millions)	2013			2012
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 2014-2028	395			355
MPLX Operations LLC revolving credit agreement due 2017	—			—
Trade receivables securitization facility due 2016	—			—
Total	3,395			3,355
Unamortized discount	(10		)	(10		)
Fair value adjustments(a)	11			16
Amounts due within one year	(23		)	(19		)
Total long-term debt due after one year	$	3,373		$	3,342

^(a)  See Notes 17 and 18 for information on interest rate swaps.

The following table shows five years of scheduled debt payments.

(In millions)
2014	$	23
2015	27
2016	777
2017	28
2018	30

There were no borrowings or letters of credit outstanding under the revolving credit agreements or the trade receivable securitization facility at December 31, 2013.

MPC Revolving Credit Agreement- We have a $2.5 billion unsecured revolving credit agreement ("Credit Agreement") in place with a maturity date of September 14, 2017. 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 our 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, the maturity date may be extended for up to two additional one-year periods subject to the approval of lenders holding greater than 50 percent of the commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the then-effective maturity date.

Borrowings under the Credit Agreement bear interest at either the Adjusted LIBO Rate (as defined in the Credit Agreement) plus a margin or the Alternate Base Rate (as defined in the Credit Agreement) plus a margin. We are charged various fees and expenses in connection with the Credit Agreement, including administrative agent fees, commitment fees on the unused portion of our borrowing capacity and fees related to issued and outstanding letters of credit. The applicable interest rates and certain of the fees fluctuate based on the credit ratings in effect from time to time on our long-term debt.

The Credit Agreement contains certain representations and warranties, affirmative and restrictive covenants and events of default that we consider to be usual and customary for arrangements of this type, including a financial covenant that requires us to maintain 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 the last day of each fiscal quarter. Other covenants, among other things, restrict our ability to incur debt, create liens on our assets or enter into transactions with affiliates. As of December 31, 2013, we were in compliance with the covenants contained in the Credit Agreement.

MPLX Operations LLC Revolving Credit Agreement- MPLX Operations LLC, an affiliate of MPC and wholly-owned subsidiary of MPLX LP, has a $500 million unsecured revolving credit agreement ("MPLX Credit Agreement") in place with a maturity date of October 31, 2017. The MPLX Credit Agreement includes letter of credit issuing capacity of up to $250 million and swingline loan capacity of up to $50 million. The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional $300 million, subject to certain conditions, including the consent of the lenders whose commitments would increase. In addition, the maturity date may be extended up to two additional one-year periods subject to the approval of lenders holding greater than 50 percent of the commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the then-effective maturity date.

Borrowings under the MPLX Credit Agreement bear interest at either the Adjusted LIBO Rate (as defined in the MPLX Credit Agreement) plus a margin, or the Alternate Base Rate (as defined in the MPLX Credit Agreement) plus a margin. MPLX is charged various fees and expenses in connection with the agreement, including administrative agent fees, commitment fees on the unused portion of the borrowing capacity and fees with respect to issued and outstanding letters of credit. The applicable interest rates and certain of the fees fluctuate based on MPLX's 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, or the credit ratings in effect from time to time on MPLX's long-term debt subsequent to the Rating Date (as defined in the MPLX Credit Agreement).

The MPLX Credit Agreement includes certain representations and warranties, affirmative and restrictive covenants and events of default that we consider to be usual and customary for an agreement of this type, including a financial covenant that requires MPLX to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 during the six-month period following certain acquisitions). Other covenants restrict MPLX from incurring debt, creating liens on its assets and entering into transactions with affiliates. As of December 31, 2013, MPLX was in compliance with the covenants contained in the MPLX Credit Agreement.

Trade receivables securitization facility - On December 18, 2013, we entered into a three-year, $1.3 billion trade receivables securitization facility with a group of financial institutions that act as committed purchasers, conduit purchasers, letter of credit issuers and managing agents under the facility. The facility is evidenced by a Receivables Purchase Agreement and a Second Amended and Restated Receivables Sale Agreement and replaces the previously existing accounts receivable facility that was set to expire on June 30, 2014.

The facility consists of one of our wholly-owned subsidiaries, Marathon Petroleum Company LP (“MPC LP”), selling or contributing on an on-going basis all of its trade receivables (including trade receivables acquired from Marathon Petroleum Trading Canada LLC, a wholly-owned subsidiary of MPC LP), together with all related security and interests in the proceeds thereof, without recourse, to another wholly-owned, bankruptcy-remote special purpose subsidiary, MPC Trade Receivables Company LLC (“TRC”), in exchange for a combination of cash, equity or a subordinated note issued by TRC to MPC LP. TRC, in turn, has the ability to finance its purchase of the receivables from MPC LP by selling undivided ownership interests in qualifying trade receivables, together with all related security and interests in the proceeds thereof, without recourse, to the purchasing group in exchange for cash proceeds. The facility also provides for the issuance of letters of credit of up to an initial amount of $1.25 billion, provided that the aggregate credit exposure of the purchasing group is limited to no more than $1.3 billion at any one time.

