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, 2014

Commission file number 001-35054

Marathon Petroleum Corporation

(Exact name of registrant as specified in its charter)

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

539 South Main Street, Findlay, OH 45840-3229

(Address of principal executive offices)

(419) 422-2121

(Registrant’s telephone number, including area code)

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

Title of Each Class	Name of Each Exchange on Which Registered
Common Stock, par value $.01	New York Stock Exchange

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

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

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

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

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

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

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

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

The aggregate market value of Common Stock held by non-affiliates as of June 30, 2014 was approximately $22.2 billion. This amount is based on the closing price of the registrant’s Common Stock on the New York Stock Exchange on June 30, 2014. 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 273,062,880 shares of Marathon Petroleum Corporation Common Stock outstanding as of February 13, 2015.

Documents Incorporated By Reference

Portions of the registrant’s proxy statement relating to its 2015 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	28
	Item 1B.	Unresolved Staff Comments	38
	Item 2.	Properties	38
	Item 3.	Legal Proceedings	38
	Item 4.	Mine Safety Disclosures	39
PART II
	Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	40
	Item 6.	Selected Financial Data	41
	Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
	Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	69
	Item 8.	Financial Statements and Supplementary Data	72
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	126
	Item 9A.	Controls and Procedures	126
	Item 9B.	Other Information	126
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	128
	Item 11.	Executive Compensation	128
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	129
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	129
	Item 14.	Principal Accountant Fees and Services	129
PART IV
	Item 15.	Exhibits and Financial Statement Schedules	130
		SIGNATURES	134

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,” “potential,” “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;

• an easing or lifting of the U.S. crude oil export ban;

• 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;

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• 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;

• modifications to MPLX LP earnings and distribution growth objectives;

• the ability to successfully implement growth opportunities;

• the ability to successfully integrate the acquired Hess Corporation retail operations and achieve the strategic and other expected objectives relating to the acquisition including any expected synergies;

• 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 127 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 refining, marketing, retail and transportation businesses in the United States and the largest east of the Mississippi. 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 it offers.

• Refining & Marketing—refines crude oil and other feedstocks at our seven refineries in the Gulf Coast and Midwest regions of the United States, purchases refined products and ethanol 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, East Coast and Southeast.

• 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.

See Item 8. Financial Statements and Supplementary Data – Note 11 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 on June 30, 2011 (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 September 30, 2014, we acquired from Hess Corporation (“Hess”) all of its retail locations, transport operations and shipper history on various pipelines, including approximately 40 thousand barrels per day (“mbpd”) on Colonial Pipeline, for $2.82 billion. We refer to these assets as “Hess’ Retail Operations and Related Assets” and substantially all of these assets are part of our Speedway segment. This acquisition significantly expands our Speedway presence from nine to 22 states throughout the East Coast and Southeast and is aligned with our strategy to grow higher-valued, stable cash flow businesses. This acquisition also enables us to further leverage our integrated refining and transportation operations, providing an outlet for an incremental 200 mbpd of assured sales from our refining system. The transaction was funded with a combination of debt and available cash. Our financial results and operating statistics for the periods prior to the acquisition do not include amounts for Hess’ Retail Operations and Related Assets.

In July 2014, we exercised our option to acquire a 35 percent ownership interest in Enbridge Inc.’s Southern Access Extension (“SAX”) pipeline, which will run from Flanagan, Ill. to Patoka, Ill. and is expected to be operational in late 2015. This option resulted from our agreement to be the anchor shipper on the SAX pipeline and our commitment to the Sandpiper pipeline project as discussed below. During 2014, we made contributions of $120 million to Illinois Extension Pipeline Company, LLC (“Illinois Extension Pipeline”) to fund our portion of the construction costs incurred-to-date on the SAX pipeline project.

On April 1, 2014, we purchased a facility in Cincinnati, Ohio from Felda Iffco Sdn Bhd, Malaysia for $40 million. The plant currently produces biodiesel, glycerin and other by-products. The capacity of the plant is approximately 60 million gallons per year.

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In March 2014, we acquired from Chevron Raven Ridge Pipe Line Company an additional seven percent interest in Explorer Pipeline Company (“Explorer”) for $77 million, bringing our ownership interest to 25 percent. Explorer owns approximately 1,900 miles of refined products pipeline from Lake Charles, Louisiana to Hammond, Indiana.

In November 2013, we agreed with Enbridge Energy Partners L.P. (“Enbridge Energy Partners”) to serve as an anchor shipper for the Sandpiper pipeline, which will run from Beaver Lodge, North Dakota to Superior, Wisconsin. 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 contributions of $192 million during 2014 and have contributed $216 million since project inception. 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 Energy Partners’ North Dakota System when the Sandpiper pipeline is placed into service, which is expected to be in 2017. Enbridge Energy Partners’ 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.

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.

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 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. In July 2014, we paid BP $180 million for the first period’s contingent earnout. These assets are part of our Refining & Marketing and Pipeline Transportation segments. Our financial results and operating statistics for the 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 these acquisitions and investments. See Item 8. Financial Statements and Supplementary Data – Note 26 for information regarding our future contributions to the SAX pipeline project and the Sandpiper pipeline project.

MPLX LP

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 19.9 million common units, which represented the sale by us of a 26.4 percent interest in MPLX.

As of December 31, 2014, we owned a 71.5 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.

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. We originally retained a 49 percent limited partner interest in Pipe Line Holdings.

On May 1, 2013, we sold a five percent interest in Pipe Line Holdings to MPLX for $100 million, which was financed by MPLX with cash on hand.

On March 1, 2014, we sold MPLX a 13 percent interest in Pipe Line Holdings for $310 million. MPLX financed this transaction with $40 million of cash on-hand and $270 million of borrowings on its bank revolving credit agreement.

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On October 30, 2014, we announced plans to substantially accelerate the growth of MPLX, which is expected to provide unitholders an average annual distribution growth rate percentage in the mid-20s over the next five years as we build meaningful scale more quickly. We believe this increased scale provides MPLX greater flexibility to fund organic projects and to pursue acquisition opportunities.

On December 1, 2014, we sold and contributed interests in Pipe Line Holdings totaling 30.5 percent to MPLX for $600 million in cash and 2.9 million MPLX common units valued at $200 million. MPLX financed the sales portion of this transaction with $600 million of borrowings on its bank revolving credit facility.

On December 8, 2014, MPLX completed a public offering of 3.5 million common units at a price to the public of $66.68 per common unit, with net proceeds of $221 million. MPLX used the net proceeds from this offering to repay borrowings under its bank revolving credit facility and for general partnership purposes. On December 10, 2014, we exercised our right to maintain our two percent general partner interest in MPLX by purchasing 130 thousand general partner units for $9 million.

On February 12, 2015, MPLX completed its initial underwritten public offering of $500 million aggregate principal amount of four percent unsecured senior notes due February 15, 2025 (the “Senior Notes”). The Senior Notes were offered at a price to the public of 99.64 percent of par. The net proceeds of this offering were used to repay the amounts outstanding under its bank revolving credit facility, as well as for general partnership purposes.

See Item 8. Financial Statements and Supplementary Data – Note 4 for additional information on MPLX.

Our Competitive Strengths

High Quality Refining Assets

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. While we have historically processed significant quantities of heavy and sour crude oils, our refineries have the ability to process up to 68 percent light sweet crude oils.

Strategic Location

The geographic locations of our refineries 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 refined product 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, 2014

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, 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 largestprivate 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 other raw material supplies and refined product distribution, and further allows for important economies of scale across our system.

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General Partner and Sponsor of MPLX

Our investment in MPLX should allow us to enhance our share price through our limited partner and general partner interests which tend to receive higher market multiples. MPLX also provides us an efficient vehicle to invest in organic projects and pursue acquisitions of midstream assets. MPLX’s significant liquidity and access to the capital markets should provide 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 midstream assets that can potentially be sold and/or contributed to MPLX, providing MPLX with a competitive advantage. As of December 31, 2014, these assets included:

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

• 19 owned or leased inland towboats and 211 owned or leased inland barges;

• 63 owned and operated light product terminals with approximately 20 million barrels of storage capacity and 192 loading lanes;

• 18 owned and operated asphalt terminals with approximately 5 million barrels of storage capacity and 65 loading lanes;

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

• 2,210 owned or leased railcars;

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

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

• seven owned and 11 non-owned docks at our refineries;

• a condensate splitter at our Canton refinery; and

• approximately 20 billion gallons of fuels distribution.

We continue to focus resources on growing this portfolio of midstream assets, including investments in the Sandpiper and SAX pipeline projects and a condensate splitter project at our Catlettsburg refinery. We broadly estimate these assets and growth projects can generate annual earnings before interest, tax, depreciation and amortization (“EBITDA”) of $1.6 billion. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for additional information on these pipeline investments.

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 that Speedway LLC, a wholly-owned subsidiary, operates the second largest chain of company-owned and operated retail gasoline and convenience stores in the United States, with approximately 2,750 convenience stores in 22 states throughout the Midwest, East Coast and Southeast. The Marathon brand is an established motor fuel brand in the Midwest and Southeast regions of the United States, comprised of approximately 5,460 retail outlets operated by independent entrepreneurs in 19 states as of December 31, 2014. In addition, as part of the acquisition of the Galveston Bay Refinery and Related Assets in 2013 and Hess’ Retail Operations and Related Assets in 2014, we obtained retail marketing contracts that provide us with the opportunity to convert the associated retail outlets to the Marathon brand. As of December 31, 2014, we had outstanding retail marketing contract assignments for approximately 590 retail outlets. We believe our distribution system allows us to maximize the sales value of our products and minimize cost.

Attractive Growth Opportunities

We believe we have attractive growth opportunities. Our capital and investment budget for 2015 of $2.53 billion includes $1.28 billion for the Refining & Marketing segment (which includes $234 million for midstream investments), $452 million for the Speedway segment and $659 million for the Pipeline Transportation segment.

Our Refining & Marketing segment’s midstream investments include building condensate splitters at our Canton, Ohio and Catlettsburg, Kentucky refineries to increase our capacity to process condensate from the Utica Shale region. The condensate splitter at our Canton refinery began operation at the end of 2014 and we expect to complete the condensate splitter at our Catlettsburg refinery in 2015. Our Refining & Marketing segment’s investments also include refining margin enhancement projects, including projects to further capture synergies at our Galveston Bay refinery, increase our distillate production, expand our export capacity and increase our capacity to process condensates and light crude oils.

Our Speedway segment investments include converting and integrating Hess’ Retail Operations and Related Assets, constructing new convenience stores and rebuilding existing locations. We also anticipate acquiring high quality stores through opportunistic acquisitions.

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Our Pipeline Transportation segment’s midstream investments include investments in equity interests in the Sandpiper and SAX pipeline projects that will transport crude oil from growing North American hydrocarbon production regions to our refineries. MPLX is also pursuing the Cornerstone pipeline project, which will connect the Utica Shale production to our Canton, Ohio refinery. There are also potential opportunities for additional build-out projects to provide transportation solutions from the Utica Shale region to a wide range of markets.

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 segment, which was significantly expanded with the acquisition of Hess’ Retail Operations and Related Assets, and our Pipeline Transportation segment 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, 2014, we had $1.49 billion in cash and cash equivalents and $3.80 billion in unused committed borrowing facilities, excluding MPLX’s credit facility. We had $6.64 billion of debt at year-end, which represented 37 percent of our total capitalization. This combination of strong liquidity and manageable leverage provides financial flexibility 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 2014 with a solid 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 and reliability of our operations. We proactively address our regulatory requirements and encourage our operations to improve their environmental performance, with our 2014 designated environmental incidents showing an additional 15 percent reduction over 2013 results. Our Robinson, Illinois refinery had no significant designated environmental incidents in 2014, and our Galveston Bay refinery achieved further reduction of approximately 87 percent in designated environmental incidents since we acquired it on February 1, 2013.

Grow Higher-Valued, Stable Cash Flow Businesses

We intend to allocate significantly more capital to grow our midstream and retail businesses. These businesses typically have more predictable and stable income and cash flows compared to our refining operations and we believe investors assign a higher value to businesses with stable cash flows. Our capital and investment budget for 2015 includes investments in both our Refining & Marketing and Pipeline Transportation segments related to midstream assets. We have budgeted $234 million for midstream assets that are part of the Refining & Marketing segment, $659 million for the Pipeline Transportation segment and $452 million for the Speedway segment.

We plan to substantially accelerate the growth of MPLX and intend to evolve it into a large cap, diversified MLP. 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. We also plan to pursue acquisitions of midstream assets through MPLX, both within our existing geographic footprint and in new areas. We expect there will continue to 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 grow our midstream business primarily through MPLX.

We significantly expanded Speedway’s presence along the East Coast and Southeast through our acquisition of Hess’ Retail Operations and Related Assets. We intend to continue growing Speedway’s sales and profitability by focusing on the conversion and integration of these locations, from which we expect to realize increased merchandise sales and other synergies. We also remain focused on organic growth through constructing new stores, rebuilding old stores, acquiring high quality stores through opportunistic acquisitions and improving margins at our existing operations. We have identified numerous opportunities for new convenience stores or store rebuilds in our existing market, western Pennsylvania and Tennessee. In addition, our highly successful Speedy Rewards^® customer loyalty program, which has more than 3.9 million active members as of December 31, 2014, provides us with a unique competitive advantage and opportunity to increase our Speedway customer base with existing and new Speedway locations, including the stores recently acquired from Hess.

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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.

We intend to enhance our margins in the Refining & Marketing segment by capturing synergies at our Galveston Bay refinery, increasing our condensate and light crude oil processing capacity, growing our distillate production and expanding our exports. For example, we recently completed construction of a condensate splitter at our Canton refinery and we have a project underway to increase condensate processing capacity at our Catlettsburg refinery. We also have projects to increase light crude oil processing capacity at our Robinson 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. We will continue to evaluate opportunities to expand our existing asset base, with an emphasis on increasing distillate production, light crude oil processing and export capabilities and synergistic 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 150 percent since becoming a stand-alone company in June 2011 and our board of directors has authorized share repurchases totaling $8.0 billion. Through open market purchases and two accelerated share repurchase (“ASR”) programs, we repurchased 89 million shares of our common stock for approximately $6.27 billion, representing approximately 25 percent of our outstanding common shares when we became a stand-alone company in June 2011. After the effects of these repurchases, $1.73 billion of the $8.0 billion total authorization was available for future repurchases as of December 31, 2014.

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 Hess’ Retail Operations and Related Assets significantly expands our Speedway presence from nine to 22 states throughout the East Coast and Southeast and enables us to further leverage our integrated refining and transportation operations, providing an outlet for an incremental 200 mbpd of assured sales from our refining system.

Utilize and Enhance our High Quality Employee Workforce

We utilize our high quality employee workforce by continuing to leverage our commercial skills. In addition, we continue 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 portfolio of midstream assets and growth projects that can potentially be sold and/or contributed 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 portfolio of midstream assets and growth projects that can potentially be sold and/or contributed to MPLX will achieve expected earnings. 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 portfolio of midstream assets and growth projects that can potentially be sold and/or contributed to 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. 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 1,731 thousand barrels per calender day (“mbpcd”). During 2014, our refineries processed 1,622 mbpd of crude oil and 184 mbpd of other charge and blendstocks. During 2013, our refineries processed 1,589 mbpd of crude oil and 213 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, 2014.

Refinery	Crude Oil Refining Capacity (mbpcd)(a)	Tank Storage Capacity (million barrels)	Number of Tanks
Garyville, Louisiana	522	16.8	78
Galveston Bay, Texas City, Texas	451	16.3	156
Catlettsburg, Kentucky	242	5.6	115
Robinson, Illinois	212	6.3	95
Detroit, Michigan	130	6.5	86
Canton, Ohio	90	3.0	75
Texas City, Texas	84	4.7	61
Total	1,731	59.2	666

^(a)  Refining throughput can exceed crude oil capacity due to the processing of other charge and blendstocks 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 ultra-low sulfur diesel (“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 efficiently utilize our processing capacity. For example, naphtha may be moved from Texas City to Robinson where excess reforming capacity is available. Also, shipping intermediate products between facilities during partial refinery shutdowns allows us 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, asphalt, polymer-grade propylene, propane, slurry, sulfur and dry gas. The refinery has access to the export market and multiple options to sell refined products. 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, refinery-grade propylene, heavy fuel oil, fuel-grade coke, dry gas and sulfur. The refinery has access to the export market and multiple options to sell refined products. Our cogeneration facility, which supplies the Galveston Bay refinery, currently has 1,055 megawatts of electrical production capacity and can produce 4.3 million pounds of steam per hour. Approximately 45 percent of the power generated in 2014 was 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, 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 gasoline, distillates, propane, anode-grade coke, aromatics and slurry. 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 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 crude oils.

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 production from the nearby Utica Shale, into gasoline, distillates, asphalt, roofing flux, propane, refinery-grade propylene and slurry. In December 2014, we completed construction of a condensate splitter at our Canton refinery, which increased our capacity to process condensate from the Utica Shale region.

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, dry gas and slurry. Our Texas City refinery earned designation as an OSHA VPP Star site in 2012.

As of December 31, 2014, 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 2014 was 84 mbpd for the refinery loading racks and 911 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)	2014	2013	2012
Gasoline	869	921	738
Distillates	580	572	433
Propane	35	37	26
Feedstocks and special products	276	221	109
Heavy fuel oil	25	31	18
Asphalt	54	54	62
Total	1,839	1,836	1,386

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)	2014	2013	2012
United States	1,120	946	649
Canada	223	255	195
Middle East and other international	279	388	351
Total	1,622	1,589	1,195

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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Renewable Fuels

We currently own a biofuel production facility in Cincinnati, Ohio that produces biodiesel, glycerin and other by-products. The capacity of the plant is approximately 60 million gallons per year.

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 (18 mbpd) and are managed by a co-owner.

Refined Product Marketing

We believe we are one of the largest wholesale suppliers of gasoline and distillates to resellers and consumers within our 19-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, 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)	2014	2013	2012
Gasoline	79	38	1
Distillates	191	173	114
Asphalt	5	6	8
Other	—	1	—
Total	275	218	123

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	2014		2013		2012
Private-brand marketers, commercial and industrial customers, including spot market	73	%	75	%	72	%
Marathon-branded independent entrepreneurs	15	%	16	%	17	%
Speedway® convenience stores	12	%	9	%	11	%

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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, 2014.

State	Approximate Number of Marathon® Retail Outlets
Alabama	202
Florida	523
Georgia	297
Illinois	344
Indiana	648
Kentucky	586
Louisiana	1
Maryland	1
Michigan	753
Minnesota	74
Mississippi	38
North Carolina	297
Ohio	857
Pennsylvania	60
South Carolina	129
Tennessee	328
Virginia	129
West Virginia	124
Wisconsin	64
Total	5,455

As of December 31, 2014, we also had branded marketing contract assignments for retail outlets, primarily in Florida, Mississippi, Tennessee and Alabama and branded lessee dealer marketing contract assignments, primarily in Connecticut, Maryland and New York, which we acquired as either part of the Galveston Bay Refinery and Related Assets acquisition in 2013 or the acquisition of Hess’ Retail Operations and Related Assets in 2014. As of December 31, 2014, we had outstanding retail marketing contract assignments for approximately 590 retail outlets.

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

Refined Product Sales by Product Group (mbpd)	2014	2013	2012
Gasoline	1,116	1,126	916
Distillates	623	615	463
Propane	34	37	27
Feedstocks and special products	268	214	112
Heavy fuel oil	28	29	19
Asphalt	56	54	62
Total	2,125	2,075	1,599

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 and on the spot market. In addition, we sell diesel fuel and gasoline for export to international customers. We sold 55 percent of our gasoline sales volumes and 89 percent of our distillates sales volumes on a wholesale or spot market basis in 2014. The demand for gasoline and distillates is seasonal in many of our markets, with demand typically at its highest levels during the summer months.

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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 78 mbpd in 2014, 74 mbpd in 2013 and 68 mbpd in 2012. We sell reformulated gasoline, which is also blended with ethanol, in 12 states in our marketing area. We also sell biodiesel-blended diesel fuel in 15 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.

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 these 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 268 mbpd in 2014 from 214 mbpd in 2013 and 112 mbpd in 2012 primarily due to our 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. 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, 2014, we owned and operated 63 light product and 18 asphalt terminals. Our light product and asphalt terminals averaged 1,426 mbpd and 27 mbpd of throughput in 2014, 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 118 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, 2014.

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	2.8	83	22
Georgia	4	0.9	38	9
Illinois	4	1.2	44	14
Indiana	6	2.9	72	17
Kentucky	6	2.3	68	24
Louisiana	1	0.1	9	2
Michigan	9	2.3	89	28
North Carolina	4	1.1	50	13
Ohio	13	3.6	156	33
Pennsylvania	1	0.2	8	2
South Carolina	1	0.3	9	3
Tennessee	4	1.0	44	12
West Virginia	2	0.1	10	2
Wisconsin	2	0.8	19	7
Subtotal light product terminals	63	20.0	719	192
Asphalt Terminals:
Florida	1	0.2	4	3
Illinois	2	0.1	33	6
Indiana	2	0.5	19	6
Kentucky	4	0.5	60	14
Louisiana	1	0.1	11	2
Michigan	1	—	—	8
Ohio	4	2.1	74	10
Pennsylvania	1	0.5	22	8
Tennessee	2	0.5	44	8
Subtotal asphalt terminals	18	4.5	267	65
Total owned and operated terminals	81	24.5	986	257

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Transportation

As of December 31, 2014, our marine transportation operations included 18 owned and one leased towboat, as well as 199 owned and 12 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	61	886
25,000 barrels and over	150	4,392
Total	211	5,278
Inland towboats:
Less than 2,000 horsepower	2
2,000 horsepower and over	17
Total	19

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

As of December 31, 2014, we owned 142 transport trucks and 151 trailers with an aggregate capacity of 1.4 million gallons for the movement of refined products and crude oil. In addition, we had 2,183 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	—	794	794	20,000-30,000 gallons
High pressure tank cars	—	1,171	1,171	33,500 gallons
Open-top hoppers	27	218	245	4,000 cubic feet
	27	2,183	2,210

Speedway

Our Speedway segment sells gasoline, diesel and merchandise through convenience stores that it owns and operates, primarily under the Speedway and Hess brands. We have the right to use the Hess brand through September 30, 2017. We are in the process of converting convenience stores acquired from Hess to the Speedway brand, which we target to complete by the end of 2016. Speedway convenience stores offer a wide variety of merchandise, including prepared foods, beverages and non-food items. Speedway’s Speedy Rewards® loyalty program has been a highly successful loyalty program since its inception in 2004, with a consistently growing base of more than 3.9 million active members as of December 31, 2014. 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. Merchandise margin as a percent of total gross margin for Speedway decreased in 2014, primarily related to the convenience stores acquired from Hess. The following table sets forth Speedway merchandise statistics for the past three years.

Speedway Merchandise Statistics	2014			2013			2012
Merchandise sales (in millions)	$	3,611		$	3,135		$	3,058
Merchandise gross margin (in millions)	975			825			795
Merchandise as a percent of total gross margin	57		%	65		%	67		%

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As of December 31, 2014, Speedway had 2,746 convenience stores in 22 states. The following table sets forth the number of convenience stores by state owned by our Speedway segment as of December 31, 2014.

State	Number of Convenience Stores
Alabama	2
Connecticut	1
Delaware	4
Florida	248
Georgia	6
Illinois	107
Indiana	307
Kentucky	144
Massachusetts	117
Michigan	303
New Hampshire	12
New Jersey	72
New York	243
North Carolina	288
Ohio	487
Pennsylvania	105
Rhode Island	20
South Carolina	61
Tennessee	26
Virginia	68
West Virginia	62
Wisconsin	63
Total	2,746

Pipeline Transportation

As of December 31, 2014, 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.

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. As of December 31, 2014, we owned a 71.5 percent interest in MPLX, including the two percent general partner interest, and MPLX’s assets consisted of a 99.5 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.

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As of December 31, 2014, 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 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 these pipeline systems and storage assets as of December 31, 2014.

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	197	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	1,255
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	244	Catlettsburg, Canton
Robinson, IL products system(b)	Various	Various	10”-16”	1,171	548	Robinson
Louisville, KY Airport products system	Louisville, KY	Louisville, KY	6”-8”	14	29	Robinson
Inactive pipelines(b)				85	N/A
Total				1,902	1,425
Wood River, IL barge dock (mbpd)					78	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.

^(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 12 percent of the crude oil and refined product shipments on these common carrier pipelines in 2014, 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)	2014	2013	2012
Crude oil pipelines	1,041	1,075	1,032
Refined products pipelines	878	911	980
Total	1,919	1,986	2,012

^(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.

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MPC-Retained Assets and Investments

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)	2014	2013	2012
Crude oil pipelines	1,241	1,293	1,191
Refined products pipelines	878	911	980
Total	2,119	2,204	2,171

As of December 31, 2014, 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”	643	33	%	Yes
Maumee	Lima, OH	Samaria, MI	22”	95	26	%	No
Total				738

As of December 31, 2014, 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:
Illinois Extension Pipeline Company LLC(a)	Flanagan, IL	Patoka, IL	TBD	TBD	35	%	No
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)(b)	Plentywood, MT	Clearbrook, MN	TBD	TBD	38	%	No
Total				105
Products pipeline companies:
Ascension Pipeline Company LLC(a)	Riverside, LA	Garyville	TBD	TBD	50	%	No
Centennial Pipeline LLC(c)	Beaumont, TX	Bourbon, IL	24”-26”	795	50	%	Yes
Explorer Pipeline Company	Lake Charles, LA	Hammond, IN	12”-28”	1,883	25	%	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)  The pipeline diameter and length for these companies will be determined when these pipeline projects are placed into service.

^(b)  We own 38 percent of the Class B units in this entity. Upon completion of the Sandpiper pipeline project, which is to construct a pipeline running from Beaver Lodge, North Dakota to Superior, Wisconsin and targeted for completion in 2017, our Class B units will be converted to an approximate 27 percent ownership interest in the Class A units of this entity.

^(c)  Includes 491 miles of inactive pipeline.

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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	85
St. James, LA to Garyville, LA	30”	20	620
Other	6”-14”	2	15
Inactive pipelines		8	N/A
Total		183	720
Products pipeline systems:
Robinson, IL to Lima, OH	8”	250	18
Louisville, KY to Lexington, KY (a)	8”	87	37
Woodhaven, MI to Detroit, MI	4”	26	12
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	183

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

As of December 31, 2014, we owned or leased 60 private tanks with storage capacity of approximately 6.5 million barrels, which are located along MPL and ORPL pipelines.

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 2014 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, 2014. 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; 12 refiners or marketers in the supply of refined products to refiner-branded independent entrepreneurs; and approximately 910 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 retail 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 sales of retail gasoline and diesel fuel. Energy Analysts International, Inc. estimated such retailers had approximately 14 percent of the U.S. gasoline market in mid-2014.

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 (“WTI”) and Light Louisiana Sweet (“LLS”) crude oils and other market structure differentials also affect our operating results.

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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 environmental performance. We also have a Corporate Emergency Response Team that 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, 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. Additionally, we continuously strive to improve operational and energy efficiencies through resource and energy conservation where practicable.

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

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 many 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 CAA, 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 June 2014, the Supreme Court limited the EPA’s greenhouse gas permitting authority to only those sources that also trigger Prevention of Significant Deterioration (“PSD”) conventional pollutants. A few MPC projects triggered greenhouse gas permitting requirements but any additional capital spend will likely not be significant. Legal challenges continue in the wake of the Supreme Court decision. The EPA has proposed New Source Performance Standards for greenhouse gas emissions for new and existing electric utility generating units. This could impact electric and natural gas rates for all our operations and could impose new requirements on the combined heat and power unit we operate. 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 such suits have been largely unsuccessful. 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. In sum, requiring reductions in greenhouse gas emissions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any greenhouse gas emissions programs, including acquiring emission credits or allotments. These requirements may also significantly affect MPC’s refinery operations and may have an indirect effect on our business, financial condition and results of operations. The extent and magnitude of the impact from greenhouse gas regulation or legislation cannot be reasonably estimated due to the uncertainty regarding the additional measures and how they will be implemented.

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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. In 2013, the Obama administration significantly increased the estimate to $36 per ton. In response to the regulated community and Congress’ critiques of how the SCC was developed, the Office of Management and Budget provided an opportunity to comment on the SCC, but ultimately did not make any significant revisions. In December 2014, the White House Council on Environmental Quality (“CEQ”) issued new draft guidance for assessing greenhouse gas emissions under the National Environmental Policy Act (“NEPA”), adding for the first time language that requires the analyses to also include the impact of climate change on projects, including using the SCC when analyzing costs and benefits of a project. 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 compliance planning 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 CAA. On December 17, 2014, the EPA proposed to revise the NAAQS for ozone. If the ozone standard is revised, it is expected to be effective in December 2015 after which states will begin developing implementation plans that will take several years to receive final EPA approval. The impact of a stricter standard cannot be accurately estimated due to the present uncertainty regarding the final standard and the additional requirements that states may impose. 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 standard (“PM 2.5”). In December 2014, the EPA finalized the non-attainment areas for PM 2.5. None of our refineries are located in the non-attainment areas for PM 2.5, however, our Cincinnati Renewable Fuels LLC facility is located in Cincinnati, OH, which was designated as a non-attainment area. 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. In December 2014, the EPA proposed reconsideration of limited issues and proposed to delete rule provisions for an affirmative defense for malfunctions. Currently, litigation is pending in the D.C. Circuit Court on both the 2011 and 2013 rule-makings. We anticipate litigation to continue through 2015. We are in the process of implementing the work practice standards. Final financial impacts of the Boiler MACT rule cannot be determined at this time because the ongoing litigation could affect the final rule.

On June 30, 2014, the EPA proposed to revise existing refinery air emissions standards. The final rule is expected to be issued by June 17, 2015 and allows for implementation through June 2018. EPA’s periodic review and possible revision of these standards is required under the CAA. This rule may require additional controls, lower emission standards and ambient air monitoring. Due to the present uncertainty regarding final standards, we cannot reasonably estimate the cost associated with this rule.

Water

We maintain numerous discharge permits as required under the National Pollutant Discharge Elimination System program of the CWA and have implemented systems to oversee our compliance with these permits. In addition, we are regulated under OPA-90, which among other things, 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 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, that include provisions for cargo owner responsibility as well as ship owner and operator responsibility.

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In 2013, the EPA and the US Army Corps of Engineers proposed significant changes to the definition of the term “waters of the US” (WOTUS) used in numerous programs under the CWA. The proposed changes have the potential to expand permitting, planning and reporting obligations and extend the timing to secure permits for pipeline and fixed asset construction and maintenance activities. Some man-made water bodies on our plant sites (firewater ponds, stormwater systems, and green infrastructure systems) may become WOTUS, which may require new permits requiring the control of liquids entering and exiting these water bodies. A final rule is anticipated in early 2015.

In May 2014, the EPA issued the final rule regarding cooling water intake structures which impacts three of our refineries. The final rule established closed-loop cooling as one of eight required technologies. The final rule also requires company engagement with Fish and Wildlife to determine if any endangered species are at risk in the locations during the next NPDES permit cycle. This rule will apply with the next NPDES renewal at our Catlettsburg, Garyville, and Robinson refineries. This rule is not anticipated to have a material impact on our operations.

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 applicable state laws and regulations. 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. EPA has not finalized the 2014 volumes at this time. In the near term, the RFS2 will be satisfied primarily with ethanol blended into gasoline. Vehicle, regulatory and infrastructure constraints limit the blending of significantly more than 10 percent ethanol into gasoline (“E10”), but blending more than E10 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 CAA to reduce the amount of cellulosic biofuel required under the statute from 1.0 billion gallons to 6.0 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.

On November 29, 2013, the EPA issued a proposed rule for the 2014 renewal fuel volume requirements. On November 21, 2014, the EPA announced the rule would not become final until sometime in 2015. This continues the lack of clarity and timeliness that has become common place with the EPA’s administration of the RFS2 requirements. This proposed rule has substantially reduced the RFS2 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 (“E15”) gasolines and postpone the issues and concerns of having to blend ethanol past the E10 “blendwall” at least for 2014. Likewise, the EPA has not finalized the 2015 renewable fuel volumes as required by the November 30, 2014 statutory deadline. As a result, the future of the RFS still remains undecided and is in need of a legislative re-write or repeal to provide a stable business platform for the obligated parties.

With potentially uncertain supplies, the advanced biofuels programs may 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. 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. The continued delay of the final rule for 2014 has also delayed the day when compliance reports are due for 2013. 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 finalized a rule establishing a quality assurance program for RINs purchased to help meet the annual biofuel requirements under the RFS2 program. The program is aimed at reducing the risks that RINs are fraudulently created or sold. We have already instituted internal procedures to help mitigate that 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 April 1, 2014, we purchased a facility in Cincinnati, Ohio, which currently produces biodiesel, glycerin and other by-products. The capacity of the plant is approximately 60 million gallons per year. As a producer of biodiesel, we now generate RINs, thereby reducing our reliance on the external RIN market.

On October 13, 2010, the EPA issued a partial waiver decision under the CAA to allow for an increase in the amount of ethanol permitted to be blended into gasoline from E10 to 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 3, 2014, the EPA signed the final Tier 3 fuel standards. The final Tier 3 fuel standards require, among other things, a lower annual average sulfur level in gasoline to no more than 10 parts per million (“ppm”) beginning in calendar year 2017. In addition, gasoline refiners and importers may not exceed a maximum per-gallon sulfur standard of 80 ppm while retailers may not exceed a maximum per-gallon sulfur standard of 95 ppm. We anticipate that we will spend an estimated $750 million to $1 billion between 2014 and 2019 for capital expenditures necessary to comply with these standards.

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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 45,340 regular employees as of December 31, 2014, which includes approximately 35,400 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. The labor agreements for our Canton, Catlettsburg and Galveston Bay refineries expired on January 31, 2015 and no successor agreements have been negotiated. As of February 1, 2015 our Catlettsburg and Galveston Bay refineries are experiencing work stoppages. The labor agreement for our Canton refinery was extended on a rolling 24-hour notice of expiration basis. The impacted refineries continue to operate as normal. The labor agreement for our Texas City refinery is due to expire on March 31, 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. In addition, they represent certain hourly employees at Speedway under agreements that cover certain outlets in New York and New Jersey that expire between September 14, 2015 and June 30, 2016.

Executive and Corporate Officers of the Registrant

The executive and corporate officers of MPC and their ages as of February 1, 2015, are as follows:

Name	Age	Position with MPC
Gary R. Heminger	61	President and Chief Executive Officer
Pamela K.M. Beall	58	Senior Vice President, Corporate Planning, Government & Public Affairs
Richard D. Bedell	60	Senior Vice President, Refining
Timothy T. Griffith	45	Vice President, Finance and Investor Relations, and Treasurer
John R. Haley(a)	58	Vice President, Tax
Thomas M. Kelley	55	Senior Vice President, Marketing
Anthony R. Kenney	61	President, Speedway LLC
Rodney P. Nichols	62	Senior Vice President, Human Resources and Administrative Services
C. Michael Palmer	61	Senior Vice President, Supply, Distribution and Planning
John J. Quaid	43	Vice President and Controller
George P. Shaffner	55	Senior Vice President, Transportation and Logistics
John S. Swearingen(a)	55	Vice President, Health, Environment, Safety & Security
Donald C. Templin	51	Senior Vice President and Chief Financial Officer
Donald W. Wehrly(a)	55	Vice President and Chief Information Officer
J. Michael Wilder	62	Vice President, General Counsel and Secretary

^(a)  Corporate officer.

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.

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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. 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 1, 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. Quaid was appointed vice president and controller effective June 23, 2014. Prior to this appointment, Mr. Quaid was vice president of Iron Ore at United States Steel Corporation (“U. S. Steel”), an integrated steel producer, beginning in January 2014. Previously, Mr. Quaid served in various leadership positions at U. S. Steel since February 2002, including vice president and treasurer beginning in August 2011, controller, North American Flat-Rolled Operations beginning in July 2010 and assistant corporate controller beginning in 2008.

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.

Michael G. Braddock, who was vice president and controller since June 30, 2011, retired effective October 1, 2014.

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

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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

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, the carrying value of our assets and our ability to execute share repurchases and continue the payment of our base dividend.

Our operating results, cash flows, future rate of growth, the carrying value of our assets and our ability to execute share repurchases and continue the payment of our base dividend 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 from the sale of 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, impair the carrying value of our assets (such as property, plant and equipment, inventory or goodwill), decrease or eliminate our share repurchase activity and our base dividend.

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Our operations are subject to business interruptions and casualty losses. Failure to manage risks associated with business interruptions could adversely impact our operations, financial condition, results of operations and cash flows.

Our operations are subject to business interruptions due to scheduled refinery turnarounds, unplanned maintenance or unplanned events such as explosions, fires, refinery or pipeline releases or other incidents, power outages, severe weather, labor disputes, or other natural or man-made disasters, such as acts of terrorism. 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 do not insure against all potential losses, and, therefore, our business, financial condition, results of operations and cash flows could be adversely affected by unexpected liabilities and increased costs.

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, including but not limited to, explosions, fires, refinery or pipeline releases or other incidents involving our assets or operations, 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 involve data network and telecommunications, Internet access and website functionality, 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 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 significant 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, 2014, our total debt obligations for borrowed money and capital lease obligations were $6.7 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, share repurchases, dividends 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.

We have a trade receivables securitization facility that provides liquidity of up to $1.3 billion depending on the amount of eligible domestic trade accounts receivables. In periods of lower prices, we may not have sufficient eligible accounts receivables to support full availability of this facility.

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

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

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

Approximately 38 percent of our refining employees are covered by collective bargaining agreements. The contracts for the hourly refinery workers at our 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 expired on January 31, 2015 and no successor agreements have been negotiated. In addition, three agreements scheduled to expire on September 14, 2015, March 14, 2016 and June 30, 2016, respectively, cover certain Speedway LLC hourly employees at certain outlets in New York and New Jersey. These contracts may be renewed at an increased cost to us. In addition, we have experienced, or may experience, work stoppages as a result of labor disagreements. Any prolonged work stoppages disrupting operations could have a material adverse effect on our business, financial condition, results of operations and cash flows.

One of our subsidiaries acts as the general partner of a publicly traded master limited partnership, MPLX, which may involve a greater exposure to certain legal liabilities than existed under 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 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.

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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 business, financial condition, results of operation and cash flows.

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.

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Significant acquisitions involve the integration of new assets or businesses and present substantial risks that could adversely affect our business, financial conditions, results of operations and cash flows.

Significant transactions involving the addition of new assets or businesses present potential risks, which may include, among others:

• Inaccurate assumptions about future synergies, revenues, capital expenditures and operating costs;

• An inability to successfully integrate assets or businesses we acquire;

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

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

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

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

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

Risks Relating to Our 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 expected to become more stringent relate to the following:

• the emission or discharge of materials into the environment,

• solid and hazardous waste management,

• pollution prevention,

• greenhouse gas emissions,

• characteristics and composition of gasoline and diesel fuels,

• public and employee safety and health, and

• facility security.

The specific impact of laws and regulations on us and our competitors may vary depending on a number of factors, including the age and location of operating facilities, marketing areas, crude oil and feedstock sources and production processes. We may be required to make expenditures to modify operations, install pollution control equipment, perform site cleanups or curtail operations that could materially and adversely affect our business, financial condition, results of operations and cash flows.

We believe the issue of climate change will likely continue to receive scientific and political attention, with the potential for further laws and regulations that could affect our operations. The U.S. pledge in 2009, as part of the Copenhagen Accord, to reduce greenhouse gas emissions 17 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. In June 2014, the U.S. Supreme Court ruled that the Clean Air Act Prevention of Significant Deterioration program for new and modified stationary sources is not triggered by greenhouse gas emissions alone. The U.S. Supreme Court did, however, uphold the requirement for new or modified stationary sources that will also emit a criteria pollutant to control greenhouse gas emissions through Best Available Control Technology. Implementing Best Available Control Technology may result in increased costs to our operations.

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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. In 2013, the Obama administration significantly increased the estimate to $36 per ton. In response to the regulated community and Congress’ critiques of how the SCC was developed, the Office of Management and Budget provided an opportunity to comment on the SCC, but ultimately did not make any significant revisions. In December 2014, the White House Council on Environmental Quality (“CEQ”) issued new draft guidance for assessing greenhouse gas emissions under the National Environmental Policy Act (“NEPA”), adding for the first time language that requires that analyses also include the impact of climate change on projects, including using the SCC when analyzing costs and benefits of a project. 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 2013, the EPA proposed carbon emission standards for new power plants built in the future. In June 2014, the EPA proposed the Clean Power Plan, which would reduce carbon emissions from existing power plants. Through the Plan, the EPA proposes to reduce nationwide carbon emissions from the power generation sector by 30 percent below 2005 levels. These standards, if finalized, could increase our electricity costs and potentially reduce the reliability of our electricity supply.

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.

In November 2014, the EPA proposed a tightening of the primary (health) ozone National Ambient Air Quality Standards (“NAAQS”) to within the range of 65 to 70 parts per billion (“ppb”), while accepting comments on levels as low as 60 ppb and an option of maintaining the current ozone level of 75 ppb. In addition, the EPA is asking for comment on a new secondary (welfare) ozone NAAQS using a three-month seasonal index. The final rule is expected to be promulgated in late 2015. If timely finalized, the EPA would then implement a revised ozone NAAQS with attainment and nonattainment designations by late 2017, using 2014-2016 air quality monitor data. A lower primary ozone standard may not by attainable in many areas and could result in the cancellation or delay of capital projects at our 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 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). 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. Gasoline consumption has been lower than forecasted by the EPA, which has led to concerns that the renewable fuel volumes may not be met. As a result, the EPA delayed issuance of the 2014 RFS2 standards and has not finalized the 2015 renewable fuel volumes as required by the November 30, 2014 statutory deadline. 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 3, 2014, the EPA signed the final Tier 3 fuel standards. The final Tier 3 fuel standards require, among other things, a lower annual average sulfur level in gasoline to no more than 10 parts per million (“ppm”) beginning in calendar year 2017. In addition, gasoline refiners and importers may not exceed a maximum per-gallon sulfur standard of 80 ppm, while retailers may not exceed a maximum per-gallon sulfur standard of 95 ppm. We anticipate that we will spend an estimated $750 million to $1 billion between 2014 and 2019 for capital expenditures necessary to comply with these standards.

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

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

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

Plans we may have to expand existing assets or construct new assets are subject to risks associated with societal and political pressures and other forms of opposition to the future development, transportation and use of carbon-based fuels. Such risks could adversely impact our business and ability to realize certain growth strategies.

Our anticipated growth and planned expenditures are based upon the assumption that societal sentiment will continue to enable and existing regulations will remain intact to allow for the future development, transportation and use of carbon-based fuels. A portion of our growth strategy is dependent on our ability to expand existing assets and to construct additional assets. However, policy decisions relating to the production, refining, transportation and marketing of carbon-based fuels are subject to political pressures and the influence of environmental and other special interest groups. The construction of new refinery processing units or crude oil or refined products pipelines, or the extension or expansion of existing assets, involve numerous political and legal uncertainties, many of which may cause significant delays or cost increases and most of which are beyond our control. Delays or cost increases related to capital spending programs involving engineering, procurement and construction of facilities (including improvements and repairs to our existing facilities) could adversely affect our ability to achieve forecasted internal rates of return and operating results, thereby limiting our ability to grow and generate cash flows.

Large capital projects can take many years to complete, and market conditions could deteriorate significantly between the project approval date and the project startup date, negatively impacting project returns. If we are unable to complete capital projects at their expected costs and in a timely manner, or if the market conditions assumed in our project economics deteriorate, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

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

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

• unplanned increases in the cost of construction materials or labor;

• disruptions in transportation of components or construction materials;

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

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

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

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

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

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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.

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 and/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. For example, 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.

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.

An easing or lifting of the U.S. crude oil export ban could adversely affect crack spreads or crude oil price differentials and have a material adverse effect on our business, financial condition, results of operations and cash flows.

Since the 1970s, the U.S. has restricted the ability of producers to export domestic crude oil. As total crude oil production has increased in the U.S. in recent years, primarily due to the increase in shale crude oil production, there have been increasing calls by crude oil producers and others for an easing or lifting of the crude oil export ban. If the export ban were to be significantly eased or lifted, the price of domestic crude oil would likely rise, potentially impacting crack spreads and price differentials between domestic and foreign crude oils. A deterioration of crack spreads or price differentials between domestic and foreign crude oils could have a material adverse effect on our business, financial condition, results or operations 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, 2014, 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 25 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 alleged violations of various statutory and regulatory provisions related to motor fuels, some of which we had previously self-reported to the EPA. Subsequently, we self-reported four additional alleged Clean Air Act violations related to motor fuels to the EPA. In July 2014, we tentatively agreed to pay a $2.75 million civil penalty as well as undertake certain projects to reduce emissions. In August and December 2014, we self-reported three similar alleged violations to the EPA. The EPA has agreed to include these incidents in the consent decree and increased the civil penalty demand to $2.9 million. We believe the ultimate resolution of this matter will not have a material impact on our consolidated results of operations, financial position or cash flows.

We have been subject to a pending enforcement matter with the Illinois Environmental Protection Agency and the Illinois attorney general’s office since 2002 concerning self-reporting of possible emission exceedences and permitting issues related to storage tanks at the Robinson, Illinois refinery. As a result of these allegations, we tentatively agreed to pay $150,000 civil penalty and undertake a supplemental environmental project involving the installation of ambient air monitors at the refinery.

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The consent order is not yet finalized, but the ultimate resolution of this matter will not have a material impact on our consolidated results of operations, financial position or cash flows.

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.

We are involved in a number of other environmental proceedings arising in the ordinary course of business. While the ultimate outcome and impact on us cannot be predicted with certainty, we believe the resolution of these environmental proceedings 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 13, 2015, there were 37,906 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:

	2014						2013
Dollars per share	High Price		Low Price		Dividends		High Price		Low Price		Dividends
Quarter 1	$	94.88	$	80.68	$	0.42	$	92.73	$	60.04	$	0.35
Quarter 2	97.70		77.94		0.42		90.54		69.31		0.35
Quarter 3	92.89		75.68		0.50		76.58		62.51		0.42
Quarter 4	97.94		74.64		0.50		91.95		61.32		0.42
Year	97.94		74.64		1.84		92.73		60.04		1.54

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 31, 2015, our board of directors approved a 50 cent per share dividend, payable March 10, 2015 to stockholders of record at the close of business on February 18, 2015.

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, 2014, 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)
10/01/14-10/31/14	835,416	$	82.41	834,500	$	2,339,234,812
11/01/14-11/30/14	4,948,398	93.36		4,948,217	1,877,249,784
12/01/14-12/31/14	1,657,786	91.42		1,656,562	1,725,807,942
Total	7,441,600	91.70		7,439,279

^(a)  The amounts in this column include 916, 181 and 1,224 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)  The $2.0 billion share repurchase authorization announced on September 26, 2013 was exhausted during the fourth quarter of 2014. On July 30, 2014, we announced that our board of directors approved an additional $2.0 billion share repurchase authorization through July 31, 2016, resulting in $8.0 billion of total share repurchase authorizations since January 1, 2012. As of December 31, 2014, we have purchased a total of $6.27 billion of our common stock under repurchase authorizations since January 1, 2012, leaving $1.73 billion available for repurchases.

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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)	2014(a)		2013(a)		2012		2011		2010(b)
Statements of Income Data
Revenues	$	97,817	$	100,160	$	82,243	$	78,638	$	62,487
Income from operations	4,051		3,425		5,347		3,745		1,011
Net income	2,555		2,133		3,393		2,389		623
Net income attributable to MPC	2,524		2,112		3,389		2,389		623
Per Share Data(c)
Basic:
Net income attributable to MPC per share	$	8.84	$	6.69	$	9.95	$	6.70	$	1.75
Diluted:
Net income attributable to MPC per share	$	8.78	$	6.64	$	9.89	$	6.67	$	1.74
Dividends per share	$	1.84	$	1.54	$	1.20	0.45		—
Statements of Cash Flows Data
Net cash provided by operating activities	$	3,110	$	3,405	$	4,492	$	3,309	$	2,217
Additions to property, plant and equipment	1,480		1,206		1,369		1,185		1,217
Common stock repurchased	2,131		2,793		1,350		—		—
Dividends paid	524		484		407		160		—

	December 31,
(In millions)	2014(a)		2013(a)		2012		2011		2010
Balance Sheets Data
Total assets	$	30,460	$	28,385	$	27,223	$	25,745	$	23,232
Long-term debt, including capitalized leases(d)	6,637		3,396		3,361		3,307		279
Long-term debt payable to Marathon Oil and subsidiaries(e)	—		—		—		—		3,618

^(a)  On September 30, 2014, we acquired Hess’ Retail Operations and Related Assets. On February 1, 2013, we acquired the Galveston Bay Refinery and Related Assets. Data presented subsequent to these acquisitions include amounts for these operations.

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

^(c)  The number of weighted average shares for 2014, 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 aggregate principal amount of senior notes, which replaced a portion of the debt payable to Marathon Oil and subsidiaries. During 2014, we issued $1.95 billion aggregate principal amount of senior notes and entered into a $700 million term loan agreement to fund a portion of the Hess’ Retail Operations and Related Assets acquisition. Also during 2014, MPLX entered into a $250 million term loan agreement and drew upon their credit facility to fund a portion of its purchase of additional interest in Pipe Line Holdings from MPC.

^(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,” “objective,” “expect,” “forecast,” “goal,” “intend,” “plan,” “predict,” “project,” “potential,” “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 and marketing, retail and pipeline 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, East 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. 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 that Speedway LLC, a wholly-owned subsidiary, operates the second largest chain of company-owned and operated retail gasoline and convenience stores in the United States, with approximately 2,750 convenience stores in 22 states throughout the Midwest, East Coast and Southeast. The Marathon brand is an established motor fuel brand in the Midwest and Southeast regions of the United States, and is available through approximately 5,460 retail outlets operated by independent entrepreneurs in 19 states.

As of December 31, 2014, 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. Overall, we are one of the largest independent petroleum product refining, marketing, retail and transportation businesses in the United States and the largest east of the Mississippi.

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 refined products and ethanol 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, East Coast and Southeast.

• 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.

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Executive Summary

Results

Select results for 2014 and 2013 are reflected in the following table.

(In millions, except per share data)	2014		2013
Income from Operations by segment
Refining & Marketing	$	3,609	$	3,206
Speedway	544		375
Pipeline Transportation	280		210
Net income attributable to MPC	$	2,524	$	2,112
Net income attributable to MPC per diluted share	$	8.78	$	6.64

Net income attributable to MPC increased $412 million, or $2.14 per diluted share, in 2014 compared to 2013, primarily due to our Refining & Marketing segment.

Refining & Marketing segment income from operations increased $403 million in 2014 compared to 2013, primarily due to more favorable net product price realizations and higher U.S. Gulf Coast (“USGC”) and Chicago crack spreads, partially offset by narrower crude oil differentials and higher turnaround and other direct operating costs.

Speedway segment income from operations increased $169 million in 2014 compared to 2013, primarily due to increases in gasoline and distillate gross margin and merchandise gross margin, partially offset by higher operating expenses. These increases were primarily attributable to the acquisition of convenience stores from Hess.

Pipeline Transportation segment income from operations increased $70 million in 2014 compared to 2013, primarily due to higher pipeline transportation revenue and an increase in income from our pipeline affiliates, partially offset by an increase in operating expenses.

MPLX LP

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.

As of December 31, 2014, we owned a 71.5 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.

MPLX’s initial assets consisted of a 51 percent general partner interest in Pipe Line Holdings, which owns a network of common carrier crude oil and product pipeline systems and associated storage assets in the Midwest and Gulf Coast regions of the United States, and a 100 percent interest in a butane storage cavern in West Virginia. We originally retained a 49 percent limited partner interest in Pipe Line Holdings.

On May 1, 2013, we sold a five percent interest in Pipe Line Holdings to MPLX for $100 million, which was financed by MPLX with cash on hand.

On March 1, 2014, we sold MPLX a 13 percent interest in Pipe Line Holdings for $310 million. MPLX financed this transaction with $40 million of cash on-hand and $270 million of borrowings on its bank revolving credit agreement.

On October 30, 2014, we announced plans to substantially accelerate the growth of MPLX, which is expected to provide unitholders an average annual distribution growth rate percentage in the mid-20s over the next five years as we build meaningful scale more quickly. We believe this increased scale provides MPLX greater flexibility to fund organic projects and to pursue acquisition opportunities.

On December 1, 2014, we sold and contributed interests in Pipe Line Holdings totaling 30.5 percent to MPLX for $600 million in cash and 2.9 million MPLX common units valued at $200 million. MPLX financed the sales portion of this transaction with $600 million of borrowings on its bank revolving credit facility.

The sales and contribution of our interests in Pipe Line Holdings to MPLX resulted in a change of our ownership in Pipe Line Holdings, but not a change in control. We accounted for these sales as transactions between entities under common control and did not record a gain or loss.

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On December 8, 2014, MPLX completed a public offering of 3.5 million common units at a price to the public of $66.68 per common unit, with net proceeds of $221 million. MPLX used the net proceeds from this offering to repay borrowings under its bank revolving credit facility and for general partnership purposes. On December 10, 2014, we exercised our right to maintain our two percent general partner interest in MPLX by purchasing 130 thousand general partner units for $9 million.

On February 12, 2015, MPLX completed its initial underwritten public offering of $500 million aggregate principal amount of four percent unsecured senior notes due February 15, 2025 (the “Senior Notes”). The Senior Notes were offered at a price to the public of 99.64 percent of par. The net proceeds of this offering were used to repay the amounts outstanding under its bank revolving credit facility, as well as for general partnership purposes.

The following table summarizes the cash distributions we received from MPLX during 2014 and 2013.

(In millions)	2014		2013
Cash distributions received from MPLX:
General partner distributions, including incentive distribution rights	$	4	$	1
Limited partner distributions	72		56
Total	$	76	$	57

The market value of the 19,980,619 MPLX common units and 36,951,515 MPLX subordinated units we owned at December 31, 2014 was $4.18 billion based on the December 31, 2014 closing unit price of $73.49. Over time, we also believe there will be substantial value attributable to our general partnership interests.

See Item 8. Financial Statements and Supplementary Data – Note 4 for additional information on MPLX.

Acquisitions and Investments

On September 30, 2014, we acquired from Hess all of its retail locations, transport operations and shipper history on various pipelines, including approximately 40 mbpd on Colonial Pipeline, for $2.82 billion. We refer to these assets as “Hess’ Retail Operations and Related Assets” and substantially all of these assets are part of our Speedway segment. This acquisition significantly expands our Speedway presence from nine to 22 states throughout the East Coast and Southeast and is aligned with our strategy to grow higher-valued, stable cash flow businesses. This acquisition also enables us to further leverage our integrated refining and transportation operations, providing an outlet for an incremental 200 mbpd of assured sales from our refining system. The transaction was funded with a combination of debt and available cash. Our financial results and operating statistics for the periods prior to the acquisition do not include amounts for Hess’ Retail Operations and Related Assets.

In July 2014, we exercised our option to acquire a 35 percent ownership interest in Enbridge Inc.’s SAX pipeline, which will run from Flanagan, Ill. to Patoka, Ill. and is expected to be operational in late 2015. This option resulted from our agreement to be the anchor shipper on the SAX pipeline and our commitment to the Sandpiper pipeline project. During 2014, we made contributions of $120 million to Illinois Extension Pipeline to fund our portion of the construction costs incurred-to-date on the SAX pipeline project.

On April 1, 2014, we purchased a facility in Cincinnati, Ohio from Felda Iffco Sdn Bhd, Malaysia for $40 million. The plant currently produces biodiesel, glycerin and other by-products. The capacity of the plant is approximately 60 million gallons per year.

In March 2014, we acquired from Chevron Raven Ridge Pipe Line Company an additional seven percent interest in Explorer for $77 million, bringing our ownership interest to 25 percent. Due to this increase in our ownership percentage, we now account for our investment in Explorer using the equity method of accounting and report Explorer as a related party. Explorer owns approximately 1,900 miles of refined products pipeline from Lake Charles, Louisiana to Hammond, Indiana.

In November 2013, we agreed with Enbridge Energy Partners to serve as an anchor shipper for the Sandpiper pipeline, which will run from Beaver Lodge, North Dakota to Superior, Wisconsin. 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 contributions of $192 million during 2014 and have contributed $216 million since project inception. 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 Energy Partners’ North Dakota System when the Sandpiper pipeline is placed into service, which is expected to be in 2017. Enbridge Energy Partners’ 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.

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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.

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. In July 2014, we paid BP $180 million for the first period’s contingent earnout. These assets are part of our Refining & Marketing and Pipeline Transportation segments. Our financial results and operating statistics for the 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 these acquisitions and investments. See Item 8. Financial Statements and Supplementary Data – Note 26 for information regarding our future contributions to the SAX pipeline project and the Sandpiper pipeline project.

Share Repurchases

On July 30, 2014, our board of directors approved an additional $2.0 billion share repurchase authorization expiring in July 2016. As of December 31, 2014, our board of directors had approved $8.0 billion in total share repurchase authorizations since January 1, 2012 and we have repurchased a total of $6.27 billion of our common stock under these authorizations, leaving $1.73 billion available for repurchases. Under these authorizations, we have acquired 89 million shares at an average cost per share of $70.35.

Liquidity

As of December 31, 2014, we had cash and cash equivalents of $1.49 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. As of January 31, 2015, eligible trade receivables supported borrowings of $700 million. MPLX had $385 million of borrowings outstanding under its $1 billion revolving credit agreement as of December 31, 2014.

The above discussion contains forward-looking statements with respect to the estimated construction costs, timing and completion of the Sandpiper and SAX pipeline projects and the share repurchase authorizations. Factors that could affect the estimated construction costs, timing and completion of the Sandpiper and SAX 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.

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 products purchased for resale. 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 USGC crack spreads that we believe most closely track our operations and slate of products. LLS prices and a 6-3-2-1 ratio of products (6 barrels of LLS crude oil producing 3 barrels of unleaded regular gasoline, 2 barrels of ultra-low sulfur diesel and 1 barrel of three percent residual fuel oil) are used for these crack-spread calculations.

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Refined product prices have historically moved relative to international crude oil prices like Brent crude. In recent years, domestic U.S. crude oils, such as WTI and LLS, traded at prices less than Brent due to the growth in U.S. crude oil production, logistical constraints and other market factors. These price discounts compared to Brent favorably impacted the LLS 6-3-2-1 crack spread. During 2011 and continuing through the first half of 2013, WTI traded at prices significantly less than Brent and LLS, which favorably impacted our Refining & Marketing gross margin. The differential between WTI and LLS significantly narrowed during the second half of 2013 with a further narrowing broadly continuing through 2014. In addition, the differential between LLS and Brent narrowed significantly during the second half of 2014. The spread between domestic crude oils and Brent could remain narrow if there is a change in existing U.S. energy policy regarding crude oil exports, or if low crude oil prices reduce U.S. crude oil production growth substantially. If either were to occur, it could reduce our Refining & Marketing gross margin.

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.

Future crude oil differentials will be dependent on a variety of market and economic factors, as well as U.S. energy policy.

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)	100
Natural gas price sensitivity (per $1.00/million British thermal unit change)	140

^(a)  Weighted 38 percent Chicago and 62 percent 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 percent 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;

• the cost of products purchased for resale; and

• the potential impact of lower of cost or market adjustments to inventories in periods of declining prices.

Inventories are stated at the lower of cost or market. The cost of our crude oil and refined product inventories is determined under the last in, first out (“LIFO”) method. During periods of rapidly declining prices, the LIFO cost basis of our crude oil and refined product inventories may have to be written down to market value. Despite a significant drop in refined product prices in 2014, we determined that the LIFO cost basis of our crude oil and refined product inventories was recoverable as of December 31, 2014. If prices decrease further in 2015, we may be required to recognize a lower of cost or market adjustment to these inventories, which totaled approximately 96 million barrels as of December 31, 2014.

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
2014	Catlettsburg, Galveston Bay, Garyville and Robinson
2013	Canton, Catlettsburg, Galveston Bay, Garyville and Robinson
2012	Catlettsburg, Detroit, Garyville and Robinson

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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	2014	2013	2012
Garyville, Louisiana	522	522	522
Galveston Bay, Texas City, Texas(a)	451	451	N/A
Catlettsburg, Kentucky	242	242	240
Robinson, Illinois	212	212	206
Detroit, Michigan	130	123	120
Canton, Ohio	90	80	80
Texas City, Texas	84	84	80
Total	1,731	1,714	1,248

^(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 about half a percent in 2014 after climbing by 1.4 percent in 2013. Meanwhile, gasoline demand in PADD 1 is estimated to have grown by 1.5 percent in 2014 after a 1.5 percent decline in 2013, reversing a three-year trend of declines and returning to 2012 levels. Strong economic growth in the last three quarters of 2014 and strongly falling prices throughout the second half supported gasoline demand. Distillate demand was supported by severe winter temperatures in early 2014 and a very strong harvest season. PADD 2 distillate demand is estimated to have grown by 3.7 percent in 2014 after climbing by 1.6 percent in 2013. PADD 1 estimated distillate demand grew over five percent after climbing by 8.8 percent in 2013. 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. More than half of Speedway’s gross margin was derived from merchandise sales in 2014. 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

Consolidated Results of Operations

(In millions)	2014			2013			2014 vs. 2013 Variance			2012			2013 vs. 2012 Variance
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$	97,817		$	100,160		$	(2,343	)	$	82,243		$	17,917
Income from equity method investments	153			36			117			26			10
Net gain on disposal of assets	21			6			15			177			(171		)
Other income	111			52			59			46			6
Total revenues and other income	98,102			100,254			(2,152		)	82,492			17,762
Costs and expenses:
Cost of revenues (excludes items below)	83,770			87,401			(3,631		)	68,668			18,733
Purchases from related parties	505			357			148			280			77
Consumer excise taxes	6,685			6,263			422			5,709			554
Depreciation and amortization	1,326			1,220			106			995			225
Selling, general and administrative expenses	1,375			1,248			127			1,223			25
Other taxes	390			340			50			270			70
Total costs and expenses	94,051			96,829			(2,778		)	77,145			19,684
Income from operations	4,051			3,425			626			5,347			(1,922		)
Net interest and other financial income (costs)	(216		)	(179		)	(37		)	(109		)	(70		)
Income before income taxes	3,835			3,246			589			5,238			(1,992		)
Provision for income taxes	1,280			1,113			167			1,845			(732		)
Net income	2,555			2,133			422			3,393			(1,260		)
Less net income attributable to noncontrolling interests	31			21			10			4			17
Net income attributable to MPC	$	2,524		$	2,112		$	412		$	3,389		$	(1,277	)

Net income attributable to MPC increased $412 million in 2014 compared to 2013 and decreased $1.28 billion in 2013 compared to 2012, primarily due to our Refining & Marketing segment income from operations, which increased $403 million in 2014 compared to 2013 and decreased $1.89 billion in 2013 compared to 2012. The increase in Refining & Marketing segment income from operations in 2014 was primarily due to more favorable net product price realizations and higher USGC and Chicago crack spreads, partially offset by narrower crude oil differentials and higher turnaround and other direct operating costs. The decrease in 2013 was primarily due tonarrower 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) decreased $2.34 billion in 2014 compared to 2013 and increased $17.92 billion in 2013 compared to 2012. The decrease in 2014 was primarily due to lower refined product sales prices, partially offset by an increase in refined product sales volumes and higher merchandise sales for our Speedway segment primarily attributable to the convenience stores acquired from Hess. The increase in 2013 was primarily due to higher refined product sales volumes, which were primarily associated with the acquisition of the Galveston Bay refinery in February 2013, partially offset by a decrease in refined product sales prices. Consolidated refined product sales increased 52 mbpd in 2014 compared to 2013 and 468 mbpd in 2013 compared to 2012.

Income from equity method investments increased $117 million in 2014 compared to 2013 and $10 million in 2013 compared to 2012. The increase in 2014 was primarily due to increases in income from our ethanol affiliates of $68 million and income from our pipeline affiliates of $49 million. The increase in income from our ethanol affiliates includes the affects of our acquisition of interests in TAAE, TACE and TAEI in August 2013. The higher income from our pipeline affiliates is primarily due to increases from LOOP LLC (“LOOP”) and Explorer, which is now accounted for as an equity method investment following our acquisition of an increased ownership interest in this pipeline company. The increase in 2013 was 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 of $17 million. The increase in income from ethanol investments was primarily due to higher income in 2013 compared to 2012 and the acquisition of interests in TAAE, TACE and TAEI in 2013.

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Net gain on disposal of assets increased $15 million in 2014 compared to 2013 and decreased $171 million in 2013 compared to 2012, primarily due to the sale of two terminals and terminal assets in 2014 and 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.

Other income increased $59 million in 2014 compared to 2013 and $6 million in 2013 compared to 2012. The increase in 2014 was primarily due to higher gains on sales of excess Renewable Identification Numbers (“RINs”) of $74 million, partially offset by an $11 million impairment in 2014 of an investment in a company accounted for using the cost method. The increase in 2013 was primarily due to higher gains on sales of excess 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 decreased $3.63 billion in 2014 compared to 2013 and increased $18.73 billion in 2013 compared to 2012. The decrease in 2014 was primarily due to:

• a decrease in refined product cost of sales of $5.01 billion, primarily due to a decrease in our average crude oil costs of $9.30 per barrel, partially offset by an increase in refined product sales volumes;

• partially offset by an increase in refinery direct operating costs of $913 million, or $1.37 per barrel of total refinery throughput, which included costs associated with significant planned turnaround activity; and

• an increase in merchandise cost of sales for our Speedway segment of $327 million, primarily attributable to the convenience stores acquired from Hess.

The increase in 2013 was primarily due to:

• an increase in refined product cost of sales of $17.09 billion, primarily due to an increase in refined product sales volumes attributable to the acquisition of the Galveston Bay refinery; and

• an increase in refinery direct operating costs of $1.62 billion, or $1.11 per barrel of total refinery throughput, 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.

Purchases from related parties increased $148 million in 2014 compared to 2013 and $77 million in 2013 compared to 2012. The increase in 2014 was primarily due to acquisitions of ownership interests in TAAE in August 2013 and Explorer in March 2014, resulting in purchases from these companies totaling $118 million in 2014 and $24 million in 2013, being reported as purchases from related parties while purchases from these companies prior to these acquisitions were reported as cost of revenues. In addition, we also had an increase in purchases from LOOP of $45 million in 2014. The increase in 2013 was 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”).

Consumer excise taxes increased $422 million in 2014 compared to 2013 and $554 million in 2013 compared to 2012, primarily due to increases in taxable refined product sales volumes, including the effects of the acquisitions of the Galveston Bay Refinery and Related Assets and Hess’ Retail Operations and Related Assets.

Depreciation and amortization increased $106 million in 2014 compared to 2013 and $225 million in 2013 compared to 2012. The increase in 2014 was primarily due to completion of certain capital investments at our Galveston Bay refinery, an increase in the number of convenience stores in our Speedway segment and the implementation of corporate-level information technology projects, partially offset by an impairment of a light products terminal in 2013. The increase in 2013 was 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.

Selling, general and administrative expenses increased $127 million in 2014 compared to 2013, primarily due to increases in contract services, employee compensation and benefit expenses and credit card processing fees.

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Other taxes increased $50 million in 2014 compared to 2013 and $70 million in 2013 compared to 2012. The increase in 2014 was primarily due to increases in property taxes of $30 million, payroll taxes of $27 million and environmental taxes of $11 million, partially offset by decreases in other tax expenses. These increases were attributable to a number of factors including the acquisitions of the Galveston Bay Refinery and Related Assets and Hess’ Retail Operations and Related Assets and the absence of a Federal Oil Spill Tax refund received in 2013. The increase in 2013 was primarily due to increases in property taxes of $41 million, payroll taxes of $21 million and sales and use tax expense of $13 million. The increases in 2013 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 $37 million in 2014 compared to 2013 and $70 million in 2013 compared to 2012. The increase in 2014 was primarily due to an increase in long-term debt related to the acquisition of Hess’ Retail Operations and Related Assets and MPLX’s acquisition of additional interest in Pipe Line Holdings. The increase in 2013 was primarily due toa 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 $27 million in 2014, $28 million in 2013 and $101 million in 2012.

Provision for income taxes increased $167 million in 2014 compared to 2013 and decreased $732 million in 2013 compared to 2012, primarily due to our income before income taxes, which increased $589 million in 2014 compared to 2013 and decreased $1.99 billion in 2013 compared to 2012. The effective tax rates in 2014, 2013 and 2012 are equivalent to or slightly 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 13 for further details.

Segment Results

Revenues are summarized by segment in the following table.

(In millions)	2014		2013		2012
Refining & Marketing	$	91,734	$	94,910	$	76,710
Speedway	16,932		14,475		14,243
Pipeline Transportation	597		537		459
Segment revenues	$	109,263	$	109,922	$	91,412
Items included in both revenues and costs:
Consumer excise taxes	$	6,685	$	6,263	$	5,709

Refining & Marketing segment revenues decreased $3.18 billion in 2014 compared to 2013 and increased $18.20 billion in 2013 compared to 2012. The decrease in 2014 was primarily due tolower refined product sales prices, partially offset by an increase in refined product sales volumes. The increase in 2013 was 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.

	2014		2013		2012
Refining & Marketing segment:
Refined product sales volumes (thousands of barrels per day)(a)	2,125		2,075		1,599
Refined product sales destined for export (thousands of barrels per day)	275		218		123
Average refined product sales prices (dollars per gallon)	$	2.71	$	2.87	$	3.00

^(a)  Includes intersegment sales and sales destined for export.

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

(Dollars per gallon)	2014		2013		2012
Chicago spot unleaded regular gasoline	$	2.55	$	2.76	$	2.84
Chicago spot ultra-low sulfur diesel	2.80		3.01		3.01
USGC spot unleaded regular gasoline	2.49		2.69		2.81
USGC spot ultra-low sulfur diesel	2.71		2.97		3.05

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Refining & Marketing intersegment sales to our Speedway segment increased $1.62 billion in 2014 compared to 2013 and $512 million in 2013 compared to 2012, primarily due to increases in intersegment refined product sales volumes, partially offset by lower refined product sales prices. The increase in intersegment refined product sales volumes for 2014 was primarily due to the acquisition of convenience stores from Hess.

	2014		2013		2012
Refining & Marketing intersegment sales to Speedway:
Intersegment sales (in millions)	$	10,912	$	9,294	$	8,782
Refined product sales volumes (millions of gallons)	3,766		2,976		2,727
Average refined product sales prices (dollars per gallon)	$	2.89	$	3.11	$	3.21

Speedway segment revenues increased $2.46 billion in 2014 compared to 2013 and $232 million in 2013 compared to 2012, primarily due to increases in gasoline and distillate sales of $1.98 billion and $138 million, respectively, and increases in merchandise sales of $476 million and $77 million, respectively. The increases in gasoline and distillate sales were primarily due to volume increases of 796 million gallons and 119 million gallons, respectively, primarily due to increases in the number of convenience stores, partially offset by decreases in gasoline and distillate selling prices of $0.20 per gallon and $0.09 per gallon, respectively. The increases in merchandise sales were primarily due to increases in the number of convenience stores and higher same store sales. The increase in the number of convenience stores for 2014 was primarily due to the acquisition of convenience stores from Hess.

The following table includes certain revenue statistics for the Speedway segment.

	2014			2013			2012
Convenience stores at period-end	2,746			1,478			1,464
Gasoline & distillate sales (millions of gallons)	3,942			3,146			3,027
Average gasoline & distillate sales prices (dollars per gallon)	$	3.25		$	3.45		$	3.54
Merchandise sales (in millions)	$	3,611		$	3,135		$	3,058
Same store gasoline sales volume (period over period)	(0.7		)%	0.5		%	(0.8		)%
Same store merchandise sales (period over period)(a)	5.0		%	4.3		%	7.0		%

^(a)  Excludes cigarettes.

Pipeline Transportation segment revenue increased $60 million in 2014 compared to 2013 and $78 million in 2013 compared to 2012. The increase in 2014 was primarily due toan increase in revenue related to volume deficiency credits and higher average tariffs received on crude oil and refined products shipped, partially offset by lower refined products and crude oil pipeline throughput volumes. The increase in 2013 was 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.

The following table includes throughput volumes for the Pipeline Transportation segment.

	2014	2013	2012
Pipeline Throughputs (thousands of barrels per day):(a)
Crude oil pipelines	1,241	1,293	1,191
Refined products pipelines	878	911	980
Total	2,119	2,204	2,171

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

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

(In millions)	2014			2013			2012
Income from operations by segment:
Refining & Marketing	$	3,609		$	3,206		$	5,098
Speedway	544			375			310
Pipeline Transportation(a)	280			210			216
Items not allocated to segments:
Corporate and other unallocated items(a)	(286		)	(271		)	(336		)
Minnesota Assets sale settlement gain	—			—			183
Pension settlement expenses(b)	(96		)	(95		)	(124		)
Income from operations	4,051			3,425			5,347
Net interest and other financial income (costs)	(216		)	(179		)	(109		)
Income before income taxes	$	3,835		$	3,246		$	5,238

^(a)  Included in the Pipeline Transportation segment for 2014, 2013 and 2012 are $19 million,$20 million and $4 million of corporate overhead expenses 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 23.

Refining & Marketing segment income from operations increased $403 million in 2014 compared to 2013 and decreased $1.89 billion in 2013 compared to 2012. The increase in 2014 was primarily due tomore favorable net product price realizations and higher USGC and Chicago crack spreads, partially offset by narrower crude oil differentials and higher turnaround and other direct operating costs. The decrease in 2013 was primarily due tonarrower crude oil differentials and lower net product price realizations, partially offset by higher refinery throughput and sales volumes.

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)	2014		2013		2012
Chicago LLS 6-3-2-1(a)(b)	$	9.56	$	8.16	$	6.74
USGC LLS 6-3-2-1(a)	7.23		6.24		6.67
Blended 6-3-2-1(a)(c)	8.11		6.97		6.71
LLS	96.90		107.38		111.67
WTI	92.91		98.05		94.15
LLS – WTI crude oil differential(a)	3.99		9.33		17.52
Sweet/Sour crude oil differential(a)(d)	6.97		8.53		12.47

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

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

^(c)  Blended Chicago/USGC crack spread is 38/62 percent in 2014, 38/62 percent in 2013 and 52/48 percent 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].

Based on the market indicators above and our refinery throughputs, we estimate the following impacts on Refining & Marketing segment income from operations for 2014 compared to 2013 and for 2013 compared to 2012:

• The Chicago LLS 6-3-2-1 crack spread increased $1.40 per barrel in 2014 compared to 2013 and $1.42 per barrel in 2013 compared to 2012, which had positive impacts on segment income of $354 million and $291 million, respectively.

• The USGC LLS 6-3-2-1 crack spread increased $0.99 per barrel in 2014 compared to 2013 which had a positive impact on segment income of $407 million. The USGC LLS 6-3-2-1 crack spread decreased $0.43 per barrel in 2013 compared to 2012. This decrease was offset by an increase in refinery throughput volumes, primarily due to the acquisition of the Galveston Bay refinery, which resulted in a positive impact to segment income of $949 million in 2013 compared to 2012.

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• The LLS-WTI crude oil differential narrowed $5.34 per barrel in 2014 compared to 2013 and $8.19 per barrel in 2013 compared to 2012, which had negative impacts on segment income of $695 million and $978 million, respectively.

• The sweet/sour crude oil differential narrowed $1.56 per barrel in 2014 compared to 2013 and $3.94 per barrel in 2013 compared to 2012, which had negative impacts on segment income of $489 million and $273 million, respectively. The unfavorable impact from 2013 compared to 2012 was partially offset by higher refinery throughput and sales volumes.

The market indicators shown above use spot market values and an estimated mix of crude purchases and products sold. Differences in our results compared to these market indicators, including product price realizations, mix and crude costs as well as other items like refinery yields and other feedstock variances, had estimated positive impacts on Refining & Marketing segment income of $1.73 billion in 2014 compared to 2013 and $298 million in 2013 compared to 2012. We estimate the positive impact for 2014 was primarily due to more favorable net product price realizations as compared to spot market values and a favorable effect from valuing year end inventories using the LIFO method of accounting. We estimate the positive impact for 2013 was primarily due to favorable crude oil and feedstock acquisition costs compared to market indicators, partially offset by lower product price realizations.

In the fourth quarter of 2014, we recognized a build in our crude oil and refined products inventories. For purposes of our annual LIFO inventory costing, this increase in inventory is recorded based on pricing at the beginning of 2014, which was substantially higher than fourth quarter prices. As a result, Refining & Marketing segment income for the fourth quarter reflects a favorable effect of approximately $240 million. Comparing 2014 to 2013, the favorable LIFO impact was approximately $130 million.

The following table summarizes our refinery throughputs.

	2014	2013	2012
Refinery throughputs (thousands of barrels per day):
Crude oil refined	1,622	1,589	1,195
Other charge and blendstocks	184	213	168
Total	1,806	1,802	1,363
Sour crude oil throughput percent	52	53	53
WTI-priced crude oil throughput percent	19	21	28

Total refinery throughputs increased 439 mbpd in 2013 compared to 2012, primarily due to the Galveston Bay refinery, which we acquired on February 1, 2013.

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

	2014		2013		2012
Refining & Marketing gross margin (dollars per barrel)(a)	$	15.05	$	13.24	$	17.85
Refinery direct operating costs (dollars per barrel):(b)
Planned turnaround and major maintenance	$	1.80	$	1.20	$	1.00
Depreciation and amortization	1.41		1.36		1.44
Other manufacturing(c)	4.86		4.14		3.15
Total	$	8.07	$	6.70	$	5.59

^(a)  Sales revenue less cost of refinery inputs and purchased products, divided by total refinery throughputs.

^(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 $1.37 per barrel in 2014 compared to 2013 and $1.11 per barrel in 2013 compared to 2012, which include increases in planned turnaround and major maintenance costs of $0.60 per barrel and $0.20 per barrel, respectively, and increases in other manufacturing costs of $0.72 per barrel and $0.99 per barrel, respectively. The increase in planned turnaround and major maintenance costs for 2014 was primarily attributable to the Galveston Bay, Robinson and Catlettsburg refineries, partially offset by decreases at the Garyville and Canton refineries. The increase in planned turnaround and major maintenance costs for 2013 was primarily attributable to the Galveston Bay refinery. The increases in other manufacturing costs were primarily attributable to higher energy costs, catalyst expenses and routine maintenance costs for 2014 and the addition of the Galveston Bay refinery for 2013, 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 RFS2 compliance. Our expenses associated with purchased RINs were $141 million in 2014, $264 million in 2013 and $105 million in 2012. The decrease in 2014 was primarily due to decreases in the average cost of ethanol and biomass-based biodiesel RINs and decreases in our estimated advanced biofuel and ethanol obligation volumes. The increase in 2013 was primarily due to increases in the average cost of ethanol and biodiesel RINs.

Speedway segment income from operations increased $169 million in 2014 compared to 2013 and $65 million in 2013 compared to 2012, primarily due to increases in our gasoline and distillate gross margin of $246 million and $54 million, respectively, and increases in our merchandise gross margin of $150 million and $30 million, respectively, partially offset by higher operating expenses. The increases were primarily attributable to increases in the number of convenience stores, which for 2014 was primarily due to the acquisition of convenience stores from Hess. The increases in merchandise gross margin were related to a combination of higher merchandise and food sales and improved margins. The convenience stores acquired from Hess contributed $113 million to Speedway segment income from operations in 2014.

The following table includes margin statistics for the Speedway segment.

	2014			2013			2012
Gasoline & distillate gross margin (dollars per gallon)(a)	$	0.1775		$	0.1441		$	0.1318
Merchandise gross margin (in millions)	$	975		$	825		$	795
Merchandise gross margin percent	27.0		%	26.3		%	26.0		%

^(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.

Pipeline Transportation segment income from operations increased $70 million in 2014 compared to 2013 and decreased $6 million in 2013 compared to 2012. The increase in 2014 was primarily due tohigher pipeline transportation revenue and an increase in income from our pipeline affiliates, which was primarily attributable to our investment in LOOP, partially offset by an increase in operating expenses primarily attributable to the proposed Cornerstone pipeline project and pipeline maintenance costs. The decrease in 2013 was primarily due to 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 increased $15 million in 2014 compared to 2013 and decreased $65 million in 2013 compared to 2012, primarily due to costs incurred in connection with the acquisition of Hess’ Retail Operations and Related Assets in 2014 and lower unallocated employee benefit expenses and lower employee incentive compensation expenses in 2013 compared to 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 $96 million in 2014, $95 million in 2013 and $124 million in 2012 resulting from the level of employee lump sum retirement distributions that occurred during these years.

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Liquidity and Capital Resources

Cash Flows

Our cash and cash equivalents balance was $1.49 billion at December 31, 2014 compared to $2.29 billion at December 31, 2013. 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)	2014			2013			2012
Net cash provided by (used in):
Operating activities	$	3,110		$	3,405		$	4,492
Investing activities	(4,543		)	(2,756		)	(1,452		)
Financing activities	635			(3,217		)	(1,259		)
Total	$	(798	)	$	(2,568	)	$	1,781

Net cash provided by operating activities decreased$295 million in 2014 compared to 2013, primarily due to unfavorable changes in working capital of $892 million compared to 2013, partially offset by an increase in net income of $422 million and non-cash income adjustments of $175 million. 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.

For 2014, changes in working capital were a net $694 millionuse of cash, primarily due to a decrease in accounts payable and accrued liabilities and an increase in inventories, partially offset by a decrease in current receivables. Changes from December 31, 2013 to December 31, 2014 per the consolidated balance sheets, excluding the impact of acquisitions, were as follows:

• Accounts payable decreased$1.65 billion from year-end 2013, primarily due to lower crude oil payable prices, partially offset by higher crude oil payable volumes.

• Inventories increased $796 million from year-end 2013, primarily due to higher refined product and crude oil inventory volumes.

• Current receivables decreased $1.63 billion from year-end 2013, primarily due to lower refined product and crude oil receivable prices.

For 2013, changes in working capital were a net $198 million source 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.

For 2012, changes in working capital were a net $428 million use of cash, 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.

Cash flows used in investing activities increased $1.79 billion in 2014 compared to 2013 and $1.30 billion in 2013 compared to 2012. 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 total capital expenditures and investments follows for each of the last three years.

(In millions)	2014		2013		2012
Additions to property, plant and equipment per consolidated statements of cash flows	$	1,480	$	1,206	$	1,369
Non-cash additions to property, plant and equipment	4		—		—
Asset retirement expenditures	2		—		—
Increase (decrease) in capital accruals	95		73		(117		)
Investments in equity method investees	413		124		28
Total capital expenditures and investments before acquisitions	1,994		1,403		1,280
Acquisitions(a)	2,744		1,386		180
Total capital expenditures and investments	$	4,738	$	2,789	$	1,460

^(a)  The 2014 acquisitions include the acquisition of Hess’ Retail Operations and Related Assets. The 2013 acquisitions include the acquisition of the Galveston Bay Refinery and Related Assets. The acquisition numbers above include property, plant and equipment and intangibles. 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)	2014		2013		2012
Capital expenditures and investments:(a)(b)
Refining & Marketing	$	1,104	$	2,094	$	705
Speedway	2,981		296		340
Pipeline Transportation	543		234		211
Corporate and Other(c)	110		165		204
Total	$	4,738	$	2,789	$	1,460

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

^(b)  Includes $2.71 billion in 2014 for the acquisition of Hess’ Retail Operations and Related Assets and $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Item 8. Financial Statements and Supplementary Data – Note 5.

^(c)  Includes capitalized interest of $27 million, $28 million and $101 million for 2014, 2013 and 2012, respectively.

The acquisition of Hess’ Retail Operations and Related Assets comprised 58 percent of our total capital spending in 2014. 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 (excluding capitalized interest associated with this project) of our Refining & Marketing segment capital spending in 2012.

Cash provided by disposal of assets totaled $27 million, $16 million and $53 million in 2014, 2013 and 2012, 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.

Net investments were a $404 millionuse of cash in 2014 compared to a $74 millionuse of cash in 2013 and a $51 millionsource of cash in 2012. The change in 2014 compared to 2013 was primarily due to increases in contributions to the Sandpiper and SAX pipeline projects of $287 million and our investment in Explorer of $77 million, partially offset by a return of capital from our ethanol affiliates of $9 million. The change in 2013 compared to 2012 was primarily due to investments in our ethanol affiliates of $75 million and the Sandpiper pipeline project of $24 million.

Financing activities were a $635 millionsource of cash in 2014, a $3.22 billionuse of cash in 2013 and a $1.26 billionuse of cash in 2012. The sources of cash primarily consisted of net long-term debt borrowings in 2014 and proceeds from the issuance of MPLX common units in 2014 and 2012. The uses of cash in all three years primarily consisted of common stock repurchases through open market purchases and our ASR programs and dividend payments.

Long-term debt borrowings and repayments were a net $3.25 billionsource of cash in 2014 compared to a $21 millionuse of cash in 2013 and a $17 millionuse of cash in 2012. During 2014, we issued $1.95 billion aggregate principal amount of senior unsecured notes and borrowed $700 million under a term loan credit agreement to finance the acquisition of Hess’ Retail Operations and Related Assets. In addition, MPLX had net borrowings of $635 million under its revolving credit agreement and term loan agreement. See Item 8. Financial Statements and Supplementary Data – Note 20 for additional information on our long-term debt.

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Cash used in common stock repurchases totaled $2.13 billion in 2014, $2.79 billion in 2013 and $1.35 billion in 2012 associated with the share repurchase plans authorized by our board of directors. The table below summarizes our total share repurchases. See Item 8. Financial Statements and Supplementary Data – Note 10 for further discussion of the share repurchase plans.

(In millions, except per share data)	2014		2013		2012
Number of shares repurchased(a)	24		37		28
Cash paid for shares repurchased	$	2,131	$	2,793	$	1,350
Effective average cost per delivered share	$	88.63	$	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.

Cash used in dividend payments totaled $524 million in 2014, $484 million in 2013 and $407 million in 2012. The increases were primarily due to increases in our base dividend, partially offset by a decrease in the number of outstanding shares of our common stock as a result of share repurchases. Dividends per share were $1.84 in 2014, $1.54 in 2013 and $1.20 in 2012.

Cash proceeds from the issuance of MPLX common units were $221 million in 2014 and $407 million in 2012. The initial public offering in 2012 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.

Derivative Instruments

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

Capital Resources

Our liquidity totaled $5.27 billion at December 31, 2014 consisting of:

	December 31, 2014
(In millions)	Total Capacity		Outstanding Borrowings		Available Capacity
Revolving credit agreement(a)	$	2,500	$	—	$	2,500
Trade receivables securitization facility(b)	1,280		—		1,280
Total	$	3,780	$	—	$	3,780
Cash and cash equivalents					1,494
Total liquidity					$	5,274

^(a)  Excludes MPLX’s $1 billion revolving credit agreement, which had $385 million of borrowings outstanding as of December 31, 2014.

^(b)  Availability under our $1.3 billion trade receivables securitization facility is a function of refined product selling prices, which will be lower in a sustained lower price environment. As of January 31, 2015, eligible trade receivables supported borrowings of $700 million.

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.

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.

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There were no borrowings or letters of credit outstanding at December 31, 2014.

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. 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.

As of December 31, 2014, eligible trade receivables supported borrowings of $1.28 billion. There were no borrowings outstanding at December 31, 2014. Availability under our trade receivables securitization facility is a function of refined product selling prices, which will be lower in a sustained lower price environment. As of January 31, 2015, eligible trade receivables supported borrowings of $700 million.

MPLX Credit Agreement – On November 20, 2014, MPLX entered into a credit agreement with a syndicate of lenders (“MPLX Credit Agreement”), which provides for a five-year $1 billion bank revolving credit facility and a $250 million term loan facility. The maturity date on both facilities is November 20, 2019.

The bank revolving credit facility includes letter of credit issuing capacity of up to $250 million and swingline loan capacity of up to $100 million. The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional $500 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 the majority of the commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the original maturity date.

The term loan facility was drawn in full on November 20, 2014. The maturity date for the term loan facility may be extended for up to two additional one-year periods subject to the consent of the lenders holding a majority of the outstanding term loan borrowings, provided that the portion of the term loan borrowings held by any non-consenting lenders will continue to be due and payable on the original maturity date. The borrowings under this facility during 2014 were at an average interest rate of 1.4 percent.

Borrowings under the MPLX Credit Agreement bear interest at either the Adjusted LIBO Rate or the Alternate Base Rate (as defined in the MPLX Credit Agreement) plus a specified 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 bank revolving credit facility and fees with respect to issued and outstanding letters of credit. The applicable interest rates and certain of the fees fluctuate based the credit ratings in effect from time to time on MPLX’s long-term debt.

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In connection with entering into this new credit agreement, MPLX terminated its previously existing $500 millionfive-year MPLX Operations LLC bank revolving credit agreement, dated as of September 14, 2012. During 2014, MPLX borrowed $280 million under the MPLX Operations LLC bank revolving credit agreement, at an average interest rate of 1.5 percent, per annum, and repaid all of these borrowings.

During 2014, MPLX borrowed $630 million under the new revolving credit agreement, at an average interest rate of 1.4 percent, per annum, and repaid $245 million of these borrowings. At December 31, 2014, MPLX had $385 million of borrowings and no letters of credit outstanding under the MPLX Credit Agreement, resulting in total unused loan availability of $615 million, or 61.5 percent of the borrowing capacity.

Debt-to-Total-Capital Ratio

As described in further detail below, the increase in debt as of year-end 2014 compared to year-end 2013 was primarily related to financing a portion of the purchase price for the acquisition of Hess’ Retail Operations and Related Assets. Our debt-to-total capital ratio (total debt to total debt-plus-equity) was 37 percent and 23 percent at December 31, 2014 and 2013, respectively.

	December 31,
(In millions)	2014			2013
Long-term debt due within one year	$	27		$	23
Long-term debt	6,610			3,373
Total debt	$	6,637		$	3,396
Calculation of debt-to-total capital ratio:
Total debt	$	6,637		$	3,396
Plus equity	11,390			11,332
Total debt plus equity	$	18,027		$	14,728
Debt-to-total capital ratio	37		%	23		%

MPC Term Loan Agreement – On August 26, 2014, we entered into a $700 millionfive-year senior unsecured term loan credit agreement (the “Term Loan Agreement”) with a syndicate of lenders to fund a portion of the purchase price for the acquisition of Hess’ Retail Operations and Related Assets. The Term Loan Agreement matures on September 24, 2019 and may be prepaid at any time without premium or penalty. We are obligated to pay certain customary fees under the Term Loan Agreement, including an annual administrative fee.

Amounts outstanding under the Term Loan Agreement bear interest at either of the following rates at our election (i) the sum of the Adjusted LIBO Rate (as defined in the Term Loan Agreement), plus a margin ranging between 0.875 percent to 1.75 percent, depending on our credit ratings, or (ii) the sum of the Base Rate (as defined in the Term Loan Agreement), plus a margin ranging between zero percent to 0.75 percent, depending on our credit ratings. The borrowings under this facility during 2014 were at an average interest rate of 1.3 percent.

Senior Notes – On September 5, 2014, we completed a public offering of $1.95 billion aggregate principal amount of senior unsecured notes (the “Senior Notes”), consisting of $750 million aggregate principal amount of our Senior Notes due 2024, $800 million aggregate principal amount of our Senior Notes due 2044 and $400 million aggregate principal amount of our Senior Notes due 2054. The net proceeds from the offering of the Senior Notes were approximately $1.92 billion, after deducting underwriting discounts and estimated offering expenses. The net proceeds were used to fund a portion of the purchase price for the acquisition of Hess’ Retail Operations and Related Assets. Interest on each series of Senior Notes is payable semi-annually in arrears on March 15 and September 15 of each year, commencing on March 15, 2015.

The Senior Notes are unsecured and unsubordinated obligations of ours and rank equally with all our other existing and future unsecured and unsubordinated indebtedness.

The Term Loan Agreement, the Credit Agreement and the MPLX Credit Agreement contain representations and warranties, affirmative and negative covenants and events of default that we consider usual and customary for agreements of these types. The financial covenant included in the Term Loan Agreement and the MPC Credit Agreement requires us to maintain, as of the last day of each fiscal quarter, a ratio of Consolidated Net Debt to Total Capitalization (as defined in the Term Loan Agreement and the MPC Credit Agreement) of no greater than 0.65 to 1.00. As of December 31, 2014, we were in compliance with this debt covenant with a ratio of Consolidated Net Debt to Total Capitalization of 0.33 to 1.00, as well as the other covenants contained in the Term Loan Agreement and the MPC Credit Agreement.

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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. The MPLX Credit Agreement includes 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 (both as defined in the MPLX Credit Agreement) for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 for up to two fiscal quarters following certain acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period. Other covenants restrict MPLX from incurring debt, creating liens on its assets and entering into transactions with affiliates. As of December 31, 2014, MPLX was in compliance with the covenants contained in the MPLX Credit Agreement, including a ratio of Consolidated Total Debt to Consolidated EBITDA of 2.8 to 1.0.

Our intention is to maintain an investment grade credit profile. As of February 9, 2015, the credit ratings on our senior unsecured debt were at or above investment grade level as follows.

Rating Agency	Rating
Moody’s	Baa2 (stable outlook)
Standard & Poor’s	BBB (stable outlook)
Fitch	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 letters of credit under existing transportation services agreements.

Capital Requirements

We have a capital and investment budget for 2015 of $2.53 billion, excluding capitalized interest. Additional details related to the 2015 capital and investment budget are discussed in the Capital Budget Outlook section below.

Pursuant to the purchase and sale agreement for the Galveston Bay Refinery and Related Assets, we may be required to pay the seller a contingent earnout of up to an additional $700 million over six years, subject to certain conditions. In July 2014, we paid $180 million for the first period’s contingent earnout. See Item 8. Financial Statements and Supplementary Data – Notes 5 and 18.

While we have no required contributions to our pension plans for 2015, we may make voluntary contributions at our discretion.

On January 31, 2015, our board of directors approved a 50 cents per share dividend, payable March 10, 2015 to stockholders of record at the close of business on February 18, 2015.

On July 30, 2014, our board of directors approved an additional $2.0 billion share repurchase authorization expiring in July 2016. As of December 31, 2014, our board of directors had approved $8.0 billion in total share repurchase authorizations since January 1, 2012 and we have repurchased a total of $6.27 billion of our common stock under these authorizations, leaving $1.73 billion available for repurchases. Under these authorizations, we have acquired 89 million shares at an average cost per share of $70.35.

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.

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.

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Contractual Cash Obligations

The table below provides aggregated information on our consolidated obligations to make future payments under existing contracts as of December 31, 2014. 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		2015		2016-2017		2018-2019		Later Years
Long-term debt(a)	$	11,141	$	276	$	1,256	$	1,809	$	7,800
Capital lease obligations(b)	470		47		90		84		249
Operating lease obligations	1,326		249		359		250		468
Purchase obligations:(c)
Crude oil, feedstock, refined product and renewable fuel contracts(d)	10,379		7,500		800		1,023		1,056
Transportation and related contracts	4,336		257		656		840		2,583
Contracts to acquire property, plant and equipment(e)(f)	1,727		784		943		—		—
Service, materials and other contracts(g)	2,047		478		532		402		635
Total purchase obligations	18,489		9,019		2,931		2,265		4,274
Other long-term liabilities reported in the consolidated balance sheet(h)	1,111		77		181		235		618
Total contractual cash obligations	$	32,537	$	9,668	$	4,817	$	4,643	$	13,409

^(a)  Includes interest payments for our senior notes, term loans and the MPLX Credit Agreement 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.

^(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 futures curves.

^(e)  Includes $703 million to fund 37.5 percent of the construction of the Sandpiper pipeline project and $185 million to fund 35 percent of the construction of the SAX pipeline project.

^(f)  Includes $520 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 2024. See Item 8. Financial Statements and Supplementary Data – Note 23.

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 26.

Capital Budget Outlook

We have a capital and investment budget for 2015 of $2.53 billion, excluding capitalized interest and any acquisitions we may make. This represents a 27 percent increase from our 2014 spending, excluding the acquisition of Hess’ Retail Operations and Related Assets. 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 2015 capital budget is $1.28 billion, which includes $234 million for midstream assets, approximately $370 million for refining margin enhancement projects and approximately $675 million for refinery-sustaining capital. A number of these projects span multiple years.

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The $234 million budgeted for midstream assets includes projects that will allow us to process condensate from the Utica Shale region and grow Gulf Coast export capabilities. We have a project to build a condensate splitter at our Catlettsburg refinery to allow it to process up to 35 mbpcd of condensate from the Utica Shale region that we expect to complete in 2015. We began operation of a condensate splitter at our Canton refinery at the end of 2014 to allow it to process up to 25 mbpcd of condensate. We have projects at our Galveston Bay and Garyville refineries to increase export capabilities by 165 mbpd by 2018. In 2015, we expect to complete projects representing 50 mbpd of that total.

The $370 million budgeted for refining margin enhancement projects includes projects that will allow us to increase our diesel production and to process light crude oil from the Utica Shale region. At our Garyville refinery, 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 nine 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 five mbpd of light products to ULSD production and a project to increase the light crude oil processing capacity by 30 mbpcd, which will allow it to run 100 percent light crude oil. We expect to complete these projects in 2015 and 2016, respectively.

During 2014, we worked on a front-end engineering and design study for a residual fuel hydrocracker project at our Garyville refinery intended to increase margins by upgrading residual fuel to ULSD and gas oil. We are deferring a final investment decision on this project with estimated total costs of $2.2 billion to $2.5 billion as we further evaluate the implications of current market conditions on the project. As of December 31, 2014, we have capitalized $90 million of costs associated with this project. If a decision is made to not pursue this project, there could be a future impairment of the costs incurred for the project.

The remaining $675 million budget is primarily allocated to maintaining facilities and meeting regulatory requirements at our refineries.

Speedway

The Speedway segment’s 2015 capital budget of $452 million is focused on continued growth and integrating the convenience stores acquired from Hess into Speedway. The budget includes approximately $240 million for the Hess retail outlets primarily associated with store conversions and remodels, which will drive incremental merchandise sales. The remaining budget is primarily for new convenience store construction and land acquisition 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 or store rebuilds in our existing market, western Pennsylvania and Tennessee. Also included in the capital budget are expenditures for technology, equipment and dispenser upgrades.

Pipeline Transportation

The Pipeline Transportation segment’s 2015 capital budget of $659 million is focused on projects to support the changing energy landscape in the United States, including equity investments in major pipeline projects, new infrastructure and upgrades to replace or enhance our existing facilities. We expect to invest approximately $310 million in the Sandpiper and SAX pipeline projects in 2015 and $1.5 billion in total.

In addition, pending the completion of a binding open season, MPLX is planning to construct the Cornerstone pipeline project to connect Utica Shale production in southeastern Ohio to our Canton refinery and related build-out opportunities, which is expected to cost approximately $200 million and is anticipated to be operational in 2016.

Corporate and Other

The remaining 2015 capital budget includes $140 million, primarily related to an expansion project for our corporate headquarters and upgrades to information technology systems.

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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.

Transactions with Related Parties

We believe that transactions with related parties were conducted under terms comparable to those with unrelated parties. See Item 8. Financial Statements and Supplementary Data – Note 8 for 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)	2014		2013		2012
Capital	$	102	$	50	$	115
Compliance:(a)
Operating and maintenance	397		321		318
Remediation(b)	36		22		24
Total	$	535	$	393	$	457

^(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.

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

Our environmental capital expenditures accounted for five percent, four percent and eight percent of capital expenditures excluding the acquisitions of the Galveston Bay Refinery and Related Assets and Hess’ Retail Operations and Related Assets in 2014, 2013 and 2012, respectively. Our environmental capital expenditures are expected to approximate $250 million, or ten percent, of total capital expenditures in 2015. Predictions beyond 2015 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 $410 million in 2016; 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 18 for disclosures regarding our fair value measurements.

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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.

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, 2014, we had a total of $1.57 billion of goodwill recorded on our consolidated balance sheet. The fair value of our reporting units exceeded book value for each of our reporting units in 2014.

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, 2014, we had $865 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.

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Centennial experienced a significant reduction in shipment volumes in the second half of 2011 that has continued through 2014. At December 31, 2014, 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 market conditions were to change 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, 2014, our equity investment in Centennial was $36 million and we had a $38 million guarantee associated with 50 percent of Centennial’s outstanding debt. See Item 8. Financial Statements and Supplementary Data – Note 26 for additional information on the debt guarantee.

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 18 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 18. Additional information about derivatives and their valuation may be found in Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

Pension and Other Postretirement Benefit Obligations

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

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

• the expected long-term return on plan assets;

• the rate of future increases in compensation levels;

• health care cost projections; and

• the mortality table used in determining future plan obligations.

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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.

Of the assumptions used to measure the year-end obligations and estimated annual net periodic benefit cost, the discount rate has the most significant effect on the periodic benefit cost reported for the plans. Decreasing the discount rates of 3.65 percent for our pension plans and 4.15 percent for our other postretirement benefit plans by 0.25 percent would increase pension obligations and other postretirement benefit plan obligations by $42 million and $32 million, respectively, and would increase defined benefit pension expense and other postretirement benefit plan expense by $2 million and $4 million, respectively.

The long-term asset rate of return assumption considers the asset mix of the plans (currently targeted at approximately 51 percent equity securities and 49 percent fixed income securities for the primary funded pension plan), 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 for our primary plan from 7.00 percent to 6.75 percent effective for 2015. We used the 7.00 percent long-term rate of return to determine our 2014 defined benefit pension expense. Decreasing the 6.75 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.

We utilized the 2014 mortality tables from the U.S. Society of Actuaries.

Item 8. Financial Statements and Supplementary Data – Note 23 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.

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Accounting Standards Not Yet Adopted

In February 2015, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update making targeted changes to the current consolidation guidance. The new standard changes the way certain decisions are made related to substantive rights, related parties, and decision making fees when applying the VIE consolidation model and eliminates certain guidance for limited partnerships and similar entities under the voting interest consolidation model. The update is effective for annual periods beginning after December 15, 2015. Early adoption is permitted. At this point, we have not determined the impact of the new standards update on our consolidated financial statements and related disclosures. 

In August 2014, the FASB issued an accounting standards update requiring management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Management will be required to assess if there is substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. Disclosures will be required if conditions give rise to substantial doubt and the type of disclosure will be determined based on whether management’s plans will be able to alleviate the substantial doubt. The accounting standards update will be effective for the first annual period ending after December 15, 2016, and for annual periods and interim periods thereafter with early application permitted.