To the extent that TRC retains an ownership interest in the receivables it has purchased or received from MPC LP, such interest will be included in our consolidated financial statements solely as a result of the consolidation of the financial statements of TRC with those of MPC. The receivables sold or contributed to TRC are available first and foremost to satisfy claims of the creditors of TRC and are not available to satisfy the claims of creditors of MPC. TRC has granted a security interest in all of its assets to the purchasing group to secure its obligations under the Receivables Purchase Agreement.

Proceeds from the sale of undivided percentage ownership interests in qualifying receivables under the facility will be reflected as debt on our consolidated balance sheet, none of which was outstanding as of December 31, 2013. We will remain responsible for servicing the receivables sold to the purchasing group. TRC pays floating-rate interest charges and usage fees on amounts outstanding under the facility, if any, and certain other fees related to the administration of the facility and letters of credit that are issued and outstanding under the facility.

The Receivables Purchase Agreement and Second Amended and Restated Receivables Sale Agreement include representations and covenants that we consider usual and customary for arrangements of this type. Trade receivables are subject to customary criteria, limits and reserves before being deemed to qualify for sale by TRC pursuant to the facility. In addition, further purchases of qualified trade receivables under the facility are subject to termination, and TRC may be subject to default fees, upon the occurrence of certain amortization events that are included in the Receivables Purchase Agreement, which we consider to be usual and customary for arrangements of this type.

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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, 2013		Dec. 31, 2012		Dec. 31, 2011
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$ 161		$ 67		$ 5
Net income taxes paid to taxing authorities	1,099	[1]	1,211	[1]	617	[1]
Income taxes paid to Marathon Oil under tax sharing agreement			181
Non-cash investing and financing activities:
Capital lease obligations increase	61		62		26
Non-cash contributions from Marathon Oil(a)	43		0		0
Preferred equity interest received in contract settlement	0		45	[2]	0
Preferred equity interest dividend received in-kind	0		1		0
Acquisitions:
Contingent consideration	600	[3]	0		0
Payable to seller	6	[3]	0		0
Intangible asset acquired	0		3		0
Liability assumed	0		2		0
Marathon Oil Companies [Member]
Non-cash investing and financing activities:
Property, Plant and Equipment contributed by Marathon Oil	0		0		81
Non-cash contributions from Marathon Oil(a)					$ 57	[4]

[1] U.S. 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 tax credits. See Note 25.

[2] See Note 6.

[3] See Note 5.

[4] See Note 7.

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Defined Benefit Pension And Other Postretirement Plans (Estimated Future Benefit Payments) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013
Pension Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2014	$ 186
2015	181
2016	177
2017	178
2018	175
2019 through 2023	814
Other Benefits [Member]
Defined Benefit Plan Disclosure [Line Items]
2014	26	[1]
2015	29	[1]
2016	32	[1]
2017	34	[1]
2018	38	[1]
2019 through 2023	$ 231	[1]

[1] Effective 2013, as a result of the Patient Protection and Affordable Care Act, 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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Defined Benefit Pension And Other Postretirement Plans (Summarizes Assumed Health Care Cost Trend Rates) (Detail)	12 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Medical, Pre-65 [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for the following year	8.00%	8.00%	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	2020	2018
Medical, Post-65 [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for the following year			7.00%	[1]
Rate to which the cost trend rate is assumed to decline			5.00%	[1]
Year that the rate reaches the ultimate trend rate			2017	[1]
Medical, Post-65 [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for the following year	4.00%
Prescription Drugs [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for the following year	7.00%	7.00%	7.50%
Rate to which the cost trend rate is assumed to decline	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 percent.

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Related Party Transactions (Payables To Related Parties) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Payables to related parties	$ 16	$ 13
LOOP [Member]
Related Party Transaction [Line Items]
Payables to related parties	3	4
TAAE [Member]
Related Party Transaction [Line Items]
Payables to related parties	2	0
TACE [Member]
Related Party Transaction [Line Items]
Payables to related parties	4	2
TAME [Member]
Related Party Transaction [Line Items]
Payables to related parties	5	5
Other Equity Method Investees [Member]
Related Party Transaction [Line Items]
Payables to related parties	$ 2	$ 2

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Acquisitions and Investments (Tables)

12 Months Ended

Dec. 31, 2013

Business Combinations [Abstract]

Components Of The Fair Value Of Consideration Transferred [Table Text Block]

The components of the fair value of consideration transferred are as follows:

(In millions)
Cash	$	1,491
Fair value of contingent consideration as of acquisition date	600
Payable to seller	6
Post-closing adjustment	(9		)
Total consideration	$	2,088

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

The following table summarizes the final amounts assigned to the assets acquired and liabilities assumed as of the acquisition date.