In June 2014, the FASB issued an accounting standards update for the elimination of the concept of development stage entity (“DSE”) from U.S. GAAP and removes the related incremental reporting. The standards update eliminates the additional financial statement requirements specific to a DSE. In addition, it amends the consolidation model by eliminating the special provisions in the variable interest entity rules for assessing the sufficiency of the equity of a DSE. The portion of the accounting standards update related to the amendment to the consolidation guidance will be effective on a retrospective basis for annual reporting periods beginning after December 15, 2015, and interim periods within those years, with early adoption permitted. The portion of the accounting standards update related to the removal of the DSE reporting requirements will be effective on a retrospective basis for annual reporting periods beginning after December 15, 2014, and interim periods within those years, with early adoption permitted. Adoption of this standards update in the first quarters of 2015 and 2016 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

In May 2014, the FASB issued an accounting standards update for revenue recognition that is aligned with the International Accounting Standards Board’s revenue recognition standard issued on the same day. The guidance in the update states that revenue is recognized when a customer obtains control of a good or service. Recognition of the revenue will involve a multiple step approach including identifying the contract, identifying the separate performance obligations, determining the transaction price, allocating the price to the performance obligations and then recognizing the revenue as the obligations are satisfied. Additional disclosures will be required to provide adequate information to understand the nature, amount, timing and uncertainty of reported revenues and revenues expected to be recognized. The accounting standards update will be effective on a retrospective or modified retrospective basis for annual reporting periods beginning after December 15, 2016, and interim periods within those years, with no early adoption permitted. At this point, we have not determined the impact of the new standard on our consolidated financial statements.

In April 2014, the FASB issued an accounting standards update that redefines the criteria for determining discontinued operations and introduces new disclosures related to these disposals. The updated definition of a discontinued operation is the disposal of a component (or components) of an entity or the classification of a component (or components) of an entity as held for sale that represents a strategic shift for an entity and has (or will have) a major impact on an entity’s operations and financial results. The standard requires disclosure of additional financial information for discontinued operations and individually material components not qualifying for discontinued operation presentation, as well as information regarding an entity’s continuing involvement with the discontinued operation. The accounting standards update is effective prospectively for annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted. Adoption of this standards update in the first quarter of 2015 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

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Item 7A. Quantitative and Qualitative Disclosures about Market Risk

General

We are exposed to market risks related to the volatility of crude oil and refined product prices. We employ various strategies, including the use of commodity derivative instruments, to hedge the risks related to these price fluctuations. We are also exposed to market risks related to changes in interest rates and foreign currency exchange rates. As of December 31, 2014, we did not have any financial derivative instruments to hedge the risks related to interest rate fluctuations; however, we have used them in the past, and we continually monitor the market and our exposure and may enter into these agreements again in the future. We are at risk for changes in fair value of all of our derivative instruments; however, such risk should be mitigated by price or rate changes related to the underlying commodity or financial transaction.

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

See Item 8. Financial Statements and Supplementary Data – Notes 18 and 19 for more information about the fair value measurement of our derivatives, as well as the amounts recorded in our consolidated balance sheets and statements of income. We do not designate any of our commodity derivative instruments as hedges for accounting purposes.

Commodity Price Risk

Our strategy is to obtain competitive prices for our products and allow operating results to reflect market price movements dictated by supply and demand. We use a variety of commodity derivative instruments, including futures 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, 2014.

	December 31, 2014
	Position	Total Barrels (In thousands)	Weighted Average Price (Per barrel)	Benchmark
Crude Oil(a)
Exchange-traded	Long	15,678	$61.53	CME and ICE Crude(c)(d)
Exchange-traded	Short	(25,257)	$65.39	CME and ICE Crude(c)(d)
Refined Products(b)
Exchange-traded	Long	2,948	$1.74	CME Heating Oil and RBOB(c)(e)
Exchange-traded	Short	(3,804)	$1.71	CME Heating Oil and RBOB(c)(e)

^(a)97 percent of these contracts expire in the first quarter of 2015.

^(b)100 percent of these contracts expire in the first quarter of 2015.

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

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

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

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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, 2014 is provided in the following table.

	Change in IFO from a Hypothetical Price Increase of						Change in IFO from a Hypothetical Price Decrease of
(In millions)	10%			25%			10%		25%
As of December 31, 2014
Crude	$	(58	)	$	(145	)	$	62	$	157
Refined products	(2		)	(4		)	2		4

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, 2014 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, 2014, our debt was primarily comprised of the $3.0 billion aggregate principal amount of fixed rate senior notes issued on February 1, 2011 and the $1.95 billion aggregate principal amount of fixed rate senior notes issued September 5, 2014. Additionally, we have $950 million of variable rate term debt.

Sensitivity analysis of the effect of a hypothetical 100-basis-point change in interest rates on long-term debt as of December 31, 2014 is provided in the following table. 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.

(In millions)	Fair Value(b)		Change in Fair Value			Change in Net Income for the Twelve Months Ended December 31, 2014
Long-term debt(a)
Fixed-rate	$	5,236	$	563	(c)	n/a
Variable-rate	1,338		n/a			4	(d)

^(a)  Excludes capital leases.

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

^(c)  Assumes a 100-basis point decrease in the weighted average yield-to-maturity at December 31, 2014.

^(d)  Assumes a 100-basis-point change in interest rates. The change in net income was based on the weighted average balance of debt outstanding for the year ended December 31, 2014.

At December 31, 2014, our portfolio of long-term debt was comprised of fixed-rate instruments and variable-rate borrowings under the Term Loan Agreement and the MPLX Credit Agreement. The fair value of our fixed-rate debt 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. Interest rate fluctuations generally do not impact the fair value of borrowings under the Term Loan Agreement and the MPLX Credit Agreement, but will affect our results of operations and cash flows.

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 2014.

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Counterparty Risk

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

Forward-Looking Statements

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

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Item 8. Financial Statements and Supplementary Data

Index

	Page
Management’s Responsibilities for Financial Statements	73
Management’s Report on Internal Control Over Financial Reporting	73
Report of Independent Registered Public Accounting Firm	74
Audited Consolidated Financial Statements:
Consolidated Statements of Income	75
Consolidated Statements of Comprehensive Income	76
Consolidated Balance Sheets	77
Consolidated Statements of Cash Flows	78
Consolidated Statements of Equity	79
Notes to Consolidated Financial Statements	80
Selected Quarterly Financial Data (Unaudited)	122
Supplementary Statistics (Unaudited)	123

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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/ John J. Quaid
Gary R. Heminger President and Chief Executive Officer	Donald C. Templin Senior Vice President and Chief Financial Officer	John J. Quaid 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 Rules 13a-15(f) and 15d-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 (2013) 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, 2014.

Management has excluded Hess’ Retail Operations and Related Assets (as defined in footnote 5) from the Company’s assessment of internal control over financial reporting as of December 31, 2014 as it was acquired by the Company in a business combination on September 30, 2014. Hess’ Retail Operations and Related Assets represents approximately 8% of consolidated total assets as of December 31, 2014 and 2% of total revenues and other income for the year ended December 31, 2014. We plan to fully integrate the acquired businesses into our internal control over financial reporting in 2015.

The effectiveness of MPC’s internal control over financial reporting as of December 31, 2014 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

73

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, and cash flows present fairly, in all material respects, the financial position of Marathon Petroleum Corporation and its subsidiariesat December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014in 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, 2014, based on criteria established in Internal Control – Integrated Framework (2013)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 Hess’ Retail Operations and Related Assets (as defined in footnote 5) from the Company’s assessment of internal control over financial reporting as of December 31, 2014 as it was acquired by the Company in a business combination on September 30, 2014. We have also excluded Hess’ Retail Operations and Related Assets from our audit of internal control over financial reporting. Hess’ Retail Operations and Related Assets represents approximately 8% of consolidated total assets as of December 31, 2014 and 2% of total revenue and other income for the year ended December 31, 2014.

/s/PricewaterhouseCoopers LLP

Toledo, Ohio

February 27, 2015

74

Marathon Petroleum Corporation

Consolidated Statements of Income

(In millions, except per share data)	2014			2013			2012
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$	97,817		$	100,160		$	82,243
Income from equity method investments	153			36			26
Net gain on disposal of assets	21			6			177
Other income	111			52			46
Total revenues and other income	98,102			100,254			82,492
Costs and expenses:
Cost of revenues (excludes items below)	83,770			87,401			68,668
Purchases from related parties	505			357			280
Consumer excise taxes	6,685			6,263			5,709
Depreciation and amortization	1,326			1,220			995
Selling, general and administrative expenses	1,375			1,248			1,223
Other taxes	390			340			270
Total costs and expenses	94,051			96,829			77,145
Income from operations	4,051			3,425			5,347
Net interest and other financial income (costs)	(216		)	(179		)	(109		)
Income before income taxes	3,835			3,246			5,238
Provision for income taxes	1,280			1,113			1,845
Net income	2,555			2,133			3,393
Less net income attributable to noncontrolling interests	31			21			4
Net income attributable to MPC	$	2,524		$	2,112		$	3,389
Per Share Data (See Note 9)
Basic:
Net income attributable to MPC per share	$	8.84		$	6.69		$	9.95
Weighted average shares outstanding	285			315			340
Diluted:
Net income attributable to MPC per share	$	8.78		$	6.64		$	9.89
Weighted average shares outstanding	287			317			342
Dividends paid	$	1.84		$	1.54		$	1.20

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

75

Marathon Petroleum Corporation

Consolidated Statements of Comprehensive Income

(In millions)	2014			2013			2012
Net income	$	2,555		$	2,133		$	3,393
Other comprehensive income (loss):
Defined benefit postretirement and post-employment plans:
Actuarial changes, net of tax of ($47), $174 and $47	(78		)	294			78
Prior service costs, net of tax of ($19), ($19) and $203	(31		)	(34		)	337
Other comprehensive income (loss)	(109		)	260			415
Comprehensive income	2,446			2,393			3,808
Less comprehensive income attributable to noncontrolling interests	31			21			4
Comprehensive income attributable to MPC	$	2,415		$	2,372		$	3,804

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

76

Marathon Petroleum Corporation

Consolidated Balance Sheets

	December 31,
(In millions, except share data)	2014			2013
Assets
Current assets:
Cash and cash equivalents	$	1,494		$	2,292
Receivables, less allowance for doubtful accounts of $13 and $9	4,058			5,559
Inventories	5,642			4,689
Other current assets	145			197
Total current assets	11,339			12,737
Equity method investments	865			463
Property, plant and equipment, net	16,261			13,921
Goodwill	1,566			938
Other noncurrent assets	429			326
Total assets	$	30,460		$	28,385
Liabilities
Current liabilities:
Accounts payable	$	6,661		$	8,234
Payroll and benefits payable	427			406
Consumer excise taxes payable	463			373
Accrued taxes	647			513
Long-term debt due within one year	27			23
Other current liabilities	354			275
Total current liabilities	8,579			9,824
Long-term debt	6,610			3,373
Deferred income taxes	2,014			2,304
Defined benefit postretirement plan obligations	1,099			771
Deferred credits and other liabilities	768			781
Total liabilities	19,070			17,053
Commitments and contingencies (see Note 26)
Equity
MPC stockholders’ equity:
Preferred stock, no shares issued and outstanding (par value $0.01 per share, 30 million shares authorized)	—			—
Common stock:
Issued – 363 million and 362 million shares (par value $0.01 per share, 1 billion shares authorized)	4			4
Held in treasury, at cost – 89 million and 65 million shares	(6,299		)	(4,155		)
Additional paid-in capital	9,844			9,768
Retained earnings	7,515			5,507
Accumulated other comprehensive loss	(313		)	(204		)
Total MPC stockholders’ equity	10,751			10,920
Noncontrolling interests	639			412
Total equity	11,390			11,332
Total liabilities and equity	$	30,460		$	28,385

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

77

Marathon Petroleum Corporation

Consolidated Statements of Cash Flows

(In millions)	2014			2013			2012
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	2,555		$	2,133		$	3,393
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	1,326			1,220			995
Pension and other postretirement benefits, net	151			(124		)	153
Deferred income taxes	(242		)	23			492
Net gain on disposal of assets	(21		)	(6		)	(177		)
Equity method investments, net	17			(18		)	11
Changes in the fair value of derivative instruments	(3		)	(21		)	59
Changes in:
Current receivables	1,642			(940		)	851
Inventories	(786		)	(305		)	(115		)
Current accounts payable and accrued liabilities	(1,547		)	1,464			(1,223		)
All other, net	18			(21		)	53
Net cash provided by operating activities	3,110			3,405			4,492
Investing activities:
Additions to property, plant and equipment	(1,480		)	(1,206		)	(1,369		)
Acquisitions, net of cash acquired	(2,821		)	(1,515		)	(190		)
Disposal of assets	27			16			53
Investments – acquisitions, loans and contributions	(413		)	(151		)	(57		)
– redemptions, repayments and return of capital	9			77			108
All other, net	135			23			3
Net cash used in investing activities	(4,543		)	(2,756		)	(1,452		)
Financing activities:
Long-term debt – borrowings	3,793			—			—
– repayments	(548		)	(21		)	(17		)
Debt issuance costs	(22		)	(4		)	(6		)
Issuance of common stock	26			48			108
Common stock repurchased	(2,131		)	(2,793		)	(1,350		)
Dividends paid	(524		)	(484		)	(407		)
Net proceeds from issuance of MPLX LP common units	221			—			407
Distributions to noncontrolling interests	(27		)	(21		)	—
Tax settlement with Marathon Oil Corporation	—			39			—
Contingent consideration payment	(172		)	—			—
All other, net	19			19			6
Net cash provided by (used in) financing activities	635			(3,217		)	(1,259		)
Net increase (decrease) in cash and cash equivalents	(798		)	(2,568		)	1,781
Cash and cash equivalents at beginning of period	2,292			4,860			3,079
Cash and cash equivalents at end of period	$	1,494		$	2,292		$	4,860

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

78

Marathon Petroleum Corporation

Consolidated Statements of Equity

	MPC Stockholders’ Equity
(In millions)	Common Stock		Treasury Stock			Additional Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Noncontrolling Interests			Total Equity
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
Net income	—		—			—			2,524			—			31			2,555
Dividends declared	—		—			—			(525		)	—			—			(525		)
Distributions to noncontrolling interests	—		—			—			—			—			(27		)	(27		)
Other comprehensive loss	—		—			—			—			(109		)	—			(109		)
Shares repurchased	—		(2,131		)	—			—			—			—			(2,131		)
Shares issued (returned) – stock-based compensation	—		(13		)	26			—			—			—			13
Stock-based compensation	—		—			50			—			—			2			52
Issuance of MPLX LP common units	—		—			—			—			—			221			221
Other	—		—			—			9			—			—			9
Balance as of December 31, 2014	$	4	$	(6,299	)	$	9,844		$	7,515		$	(313	)	$	639		$	11,390

(Shares in millions)	Common Stock	Treasury Stock
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	)
Shares repurchased	—	(24	)
Shares issued – stock-based compensation	1	—
Balance as of December 31, 2014	363	(89	)

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

79

Notes to Consolidated Financial Statements

1. Description of the Business 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 and pipeline transportation operations conducted primarily in the Midwest, Gulf Coast, East Coast and Southeast regions of the United States, through subsidiaries, including Marathon Petroleum Company LP, Speedway LLC and its subsidiaries (“Speedway”) and MPLX LP and its subsidiaries (“MPLX”).

See Note 11 for additional information about our operations.

Spinoff– 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 (the “Spinoff”). MPC became an independent, publicly traded company on July 1, 2011.

Basis of Presentation – Our results of operations and cash flows consist of consolidated MPC activities. All significant intercompany transactions and accounts have been eliminated.

During the first quarter of 2014, we recorded an out-of-period adjustment for additional expenses related to the prior year’s bonus programs of $29 million, included in total costs and expenses on the consolidated statements of income. The impact to our consolidated results of operations for the year ended December 31, 2014 and for the year ended December 31, 2013 was immaterial.

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 71.5 percent controlling financial interest, and we record a noncontrolling interest for the 28.5 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.

80

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, 2014 and 2013, the amount of restricted cash included in other current assets on the consolidated balance sheets were $4 million and $7 million, respectively.

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 41 percent and 38 percent of our accounts receivable balances at December 31, 2014 and 2013, 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. Costs for crude oil and refined product inventories are aggregated on a consolidated basis for purposes of assessing if the LIFO cost basis of these inventories may have to be written down to market value.

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.

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.

81

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 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.

82

Stock-based compensation arrangements – The fair value of stock options 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 50 percent of our common stock implied volatility and 50 percent of MPC’s common stock historical volatility.

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. 

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.

3. Accounting Standards

Not Yet Adopted

In February 2015, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update making targeted changes to the current consolidation guidance. The new standard changes the way certain decisions are made related to substantive rights, related parties, and decision making fees when applying the VIE consolidation model and eliminates certain guidance for limited partnerships and similar entities under the voting interest consolidation model. The update is effective for annual periods beginning after December 15, 2015. Early adoption is permitted. At this point, we have not determined the impact of the new standards update on our consolidated financial statements and related disclosures. 

In August 2014, the FASB issued an accounting standards update requiring management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Management will be required to assess if there is substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. Disclosures will be required if conditions give rise to substantial doubt and the type of disclosure will be determined based on whether management’s plans will be able to alleviate the substantial doubt. The accounting standards update will be effective for the first annual period ending after December 15, 2016, and for annual periods and interim periods thereafter with early application permitted.

In June 2014, the FASB issued an accounting standards update for the elimination of the concept of development stage entity (“DSE”) from U.S. GAAP and removes the related incremental reporting. The standards update eliminates the additional financial statement requirements specific to a DSE. In addition, it amends the consolidation model by eliminating the special provisions in the variable interest entity rules for assessing the sufficiency of the equity of a DSE. The portion of the accounting standards update related to the amendment to the consolidation guidance will be effective on a retrospective basis for annual reporting periods beginning after December 15, 2015, and interim periods within those years, with early adoption permitted. The portion of the accounting standards update related to the removal of the DSE reporting requirements will be effective on a retrospective basis for annual reporting periods beginning after December 15, 2014, and interim periods within those years, with early adoption permitted. Adoption of this standards update in the first quarters of 2015 and 2016 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

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In May 2014, the FASB issued an accounting standards update for revenue recognition that is aligned with the International Accounting Standards Board’s revenue recognition standard issued on the same day. The guidance in the update states that revenue is recognized when a customer obtains control of a good or service. Recognition of the revenue will involve a multiple step approach including identifying the contract, identifying the separate performance obligations, determining the transaction price, allocating the price to the performance obligations and then recognizing the revenue as the obligations are satisfied. Additional disclosures will be required to provide adequate information to understand the nature, amount, timing and uncertainty of reported revenues and revenues expected to be recognized. The accounting standards update will be effective on a retrospective or modified retrospective basis for annual reporting periods beginning after December 15, 2016, and interim periods within those years, with no early adoption permitted. At this point, we have not determined the impact of the new standard on our consolidated financial statements.

In April 2014, the FASB issued an accounting standards update that redefines the criteria for determining discontinued operations and introduces new disclosures related to these disposals. The updated definition of a discontinued operation is the disposal of a component (or components) of an entity or the classification of a component (or components) of an entity as held for sale that represents a strategic shift for an entity and has (or will have) a major impact on an entity’s operations and financial results. The standard requires disclosure of additional financial information for discontinued operations and individually material components not qualifying for discontinued operation presentation, as well as information regarding an entity’s continuing involvement with the discontinued operation. The accounting standards update is effective prospectively for annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted. Adoption of this standards update in the first quarter of 2015 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

4. MPLX LP    

MPLX is a publicly traded master limited partnership that was formed by us to own, operate, develop and acquire pipelines and other midstream assets related to the transportation and storage of crude oil, refined products and other hydrocarbon-based products. In October 2012, MPLX completed its initial public offering of 19.9 million common units. Net proceeds to MPLX from the sale of the units were $407 million.

As of December 31, 2014, we owned a 71.5 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.

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 a five percent interest in Pipe Line Holdings to MPLX for $100 million of cash on-hand.

On March 1, 2014, we sold MPLX a 13 percent interest in Pipe Line Holdings for $310 million. MPLX financed this transaction with $40 million of cash on-hand and $270 million of borrowings on its bank revolving credit agreement.

On December 1, 2014, we sold and contributed interests in Pipe Line Holdings totaling 30.5 percent to MPLX for $600 million in cash and 2.9 million MPLX common units valued at $200 million. MPLX financed the sales portion of this transaction with $600 million of borrowings on its bank revolving credit facility.

The sales and contribution of our interests in Pipe Line Holdings to MPLX resulted in a change of our ownership in Pipe Line Holdings, but not a change in control. We accounted for these sales as transactions between entities under common control and did not record a gain or loss.

On December 8, 2014, MPLX completed a public offering of 3.5 million common units at a price to the public of $66.68 per common unit, with net proceeds of $221 million. MPLX used the net proceeds from this offering to repay borrowings under its bank revolving credit facility and for general partnership purposes. On December 10, 2014, we exercised our right to maintain our two percent general partner interest in MPLX by purchasing 130 thousand general partner units for $9 million.

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 various long-term, fee-based transportation and storage services agreements with MPLX. Under these agreements, MPLX provides transportation and storage services to us, and we commit to provide MPLX with minimum quarterly throughput volumes on crude oil and products systems and minimum storage volumes of crude oil, products and butane. We also have agreements with MPLX which establish fees for operational and management services provided between us and MPLX and for executive management services and certain general and administrative services provided by us to MPLX. These transactions are eliminated in consolidation.

5. Acquisitions and Investments

Acquisition of Hess’ Retail Operations and Related Assets

On September 30, 2014, we acquired from Hess Corporation (“Hess”) all of Hess’ retail locations, transport operations and shipper history on various pipelines, including approximately 40,000 barrels per day on Colonial Pipeline, for $2.82 billion. We refer to these assets as “Hess’ Retail Operations and Related Assets.” The transaction was funded with a combination of debt and available cash.

The transaction provides for an adjustment for working capital, which has not been finalized with Hess. If a change is made for working capital, the fair value of the assets acquired and liabilities assumed will be revised.

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

(In millions)
Cash	$	2,824
Net working capital adjustment estimate	(3		)
Total fair value of consideration transferred	$	2,821

During the fourth quarter of 2014, an independent appraisal of the assets acquired and liabilities assumed and other evaluations were completed and finalized. Updates to the preliminary fair value measurements of assets acquired and liabilities assumed were made during the fourth quarter of 2014. The following table summarizes the amounts assigned to the assets acquired and liabilities assumed as of the acquisition date.

(In millions)
Cash and cash equivalents	$	49
Receivables	123
Inventories	165
Other current assets	8
Property, plant and equipment, net	2,063
Other noncurrent assets	111
Total assets acquired	2,519
Accounts payable	77
Payroll and benefits payable	15
Consumer excise taxes payable	64
Accrued taxes	4
Other current liabilities	10
Defined benefit postretirement plan obligations	2
Deferred credits and other liabilities	155
Total liabilities assumed	327
Net assets acquired excluding goodwill	2,192
Goodwill	629
Net assets acquired	$	2,821

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The purchase price allocation resulted in the recognition of $629 million in goodwill by our Speedway segment, which is deductible for tax purposes. Goodwill recognized for the acquisition primarily relates to the expected benefits of a significantly expanded retail platform that should enable growth in new markets, as well as the potential for higher merchandise sales at the acquired locations. We also expect strategic benefits from the financial and operational scale we expect to realize across our entire retail network. This acquisition significantly expands our Speedway presence from nine to 22 states throughout the East Coast and Southeast and is aligned with our strategy to grow higher-valued, stable cash flow businesses. This acquisition also enables us to further leverage our integrated refining and transportation operations, providing an outlet for an incremental 200,000 barrels per day of assured sales from our refining system.

Other noncurrent assets includes a $22 million intangible asset related to a trade name and $72 million related to favorable lease contract terms. Deferred credits and other liabilities includes $90 million related to unfavorable lease contract terms. The trade name is being amortized over its estimated useful life of two years based on the utilization of the assets. The favorable and unfavorable lease contract amounts are being amortized over the terms of the leases.

We recognized $14 million of acquisition-related costs associated with Hess’ Retail Operations and Related Assets acquisition. These costs were expensed and were included in selling, general and administrative expenses.

The amounts of revenue and income from operations associated with Hess’ Retail Operations and Related Assets included in our consolidated statements of income for 2014 are as follows:

(In millions)	2014
Sales and other operating revenues (including consumer excise taxes)	$	2,403
Income from operations	113

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. The transaction was funded with cash on hand. 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. During 2014, we paid BP $180 million for the first period’s contingent earnout. On the consolidated statements of cash flows, $172 million of the contingent earnout payment is included as a financing activity with the remainder included as an operating activity. See Note 18 for additional information on the contingent consideration.

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 fair value of consideration transferred	$	2,088

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During the fourth quarter of 2013, an independent appraisal of the assets acquired and liabilities assumed and other evaluations were completed and finalized. 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
Total assets acquired	2,298
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 liabilities assumed	210
Net assets acquired	$	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.

Unaudited Pro Forma Financial Information

The following unaudited pro forma financial information presents consolidated results assuming Hess’ Retail Operations and Related Assets acquisition occurred on January 1, 2013 and 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 acquisitions and is not necessarily indicative of the results of future operations.

(In millions, except per share data)	2014		2013
Sales and other operating revenues (including consumer excise taxes)	$	106,482	$	114,148
Net income attributable to MPC	2,547		2,142
Net income attributable to MPC per share – basic	$	8.94	$	6.80
Net income attributable to MPC per share – diluted	8.87		6.76

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, additional interest expense related to financing the acquisition of Hess’ Retail Operations and Related Assets, as well as the related income tax effects.

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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.

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.

Acquisition of Biodiesel Facility

On April 1, 2014, we purchased a facility in Cincinnati, Ohio from Felda Iffco Sdn Bhd, Malaysia for $40 million. The plant currently produces biodiesel, glycerin and other by-products. The production capacity of the plant is approximately 60 million gallons per year.

Neither goodwill nor a gain from a bargain purchase was recognized in conjunction with the biodiesel facility acquisition.

Assuming the acquisitions of the convenience stores in 2013 and 2012 and the biodiesel facility in 2014 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 Companies

In July 2014, we exercised our option to acquire a 35 percent ownership interest in Enbridge Inc.’s Southern Access Extension pipeline (“SAX”) through our investment in Illinois Extension Pipeline Company, LLC (“Illinois Extension Pipeline”). During 2014, we made contributions of $120 million to Illinois Extension Pipeline to fund our portion of the construction costs incurred-to-date on the SAX project. We account for our ownership interest in Illinois Extension Pipeline as an equity method investment. See Note 26 for information on future contributions to Illinois Extension Pipeline.

In March 2014, we acquired from Chevron Raven Ridge Pipe Line Company an additional seven percent interest in Explorer Pipeline Company (“Explorer”) for $77 million, bringing our ownership interest to 25 percent. As a result of this increase in our ownership, we now account for our investment in Explorer using the equity method of accounting rather than the cost method. The cumulative impact of the change was applied as an adjustment to 2014 retained earnings.

In November 2013, we agreed to serve as an anchor shipper for the Sandpiper pipeline project and fund 37.5 percent of the construction costs of the project, which will become part of Enbridge Energy Partners L.P.’s (“Enbridge Energy Partners”) North Dakota System. In exchange for these commitments, we will earn an approximate 27 percent equity interest in Enbridge Energy Partners’ North Dakota System when the Sandpiper pipeline is placed into service, which is expected to be in 2017. We also have the option to increase our ownership interest to approximately 30 percent through additional investments in future system improvements. We made contributions of $192 million to North Dakota Pipeline Company LLC (“North Dakota Pipeline”) during 2014. We have contributed $216 million since project inception. We account for our interest in North Dakota Pipeline using the equity method of accounting. See Note 26 for information on future contributions to North Dakota Pipeline.

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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.”

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.

7. Variable Interest Entity

As stated in Note 5, we have a 35 percent ownership interest in Illinois Extension Pipeline through our contributions to the SAX project. Illinois Extension Pipeline Company LLC is considered a variable interest entity (“VIE”) because it is a development stage entity and the equity in the entity is not sufficient to fund the current stage of development, which is the construction of the SAX pipeline. Our maximum exposure to loss due to this VIE at December 31, 2014 was $120 million, which equates to our contributions to-date to fund our portion of the construction costs for the project.

We are not the primary beneficiary of this VIE and, therefore, do not consolidate it because we do not have the power to control the activities that significantly influence the economic activities of the entity. The activities that most significantly impact the VIE’s economic performance during the construction phase are the actual construction costs and risks associated with the construction process. Through our vote, we have shared power to direct the construction activities, but do not have the sole ability to control the construction activities.

8. Related Party Transactions

Our related parties included:

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

• Explorer, in which we have a 25 percent interest. Explorer owns and operates a refined products pipeline.

• LOCAP LLC (“LOCAP”), in which we have a 59 percent noncontrolling interest. LOCAP owns and operates a crude oil pipeline.

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

• 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.

• Other equity method investees.

We believe that transactions with related parties were conducted on terms comparable to those with unaffiliated parties.

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Sales to related parties, which are included in sales and other operating revenues (including consumer excise taxes) on the consolidated statements of income, were as follows:

(In millions)	2014		2013		2012
Centennial	$	—	$	—	$	1
Other equity method investees	7		8		7
Total	$	7	$	8	$	8

Related party sales to Centennial consist primarily of petroleum products.

The fees received for operating Centennial’s pipeline, which are included in other income on the consolidated statements of income, were $1 million in 2014, 2013 and 2012.

Purchases from related parties were as follows:

(In millions)	2014		2013		2012
Centennial	$	7	$	3	$	7
Explorer	39		—		—
LOCAP	21		17		24
LOOP	88		43		44
TAAE	79		24		—
TACE	121		130		73
TAME	141		131		124
Other equity method investees	9		9		8
Total	$	505	$	357	$	280

Related party purchases from Centennial consist primarily of refinery feedstocks and refined product transportation costs. Related party purchases from Explorer consist primarily of refined product transportation costs. Related party purchases from LOCAP, LOOP and other equity method investees consist primarily of crude oil transportation costs. Related party purchases from TAAE, TACE and TAME consist of ethanol purchases.

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)	2014		2013
Centennial	$	2	$	1
Explorer	2		—
TAME	3		1
Total	$	7	$	2

Long-term receivable from Centennial, which is included in other noncurrent assets on the consolidated balance sheet, was less than $1 million at December 31, 2014 and $2 million at December 31, 2013.

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

	December 31,
(In millions)	2014		2013
Explorer	$	3	$	—
LOCAP	2		2
LOOP	4		3
TAAE	2		2
TACE	2		4
TAME	5		5
Total	$	18	$	16

9. 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.

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)	2014		2013		2012
Basic earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	2,524	$	2,112	$	3,389
Income allocated to participating securities	4		4		6
Income available to common stockholders – basic	$	2,520	$	2,108	$	3,383
Weighted average common shares outstanding	285		315		340
Basic earnings per share	$	8.84	$	6.69	$	9.95
Diluted earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	2,524	$	2,112	$	3,389
Income allocated to participating securities	4		4		6
Income available to common stockholders – diluted	$	2,520	$	2,108	$	3,383
Weighted average common shares outstanding	285		315		340
Effect of dilutive securities	2		2		2
Weighted average common shares, including dilutive effect	287		317		342
Diluted earnings per share	$	8.78	$	6.64	$	9.89

The following table summarizes the shares that were anti-dilutive, and therefore, were excluded from the diluted share calculation.

(In millions)	2014	2013	2012
Shares issued under stock-based compensation plans	—	—	2

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10. Equity

On July 30, 2014, our board of directors approved an additional $2.0 billion share repurchase authorization expiring in July 2016. As of December 31, 2014, our board of directors had approved $8.0 billion in total share repurchase authorizations since January 1, 2012 and we have repurchased a total of $6.27 billion of our common stock under these authorizations, leaving $1.73 billion available for repurchases. Under these authorizations, we have acquired 89 million shares at an average cost per share of $70.35.

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 accelerated share repurchase (“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 were as follows for the respective periods:

(In millions, except per share data)	2014		2013		2012
Number of shares repurchased(a)	24		37		28
Cash paid for shares repurchased	$	2,131	$	2,793	$	1,350
Effective average cost per delivered share	$	88.63	$	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.

At December 31, 2014, we had agreements to acquire 99,084 common shares for $9 million, which were settled in early January 2015.

11. 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 it offers.

• 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, East Coast and Southeast.

• 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.

On September 30, 2014, we acquired Hess’ Retail Operations and Related Assets, which are part of the Speedway and Refining & Marketing segments. 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 each 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 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.

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(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
Year Ended December 31, 2014
Revenues:
Customer	$	80,822	$	16,927	$	70	$	97,819
Intersegment(a)	10,912		5		527		11,444
Segment revenues	$	91,734	$	16,932	$	597	$	109,263
Segment income from operations(b)	$	3,609	$	544	$	280	$	4,433
Income from equity method investments	96		—		57		153
Depreciation and amortization(c)	1,045		152		77		1,274
Capital expenditures and investments(d)(e)	1,104		2,981		543		4,628

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
Year Ended December 31, 2013
Revenues:
Customer	$	85,616	$	14,471	$	79	$	100,166
Intersegment(a)	9,294		4		458		9,756
Segment revenues	$	94,910	$	14,475	$	537	$	109,922
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)(f)	2,094		296		234		2,624

(In millions)	Refining & Marketing			Speedway		Pipeline Transportation		Total
Year Ended December 31, 2012
Revenues:
Customer	$	67,928		$	14,239	$	78	$	82,245
Intersegment(a)	8,782			4		381		9,167
Segment revenues	$	76,710		$	14,243	$	459	$	91,412
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)	705			340		211		1,256

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

^(b)  Included in the Pipeline Transportation segment for 2014, 2013 and 2012 are $19 million, $20 million and $4 million of corporate overhead expenses attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. Corporate overhead 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, acquisitions and investments in affiliates.

^(e)  The Speedway and Refining & Marketing segments include $2.66 billion and $52 million, respectively, for the acquisition of Hess’ Retail Operations and Related Assets. 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)	2014			2013			2012
Segment income from operations	$	4,433		$	3,791		$	5,624
Items not allocated to segments:
Corporate and other unallocated items(a)(b)	(286		)	(271		)	(336		)
Minnesota Assets sale settlement gain(c)	—			—			183
Pension settlement expenses(d)	(96		)	(95		)	(124		)
Net interest and other financial income (costs)	(216		)	(179		)	(109		)
Income before income taxes	$	3,835		$	3,246		$	5,238

^(a)  Corporate and other unallocated items consists primarily of MPC’s corporate administrative expenses and costs related to certain non-operating assets.

^(b)  Corporate overhead expenses attributable to MPLX were included in the Pipeline Transportation segment subsequent to MPLX’s October 31, 2012 initial public offering. Corporate overhead expenses are not allocated to the Refining & Marketing and Speedway segments.

^(c)  See Note 6.

^(d)  See Note 23.

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

(In millions)	2014		2013		2012
Segment capital expenditures and investments	$	4,628	$	2,624	$	1,256
Less: Investments in equity method investees	413		124		28
Plus: Items not allocated to segments:
Capital expenditures not allocated to segments	83		137		103
Capitalized interest	27		28		101
Total capital expenditures(a)(b)	$	4,325	$	2,665	$	1,432

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

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

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

(In millions)	2014			2013			2012
Customer revenues	$	97,819		$	100,166		$	82,245
Corporate and other unallocated items	(2		)	(6		)	(2		)
Sales and other operating revenues (including consumer excise taxes)	$	97,817		$	100,160		$	82,243

Revenues by product line were:

(In millions)	2014		2013		2012
Refined products	$	90,702	$	93,520	$	76,234
Merchandise	3,817		3,308		3,229
Crude oil and refinery feedstocks	2,917		2,988		2,514
Transportation and other	381		344		266
Sales and other operating revenues (including consumer excise taxes)	$	97,817	$	100,160	$	82,243

No single customer accounted for more than 10 percent of annual revenues for the years ended December 31, 2014 and 2012. 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.

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.

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Total assets by reportable segment were:

	December 31,
(In millions)	2014		2013
Refining & Marketing	$	19,751	$	19,573
Speedway	5,296		2,064
Pipeline Transportation	2,407		1,947
Corporate and Other	3,006		4,801
Total consolidated assets	$	30,460	$	28,385

12. Other Items

Net interest and other financial income (costs) was:

(In millions)	2014			2013			2012
Interest income	$	7		$	9		$	6
Interest expense	(229		)	(195		)	(191		)
Interest capitalized	27			28			101
Other financial costs	(21		)	(21		)	(25		)
Net interest and other financial income (costs)	$	(216	)	$	(179	)	$	(109	)

13. Income Taxes

Income tax provisions (benefits) were:

	2014								2013							2012
(In millions)	Current		Deferred			Total			Current		Deferred			Total		Current			Deferred		Total
Federal	$	1,382	$	(199	)	$	1,183		$	954	$	20		$	974	$	1,185		$	432	$	1,617
State and local	135		(37		)	98			131		8			139		169			57		226
Foreign	5		(6		)	(1		)	5		(5		)	—		(1		)	3		2
Total	$	1,522	$	(242	)	$	1,280		$	1,090	$	23		$	1,113	$	1,353		$	492	$	1,845

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

	2014		2013		2012
Statutory rate applied to income before income taxes	35	%	35	%	35	%
State and local income taxes, net of federal income tax effects	2		3		2
Domestic manufacturing deduction	(2	)	(2	)	(1	)
Other	(2	)	(2	)	(1	)
Provision for income taxes	33	%	34	%	35	%

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Deferred tax assets and liabilities resulted from the following:

	December 31,
(In millions)	2014		2013
Deferred tax assets:
Employee benefits	$	616	$	483
Environmental	54		37
Investments in subsidiaries and affiliates	24		—
Other	70		49
Total deferred tax assets	764		569
Deferred tax liabilities:
Property, plant and equipment	2,411		2,290
Inventories	614		614
Investments in subsidiaries and affiliates	—		267
Other	101		70
Total deferred tax liabilities	3,126		3,241
Net deferred tax liabilities	$	2,362	$	2,672

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

	December 31,
(In millions)	2014		2013
Assets:
Other noncurrent assets	$	7	$	2
Liabilities:
Accrued taxes	355		370
Deferred income taxes	2,014		2,304
Net deferred tax liabilities	$	2,362	$	2,672

Tax carryforwards – At December 31, 2014, our federal operating loss carryforwards included $11 million acquired with the biodiesel facility acquisition, which expire in 2022 through 2034. State and local operating loss carryforwards of $1 million expire in 2015 through 2029.

Valuation allowances – As of December 31, 2014 and 2013, $4 million and $3 million of valuation allowances were recognized related to income taxes. A federal valuation allowance was established for both December 31, 2014 and 2013 of $3 million, primarily due to the expected realizability of foreign tax credits. A state and local valuation allowance was established as of December 31, 2014 of $1 million, based on estimates of future financial income and expected realizability of state and local tax operating losses.

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, 2014, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:

United States Federal	2010	-	2013
States	2004	-	2013

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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. 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)	2014			2013			2012
January 1 balance	$	13		$	40		$	20
Additions for tax positions of prior years	7			30			32
Reductions for tax positions of prior years	(10		)	(25		)	(6		)
Settlements	2			(30		)	(6		)
Statute of limitations	—			(2		)	—
December 31 balance	$	12		$	13		$	40

If the unrecognized tax benefits as of December 31, 2014 were recognized, $5 million would affect our effective income tax rate. There were $4 million of uncertain tax positions as of December 31, 2014 for which it is reasonably possible that the amount of unrecognized tax benefits would significantly 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 less than $1 million, ($11 million) and $1 million in 2014, 2013 and 2012, respectively. As of December 31, 2014 and 2013, $14 million and $15 million of interest and penalties were accrued related to income taxes.

14. Inventories

	December 31,
(In millions)	2014		2013
Crude oil and refinery feedstocks	$	2,219	$	1,797
Refined products	2,955		2,367
Materials and supplies	302		425
Merchandise	166		100
Total (at cost)	$	5,642	$	4,689

The LIFO method accounted for 94 percent and 90 percent of total inventory value at December 31, 2014 and 2013, respectively. Current acquisition costs of inventories were estimated to exceed the LIFO inventory value at December 31, 2014 and 2013 by $684 million and $4,084 million, respectively. There were no liquidations of LIFO inventories in 2014, 2013 and 2012.

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15. Equity Method Investments

	Ownership as of	Carrying value at
	December 31,	December 31,
(In millions)	2014	2014		2013
Centennial	50%	$	36	$	29
Explorer	25%	95		—
Illinois Extension Pipeline	35%	120		—
LOCAP	59%	23		24
LOOP	51%	230		214
North Dakota Pipeline(a)	38%	216		24
TAAE	43%	22		29
TACE	60%	61		70
TAEI	34%	19		23
TAME(b)	50%	24		35
Other		19		15
Total		$	865	$	463

^(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, which is expected to be in 2017.

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

Summarized financial information for equity method investees is as follows:

(In millions)	2014		2013		2012
Income statement data:
Revenues and other income	$	1,430	$	1,067	$	1,025
Income from operations	379		87		73
Net income	316		63		47
Balance sheet data – December 31:
Current assets	$	990	$	339
Noncurrent assets	2,166		1,238
Current liabilities	280		145
Noncurrent liabilities	957		618

As of December 31, 2014, the carrying value of our equity method investments was $110 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 2014. At December 31, 2014, 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 market participant assumptions for various potential uses of Centennial’s assets. If market conditions were to change 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, 2014, our equity investment in Centennial was $36 million and we had a $38 million guarantee associated with 50 percent of Centennial’s outstanding debt. See Note 26 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 $170 million, $18 million and $37 million in 2014, 2013 and 2012.

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16. Property, Plant and Equipment

(In millions)	Estimated Useful Lives	December 31,
		2014		2013
Refining & Marketing	4 - 25 years	$	18,001	$	16,982
Speedway	4 - 25 years	4,639		2,344
Pipeline Transportation	16 - 42 years	2,044		1,921
Corporate and Other	4 - 40 years	618		546
Total		25,302		21,793
Less accumulated depreciation		9,041		7,872
Property, plant and equipment, net		$	16,261	$	13,921

Property, plant and equipment includes gross assets acquired under capital leases of $510 million at both December 31, 2014 and 2013, with related amounts in accumulated depreciation of $144 million and $111 million at December 31, 2014 and 2013. Property, plant and equipment includes construction in progress of $1,043 million and $747 million at December 31, 2014 and 2013, which primarily relates to refinery projects.

Construction in progress at December 31, 2014 includes $90 million of costs associated with a residual fuel hydrocracker project at our Garyville refinery, intended to increase margins by upgrading residual fuel to ultra-low sulfur diesel and gas oil. We are deferring a final investment decision on this project with estimated total costs of $2.2 billion to $2.5 billion as we further evaluate the implications of current market conditions on the project. If a decision is made to not pursue this project, there could be a future impairment of the costs incurred for the project.

17. Goodwill

Goodwill is tested for impairment on an annual basis and when events or changes in circumstances indicate the fair value of a reporting unit with goodwill has been reduced below the carrying value. We performed our annual impairment tests for 2014 and 2013, and no impairment was required.

The changes in the carrying amount of goodwill for 2014 and 2013 were as follows:

(In millions)	Refining & Marketing			Speedway		Pipeline Transportation		Total
2013
Beginning balance	$	551		$	217	$	162	$	930
Acquisitions(a)	—			8		—		8
Ending balance	$	551		$	225	$	162	$	938
2014
Beginning balance	$	551		$	225	$	162	$	938
Acquisitions(a)	—			629		—		629
Disposition	(1		)	—		—		(1		)
Ending balance	$	550		$	854	$	162	$	1,566

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

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18. Fair Value Measurements

Fair Values – Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2014 and 2013 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, 2014
	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	$	317	$	—	$	—	$	(258	)	$	59	$	—
Other assets	2		—		—		N/A			2		—
Total assets at fair value	$	319	$	—	$	—	$	(258	)	$	61	$	—
Commodity derivative instruments, liabilities	$	180	$	—	$	—	$	(180	)	$	—	$	—
Contingent consideration, liability(c)	—		—		478		N/A			478		—
Total liabilities at fair value	$	180	$	—	$	478	$	(180	)	$	478	$	—

	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	$	—

^(a)  Represents the impact of netting assets, liabilities and cash collateral when a legal right of offset exists. As of December 31, 2014, cash collateral of $78 million was netted with mark-to-market derivative assets. As of December 31, 2013, cash collateral of $32 million 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 $174 million at December 31, 2014 and $159 million at December 31, 2013 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, 2014 and 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 $15 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

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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 liabilities classified as Level 3 in the fair value hierarchy.

(In millions)	2014			2013		2012
Beginning balance	$	625		$	—	$	—
Contingent consideration agreement	—			600		—
Contingent consideration payment	(180		)	—		—
Unrealized and realized losses included in net income	33			25		2
Settlements of derivative instruments	—			—		(2		)
Ending balance	$	478		$	625	$	—

We did not hold any Level 3 derivative instruments during 2014, 2013 and 2012. See Note 19 for the income statement impacts of our derivative instruments. There was an unrealized loss of $33 million and $25 million in 2014 and 2013, respectively, 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,
	2014				2013				2012
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Property, plant and equipment, net	$	—	$	—	$	1	$	8	$	—	$	—
Other noncurrent assets	—		11		—		—		—		14

Based on the financial and operational status of a company in which we have an interest, we fully impaired our $11 million investment in that company in 2014. Our investment in this company was accounted for using the cost method and was included in our Refining & Marketing segment. The impairment is included in other income on the consolidated statements of income. The fair value of our investment in this cost company was measured using an income approach. This measurement is classified as Level 3.

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 expired March 31, 2014. 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, 2014 and 2013, excluding the derivative financial instruments and contingent consideration reported above.

	December 31,
	2014				2013
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial assets:
Investments	$	26	$	2	$	336	$	14
Other	32		32		31		30
Total financial assets	$	58	$	34	$	367	$	44
Financial liabilities:
Long-term debt(a)	$	6,571	$	6,265	$	3,306	$	3,001
Deferred credits and other liabilities	17		17		21		21
Total financial liabilities	$	6,588	$	6,282	$	3,327	$	3,022

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

19. Derivatives

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

The following table presents the gross fair values of derivative instruments, excluding cash collateral, and where they appear on the consolidated balance sheets as of December 31, 2014 and 2013:

	December 31, 2014
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	317	$	180	Other current assets

	December 31, 2013
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	21	$	53	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 in 2012:

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

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, 2014.

	Position	Total Barrels (In thousands)
Crude oil(a)
Exchange-traded	Long	15,678
Exchange-traded	Short	(25,257)
Refined Products(b)
Exchange-traded	Long	2,948
Exchange-traded	Short	(3,804)

^{(a )}  97 percent of these contracts expire in the first quarter of 2015.

^(b)   100 percent of these contracts expire in the first quarter of 2015.

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

(In millions)	Gain (Loss)
Income Statement Location	2014		2013			2012
Sales and other operating revenues	$	37	$	12		$	8
Cost of revenues	456		(180		)	65
Total	$	493	$	(168	)	$	73

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20. Debt

Our outstanding borrowings at December 31, 2014 and 2013 consisted of the following:

	December 31,
(In millions)	2014			2013
Marathon Petroleum Corporation:
Revolving credit agreement due 2017	$	—		$	—
Term loan agreement due 2019	700			—
3.500% senior notes due March 1, 2016	750			750
5.125% senior notes due March 1, 2021	1,000			1,000
3.625% senior notes due September 15, 2024	750			—
6.500% senior notes due March 1, 2041	1,250			1,250
4.750% senior notes due September 15, 2044	800			—
5.000% senior notes due September 15, 2054	400			—
Consolidated subsidiaries:
Capital lease obligations due 2015-2028	372			395
MPLX Operations LLC bank revolving credit agreement due 2017	—			—
MPLX bank revolving credit facility due 2019	385			—
MPLX term loan facility due 2019	250			—
Trade receivables securitization facility due 2016	—			—
Total	6,657			3,395
Unamortized discount	(26		)	(10		)
Fair value adjustments(a)	6			11
Amounts due within one year	(27		)	(23		)
Total long-term debt due after one year	$	6,610		$	3,373

^(a)  See Note 19 for information on interest rate swaps.

The following table shows five years of scheduled debt payments.

(In millions)
2015	$	27
2016	777
2017	28
2018	30
2019	1,362

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.

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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. 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, 2014, we were in compliance with the covenants contained in the Credit Agreement.

There were no borrowings or letters of credit outstanding at December 31, 2014.

MPC Term Loan Agreement – On August 26, 2014, we entered into a $700 millionfive-year senior unsecured term loan credit agreement (the “Term Loan Agreement”) with a syndicate of lenders to fund a portion of the purchase price for the acquisition of Hess’ Retail Operations and Related Assets. The Term Loan Agreement matures on September 24, 2019 and may be prepaid at any time without premium or penalty. We are obligated to pay certain customary fees under the Term Loan Agreement, including an annual administrative fee.

Amounts outstanding under the Term Loan Agreement bear interest at either of the following rates at our election (i) the sum of the Adjusted LIBO Rate (as defined in the Term Loan Agreement), plus a margin ranging between 0.875 percent to 1.75 percent, depending on our credit ratings, or (ii) the sum of the Base Rate (as defined in the Term Loan Agreement), plus a margin ranging between zero percent to 0.75 percent, depending on our credit ratings. The borrowings under this facility during 2014 were at an average interest rate of 1.3 percent.

The Term Loan Agreement contains representation and warranties, covenants and events of default that are substantially similar to those contained in the MPC revolving credit agreement, including a financial covenant, which requires us to maintain, as of the last day of each fiscal quarter, a ratio of Consolidated Net Debt to Total Capitalization (as defined in the Term Loan Agreement) of no greater than 0.65 to 1.00. As of December 31, 2014, we were in compliance with the covenants contained in the Credit Agreement.

Senior Notes – On September 5, 2014, we completed a public offering of $1.95 billion aggregate principal amount of senior unsecured notes (the “Senior Notes”), consisting of $750 million aggregate principal amount of our Senior Notes due 2024, $800 million aggregate principal amount of our Senior Notes due 2044 and $400 million aggregate principal amount of our Senior Notes due 2054. The net proceeds from the offering of the Senior Notes were approximately $1.92 billion, after deducting underwriting discounts and estimated offering expenses. The net proceeds were used to fund a portion of the purchase price for the acquisition of Hess’ Retail Operations and Related Assets. Interest on each series of Senior Notes is payable semi-annually in arrears on March 15 and September 15 of each year, commencing on March 15, 2015.

The Senior Notes are unsecured and unsubordinated obligations of ours and rank equally with all our other existing and future unsecured and unsubordinated indebtedness.

MPLX Credit Agreement – On November 20, 2014, MPLX entered into a credit agreement with a syndicate of lenders (“MPLX Credit Agreement”), which provides for a five-year $1 billion bank revolving credit facility and a $250 million term loan facility. The maturity date on both facilities is November 20, 2019.

The bank revolving credit facility includes letter of credit issuing capacity of up to $250 million and swingline loan capacity of up to $100 million. The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional $500 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 the majority of the commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the original maturity date.

The term loan facility was drawn in full on November 20, 2014. The maturity date for the term loan facility may be extended for up to two additional one-year periods subject to the consent of the lenders holding a majority of the outstanding term loan borrowings, provided that the portion of the term loan borrowings held by any non-consenting lenders will continue to be due and payable on the original maturity date. The borrowings under this facility during 2014 were at an average interest rate of 1.4 percent.

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Borrowings under the MPLX Credit Agreement bear interest at either the Adjusted LIBO Rate or the Alternate Base Rate (as defined in the MPLX Credit Agreement) plus a specified 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 bank revolving credit facility and fees with respect 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 MPLX’s long-term debt.

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. The MPLX Credit Agreement includes 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 (both as defined in the MPLX Credit Agreement) for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 for up to two fiscal quarters following certain acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period. Other covenants restrict MPLX from incurring debt, creating liens on its assets and entering into transactions with affiliates. As of December 31, 2014, MPLX was in compliance with the covenants contained in the MPLX Credit Agreement.

In connection with entering into this new credit agreement, MPLX terminated its previously existing $500 millionfive-year MPLX Operations LLC bank revolving credit agreement, dated as of September 14, 2012. During 2014, MPLX borrowed $280 million under the MPLX Operations LLC bank revolving credit agreement, at an average interest rate of 1.5 percent, per annum, and repaid all of these borrowings.

During 2014, MPLX borrowed $630 million under the new revolving credit agreement, at an average interest rate of 1.4 percent, per annum, and repaid $245 million of these borrowings. At December 31, 2014, MPLX had $385 million of borrowings and no letters of credit outstanding under the MPLX Credit Agreement, resulting in total unused loan availability of $615 million, or 61.5 percent of the borrowing capacity.

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. 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. At December 31, 2014, we were in compliance with the covenants contained in the Receivables Purchase Agreement.

As of December 31, 2014, eligible trade receivables supported borrowings of $1.28 billion. There were no borrowings outstanding at December 31, 2014. As of January 31, 2015, eligible trade receivables supported borrowings of $700 million.

21. Supplemental Cash Flow Information

(In millions)	2014		2013		2012
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	166	$	161	$	67
Net income taxes paid to taxing authorities(a)	1,362		1,099		1,211
Non-cash investing and financing activities:
Capital lease obligations increase	$	—	$	61	$	62
Property, plant and equipment sold	4		43		—
Property, plant and equipment acquired	4		—		—
Preferred equity interest received in contract settlement(b)	—		—		45
Preferred equity interest dividend received in-kind	—		—		1
Acquisition:
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 26.

^(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)	2014		2013		2012
Additions to property, plant and equipment per consolidated statements of cash flows	$	1,480	$	1,206	$	1,369
Non-cash additions to property, plant and equipment	4		—		—
Asset retirement expenditures(a)	2		—		—
Increase (decrease) in capital accruals	95		73		(117		)
Total capital expenditures before acquisitions	1,581		1,279		1,252
Acquisitions(b)	2,744		1,386		180
Total capital expenditures	$	4,325	$	2,665	$	1,432

^(a)  Included in All other, net – Operating activities on the consolidated statements of cash flows.

^(a)  The 2014 acquisitions include the acquisition of Hess’ Retail Operations and Related Assets. The 2013 acquisitions include the acquisition of the Galveston Bay Refinery and Related Assets. The acquisition numbers above include property, plant and equipment and intangibles. See Note 5.

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22. 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 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 effect	(43		)	—			—		—			(43		)
Other comprehensive income (loss)	271			(14		)	—		3			260
Balance as of December 31, 2013	$	(161	)	$	(50	)	$	4	$	3		$	(204	)

(In millions)	Pension Benefits			Other Benefits			Gain on Cash Flow Hedge		Workers Compensation			Total
Balance as of December 31, 2013	$	(161	)	$	(50	)	$	4	$	3		$	(204	)
Other comprehensive income (loss) before reclassifications	(119		)	(53		)	—		2			(170		)
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit(a)	(46		)	(4		)	—		—			(50		)
– actuarial loss(a)	51			2			—		—			53
– settlement loss(a)	96			—			—		—			96
Other(b)	—			—			—		(1		)	(1		)
Tax effect	(38		)	1			—		—			(37		)
Other comprehensive income (loss)	(56		)	(54		)	—		1			(109		)
Balance as of December 31, 2014	$	(217	)	$	(104	)	$	4	$	4		$	(313	)

^(a)  These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 23.

^(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.

23. 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.

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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.

Obligations and funded status – The accumulated benefit obligation for all defined benefit pension plans was $2,009 million and $1,912 million as of December 31, 2014 and 2013.

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

	December 31,
(In millions)	2014		2013
Projected benefit obligations	$	2,075	$	1,927
Accumulated benefit obligations	2,009		1,912
Fair value of plan assets	1,744		1,800

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)	2014			2013			2014			2013
Change in benefit obligations:
Benefit obligations at January 1	$	1,927		$	2,192		$	687		$	591
Service cost	88			93			27			25
Interest cost	74			73			33			26
Actuarial (gain) loss	257			(183		)	86			17
Benefits paid	(271		)	(248		)	(23		)	(20		)
Other(a)	—			—			2			48
Benefit obligations at December 31	2,075			1,927			812			687
Change in plan assets:
Fair value of plan assets at January 1	1,800			1,478			—			—
Actual return on plan assets	175			241			—			—
Employer contributions	40			329			—			—
Benefits paid from plan assets	(271		)	(248		)	—			—
Fair value of plan assets at December 31	1,744			1,800			—			—
Funded status of plans at December 31	$	(331	)	$	(127	)	$	(812	)	$	(687	)
Amounts recognized in the consolidated balance sheets:
Current liabilities	$	(17	)	$	(18	)	$	(27	)	$	(25	)
Noncurrent liabilities	(314		)	(109		)	(785		)	(662		)
Accrued benefit cost	$	(331	)	$	(127	)	$	(812	)	$	(687	)
Pretax amounts recognized in accumulated other comprehensive loss:(b)
Net loss	$	710		$	668		$	191		$	107
Prior service credit	(369		)	(415		)	(26		)	(30		)

^(a)  Includes adjustments related to Hess’ Retail Operations and Related Assets acquisition in 2014. For 2013, it includes adjustments related to plan amendments and adjustments related to the Galveston Bay Refinery and Related Assets acquisition.

^(b)  Amounts exclude those related to LOOP and Explorer Pipeline, equity method investees with defined benefit pension and postretirement plans for which net losses of $18 million and $1 million were recorded in accumulated other comprehensive loss in 2014, reflecting our ownership 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)	2014			2013			2012			2014			2013			2012
Components of net periodic benefit cost:
Service cost	$	88		$	93		$	66		$	27		$	25		$	20
Interest cost	74			73			94			33			26			24
Expected return on plan assets	(107		)	(107		)	(104		)	—			—			—
Amortization – prior service cost (credit)	(46		)	(45		)	(18		)	(4		)	(4		)	(2		)
– actuarial loss	51			66			93			2			3			2
– settlement loss	96			95			125			—			—			—
Net periodic benefit cost(a)	$	156		$	175		$	256		$	58		$	50		$	44
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial (gain) loss	$	188		$	(317	)	$	46		$	86		$	17		$	53
Prior service cost (credit)(b)	—			—			(520		)	—			4			(40		)
Amortization of actuarial loss	(147		)	(161		)	(218		)	(2		)	(3		)	(2		)
Amortization of prior service cost	46			45			18			4			4			2
Other	—			—			—			—			—			—
Total recognized in other comprehensive loss	$	87		$	(433	)	$	(674	)	$	88		$	22		$	13
Total recognized in net periodic benefit cost and other comprehensive loss	$	243		$	(258	)	$	(418	)	$	146		$	72		$	57

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

^(b)  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.

Lump sum payments to employees retiring in 2014, 2013 and 2012 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 2014, 2013 and 2012 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 2015 are $51 million and $46 million. 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 2015 is $9 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 2014, 2013 and 2012.

	Pension Benefits						Other Benefits
	2014		2013		2012		2014		2013		2012
Weighted-average assumptions used to determine benefit obligation:
Discount rate	3.65	%	4.30	%	3.45	%	4.15	%	4.95	%	4.05	%
Rate of compensation increase	3.70	%	3.70	%	5.00	%	3.70	%	3.70	%	5.00	%
Weighted-average assumptions used to determine net periodic benefit cost:
Discount rate	4.05	%	3.88	%	4.06	%	4.95	%	4.11	%	4.54	%
Expected long-term return on plan assets(a)	7.00	%	7.50	%	7.50	%	—	%	—	%	—	%
Rate of compensation increase	3.70	%	5.00	%	5.00	%	3.70	%	5.00	%	5.00	%

^(a)  Effective January 1, 2015, the expected long-term rate of return on plan assets is 6.75 percent due to a continuation of a change in our primary plan investment strategy, which began January 1, 2014.

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,
	2014		2013		2012
Health care cost trend rate assumed for the following year:
Medical Pre-65	8.00	%	8.00	%	8.00	%
Prescription drugs	7.00	%	7.00	%	7.00	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):
Medical Pre-65	5.00	%	5.00	%	5.00	%
Prescription drugs	5.00	%	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate:
Medical Pre-65	2021		2020		2020
Prescription drugs	2021		2018		2018

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 four 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	45		(39		)

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, 2014, the primary plan’s targeted asset allocation was 51 percent equity, private equity, real estate, and timber securities and 49 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, 2014 and 2013.

Cash and cash equivalents – Cash and cash equivalents include a collective fund serving as the investment vehicle for the cash reserves and cash held by third-party investment managers. The collective fund is valued at net asset value (“NAV”) on a scheduled basis using a cost approach, and is considered a Level 2 asset. Cash and cash equivalents held by third-party investment managers are valued using a cost approach and are considered Level 2.

Equity – Equity investments includes common stock, mutual and pooled 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.

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.

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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, 2014 and 2013.

	December 31, 2014
(In millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	—	$	29	$	—	$	29
Equity:
Common stocks	63		—		—		63
Mutual funds	155		—		—		155
Pooled funds	—		442		—		442
Fixed income:
Corporate	—		554		—		554
Government	—		99		—		99
Pooled funds	—		254		—		254
Private equity	—		—		66		66
Real estate	—		—		57		57
Other	2		2		21		25
Total investments, at fair value	$	220	$	1,380	$	144	$	1,744

	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

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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:

	2014
(In millions)	Private Equity			Real Estate			Other		Total
Beginning balance	$	57		$	60		$	20	$	137
Actual return on plan assets:
Realized	6			4			—		10
Unrealized	6			4			1		11
Purchases	10			5			—		15
Sales	(13		)	(16		)	—		(29		)
Ending balance	$	66		$	57		$	21	$	144

	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

Cash Flows

Contributions to defined benefit plans – Our funding policy with respect to the funded 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 2014, we made pension contributions totaling $16 million. We have no required funding for 2015, but may make voluntary contributions at our discretion. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are estimated to be approximately $18 million and $27 million in 2015.

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
2015	$	179	$	27
2016	181		30
2017	181		33
2018	181		37
2019	179		40
2020 through 2024	810		236

Contributions to defined contribution plans – We also contribute to several defined contribution plans for eligible employees. Contributions to these plans totaled $86 million, $76 million and $60 million in 2014, 2013 and 2012, respectively.

114

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 2014, 2013 and 2012 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 2014 and 2013 is for the plan’s year ended December 31, 2013 and December 31, 2012, 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 2014, 2013 and 2012 contributions. Our portion of the contributions does not make up more than five 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	2014	2013		2014		2013		2012
Central States, Southeast and Southwest Areas Pension Plan(a)	36-6044243	Red	Red	Implemented	$	4	$	3	$	4	No	January 31, 2019

^(a)  This agreement has a minimum contribution requirement of $280 per week per employee for 2015. A total of 267 employees participated in the plan as of December 31, 2014.

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 $6 million, $5 million and $5 million for 2014, 2013 and 2012.

24. 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 and non-employee directors. 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 April 26, 2012, our employees and non-employee directors were eligible to receive equity awards under the Marathon Petroleum Corporation 2011 Second Amended and Restated Incentive Compensation Plan (“MPC 2011 Plan”).

115

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. All of the stock options granted in 2014 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”) – SARs were granted under the Marathon Oil Corporation incentive compensation plan in effect prior to the Spinoff. No SARs have been granted under 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 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. All outstanding SAR’s expired or were exercised in 2014.

Restricted Stock and Restricted Stock Units – We grant restricted stock and restricted stock units to employees and non-employee directors. 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 equal to the market price 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 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 total shareholder return (“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 an average of 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 recorded at fair value with a mark-to-market adjustment made each quarter. The performance units that settle in shares are accounted for as equity awards.

Total Stock-Based Compensation Expense

The following table reflects activity related to our stock-based compensation arrangements:

(In millions)	2014		2013		2012
Stock-based compensation expense	$	40	$	42	$	35
Tax benefit recognized on stock-based compensation expense	15		15		13
Cash received by MPC upon exercise of stock option awards	26		48		108
Tax benefit received for tax deductions for stock awards exercised	19		18		16

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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:

	2014			2013			2012
Weighted average exercise price per share	$	85.02		$	84.65		$	42.02
Expected life in years	5.8			6.0			5.8
Expected volatility	36		%	40		%	47		%
Expected dividend yield	1.9		%	2.0		%	2.6		%
Risk-free interest rate	1.8		%	1.0		%	1.1		%
Weighted average grant date fair value of stock option awards granted	$	25.37		$	27.13		$	14.45

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 2014 assumption for expected volatility of our stock price reflects a weighting of 50 percent of our common stock implied volatility and 50 percent of MPC’s common stock historical volatility. Prior to 2014, we used a weighting of our common stock implied volatility and the historical volatility of a selected group of peers. Expected dividend yield is based on annualized dividends at the date of grant. 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 2014:

	Number of of Shares(a)		Weighted Average Exercise Price		Weighted Average Remaining Contractual Terms (in years)	Aggregate Intrinsic Value (in millions)
Outstanding at December 31, 2013	5,147,837		$	40.08
Granted	446,310		85.02
Exercised	(821,948	)	33.04
Forfeited, canceled or expired	(20,761	)	49.67
Outstanding at December 31, 2014	4,751,438		45.47
Vested and expected to vest at December 31, 2014	4,746,653		45.43		5.7	$	213
Exercisable at December 31, 2014	3,795,031		38.30		5.0	197

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

The intrinsic value of options exercised by MPC employees during 2014, 2013 and 2012 was $48 million, $60 million and $37 million, respectively.

As of December 31, 2014, unrecognized compensation cost related to stock option awards was $5 million, which is expected to be recognized over a weighted average period of 1.1 years.

117

Restricted Stock Awards

The following is a summary of restricted stock award activity of our common stock in 2014:

	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, 2013	624,122		$	61.11	385,079		$	33.96
Granted	251,351		87.64		26,725		85.90
RS’s Vested/RSU’s Issued	(330,971	)	55.36		(578	)	51.99
Forfeited	(29,429	)	70.29		(133	)	76.10
Outstanding at December 31, 2014	515,073		77.23		411,093		37.30

Of the 411,093 restricted stock units outstanding, 409,805 are vested and have a weighted average grant date fair value of $37.16. 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:

	Restricted Stock				Restricted Stock Units
	Intrinsic Value of Awards Vested During the Period (in millions)		Weighted Average Grant Date Fair Value of Awards Granted During the Period		Intrinsic Value of Awards Vested During the Period (in millions)		Weighted Average Grant Date Fair Value of Awards Granted During the Period
2014	$	28	$	87.64	$	—	$	85.90
2013	20		87.06		—		73.48
2012	5		43.11		—		44.38

As of December 31, 2014, unrecognized compensation cost related to restricted stock awards was $26 million, which is expected to be recognized over a weighted average period of 1.1 years. There was no material unrecognized compensation cost related to restricted stock unit awards.

Performance Unit Awards

The following table presents a summary of the 2014 activity for performance unit awards to be settled in shares:

	Number of Units		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2013	3,822,500		$	0.90
Granted	2,033,700		0.85
Canceled	(64,375	)	0.87
Outstanding at December 31, 2014	5,791,825		0.88

The number of shares that would be issued upon target vesting, using the closing price of our common stock on December 31, 2014 would be 64,168 shares.

As of December 31, 2014, unrecognized compensation cost related to equity-classified performance unit awards was $2 million, which is expected to be recognized over a weighted average period of 1.5 years.

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Performance units paying out in units have a grant date fair value calculated using a Monte Carlo valuation model, which requires the input of subjective assumptions. The following table provides a summary of these assumptions:

	2014			2013			2012
Risk-free interest rate	0.63		%	0.35		%	0.41		%
Look-back period	2.84 years			2.84 years			2.84 years
Expected volatility	38.51		%	41.67		%	56.06		%
Grant date fair value of performance units granted	$	0.85		$	0.95		$	0.80

The risk-free interest rate for the remaining performance period as of the grant date is based on the U.S. Treasury yield curve in effect at the time of the grant. The look-back period reflects the remaining performance period at the grant date. The assumption for the expected volatility of our stock price reflects the average MPC common stock historical volatility.

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, 2014, 2013 and 2012.

25. 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, 2014, 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
2015	$	52	$	249
2016	51		209
2017	50		150
2018	49		136
2019	45		114
Later years	300		468
Total minimum lease payments	547		$	1,326
Less imputed interest costs	176
Present value of net minimum lease payments	$	371

Operating lease rental expense was:

(In millions)	2014		2013		2012
Rental expense	$	256	$	213	$	139

119

26. 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, including those resulting from the acquisition of Hess’ Retail Operations and Related Assets. For matters for which we have not recorded an accrued liability, we are unable to estimate a range of possible loss because the issues involved have not been fully developed through pleadings and discovery. However, the ultimate resolution of some of these contingencies could, individually or in the aggregate, be material.

Environmental matters – We are subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites and certain other locations including presently or formerly owned or operated retail marketing sites. Penalties may be imposed for noncompliance.

At December 31, 2014 and 2013, accrued liabilities for remediation totaled $185 million and $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 $67 million and $51 million at December 31, 2014 and 2013, respectively.

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 millionduring 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, 2014.

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 $38 million as of December 31, 2014.

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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, 2014, which consist of unrecognized tax benefits related to MPC, its consolidated subsidiaries and the RM&T Business operations prior to the Spinoff which are not already reflected in the unrecognized tax benefits described in Note 13, and other contingent liabilities Marathon Oil may incur related to taxes. Furthermore, the separation and distribution agreement and other agreements with Marathon Oil to effect the Spinoff provide for cross-indemnities between Marathon Oil and us. In general, Marathon Oil is required to indemnify us for any liabilities relating to Marathon Oil’s historical oil and gas exploration and production operations, oil sands mining operations and integrated gas operations, and we are required to indemnify Marathon Oil for any liabilities relating to Marathon Oil’s historical refining, marketing and transportation operations. The terms of these indemnifications are indefinite and the amounts are not capped.

Other guarantees – We have entered into other guarantees with maximum potential undiscounted payments totaling $81 million as of December 31, 2014, 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 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 both December 31, 2014 and 2013, our contractual commitments to acquire property, plant and equipment and advance funds to equity method investees totaled $1.7 billion. The contractual commitments at December 31, 2014 includes $520 million of contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets, $703 million for contributions to North Dakota Pipeline and $185 million for contributions to the SAX project. The contractual commitments at December 31, 2013 included the $700 million contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets and $892 million for contributions to North Dakota Pipeline. See Note 5.

27. Subsequent Event

On February 12, 2015, MPLX completed an initial underwritten public offering of $500 million aggregate principal amount of four percent unsecured senior notes due February 15, 2025 (the “MPLX Senior Notes”). The MPLX Senior Notes were offered at a price to the public of 99.64 percent of par. The net proceeds of this offering were used to repay the amounts outstanding under the MPLX Credit Agreement, as well as for general partnership purposes.

121

Selected Quarterly Financial Data (Unaudited)

	2014								2013
(In millions, except per share data)	1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.		1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.
Revenues	$	23,285	$	26,844	$	25,438	$	22,250	$	23,330	$	25,677	$	26,256	$	24,897
Income from operations	361		1,369		1,062		1,259		1,156		960		301		1,008
Net income	207		864		679		805		730		599		173		631
Net income attributable to MPC	199		855		672		798		725		593		168		626
Net income attributable to MPC per share:
Basic	$	0.68	$	2.97	$	2.38	$	2.88	$	2.19	$	1.84	$	0.54	$	2.09
Diluted	0.67		2.95		2.36		2.86		2.17		1.83		0.54		2.07
Dividends paid per share	0.42		0.42		0.50		0.50		0.35		0.35		0.42		0.42

122

Supplementary Statistics (Unaudited)

(In millions)	2014			2013			2012
Income from Operations by segment
Refining & Marketing	$	3,609		$	3,206		$	5,098
Speedway	544			375			310
Pipeline Transportation(a)	280			210			216
Items not allocated to segments:
Corporate and other unallocated items(a)	(286		)	(271		)	(336		)
Minnesota Assets sale settlement gain	—			—			183
Pension settlement expenses	(96		)	(95		)	(124		)
Income from operations	$	4,051		$	3,425		$	5,347
Capital Expenditures and Investments(b)(c)
Refining & Marketing	$	1,104		$	2,094		$	705
Speedway	2,981			296			340
Pipeline Transportation	543			234			211
Corporate and Other(d)	110			165			204
Total	$	4,738		$	2,789		$	1,460

^(a)  Included in the Pipeline Transportation segment for 2014, 2013 and 2012 are $19 million, $20 million and $4 million of corporate overhead expenses attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. Corporate overhead expenses are not currently allocated to other segments.

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

^(c)  Includes $2.71 billion in 2014 for the acquisition of Hess’ Retail Operations and Related Assets and $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5 to the audited consolidated financial statements.

^(d)  Includes capitalized interest of $27 million, $28 million and $101 million for 2014, 2013 and 2012, respectively.

123

Supplementary Statistics (Unaudited)

	2014		2013		2012
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)(a)(b)	2,138		2,086		1,618
Refining & Marketing Operating Statistics(b)
Refining & Marketing refined product sales volume (thousands of barrels per day)(c)	2,125		2,075		1,599
Refining & Marketing gross margin (dollars per barrel)(d)	$	15.05	$	13.24	$	17.85
Crude oil capacity utilization percent(e)	95		96		100
Refinery throughputs (thousands of barrels per day):(f)
Crude oil refined	1,622		1,589		1,195
Other charge and blendstocks	184		213		168
Total	1,806		1,802		1,363
Sour crude oil throughput percent	52		53		53
WTI-priced crude oil throughput percent	19		21		28
Refined product yields (thousands of barrels per day):(f)
Gasoline	869		921		738
Distillates	580		572		433
Propane	35		37		26
Feedstocks and special products	276		221		109
Heavy fuel oil	25		31		18
Asphalt	54		54		62
Total	1,839		1,836		1,386
Refinery direct operating costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.80	$	1.20	$	1.00
Depreciation and amortization	1.41		1.36		1.44
Other manufacturing(h)	4.86		4.14		3.15
Total	$	8.07	$	6.70	$	5.59
Refining & Marketing Operating Statistics By Region – Gulf Coast(b)
Refinery throughputs (thousands of barrels per day):(i)
Crude oil refined	991		964
Other charge and blendstocks	182		195
Total	1,173		1,159
Sour crude oil throughput percent	64		65
WTI-priced crude oil throughput percent	3		7
Refined product yields (thousands of barrels per day):(i)
Gasoline	508		551
Distillates	368		365
Propane	23		23
Feedstocks and special products	274		215
Heavy fuel oil	13		19
Asphalt	13		13
Total	1,199		1,186
Refinery direct operating costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.82	$	1.00
Depreciation and amortization	1.15		1.09
Other manufacturing(h)	4.73		3.98
Total	$	7.70	$	6.07

124

Supplementary Statistics (Unaudited)
	2014			2013			2012
Refining & Marketing Operating Statistics By Region – Midwest
Refinery throughputs (thousands of barrels per day):(i)
Crude oil refined	631			625
Other charge and blendstocks	45			54
Total	676			679
Sour crude oil throughput percent	33			35
WTI-priced crude oil throughput percent	44			42
Refined product yields (thousands of barrels per day):(i)
Gasoline	361			371
Distillates	212			207
Propane	13			14
Feedstocks and special products	43			41
Heavy fuel oil	13			12
Asphalt	41			41
Total	683			686
Refinery direct operating costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.66		$	1.47
Depreciation and amortization	1.78			1.74
Other manufacturing(h)	4.76			4.21
Total	$	8.20		$	7.42
Speedway Operating Statistics(j)
Convenience stores at period-end	2,746			1,478			1,464
Gasoline and distillate sales (millions of gallons)	3,942			3,146			3,027
Gasoline & distillate gross margin (dollars per gallon)(k)	$	0.1775		$	0.1441		$	0.1318
Merchandise sales (in millions)	$	3,611		$	3,135		$	3,058
Merchandise gross margin (in millions)	$	975		$	825		$	795
Merchandise gross margin percent	27.0		%	26.3		%	26.0		%
Same store gasoline sales volume (period over period)	(0.7		)%	0.5		%	(0.8		)%
Same store merchandise sales (period over period)(l)	5.0		%	4.3		%	7.0		%
Pipeline Transportation Operating Statistics
Pipeline throughputs (thousands of barrels per day):(m)
Crude oil pipelines	1,241			1,293			1,191
Refined products pipelines	878			911			980
Total	2,119			2,204			2,171

^(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 43 thousand barrels per day (“mbpd”), 36 mbpd and 25 mbpd for 2014, 2013 and 2012, 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)  Includes the impact of Hess’ Retail Operations and Related Assets beginning on the September 30, 2014 acquisition date.

^(k)  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.

^(l)  Excludes cigarettes.

^(m)  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, 2014, 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, 2014, we acquired Hess’ Retail Operations and Related Assets. The scope of our assessment of the effectiveness of disclosure controls and procedures does not include Hess’ Retail Operations and Related Assets. There have been no other 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

On February 24, 2015, the Compensation Committee of our Board of Directors (the “Committee”) approved and authorized a retirement lump sum benefit supplement, as further described below (the “Service Benefit”), to the respective formulaic benefit to be received under the Marathon Petroleum Excess Benefit Plan (the “Plan”) by Marathon Petroleum Corporation named executive officers, Gary R. Heminger and Anthony R. Kenney, should they individually elect to continue service as our employee beyond the age of 62. The Plan was amended and restated by the Committee on October 29, 2014, and such amended and restated Plan is filed as an exhibit to this Annual Report on Form 10-K (the “Revised Plan”). While the Revised Plan permits the Committee, on a discretionary basis, to extend the Service Benefit to individual officers of Marathon Petroleum Corporation, the amendment and restatement of the Plan by itself had no material impact on the defined benefit plan compensation of our named executive officers prior to the Committee’s subsequent action on February 24, 2015.

The Plan is an unfunded, non-qualified retirement plan for the benefit of a select group of management, including our named executive officers and highly compensated employees. The Plan generally provides benefits that participants would have otherwise received under the tax-qualified Marathon Petroleum Retirement Plan (the “Retirement Plan”) were it not for Internal Revenue Code limitations. Due to the structure of the legacy final average pay benefit formula within the Retirement Plan, the age-related lump sum benefit conversion factors used to calculate lump sum benefits under the Plan result in a year-to-year decrease in the lump sum benefit for participants generally beginning on or after the age of 59. As a result, even if participants want to continue their employment with us after they reach age 59, their lump sum benefit may decline year-to-year.

The Service Benefit will not correct for any age-related erosion of benefit occurring prior to age 62 but, for those officers selected by the Committee in its sole discretion, the Service Benefit will correct for the age-related erosion of benefit from age 62 until such officer’s actual retirement date or date of death as described herein. If an officer to whom the Service Benefit has been extended by the Committee retires or dies (1) after reaching age 62 and (2) while in service as our active employee, such officer will be eligible to receive a retirement lump sum benefit supplement calculated as follows:

a. If the lump sum interest rate upon such officer reaching the age of 62 used to calculate the retirement lump sum benefit is less than or equal to the lump sum interest rate in effect on such officer’s actual retirement date or date of death, the retirement lump sum benefit supplement shall be the difference between the legacy final average pay-based lump sum benefit he or she would have been eligible to receive using the age 62 lump sum conversion factor based on the lump sum interest rate in effect on the actual retirement date or date of death and the legacy final average pay-based lump sum benefit he or she is eligible to receive using the lump sum conversion factor for the actual age at retirement or death based on the lump sum interest rate in effect on the actual retirement date or date of death; or

126

b. If the lump sum interest rate upon such officer reaching the age of 62 used to calculate the retirement lump sum benefit is greater than the lump sum interest rate in effect on such officer’s actual retirement date or date of death, the retirement lump sum benefit supplement shall be the difference between the legacy final average pay-based lump sum benefit he or she would have been eligible to receive using the lump sum conversion factor and lump sum interest rate in effect at age 62 and the legacy final average pay-based lump sum benefit he or she is eligible to receive using the lump sum conversion factor and lump sum interest rate in effect on the actual retirement date or date of death.

As designed by the Committee, the Service Benefit does not compensate for unfavorable fluctuations in the lump sum interest rate and is in fact structured to prevent payment of a retirement lump sum benefit supplement greater than intended within a favorable interest rate environment; the Service Benefit is designed to correct only for the benefit erosion an officer may experience for continued service should he or she elect to remain our employee beyond the age of 62.

The foregoing description of the Plan, the Revised Plan and the Service Benefit are summary in nature and subject to, and qualified in their entirety by, the full text of the Revised Plan, a copy of which is attached hereto as Exhibit 10.14 and is incorporated herein by reference.

127

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 I Directors” located under the heading “Proposals of the Board” in our Proxy Statement for the 2015 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 2015 Annual Meeting of Shareholders.

We have adopted a Code of Ethics for Senior Financial Officers, which applies to our Chief Executive Officer, Chief Financial Officer, Vice President and Controller, Treasurer and other persons performing similar functions. 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 2015 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 2015 Annual Meeting of Shareholders.

128

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 2015 Annual Meeting of Shareholders.

Securities Authorized for Issuance Under Equity Compensation Plans

The following table provides information as of December 31, 2014 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	5,290,867	$	45.47	23,510,876
Equity compensation plan not approved by stockholders	—	—		—
Total	5,290,867	N/A		23,510,876

^(a)Includes the following:

1) 4,751,438 stock options granted pursuant to the MPC 2012 Plan and the MPC 2011 Plan and not forfeited, cancelled or expired as of December 31, 2014.

2) 411,093 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, 2014.

3) 128,336 shares as the maximum potential number of shares that could be issued in settlement of performance units outstanding as of December 31, 2014 pursuant to the MPC 2012 Plan and the MPC 2011 Plan, based on the closing price of our common stock on December 31, 2014 of $90.26 per share. The number of shares reported for this award vehicle may overstate dilution. See Note 24 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, 515,073 shares of restricted stock have been issued pursuant to the MPC 2012 Plan and the MPC 2011 Plan and were outstanding as of December 31, 2014.

^(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 than 9,357,450 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 83,226 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, 2014, based on the closing price of our common stock on December 31, 2014, of $90.26 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 24 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 2015 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 2015 Annual Meeting of Shareholders.

129

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
2.3 †	Purchase Agreement by and between Speedway LLC and Hess Corporation, dated as of May 21, 2014	8-K	2.1	5/27/2014	001-35054
2.4 †	Amendment No. 1 effective as of September 30, 2014, to the Purchase Agreement by and between Speedway LLC and Hess Corporation, dated as of May 21, 2014	8-K	2.2	10/6/2014	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 (including form of note)	10	4.2	5/26/2011	001-35054
4.3	First Supplemental Indenture, dated as of September 5, 2014, by and between Marathon Petroleum Corporation and The Bank of New York Mellon Trust Company, N.A., as trustee	10-Q	4.1	11/3/2014	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

130

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	Credit Agreement, dated as of November 20, 2014, among MPLX LP, as borrower, Citibank, N.A., as administrative agent, each of Citigroup Global Markets Inc., Wells Fargo Securities, LLC, Barclays Bank PLC, J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporate and RBS Securities Inc., as joint lead arrangers and joint bookrunners, Wells Fargo Bank, N.A., as syndication agent, and each of Bank of America, N.A., Barclays Bank PLC, JPMorgan Chase Bank, N.A., and The Royal Bank of Scotland PLC, as documentation agents, and the other lenders and issuing banks that are parties thereto.	8-K	10.1	11/26/2014	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 Amended and Restated Excess Benefit Plan					X
10.15 *	Marathon Petroleum Amended and Restated Deferred Compensation Plan	10-K	10.13	2/29/2012	001-35054

131

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					X
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	10-K	10.38	2/28/2014	001-35054

132

Exhibit Number	Exhibit Description		Incorporated by Reference			Filed Herewith	Furnished Herewith
		Form	Exhibit	Filing Date	SEC File No.
10.39*	Form of Marathon Petroleum Corporation Performance Unit Award Agreement – 2014-2016 Performance Cycle	10-Q	10.1	5/5/2014	001-35054
10.4	Term Loan Agreement, dated August 26, 2014, by and among Marathon Petroleum Corporation, as borrower, The Royal Bank of Scotland PLC, as administrative agent, each of RBS Securities Inc., The Bank of Tokyo-Mitsubishi UFJ, Ltd. Barclays Bank PLC, Citigroup Global Markets Inc., and Morgan Stanley Senior Funding, Inc., as joint lead arrangers and joint bookrunners. The Bank of Tokyo-Mitsubishi UFJ, Ltd., as syndication agent, each of Barclays Bank PLC, Citigroup Global Markets Inc. and Morgan Stanley Senior Funding, Inc., as documentation agents, and several other commercial lending institutions that are parties thereto	8-K	10.1	8/29/2014	001-35054
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.

133

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 27, 2015	MARATHON PETROLEUM CORPORATION
	By:    /s/ John J. Quaid
	John J. Quaid                 Vice President and Controller

134

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on February 27, 2015 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/ John J. Quaid	Vice President and Controller (Principal Accounting Officer)
John J. Quaid
*	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

135

* 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 27, 2015
Gary R. Heminger                 Attorney-in-Fact

136

EX-10.14

Exhibit 10.14

MARATHON PETROLEUM

EXCESS BENEFIT PLAN

Amended and Restated As Of

October 29, 2014

EXCESS BENEFIT PLAN

ARTICLE I.     Purpose

The Marathon Petroleum Excess Benefit Plan was initially established on February 5, 1976 as the Marathon Oil Company Excess Benefit Plan, and has been amended from time to time. Its stated purpose is to compensate employees for the loss of benefits that occur due to limitations placed by the Internal Revenue Code on benefits payable and contributions permitted under qualified retirement plans. These limitations include Code section 415, Code section 401(k), Code section 401(m), Code section 402(g), and Code section 401(a)(17).

On January 1, 1998, Marathon Oil Company and Ashland Petroleum Inc. entered into a joint venture, called Marathon Ashland Petroleum LLC (“MAPLLC”). As a result of the formation of the joint venture and the transfer of a significant number of Marathon employees to MAPLLC, on April 1, 1998 a portion of the Marathon Oil Company Retirement Plan was spun off to create the Marathon Ashland Petroleum LLC Retirement Plan (“Retirement Plan”). Consistent with that action and pursuant to the agreement of the parties, Excess Retirement Benefits and Excess Thrift Benefits under the Marathon Oil Company Excess Benefit Plan for employees who transferred to MAPLLC during the 1998 calendar year were spun-off to create the Marathon Ashland Petroleum LLC Excess Benefit Plan (the “MAPLLC Excess Benefit Plan”). Any elections in effect under the Marathon Oil Company Excess Benefit Plan (such as beneficiary designations or Group I employee elections, etc.) continued to apply under the MAPLLC Excess Benefit Plan, until and unless changed. The terms and conditions of this MAPLLC Excess Benefit Plan were substantially the same as the terms and conditions of the Marathon Oil Company Excess Benefit Plan.

Effective September 1, 2005, MAPLLC changed its name to Marathon Petroleum Company LLC (“MPC” or “the Company”). Therefore, “MAP” has been replaced with “MPC” throughout this document, and all references to MPC are one and the same with respect to previous references to MAP. The name change from MAP to MPC does not affect any benefits under this Plan.

Effective January 1, 2006, this Excess Benefit Plan was restated to incorporate prior amendments.

Effective January 1, 2009, this Excess Benefit Plan was restated and shall apply only to benefits that are not fully distributed as of such date, including both 409A Accruals and Grandfathered Accruals. With respect to the 409A Accruals, the Excess Benefit Plan, as amended and restated, is intended to conform to the requirements of Code section 409A, and, in all respects, shall be administered and construed in accordance with such requirements. With respect to the Grandfathered Accruals, the Excess Benefit Plan, as amended and restated, does not represent a material enhancement of the benefits or rights available under the Excess Benefit Plan on October 3, 2004.

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Effective July 1, 2011, this Excess Benefit Plan was restated primarily to provide for the allocation of liabilities between this Excess Benefit Plan and the corresponding excess benefit plan for employees of Marathon Oil Company in accordance with the Employee Matters Agreement and to provide the Select Group Members with a Final Average Pay adjustment for their Legacy Retirement Benefit which corresponds to the Final Average Pay adjustment made available under the Retirement Plan to other Members for their Legacy Retirement Benefit. October 1, 2010, Marathon Petroleum Company LLC changed its name to Marathon Petroleum Company LP and is reflected as such throughout this document. (References to “MPC” include MAPLLC, Marathon Petroleum Company LLC, and Marathon Petroleum Company LP).

Effective October 29, 2014, the Excess Benefit Plan was amended and restated, primarily to provide for an additional Excess Retirement Benefit, as set forth in Section 3.1(d) herein. This additional Excess Retirement Benefit is intended to address the decrease in the lump sum benefit that may occur as a result of age-related conversion factors used to calculate the lump sum Legacy Retirement Benefit, to provide a retention incentive for certain individuals whose continued service is deemed to be in the best interests of the Company, as determined by the Compensation Committee of the Marathon Petroleum Corporation Board of Directors.

This Excess Benefit Plan sets forth the terms and conditions under which benefits designed to compensate Employees for the aforementioned losses of benefits shall be accrued and paid by the applicable Employer.Capitalized terms, unless otherwise specified, are defined under the Retirement Plan, the Thrift Plan, and the Employee Matters Agreement. In addition, for purposes of this Article I and the remainder of this Excess Benefit Plan, the following definitions apply:

“409A Accruals” means those benefits that were accrued after or became vested after 2004, as adjusted for interest or changes in present value, as applicable. Such amounts shall be determined in accordance with Code section 409A.

“Code” means the Internal Revenue Code.

“Code section 409A” means section 409A of the Code and any Treasury and Internal Revenue Service regulations and guidance issued thereunder.

“Company” means Marathon Petroleum Company LP.

“Distribution Agreement” means the Separation and Distribution Agreement dated as of May 25, 2011 among Marathon Oil Corporation, Marathon Oil Company and Marathon Petroleum Corporation.

“Distribution Date” means June 30, 2011.

“Employee” means any individual employed by an Employer.

“Employee Matters Agreement” means the agreement respecting certain employee matters dated as of May 25, 2011 between Marathon Oil Corporation and Marathon Petroleum Corporation.

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“Employer” includes the Company and each related company or business which is part of the same controlled group under Code sections 414(b) or 414(c); provided that where specified by the Employer in accordance with Code section 409A in applying Code section 1563(a)(1) – (a)(3) for purposes of determining a controlled group of corporations under Code section 414(b) and in applying Treasury Regulation section 1.414(c)-2 for purposes of determining whether trades or businesses are under common control under Code section 414(c), the phrase “at least 50 percent” is used instead of “at least 80 percent.” In addition, the term “Employer” shall also include any entity that previously met the requirements of an “Employer” as set forth herein that continues to employ a Participant to the extent so designated by the Plan Administrator.

“Excess Benefit Plan” means the Marathon Petroleum Excess Benefit Plan.

“Grandfathered Accruals” means those benefits that are exempt from Code section 409A because they were accrued and vested before January 1, 2005, as adjusted for interest or changes in present value, as applicable. Such amounts shall be determined in accordance with Code section 409A.

“Legacy Retirement Benefit” as defined in the Retirement Plan, means the Member’s retirement benefit (if any) determined under Article 6 of the Retirement Plan without taking into account any Plan Participation Service after December 31, 2009.

“Retirement Plan” means the Refining, Marketing and Transportation Sub-Plan of the Marathon Petroleum Retirement Plan.

“Select Group Member” means a Member of the Retirement Plan who, on August 17, 2009, either was a supervisor in Grade 14 or above or had a base pay of $190,000 (specifically excluding bonus) or higher.

“Separation from Service” shall have the same meaning as set forth under Code section 409A with respect to an Employer.

“Specified Employee” shall have the meaning as set forth under Code section 409A and as determined by the Employer in accordance with its established policy.

“Thrift Plan” means the Marathon Petroleum Thrift Plan.

ARTICLE II. Eligibility

2.1 Eligibility for Benefits

The following individuals are eligible to accrue Excess Benefit Plan benefits:

(a)    (1) Every individual who qualifies for a benefit under the terms of the Retirement Plan and (i) whose benefit as determined under the Retirement Plan is reduced due to salary deferrals under the Marathon Petroleum Deferred Compensation Plan or any similar plan maintained by the Employer or by either Code section 415 or the annual compensation limit as set forth under Code section 401(a)(17) (collectively, the “Defined Benefit Limits”), or (ii) would accrue a Special Excess Bonus Recognition benefit as set forth in section 3.1(b) hereof and is designated by the Plan Administrator and (2) each Select Group Member whose

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Legacy Retirement Benefit under the Retirement Plan is determined without taking into account his or her changes in Final Average Pay after December 31, 2009.

(b)     Every individual who participates in the Thrift Plan and who (i) has potential contributions to the Thrift Plan limited by Code Requirements (as defined below) to a point which precludes the individual’s receipt of the maximum matching Company Contributions provided under Article VI of the Thrift Plan; (ii) is limited by Code Requirements to making contributions to the Thrift Plan at a percentage that is less than their elected contribution percentage; and (iii) continues to make After-Tax and Pre-Tax Contributions to the Thrift Plan at the maximum rate as limited by Code requirements. As used in this Excess Benefit Plan, the term “Code Requirements” includes, and is limited to, the following requirements:

(1) Code section 415;

(2) Code section 401(k) (Actual Deferral Percentage test) and Code section 401(m) (Actual Contribution Percentage test);

(3) The Code section 402(g) annual dollar limitation on MSP Contributions; or

(4) The annual compensation limit as set forth under Code section 401(a)(17).

Every individual who is eligible to receive benefits under this Excess Benefit Plan by reason of his or her active employment with an Employer shall be known as a Participant. Every individual who becomes eligible to receive benefits under this Excess Benefit Plan in the event of the death of a Participant shall be known as a Beneficiary. The Beneficiary of a Participant under this Excess Benefit Plan shall be such Beneficiary as may be provided under Section 3.3(b).

2.2 No Duplication of Benefits

Any individual who is eligible under the terms of the Marathon Petroleum Deferred Compensation Plan or any similar plan maintained by the Employer shall receive excess Thrift accruals under that plan. No Participant shall receive duplicate benefits under the Thrift Plan, Excess Benefit Plan, or Deferred Compensation Plan.

2.3     Allocation of Liabilities under the Employee Matters Agreement

(a)    Immediately following the Distribution Date this Excess Benefit Plan pursuant to the Employee Matters Agreement shall assume the Liabilities of the Marathon Oil Company Excess Benefit Plan representing any benefits accrued by individuals (1) who are either MPC Employees or Delayed Transfer Employees who move from the MRO Group to the MPC Group and (2) who have accrued benefits under the Marathon Oil Company Excess Benefit Plan.

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(b)    Immediately following the Distribution Date this Excess Benefit Plan pursuant to the Employee Matters Agreement shall no longer have any Liabilities representing benefits accrued under this Excess Benefit Plan by individuals (1) who are MRO Employees or Delayed Transfer Employees who move from the MPC Group to the MRO Group and (2) who have accrued benefits under this Excess Benefit Plan, and the MRO Employees and Transfer Employees described in this Section 2.3(b) shall after the Distribution Date look exclusively to the Marathon Oil Company Excess Benefit Plan for the payment of such accrued benefits.

ARTICLE III. Excess Retirement and Thrift Benefits

3.1 Amount of Excess Retirement Benefit

The amount of a Participant’s benefit under this Section 3.1 (the “Excess Retirement Benefit”), and as specified in Appendix I, shall be determined as of the Participant’s Separation from Service, as follows:

(a)    The amount of Excess Retirement Benefit which a Participant or Beneficiary (as defined in Section 3.3(b)) is entitled to receive shall be equal to the excess of (1) over (2) below:

(1)     The amount of benefit which such Participant or Beneficiary would be entitled to receive under the Retirement Plan if such benefit were computed without giving effect to the Defined Benefit Limitations and including elected deferred compensation contributions as permitted under the Marathon Petroleum Deferred Compensation Plan or any similar plan maintained by the Employer; less

(2)     The amount of benefit which such Participant or Beneficiary is entitled to receive under the Retirement Plan.

(b)     The following individuals shall be entitled to an additional Excess Retirement Benefit equal to the difference between (1) and (2) below (“Special Excess Bonus Recognition”): (i) Eligible Grandfather Employees and (ii) any Grade 19 and above Employee of Marathon Petroleum Company LP and its subsidiaries, who is recommended by the Senior Vice President of Human Resources of Marathon Petroleum Corporation and approved by the President and CEO of Marathon Petroleum Corporation.

(1)     An amount calculated under the Retirement Plan benefit formula, without regard to any Code mandated limitations (including, but not limited to, the Defined Benefit Limits)and including elected deferred compensation contributions as permitted under the Marathon Petroleum Deferred Compensation Plan or any similar plan maintained by the Employer, and substituting the following Final Average Pay (FAP) definition for the definition of “Final Average Pay” contained in the Retirement Plan:

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Final Average Pay shall be the highest pay, excluding bonuses, of a member for any consecutive 36-month period during the ten years of employment immediately prior to January 1, 2013, plus the highest three bonuses paid out during the same ten years (not necessarily consecutive), divided by 36.

(2)    An amount as normally determined under the Retirement Plan, plus any retirement benefit otherwise payable under the Excess Benefit Plan (i.e., exclusive of any benefits attributable to the calculation in Section 3.1(b)(1) above).

For purposes of the calculations in (1) and (2) of this Section 3.1(b) “Eligible Grandfather Employee” means any MPC employee eligible for Special Excess Bonus Recognition under Article III, Section A of this Plan prior to October 1, 2006. However, an individual’s Eligible Grandfather Employee status shall permanently cease upon termination, retirement, or death as an employee.

(c)     If a Participant is a Select Group Member or a Beneficiary (as defined in Section 3.3(b)) is the Beneficiary of a Select Group Member, he or she shall be entitled to an additional Excess Retirement Benefit equal to the excess of (1) over (2) below:

(1)    The amount of the benefit which such Participant or Beneficiary would have been entitled to receive under the Retirement Plan as a Legacy Retirement Benefit if any changes in the Select Group Member’s Final Average Pay after December 31, 2009, through December 31, 2012, had been taken into account under Section 4.02(c) of the Retirement Plan in computing his or her Legacy Retirement Benefit; less

(2)    The amount of the benefit which such Participant or Beneficiary is entitled to receive under the Retirement Plan as a Legacy Retirement Benefit.

(d)     If a Participant (i) is appointed an Officer of Marathon Petroleum Corporation by the Marathon Petroleum Corporation Board of Directors, (ii) is approved to be eligible to receive the additional Excess Retirement Benefit, as determined in this Section 3.1(d)(1) and (2) below, by the Marathon Petroleum Corporation Board of Directors Compensation Committee, (iii) retires or dies on or after age 62 as an active employee, and (iv) at the time of such retirement or death, such Participant is eligible for a Legacy Retirement Benefit under the terms of the Retirement Plan and the Excess Benefit Plan, he or she shall be entitled to an additional Excess Retirement Benefit, as follows:

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(1)    In the event the lump sum interest rate at age 62 is less than or equal to the lump sum interest rate at retirement or death, the lump sum Legacy Retirement Benefit will be supplemented in an amount equal to the difference between (a.) and (b.), below:

a.The lump sum Legacy Retirement Benefit calculated using the age 62 lump sum conversion factor based on the applicable lump sum interest rate in effect at retirement or death under the terms of the Retirement Plan and the Excess Benefit Plan; and

b.The lump sum Legacy Retirement Benefit calculated using the lump sum conversion factor for the actual age of retirement or death based on the lump sum interest rate in effect at retirement or death under the terms of the Retirement Plan and the Excess Benefit Plan.

(2)    In the event the lump sum interest rate at age 62 is greater than the lump sum interest rate at retirement or death, the lump sum Legacy Retirement Benefit will be supplemented in an amount equal to the difference between (a.) and (b.), below:

a.The lump sum Legacy Retirement Benefit calculated using the lump sum interest rate and lump sum conversion factor in effect at age 62 under the terms of the Retirement Plan and the Excess Benefit Plan, and

b.The lump sum Legacy Retirement Benefit calculated using the lump sum interest rate and lump sum conversion factor in effect at retirement or death under the terms of the Retirement Plan and the Excess Benefit Plan.

Refer to Appendix II for examples of benefit calculations, as described in this Section 3.1(d).

3.2 Amount of Excess Thrift Benefit

The amount of the benefit under this Section 3.2 (the “Excess Thrift Benefit”) which a Participant or Beneficiary is entitled to receive shall be equal to the excess of (a) over (b) below for each calendar year accumulated with interest to date of payment at the “Stable Value Fund” rate provided under Article VIII of the Thrift Plan:

(a)    The amount of Company Contributions under Article VI of the Thrift Plan that would have been credited to the Participant’s Thrift Plan account if the Code Requirements were not given effect for such year and using the Participant’s rate of contributions at the time the limitation becomes effective as determined by the Plan Administrator; less

(b)    The amount of Company Contributions actually credited to the Participant’s Thrift Plan account for such year.

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3.3 Payment of Excess Benefit

A Participant shall be entitled to a cash distribution of the Participant’s Excess Retirement Benefit and Excess Thrift Benefit, as applicable (collectively, the “Excess Benefit”), as provided in this Section 3.3.

(a)    Except as otherwise provided in this Section 3.3, a Participant’s Excess Benefit shall be paid in a lump sum within 90 days of Separation from Service for any reason other than death.

(b)     In the event of the death of a Participant, the Participant’s Excess Benefit shall be paid to the Participant’s applicable Beneficiary in a lump sum within 90 days of the Participant’s death or, if earlier, within the 90-day period following the Participant’s Separation from Service as described in Section 3.3(a) (or, in the event of a Separation from Service of a Specified Employee (as defined below) not on account of death, the 90-day period described in Section 3.3(c)). The Participant’s “Beneficiary” shall be: (i) with respect to the Participant’s Excess Retirement Benefit, the Beneficiary will be his or her Eligible Surviving Spouse or estate (if no Eligible Surviving Spouse); and (ii) with respect to the Participant’s Excess Thrift Benefit, the Participant’s Beneficiary will be the beneficiary or beneficiaries designated under the Thrift Plan. In any event, if there is no valid Beneficiary under the terms of this Excess Benefit Plan, the Excess Benefit will be paid to the person or persons comprising the first surviving class of the eligible classesas set forth: (1)    the Participant’s spouse; (2) the Participant’s natural born and legally adopted children; (3) the Participant’s surviving parents; (4) the Participant’s surviving brothers and sisters; and (5) the executor or administrator of the Participant’s estate.

(c)     Distribution of the Excess Benefit of a Participant who the Plan Administrator determines is a Specified Employee (other than such Participant’s Grandfathered Accruals) shall be paid in a lump sum within the 90-day period following the first of the month following 6 months after Separation from Service (other than a Separation from Service on account of the death of Participant). In the event of a Separation from Service of a Specified Employee on account of death, payment shall be made pursuant to Section 3.3(b). Payment of a Specified Employee’s Grandfathered Accruals shall be made in accordance with Section 3.3(a).

(d)     A Participant must be vested under the Retirement Plan in order for an Excess Retirement Benefit to be payable. The amount of any lump sum payment hereunder shall be determined by using the same factors and assumptions which would be used by the Retirement Plan for such Participant or Beneficiary at the Participant’s Separation from Service. The balance of any Excess Retirement Benefit not paid at the Participant’s Separation from Service shall accrue interest beginning at the Participant’s Separation from Service at a rate used under the

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Retirement Plan to determine the actuarial equivalent lump sum of a life only monthly annuity.