(In millions)
Inventories	$	935
Other current assets	1
Property, plant and equipment, net	1,274
Other noncurrent assets	88
Accounts payable	(12		)
Payroll and benefits payable	(14		)
Long-term debt due within one year(a)	(2		)
Other current liabilities	(6		)
Long-term debt(a)	(58		)
Defined benefit postretirement plan obligations	(43		)
Deferred credits and other liabilities	(75		)
Total	$	2,088

^(a) Represents a capital lease obligation assumed

Business Acquisition, Pro Forma Information [Table Text Block]

The following unaudited pro forma financial information presents consolidated results assuming the Galveston Bay Refinery and Related Assets acquisition occurred on January 1, 2012. The pro forma financial information does not give effect to potential synergies that could result from the acquisition and is not necessarily indicative of the results of future operations.

(In millions, except per share data)	2013		2012
Sales and other operating revenues (including consumer excise taxes)	$	102,120	$	104,165
Net income attributable to MPC	2,167		3,625
Net income attributable to MPC per share - basic	$	6.88	$	10.66
Net income attributable to MPC per share - diluted	6.84		10.60

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Income Taxes

12 Months Ended

Dec. 31, 2013

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Income tax provisions (benefits) were:

	2013							2012							2011
(In millions)	Current		Deferred			Total		Current			Deferred		Total		Current		Deferred			Total
Federal	$	954	$	20		$	974	$	1,185		$	432	$	1,617	$	1,040	$	139		$	1,179
State and local	131		8			139		169			57		226		152		(16		)	136
Foreign	5		(5		)	—		(1		)	3		2		15		—			15
Total	$	1,090	$	23		$	1,113	$	1,353		$	492	$	1,845	$	1,207	$	123		$	1,330

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:

	2013		2012		2011
Statutory rate applied to income before income taxes	35	%	35	%	35	%
State and local income taxes, net of federal income tax effects	3		2		2
Domestic manufacturing deduction	(2	)	(1	)	(1	)
Other	(2	)	(1	)	—
Provision for income taxes	34	%	35	%	36	%

Deferred tax assets and liabilities resulted from the following:

	December 31,
(In millions)	2013		2012
Deferred tax assets:
Employee benefits	$	483	$	585
Environmental	37		35
Other	49		55
Total deferred tax assets	569		675
Deferred tax liabilities:
Property, plant and equipment	2,290		2,225
Inventories	614		610
Investments in subsidiaries and affiliates	267		307
Other	70		29
Total deferred tax liabilities	3,241		3,171
Net deferred tax liabilities	$	2,672	$	2,496

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

	December 31,
(In millions)	2013		2012
Assets:
Other noncurrent assets	$	2	$	—
Liabilities:
Accrued taxes	370		446
Deferred income taxes	2,304		2,050
Net deferred tax liabilities	$	2,672	$	2,496

The ability to realize the benefit of foreign tax credits is based on certain estimates concerning future financial conditions, income generated from foreign sources and our tax profile in the years that such credits may be claimed. A federal valuation allowance was established in 2013 for $2 million due to changes in the expected realizability of foreign tax credits.

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. 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, 2013, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:

United States Federal	2010	-	2012
States	2004	-	2012

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. During 2013, we settled with Marathon Oil our U.S. federal and related state return liabilities for the 2008-2009 tax years, resulting in a reduction in unrecognized tax benefits of $21 million, which are also reflected in the table below as settlements.

During 2013, we settled with Marathon Oil for the 2011 period prior to the spinoff based on filed tax returns and in accordance with the tax sharing agreement, resulting in a $39 million increase to additional paid-in capital.

The following table summarizes the activity in unrecognized tax benefits:

(In millions)	2013			2012			2011
January 1 balance	$	40		$	20		$	14
Additions for tax positions of prior years	30			32			50
Reductions for tax positions of prior years	(25		)	(6		)	—
Settlements	(30		)	(6		)	(44		)
Statute of limitations	(2		)	—			—
December 31 balance	$	13		$	40		$	20

If the unrecognized tax benefits as of December 31, 2013 were recognized, $6 million would affect our effective income tax rate. There were $5 million of uncertain tax positions as of December 31, 2013 for which it is reasonably possible that the amount of unrecognized tax benefits would significantly increase or decrease during the next twelve months.

Interest and penalties related to income taxes are recorded as part of the provision for income taxes. Such interest and penalties were net receipts (expenses) of ($11 million), $1 million and ($5 million) in 2013, 2012 and 2011. As of December 31, 2013 and 2012, $15 million and $9 million of interest and penalties were accrued related to income taxes.

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Property, Plant And Equipment (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2013	Dec. 31, 2012
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 21,793	$ 19,409
Property, plant and equipment, accumulated depreciation	7,872	6,766
Assets Held Under Capital Leases [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	510	417
Property, plant and equipment, accumulated depreciation	111	79
Construction In Progress [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 747	$ 520