(e)     A Participant must be fully vested under the Thrift Plan in order for an Excess Thrift Benefit to be payable. The balance of any Excess Thrift Benefit not paid at the Participant’s Separation from Service shall accrue interest at the “Stable Value Fund” rate provided under Article VIII of the Thrift Plan until the entire balance has been paid. If the “Stable Value Fund” rate becomes unavailable for any reason, whether for purposes of this Section 3.3(e) or for purposes of Section 3.2, the Company shall, at its sole discretion, substitute a similar interest rate which will be applicable for time periods thereafter.

(f)    Distributions of 409A Accruals prior to January 1, 2009 were made under reasonable good faith interpretations of Code section 409A and transition guidance provided thereunder. Notwithstanding any contrary provisions of this Section 3.3, to the extent the Plan Administrator permitted a Participant to submit an election to receive payment in a form of distribution other than a lump sum and such payment commenced prior to 2009, the distribution of such Participant’s Excess Benefit after 2008 shall be governed by procedures established by the Plan Administrator.

ARTICLE IV. Funding

Benefits under this Excess Benefit Plan shall be paid from the general assets of the applicable Employer. This Excess Benefit Plan shall be administered as an unfunded plan which is maintained primarily for the purpose of providing supplemental retirement compensation “for a select group of management or highly compensated employees” as set forth in sections 201(2), 301(3), and 401(a)(1) of ERISA, and is not intended to meet the qualification requirements of section 401 of the Code. Any assets set aside by the Employer for the purpose of paying benefits under this Excess Benefit Plan shall not be deemed to be the property of the Participant and shall be subject to claims of creditors of the Employer. No Participant or other person shall have any claim against, right to, or security or other interest in, any fund, account or asset of the Employer from which any payment under the Excess Benefit Plan may be made. Any use of the words “contributions” or “contribute,” or any similar phrase, shall not require actual contributions or funding of this Excess Benefit Plan and is only used for convenience when describing the deferral activities of this Excess Benefit Plan.

ARTICLE V. Plan Administration

5.1    General Duty

The Company has delegated its administrative authority hereunder to the Plan Administrator of the Retirement Plan or its successor (the “Plan Administrator.”) It shall be the principal duty of the Plan Administrator to determine that the provisions of the Excess Benefit Plan are carried out in accordance with its terms, for the exclusive benefit of persons entitled to participate in this Excess Benefit Plan.

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5.2    Plan Administrator’s General Powers, Rights and Duties

The Plan Administrator shall have full power to administer this Excess Benefit Plan in all of its details, subject to the applicable requirements of law. For this purpose, the Plan Administrator is, as respects the rights and obligations of all parties with an interest in this Excess Benefit Plan, given the powers, rights and duties specifically stated elsewhere in this Excess Benefit Plan, or any other document, and in addition is given, but not limited to, the following powers, rights and duties:

(a)    to determine all questions arising under this Excess Benefit Plan, including the power to determine the rights or eligibility of Employees or Participants and any other persons, and the amounts of their contributions or benefits under this Excess Benefit Plan, to interpret the Excess Benefit Plan, and to remedy ambiguities, inconsistencies or omissions;

(b)    to adopt such rules of procedure and regulations, including the establishment of any claims procedure that may be required by law, as in its opinion may be necessary for the proper and efficient administration of the Excess Benefit Plan and as are consistent with this Excess Benefit Plan;

(c)    to direct payments or distributions from this Excess Benefit Plan in accordance with the provisions of this Excess Benefit Plan;

(d)     to develop such information as may be required by it for tax or other purposes as respects this Excess Benefit Plan; and

(e)    to employ agents, attorneys, accountants or other persons (who also may be employed by the Company), and allocate or delegate to them such powers as the Plan Administrator may consider necessary or advisable to properly carry out the administration of this Excess Benefit Plan.

The Plan Administrator’s decision in any matter involving the interpretation and application of this Excess Benefit Plan shall be final and binding. In the event the Plan Administrator would have to decide any issue under this Excess Benefit Plan which could affect the form or timing of the payment of deferred compensation under this Excess Benefit Plan, then the Company shall make that decision.

5.3    Indemnification of Administrator

The Company agrees to indemnify and to defend to the fullest extent permitted by law any Employee serving as the Plan Administrator against all liabilities, damages, costs and expenses (including attorney’s fees and amounts paid in settlement of any claims approved by the Company) occasioned by any act or omission to act in connection with this Excess Benefit Plan, if such act or omission is or was in good faith. This Section 5.3 shall comply with Code section 409A and Treasury Regulation section 1.409A-3(i)(1)(iv) with regard to the requirements for reimbursements, to the extent applicable, for the period that such Employee’s indemnification right hereunder shall exist.

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5.4    Information Required by Plan Administrator

The Plan Administrator shall obtain such data and information as deemed necessary or desirable in order to administer this Excess Benefit Plan. The records of the Company as to an Employee’s or Participant’s period or periods of employment, termination of employment and the reason therefor, leave of absence, re-employment and earnings will be conclusive on all persons unless determined by independent agents or delegates of the Plan Administrator to be incorrect. Participants and other persons entitled to benefits under this Excess Benefit Plan also shall furnish the Plan Administrator with such evidence, data or information, as the Plan Administrator considers necessary or desirable to administer this Excess Benefit Plan.

5.5    Claims and Review Procedures

(a)    Claims Procedure. If a Participant believes any rights or benefits are being improperly denied under this Excess Benefit Plan, such Participant may file a claim in writing with the Plan Administrator. If any such claim is wholly or partially denied, the Plan Administrator shall notify such Participant of its decision in writing. Such notification shall be written in a manner calculated to be understood by such Participant and shall contain (i) specific reasons for the denial, (ii) specific reference to pertinent Excess Benefit Plan provisions, (iii) a description of any additional material or information necessary for the Participant to perfect such claim and an explanation of why such material or information is necessary, and (iv) information as to the steps to be taken if the Participant wishes to submit a request for review. Such notification shall be given within 90 days after the claim is received by the Plan Administrator (or within 180 days, if special circumstances require an extension of time for processing the claim, and if written notice of such extension and circumstances is given to such Participant within the initial 90 day period.) If such notification is not given within such period the claim shall be considered denied as of the last day of such period and such Participant may request a review of his claim.

(b)    Review Procedure. Within 60 days after the date on which a Participant receives a written notice of a denied claim (or, if applicable, within 60 days after the date on which such denial is considered to have occurred) such Participant (or the Participant’s duly authorized representative) may (i) file a written request with the Plan Administrator for a review of his denied claim and of pertinent documents, and (ii) submit written issues and comments to the Plan Administrator. The Plan Administrator shall notify such Participant of its decision in writing. Such notification shall be written in a manner calculated to be understood by such Participant and shall contain specific reasons for the decision as well as specific references to pertinent Excess Benefit Plan provision. The decision on review shall be made within 60 days after the request for review is received by the Plan Administrator (or within 120 days, if special circumstances require an extension of time for processing the request, such as an election by the Plan Administrator to hold a hearing, and if written notice of such extension and circumstances is

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given to such person within the initial 60 day period). If the decision on review is not made within such period, the claim shall be considered denied.

(c)    Section 409A Requirements. Any claim for benefits under this Section must be made by the Participant no later than the time prescribed by Code section 409A. If a claimant’s claim or appeal is approved, any resulting payment of benefits will be made no later than the time prescribed for payment of benefits by Code Section 409A.

ARTICLE VI. Modification and Discontinuance

6.1    Amendment and Termination

The Company reserves the right to modify, suspend, or terminate this Excess Benefit Plan at any time, in whole or in part, in such manner as it shall determine, provided that such action conforms to the requirements of Code section 409A. Included in the Company’s right to amend, suspend or terminate is the Company’s right at any time to no longer permit any additional Participants under this Excess Benefit Plan, to cease benefit accruals, and to distribute all benefits upon Excess Benefit Plan termination, all subject to the requirements of Code section 409A. The Plan Administrator may promulgate rules and procedures from time to time to carry out the provisions of this Article VI. However, in no event shall the Company have the right to eliminate or reduce any benefit, which has been vested or become forfeitable under this Excess Benefit Plan. o future amendment to this Excess Benefit Plan shall apply to Grandfathered Accruals to the extent such provision or amendment would constitute a “material modification” within the meaning of Code section 409A with respect to the Grandfathered Accruals unless such amendment expressly indicates otherwise.

6.2     Delegation of Authority

In addition to the other methods of amending MPC’s employee benefit plans, practices, and policies (hereinafter referred to as “MPC Employee Benefit Plans”) which have been authorized, or may in the future be authorized, by Marathon Petroleum’s Board of Directors, the Company’s Senior Vice President of Human Resources may approve the following types of amendments to MPC Employee Benefit Plans:

(a)    With the opinion of counsel, technical amendments required by applicable laws and regulations;

(b)     With the opinion of counsel, amendments that are clarifications of plan provisions;

(c)     Amendments in connection with a signed definitive agreement governing a merger, acquisition or divestiture such that, for MPC Employee Benefit Plans, needed changes are specifically described in the definitive agreement, or if not specifically described in the definitive agreement, the needed changes are in keeping with the intent of the definitive agreement;

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(d)    Amendments in connection with changes that have a minimal cost impact (as defined below) to the Company; and

(e)    With the opinion of counsel, amendments in connection with changes resulting from state or federal legislative actions that have a minimal cost impact (as defined below) to the Company.

For purposes of the above, “minimal cost impact” is defined as an annual cost impact to the Company per MPC Employee Benefit Plan case that does not exceed the greater of (i) an amount that is less than one-half of one percent of its documented total cost (including administrative costs) for the previous calendar year, or (ii) $500,000.

6.3     Transfer of Liabilities

In the event of a corporate transaction involving a Participant’s Employer, the liabilities with respect to the Participant’s Excess Benefit may be transferred to the entity or organization that becomes the Participant’s employer following the corporate transaction to the extent that such transfer (i) is permitted by applicable law, (ii) with respect to the 409A Accruals is consistent with Code section 409A, and (iii) with respect to Grandfathered Accruals, does not represent a material enhancement of the Participant’s benefits or rights available under the Excess Benefit Plan on October 3, 2004. For these purposes, a corporate transaction shall include, but not be limited to, a merger, consolidation, separation, reorganization, liquidation, split-up, or spin-off.

ARTICLE VII. General Provisions

7.1    Notices

Each Participant entitled to benefits under this Excess Benefit Plan must file in writing with the Plan Administrator such Participant’s post office address and each change of post office address. Any communication, statement or notice addressed to any such Participant at the last post office address filed with the Plan Administrator will be binding upon such person for all purposes of this Excess Benefit Plan, and the Plan Administrator shall not be obligated to search for or ascertain the whereabouts of any Participant. Any notice or document required to be given or filed with the Plan Administrator shall be considered as given or filed if delivered or mailed by registered mail, postage prepaid, to Rodney P. Nichols, Senior Vice President of Human Resources, P. O. Box 1, Findlay, Ohio 45839-0001.

7.2    Employment Rights

This Excess Benefit Plan does not constitute a contract of employment, and participation in this Excess Benefit Plan will not give any Participant the right to be retained in the employ of the Company or any Employer nor any right or claim to any benefit under this Excess Benefit Plan, unless such right or claim has specifically accrued under the terms of this Excess Benefit Plan.

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7.3    Interests Not Transferable

Except as may be required by law, including the federal income and employment tax withholding provisions of the Code, or of an applicable state’s income tax act, the interests of Participants and their Beneficiaries under this Excess Benefit Plan are not subject to the claims of their creditors and may not be voluntarily or involuntarily sold, transferred, alienated, assigned or encumbered. Notwithstanding any provision of this Excess Benefit Plan to the contrary, this Excess Benefit Plan shall not recognize or give effect to any domestic relations order attempting to alienate, transfer or assign any Participant benefits. The preceding shall not preclude the Employer from asserting any claim for damages or for any debt that the Employer may have with respect to the Participant; provided that any offset shall apply only where such debt is incurred in the ordinary course of the service relationship between the Employer and the Participant, the entire amount of reduction in any of the Participant’s taxable years does not exceed $5,000, and the reduction is made at the same time and in the same amount as the debt otherwise would have been due and collected from the Participant.

7.4    Facility of Payment

When a Participant entitled to benefits under this Excess Benefit Plan is under a legal disability, or, in the Plan Administrator’s opinion, is in any way incapacitated so as to be unable to manage their financial affairs, the Plan Administrator may direct that the benefits to which such Participant otherwise would be entitled shall be made to such Participant’s legal representative, or to such other person or persons as the Plan Administrator may direct the application of the benefits for the benefit of such Participant. Any payment made in accordance with such provisions of this Section 7.4 shall be a full and complete discharge of any liability for such payment.

7.5    Controlling State Law

To the extent not superseded by the laws of the United States, the laws of the State of Ohio shall be controlling in all matters relating to the Excess Benefit Plan.

7.6    Severability

In case any provisions of this Excess Benefit Plan shall be held illegal or invalid for any reason, such illegality or invalidity shall not affect the remaining provisions of this Excess Benefit Plan, and this Excess Benefit Plan shall be construed and enforced as if such illegal and invalid provisions had never been set forth in this Excess Benefit Plan.

7.7    Statutory References

All references to the Code and ERISA include reference to any comparable or succeeding provisions of any legislation, which amends, supplements or replaces such section or subsection.

7.8    Headings

Section headings and titles are for reference only. In the event of a conflict between a title and the content of a section, the content of the section shall control.

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7.9    Non-taxable Benefits

It is the intention of the Company that this Excess Benefit Plan meet all requirements of the Code so that the benefits provided be non-taxable during the period of deferral and until actual distribution is made.

7.10    Affect on Other Benefit Plans

Any benefit payable under the Retirement Plan or the Thrift Plan shall be paid solely in accordance with the terms and provisions of those Plans, and nothing in this Excess Benefit Plan shall operate or be construed in any way to modify, amend, or affect the terms and provisions of the Retirement Plan or Thrift Plan.

15

Appendix I

This Appendix I amends Section 3.1(b) of the Plan with respect to Donald C. Templin only. For the purpose of calculating Mr. Templin’s benefit under this Plan, Section 3.1(b) of the Plan shall be disregarded, and the following language shall be substituted:

(b) Donald C. Templin shall be entitled to an additional Excess Retirement Benefit equal to the difference between (1) and (2) below.

(1) An amount calculated under the Retirement Plan benefit formula as if Mr. Templin had 70 or more Points (as defined in Article 5 of the RMT Sub-Plan of the Marathon Petroleum Retirement Plan), without regard to any Code mandated limitations (including, but not limited to, the Defined Benefit Limitations) and including elected deferred compensation contributions as permitted under the Marathon Petroleum Deferred Compensation Plan or any similar plan maintained by the Employer.

(2) An amount as normally determined under the Retirement Plan, plus any retirement benefit otherwise payable under this Excess Benefit Plan (i.e., exclusive of any benefits attributable to the calculation in Section 3.1(b)(1) above).

16

Appendix II

Benefit Calculation Example per Section 3.1(d)

Example 1: Lump sum interest rate at age 62 = lump sum interest rate at retirement (age 65)
Step 1:	Calculate lump sum benefit using the age 62 lump sum conversion factor based on interest rate in
	effect at retirement (1.00%).
Step 2:	Calculate lump sum benefit using the conversion factor for the actual age of retirement (65) based
	on the lump sum interest rate in effect at retirement (1.00%).
Step 3:	Difference = supplemental payment.
		Step 1		Step 2		Step 3
		Hypothetical lump sum benefit at age 62		Lump sum benefit at age 65		Supplemental Payment
	Annuity Payable	$	30,000	$	30,000
	Lump Sum Conversion Factor	224.23		197.06
	Lump Sum Benefit	$	6,726,900	$	5,911,800		$815,100
Example 2: Lump sum interest rate at age 62 > lump sum interest rate at retirement (age 65)
Step 1:	Calculate lump sum benefit using the age 62 lump sum conversion factor based on interest rate in
	effect at age 62 (1.50%)
Step 2:	Calculate lump sum benefit using the conversion factor for the actual age of retirement (65) based
	on the lump sum interest rate in effect at retirement (1.00%).
Step 3:	Difference = supplemental payment.
		Step 1		Step 2		Step 3
		Hypothetical lump sum benefit at age 62		Lump sum benefit at age 65		Supplemental Payment
	Annuity Payable	$	30,000	$	30,000
	Lump Sum Conversion Factor	211.62		197.06
	Lump Sum Benefit	$	6,348,600	$	5,911,800		$436,800

17

WHEREAS, Marathon Petroleum Company LP (the “Company”), a subsidiary of Marathon Petroleum Corporation (the “Corporation”), wishes to amend and restate the Marathon Petroleum Excess Benefit Plan for the benefit of certain of its employees as set forth herein; and

NOW, THEREFORE, the Plan is hereby adopted by the Company, effective October 29, 2014.

IN WITNESS WHEREOF, the Company has directed the Senior Vice President, Human Resources and Administrative Services of the Corporation to execute this document on its behalf.

MARATHON PETROLEUM COMPANY LP

/s/ Signature on File    

By: Rodney P. Nichols

Its: Senior Vice President,

Human Resources and Administrative Services

18

EX-10.31

Exhibit 10.31

Marathon Petroleum
Annual Cash Bonus (“ACB”) Program

Effective January 1, 2015

Preamble

This program document explains the Annual Cash Bonus Program (the “Program”) of Marathon Petroleum Corporation.

The Program is a sub-plan of the Marathon Petroleum Corporation 2012 Incentive Compensation Plan (the “Plan”), and any successor shareholder-approved plan, which are hereby incorporated by reference. All Awards under the Program are granted pursuant to Section 7 of the Plan. Capitalized terms not specifically defined herein have the meanings specified in the Plan. In the event of any conflict between the Program and the Plan, the terms of the Plan shall control.

Program Objectives

The purpose of the Program is to motivate and reward Eligible Employees for achieving short-term (annual) business objectives that drive overall shareholder value while encouraging responsible risk taking and accountability.

Definitions

As used in the Program, the following terms shall have the meanings set forth below:

a. “Affiliate” means, with respect to any referenced person or entity, any other person controlling, controlled by, or under common control with such person.

b. “Award” means an award of an Incentive Stock Option, Nonqualified Stock Option, Stock Appreciation Right, Common Share, Restricted Stock, Restricted Stock Unit, or Cash granted to a Participant pursuant to the provisions of the Plan, any of which the Committee or its delegate may structure to qualify in whole or in part as a Performance Award.

c. “Board” means the Board of Directors of Marathon Petroleum Corporation.

d. “Change in Control” means a transaction of a nature that would be required to be reported in response to Item 6(e) of Schedule 14A of Regulation 14A promulgated under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), whether or not the Corporation is then subject to such reporting requirement; provided that, without limitation, such a Change in Control shall be deemed to have occurred if:

(i) any person (as such term is used in Sections 13(d) and 14(d) of the Exchange Act) (a “Person”) is or becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of securities of the Corporation (not including the amount of the securities beneficially owned

by such person, any such securities acquired directly from the Corporation or its Affiliates) representing twenty percent (20%) or more of the combined voting power of the Corporation’s then outstanding voting securities; provided, however, that for purposes of this Plan the term “Person” shall not include (A) the Corporation or any of its subsidiaries, (B) a trustee or other fiduciary holding securities under an employee benefit plan of the Corporation or any of its subsidiaries, (C) an underwriter temporarily holding securities pursuant to an offering of such securities, or (D) a corporation owned, directly or indirectly, by the stockholders of the Corporation in substantially the same proportions as their ownership of stock of the Corporation; and provided, further, however, that for purposes of this paragraph (i), there shall be excluded any Person(s) who become(s) such a beneficial owner in connection with an Excluded Transaction (as defined in paragraph (iii) below); or

(ii) the following individuals cease for any reason to constitute a majority of the number of directors then serving: individuals who, on the date hereof, constitute the Board and any new director (other than a director whose initial assumption of office is in connection with an actual or threatened election contest including, but not limited to, a consent solicitation, relating to the election of directors of the Corporation) whose appointment or election by the Board or nomination for election by the Corporation’s stockholders was approved or recommended by a vote of at least two-thirds (2/3) of the directors then still in office who either were directors on the date hereof or whose appointment, election or nomination for election was previously so approved or recommended; or

(iii) there is consummated a merger or consolidation of the Corporation or any direct or indirect subsidiary thereof with any other corporation, other than a merger or consolidation (an “Excluded Transaction”) which would result in the voting securities of the Corporation outstanding immediately prior thereto continuing to represent (either by remaining outstanding or by being converted into voting securities of the surviving corporation or any parent thereof) at least 50% of the combined voting power of the voting securities of the entity surviving the merger or consolidation (or the parent of such surviving entity) immediately after such merger or consolidation, or the shareholders of the Corporation approve a plan of complete liquidation of the Corporation; or there is consummated the sale or other disposition of all or substantially all of the Corporation’s assets; or

(iv) A Change in Control shall not be deemed to occur if the Company undergoes a bankruptcy, liquidation, or reorganization under the United States Bankruptcy Code.

e. “Code” means the Internal Revenue Code of 1986, as amended from time to time, and the rulings and regulations issued thereunder.

f. “Committee” means the Committee delegated by the Board with the authority to administer the Plan. To the extent the Committee has delegated authority to any person(s) or committee(s) pursuant to Section 6 of the Plan, a reference to the Committee herein may also include such person(s) or committee(s). However, in no event shall the Committee delegate its authority with respect to the compensation of any Participant whose compensation the Board or Committee reasonably believes may become subject to Section 162(m) of the Code.

g. “Company” means

• Blanchard Refining Company LLC,

• Catlettsburg Refining, LLC,

• Cincinnati Renewable Fuels LLC,

• Marathon Petroleum Company Canada, Ltd,

• Marathon Petroleum Company LP,

• Marathon Petroleum Corporation,

• Marathon Petroleum Services LLC,

• Marathon Petroleum Logistics Services LLC,

• Marathon Petroleum Service Company,

• Speedway LLC, and

• any other subsidiaries or controlled company of the above, as applicable.

All of the above entities are collectively referred to as “Company” or “Marathon Petroleum” for purposes of this document.

h. “Covered Employees" has the same meaning as defined in Section 162(m)(3) of the Code.

i. “Eligible Employees” means regular full-time and regular part-time Company employees who on the last day of the last pay period completed for the Performance Period are assigned to a salary grade within the Company salary structure. However, eligibility for employees of Speedway LLC and any of its subsidiaries is limited to those in salary grades 15 and above on the last day of the last pay period completed for the Performance Period. Eligible Employees may also include employees of other companies selected by the Committee and select employees of an approved Affiliate as approved by the Committee.

j. “Eligible Wages” for non-Officer employees include:

(i) actual base wages paid and compensation deferred during the Performance Period, and

(ii) overtime paid in the Performance Period. 

Eligible Wages for non-Officer employees exclude non-cash compensation, equity-based compensation, allowances, reimbursements, premiums and any bonus or recognition payments made. They also exclude wages paid or processed by a third party.

Eligible Wages for employees designated as Officers shall be equal to their annualized base salary in effect on the last day of the Performance Period. However, Eligible Wages for Officers who retire, are hired or who die during the Performance Period shall be equal to their actual base wages paid plus any compensation deferred during the Performance Period.

In the event of a Change in Control, Eligible Wages shall be the actual wages paid during the Performance Period, as of the date of Change in Control, for all employees.

k. “Performance Period” means any fiscal year or such other measurement period determined by the Committee or its delegate in their sole discretion.

l. “Qualifying Performance Criteria” shall mean any one or more of the following performance criteria that are in the Plan and were approved by shareholders (or other performance criteria approved by shareholders in the Plan), either individually, alternatively, or in any combination, applied to either the Company as a whole or to a business unit or Subsidiary or Affiliate, either individually, alternatively or in any combination, and measured either quarterly, annually, or cumulatively over a period of years, on an absolute basis or relative to a pre-established target, to previous years’ results or to a designated comparison group, in each case as specified by the Committee or its delegate: (i) revenue, (ii) income measures (which include revenue, gross margin, income from operations, net income, net sales, earnings per share, earnings before interest, depreciation, taxes, and amortization (“EBIDTA”), earnings before interest, taxes and amortization (“EBITA”) and earnings before interest and taxes (“EBIT), and economic value added, (iii) expense measures (which include costs of goods sold, selling, finding and development costs, general and administrative expenses, and overhead costs), (iv) operating measures (which include refinery throughput, mechanical availability, productivity, operating income, funds from operations, product quality, cash from operations, after-tax operating income, market share, margin, and sales volumes), (v) margins (which include crack-spread measures), (vi) refined product measures, (vii) cash management and cash flow measures (which include net cash flow from operating activities, working capital, receivables management and related customer terms), (vii) liquidity measures (which include earnings before or after the effect of certain

items such as interest, taxes, depreciation and amortization, improvement in or attainment of working capital levels, and free cash flow (viii) leverage measures (which include debt-to-equity ratio, debt reduction and net debt), (ix) market measures (which include market share, stock price, growth measure, total shareholders return, share price performance, return on equity, return on invested capital and return on assets, and market capitalization measures), (x) return measures (which include return on equity, return on assets, and return on invested capital), (xi) corporate value and sustainability measures (which include compliance, safety, environmental, and personnel matters), (xii) project completion measures (which may include measures regarding whether interim milestones regarding budgets and deadlines are met, as well as whether projects are completed on time and on or under budget), and (xii) other measures such as those relating to acquisitions, dispositions, or customer satisfaction.

Participants and Target Funding

Prior to March 30^th of the Performance Period, or at such later time as may be permitted by applicable provisions of the Code, the Committee shall establish in writing (1) the Eligible Employees who will be Participants in the Program, (2) each Participant's target funding percentage for such Performance Period or the formula for determining each Participant's Award and (3) the applicable performance objective or objectives for such Performance Period which will be based on the Qualifying Performance Criteria. Each Participant’s funding range will have a threshold of 0% and a maximum of two times (2X) their target funding percentage.

Threshold funding for individual metrics is one-half (.5X) of target and the maximum that can be funded is two times (2X) target. Percentages may be rounded. No metric will fund when results are below threshold performance.

Funding ranges for Participants shall be based on grade:

Participant Classification	Target	Award Range
Above Grade 18	Per the Committee	Per the Committee
Grade 18	50%	0% - 100%
Grade 17	40%	0% - 80%
Grade 16	35%	0% - 70%
Grade 15	30%	0% - 60%
Grade 14	25%	0% - 50%
Grade 13	20%	0% - 40%
Grade 12	15%	0% - 30%
Grade 11	12%	0% - 24%
Grade 10	12%	0% - 24%
Grade 9	10%	0% - 20%
Grade 8	10%	0% - 20%
Grade 7	7%	0% - 14%
Grade 6	7%	0% - 14%
Grade 5	7%	0% - 14%
Grade 4	7%	0% - 14%
Grade 3	7%	0% - 14%
Grade 2	7%	0% - 14%
Grade 1	7%	0% - 14%

Performance Metrics

The Committee, or its delegate, will establish metrics (in accordance with the Program), with threshold, target and maximum performance criteria. Once approved, these performance criteria are incorporated into this Program document by reference.

When any final performance metric result falls between threshold and target or between target and maximum performance levels, linear interpolation will be used to determine funding based on actual achievement. For example, if the final result of a metric is halfway between threshold and target performance levels, the funding for that metric would be halfway between the corresponding payout percentages.

Determination of Awards

Final calculated bonus payments are automatically rounded up to the nearest $50 for non-officer employees and to the nearest $1,000 for Officers.

Bonus Pool(s)

The Program for a Performance Period may consist of one or more umbrella performance pools. The Committee shall approve the structure of each such pool (if any) and designate the Participants in the pool, the total amount of the pool, and such Participant's allocable percentage share of such pool prior to March 30 of the Performance Period (or such later time as may be permitted by applicable provisions of the Code). To the extent a pool includes "Covered Employees" within the meaning of Section 162(m) of the Code, the pool shall be operated in compliance with the requirements of Section 162(m), which require that (1) each Participant's percentage share of the pool must be established no later than 90 days after the commencement of the applicable Performance Period, and (2) the exercise of negative discretion with respect to one Participant in the pool may not result in an increase in the amount payable to any Covered Employee who is a Participant in such pool.  Moreover, if the amount payable to each Participant in a pool that includes one or more Covered Employees is stated in terms of a percentage of the pool, the sum of the individual percentages of the pool may not exceed 100 percent.

The performance goals for any performance pools, to the extent they cover or potentially cover Covered Employees, will be based solely on Qualifying Performance Criteria. Satisfaction of these Criteria will enable a Participant to earn 100% of his or her allocated amount under such pools. The Committee may then take into account other criteria (whether or not Qualifying Performance Criteria) and use negative discretion to decrease a Participant's Award, but it may not use other criteria or positive discretion to increase the Award for any Covered Employee.

The same objective goals can be used both to set the amount of each performance pool and to function as the Qualifying Performance Criteria to determine if a bonus (and the amount of the bonus) was earned. The Committee shall establish a minimum threshold for the Qualifying Performance Criteria, below which no bonus will be earned.

Without regard to anything contained within this Program, the Committee reserves the unconditional right to award a payout to any Covered Employee up to the full value of their funding pool allocation without regard to the performance achieved under this operational program.

Individual Funding Vs. Payout

The operation of this Program funds individual payments based on pre-established metrics and subjective metrics as approved by the Committee. The final payout to each Participant is determined based on the assessment of their management considering each Participant’s relative performance to other employees. However, no Participant can be awarded more than their maximum percent as specified on page 6 without approval of the Committee or its delegate.

Hires, Promotions and Transfers

In the case of a newly hired, promoted, or transferred Participant, the Committee may provide for a guaranteed bonus, or a bonus that would exceed the bonus that would otherwise be payable in the Program unless the Participant is a Covered Employee, in which case no guarantees or excess payments would apply.

Participants who change from one eligible position to another during the Performance Period may experience a change to their Program target funding, individual objectives or the formula for determining each Participant’s Award. In this situation, funding shall be based on the associated target level and business unit for the position held by the Participant on the last day of the Performance Period, provided the position held is not temporary.

If a Participant transfers to a position that is not eligible under the Program during the Performance Period, such Participant will be ineligible for any payout under this Program for such Performance Period. Except however, if a Participant transfers to a Speedway position that is not eligible under the Program during the Performance Period, such Participant will remain eligible for an Award based on their Eligible Wages paid while a Participant under the Program.

Temporary Assignments

Eligibility and funding targets for employees who are on a temporary assignment on the last day of the last pay period completed for the Performance Period shall be determined based on their regular assignment.

Exclusions and Adjustments

To the extent consistent with Section 162(m) of the Code, the Committee or its delegate may (A) adjust the actual performance or performance goals (either up or down) and the level of the Performance Award that a Participant may earn under this program if it determines that the occurrence of external changes or other unanticipated business conditions have materially affected the fairness of the goals and / or have unduly influenced the Company’s ability to meet them; including, without limitation, events such as material acquisitions, asset write-downs, litigation, claims, judgments or settlements, force majeure events, unlawful acts committed against the Company or its property (including terrorism), labor disputes, legal mandates, accruals for reorganization and restructuring programs and changes in the capital structure of the Company, the effect of changes in tax law or other such laws or provisions affecting reported results, accruals of any amounts for payment under this Plan or any other compensation arrangement maintained by the Company, or other events not contemplated at the time the goals are set; provided, however, that Performance Awards granted to Covered Employees or Executive Officers shall be adjusted only to the extent permitted under Section 162(m) of the Code. In addition, Performance Goals and Performance Awards shall be calculated without regard to any changes in accounting standards or codifications that may be required by the Financial

Accounting Standards Board or other standards board or the effect of changes in tax law or other such laws or provisions affecting reported results after such Performance Goals are established.

Certification by Committee

Unless otherwise determined by the Committee, no payments shall be made hereunder in respect of any Performance Period unless the Committee shall certify in writing following the end of the Performance Period that the performance objectives applicable to the Performance Period have been satisfied. In all events, no payments hereunder shall be made to any "Covered Employee" (within the meaning of Section 162(m) of the Code) until after satisfaction of the performance criteria has been certified in writing by the Committee.

Separation of Employment

Unless otherwise determined by the Committee and except as may otherwise be provided in a Participant's written agreement with the Company or an Affiliate, if a Participant's employment terminates for any reason prior to payment, such Participant shall not be eligible for an Award under the Program, unless the Participant's employment terminated as a result of death, Severance, or Retirement (prior to July 1 of a Performance Period). Except in the case of death, an Award will be at the Committee's discretion, but any such payment of Award will (i) only be made after the end of the Performance Period (and as close as practicable to the same time as all other Award payments for such Performance Period), and (ii) only be paid to the extent that the performance criteria were achieved.

Any Participant who retires on or after July 1 of a Performance Period is eligible for an Award under this Program, based on their Eligible Wages paid during the Performance Period, at the discretion of the Committee. A Participant is considered to have Retired if the Participant, at the time of separation:

a. has reached the age 50 or more with 10 years of accredited service, and

b. is deemed to be in good standing.

Severance

Severance is defined to include any Participant who separates employment during a Performance Period and who becomes eligible for a termination allowance under the Company’s Termination Allowance Plan. However, any Participant who voluntarily requests termination under the Company’s Termination Allowance Plan is not considered to be an Eligible Employee under this Program.

In addition, Eligible Employees who would have otherwise been eligible for the Marathon Petroleum Termination Allowance Plan, but accepted an offer of employment with:

a. the “buyer” of sold Company assets, or

b. the “new operator” of a jointly-owned facility, or

c. a company that has been contracted to perform services being outsourced.

will remain eligible for consideration of an Award provided the termination date is after June 30^th of the Performance Period.

Death of Participant

If the death of a Participant occurs:

a. during a Performance Period, their eligibility for the Program will end and a payment will be made to the Participant’s estate as soon as practicable following death. Such payment will be based on target performance levels for all metrics and the Participant’s Eligible Wages paid during a Performance Period.

b. after a Performance Period, but before payment for that Performance Period has been made, the full Award otherwise deemed payable under the Program will be made to the Participant’s estate (as close to the time all other Award payments for such Performance Period are made).

Payment of Awards

Following the Performance Period, each Participant's Award for the Performance Period will be determined in accordance with the terms of the Program and the Participant shall be eligible to receive payment of the Award.

The Committee shall determine whether payment of the Award will be in cash, Common Shares, the right to receive Common Shares, Stock Options or other Awards provided for under the Plan; and whether any such payments will be subject to restrictions on transfer, vesting, forfeiture or deferral requirements. Any equity or equity-based Awards shall be granted under the terms and conditions of the Plan.

Change in Control

Unless otherwise determined by the Committee prior to a Change in Control, and except as otherwise may be provided in a Participant’s written agreement with the Company or Affiliate upon a Change in Control, this Program will automatically terminate and all Participants will be vested and entitled to a pro-rated lump sum payment equal to 100% of the Participant’s target multiplied by their Eligible Wages. This payment will be made as soon as administratively practicable following the Change in Control, but in no event later than 45 days from the Change in Control.

No Right to Awards

Except as may be provided for under the Change in Control section of this Program, no Participant or other person shall have any claim or right to be granted an Award under this Program. Neither the establishment of this Program, nor any action taken hereunder, shall be construed as giving any Participant any right to be retained in the employ of the Company, or participate hereunder in the current or succeeding Performance Periods. Nothing contained in this Program shall limit the ability of the Company to make payments or Awards to Participants under any other Program, agreement or arrangement; provided, however, that no payment under any other Program, agreement, or arrangement will be made because of a failure of a Participant to earn an Award hereunder, and no such payment outside of this Program will be in the nature of or in any way related to make-whole payments for what would have been earned or paid hereunder if the performance goals had been met.

Non-Transferability

The rights and benefits of a Participant hereunder are personal to the Participant and, except for any payments that may be made following a Participant's death, shall not be subject to any voluntary or involuntary alienation, assignment, pledge, transfer, encumbrance, attachment, garnishment or other disposition.

No Impact on Benefits

Except as may be required by law or otherwise be specifically stated under any employee benefit plan, policy, or program, no amount payable in respect of any Award shall be treated as compensation for purposes of calculating a Participant's right under any such plan, policy, or program; nor shall any Award be treated as compensation for purposes of termination indemnities or other similar rights, except as may be required by law.

No Constraint on Corporate Actions

Nothing in this Program shall be construed (1) to limit, impair, or otherwise affect the Company's right or power to make adjustments, reclassifications, reorganizations, or changes of its capital or business structure, or to merge or consolidate, or dissolve, liquidate, sell, or transfer all or any part of its business or assets, or (2) to limit the right or power of the Company or any of its Affiliates to take any action which such entity deems to be necessary or appropriate.

Program Administration

The program shall be administered by the Committee, which shall have full authority to:

a. interpret the Program,

b. establish, interpret, amend or revoke rules and regulations relating to the operation of the Program,

c. interpret the Program, to correct any defect, supply any omission or reconcile any inconsistency in the Program,

d. adopt such rules for the administration, interpretation and application of the Program, and

e. make all determination and take all other actions necessary or appropriate for the proper administration of the Program.

The Committee has complete, unilateral discretion with respect to all aspects of the operation, administration, design, features, benefits and Awards under the Program and can change, terminate, or modify Awards, or otherwise change any aspect of the Plan in its discretion prospectively or retroactively, regardless of anything stated in this document. Notwithstanding the above, with respect to a Covered Employee, the Committee cannot (1) grant or change an Award, or the Qualified Performance Criteria thereunder, after the deadline under Code Section 162(m) for setting such Award (generally March 30th of a Performance Period for annual Awards), (2) deem its performance goals satisfied when they have not been met, or (3) use its discretion to increase the amount otherwise payable under any Award.

The Committee may delegate any or all of their authorities hereunder, provided that the Committee shall, in no event, delegate its authority with respect to the compensation of any Participant whose compensation the Board or Committee reasonably believes may become subject to Section 162(m) of the Code. No member of the Committee shall be eligible to participate in the Program.

Taxes

For U.S. Participants, any Award received under the Program is subject to all applicable employment withholding taxes in the year paid. For Participants outside the United States, local country tax regulations will apply.

Deductions

There shall be deducted from all individual payouts any taxes required to be withheld by national, Federal, state provincial or local governments and paid over to such government for the accounts of such Participants.

The Company may also deduct from an individual Award, at its sole discretion, any and all amounts determined by Company management to be owed to the Company by the Participant.

Affiliate Requirements

Prior to the selection of employees of an affiliated company to participate in the Program, the Committee may require the Affiliate to consent to the participation of such employee or employees in the Program and to the charging of such Affiliate with the amount of any Award which may be made to such employee or employees.

Recoupment / Clawback

Officers are subject to recoupment provisions in the Program, in the case of certain forfeiture events. If the Company is required, pursuant to a determination made by the SEC or the Audit Committee of the Board, to prepare a material accounting restatement due to the noncompliance of the Company with any financial reporting requirement under applicable securities laws as a result of misconduct, the Audit Committee of the Board may determine that a forfeiture event has occurred based on an assessment of whether an officer knowingly engaged in misconduct, was grossly negligent with respect to misconduct, knowingly failed or was grossly negligent in failing to prevent misconduct or engaged in fraud, embezzlement, or other similar misconduct materially detrimental to the Company.

Upon the Audit Committee’s determination that forfeiture event has occurred, the Company has the right to request and receive reimbursement of any portion of an officer’s bonus from the Program that would not have been earned or paid had the forfeiture event not have taken place.

These recoupment provisions are in addition to the requirements in Section 304 of the Sarbanes-Oxley Act of 2002 which provide that the CEO and CFO shall reimburse the Company for any bonus or other incentive-based or equity-based compensation as well as any related profits received in the 12-month period prior to the filing of an accounting restatement due to non-compliance with financial reporting requirements as a result of Company misconduct.

Notwithstanding the foregoing or any other provision of this Program to the contrary, the Company may also require that the Participant repay to the Company any compensation paid to the Participant under this Program, as is required by the provisions of the Dodd-Frank Act and the regulations thereunder or any other “clawback” provisions as required by law or by the applicable listing standards of the exchange on which the Corporation’s common stock is listed for trading.

Other Provisions

In all events, whether any cash Award is paid to a Participant will depend on the decision of the Committee (or its delegate, as appropriate). All Awards are subject to the sole discretion of the Committee or its delegate, and nothing in this document (except as may be provided for in the Change in Control provisions) or any other document describing or referring to the Program shall confer any right whatsoever on any person to be considered for any Award.

This document does not purport to be complete and is subject to and governed by actions, rules and regulations of the Committee (or its delegate, as appropriate).

The Program may be changed or discontinued at any time without notice or liability at the sole discretion of the Committee.

Awards shall be subject to and governed by the specific terms and conditions of the Program and the applicable Award.

Nothing contained herein shall require the Company to segregate any monies from its general fund or to create any trusts, or to make any special deposits for amounts payable to any Participant.

The Program is intended to be operated in accordance with the requirements of Section 162(m) of the Code where applicable, and shall be interpreted consistent with that intent.

No member of the Committee, or employee of the Company, shall be liable for any act done, or determination made in good faith, with respect to the administration of this Program. The Company indemnifies and holds harmless to the fullest extend allowed by law such persons individually and collectively, from and against any and all losses resulting from liability to which the Committee, or the members of the Committee, or employee of the Company may be subjected by reason of any act or conduct (except willful misconduct, fraud or gross negligence) in their official capacities in the administration of the Program, including all expenses reasonably incurred in their defense, in case the Company fails to provide such defense.

Any provision of the Program prohibited by law shall be ineffective to the extent of such prohibition without invalidating the remaining provisions.

The terms of this Program document supersede any written or verbal agreements, representations, proposals, or plans with respect to the subject matter hereof; provided, however, that the forgoing shall not act to supersede an existing written agreement between a Participant and the Company that has been approved by the Committee.

MARATHON PETROLEUM CORPORATION

/s/ Signature on File    

By: Rodney P. Nichols

Its: Senior Vice President,

Human Resources and Administrative Services

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,
	2014		2013		2012		2011		2010
Portion of rentals representing interest	$	85	$	71	$	46	$	41	$	45
Capitalized interest	27		28		101		112		83
Other interest and fixed charges	201		167		90		60		1
Total fixed charges (A)	$	313	$	266	$	237	$	213	$	129
Earnings-pretax income with applicable adjustments (B)	$	4,194	$	3,518	$	5,423	$	3,848	$	1,063
Ratio of (B) to (A)	13.4		13.2		22.9		18.1		8.2

EX-21.1

Exhibit 21.1

MARATHON PETROLEUM CORPORATION

LIST OF SUBSIDIARIES

as of December 31, 2014

	Name of Subsidiary	Jurisdiction of Organization/Incorporation
*	Ascension Pipeline Company, LLC	Delaware
	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
	Cincinnati BioRefining Corp.	Delaware
	Cincinnati Renewable Fuels LLC	Delaware
*	Enchi Corporation	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
	Hardin Street Marine LLC	Delaware
	Hardin Street Terminals LLC	Delaware
	Hardin Street Transportation LLC	Delaware
	Hess Express of Virginia, LLC	Virginia
	Hess Mart of Massachusetts, LLC	Massachusetts
	Hess Mart of Virginia, LLC	Virginia
	Hess Realty LLC	Delaware
	Hess Retail Holdings LLC	Delaware
	Hess Retail Operations LLC	Delaware
	Hess Retail Services, Inc.	New Hampshire
	Hess Retail Stores LLC	Delaware
	Hess Wilco Holdings, LLC	Delaware
*	Illinois Extension Pipeline Company, L.L.C.	Delaware
*	Johnston County Terminal, LLC	Delaware
	Lincoln Pipeline 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 Supply LLC	Delaware
	Merit Oil of Connecticut, Inc.	Connecticut
	Merit Oil of Delaware L.P.	Delaware
	Merit Oil of Delaware, Inc.	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
	Wilco Food Services LLC	Delaware
	Wilco Transportation LLC	Delaware
	WilcoHess LLC	Delaware
	Williston Basin Pipe Line LLC	Delaware
*	WIP, LLC	Indiana
*	Wolverine Pipe Line Company	Delaware
	Woodhaven Cavern LLC	Delaware

* Indicates a company that is not wholly owned directly or indirectly by Marathon Petroleum Corporation

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on FormS-3 (No. 333-197130, 333-197128, and 333-197126) and Form S-8 (No. 333-181007, 333-175245 and 333-175244) of Marathon Petroleum Corporation of our reportdated February 27, 2015 relating to the financial statementsand the effectiveness of internal control over financial reporting, which appears in this Form 10‑K.

/s/PricewaterhouseCoopers LLP

Toledo, Ohio

February 27, 2015

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 John J. Quaid, 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, 2014 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 27th day of February, 2015.

/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/ John J. Quaid	/s/ Evan Bayh
John J. Quaid	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 27, 2015	/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 27, 2015	/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, 2014 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 27, 2015

/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, 2014 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 27, 2015

/s/ Donald C. Templin

Donald C. Templin

Senior Vice President and Chief Financial Officer

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Summary Of Principal Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2014

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 71.5 percent controlling financial interest, and we record a noncontrolling interest for the 28.5 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, 2014 and 2013, the amount of restricted cash included in other current assets on the consolidated balance sheets were $4 million and $7 million, respectively.

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 41 percent and 38 percent of our accounts receivable balances at December 31, 2014 and 2013, 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. Costs for crude oil and refined product inventories are aggregated on a consolidated basis for purposes of assessing if the LIFO cost basis of these inventories may have to be written down to market value.

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.

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 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.

Stock-based compensation arrangements

Stock-based compensation arrangements – The fair value of stock options 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 50 percent of our common stock implied volatility and 50 percent of MPC’s common stock historical volatility.

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. 

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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Defined Benefit Pension And Other Postretirement Plans (Multi Employer Pension Plan) (Detail) (Multiemployer Plans, Pension, USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Multiemployer Plans [Line Items]
Multiemployer pension plan, minimum contribution requirement per week per employee	$ 280
Number of employees participated in the plan	267
Central States, Southeast and Southwest Pension Plan [Member]
Multiemployer Plans [Line Items]
MPC contributions	$ 4,000,000	[1]	$ 3,000,000	[1]	$ 4,000,000	[1]

[1] This agreement has a minimum contribution requirement of $280 per week per employee for 2015. A total of 267 employees participated in the plan as of December 31, 2014.

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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, 2014		Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash collateral netted with derivative assets	$ 78
Cash collateral netted with derivative liabilities			32
Contingent consideration, current	174		159
Fair Value, Measurements, Recurring
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets - collateral and netting	(258)	[1]	(21)	[1]
Commodity derivative instruments, assets - net	59	[2]	0	[2]
Commodity derivative instruments, assets - collateral pledged not offset	0		61
Other assets	2		2
Total assets at fair value	61		2
Commodity derivative instruments, liabilities - netting and collateral	(180)	[1]	(53)	[1]
Commodity derivative instruments, liabilities - net	0	[2]	0	[2]
Commodity derivative instruments, liabilities - collateral pledged not offset	0		0
Contingent consideration, liability	478	[3]	625	[3]
Total liabilities at fair value	478		625
Level 1 | Fair Value, Measurements, Recurring
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets - gross	317		21
Other assets	2		2
Total assets at fair value	319		23
Commodity derivative instruments, liabilities - gross	180		53
Contingent consideration, liability	0		0
Total liabilities at fair value	180		53
Level 2 | Fair Value, Measurements, Recurring
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets - gross	0		0
Other assets	0		0
Total assets at fair value	0		0
Commodity derivative instruments, liabilities - gross	0		0
Contingent consideration, liability	0		0
Total liabilities at fair value	0		0
Level 3 | Fair Value, Measurements, Recurring
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets - gross	0		0
Other assets	0		0
Total assets at fair value	0		0
Commodity derivative instruments, liabilities - gross	0		0
Contingent consideration, liability	478	[3]	625	[3]
Total liabilities at fair value	$ 478		$ 625

[1] Represents the impact of netting assets, liabilities and cash collateral when a legal right of offset exists. As of December 31, 2014, cash collateral of $78 million was netted with mark-to-market derivative assets. As of December 31, 2013, cash collateral of $32 million was netted with mark-to-market derivative liabilities.

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

[3] Includes $174 million at December 31, 2014 and $159 million at December 31, 2013 classified as current.

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2014

Supplemental Cash Flow Information [Abstract]

Summary of Supplemental Cash Flow Information

(In millions)	2014		2013		2012
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	166	$	161	$	67
Net income taxes paid to taxing authorities(a)	1,362		1,099		1,211
Non-cash investing and financing activities:
Capital lease obligations increase	$	—	$	61	$	62
Property, plant and equipment sold	4		43		—
Property, plant and equipment acquired	4		—		—
Preferred equity interest received in contract settlement(b)	—		—		45
Preferred equity interest dividend received in-kind	—		—		1
Acquisition:
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 26.

^(b)  See Note 6.

^(c)  See Note 5.

Schedule Of Reconciliation Of Additions To Property Plant And Equipment To Total Capital Expenditures

The consolidated statements of cash flows exclude changes to the consolidated balance sheets that did not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures:

(In millions)	2014		2013		2012
Additions to property, plant and equipment per consolidated statements of cash flows	$	1,480	$	1,206	$	1,369
Non-cash additions to property, plant and equipment	4		—		—
Asset retirement expenditures(a)	2		—		—
Increase (decrease) in capital accruals	95		73		(117		)
Total capital expenditures before acquisitions	1,581		1,279		1,252
Acquisitions(b)	2,744		1,386		180
Total capital expenditures	$	4,325	$	2,665	$	1,432

^(a)  Included in All other, net – Operating activities on the consolidated statements of cash flows.

^(a)  The 2014 acquisitions include the acquisition of Hess’ Retail Operations and Related Assets. The 2013 acquisitions include the acquisition of the Galveston Bay Refinery and Related Assets. The acquisition numbers above include property, plant and equipment and intangibles. See Note 5.

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Leases (Schedule Of Operating Lease Rental Expense) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Leases [Abstract]
Rental expense	$ 256	$ 213	$ 139

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Equity Method Investments (Tables)

12 Months Ended

Dec. 31, 2014

Equity Method Investments and Joint Ventures [Abstract]

Schedule Of Equity Method Investments

	Ownership as of	Carrying value at
	December 31,	December 31,
(In millions)	2014	2014		2013
Centennial	50%	$	36	$	29
Explorer	25%	95		—
Illinois Extension Pipeline	35%	120		—
LOCAP	59%	23		24
LOOP	51%	230		214
North Dakota Pipeline(a)	38%	216		24
TAAE	43%	22		29
TACE	60%	61		70
TAEI	34%	19		23
TAME(b)	50%	24		35
Other		19		15
Total		$	865	$	463

^(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, which is expected to be in 2017.

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

Summarized Financial Information For Equity Method Investees

Summarized financial information for equity method investees is as follows:

(In millions)	2014		2013		2012
Income statement data:
Revenues and other income	$	1,430	$	1,067	$	1,025
Income from operations	379		87		73
Net income	316		63		47
Balance sheet data – December 31:
Current assets	$	990	$	339
Noncurrent assets	2,166		1,238
Current liabilities	280		145
Noncurrent liabilities	957		618

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Derivatives (Effect Of Commodity Derivative Instruments In Statements Of Income) (Detail) (Commodity derivatives, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ 493	$ (168)	$ 73
Sales and other operating revenues
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	37	12	8
Cost of revenues
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ 456	$ (180)	$ 65

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Acquisitions and Investments (Schedule of Assets Acquired and Liabilities Assumed - Galveston Bay) (Details) (Galveston Bay Refinery and Related Assets, USD $) In Millions, unless otherwise specified	Feb. 01, 2013
Galveston Bay Refinery and Related Assets
Business Acquisition [Line Items]
Inventories	$ 935
Other current assets	1
Property, plant and equipment, net	1,274
Other noncurrent assets	88
Total assets acquired	2,298
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 liabilities assumed	210
Net assets acquired excluding goodwill	$ 2,088

[1] Represents a capital lease obligation assumed.

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MPC Revolving Credit Agreement (Detail) (USD $) In Millions, unless otherwise specified	0 Months Ended		12 Months Ended
	Sep. 14, 2012	Nov. 21, 2014	Dec. 31, 2014	Nov. 20, 2014 Period
MPC Revolver
Line of Credit Facility [Line Items]
Line of credit facility, current borrowing capacity	$ 2,500
Number of renewal periods	2
Line of credit facility duration of renewal period	1 year
MPC Revolver | Letter of Credit
Line of Credit Facility [Line Items]
Letters of credit outstanding			0
MPC Revolver | Maximum
Line of Credit Facility [Line Items]
Line of credit facility additional borrowing capacity	500
Ratio of indebtedness to net capital	0.65
MPC Revolver | Maximum | Bridge Loan
Line of Credit Facility [Line Items]
Line of credit facility, current borrowing capacity	100
MPC Revolver | Maximum | Letter of Credit
Line of Credit Facility [Line Items]
Line of credit facility, current borrowing capacity	2,000
MPC Revolver | Minimum
Line of Credit Facility [Line Items]
Lender holding percentage of outstanding commitments needed to approve increase in borrowing capacity	50.00%
MPLX LP | MPLX Term Loan
Line of Credit Facility [Line Items]
Number of renewal periods				2
Line of credit facility duration of renewal period		1 year
MPLX LP | MPLX Revolver
Line of Credit Facility [Line Items]
Line of credit facility, current borrowing capacity				1,000
Number of renewal periods				2
Line of credit facility duration of renewal period		1 year
MPLX LP | MPLX Revolver | Letter of Credit
Line of Credit Facility [Line Items]
Letters of credit outstanding			0
MPLX LP | MPLX Revolver | Maximum
Line of Credit Facility [Line Items]
Line of credit facility additional borrowing capacity				500
MPLX LP | MPLX Revolver | Maximum | Bridge Loan
Line of Credit Facility [Line Items]
Line of credit facility, current borrowing capacity				100
MPLX LP | MPLX Revolver | Maximum | Letter of Credit
Line of Credit Facility [Line Items]
Line of credit facility, current borrowing capacity				250
MPLX LP | Unsecured Debt | MPLX Term Loan
Line of Credit Facility [Line Items]
Line of credit facility, expiration date			Dec. 20, 2019
MPLX Operations LLC | MPLX Revolver | Maximum
Line of Credit Facility [Line Items]
Line of credit facility, current borrowing capacity	$ 500
MPLX Operations LLC | Unsecured Debt | MPLX Revolver
Line of Credit Facility [Line Items]
Line of credit facility, expiration date			Oct. 31, 2017

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Accumulated Other Comprehensive Loss (Tables)

12 Months Ended

Dec. 31, 2014

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 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 effect	(43		)	—			—		—			(43		)
Other comprehensive income (loss)	271			(14		)	—		3			260
Balance as of December 31, 2013	$	(161	)	$	(50	)	$	4	$	3		$	(204	)

(In millions)	Pension Benefits			Other Benefits			Gain on Cash Flow Hedge		Workers Compensation			Total
Balance as of December 31, 2013	$	(161	)	$	(50	)	$	4	$	3		$	(204	)
Other comprehensive income (loss) before reclassifications	(119		)	(53		)	—		2			(170		)
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit(a)	(46		)	(4		)	—		—			(50		)
– actuarial loss(a)	51			2			—		—			53
– settlement loss(a)	96			—			—		—			96
Other(b)	—			—			—		(1		)	(1		)
Tax effect	(38		)	1			—		—			(37		)
Other comprehensive income (loss)	(56		)	(54		)	—		1			(109		)
Balance as of December 31, 2014	$	(217	)	$	(104	)	$	4	$	4		$	(313	)

^(a)  These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 23.

^(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 (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Centennial
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	50.00%
Operating pipeline revenue from related parties included in other income	$ 1	$ 1	$ 1
Long-term receivable from related party	$ 1	$ 2
Explorer
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	25.00%
LOCAP
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	59.00%
LOOP
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	51.00%
TAAE
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	43.00%
TACE
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	60.00%
TAME
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	67.00%

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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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Quarterly Financial Data [Abstract]
Revenues	$ 22,250	$ 25,438	$ 26,844	$ 23,285	$ 24,897	$ 26,256	$ 25,677	$ 23,330
Income from operations	1,259	1,062	1,369	361	1,008	301	960	1,156	4,051	3,425	5,347
Net income	805	679	864	207	631	173	599	730	2,555	2,133	3,393
Net income attributable to MPC	$ 798	$ 672	$ 855	$ 199	$ 626	$ 168	$ 593	$ 725	$ 2,524	$ 2,112	$ 3,389
Net income attributable to MPC per share:
Basic (in USD per share)	$ 2.88	$ 2.38	$ 2.97	$ 0.68	$ 2.09	$ 0.54	$ 1.84	$ 2.19	$ 8.84	$ 6.69	$ 9.95
Diluted (in USD per share)	$ 2.86	$ 2.36	$ 2.95	$ 0.67	$ 2.07	$ 0.54	$ 1.83	$ 2.17	$ 8.78	$ 6.64	$ 9.89
Dividends paid per share (in USD per share)	$ 0.50	$ 0.50	$ 0.42	$ 0.42	$ 0.42	$ 0.42	$ 0.35	$ 0.35	$ 1.84	$ 1.54	$ 1.20

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Inventories (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Inventory Disclosure [Abstract]
Total inventory LIFO percentage	94.00%	90.00%
Excess of current acquisition costs over stated LIFO value	$ 684	$ 4,084
Impact on revenues and costs as a result of LIFO liquidations	$ 0	$ 0	$ 0

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Components Of Income Tax Provisions (Benefits)

Income tax provisions (benefits) were:

	2014								2013							2012
(In millions)	Current		Deferred			Total			Current		Deferred			Total		Current			Deferred		Total
Federal	$	1,382	$	(199	)	$	1,183		$	954	$	20		$	974	$	1,185		$	432	$	1,617
State and local	135		(37		)	98			131		8			139		169			57		226
Foreign	5		(6		)	(1		)	5		(5		)	—		(1		)	3		2
Total	$	1,522	$	(242	)	$	1,280		$	1,090	$	23		$	1,113	$	1,353		$	492	$	1,845

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:

	2014		2013		2012
Statutory rate applied to income before income taxes	35	%	35	%	35	%
State and local income taxes, net of federal income tax effects	2		3		2
Domestic manufacturing deduction	(2	)	(2	)	(1	)
Other	(2	)	(2	)	(1	)
Provision for income taxes	33	%	34	%	35	%

Components Of Deferred Tax Assets And Liabilities

Deferred tax assets and liabilities resulted from the following:

	December 31,
(In millions)	2014		2013
Deferred tax assets:
Employee benefits	$	616	$	483
Environmental	54		37
Investments in subsidiaries and affiliates	24		—
Other	70		49
Total deferred tax assets	764		569
Deferred tax liabilities:
Property, plant and equipment	2,411		2,290
Inventories	614		614
Investments in subsidiaries and affiliates	—		267
Other	101		70
Total deferred tax liabilities	3,126		3,241
Net deferred tax liabilities	$	2,362	$	2,672

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)	2014		2013
Assets:
Other noncurrent assets	$	7	$	2
Liabilities:
Accrued taxes	355		370
Deferred income taxes	2,014		2,304
Net deferred tax liabilities	$	2,362	$	2,672

Summary Of Income Tax Returns Subject To Examination

As of December 31, 2014, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:

United States Federal	2010	-	2013
States	2004	-	2013

Summary Of Activity In Unrecognized Tax Benefits

The following table summarizes the activity in unrecognized tax benefits:

(In millions)	2014			2013			2012
January 1 balance	$	13		$	40		$	20
Additions for tax positions of prior years	7			30			32
Reductions for tax positions of prior years	(10		)	(25		)	(6		)
Settlements	2			(30		)	(6		)
Statute of limitations	—			(2		)	—
December 31 balance	$	12		$	13		$	40

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Stock-Based Compensation Plans

12 Months Ended

Dec. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [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 and non-employee directors. 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 April 26, 2012, our employees and non-employee directors were eligible to receive equity awards under the Marathon Petroleum Corporation 2011 Second Amended and Restated Incentive Compensation Plan (“MPC 2011 Plan”).

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. All of the stock options granted in 2014 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”) – SARs were granted under the Marathon Oil Corporation incentive compensation plan in effect prior to the Spinoff. No SARs have been granted under 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 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. All outstanding SAR’s expired or were exercised in 2014.

Restricted Stock and Restricted Stock Units – We grant restricted stock and restricted stock units to employees and non-employee directors. 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 equal to the market price 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 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 total shareholder return (“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 an average of 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 recorded at fair value with a mark-to-market adjustment made each quarter. The performance units that settle in shares are accounted for as equity awards.

Total Stock-Based Compensation Expense

The following table reflects activity related to our stock-based compensation arrangements:

(In millions)	2014		2013		2012
Stock-based compensation expense	$	40	$	42	$	35
Tax benefit recognized on stock-based compensation expense	15		15		13
Cash received by MPC upon exercise of stock option awards	26		48		108
Tax benefit received for tax deductions for stock awards exercised	19		18		16

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:

	2014			2013			2012
Weighted average exercise price per share	$	85.02		$	84.65		$	42.02
Expected life in years	5.8			6.0			5.8
Expected volatility	36		%	40		%	47		%
Expected dividend yield	1.9		%	2.0		%	2.6		%
Risk-free interest rate	1.8		%	1.0		%	1.1		%
Weighted average grant date fair value of stock option awards granted	$	25.37		$	27.13		$	14.45

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 2014 assumption for expected volatility of our stock price reflects a weighting of 50 percent of our common stock implied volatility and 50 percent of MPC’s common stock historical volatility. Prior to 2014, we used a weighting of our common stock implied volatility and the historical volatility of a selected group of peers. Expected dividend yield is based on annualized dividends at the date of grant. 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 2014:

	Number of of Shares(a)		Weighted Average Exercise Price		Weighted Average Remaining Contractual Terms (in years)	Aggregate Intrinsic Value (in millions)
Outstanding at December 31, 2013	5,147,837		$	40.08
Granted	446,310		85.02
Exercised	(821,948	)	33.04
Forfeited, canceled or expired	(20,761	)	49.67
Outstanding at December 31, 2014	4,751,438		45.47
Vested and expected to vest at December 31, 2014	4,746,653		45.43		5.7	$	213
Exercisable at December 31, 2014	3,795,031		38.30		5.0	197

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

The intrinsic value of options exercised by MPC employees during 2014, 2013 and 2012 was $48 million, $60 million and $37 million, respectively.

As of December 31, 2014, unrecognized compensation cost related to stock option awards was $5 million, which is expected to be recognized over a weighted average period of 1.1 years.

Restricted Stock Awards

The following is a summary of restricted stock award activity of our common stock in 2014:

	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, 2013	624,122		$	61.11	385,079		$	33.96
Granted	251,351		87.64		26,725		85.90
RS’s Vested/RSU’s Issued	(330,971	)	55.36		(578	)	51.99
Forfeited	(29,429	)	70.29		(133	)	76.10
Outstanding at December 31, 2014	515,073		77.23		411,093		37.30

Of the 411,093 restricted stock units outstanding, 409,805 are vested and have a weighted average grant date fair value of $37.16. 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:

	Restricted Stock				Restricted Stock Units
	Intrinsic Value of Awards Vested During the Period (in millions)		Weighted Average Grant Date Fair Value of Awards Granted During the Period		Intrinsic Value of Awards Vested During the Period (in millions)		Weighted Average Grant Date Fair Value of Awards Granted During the Period
2014	$	28	$	87.64	$	—	$	85.90
2013	20		87.06		—		73.48
2012	5		43.11		—		44.38

As of December 31, 2014, unrecognized compensation cost related to restricted stock awards was $26 million, which is expected to be recognized over a weighted average period of 1.1 years. There was no material unrecognized compensation cost related to restricted stock unit awards.

Performance Unit Awards

The following table presents a summary of the 2014 activity for performance unit awards to be settled in shares:

	Number of Units		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2013	3,822,500		$	0.90
Granted	2,033,700		0.85
Canceled	(64,375	)	0.87
Outstanding at December 31, 2014	5,791,825		0.88

The number of shares that would be issued upon target vesting, using the closing price of our common stock on December 31, 2014 would be 64,168 shares.

As of December 31, 2014, unrecognized compensation cost related to equity-classified performance unit awards was $2 million, which is expected to be recognized over a weighted average period of 1.5 years.

Performance units paying out in units have a grant date fair value calculated using a Monte Carlo valuation model, which requires the input of subjective assumptions. The following table provides a summary of these assumptions:

	2014			2013			2012
Risk-free interest rate	0.63		%	0.35		%	0.41		%
Look-back period	2.84 years			2.84 years			2.84 years
Expected volatility	38.51		%	41.67		%	56.06		%
Grant date fair value of performance units granted	$	0.85		$	0.95		$	0.80

The risk-free interest rate for the remaining performance period as of the grant date is based on the U.S. Treasury yield curve in effect at the time of the grant. The look-back period reflects the remaining performance period at the grant date. The assumption for the expected volatility of our stock price reflects the average MPC common stock historical volatility.

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, 2014, 2013 and 2012.

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Related Party Transactions (Sales To Related Parties) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Sales to related parties	$ 7	$ 8	$ 8
Centennial
Related Party Transaction [Line Items]
Sales to related parties	0	0	1
Other equity method investees
Related Party Transaction [Line Items]
Sales to related parties	$ 7	$ 8	$ 7

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Derivatives (Narrative) (Detail) (USD $)
In Millions, unless otherwise specified

12 Months Ended

Dec. 31, 2012

Notes Payable And Other Payables | 3.500% senior notes due March 1, 2016

Derivative [Line Items]

Debt instrument, interest rate (in percentage)

3.50%

Maturity period of senior notes

March 2016

Interest Rate Swap

Derivative [Line Items]

Notional amount of interest rate swap agreements

500

Hedge agreements

3.50 percent senior notes due in March 2016

Deferred gain on discontinuation of interest rate fair value hedge

20

Hedge ineffectiveness of interest rate swaps

0

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Debt MPLX Credit Agreement (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended	12 Months Ended	0 Months Ended
	Nov. 21, 2014	Dec. 31, 2014	Sep. 14, 2012	Nov. 20, 2014 Period	Dec. 31, 2013
MPLX LP | MPLX Term Loan
Debt Instrument [Line Items]
Debt instrument, term	5 years
Line of credit facility, maximum borrowing capacity				$ 250
Number of renewal periods				2
Line of credit facility duration of renewal period	1 year
Line of credit facility, interest rate during period		1.40%
Debt instrument, description of variable rate basis	Adjusted LIBO Rate or the Alternate Base Rate (as defined in the MPLX Credit Agreement)
MPLX LP | MPLX Revolver
Debt Instrument [Line Items]
Debt instrument, term	5 years
Line of credit facility, current borrowing capacity				1,000
Number of renewal periods				2
Line of credit facility duration of renewal period	1 year
Line of credit facility, interest rate during period		1.40%
Debt instrument, description of variable rate basis	Adjusted LIBO Rate or the Alternate Base Rate (as defined in the MPLX Credit Agreement)
Line of credit facility, borrowings during period		630
Line of credit facility, repayments during period		245
Remaining borrowing capacity		615
Remaining borrowing capacity, percentage		61.50%
MPLX LP | Line of Credit | MPLX Revolver
Debt Instrument [Line Items]
Long-term debt, gross		385			0
MPLX LP | Maximum | MPLX Term Loan
Debt Instrument [Line Items]
Number of prior quarterly reporting periods covenant				4
Covenant ratio debt to EBITDA				5.0
Covenant ratio debt to EBITDA post acquisition				5.5
MPLX LP | Maximum | MPLX Revolver
Debt Instrument [Line Items]
Line of credit facility additional borrowing capacity				500
Number of prior quarterly reporting periods covenant				4
Covenant ratio debt to EBITDA				5.0
Covenant ratio debt to EBITDA post acquisition				5.5
MPLX LP | Letter of Credit | MPLX Revolver
Debt Instrument [Line Items]
Letters of credit outstanding		0
MPLX LP | Letter of Credit | Maximum | MPLX Revolver
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity				250
MPLX LP | Bridge Loan | Maximum | MPLX Revolver
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity				100
MPLX Operations LLC | MPLX Revolver
Debt Instrument [Line Items]
Debt instrument, term			5 years
Line of credit facility, interest rate during period		1.50%
Line of credit facility, borrowings during period		280
MPLX Operations LLC | Line of Credit | MPLX Revolver
Debt Instrument [Line Items]
Line of credit facility, repayments during period		280
Long-term debt, gross		0			0
MPLX Operations LLC | Maximum | MPLX Revolver
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity			500

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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, 2014	Dec. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Projected benefit obligations	$ 2,075	$ 1,927
Accumulated benefit obligations	2,009	1,912
Fair value of plan assets	$ 1,744	$ 1,800

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Acquisitions and Investments (Acquisition of Biodiesel Facility) (Details) (Felda Iffco Sdn Bhd, USD $) In Millions, unless otherwise specified	1 Months Ended
	Apr. 30, 2014	Apr. 01, 2014 gallons_per_year
Felda Iffco Sdn Bhd
Business Acquisition [Line Items]
Cash paid for acquisition	$ 40
Plant capacity volume		60,000,000

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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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income from operations	$ 1,259	$ 1,062	$ 1,369	$ 361	$ 1,008	$ 301	$ 960	$ 1,156	$ 4,051		$ 3,425		$ 5,347
Minnesota Assets sale settlement gain									21		6		177
Net interest and other financial income (costs)									216		179		109
Income before income taxes									3,835		3,246		5,238
Operating Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income from operations									4,433	[1]	3,791	[1]	5,624	[1]
Corporate and Other
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income from operations									(286)	[2],[3]	(271)	[2],[3]	(336)	[2],[3]
Segment Reconciling Items
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Minnesota Assets sale settlement gain									0	[4]	0	[4]	183	[4]
Pension settlement expenses									$ (96)	[5]	$ (95)	[5]	$ (124)	[5]

[1] Included in the Pipeline Transportation segment for 2014, 2013 and 2012 are $19 million, $20 million and $4 million of corporate overhead expenses attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. Corporate overhead expenses are not currently allocated to other segments.

[2] Corporate and other unallocated items consists primarily of MPC’s corporate administrative expenses and costs related to certain non-operating assets.

[3] Corporate overhead expenses attributable to MPLX were included in the Pipeline Transportation segment subsequent to MPLX’s October 31, 2012 initial public offering. Corporate overhead expenses are not allocated to the Refining & Marketing and Speedway segments.

[4] See Note 6.

[5] See Note 23.

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Stock-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award

The following table reflects activity related to our stock-based compensation arrangements:

(In millions)	2014		2013		2012
Stock-based compensation expense	$	40	$	42	$	35
Tax benefit recognized on stock-based compensation expense	15		15		13
Cash received by MPC upon exercise of stock option awards	26		48		108
Tax benefit received for tax deductions for stock awards exercised	19		18		16

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:

	2014			2013			2012
Weighted average exercise price per share	$	85.02		$	84.65		$	42.02
Expected life in years	5.8			6.0			5.8
Expected volatility	36		%	40		%	47		%
Expected dividend yield	1.9		%	2.0		%	2.6		%
Risk-free interest rate	1.8		%	1.0		%	1.1		%
Weighted average grant date fair value of stock option awards granted	$	25.37		$	27.13		$	14.45

Summary of Stock Option Award Activity

The following is a summary of our common stock option activity in 2014:

	Number of of Shares(a)		Weighted Average Exercise Price		Weighted Average Remaining Contractual Terms (in years)	Aggregate Intrinsic Value (in millions)
Outstanding at December 31, 2013	5,147,837		$	40.08
Granted	446,310		85.02
Exercised	(821,948	)	33.04
Forfeited, canceled or expired	(20,761	)	49.67
Outstanding at December 31, 2014	4,751,438		45.47
Vested and expected to vest at December 31, 2014	4,746,653		45.43		5.7	$	213
Exercisable at December 31, 2014	3,795,031		38.30		5.0	197

^(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 2014:

	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, 2013	624,122		$	61.11	385,079		$	33.96
Granted	251,351		87.64		26,725		85.90
RS’s Vested/RSU’s Issued	(330,971	)	55.36		(578	)	51.99
Forfeited	(29,429	)	70.29		(133	)	76.10
Outstanding at December 31, 2014	515,073		77.23		411,093		37.30

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:

	Restricted Stock				Restricted Stock Units
	Intrinsic Value of Awards Vested During the Period (in millions)		Weighted Average Grant Date Fair Value of Awards Granted During the Period		Intrinsic Value of Awards Vested During the Period (in millions)		Weighted Average Grant Date Fair Value of Awards Granted During the Period
2014	$	28	$	87.64	$	—	$	85.90
2013	20		87.06		—		73.48
2012	5		43.11		—		44.38

Schedule of Performance Unit Awards

The following table presents a summary of the 2014 activity for performance unit awards to be settled in shares:

	Number of Units		Weighted Average Grant Date Fair Value
Outstanding at December 31, 2013	3,822,500		$	0.90
Granted	2,033,700		0.85
Canceled	(64,375	)	0.87
Outstanding at December 31, 2014	5,791,825		0.88

Schedule of Share-based Compensation, Performance Unit Awards, Valuation Assumptions

Performance units paying out in units have a grant date fair value calculated using a Monte Carlo valuation model, which requires the input of subjective assumptions. The following table provides a summary of these assumptions:

	2014			2013			2012
Risk-free interest rate	0.63		%	0.35		%	0.41		%
Look-back period	2.84 years			2.84 years			2.84 years
Expected volatility	38.51		%	41.67		%	56.06		%
Grant date fair value of performance units granted	$	0.85		$	0.95		$	0.80

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Property, Plant And Equipment (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 25,302	$ 21,793
Property, plant and equipment, accumulated depreciation	9,041	7,872
Assets Held Under Capital Leases
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	510	510
Property, plant and equipment, accumulated depreciation	144	111
Construction In Progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	1,043	747
Residual Fuel Hydrocracker - Garyville | Construction In Progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	90
Residual Fuel Hydrocracker - Garyville | Scenario, Forecast | Minimum | Construction In Progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross			2,200
Residual Fuel Hydrocracker - Garyville | Scenario, Forecast | Maximum | Construction In Progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross			$ 2,500

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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, 2014		Dec. 31, 2013		Dec. 31, 2012
Change in plan assets:
Fair value of plan assets at December 31	$ 1,744		$ 1,800
Amounts recognized in the consolidated balance sheets:
Noncurrent liabilities	(1,099)		(771)
Pension Benefits
Change in benefit obligations:
Benefit obligations at January 1	1,927		2,192
Service cost	88		93		66
Interest cost	74		73		94
Actuarial (gain) loss	257		(183)
Benefits paid	(271)		(248)
Other	0	[1]	0	[1]
Benefit obligations at December 31	2,075		1,927		2,192
Change in plan assets:
Fair value of plan assets at January 1	1,800		1,478
Actual return on plan assets	175		241
Employer contributions	40		329
Benefits paid	(271)		(248)
Fair value of plan assets at December 31	1,744		1,800		1,478
Funded status of plans at December 31	(331)		(127)
Amounts recognized in the consolidated balance sheets:
Current liabilities	(17)		(18)
Noncurrent liabilities	(314)		(109)
Accrued benefit cost	(331)		(127)
Pretax amounts recognized in accumulated other comprehensive loss:
Net loss	710	[2]	668	[2]
Prior service credit	(369)	[2]	(415)	[2]
Pension Benefits | LOOP LLC and Explorer Pipeline [Member]
Pretax amounts recognized in accumulated other comprehensive loss:
Net loss	18	[2]
Other Benefits
Change in benefit obligations:
Benefit obligations at January 1	687		591
Service cost	27		25		20
Interest cost	33		26		24
Actuarial (gain) loss	86		17
Benefits paid	(23)		(20)
Other	2	[1]	48	[1]
Benefit obligations at December 31	812		687		591
Change in plan assets:
Benefits paid	(23)		(20)
Funded status of plans at December 31	(812)		(687)
Amounts recognized in the consolidated balance sheets:
Current liabilities	(27)		(25)
Noncurrent liabilities	(785)		(662)
Accrued benefit cost	(812)		(687)
Pretax amounts recognized in accumulated other comprehensive loss:
Net loss	191	[2]	107	[2]
Prior service credit	(26)	[2]	(30)	[2]
Other Benefits | LOOP LLC and Explorer Pipeline [Member]
Pretax amounts recognized in accumulated other comprehensive loss:
Net loss	$ 1	[2]

[1] Includes adjustments related to Hess’ Retail Operations and Related Assets acquisition in 2014. For 2013, it includes adjustments related to plan amendments and adjustments related to the Galveston Bay Refinery and Related Assets acquisition.

[2] Amounts exclude those related to LOOP and Explorer Pipeline, equity method investees with defined benefit pension and postretirement plans for which net losses of $18 million and $1 million were recorded in accumulated other comprehensive loss in 2014, reflecting our ownership share.

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Disposition (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended				1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012		Jul. 31, 2012	Dec. 01, 2010
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Buyer redeemed preferred equity interest	$ 27	$ 16	$ 53
Preferred equity interest	0	0	45	[1]
Minnesota Assets
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Refinery capacity (in barrels per calendar day)						74,000
Minnesota Assets | Variable Interest Entity
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Buyer redeemed preferred equity interest		49			80
Cash proceeds, dividends on preferred equity interest		4			12
Cash proceeds, distribution from VIE's offering					40
Cash proceeds, total					132
Preferred equity interest					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
Super America
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Convenience stores						166
Wisconsin
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Convenience stores						6

[1] See Note 6.

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Stock-Based Compensation Plans (Summary Of Values Related To Vested And Unvested Restricted Stock Awards) (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic Value of Awards Vested During the Period (in millions)	$ 28	$ 20	$ 5
Weighted Average Grant Date Fair Value of Awards Granted During the Period	$ 87.64	$ 87.06	$ 43.11
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic Value of Awards Vested During the Period (in millions)	$ 0	$ 0	$ 0
Weighted Average Grant Date Fair Value of Awards Granted During the Period	$ 85.90	$ 73.48	$ 44.38

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Equity (Share Repurchases) (Details) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended				36 Months Ended
	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2014
Stockholders Equity [Line Items]
Number of shares repurchased	24,000,000	37,000,000	[1]	28,000,000	89,000,000
Cash paid for shares repurchased	$ 2,131	$ 2,793		$ 1,350	$ 6,270
Effective average cost per delivered share	$ 88.63	$ 76.14		$ 46.73	$ 70.35
Accelerated Share Repurchase Program November 2012
Stockholders Equity [Line Items]
Number of shares repurchased		1,000,000

[1] 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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Stock-Based Compensation Plans (Weighted Average Assumptions Used To Value Stock Options Awards) (Detail) (Stock Options, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average exercise price per share	$ 85.02	$ 84.65	$ 42.02
Expected life in years	5 years 9 months 19 days	6 years	5 years 9 months 18 days
Expected volatility	36.00%	40.00%	47.00%
Expected dividend yield	1.90%	2.00%	2.60%
Risk-free interest rate	1.80%	1.00%	1.10%
Weighted average grant date fair value of stock option awards granted	$ 25.37	$ 27.13	$ 14.45

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Stock-Based Compensation Plans (Summary Of Performance Unit Awards) (Detail) (Performance Shares, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Performance Shares
Number of Shares
Outstanding, beginning balance	3,822,500
Granted	2,033,700
Canceled	(64,375)
Outstanding, ending balance	5,791,825	3,822,500
Weighted Average Grant Date Fair Value
Outstanding, beginning balance (in USD per share)	$ 0.90
Granted (in USD per share)	$ 0.85	$ 0.95	$ 0.80
Forfeited (in USD per share)	$ 0.87
Outstanding, ending balance (in USD per share)	$ 0.88	$ 0.90

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Related Party Transactions (Receivables From Related Parties) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Current receivables from related parties	$ 7	$ 2
Centennial
Related Party Transaction [Line Items]
Current receivables from related parties	2	1
Explorer
Related Party Transaction [Line Items]
Current receivables from related parties	2	0
TAME
Related Party Transaction [Line Items]
Current receivables from related parties	$ 3	$ 1

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Segment Information (Narrative) (Detail)	9 Months Ended	12 Months Ended
	Sep. 30, 2014 Segment	Dec. 31, 2014	Dec. 31, 2012	Dec. 31, 2013
Segment Reporting Information [Line Items]
Number of reportable segments	3
None | Maximum
Segment Reporting Information [Line Items]
Percent of annual revenues		10.00%	10.00%
BP plc
Segment Reporting Information [Line Items]
Percent of annual revenues				10.00%

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Variable Interest Entity Variable Interest Entity (Details) (Illinois Extension Pipeline Company LLC, Variable Interest Entity, Not Primary Beneficiary, USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Illinois Extension Pipeline Company LLC | Variable Interest Entity, Not Primary Beneficiary
Variable Interest Entity [Line Items]
VIE, maximum loss exposure, amount	$ 120

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Acquisitions and Investments (Schedule of Acquisition Related Pro Forma Financial Information (Details) (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Business Combinations [Abstract]
Sales and other operating revenues (including consumer excise taxes)	$ 106,482	$ 114,148
Net income attributable to MPC	$ 2,547	$ 2,142
Net income attributable to MPC per share – basic	$ 8.94	$ 6.80
Net income attributable to MPC per share – diluted	$ 8.87	$ 6.76

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

(In millions)	Estimated Useful Lives	December 31,
		2014		2013
Refining & Marketing	4 - 25 years	$	18,001	$	16,982
Speedway	4 - 25 years	4,639		2,344
Pipeline Transportation	16 - 42 years	2,044		1,921
Corporate and Other	4 - 40 years	618		546
Total		25,302		21,793
Less accumulated depreciation		9,041		7,872
Property, plant and equipment, net		$	16,261	$	13,921

Property, plant and equipment includes gross assets acquired under capital leases of $510 million at both December 31, 2014 and 2013, with related amounts in accumulated depreciation of $144 million and $111 million at December 31, 2014 and 2013. Property, plant and equipment includes construction in progress of $1,043 million and $747 million at December 31, 2014 and 2013, which primarily relates to refinery projects.

Construction in progress at December 31, 2014 includes $90 million of costs associated with a residual fuel hydrocracker project at our Garyville refinery, intended to increase margins by upgrading residual fuel to ultra-low sulfur diesel and gas oil. We are deferring a final investment decision on this project with estimated total costs of $2.2 billion to $2.5 billion as we further evaluate the implications of current market conditions on the project. If a decision is made to not pursue this project, there could be a future impairment of the costs incurred for the project.

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Defined Benefit Pension And Other Postretirement Plans (Estimated Future Benefit Payments) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2015	$ 179
2016	181
2017	181
2018	181
2019	179
2020 through 2024	810
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
2015	27
2016	30
2017	33
2018	37
2019	40
2020 through 2024	$ 236

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Goodwill (Tables)

12 Months Ended

Dec. 31, 2014

Goodwill and Intangible Assets Disclosure [Abstract]

Changes in Carrying Amount of Goodwill

The changes in the carrying amount of goodwill for 2014 and 2013 were as follows:

(In millions)	Refining & Marketing			Speedway		Pipeline Transportation		Total
2013
Beginning balance	$	551		$	217	$	162	$	930
Acquisitions(a)	—			8		—		8
Ending balance	$	551		$	225	$	162	$	938
2014
Beginning balance	$	551		$	225	$	162	$	938
Acquisitions(a)	—			629		—		629
Disposition	(1		)	—		—		(1		)
Ending balance	$	550		$	854	$	162	$	1,566

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

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Supplementary Statistics (Supplementary Statistics) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended								12 Months Ended						0 Months Ended	1 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Sep. 30, 2014	Feb. 01, 2013
Supplementary Statistics [Line Items]
Income from operations	$ 1,259	$ 1,062	$ 1,369	$ 361	$ 1,008	$ 301	$ 960	$ 1,156	$ 4,051		$ 3,425		$ 5,347
Minnesota Assets sale settlement gain									21		6		177
Segment capital expenditures and investments									4,738	[1],[2]	2,789	[1],[2]	1,460	[1],[2]
Hess Retail Operations and Related Assets
Supplementary Statistics [Line Items]
Segment capital expenditures and investments									2,710
Galveston Bay Refinery and Related Assets
Supplementary Statistics [Line Items]
Segment capital expenditures and investments											1,360
Operating Segments
Supplementary Statistics [Line Items]
Income from operations									4,433	[3]	3,791	[3]	5,624	[3]
Segment capital expenditures and investments									4,628	[4],[5]	2,624	[4],[6]	1,256	[4]
Operating Segments | Refining & Marketing
Supplementary Statistics [Line Items]
Income from operations									3,609	[3]	3,206	[3]	5,098	[3]
Segment capital expenditures and investments									1,104	[4],[5]	2,094	[4],[6]	705	[4]
Operating Segments | Refining & Marketing | Hess Retail Operations and Related Assets
Supplementary Statistics [Line Items]
Segment capital expenditures and investments															52
Operating Segments | Refining & Marketing | Galveston Bay Refinery and Related Assets
Supplementary Statistics [Line Items]
Segment capital expenditures and investments																1,290
Operating Segments | Speedway
Supplementary Statistics [Line Items]
Income from operations									544	[3]	375	[3]	310	[3]
Segment capital expenditures and investments									2,981	[4],[5]	296	[4],[6]	340	[4]
Operating Segments | Speedway | Hess Retail Operations and Related Assets
Supplementary Statistics [Line Items]
Segment capital expenditures and investments															2,660
Operating Segments | Pipeline Transportation
Supplementary Statistics [Line Items]
Income from operations									280	[3]	210	[3]	216	[3]
Segment capital expenditures and investments									543	[4],[5]	234	[4],[6]	211	[4]
Operating Segments | Pipeline Transportation | Galveston Bay Refinery and Related Assets
Supplementary Statistics [Line Items]
Segment capital expenditures and investments																70
Operating Segments | Pipeline Transportation | MPLX LP
Supplementary Statistics [Line Items]
Cost of services, overhead									19		20		4
Corporate and Other
Supplementary Statistics [Line Items]
Income from operations									(286)	[7],[8]	(271)	[7],[8]	(336)	[7],[8]
Segment capital expenditures and investments									110	[9]	165	[9]	204	[9]
Capitalized interest									27		28		101
Segment Reconciling Items
Supplementary Statistics [Line Items]
Minnesota Assets sale settlement gain									0	[10]	0	[10]	183	[10]
Pension settlement expenses									$ (96)	[11]	$ (95)	[11]	$ (124)	[11]

[1] Capital expenditures include changes in capital accruals.

[2] Includes $2.71 billion in 2014 for the acquisition of Hess’ Retail Operations and Related Assets and $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5 to the audited consolidated financial statements.

[3] Included in the Pipeline Transportation segment for 2014, 2013 and 2012 are $19 million, $20 million and $4 million of corporate overhead expenses attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. Corporate overhead expenses are not currently allocated to other segments.

[4] Capital expenditures include changes in capital accruals, acquisitions and investments in affiliates.

[5] The Speedway and Refining & Marketing segments include $2.66 billion and $52 million, respectively, for the acquisition of Hess’ Retail Operations and Related Assets. See Note 5.

[6] 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.

[7] Corporate and other unallocated items consists primarily of MPC’s corporate administrative expenses and costs related to certain non-operating assets.

[8] Corporate overhead expenses attributable to MPLX were included in the Pipeline Transportation segment subsequent to MPLX’s October 31, 2012 initial public offering. Corporate overhead expenses are not allocated to the Refining & Marketing and Speedway segments.

[9] Includes capitalized interest of $27 million, $28 million and $101 million for 2014, 2013 and 2012, respectively.

[10] See Note 6.

[11] See Note 23.

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Income per Common Share (Tables)

12 Months Ended

Dec. 31, 2014

Earnings Per Share [Abstract]

Summary of Earnings Per Common Share

(In millions, except per share data)	2014		2013		2012
Basic earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	2,524	$	2,112	$	3,389
Income allocated to participating securities	4		4		6
Income available to common stockholders – basic	$	2,520	$	2,108	$	3,383
Weighted average common shares outstanding	285		315		340
Basic earnings per share	$	8.84	$	6.69	$	9.95
Diluted earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	2,524	$	2,112	$	3,389
Income allocated to participating securities	4		4		6
Income available to common stockholders – diluted	$	2,520	$	2,108	$	3,383
Weighted average common shares outstanding	285		315		340
Effect of dilutive securities	2		2		2
Weighted average common shares, including dilutive effect	287		317		342
Diluted earnings per share	$	8.78	$	6.64	$	9.89

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

The following table summarizes the shares that were anti-dilutive, and therefore, were excluded from the diluted share calculation.

(In millions)	2014	2013	2012
Shares issued under stock-based compensation plans	—	—	2

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Acquisitions and Investments (Investment in Pipeline Companies) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended	0 Months Ended	15 Months Ended
	Dec. 31, 2014	Mar. 04, 2014	Dec. 31, 2014	Jul. 01, 2014	Jan. 01, 2017
Illinois Extension Pipeline Company LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	35.00%		35.00%	35.00%
Cash paid to acquire equity method investments	$ 120
Explorer
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	25.00%		25.00%
Cash paid to acquire equity method investments		77
Ownership percentage acquired		7.00%
North Dakota Pipeline
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	37.50%		37.50%
Cash paid to acquire equity method investments	$ 192		$ 216
North Dakota Pipeline Class A Units | Scenario, Forecast
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage					27.00%
North Dakota Pipeline Class A Units | Scenario, Forecast | Maximum
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage					30.00%

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Income Taxes Income Taxes (Tax Carryforwards) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
States
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	1
Felda Iffco Sdn Bhd | United States Federal
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	11
Minimum | United States Federal
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards, expiration date	Jan. 01, 2022
Minimum | States
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards, expiration date	Jan. 01, 2015
Maximum | United States Federal
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards, expiration date	Dec. 31, 2034
Maximum | States
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards, expiration date	Dec. 31, 2029

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Selected Quarterly Financial Data

12 Months Ended

Dec. 31, 2014

Quarterly Financial Data [Abstract]

Selected Quarterly Financial Data

Selected Quarterly Financial Data (Unaudited)

	2014								2013
(In millions, except per share data)	1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.		1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.
Revenues	$	23,285	$	26,844	$	25,438	$	22,250	$	23,330	$	25,677	$	26,256	$	24,897
Income from operations	361		1,369		1,062		1,259		1,156		960		301		1,008
Net income	207		864		679		805		730		599		173		631
Net income attributable to MPC	199		855		672		798		725		593		168		626
Net income attributable to MPC per share:
Basic	$	0.68	$	2.97	$	2.38	$	2.88	$	2.19	$	1.84	$	0.54	$	2.09
Diluted	0.67		2.95		2.36		2.86		2.17		1.83		0.54		2.07
Dividends paid per share	0.42		0.42		0.50		0.50		0.35		0.35		0.42		0.42

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Derivatives (Tables)

12 Months Ended

Dec. 31, 2014

Summary of Derivative Instruments [Abstract]

Classification of 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, 2014 and 2013:

	December 31, 2014
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	317	$	180	Other current assets

	December 31, 2013
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	21	$	53	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 in 2012:

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

Open Commodity Derivative Contracts

The table below summarizes open commodity derivative contracts for crude oil and refined products as of December 31, 2014.

	Position	Total Barrels (In thousands)
Crude oil(a)
Exchange-traded	Long	15,678
Exchange-traded	Short	(25,257)
Refined Products(b)
Exchange-traded	Long	2,948
Exchange-traded	Short	(3,804)

^{(a )}  97 percent of these contracts expire in the first quarter of 2015.

^(b)   100 percent of these contracts expire in the first quarter of 2015.

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	2014		2013			2012
Sales and other operating revenues	$	37	$	12		$	8
Cost of revenues	456		(180		)	65
Total	$	493	$	(168	)	$	73

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Acquisitions and Investments (Revenues and Earnings of Hess Retail Included in Consolidated Statement of Operations) (Details) (Hess Retail Operations and Related Assets, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Hess Retail Operations and Related Assets
Business Acquisition [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ 2,403
Income from operations	$ 113

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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		Dec. 31, 2014		Dec. 31, 2013
Goodwill [Line Items]
Beginning balance					$ 938		$ 930
Goodwill acquired during period					629	[1]	8	[1]
Goodwill, disposition					(1)
Ending balance					1,566		938
Refining & Marketing
Goodwill [Line Items]
Beginning balance					551		551
Goodwill acquired during period					0		0
Goodwill, disposition					(1)
Ending balance					550		551
Speedway
Goodwill [Line Items]
Beginning balance					225		217
Goodwill acquired during period	5	[1]	83	[1]	629	[1]	8	[1]
Goodwill, disposition					0
Ending balance					854		225
Pipeline Transportation
Goodwill [Line Items]
Beginning balance					162		162
Goodwill acquired during period					0		0
Goodwill, disposition					0
Ending balance					$ 162		$ 162

[1] See Note 5 for information on the acquisitions.

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Leases (Schedule Of Future Minimum Commitments) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Capital Lease Obligations, 2015	$ 52
Capital Lease Obligations, 2016	51
Capital Lease Obligations, 2017	50
Capital Lease Obligations, 2018	49
Capital Lease Obligations, 2019	45
Capital Lease Obligations, Later years	300
Total minimum lease payments	547
Less imputed interest costs	(176)
Present value of net minimum lease payments	371
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
Operating Lease Obligations, 2015	249
Operating Lease Obligations, 2016	209
Operating Lease Obligations, 2017	150
Operating Lease Obligations, 2018	136
Operating Lease Obligations, 2019	114
Operating Lease Obligations, Later years	468
Total minimum lease payments	$ 1,326

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Description Of The Business And Basis Of Presentation Basis of Presentation (Details) (Increase in Prior Year Bonus Expense, Total costs and expenses, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014
Increase in Prior Year Bonus Expense | Total costs and expenses
Quantifying misstatement in current year financial statements, amount	$ 29

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Inventories (Tables)

12 Months Ended

Dec. 31, 2014

Inventory Disclosure [Abstract]

Summary Of Inventories

	December 31,
(In millions)	2014		2013
Crude oil and refinery feedstocks	$	2,219	$	1,797
Refined products	2,955		2,367
Materials and supplies	302		425
Merchandise	166		100
Total (at cost)	$	5,642	$	4,689

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Consolidated Statements of Equity - Shares	Total		Common Stock	Treasury Stock
Number of shares held in treasury (beginning balance) at Dec. 31, 2011				0
Number of shares issued (beginning balance) at Dec. 31, 2011			357,000,000
Number of shares issued - stock-based compensation			4,000,000
Number of shares repurchased	(28,000,000)			(28,000,000)
Number of shares held in treasury (ending balance) at Dec. 31, 2012				(28,000,000)
Number of shares issued (ending balance) at Dec. 31, 2012			361,000,000
Number of shares issued - stock-based compensation			1,000,000
Number of shares repurchased	(37,000,000)	[1]		(37,000,000)
Number of shares held in treasury (ending balance) at Dec. 31, 2013	(65,000,000)			(65,000,000)
Number of shares issued (ending balance) at Dec. 31, 2013	362,000,000		362,000,000
Number of shares issued - stock-based compensation			1,000,000
Number of shares repurchased	(24,000,000)			(24,000,000)
Number of shares held in treasury (ending balance) at Dec. 31, 2014	(89,000,000)			(89,000,000)
Number of shares issued (ending balance) at Dec. 31, 2014	363,000,000		363,000,000

[1] 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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Defined Benefit Pension And Other Postretirement Plans (Fair Values Of Defined Benefit Pension Plan Assets) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	$ 1,744	$ 1,800
Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	29	189
Equity investments, common stocks
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	63	69
Equity funds, mutual funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	155	217
Equity funds, pooled funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	442	590
Fixed income, corporate
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	554	356
Fixed income, government
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	99	22
Fixed income, pooled funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	254	218
Private equity
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	66	57
Real estate
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	57	60
Other
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	25	22
Level 1
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	220	288
Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 1 | Equity investments, common stocks
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	63	69
Level 1 | Equity funds, mutual funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	155	217
Level 1 | Equity funds, pooled funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 1 | Fixed income, corporate
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 1 | Fixed income, government
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 1 | Fixed income, pooled funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 1 | Private equity
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 1 | Real estate
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 1 | Other
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	2	2
Level 2
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	1,380	1,375
Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	29	189
Level 2 | Equity investments, common stocks
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 2 | Equity funds, mutual funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 2 | Equity funds, pooled funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	442	590
Level 2 | Fixed income, corporate
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	554	356
Level 2 | Fixed income, government
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	99	22
Level 2 | Fixed income, pooled funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	254	218
Level 2 | Private equity
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 2 | Real estate
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 2 | Other
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	2	0
Level 3
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	144	137	127
Level 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 3 | Equity investments, common stocks
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 3 | Equity funds, mutual funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 3 | Equity funds, pooled funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 3 | Fixed income, corporate
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 3 | Fixed income, government
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 3 | Fixed income, pooled funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 3 | Private equity
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	66	57	56
Level 3 | Real estate
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	57	60	54
Level 3 | Other
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	$ 21	$ 20	$ 17

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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, 2014		Dec. 31, 2013
Fair Value
Financial assets:
Investments	$ 26		$ 336
Other	32		31
Total financial assets	58		367
Financial liabilities:
Long-term debt	6,571	[1]	3,306	[1]
Deferred credits and other liabilities	17		21
Total financial liabilities	6,588		3,327
Carrying Value
Financial assets:
Investments	2		14
Other	32		30
Total financial assets	34		44
Financial liabilities:
Long-term debt	6,265	[1]	3,001	[1]
Deferred credits and other liabilities	17		21
Total financial liabilities	$ 6,282		$ 3,022

[1] Excludes capital leases

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Summary Of Principal Accounting Policies (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Summary Of Principal Accounting Policies [Line Items]
Restricted cash and cash equivalents	4	7
Accounts receivable number of days past-due evaluated for doubtful accounts	180 days
Stock Options
Summary Of Principal Accounting Policies [Line Items]
Implied volatility rate weighting (in percentage)	50.00%
Historical volatility rate weighting (in percentage)	50.00%
Minimum
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
Summary Of Principal Accounting Policies [Line Items]
Estimated useful lives (in years)	42 years
Accounts Receivable with Master Netting Arrangements | Customer Concentration Risk
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	41.00%	38.00%
MPLX LP
Summary Of Principal Accounting Policies [Line Items]
MPC's partnership interest in MPLX (in percentage)	71.50%
Percentage of noncontrolling interest (in percentage)	28.50%

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Debt Trade Receivables Securitization Facility (Details) (Trade Receivables Securitization, USD $) In Millions, unless otherwise specified	0 Months Ended
	Dec. 18, 2013	Dec. 31, 2014	Jan. 31, 2015
Debt Instrument [Line Items]
Line of credit facility, expiration period	3 years
Line of credit facility, maximum borrowing capacity	$ 1,300
Line of credit facility, current borrowing capacity		1,280
Scenario, Forecast
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity			700
Letter of Credit
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 1,250

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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
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Jan. 31, 2015
Pension Benefits
Weighted-average assumptions used to determine benefit obligation:
Discount rate	3.65%		4.30%		3.45%
Rate of compensation increase	3.70%		3.70%		5.00%
Weighted-average assumptions used to determine net periodic benefit cost:
Discount rate	4.05%		3.88%		4.06%
Expected long-term return on plan assets	7.00%	[1]	7.50%	[1]	7.50%	[1]
Rate of compensation increase	3.70%		5.00%		5.00%
Pension Benefits | Scenario, Forecast
Weighted-average assumptions used to determine net periodic benefit cost:
Expected long-term return on plan assets							6.75%	[1]
Other Benefits
Weighted-average assumptions used to determine benefit obligation:
Discount rate	4.15%		4.95%		4.05%
Rate of compensation increase	3.70%		3.70%		5.00%
Weighted-average assumptions used to determine net periodic benefit cost:
Discount rate	4.95%		4.11%		4.54%
Expected long-term return on plan assets	0.00%	[1]	0.00%	[1]	0.00%	[1]
Rate of compensation increase	3.70%		5.00%		5.00%

[1] Effective January 1, 2015, the expected long-term rate of return on plan assets is 6.75 percent due to a continuation of a change in our primary plan investment strategy, which began January 1, 2014.

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Equity (Tables)

12 Months Ended

Dec. 31, 2014

Equity [Abstract]

Share Repurchases

Total share repurchases were as follows for the respective periods:

(In millions, except per share data)	2014		2013		2012
Number of shares repurchased(a)	24		37		28
Cash paid for shares repurchased	$	2,131	$	2,793	$	1,350
Effective average cost per delivered share	$	88.63	$	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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Debt

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Debt

Debt

Our outstanding borrowings at December 31, 2014 and 2013 consisted of the following:

	December 31,
(In millions)	2014			2013
Marathon Petroleum Corporation:
Revolving credit agreement due 2017	$	—		$	—
Term loan agreement due 2019	700			—
3.500% senior notes due March 1, 2016	750			750
5.125% senior notes due March 1, 2021	1,000			1,000
3.625% senior notes due September 15, 2024	750			—
6.500% senior notes due March 1, 2041	1,250			1,250
4.750% senior notes due September 15, 2044	800			—
5.000% senior notes due September 15, 2054	400			—
Consolidated subsidiaries:
Capital lease obligations due 2015-2028	372			395
MPLX Operations LLC bank revolving credit agreement due 2017	—			—
MPLX bank revolving credit facility due 2019	385			—
MPLX term loan facility due 2019	250			—
Trade receivables securitization facility due 2016	—			—
Total	6,657			3,395
Unamortized discount	(26		)	(10		)
Fair value adjustments(a)	6			11
Amounts due within one year	(27		)	(23		)
Total long-term debt due after one year	$	6,610		$	3,373

^(a)  See Note 19 for information on interest rate swaps.

The following table shows five years of scheduled debt payments.

(In millions)
2015	$	27
2016	777
2017	28
2018	30
2019	1,362

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, 2014, we were in compliance with the covenants contained in the Credit Agreement.

There were no borrowings or letters of credit outstanding at December 31, 2014.

MPC Term Loan Agreement – On August 26, 2014, we entered into a $700 millionfive-year senior unsecured term loan credit agreement (the “Term Loan Agreement”) with a syndicate of lenders to fund a portion of the purchase price for the acquisition of Hess’ Retail Operations and Related Assets. The Term Loan Agreement matures on September 24, 2019 and may be prepaid at any time without premium or penalty. We are obligated to pay certain customary fees under the Term Loan Agreement, including an annual administrative fee.

Amounts outstanding under the Term Loan Agreement bear interest at either of the following rates at our election (i) the sum of the Adjusted LIBO Rate (as defined in the Term Loan Agreement), plus a margin ranging between 0.875 percent to 1.75 percent, depending on our credit ratings, or (ii) the sum of the Base Rate (as defined in the Term Loan Agreement), plus a margin ranging between zero percent to 0.75 percent, depending on our credit ratings. The borrowings under this facility during 2014 were at an average interest rate of 1.3 percent.

The Term Loan Agreement contains representation and warranties, covenants and events of default that are substantially similar to those contained in the MPC revolving credit agreement, including a financial covenant, which requires us to maintain, as of the last day of each fiscal quarter, a ratio of Consolidated Net Debt to Total Capitalization (as defined in the Term Loan Agreement) of no greater than 0.65 to 1.00. As of December 31, 2014, we were in compliance with the covenants contained in the Credit Agreement.

Senior Notes – On September 5, 2014, we completed a public offering of $1.95 billion aggregate principal amount of senior unsecured notes (the “Senior Notes”), consisting of $750 million aggregate principal amount of our Senior Notes due 2024, $800 million aggregate principal amount of our Senior Notes due 2044 and $400 million aggregate principal amount of our Senior Notes due 2054. The net proceeds from the offering of the Senior Notes were approximately $1.92 billion, after deducting underwriting discounts and estimated offering expenses. The net proceeds were used to fund a portion of the purchase price for the acquisition of Hess’ Retail Operations and Related Assets. Interest on each series of Senior Notes is payable semi-annually in arrears on March 15 and September 15 of each year, commencing on March 15, 2015.

The Senior Notes are unsecured and unsubordinated obligations of ours and rank equally with all our other existing and future unsecured and unsubordinated indebtedness.

MPLX Credit Agreement – On November 20, 2014, MPLX entered into a credit agreement with a syndicate of lenders (“MPLX Credit Agreement”), which provides for a five-year $1 billion bank revolving credit facility and a $250 million term loan facility. The maturity date on both facilities is November 20, 2019.

The bank revolving credit facility includes letter of credit issuing capacity of up to $250 million and swingline loan capacity of up to $100 million. The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional $500 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 the majority of the commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the original maturity date.

The term loan facility was drawn in full on November 20, 2014. The maturity date for the term loan facility may be extended for up to two additional one-year periods subject to the consent of the lenders holding a majority of the outstanding term loan borrowings, provided that the portion of the term loan borrowings held by any non-consenting lenders will continue to be due and payable on the original maturity date. The borrowings under this facility during 2014 were at an average interest rate of 1.4 percent.

Borrowings under the MPLX Credit Agreement bear interest at either the Adjusted LIBO Rate or the Alternate Base Rate (as defined in the MPLX Credit Agreement) plus a specified 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 bank revolving credit facility and fees with respect 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 MPLX’s long-term debt.

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. The MPLX Credit Agreement includes 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 (both as defined in the MPLX Credit Agreement) for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 for up to two fiscal quarters following certain acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period. Other covenants restrict MPLX from incurring debt, creating liens on its assets and entering into transactions with affiliates. As of December 31, 2014, MPLX was in compliance with the covenants contained in the MPLX Credit Agreement.

In connection with entering into this new credit agreement, MPLX terminated its previously existing $500 millionfive-year MPLX Operations LLC bank revolving credit agreement, dated as of September 14, 2012. During 2014, MPLX borrowed $280 million under the MPLX Operations LLC bank revolving credit agreement, at an average interest rate of 1.5 percent, per annum, and repaid all of these borrowings.

During 2014, MPLX borrowed $630 million under the new revolving credit agreement, at an average interest rate of 1.4 percent, per annum, and repaid $245 million of these borrowings. At December 31, 2014, MPLX had $385 million of borrowings and no letters of credit outstanding under the MPLX Credit Agreement, resulting in total unused loan availability of $615 million, or 61.5 percent of the borrowing capacity.

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. 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. At December 31, 2014, we were in compliance with the covenants contained in the Receivables Purchase Agreement.

As of December 31, 2014, eligible trade receivables supported borrowings of $1.28 billion. There were no borrowings outstanding at December 31, 2014. As of January 31, 2015, eligible trade receivables supported borrowings of $700 million.

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Derivatives

12 Months Ended

Dec. 31, 2014

Summary of Derivative Instruments [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 18. See Note 2 for a discussion of the types of derivatives we use and the reasons for them. We do not designate any of our commodity derivative instruments as hedges for accounting purposes. Our interest rate derivative instruments were designated as fair value accounting hedges.

The following table presents the gross fair values of derivative instruments, excluding cash collateral, and where they appear on the consolidated balance sheets as of December 31, 2014 and 2013:

	December 31, 2014
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	317	$	180	Other current assets

	December 31, 2013
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	21	$	53	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 in 2012:

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

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, 2014.

	Position	Total Barrels (In thousands)
Crude oil(a)
Exchange-traded	Long	15,678
Exchange-traded	Short	(25,257)
Refined Products(b)
Exchange-traded	Long	2,948
Exchange-traded	Short	(3,804)

^{(a )}  97 percent of these contracts expire in the first quarter of 2015.

^(b)   100 percent of these contracts expire in the first quarter of 2015.

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

(In millions)	Gain (Loss)
Income Statement Location	2014		2013			2012
Sales and other operating revenues	$	37	$	12		$	8
Cost of revenues	456		(180		)	65
Total	$	493	$	(168	)	$	73

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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, 2014	Dec. 31, 2013
Assets
Other noncurrent assets	$ 7	$ 2
Liabilities
Accrued taxes	355	370
Deferred income taxes	2,014	2,304
Net deferred tax liabilities	$ 2,362	$ 2,672

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Defined Benefit Pension and Other Postretirement Plans (Tables)

12 Months Ended

Dec. 31, 2014

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [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)	2014		2013
Projected benefit obligations	$	2,075	$	1,927
Accumulated benefit obligations	2,009		1,912
Fair value of plan assets	1,744		1,800

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)	2014			2013			2014			2013
Change in benefit obligations:
Benefit obligations at January 1	$	1,927		$	2,192		$	687		$	591
Service cost	88			93			27			25
Interest cost	74			73			33			26
Actuarial (gain) loss	257			(183		)	86			17
Benefits paid	(271		)	(248		)	(23		)	(20		)
Other(a)	—			—			2			48
Benefit obligations at December 31	2,075			1,927			812			687
Change in plan assets:
Fair value of plan assets at January 1	1,800			1,478			—			—
Actual return on plan assets	175			241			—			—
Employer contributions	40			329			—			—
Benefits paid from plan assets	(271		)	(248		)	—			—
Fair value of plan assets at December 31	1,744			1,800			—			—
Funded status of plans at December 31	$	(331	)	$	(127	)	$	(812	)	$	(687	)
Amounts recognized in the consolidated balance sheets:
Current liabilities	$	(17	)	$	(18	)	$	(27	)	$	(25	)
Noncurrent liabilities	(314		)	(109		)	(785		)	(662		)
Accrued benefit cost	$	(331	)	$	(127	)	$	(812	)	$	(687	)
Pretax amounts recognized in accumulated other comprehensive loss:(b)
Net loss	$	710		$	668		$	191		$	107
Prior service credit	(369		)	(415		)	(26		)	(30		)

^(a)  Includes adjustments related to Hess’ Retail Operations and Related Assets acquisition in 2014. For 2013, it includes adjustments related to plan amendments and adjustments related to the Galveston Bay Refinery and Related Assets acquisition.

^(b)  Amounts exclude those related to LOOP and Explorer Pipeline, equity method investees with defined benefit pension and postretirement plans for which net losses of $18 million and $1 million were recorded in accumulated other comprehensive loss in 2014, reflecting our ownership share.

Components of Net Periodic Benefit Costs

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)	2014			2013			2012			2014			2013			2012
Components of net periodic benefit cost:
Service cost	$	88		$	93		$	66		$	27		$	25		$	20
Interest cost	74			73			94			33			26			24
Expected return on plan assets	(107		)	(107		)	(104		)	—			—			—
Amortization – prior service cost (credit)	(46		)	(45		)	(18		)	(4		)	(4		)	(2		)
– actuarial loss	51			66			93			2			3			2
– settlement loss	96			95			125			—			—			—
Net periodic benefit cost(a)	$	156		$	175		$	256		$	58		$	50		$	44
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial (gain) loss	$	188		$	(317	)	$	46		$	86		$	17		$	53
Prior service cost (credit)(b)	—			—			(520		)	—			4			(40		)
Amortization of actuarial loss	(147		)	(161		)	(218		)	(2		)	(3		)	(2		)
Amortization of prior service cost	46			45			18			4			4			2
Other	—			—			—			—			—			—
Total recognized in other comprehensive loss	$	87		$	(433	)	$	(674	)	$	88		$	22		$	13
Total recognized in net periodic benefit cost and other comprehensive loss	$	243		$	(258	)	$	(418	)	$	146		$	72		$	57

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

^(b)  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.

Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Loss (Pretax)

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)	2014			2013			2012			2014			2013			2012
Components of net periodic benefit cost:
Service cost	$	88		$	93		$	66		$	27		$	25		$	20
Interest cost	74			73			94			33			26			24
Expected return on plan assets	(107		)	(107		)	(104		)	—			—			—
Amortization – prior service cost (credit)	(46		)	(45		)	(18		)	(4		)	(4		)	(2		)
– actuarial loss	51			66			93			2			3			2
– settlement loss	96			95			125			—			—			—
Net periodic benefit cost(a)	$	156		$	175		$	256		$	58		$	50		$	44
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial (gain) loss	$	188		$	(317	)	$	46		$	86		$	17		$	53
Prior service cost (credit)(b)	—			—			(520		)	—			4			(40		)
Amortization of actuarial loss	(147		)	(161		)	(218		)	(2		)	(3		)	(2		)
Amortization of prior service cost	46			45			18			4			4			2
Other	—			—			—			—			—			—
Total recognized in other comprehensive loss	$	87		$	(433	)	$	(674	)	$	88		$	22		$	13
Total recognized in net periodic benefit cost and other comprehensive loss	$	243		$	(258	)	$	(418	)	$	146		$	72		$	57

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

^(b)  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.

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 2014, 2013 and 2012.

	Pension Benefits						Other Benefits
	2014		2013		2012		2014		2013		2012
Weighted-average assumptions used to determine benefit obligation:
Discount rate	3.65	%	4.30	%	3.45	%	4.15	%	4.95	%	4.05	%
Rate of compensation increase	3.70	%	3.70	%	5.00	%	3.70	%	3.70	%	5.00	%
Weighted-average assumptions used to determine net periodic benefit cost:
Discount rate	4.05	%	3.88	%	4.06	%	4.95	%	4.11	%	4.54	%
Expected long-term return on plan assets(a)	7.00	%	7.50	%	7.50	%	—	%	—	%	—	%
Rate of compensation increase	3.70	%	5.00	%	5.00	%	3.70	%	5.00	%	5.00	%

^(a)  Effective January 1, 2015, the expected long-term rate of return on plan assets is 6.75 percent due to a continuation of a change in our primary plan investment strategy, which began January 1, 2014.

Assumed Health Care Cost Trend Rates

The following summarizes the assumed health care cost trend rates.

	December 31,
	2014		2013		2012
Health care cost trend rate assumed for the following year:
Medical Pre-65	8.00	%	8.00	%	8.00	%
Prescription drugs	7.00	%	7.00	%	7.00	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):
Medical Pre-65	5.00	%	5.00	%	5.00	%
Prescription drugs	5.00	%	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate:
Medical Pre-65	2021		2020		2020
Prescription drugs	2021		2018		2018

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	45		(39		)

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, 2014 and 2013.

	December 31, 2014
(In millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	—	$	29	$	—	$	29
Equity:
Common stocks	63		—		—		63
Mutual funds	155		—		—		155
Pooled funds	—		442		—		442
Fixed income:
Corporate	—		554		—		554
Government	—		99		—		99
Pooled funds	—		254		—		254
Private equity	—		—		66		66
Real estate	—		—		57		57
Other	2		2		21		25
Total investments, at fair value	$	220	$	1,380	$	144	$	1,744

	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

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:

	2014
(In millions)	Private Equity			Real Estate			Other		Total
Beginning balance	$	57		$	60		$	20	$	137
Actual return on plan assets:
Realized	6			4			—		10
Unrealized	6			4			1		11
Purchases	10			5			—		15
Sales	(13		)	(16		)	—		(29		)
Ending balance	$	66		$	57		$	21	$	144

	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

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
2015	$	179	$	27
2016	181		30
2017	181		33
2018	181		37
2019	179		40
2020 through 2024	810		236

Multi Employer Pension Plan

Our participation in this plan for 2014, 2013 and 2012 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 2014 and 2013 is for the plan’s year ended December 31, 2013 and December 31, 2012, 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 2014, 2013 and 2012 contributions. Our portion of the contributions does not make up more than five 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	2014	2013		2014		2013		2012
Central States, Southeast and Southwest Areas Pension Plan(a)	36-6044243	Red	Red	Implemented	$	4	$	3	$	4	No	January 31, 2019

^(a)  This agreement has a minimum contribution requirement of $280 per week per employee for 2015. A total of 267 employees participated in the plan as of December 31, 2014.

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2014

Segment Reporting [Abstract]

Income From Operations Attributable To Operating Segments

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
Year Ended December 31, 2014
Revenues:
Customer	$	80,822	$	16,927	$	70	$	97,819
Intersegment(a)	10,912		5		527		11,444
Segment revenues	$	91,734	$	16,932	$	597	$	109,263
Segment income from operations(b)	$	3,609	$	544	$	280	$	4,433
Income from equity method investments	96		—		57		153
Depreciation and amortization(c)	1,045		152		77		1,274
Capital expenditures and investments(d)(e)	1,104		2,981		543		4,628

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
Year Ended December 31, 2013
Revenues:
Customer	$	85,616	$	14,471	$	79	$	100,166
Intersegment(a)	9,294		4		458		9,756
Segment revenues	$	94,910	$	14,475	$	537	$	109,922
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)(f)	2,094		296		234		2,624

(In millions)	Refining & Marketing			Speedway		Pipeline Transportation		Total
Year Ended December 31, 2012
Revenues:
Customer	$	67,928		$	14,239	$	78	$	82,245
Intersegment(a)	8,782			4		381		9,167
Segment revenues	$	76,710		$	14,243	$	459	$	91,412
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)	705			340		211		1,256

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

^(b)  Included in the Pipeline Transportation segment for 2014, 2013 and 2012 are $19 million, $20 million and $4 million of corporate overhead expenses attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. Corporate overhead 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, acquisitions and investments in affiliates.

^(e)  The Speedway and Refining & Marketing segments include $2.66 billion and $52 million, respectively, for the acquisition of Hess’ Retail Operations and Related Assets. 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)	2014			2013			2012
Segment income from operations	$	4,433		$	3,791		$	5,624
Items not allocated to segments:
Corporate and other unallocated items(a)(b)	(286		)	(271		)	(336		)
Minnesota Assets sale settlement gain(c)	—			—			183
Pension settlement expenses(d)	(96		)	(95		)	(124		)
Net interest and other financial income (costs)	(216		)	(179		)	(109		)
Income before income taxes	$	3,835		$	3,246		$	5,238

^(a)  Corporate and other unallocated items consists primarily of MPC’s corporate administrative expenses and costs related to certain non-operating assets.

^(b)  Corporate overhead expenses attributable to MPLX were included in the Pipeline Transportation segment subsequent to MPLX’s October 31, 2012 initial public offering. Corporate overhead expenses are not allocated to the Refining & Marketing and Speedway segments.

^(c)  See Note 6.

^(d)  See Note 23.

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)	2014		2013		2012
Segment capital expenditures and investments	$	4,628	$	2,624	$	1,256
Less: Investments in equity method investees	413		124		28
Plus: Items not allocated to segments:
Capital expenditures not allocated to segments	83		137		103
Capitalized interest	27		28		101
Total capital expenditures(a)(b)	$	4,325	$	2,665	$	1,432

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

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

Reconciliation Of Total Revenues To Sales And Other Operating Revenues

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

(In millions)	2014			2013			2012
Customer revenues	$	97,819		$	100,166		$	82,245
Corporate and other unallocated items	(2		)	(6		)	(2		)
Sales and other operating revenues (including consumer excise taxes)	$	97,817		$	100,160		$	82,243

Schedule Of Revenues By Product Line

Revenues by product line were:

(In millions)	2014		2013		2012
Refined products	$	90,702	$	93,520	$	76,234
Merchandise	3,817		3,308		3,229
Crude oil and refinery feedstocks	2,917		2,988		2,514
Transportation and other	381		344		266
Sales and other operating revenues (including consumer excise taxes)	$	97,817	$	100,160	$	82,243

Total Assets by Reportable Segment

Total assets by reportable segment were:

	December 31,
(In millions)	2014		2013
Refining & Marketing	$	19,751	$	19,573
Speedway	5,296		2,064
Pipeline Transportation	2,407		1,947
Corporate and Other	3,006		4,801
Total consolidated assets	$	30,460	$	28,385

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2014

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

Supplemental Cash Flow Information

(In millions)	2014		2013		2012
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	166	$	161	$	67
Net income taxes paid to taxing authorities(a)	1,362		1,099		1,211
Non-cash investing and financing activities:
Capital lease obligations increase	$	—	$	61	$	62
Property, plant and equipment sold	4		43		—
Property, plant and equipment acquired	4		—		—
Preferred equity interest received in contract settlement(b)	—		—		45
Preferred equity interest dividend received in-kind	—		—		1
Acquisition:
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 26.

^(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)	2014		2013		2012
Additions to property, plant and equipment per consolidated statements of cash flows	$	1,480	$	1,206	$	1,369
Non-cash additions to property, plant and equipment	4		—		—
Asset retirement expenditures(a)	2		—		—
Increase (decrease) in capital accruals	95		73		(117		)
Total capital expenditures before acquisitions	1,581		1,279		1,252
Acquisitions(b)	2,744		1,386		180
Total capital expenditures	$	4,325	$	2,665	$	1,432

^(a)  Included in All other, net – Operating activities on the consolidated statements of cash flows.

^(a)  The 2014 acquisitions include the acquisition of Hess’ Retail Operations and Related Assets. The 2013 acquisitions include the acquisition of the Galveston Bay Refinery and Related Assets. The acquisition numbers above include property, plant and equipment and intangibles. See Note 5.

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Accumulated Other Comprehensive Loss

12 Months Ended

Dec. 31, 2014

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 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 effect	(43		)	—			—		—			(43		)
Other comprehensive income (loss)	271			(14		)	—		3			260
Balance as of December 31, 2013	$	(161	)	$	(50	)	$	4	$	3		$	(204	)

(In millions)	Pension Benefits			Other Benefits			Gain on Cash Flow Hedge		Workers Compensation			Total
Balance as of December 31, 2013	$	(161	)	$	(50	)	$	4	$	3		$	(204	)
Other comprehensive income (loss) before reclassifications	(119		)	(53		)	—		2			(170		)
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit(a)	(46		)	(4		)	—		—			(50		)
– actuarial loss(a)	51			2			—		—			53
– settlement loss(a)	96			—			—		—			96
Other(b)	—			—			—		(1		)	(1		)
Tax effect	(38		)	1			—		—			(37		)
Other comprehensive income (loss)	(56		)	(54		)	—		1			(109		)
Balance as of December 31, 2014	$	(217	)	$	(104	)	$	4	$	4		$	(313	)

^(a)  These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 23.

^(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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Consolidated Statements of Equity (USD $) In Millions, unless otherwise specified	Total	Common Stock	Treasury Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Noncontrolling Interests
Beginning balance at Dec. 31, 2011	$ 9,505	$ 4	$ 0	$ 9,482	$ 898	$ (879)	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	3,393				3,389		4
Dividends declared	(407)				(407)
Other comprehensive income (loss)	415					415
Shares repurchased	(1,350)		(1,250)	(100)
Shares returned - stock based compensation			(3)
Shares issued - stock based compensation				108
Shares issued (returned) – stock-based compensation	105
Stock-based compensation	46			46			0
Issuance of MPLX LP common units	407						407
Other	(9)			(9)
Ending balance at Dec. 31, 2012	12,105	4	(1,253)	9,527	3,880	(464)	411
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 income (loss)	260					260
Shares repurchased	(2,793)		(2,893)	100
Shares returned - stock based compensation			(9)
Shares issued - stock based compensation				47
Shares issued (returned) – stock-based compensation	38
Stock-based compensation	56			55			1
Tax settlement with Marathon Oil Corporation	39			39
Ending balance at Dec. 31, 2013	11,332	4	(4,155)	9,768	5,507	(204)	412
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	2,555				2,524		31
Dividends declared	(525)				(525)
Distributions to noncontrolling interests	(27)						(27)
Other comprehensive income (loss)	(109)					(109)
Shares repurchased	(2,131)		(2,131)	0
Shares returned - stock based compensation			(13)
Shares issued - stock based compensation				26
Shares issued (returned) – stock-based compensation	13
Stock-based compensation	52			50			2
Issuance of MPLX LP common units	221						221
Other	9				9
Ending balance at Dec. 31, 2014	$ 11,390	$ 4	$ (6,299)	$ 9,844	$ 7,515	$ (313)	$ 639

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Defined Benefit Pension and Other Postretirement Plans

12 Months Ended

Dec. 31, 2014

Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [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.

Obligations and funded status – The accumulated benefit obligation for all defined benefit pension plans was $2,009 million and $1,912 million as of December 31, 2014 and 2013.

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

	December 31,
(In millions)	2014		2013
Projected benefit obligations	$	2,075	$	1,927
Accumulated benefit obligations	2,009		1,912
Fair value of plan assets	1,744		1,800

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)	2014			2013			2014			2013
Change in benefit obligations:
Benefit obligations at January 1	$	1,927		$	2,192		$	687		$	591
Service cost	88			93			27			25
Interest cost	74			73			33			26
Actuarial (gain) loss	257			(183		)	86			17
Benefits paid	(271		)	(248		)	(23		)	(20		)
Other(a)	—			—			2			48
Benefit obligations at December 31	2,075			1,927			812			687
Change in plan assets:
Fair value of plan assets at January 1	1,800			1,478			—			—
Actual return on plan assets	175			241			—			—
Employer contributions	40			329			—			—
Benefits paid from plan assets	(271		)	(248		)	—			—
Fair value of plan assets at December 31	1,744			1,800			—			—
Funded status of plans at December 31	$	(331	)	$	(127	)	$	(812	)	$	(687	)
Amounts recognized in the consolidated balance sheets:
Current liabilities	$	(17	)	$	(18	)	$	(27	)	$	(25	)
Noncurrent liabilities	(314		)	(109		)	(785		)	(662		)
Accrued benefit cost	$	(331	)	$	(127	)	$	(812	)	$	(687	)
Pretax amounts recognized in accumulated other comprehensive loss:(b)
Net loss	$	710		$	668		$	191		$	107
Prior service credit	(369		)	(415		)	(26		)	(30		)

^(a)  Includes adjustments related to Hess’ Retail Operations and Related Assets acquisition in 2014. For 2013, it includes adjustments related to plan amendments and adjustments related to the Galveston Bay Refinery and Related Assets acquisition.

^(b)  Amounts exclude those related to LOOP and Explorer Pipeline, equity method investees with defined benefit pension and postretirement plans for which net losses of $18 million and $1 million were recorded in accumulated other comprehensive loss in 2014, reflecting our ownership 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)	2014			2013			2012			2014			2013			2012
Components of net periodic benefit cost:
Service cost	$	88		$	93		$	66		$	27		$	25		$	20
Interest cost	74			73			94			33			26			24
Expected return on plan assets	(107		)	(107		)	(104		)	—			—			—
Amortization – prior service cost (credit)	(46		)	(45		)	(18		)	(4		)	(4		)	(2		)
– actuarial loss	51			66			93			2			3			2
– settlement loss	96			95			125			—			—			—
Net periodic benefit cost(a)	$	156		$	175		$	256		$	58		$	50		$	44
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial (gain) loss	$	188		$	(317	)	$	46		$	86		$	17		$	53
Prior service cost (credit)(b)	—			—			(520		)	—			4			(40		)
Amortization of actuarial loss	(147		)	(161		)	(218		)	(2		)	(3		)	(2		)
Amortization of prior service cost	46			45			18			4			4			2
Other	—			—			—			—			—			—
Total recognized in other comprehensive loss	$	87		$	(433	)	$	(674	)	$	88		$	22		$	13
Total recognized in net periodic benefit cost and other comprehensive loss	$	243		$	(258	)	$	(418	)	$	146		$	72		$	57

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

^(b)  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.

Lump sum payments to employees retiring in 2014, 2013 and 2012 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 2014, 2013 and 2012 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 2015 are $51 million and $46 million. 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 2015 is $9 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 2014, 2013 and 2012.

	Pension Benefits						Other Benefits
	2014		2013		2012		2014		2013		2012
Weighted-average assumptions used to determine benefit obligation:
Discount rate	3.65	%	4.30	%	3.45	%	4.15	%	4.95	%	4.05	%
Rate of compensation increase	3.70	%	3.70	%	5.00	%	3.70	%	3.70	%	5.00	%
Weighted-average assumptions used to determine net periodic benefit cost:
Discount rate	4.05	%	3.88	%	4.06	%	4.95	%	4.11	%	4.54	%
Expected long-term return on plan assets(a)	7.00	%	7.50	%	7.50	%	—	%	—	%	—	%
Rate of compensation increase	3.70	%	5.00	%	5.00	%	3.70	%	5.00	%	5.00	%

^(a)  Effective January 1, 2015, the expected long-term rate of return on plan assets is 6.75 percent due to a continuation of a change in our primary plan investment strategy, which began January 1, 2014.

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,
	2014		2013		2012
Health care cost trend rate assumed for the following year:
Medical Pre-65	8.00	%	8.00	%	8.00	%
Prescription drugs	7.00	%	7.00	%	7.00	%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):
Medical Pre-65	5.00	%	5.00	%	5.00	%
Prescription drugs	5.00	%	5.00	%	5.00	%
Year that the rate reaches the ultimate trend rate:
Medical Pre-65	2021		2020		2020
Prescription drugs	2021		2018		2018

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 four 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	45		(39		)

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, 2014, the primary plan’s targeted asset allocation was 51 percent equity, private equity, real estate, and timber securities and 49 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, 2014 and 2013.

Cash and cash equivalents – Cash and cash equivalents include a collective fund serving as the investment vehicle for the cash reserves and cash held by third-party investment managers. The collective fund is valued at net asset value (“NAV”) on a scheduled basis using a cost approach, and is considered a Level 2 asset. Cash and cash equivalents held by third-party investment managers are valued using a cost approach and are considered Level 2.

Equity – Equity investments includes common stock, mutual and pooled 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.

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, 2014 and 2013.

	December 31, 2014
(In millions)	Level 1		Level 2		Level 3		Total
Cash and cash equivalents	$	—	$	29	$	—	$	29
Equity:
Common stocks	63		—		—		63
Mutual funds	155		—		—		155
Pooled funds	—		442		—		442
Fixed income:
Corporate	—		554		—		554
Government	—		99		—		99
Pooled funds	—		254		—		254
Private equity	—		—		66		66
Real estate	—		—		57		57
Other	2		2		21		25
Total investments, at fair value	$	220	$	1,380	$	144	$	1,744

	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

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

	2014
(In millions)	Private Equity			Real Estate			Other		Total
Beginning balance	$	57		$	60		$	20	$	137
Actual return on plan assets:
Realized	6			4			—		10
Unrealized	6			4			1		11
Purchases	10			5			—		15
Sales	(13		)	(16		)	—		(29		)
Ending balance	$	66		$	57		$	21	$	144

	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

Cash Flows

Contributions to defined benefit plans – Our funding policy with respect to the funded 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 2014, we made pension contributions totaling $16 million. We have no required funding for 2015, but may make voluntary contributions at our discretion. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are estimated to be approximately $18 million and $27 million in 2015.

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
2015	$	179	$	27
2016	181		30
2017	181		33
2018	181		37
2019	179		40
2020 through 2024	810		236

Contributions to defined contribution plans – We also contribute to several defined contribution plans for eligible employees. Contributions to these plans totaled $86 million, $76 million and $60 million in 2014, 2013 and 2012, respectively.

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 2014, 2013 and 2012 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 2014 and 2013 is for the plan’s year ended December 31, 2013 and December 31, 2012, 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 2014, 2013 and 2012 contributions. Our portion of the contributions does not make up more than five 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	2014	2013		2014		2013		2012
Central States, Southeast and Southwest Areas Pension Plan(a)	36-6044243	Red	Red	Implemented	$	4	$	3	$	4	No	January 31, 2019

^(a)  This agreement has a minimum contribution requirement of $280 per week per employee for 2015. A total of 267 employees participated in the plan as of December 31, 2014.

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 $6 million, $5 million and $5 million for 2014, 2013 and 2012.

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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, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Basic earnings per share:
Net income attributable to MPC	$ 798	$ 672	$ 855	$ 199	$ 626	$ 168	$ 593	$ 725	$ 2,524	$ 2,112	$ 3,389
Income allocated to participating securities, basic									4	4	6
Income available to common stockholders – basic									2,520	2,108	3,383
Weighted average common shares outstanding (in shares)									285	315	340
Basic (in USD per share)	$ 2.88	$ 2.38	$ 2.97	$ 0.68	$ 2.09	$ 0.54	$ 1.84	$ 2.19	$ 8.84	$ 6.69	$ 9.95
Diluted earnings per share:
Net income attributable to MPC	798	672	855	199	626	168	593	725	2,524	2,112	3,389
Income allocated to participating securities, diluted									4	4	6
Income available to common stockholders – diluted									$ 2,520	$ 2,108	$ 3,383
Weighted average common shares outstanding (in shares)									285	315	340
Effect of dilutive securities (in shares)									2	2	2
Weighted average common shares, including dilutive effect (in shares)									287	317	342
Diluted (in USD per share)	$ 2.86	$ 2.36	$ 2.95	$ 0.67	$ 2.07	$ 0.54	$ 1.83	$ 2.17	$ 8.78	$ 6.64	$ 9.89

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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, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value Disclosures [Abstract]
Beginning balance	$ 625	$ 0	$ 0
Contingent consideration agreement	0	600	0
Contingent consideration payment	(180)	0	0
Unrealized and realized losses included in net income	33	25	2
Settlements of derivative instruments	0	0	(2)
Ending balance	$ 478	$ 625	$ 0

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Acquisitions and Investments (Tables)

12 Months Ended

Dec. 31, 2014

Business Acquisition [Line Items]

Business Acquisition, Pro Forma Information [Table Text Block]

The following unaudited pro forma financial information presents consolidated results assuming Hess’ Retail Operations and Related Assets acquisition occurred on January 1, 2013 and 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 acquisitions and is not necessarily indicative of the results of future operations.

(In millions, except per share data)	2014		2013
Sales and other operating revenues (including consumer excise taxes)	$	106,482	$	114,148
Net income attributable to MPC	2,547		2,142
Net income attributable to MPC per share – basic	$	8.94	$	6.80
Net income attributable to MPC per share – diluted	8.87		6.76

Hess Retail Operations and Related Assets

Business Acquisition [Line Items]

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	$	2,824
Net working capital adjustment estimate	(3		)
Total fair value of consideration transferred	$	2,821

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

During the fourth quarter of 2014, an independent appraisal of the assets acquired and liabilities assumed and other evaluations were completed and finalized. Updates to the preliminary fair value measurements of assets acquired and liabilities assumed were made during the fourth quarter of 2014. The following table summarizes the amounts assigned to the assets acquired and liabilities assumed as of the acquisition date.

(In millions)
Cash and cash equivalents	$	49
Receivables	123
Inventories	165
Other current assets	8
Property, plant and equipment, net	2,063
Other noncurrent assets	111
Total assets acquired	2,519
Accounts payable	77
Payroll and benefits payable	15
Consumer excise taxes payable	64
Accrued taxes	4
Other current liabilities	10
Defined benefit postretirement plan obligations	2
Deferred credits and other liabilities	155
Total liabilities assumed	327
Net assets acquired excluding goodwill	2,192
Goodwill	629
Net assets acquired	$	2,821

Business Acquisition, Pro Forma Information [Table Text Block]

The amounts of revenue and income from operations associated with Hess’ Retail Operations and Related Assets included in our consolidated statements of income for 2014 are as follows:

(In millions)	2014
Sales and other operating revenues (including consumer excise taxes)	$	2,403
Income from operations	113

Galveston Bay Refinery and Related Assets

Business Acquisition [Line Items]

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 fair value of consideration transferred	$	2,088

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

During the fourth quarter of 2013, an independent appraisal of the assets acquired and liabilities assumed and other evaluations were completed and finalized. 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
Total assets acquired	2,298
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 liabilities assumed	210
Net assets acquired	$	2,088

^(a)  Represents a capital lease obligation assumed.

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Debt (Tables)

12 Months Ended

Dec. 31, 2014

Debt Disclosure [Abstract]

Outstanding Borrowings

Our outstanding borrowings at December 31, 2014 and 2013 consisted of the following:

	December 31,
(In millions)	2014			2013
Marathon Petroleum Corporation:
Revolving credit agreement due 2017	$	—		$	—
Term loan agreement due 2019	700			—
3.500% senior notes due March 1, 2016	750			750
5.125% senior notes due March 1, 2021	1,000			1,000
3.625% senior notes due September 15, 2024	750			—
6.500% senior notes due March 1, 2041	1,250			1,250
4.750% senior notes due September 15, 2044	800			—
5.000% senior notes due September 15, 2054	400			—
Consolidated subsidiaries:
Capital lease obligations due 2015-2028	372			395
MPLX Operations LLC bank revolving credit agreement due 2017	—			—
MPLX bank revolving credit facility due 2019	385			—
MPLX term loan facility due 2019	250			—
Trade receivables securitization facility due 2016	—			—
Total	6,657			3,395
Unamortized discount	(26		)	(10		)
Fair value adjustments(a)	6			11
Amounts due within one year	(27		)	(23		)
Total long-term debt due after one year	$	6,610		$	3,373

^(a)  See Note 19 for information on interest rate swaps.

Schedule Of Debt Payments

The following table shows five years of scheduled debt payments.

(In millions)
2015	$	27
2016	777
2017	28
2018	30
2019	1,362

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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		Dec. 31, 2014		Dec. 31, 2013 Store
Business Acquisition [Line Items]
Goodwill acquired during period					$ 629	[1]	$ 8	[1]
Speedway
Business Acquisition [Line Items]
Number of convenience stores acquired	10		87				9
Goodwill acquired during period	$ 5	[1]	$ 83	[1]	$ 629	[1]	$ 8	[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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Consolidated Statements of Income (USD $) In Millions, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$ 97,817	$ 100,160	$ 82,243
Income from equity method investments	153	36	26
Net gain on disposal of assets	21	6	177
Other income	111	52	46
Total revenues and other income	98,102	100,254	82,492
Costs and expenses:
Cost of revenues (excludes items below)	83,770	87,401	68,668
Purchases from related parties	505	357	280
Consumer excise taxes	6,685	6,263	5,709
Depreciation and amortization	1,326	1,220	995
Selling, general and administrative expenses	1,375	1,248	1,223
Other taxes	390	340	270
Total costs and expenses	94,051	96,829	77,145
Income from operations	4,051	3,425	5,347
Net interest and other financial income (costs)	(216)	(179)	(109)
Income before income taxes	3,835	3,246	5,238
Provision for income taxes	1,280	1,113	1,845
Net income	2,555	2,133	3,393
Less net income attributable to noncontrolling interests	31	21	4
Net income attributable to MPC	$ 2,524	$ 2,112	$ 3,389
Basic:
Net income attributable to MPC per share	$ 8.84	$ 6.69	$ 9.95
Weighted average shares outstanding (in shares)	285	315	340
Diluted:
Net income attributable to MPC per share	$ 8.78	$ 6.64	$ 9.89
Weighted average shares outstanding (in shares)	287	317	342
Dividends paid (in USD per share)	$ 1.84	$ 1.54	$ 1.20

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Other Items (Tables)

12 Months Ended

Dec. 31, 2014

Other Income and Expenses [Abstract]

Net Interest And Other Financial Income (Costs)

Net interest and other financial income (costs) was:

(In millions)	2014			2013			2012
Interest income	$	7		$	9		$	6
Interest expense	(229		)	(195		)	(191		)
Interest capitalized	27			28			101
Other financial costs	(21		)	(21		)	(25		)
Net interest and other financial income (costs)	$	(216	)	$	(179	)	$	(109	)

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Income Taxes (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [Abstract]
Statutory rate applied to income before income taxes	35.00%	35.00%	35.00%
Valuation allowance	$ 4	$ 3
Tax credit carryforward, valuation allowance	3	3
Operating loss carryforwards, valuation allowance	1
Unrecognized tax benefits, increase (decrease)		(21)
Tax settlement with Marathon Oil Corporation		39
Unrecognized tax benefits that would impact effective income tax rate	5
Uncertain tax positions, reasonably possible increase or decrease during the next twelve months	4
Unrecognized tax benefits income tax net penalties and interest receipts (expenses)	1	(11)	1
Interest and penalties accrued	$ 14	$ 15

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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, 2014		Dec. 31, 2013		Dec. 31, 2012
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Amortization of prior service cost	$ 50	[1]	$ 49	[1]
Pension Benefits
Components of net periodic benefit cost:
Service cost	88		93		66
Interest cost	74		73		94
Expected return on plan assets	(107)		(107)		(104)
Amortization – prior service cost (credit)	(46)		(45)		(18)
Amortization – actuarial loss	51		66		93
Amortization – settlement loss	96		95		125
Net periodic benefit cost	156	[2]	175	[2]	256	[2]
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial (gain) loss	188		(317)		46
Prior service cost (credit)	0	[3]	0	[3]	(520)	[3]
Amortization of actuarial loss	(147)		(161)		(218)
Amortization of prior service cost	46		45		18
Other	0		0		0
Total recognized in other comprehensive loss	87		(433)		(674)
Total recognized in net periodic benefit cost and other comprehensive loss	243		(258)		(418)
Other Benefits
Components of net periodic benefit cost:
Service cost	27		25		20
Interest cost	33		26		24
Expected return on plan assets	0		0		0
Amortization – prior service cost (credit)	(4)		(4)		(2)
Amortization – actuarial loss	2		3		2
Amortization – settlement loss	0		0		0
Net periodic benefit cost	58	[2]	50	[2]	44	[2]
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial (gain) loss	86		17		53
Prior service cost (credit)	0	[3]	4	[3]	(40)	[3]
Amortization of actuarial loss	(2)		(3)		(2)
Amortization of prior service cost	4		4		2
Other	0		0		0
Total recognized in other comprehensive loss	88		22		13
Total recognized in net periodic benefit cost and other comprehensive loss	$ 146		$ 72		$ 57

[1] These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 23.

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

[3] Includes adjustments due to 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.

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Fair Value Measurements (Narrative) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 01, 2013
Fair Value, Measurements, Recurring | Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized losses included in net income	$ 0	$ 0	$ 0
Fair Value, Measurements, Recurring | Contingent Consideration
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized losses included in net income	33,000,000	25,000,000
Fair Value, Measurements, Nonrecurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other noncurrent assets, impairment	11,000,000	0
Impairment charge	0	8,000,000	0
Fair Value, Measurements, Nonrecurring | Centennial
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other noncurrent assets, impairment			14,000,000
Galveston Bay Refinery and Related Assets
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	$ 520,000,000	$ 700,000,000		$ 700,000,000
Galveston Bay Refinery and Related Assets | Fair Value, Measurements, Recurring | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range of internal and external crack spread forecast per barrel	13
Discount rate	5.00%
Galveston Bay Refinery and Related Assets | Fair Value, Measurements, Recurring | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range of internal and external crack spread forecast per barrel	15
Discount rate	10.00%

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Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 13	$ 9
Preferred stock:
Shares issued	0	0
Shares outstanding	0	0
Par value	$ 0.01
Shares authorized	30,000,000
Common stock:
Shares issued	363,000,000	362,000,000
Par value	$ 0.01
Shares authorized	1,000,000,000
Treasury stock	(89,000,000)	(65,000,000)

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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, 2014	Dec. 31, 2013	Dec. 31, 2012
Other Income and Expenses [Abstract]
Interest income	$ 7	$ 9	$ 6
Interest expense	(229)	(195)	(191)
Interest capitalized	27	28	101
Other financial costs	(21)	(21)	(25)
Net interest and other financial income (costs)	$ (216)	$ (179)	$ (109)

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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, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [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	45
Effect on total of service and interest cost components, 1-Percentage-Point Decrease	(4)
Effect on other postretirement benefit obligations, 1-Percentage-Point-Decrease	$ (39)

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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, 2014	Dec. 31, 2013
Actual return on plan assets:
Fair value of plan assets at December 31	$ 1,744	$ 1,800
Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	137	127
Actual return on plan assets:
Realized	10	16
Unrealized	11	16
Purchases	15	12
Sales	(29)	(34)
Fair value of plan assets at December 31	144	137
Private equity
Actual return on plan assets:
Fair value of plan assets at December 31	66	57
Private equity | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	57	56
Actual return on plan assets:
Realized	6	13
Unrealized	6	3
Purchases	10	7
Sales	(13)	(22)
Fair value of plan assets at December 31	66	57
Real estate
Actual return on plan assets:
Fair value of plan assets at December 31	57	60
Real estate | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	60	54
Actual return on plan assets:
Realized	4	3
Unrealized	4	10
Purchases	5	5
Sales	(16)	(12)
Fair value of plan assets at December 31	57	60
Other
Actual return on plan assets:
Fair value of plan assets at December 31	25	22
Other | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	20	17
Actual return on plan assets:
Realized	0	0
Unrealized	1	3
Purchases	0	0
Sales	0	0
Fair value of plan assets at December 31	$ 21	$ 20

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Selected Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2014

Quarterly Financial Data [Abstract]

Schedule Of Quarterly Financial Information

	2014								2013
(In millions, except per share data)	1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.		1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.
Revenues	$	23,285	$	26,844	$	25,438	$	22,250	$	23,330	$	25,677	$	26,256	$	24,897
Income from operations	361		1,369		1,062		1,259		1,156		960		301		1,008
Net income	207		864		679		805		730		599		173		631
Net income attributable to MPC	199		855		672		798		725		593		168		626
Net income attributable to MPC per share:
Basic	$	0.68	$	2.97	$	2.38	$	2.88	$	2.19	$	1.84	$	0.54	$	2.09
Diluted	0.67		2.95		2.36		2.86		2.17		1.83		0.54		2.07
Dividends paid per share	0.42		0.42		0.50		0.50		0.35		0.35		0.42		0.42

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Income Taxes (Components Of Deferred Tax Assets And Liabilities) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Deferred tax assets:
Employee benefits	$ 616	$ 483
Environmental	54	37
Investments in subsidiaries and affiliates	24	0
Other	70	49
Total deferred tax assets	764	569
Deferred tax liabilities:
Property, plant and equipment	2,411	2,290
Inventories	614	614
Investments in subsidiaries and affiliates	0	267
Other	101	70
Total deferred tax liabilities	3,126	3,241
Net deferred tax liabilities	$ 2,362	$ 2,672

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2014

Commitments and Contingencies Disclosure [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, including those resulting from the acquisition of Hess’ Retail Operations and Related Assets. For matters for which we have not recorded an accrued liability, we are unable to estimate a range of possible loss because the issues involved have not been fully developed through pleadings and discovery. However, the ultimate resolution of some of these contingencies could, individually or in the aggregate, be material.

Environmental matters – We are subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites and certain other locations including presently or formerly owned or operated retail marketing sites. Penalties may be imposed for noncompliance.

At December 31, 2014 and 2013, accrued liabilities for remediation totaled $185 million and $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 $67 million and $51 million at December 31, 2014 and 2013, respectively.

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 millionduring 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, 2014.

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 $38 million as of December 31, 2014.

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, 2014, which consist of unrecognized tax benefits related to MPC, its consolidated subsidiaries and the RM&T Business operations prior to the Spinoff which are not already reflected in the unrecognized tax benefits described in Note 13, and other contingent liabilities Marathon Oil may incur related to taxes. Furthermore, the separation and distribution agreement and other agreements with Marathon Oil to effect the Spinoff provide for cross-indemnities between Marathon Oil and us. In general, Marathon Oil is required to indemnify us for any liabilities relating to Marathon Oil’s historical oil and gas exploration and production operations, oil sands mining operations and integrated gas operations, and we are required to indemnify Marathon Oil for any liabilities relating to Marathon Oil’s historical refining, marketing and transportation operations. The terms of these indemnifications are indefinite and the amounts are not capped.

Other guarantees – We have entered into other guarantees with maximum potential undiscounted payments totaling $81 million as of December 31, 2014, 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 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 both December 31, 2014 and 2013, our contractual commitments to acquire property, plant and equipment and advance funds to equity method investees totaled $1.7 billion. The contractual commitments at December 31, 2014 includes $520 million of contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets, $703 million for contributions to North Dakota Pipeline and $185 million for contributions to the SAX project. The contractual commitments at December 31, 2013 included the $700 million contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets and $892 million for contributions to North Dakota Pipeline. See Note 5.

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Stock-Based Compensation Plans (Summary Of Restricted Stock Award Activity) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Restricted Stock
Number of Shares
Outstanding, beginning balance	624,122
Granted	251,351
RS’s Vested/RSU’s Issued	(330,971)
Forfeited	(29,429)
Outstanding, ending balance	515,073	624,122
Weighted Average Grant Date Fair Value
Outstanding, beginning balance (in USD per share)	$ 61.11
Granted (in USD per share)	$ 87.64	$ 87.06	$ 43.11
RS's Vested/RSU's Issued (in USD per share)	$ 55.36
Forfeited (in USD per share)	$ 70.29
Outstanding, ending balance (in USD per share)	$ 77.23	$ 61.11
Restricted Stock Units
Number of Shares
Outstanding, beginning balance	385,079
Granted	26,725
RS’s Vested/RSU’s Issued	(578)
Forfeited	(133)
Outstanding, ending balance	411,093	385,079
Weighted Average Grant Date Fair Value
Outstanding, beginning balance (in USD per share)	$ 33.96
Granted (in USD per share)	$ 85.90	$ 73.48	$ 44.38
RS's Vested/RSU's Issued (in USD per share)	$ 51.99
Forfeited (in USD per share)	$ 76.10
Outstanding, ending balance (in USD per share)	$ 37.30	$ 33.96

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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, 2014		Dec. 31, 2013		Dec. 31, 2012
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	$ (204)		$ (464)
Other comprehensive income (loss) before reclassifications	(170)		189
Amounts reclassified from accumulated other comprehensive loss:
Amortization - prior service credit	(50)	[1]	(49)	[1]
Amortization– actuarial loss	53	[1]	69	[1]
Amortization– settlement loss	96	[1]	95	[1]
Other	(1)	[2]	(1)	[2]
Tax effect	(37)		(43)
Other comprehensive income (loss)	(109)		260		415
Ending balance	(313)		(204)		(464)
Pension Benefits
Amounts reclassified from accumulated other comprehensive loss:
Amortization - prior service credit	(46)		(45)		(18)
Other Benefits
Amounts reclassified from accumulated other comprehensive loss:
Amortization - prior service credit	(4)		(4)		(2)
Accumulated Defined Benefit Plans Adjustment | Pension Benefits
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(161)		(432)
Other comprehensive income (loss) before reclassifications	(119)		198
Amounts reclassified from accumulated other comprehensive loss:
Amortization - prior service credit	(46)		(45)
Amortization– actuarial loss	51		66
Amortization– settlement loss	96		95
Tax effect	(38)		(43)
Other comprehensive income (loss)	(56)		271
Ending balance	(217)		(161)
Accumulated Defined Benefit Plans Adjustment | Other Benefits
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	(50)		(36)
Other comprehensive income (loss) before reclassifications	(53)		(13)
Amounts reclassified from accumulated other comprehensive loss:
Amortization - prior service credit	(4)		(4)
Amortization– actuarial loss	2		3
Amortization– settlement loss	0		0
Tax effect	1		0
Other comprehensive income (loss)	(54)		(14)
Ending balance	(104)		(50)
Gain on Cash Flow Hedge
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	4		4
Other comprehensive income (loss) before reclassifications	0		0
Amounts reclassified from accumulated other comprehensive loss:
Tax effect	0		0
Other comprehensive income (loss)	0		0
Ending balance	4		4
Workers Compensation
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance	3		0
Other comprehensive income (loss) before reclassifications	2		4
Amounts reclassified from accumulated other comprehensive loss:
Other	(1)		(1)
Tax effect	0		0
Other comprehensive income (loss)	1		3
Ending balance	$ 4		$ 3

[1] These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 23.

[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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Acquisitions and Investments (Fair Value of Consideration Transferred - Hess Retail) (Details) (Hess Retail Operations and Related Assets, USD $) In Millions, unless otherwise specified	0 Months Ended
	Sep. 30, 2014
Hess Retail Operations and Related Assets
Business Acquisition [Line Items]
Cash paid for acquisition	$ 2,824
Net working capital adjustment estimate	(3)
Total fair value of consideration transferred	$ 2,821

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Income Taxes

12 Months Ended

Dec. 31, 2014

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

Income tax provisions (benefits) were:

	2014								2013							2012
(In millions)	Current		Deferred			Total			Current		Deferred			Total		Current			Deferred		Total
Federal	$	1,382	$	(199	)	$	1,183		$	954	$	20		$	974	$	1,185		$	432	$	1,617
State and local	135		(37		)	98			131		8			139		169			57		226
Foreign	5		(6		)	(1		)	5		(5		)	—		(1		)	3		2
Total	$	1,522	$	(242	)	$	1,280		$	1,090	$	23		$	1,113	$	1,353		$	492	$	1,845

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

	2014		2013		2012
Statutory rate applied to income before income taxes	35	%	35	%	35	%
State and local income taxes, net of federal income tax effects	2		3		2
Domestic manufacturing deduction	(2	)	(2	)	(1	)
Other	(2	)	(2	)	(1	)
Provision for income taxes	33	%	34	%	35	%

Deferred tax assets and liabilities resulted from the following:

	December 31,
(In millions)	2014		2013
Deferred tax assets:
Employee benefits	$	616	$	483
Environmental	54		37
Investments in subsidiaries and affiliates	24		—
Other	70		49
Total deferred tax assets	764		569
Deferred tax liabilities:
Property, plant and equipment	2,411		2,290
Inventories	614		614
Investments in subsidiaries and affiliates	—		267
Other	101		70
Total deferred tax liabilities	3,126		3,241
Net deferred tax liabilities	$	2,362	$	2,672

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

	December 31,
(In millions)	2014		2013
Assets:
Other noncurrent assets	$	7	$	2
Liabilities:
Accrued taxes	355		370
Deferred income taxes	2,014		2,304
Net deferred tax liabilities	$	2,362	$	2,672

Tax carryforwards – At December 31, 2014, our federal operating loss carryforwards included $11 million acquired with the biodiesel facility acquisition, which expire in 2022 through 2034. State and local operating loss carryforwards of $1 million expire in 2015 through 2029.

Valuation allowances – As of December 31, 2014 and 2013, $4 million and $3 million of valuation allowances were recognized related to income taxes. A federal valuation allowance was established for both December 31, 2014 and 2013 of $3 million, primarily due to the expected realizability of foreign tax credits. A state and local valuation allowance was established as of December 31, 2014 of $1 million, based on estimates of future financial income and expected realizability of state and local tax operating losses.

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, 2014, our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated:

United States Federal	2010	-	2013
States	2004	-	2013

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. 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)	2014			2013			2012
January 1 balance	$	13		$	40		$	20
Additions for tax positions of prior years	7			30			32
Reductions for tax positions of prior years	(10		)	(25		)	(6		)
Settlements	2			(30		)	(6		)
Statute of limitations	—			(2		)	—
December 31 balance	$	12		$	13		$	40

If the unrecognized tax benefits as of December 31, 2014 were recognized, $5 million would affect our effective income tax rate. There were $4 million of uncertain tax positions as of December 31, 2014 for which it is reasonably possible that the amount of unrecognized tax benefits would significantly 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 less than $1 million, ($11 million) and $1 million in 2014, 2013 and 2012, respectively. As of December 31, 2014 and 2013, $14 million and $15 million of interest and penalties were accrued related to income taxes.

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Subsequent Event

12 Months Ended

Dec. 31, 2014

Subsequent Events [Abstract]

Subsequent Events

Subsequent Event

On February 12, 2015, MPLX completed an initial underwritten public offering of $500 million aggregate principal amount of four percent unsecured senior notes due February 15, 2025 (the “MPLX Senior Notes”). The MPLX Senior Notes were offered at a price to the public of 99.64 percent of par. The net proceeds of this offering were used to repay the amounts outstanding under the MPLX Credit Agreement, as well as for general partnership purposes.

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Income Taxes (Reconciliation Of Federal Statutory Income Tax Rate) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Tax Disclosure [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	2.00%	3.00%	2.00%
Domestic manufacturing deduction	(2.00%)	(2.00%)	(1.00%)
Other	(2.00%)	(2.00%)	(1.00%)
Provision for income taxes	33.00%	34.00%	35.00%

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Debt (Schedule Of Debt Payments) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014
Debt Disclosure [Abstract]
2015	$ 27
2016	777
2017	28
2018	30
2019	$ 1,362

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Equity Method Investments

12 Months Ended

Dec. 31, 2014

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

Equity Method Investments

	Ownership as of	Carrying value at
	December 31,	December 31,
(In millions)	2014	2014		2013
Centennial	50%	$	36	$	29
Explorer	25%	95		—
Illinois Extension Pipeline	35%	120		—
LOCAP	59%	23		24
LOOP	51%	230		214
North Dakota Pipeline(a)	38%	216		24
TAAE	43%	22		29
TACE	60%	61		70
TAEI	34%	19		23
TAME(b)	50%	24		35
Other		19		15
Total		$	865	$	463

^(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, which is expected to be in 2017.

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

Summarized financial information for equity method investees is as follows:

(In millions)	2014		2013		2012
Income statement data:
Revenues and other income	$	1,430	$	1,067	$	1,025
Income from operations	379		87		73
Net income	316		63		47
Balance sheet data – December 31:
Current assets	$	990	$	339
Noncurrent assets	2,166		1,238
Current liabilities	280		145
Noncurrent liabilities	957		618

As of December 31, 2014, the carrying value of our equity method investments was $110 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 2014. At December 31, 2014, 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 market participant assumptions for various potential uses of Centennial’s assets. If market conditions were to change 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, 2014, our equity investment in Centennial was $36 million and we had a $38 million guarantee associated with 50 percent of Centennial’s outstanding debt. See Note 26 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 $170 million, $18 million and $37 million in 2014, 2013 and 2012.

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Acquisitions and Investments (Acquisition of Refinery and Related Logistics and Marketing Assets) (Detail) (USD $)	9 Months Ended	12 Months Ended			1 Months Ended
	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Feb. 01, 2013 Pipeline site Terminal BPCD MW
Business Acquisition [Line Items]
Contingent consideration payment	$ 172,000,000	$ 172,000,000	$ 0	$ 0
Galveston Bay Refinery and Related Assets
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, megawatt					1,040
Allocation of space on Colonial Pipeline (in barrels per day)					50,000
Cash paid for acquisition		180,000,000			1,491,000,000
Inventories					935,000,000
Maximum earnout provision payable to the company		520,000,000	700,000,000		700,000,000
Term of payment of maximum earnout provision payable to the company, years					6 years
Post-closing adjustment					9,000,000
Finite-lived intangible assets, weighted average useful life					13 years
Acquisition related costs					7,000,000
Galveston Bay Refinery and Related Assets | Customer Relationships
Business Acquisition [Line Items]
Finite-lived intangibles					20,000,000
Finite-lived intangible asset, useful life					4 years
Galveston Bay Refinery and Related Assets | Prepaid Licensed Refinery Technology Agreements
Business Acquisition [Line Items]
Finite-lived intangibles					$ 68,000,000
Finite-lived intangible asset, useful life					15 years

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Property, Plant And Equipment (Summary Of Property, Plant And Equipment) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	25,302	$ 21,793
Less accumulated depreciation	9,041	7,872
Net property, plant and equipment	16,261	13,921
Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	4 years
Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	42 years
Operating Segments | Refining & Marketing
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	18,001	16,982
Operating Segments | Refining & Marketing | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	4 years
Operating Segments | Refining & Marketing | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	25 years
Operating Segments | Speedway
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	4,639	2,344
Operating Segments | Speedway | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	4 years
Operating Segments | Speedway | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	25 years
Operating Segments | Pipeline Transportation
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	2,044	1,921
Operating Segments | Pipeline Transportation | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	16 years
Operating Segments | Pipeline Transportation | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	42 years
Corporate and Other
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	618	$ 546
Corporate and Other | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	4 years
Corporate and Other | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	40 years

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Commitments And Contingencies (Detail) (USD $)

12 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Feb. 01, 2013

Loss Contingencies [Line Items]

Accrued liabilities for remediation

$ 185,000,000

$ 123,000,000

Receivables for recoverable costs

67,000,000

51,000,000

Contractual commitments to acquire property, plant and equipment and advance funds to equity method investees

1,700,000,000

1,700,000,000

Galveston Bay Refinery and Related Assets

Loss Contingencies [Line Items]

Maximum earnout provision payable to the company

520,000,000

700,000,000

700,000,000

North Dakota Pipeline

Loss Contingencies [Line Items]

Contractual commitments to acquire property, plant and equipment and advance funds to equity method investees

703,000,000

892,000,000

Illinois Extension Pipeline Company LLC

Loss Contingencies [Line Items]

Contractual commitments to acquire property, plant and equipment and advance funds to equity method investees

185,000,000

Indemnification Agreement | Marathon Oil Companies

Loss Contingencies [Line Items]

Guarantee obligation current carrying value

2,000,000

Other Guarantees | Equity Method Investees

Loss Contingencies [Line Items]

Maximum potential undiscounted payments

81,000,000

Guarantee obligations maximum exposure per event

50,000,000

Guarantee of Indebtedness of Others | Financial Guarantee | LOOP and LOCAP LLC

Loss Contingencies [Line Items]

Line of credit facility, expiration date

Dec. 31, 2037

Maximum potential undiscounted payments

172,000,000

Master Shelf Agreement | Financial Guarantee | Centennial

Loss Contingencies [Line Items]

Line of credit facility, expiration date

Dec. 31, 2024

Maximum potential undiscounted payments

38,000,000

Pending Litigation

Loss Contingencies [Line Items]

Loss contingency, inestimable loss

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.

Pending Litigation | Emergency Pricing And Consumer Protection Laws

Loss Contingencies [Line Items]

Plaintiff

Commonwealth of Kentucky

Alleged amount overcharged from customers

$ 89,000,000

Loss contingency, period of occurrence

during September and October 2005

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating activities:
Net income	$ 2,555	$ 2,133	$ 3,393
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	1,326	1,220	995
Pension and other postretirement benefits, net	151	(124)	153
Deferred income taxes	(242)	23	492
Net gain on disposal of assets	(21)	(6)	(177)
Equity method investments, net	17	(18)	11
Changes in the fair value of derivative instruments	(3)	(21)	59
Changes in:
Current receivables	1,642	(940)	851
Inventories	(786)	(305)	(115)
Current accounts payable and accrued liabilities	(1,547)	1,464	(1,223)
All other, net	18	(21)	53
Net cash provided by operating activities	3,110	3,405	4,492
Investing activities:
Additions to property, plant and equipment	(1,480)	(1,206)	(1,369)
Acquisitions, net of cash acquired	(2,821)	(1,515)	(190)
Disposal of assets	27	16	53
Investments – acquisitions, loans and contributions	(413)	(151)	(57)
Investments—redemptions, repayments and return of capital	9	77	108
All other, net	135	23	3
Net cash used in investing activities	(4,543)	(2,756)	(1,452)
Financing activities:
Long-term debt – borrowings	3,793	0	0
Long-term debt – repayments	(548)	(21)	(17)
Debt issuance costs	(22)	(4)	(6)
Issuance of common stock	26	48	108
Common stock repurchased	(2,131)	(2,793)	(1,350)
Dividends paid	(524)	(484)	(407)
Net proceeds from issuance of MPLX LP common units	221	0	407
Distributions to noncontrolling interests	(27)	(21)	0
Tax settlement with Marathon Oil Corporation	0	39	0
Contingent consideration payment	(172)	0	0
All other, net	19	19	6
Net cash provided by (used in) financing activities	635	(3,217)	(1,259)
Net increase (decrease) in cash and cash equivalents	(798)	(2,568)	1,781
Cash and cash equivalents at beginning of period	2,292	4,860	3,079
Cash and cash equivalents at end of period	$ 1,494	$ 2,292	$ 4,860

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Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net income	$ 2,555	$ 2,133	$ 3,393
Defined benefit postretirement and post-employment plans:
Actuarial changes, net of tax of ($47), $174 and $47	(78)	294	78
Prior service costs, net of tax of ($19), ($19) and $203	(31)	(34)	337
Other comprehensive income (loss)	(109)	260	415
Comprehensive income	2,446	2,393	3,808
Less comprehensive income attributable to noncontrolling interests	31	21	4
Comprehensive income attributable to MPC	$ 2,415	$ 2,372	$ 3,804

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Related Party Transactions

12 Months Ended

Dec. 31, 2014

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

Our related parties included:

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

• Explorer, in which we have a 25 percent interest. Explorer owns and operates a refined products pipeline.

• LOCAP LLC (“LOCAP”), in which we have a 59 percent noncontrolling interest. LOCAP owns and operates a crude oil pipeline.

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

• 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.

• Other equity method investees.

We believe that transactions with related parties were conducted on terms comparable to those with unaffiliated parties.

Sales to related parties, which are included in sales and other operating revenues (including consumer excise taxes) on the consolidated statements of income, were as follows:

(In millions)	2014		2013		2012
Centennial	$	—	$	—	$	1
Other equity method investees	7		8		7
Total	$	7	$	8	$	8

Related party sales to Centennial consist primarily of petroleum products.

The fees received for operating Centennial’s pipeline, which are included in other income on the consolidated statements of income, were $1 million in 2014, 2013 and 2012.

Purchases from related parties were as follows:

(In millions)	2014		2013		2012
Centennial	$	7	$	3	$	7
Explorer	39		—		—
LOCAP	21		17		24
LOOP	88		43		44
TAAE	79		24		—
TACE	121		130		73
TAME	141		131		124
Other equity method investees	9		9		8
Total	$	505	$	357	$	280

Related party purchases from Centennial consist primarily of refinery feedstocks and refined product transportation costs. Related party purchases from Explorer consist primarily of refined product transportation costs. Related party purchases from LOCAP, LOOP and other equity method investees consist primarily of crude oil transportation costs. Related party purchases from TAAE, TACE and TAME consist of ethanol purchases.

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)	2014		2013
Centennial	$	2	$	1
Explorer	2		—
TAME	3		1
Total	$	7	$	2

Long-term receivable from Centennial, which is included in other noncurrent assets on the consolidated balance sheet, was less than $1 million at December 31, 2014 and $2 million at December 31, 2013.

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

	December 31,
(In millions)	2014		2013
Explorer	$	3	$	—
LOCAP	2		2
LOOP	4		3
TAAE	2		2
TACE	2		4
TAME	5		5
Total	$	18	$	16

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Inventories (Summary Of Inventories) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Inventory Disclosure [Abstract]
Crude oil and refinery feedstocks	$ 2,219	$ 1,797
Refined products	2,955	2,367
Materials and supplies	302	425
Merchandise	166	100
Total (at cost)	$ 5,642	$ 4,689

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Segment Information (Total Assets By Reportable Segment) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	$ 30,460	$ 28,385
Operating Segments | Refining & Marketing
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	19,751	19,573
Operating Segments | Speedway
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	5,296	2,064
Operating Segments | Pipeline Transportation
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	2,407	1,947
Corporate and Other
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	$ 3,006	$ 4,801

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Segment Information (Reconciliation Of Total Revenues To Sales And Other Operating Revenues) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ 97,817	$ 100,160	$ 82,243
Corporate and Other
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales and other operating revenues (including consumer excise taxes)	(2)	(6)	(2)
Reportable Segment
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ 97,819	$ 100,166	$ 82,245

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Debt (Outstanding Borrowings) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013
Debt Instrument [Line Items]
Total	$ 6,657		$ 3,395
Unamortized discount	(26)		(10)
Fair value adjustments	6	[1]	11	[1]
Amounts due within one year	(27)		(23)
Total long-term debt due after one year	6,610		3,373
Capital Lease Obligations [Member] | Consolidated subsidiaries:
Debt Instrument [Line Items]
Capital lease obligations	372		395
Debt instrument maturity year, start	Jan. 01, 2015
Debt instrument maturity year, end	Dec. 31, 2028
MPC Revolver | Line of Credit
Debt Instrument [Line Items]
Long-term debt, gross	0		0
Line of credit facility, expiration date	Sep. 14, 2017
Term loan agreement due 2019 | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross	700		0
Line of credit facility, expiration date	Sep. 30, 2019
3.500% senior notes due March 1, 2016 | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross	750		750
Debt instrument, maturity date	Mar. 01, 2016
Debt instrument, interest rate	3.50%
5.125% senior notes due March 1, 2021 | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross	1,000		1,000
Debt instrument, maturity date	Mar. 01, 2021
Debt instrument, interest rate	5.125%
3.625% senior notes due September 15, 2024 | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross	750		0
Debt instrument, maturity date	Sep. 15, 2024
Debt instrument, interest rate	3.625%
6.500% senior notes due March 1, 2041 | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross	1,250		1,250
Debt instrument, maturity date	Mar. 01, 2041
Debt instrument, interest rate	6.50%
4.750% senior notes due September 15, 2044 | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross	800		0
Debt instrument, maturity date	Sep. 15, 2044
Debt instrument, interest rate	4.75%
5.000% senior notes due September 15, 2054 | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross	400		0
Debt instrument, maturity date	Sep. 15, 2054
Debt instrument, interest rate	5.00%
MPLX Revolver | Line of Credit | MPLX Operations LLC
Debt Instrument [Line Items]
Long-term debt, gross	0		0
MPLX Revolver | Line of Credit | MPLX LP
Debt Instrument [Line Items]
Long-term debt, gross	385		0
Line of credit facility, expiration date	Dec. 20, 2019
MPLX Revolver | Unsecured Debt | MPLX Operations LLC
Debt Instrument [Line Items]
Line of credit facility, expiration date	Oct. 31, 2017
MPLX Term Loan | Unsecured Debt | MPLX LP
Debt Instrument [Line Items]
Long-term debt, gross	250		0
Line of credit facility, expiration date	Dec. 20, 2019
Trade Receivables Securitization | Secured Debt | Consolidated subsidiaries:
Debt Instrument [Line Items]
Long-term debt, gross	$ 0		$ 0
Line of credit facility, expiration date	Dec. 31, 2016

[1] See Note 19 for information on interest rate swaps.

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Defined Benefit Pension And Other Postretirement Plans (Narrative) (Detail) (USD $)
In Millions, unless otherwise specified

12 Months Ended

1 Months Ended

Dec. 31, 2014

Dec. 31, 2013

Dec. 31, 2012

Feb. 01, 2013

Defined Benefit Plan Disclosure [Line Items]

Accumulated benefit obligation

$ 2,009

$ 1,912

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

86

76

60

Multiemployer pension plans percentage funded

65.00%

Marathon Petroleum's contributions as a percentage of total contributions to the multi-employer pension plan, maximum

5.00%

Multiemployer Plans, Pension

Defined Benefit Plan Disclosure [Line Items]

Number of multiemployer defined benefit pension or health and welfare plan

1

Multi employer pension plans

There have been no significant changes that affect the comparability of 2014, 2013 and 2012 contributions.

Multiemployer Plans, Postretirement Benefit

Defined Benefit Plan Disclosure [Line Items]

Number of multiemployer defined benefit pension or health and welfare plan

1

MPC contributions

6

5

5

Equity Securities

Defined Benefit Plan Disclosure [Line Items]

Targeted asset allocation

51.00%

Fixed Income Securities

Defined Benefit Plan Disclosure [Line Items]

Targeted asset allocation

49.00%

Pension Benefits

Defined Benefit Plan Disclosure [Line Items]

Estimated net gain (loss) that will be amortized from accumulated other comprehensive loss in 2014

51

Estimated prior service cost that will be amortized from accumulated other comprehensive loss in 2014

46

Pension contributions

16

Defined benefit plans, estimated future employer contributions in next fiscal year

0

Medical Post-65 | Maximum

Defined Benefit Plan Disclosure [Line Items]

Health care cost trend rate assumed for the following year:

4.00%

Unfunded Pension Plan

Defined Benefit Plan Disclosure [Line Items]

Defined benefit plans, estimated future employer contributions in next fiscal year

18

Other Benefits

Defined Benefit Plan Disclosure [Line Items]

Estimated net gain (loss) that will be amortized from accumulated other comprehensive loss in 2014

9

Estimated prior service cost that will be amortized from accumulated other comprehensive loss in 2014

4

Defined benefit plans, estimated future employer contributions in next fiscal year

27

Galveston Bay Refinery and Related Assets

Defined Benefit Plan Disclosure [Line Items]

Decrease in liabilities

(122)

Galveston Bay Refinery and Related Assets | Pension Benefits

Defined Benefit Plan Disclosure [Line Items]

Percentage increase in discount rates

0.20%

Galveston Bay Refinery and Related Assets | Other Benefits

Defined Benefit Plan Disclosure [Line Items]

Liability related to retiree medical assumed at the acquisition date

$ 43

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Stock-Based Compensation Plans (Summary Of Stock Option Award Activity) (Detail) (Stock Options, USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Stock Options
Number of Shares
Outstanding, beginning balance	5,147,837	[1]
Granted	446,310	[1]
Exercised	(821,948)	[1]
Forfeited, canceled or expired	(20,761)	[1]
Outstanding, ending balance	4,751,438	[1]	5,147,837	[1]
Vested and expected to vest at December 31, 2014 (in shares)	4,746,653	[1]
Exercisable at December 31, 2014 (in shares)	3,795,031	[1]
Weighted Average Exercise Price
Outstanding, beginning balance (in USD per share)	$ 40.08
Granted (in USD per share)	$ 85.02		$ 84.65		$ 42.02
Exercised (in USD per share)	$ 33.04
Forfeited, canceled or expired (in USD per share)	$ 49.67
Outstanding, ending balance (in USD per share)	$ 45.47		$ 40.08
Vested and expected to vest at December 31, 2014 (in USD per share)	$ 45.43
Exercisable at December 31, 2014 (in USD per share)	$ 38.30
Weighted Average Remaining Contractual Terms (in years)
Vested and expected to vest at December 31, 2013 (in years)	5 years 8 months
Exercisable at December 31, 2013 (in years)	5 years 15 days
Aggregate Intrinsic Value (in millions)
Vested and expected to vest at December 31, 2013 (in USD)	$ 213
Exercisable at December 31, 2013 (in USD)	$ 197

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

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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), USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2012
Derivative | Interest rate
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ 1
Hedged Item | Long-term debt
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ (1)

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Document and Entity Information (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Feb. 13, 2015	Jun. 30, 2014
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus (Q1,Q2,Q3,FY)	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		273,062,880
Entity Public Float			$ 22.2

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Debt MPC Term Loan (Details) (MPC Term Loan, USD $) In Millions, unless otherwise specified	0 Months Ended	12 Months Ended
	Aug. 26, 2014	Dec. 31, 2014	Aug. 26, 2014
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 700		$ 700
Debt instrument, term	5 years
Debt instrument, description of variable rate basis	Adjusted LIBO Rate (as defined in the Term Loan Agreement)
Line of credit facility, interest rate during period		1.30%
Minimum | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	0.875%
Minimum | Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	0.00%
Maximum
Debt Instrument [Line Items]
Ratio of indebtedness to net capital	0.65		0.65
Maximum | London Interbank Offered Rate (LIBOR)
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	1.75%
Maximum | Base Rate
Debt Instrument [Line Items]
Debt instrument, basis spread on variable rate	0.75%

XML

Income per Common Share

12 Months Ended

Dec. 31, 2014

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.

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)	2014		2013		2012
Basic earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	2,524	$	2,112	$	3,389
Income allocated to participating securities	4		4		6
Income available to common stockholders – basic	$	2,520	$	2,108	$	3,383
Weighted average common shares outstanding	285		315		340
Basic earnings per share	$	8.84	$	6.69	$	9.95
Diluted earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	2,524	$	2,112	$	3,389
Income allocated to participating securities	4		4		6
Income available to common stockholders – diluted	$	2,520	$	2,108	$	3,383
Weighted average common shares outstanding	285		315		340
Effect of dilutive securities	2		2		2
Weighted average common shares, including dilutive effect	287		317		342
Diluted earnings per share	$	8.78	$	6.64	$	9.89

The following table summarizes the shares that were anti-dilutive, and therefore, were excluded from the diluted share calculation.

(In millions)	2014	2013	2012
Shares issued under stock-based compensation plans	—	—	2

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Related Party Transactions (Purchases From Related Parties) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Related Party Transaction [Line Items]
Purchases from related parties	$ 505	$ 357	$ 280
Centennial
Related Party Transaction [Line Items]
Purchases from related parties	7	3	7
Explorer
Related Party Transaction [Line Items]
Purchases from related parties	39	0	0
LOCAP
Related Party Transaction [Line Items]
Purchases from related parties	21	17	24
LOOP
Related Party Transaction [Line Items]
Purchases from related parties	88	43	44
TAAE
Related Party Transaction [Line Items]
Purchases from related parties	79	24	0
TACE
Related Party Transaction [Line Items]
Purchases from related parties	121	130	73
TAME
Related Party Transaction [Line Items]
Purchases from related parties	141	131	124
Other equity method investees
Related Party Transaction [Line Items]
Purchases from related parties	$ 9	$ 9	$ 8

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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, 2014		Dec. 31, 2013		Dec. 31, 2012
Segment Reporting, Other Significant Reconciling Item [Line Items]
Segment capital expenditures and investments	$ 4,738	[1],[2]	$ 2,789	[1],[2]	$ 1,460	[1],[2]
Plus: Items not allocated to segments:
Total capital expenditures	4,325	[1],[3]	2,665	[1],[3]	1,432	[1],[3]
Operating Segments
Segment Reporting, Other Significant Reconciling Item [Line Items]
Segment capital expenditures and investments	4,628	[4],[5]	2,624	[4],[6]	1,256	[4]
Less: Investments in equity method investees	413		124		28
Corporate and Other
Segment Reporting, Other Significant Reconciling Item [Line Items]
Segment capital expenditures and investments	110	[7]	165	[7]	204	[7]
Plus: Items not allocated to segments:
Capital expenditures not allocated to segments	83		137		103
Capitalized interest	$ 27		$ 28		$ 101

[1] Capital expenditures include changes in capital accruals.

[2] Includes $2.71 billion in 2014 for the acquisition of Hess’ Retail Operations and Related Assets and $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5 to the audited consolidated financial statements.

[3] See Note 21 for a reconciliation of total capital expenditures to additions to property, plant and equipment as reported in the consolidated statements of cash flows.

[4] Capital expenditures include changes in capital accruals, acquisitions and investments in affiliates.

[5] The Speedway and Refining & Marketing segments include $2.66 billion and $52 million, respectively, for the acquisition of Hess’ Retail Operations and Related Assets. See Note 5.

[6] 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.

[7] Includes capitalized interest of $27 million, $28 million and $101 million for 2014, 2013 and 2012, respectively.

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Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Actuarial changes, tax	$ (47)	$ 174	$ 47
Prior service costs, tax	$ (19)	$ (19)	$ 203

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Accounting Standards

12 Months Ended

Dec. 31, 2014

Accounting Changes and Error Corrections [Abstract]

Accounting Standards

Accounting Standards

Not Yet Adopted

In February 2015, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update making targeted changes to the current consolidation guidance. The new standard changes the way certain decisions are made related to substantive rights, related parties, and decision making fees when applying the VIE consolidation model and eliminates certain guidance for limited partnerships and similar entities under the voting interest consolidation model. The update is effective for annual periods beginning after December 15, 2015. Early adoption is permitted. At this point, we have not determined the impact of the new standards update on our consolidated financial statements and related disclosures. 

In August 2014, the FASB issued an accounting standards update requiring management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Management will be required to assess if there is substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. Disclosures will be required if conditions give rise to substantial doubt and the type of disclosure will be determined based on whether management’s plans will be able to alleviate the substantial doubt. The accounting standards update will be effective for the first annual period ending after December 15, 2016, and for annual periods and interim periods thereafter with early application permitted.

In June 2014, the FASB issued an accounting standards update for the elimination of the concept of development stage entity (“DSE”) from U.S. GAAP and removes the related incremental reporting. The standards update eliminates the additional financial statement requirements specific to a DSE. In addition, it amends the consolidation model by eliminating the special provisions in the variable interest entity rules for assessing the sufficiency of the equity of a DSE. The portion of the accounting standards update related to the amendment to the consolidation guidance will be effective on a retrospective basis for annual reporting periods beginning after December 15, 2015, and interim periods within those years, with early adoption permitted. The portion of the accounting standards update related to the removal of the DSE reporting requirements will be effective on a retrospective basis for annual reporting periods beginning after December 15, 2014, and interim periods within those years, with early adoption permitted. Adoption of this standards update in the first quarters of 2015 and 2016 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

In May 2014, the FASB issued an accounting standards update for revenue recognition that is aligned with the International Accounting Standards Board’s revenue recognition standard issued on the same day. The guidance in the update states that revenue is recognized when a customer obtains control of a good or service. Recognition of the revenue will involve a multiple step approach including identifying the contract, identifying the separate performance obligations, determining the transaction price, allocating the price to the performance obligations and then recognizing the revenue as the obligations are satisfied. Additional disclosures will be required to provide adequate information to understand the nature, amount, timing and uncertainty of reported revenues and revenues expected to be recognized. The accounting standards update will be effective on a retrospective or modified retrospective basis for annual reporting periods beginning after December 15, 2016, and interim periods within those years, with no early adoption permitted. At this point, we have not determined the impact of the new standard on our consolidated financial statements.

In April 2014, the FASB issued an accounting standards update that redefines the criteria for determining discontinued operations and introduces new disclosures related to these disposals. The updated definition of a discontinued operation is the disposal of a component (or components) of an entity or the classification of a component (or components) of an entity as held for sale that represents a strategic shift for an entity and has (or will have) a major impact on an entity’s operations and financial results. The standard requires disclosure of additional financial information for discontinued operations and individually material components not qualifying for discontinued operation presentation, as well as information regarding an entity’s continuing involvement with the discontinued operation. The accounting standards update is effective prospectively for annual periods beginning on or after December 15, 2014, and interim periods within those years. Early adoption is permitted. Adoption of this standards update in the first quarter of 2015 is not expected to have an impact on our consolidated results of operations, financial position or cash flows.

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Summary Of Principal Accounting Policies

12 Months Ended

Dec. 31, 2014

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 71.5 percent controlling financial interest, and we record a noncontrolling interest for the 28.5 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, 2014 and 2013, the amount of restricted cash included in other current assets on the consolidated balance sheets were $4 million and $7 million, respectively.

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 41 percent and 38 percent of our accounts receivable balances at December 31, 2014 and 2013, 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. Costs for crude oil and refined product inventories are aggregated on a consolidated basis for purposes of assessing if the LIFO cost basis of these inventories may have to be written down to market value.

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.

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 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.

Stock-based compensation arrangements – The fair value of stock options 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 50 percent of our common stock implied volatility and 50 percent of MPC’s common stock historical volatility.

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. 

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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Stock-Based Compensation Plans (Stock-Based Compensation Expense) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-based compensation expense	$ 40	$ 42	$ 35
Tax benefit recognized on stock-based compensation expense	15	15	13
Cash received by MPC upon exercise of stock option awards	26	48	108
Tax benefit received for tax deductions for stock awards exercised	$ 19	$ 18	$ 16

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Inventories

12 Months Ended

Dec. 31, 2014

Inventory Disclosure [Abstract]

Inventories

Inventories

	December 31,
(In millions)	2014		2013
Crude oil and refinery feedstocks	$	2,219	$	1,797
Refined products	2,955		2,367
Materials and supplies	302		425
Merchandise	166		100
Total (at cost)	$	5,642	$	4,689

The LIFO method accounted for 94 percent and 90 percent of total inventory value at December 31, 2014 and 2013, respectively. Current acquisition costs of inventories were estimated to exceed the LIFO inventory value at December 31, 2014 and 2013 by $684 million and $4,084 million, respectively. There were no liquidations of LIFO inventories in 2014, 2013 and 2012.

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Equity

12 Months Ended

Dec. 31, 2014

Equity [Abstract]

Equity

Equity

On July 30, 2014, our board of directors approved an additional $2.0 billion share repurchase authorization expiring in July 2016. As of December 31, 2014, our board of directors had approved $8.0 billion in total share repurchase authorizations since January 1, 2012 and we have repurchased a total of $6.27 billion of our common stock under these authorizations, leaving $1.73 billion available for repurchases. Under these authorizations, we have acquired 89 million shares at an average cost per share of $70.35.

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 accelerated share repurchase (“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 were as follows for the respective periods:

(In millions, except per share data)	2014		2013		2012
Number of shares repurchased(a)	24		37		28
Cash paid for shares repurchased	$	2,131	$	2,793	$	1,350
Effective average cost per delivered share	$	88.63	$	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.

At December 31, 2014, we had agreements to acquire 99,084 common shares for $9 million, which were settled in early January 2015.

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Income per Common Share Income Per Common Share (Anti-dilutive Shares) (Detail) (Shares issued under stock-based compensation plans) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Shares issued under stock-based compensation plans
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount	0	0	2

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Disposition

12 Months Ended

Dec. 31, 2014

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.”

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.

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Stock-Based Compensation Plans (Weighted Average Assumptions Used to Value Performance Unit Awards) (Details) (Performance Shares, USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	0.63%	0.35%	0.41%
Look-back period	2 years 10 months 3 days	2 years 10 months 3 days	2 years 10 months 3 days
Expected volatility	38.51%	41.67%	56.06%
Grant date fair value of performance units granted	$ 0.85	$ 0.95	$ 0.80

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Supplementary Statistics (Tables)

12 Months Ended

Dec. 31, 2014

Text Block [Abstract]

Supplementary Statistics

(In millions)	2014			2013			2012
Income from Operations by segment
Refining & Marketing	$	3,609		$	3,206		$	5,098
Speedway	544			375			310
Pipeline Transportation(a)	280			210			216
Items not allocated to segments:
Corporate and other unallocated items(a)	(286		)	(271		)	(336		)
Minnesota Assets sale settlement gain	—			—			183
Pension settlement expenses	(96		)	(95		)	(124		)
Income from operations	$	4,051		$	3,425		$	5,347
Capital Expenditures and Investments(b)(c)
Refining & Marketing	$	1,104		$	2,094		$	705
Speedway	2,981			296			340
Pipeline Transportation	543			234			211
Corporate and Other(d)	110			165			204
Total	$	4,738		$	2,789		$	1,460

^(a)  Included in the Pipeline Transportation segment for 2014, 2013 and 2012 are $19 million, $20 million and $4 million of corporate overhead expenses attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. Corporate overhead expenses are not currently allocated to other segments.

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

^(c)  Includes $2.71 billion in 2014 for the acquisition of Hess’ Retail Operations and Related Assets and $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5 to the audited consolidated financial statements.

^(d)  Includes capitalized interest of $27 million, $28 million and $101 million for 2014, 2013 and 2012, respectively.

Operating Statistics

	2014		2013		2012
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)(a)(b)	2,138		2,086		1,618
Refining & Marketing Operating Statistics(b)
Refining & Marketing refined product sales volume (thousands of barrels per day)(c)	2,125		2,075		1,599
Refining & Marketing gross margin (dollars per barrel)(d)	$	15.05	$	13.24	$	17.85
Crude oil capacity utilization percent(e)	95		96		100
Refinery throughputs (thousands of barrels per day):(f)
Crude oil refined	1,622		1,589		1,195
Other charge and blendstocks	184		213		168
Total	1,806		1,802		1,363
Sour crude oil throughput percent	52		53		53
WTI-priced crude oil throughput percent	19		21		28
Refined product yields (thousands of barrels per day):(f)
Gasoline	869		921		738
Distillates	580		572		433
Propane	35		37		26
Feedstocks and special products	276		221		109
Heavy fuel oil	25		31		18
Asphalt	54		54		62
Total	1,839		1,836		1,386
Refinery direct operating costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.80	$	1.20	$	1.00
Depreciation and amortization	1.41		1.36		1.44
Other manufacturing(h)	4.86		4.14		3.15
Total	$	8.07	$	6.70	$	5.59
Refining & Marketing Operating Statistics By Region – Gulf Coast(b)
Refinery throughputs (thousands of barrels per day):(i)
Crude oil refined	991		964
Other charge and blendstocks	182		195
Total	1,173		1,159
Sour crude oil throughput percent	64		65
WTI-priced crude oil throughput percent	3		7
Refined product yields (thousands of barrels per day):(i)
Gasoline	508		551
Distillates	368		365
Propane	23		23
Feedstocks and special products	274		215
Heavy fuel oil	13		19
Asphalt	13		13
Total	1,199		1,186
Refinery direct operating costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.82	$	1.00
Depreciation and amortization	1.15		1.09
Other manufacturing(h)	4.73		3.98
Total	$	7.70	$	6.07

Supplementary Statistics (Unaudited)
	2014			2013			2012
Refining & Marketing Operating Statistics By Region – Midwest
Refinery throughputs (thousands of barrels per day):(i)
Crude oil refined	631			625
Other charge and blendstocks	45			54
Total	676			679
Sour crude oil throughput percent	33			35
WTI-priced crude oil throughput percent	44			42
Refined product yields (thousands of barrels per day):(i)
Gasoline	361			371
Distillates	212			207
Propane	13			14
Feedstocks and special products	43			41
Heavy fuel oil	13			12
Asphalt	41			41
Total	683			686
Refinery direct operating costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.66		$	1.47
Depreciation and amortization	1.78			1.74
Other manufacturing(h)	4.76			4.21
Total	$	8.20		$	7.42
Speedway Operating Statistics(j)
Convenience stores at period-end	2,746			1,478			1,464
Gasoline and distillate sales (millions of gallons)	3,942			3,146			3,027
Gasoline & distillate gross margin (dollars per gallon)(k)	$	0.1775		$	0.1441		$	0.1318
Merchandise sales (in millions)	$	3,611		$	3,135		$	3,058
Merchandise gross margin (in millions)	$	975		$	825		$	795
Merchandise gross margin percent	27.0		%	26.3		%	26.0		%
Same store gasoline sales volume (period over period)	(0.7		)%	0.5		%	(0.8		)%
Same store merchandise sales (period over period)(l)	5.0		%	4.3		%	7.0		%
Pipeline Transportation Operating Statistics
Pipeline throughputs (thousands of barrels per day):(m)
Crude oil pipelines	1,241			1,293			1,191
Refined products pipelines	878			911			980
Total	2,119			2,204			2,171

^(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 43 thousand barrels per day (“mbpd”), 36 mbpd and 25 mbpd for 2014, 2013 and 2012, 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)  Includes the impact of Hess’ Retail Operations and Related Assets beginning on the September 30, 2014 acquisition date.

^(k)  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.

^(l)  Excludes cigarettes.

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

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Subsequent Event Subsequent Event (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended
	Feb. 12, 2015	Sep. 05, 2014
Senior Notes Due Two Thousand Twenty Five [Member] | MPLX LP | Subsequent Event
Subsequent Event [Line Items]
Price to the public	99.64%
Senior Notes
Subsequent Event [Line Items]
Debt instrument, face amount		$ 1,950
Senior Notes | Senior Notes Due Two Thousand Twenty Five [Member] | MPLX LP | Subsequent Event
Subsequent Event [Line Items]
Debt instrument, face amount	$ 500
Debt instrument, interest rate	4.00%
Debt instrument, maturity date	Feb. 15, 2025

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Goodwill (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Goodwill and Intangible Assets Disclosure [Abstract]
Amount of required impairment	$ 0	$ 0

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MPLX LP

12 Months Ended

Dec. 31, 2014

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 19.9 million common units. Net proceeds to MPLX from the sale of the units were $407 million.

As of December 31, 2014, we owned a 71.5 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.

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 a five percent interest in Pipe Line Holdings to MPLX for $100 million of cash on-hand.

On March 1, 2014, we sold MPLX a 13 percent interest in Pipe Line Holdings for $310 million. MPLX financed this transaction with $40 million of cash on-hand and $270 million of borrowings on its bank revolving credit agreement.

On December 1, 2014, we sold and contributed interests in Pipe Line Holdings totaling 30.5 percent to MPLX for $600 million in cash and 2.9 million MPLX common units valued at $200 million. MPLX financed the sales portion of this transaction with $600 million of borrowings on its bank revolving credit facility.

The sales and contribution of our interests in Pipe Line Holdings to MPLX resulted in a change of our ownership in Pipe Line Holdings, but not a change in control. We accounted for these sales as transactions between entities under common control and did not record a gain or loss.

On December 8, 2014, MPLX completed a public offering of 3.5 million common units at a price to the public of $66.68 per common unit, with net proceeds of $221 million. MPLX used the net proceeds from this offering to repay borrowings under its bank revolving credit facility and for general partnership purposes. On December 10, 2014, we exercised our right to maintain our two percent general partner interest in MPLX by purchasing 130 thousand general partner units for $9 million.

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 various long-term, fee-based transportation and storage services agreements with MPLX. Under these agreements, MPLX provides transportation and storage services to us, and we commit to provide MPLX with minimum quarterly throughput volumes on crude oil and products systems and minimum storage volumes of crude oil, products and butane. We also have agreements with MPLX which establish fees for operational and management services provided between us and MPLX and for executive management services and certain general and administrative services provided by us to MPLX. These transactions are eliminated in consolidation.

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Acquisitions and Investments

12 Months Ended

Dec. 31, 2014

Business Combinations [Abstract]

Acquisitions and Investments

Acquisitions and Investments

Acquisition of Hess’ Retail Operations and Related Assets

On September 30, 2014, we acquired from Hess Corporation (“Hess”) all of Hess’ retail locations, transport operations and shipper history on various pipelines, including approximately 40,000 barrels per day on Colonial Pipeline, for $2.82 billion. We refer to these assets as “Hess’ Retail Operations and Related Assets.” The transaction was funded with a combination of debt and available cash.

The transaction provides for an adjustment for working capital, which has not been finalized with Hess. If a change is made for working capital, the fair value of the assets acquired and liabilities assumed will be revised.

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

(In millions)
Cash	$	2,824
Net working capital adjustment estimate	(3		)
Total fair value of consideration transferred	$	2,821

During the fourth quarter of 2014, an independent appraisal of the assets acquired and liabilities assumed and other evaluations were completed and finalized. Updates to the preliminary fair value measurements of assets acquired and liabilities assumed were made during the fourth quarter of 2014. The following table summarizes the amounts assigned to the assets acquired and liabilities assumed as of the acquisition date.

(In millions)
Cash and cash equivalents	$	49
Receivables	123
Inventories	165
Other current assets	8
Property, plant and equipment, net	2,063
Other noncurrent assets	111
Total assets acquired	2,519
Accounts payable	77
Payroll and benefits payable	15
Consumer excise taxes payable	64
Accrued taxes	4
Other current liabilities	10
Defined benefit postretirement plan obligations	2
Deferred credits and other liabilities	155
Total liabilities assumed	327
Net assets acquired excluding goodwill	2,192
Goodwill	629
Net assets acquired	$	2,821

The purchase price allocation resulted in the recognition of $629 million in goodwill by our Speedway segment, which is deductible for tax purposes. Goodwill recognized for the acquisition primarily relates to the expected benefits of a significantly expanded retail platform that should enable growth in new markets, as well as the potential for higher merchandise sales at the acquired locations. We also expect strategic benefits from the financial and operational scale we expect to realize across our entire retail network. This acquisition significantly expands our Speedway presence from nine to 22 states throughout the East Coast and Southeast and is aligned with our strategy to grow higher-valued, stable cash flow businesses. This acquisition also enables us to further leverage our integrated refining and transportation operations, providing an outlet for an incremental 200,000 barrels per day of assured sales from our refining system.

Other noncurrent assets includes a $22 million intangible asset related to a trade name and $72 million related to favorable lease contract terms. Deferred credits and other liabilities includes $90 million related to unfavorable lease contract terms. The trade name is being amortized over its estimated useful life of two years based on the utilization of the assets. The favorable and unfavorable lease contract amounts are being amortized over the terms of the leases.

We recognized $14 million of acquisition-related costs associated with Hess’ Retail Operations and Related Assets acquisition. These costs were expensed and were included in selling, general and administrative expenses.

The amounts of revenue and income from operations associated with Hess’ Retail Operations and Related Assets included in our consolidated statements of income for 2014 are as follows:

(In millions)	2014
Sales and other operating revenues (including consumer excise taxes)	$	2,403
Income from operations	113

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. The transaction was funded with cash on hand. 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. During 2014, we paid BP $180 million for the first period’s contingent earnout. On the consolidated statements of cash flows, $172 million of the contingent earnout payment is included as a financing activity with the remainder included as an operating activity. See Note 18 for additional information on the contingent consideration.

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 fair value of consideration transferred	$	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. 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
Total assets acquired	2,298
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 liabilities assumed	210
Net assets acquired	$	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.

Unaudited Pro Forma Financial Information

The following unaudited pro forma financial information presents consolidated results assuming Hess’ Retail Operations and Related Assets acquisition occurred on January 1, 2013 and 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 acquisitions and is not necessarily indicative of the results of future operations.

(In millions, except per share data)	2014		2013
Sales and other operating revenues (including consumer excise taxes)	$	106,482	$	114,148
Net income attributable to MPC	2,547		2,142
Net income attributable to MPC per share – basic	$	8.94	$	6.80
Net income attributable to MPC per share – diluted	8.87		6.76

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, additional interest expense related to financing the acquisition of Hess’ Retail Operations and Related Assets, as well as the related income tax effects.

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.

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.

Acquisition of Biodiesel Facility

On April 1, 2014, we purchased a facility in Cincinnati, Ohio from Felda Iffco Sdn Bhd, Malaysia for $40 million. The plant currently produces biodiesel, glycerin and other by-products. The production capacity of the plant is approximately 60 million gallons per year.

Neither goodwill nor a gain from a bargain purchase was recognized in conjunction with the biodiesel facility acquisition.

Assuming the acquisitions of the convenience stores in 2013 and 2012 and the biodiesel facility in 2014 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 Companies

In July 2014, we exercised our option to acquire a 35 percent ownership interest in Enbridge Inc.’s Southern Access Extension pipeline (“SAX”) through our investment in Illinois Extension Pipeline Company, LLC (“Illinois Extension Pipeline”). During 2014, we made contributions of $120 million to Illinois Extension Pipeline to fund our portion of the construction costs incurred-to-date on the SAX project. We account for our ownership interest in Illinois Extension Pipeline as an equity method investment. See Note 26 for information on future contributions to Illinois Extension Pipeline.

In March 2014, we acquired from Chevron Raven Ridge Pipe Line Company an additional seven percent interest in Explorer Pipeline Company (“Explorer”) for $77 million, bringing our ownership interest to 25 percent. As a result of this increase in our ownership, we now account for our investment in Explorer using the equity method of accounting rather than the cost method. The cumulative impact of the change was applied as an adjustment to 2014 retained earnings.

In November 2013, we agreed to serve as an anchor shipper for the Sandpiper pipeline project and fund 37.5 percent of the construction costs of the project, which will become part of Enbridge Energy Partners L.P.’s (“Enbridge Energy Partners”) North Dakota System. In exchange for these commitments, we will earn an approximate 27 percent equity interest in Enbridge Energy Partners’ North Dakota System when the Sandpiper pipeline is placed into service, which is expected to be in 2017. We also have the option to increase our ownership interest to approximately 30 percent through additional investments in future system improvements. We made contributions of $192 million to North Dakota Pipeline Company LLC (“North Dakota Pipeline”) during 2014. We have contributed $216 million since project inception. We account for our interest in North Dakota Pipeline using the equity method of accounting. See Note 26 for information on future contributions to North Dakota Pipeline.

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Defined Benefit Pension And Other Postretirement Plans (Summarizes Assumed Health Care Cost Trend Rates) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Medical Pre-65
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for the following year:	8.00%	8.00%	8.00%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):	5.00%	5.00%	5.00%
Year that the rate reaches the ultimate trend rate:	2021	2020	2020
Prescription drugs
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for the following year:	7.00%	7.00%	7.00%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):	5.00%	5.00%	5.00%
Year that the rate reaches the ultimate trend rate:	2021	2018	2018

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Variable Interest Entity

12 Months Ended

Dec. 31, 2014

Variable Interest Entity [Abstract]

Variable Interest Entity

Variable Interest Entity

As stated in Note 5, we have a 35 percent ownership interest in Illinois Extension Pipeline through our contributions to the SAX project. Illinois Extension Pipeline Company LLC is considered a variable interest entity (“VIE”) because it is a development stage entity and the equity in the entity is not sufficient to fund the current stage of development, which is the construction of the SAX pipeline. Our maximum exposure to loss due to this VIE at December 31, 2014 was $120 million, which equates to our contributions to-date to fund our portion of the construction costs for the project.

We are not the primary beneficiary of this VIE and, therefore, do not consolidate it because we do not have the power to control the activities that significantly influence the economic activities of the entity. The activities that most significantly impact the VIE’s economic performance during the construction phase are the actual construction costs and risks associated with the construction process. Through our vote, we have shared power to direct the construction activities, but do not have the sole ability to control the construction activities.

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Acquisitions and Investments (Acquisition of Hess' Retail Operations and Related Assets) (Details) (USD $) In Millions, unless otherwise specified	0 Months Ended
	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Jun. 30, 2014 Store
Business Acquisition [Line Items]
Goodwill		$ 1,566	$ 938	$ 930
Speedway
Business Acquisition [Line Items]
Goodwill		854	225	217
Number of states in which entity operates					9
Hess Retail Operations and Related Assets
Business Acquisition [Line Items]
Allocation of space on Colonial Pipeline (in barrels per day)	40,000
Cash paid for acquisition	2,824
Goodwill	629
Assured sales volume (bpd)	200,000
Other noncurrent assets	111
Deferred credits and other liabilities	155
Acquisition-related costs	14
Hess Retail Operations and Related Assets | Trade Names
Business Acquisition [Line Items]
Finite-lived intangibles	22
Finite-lived intangible asset, useful life	2 years
Hess Retail Operations and Related Assets | Favorable Leases
Business Acquisition [Line Items]
Other noncurrent assets	72
Hess Retail Operations and Related Assets | Unfavorable Leases
Business Acquisition [Line Items]
Deferred credits and other liabilities	$ 90
Hess Retail Operations and Related Assets | Speedway
Business Acquisition [Line Items]
Number of states in which entity operates	22

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Derivatives (Open Commodity Derivative Contracts) (Detail)	12 Months Ended
	Dec. 31, 2014
Crude Oil Exchange-Traded
Derivative [Line Items]
Percentage of derivative contracts expiring in the period	97.00%
Derivative contract expiration date	Mar. 31, 2015
Refined Products Exchange-Traded
Derivative [Line Items]
Percentage of derivative contracts expiring in the period	100.00%
Derivative contract expiration date	Mar. 31, 2015
Long | Crude Oil Exchange-Traded
Derivative [Line Items]
Notional Contracts (in thousands of Total Barrels)	15,678,000	[1]
Long | Refined Products Exchange-Traded
Derivative [Line Items]
Notional Contracts (in thousands of Total Barrels)	2,948,000	[2]
Short | Crude Oil Exchange-Traded
Derivative [Line Items]
Notional Contracts (in thousands of Total Barrels)	25,257,000	[1]
Short | Refined Products Exchange-Traded
Derivative [Line Items]
Notional Contracts (in thousands of Total Barrels)	3,804,000	[2]

[1] 97 percent of these contracts expire in the first quarter of 2015.

[2] 100 percent of these contracts expire in the first quarter of 2015.

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Equity (Narrative) (Detail) (USD $)	12 Months Ended				36 Months Ended	1 Months Ended	0 Months Ended
	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012	Dec. 31, 2014	Jan. 31, 2015	Jul. 30, 2014	Feb. 28, 2012	Nov. 30, 2012
Stockholders Equity [Line Items]
Stock repurchase plan authorized amount	$ 8,000,000,000				$ 8,000,000,000
Cash paid for shares repurchased	2,131,000,000	2,793,000,000		1,350,000,000	6,270,000,000
Stock repurchase plan remaining authorized amount	1,730,000,000				1,730,000,000
Number of shares repurchased	24,000,000	37,000,000	[1]	28,000,000	89,000,000
Effective average cost per delivered share	$ 88.63	$ 76.14		$ 46.73	$ 70.35
Scenario, Forecast
Stockholders Equity [Line Items]
Cash paid for shares repurchased						9,000,000
Number of shares repurchased						99,084
Share Repurchase Authorization July 2014
Stockholders Equity [Line Items]
Stock repurchase plan authorized amount							2,000,000,000
Ending date of share repurchase authorization							Jul. 30, 2016
Accelerated Share Repurchase Program February 2012
Stockholders Equity [Line Items]
Repurchase shares of MPC common stock under ASR program								850,000,000
Accelerated Share Repurchase Program November 2012
Stockholders Equity [Line Items]
Number of shares repurchased		1,000,000
Repurchase shares of MPC common stock under ASR program									$ 500,000,000

[1] 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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Acquisitions and Investments (Schedule of Assets Acquired and Liabilities Assumed - Hess Retail) (Details) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Sep. 30, 2014
Business Acquisition [Line Items]
Goodwill	$ 1,566	$ 938	$ 930
Hess Retail Operations and Related Assets
Business Acquisition [Line Items]
Cash and cash equivalents				49
Receivables				123
Inventories				165
Other current assets				8
Property, plant and equipment, net				2,063
Other noncurrent assets				111
Total assets acquired				2,519
Accounts payable				77
Payroll and benefits payable				15
Consumer excise taxes payable				64
Accrued taxes				4
Other current liabilities				10
Defined benefit postretirement plan obligations				2
Deferred credits and other liabilities				155
Total liabilities assumed				327
Net assets acquired excluding goodwill				2,192
Goodwill				629
Net assets acquired				$ 2,821

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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, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
January 1 balance	$ 13	$ 40	$ 20
Additions for tax positions of prior years	7	30	32
Reductions for tax positions of prior years	(10)	(25)	(6)
Settlements	2	(30)	(6)
Statute of limitations	0	(2)	0
December 31 balance	$ 12	$ 13	$ 40

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MPLX LP (Narrative) (Detail) (USD $) In Millions, except Share data, unless otherwise specified	12 Months Ended			0 Months Ended				6 Months Ended	1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 02, 2014	Mar. 01, 2014	May 01, 2013	Dec. 08, 2014	Apr. 30, 2013	Oct. 31, 2012	Dec. 01, 2014	Dec. 10, 2014
Noncontrolling Interest [Line Items]
Net proceeds from issuance of MPLX LP common units	$ 221	$ 0	$ 407
MPLX Pipe Line Holdings LP
Noncontrolling Interest [Line Items]
Additional interest sold					13.00%	5.00%				30.50%
Proceeds from sale of ownership interest				600	310	100
MPLX LP
Noncontrolling Interest [Line Items]
Net proceeds from issuance of MPLX LP common units							221
MPC's partnership interest in MPLX (in percentage)	71.50%
General partner units issued											130,000
General partners' contributed capital											9
MPLX LP | MPLX Revolver
Noncontrolling Interest [Line Items]
Cash paid for acquisition				600	270
MPLX LP | Cash and cash equivalents
Noncontrolling Interest [Line Items]
Cash paid for acquisition					40
MPLX LP | Butane Cavern
Noncontrolling Interest [Line Items]
MPLX's partnership percent indirect interest in assets									100.00%
MPLX LP | General Partner and Limited Partner
Noncontrolling Interest [Line Items]
MPC's partnership interest in MPLX (in percentage)	71.50%
MPLX LP | General Partner
Noncontrolling Interest [Line Items]
MPC's partnership interest in MPLX (in percentage)	2.00%
MPLX LP | Limited Partner
Noncontrolling Interest [Line Items]
Public offering of common units (in number of common units)							3,500,000
Equity interest issued, number of shares				2,900,000
Equity interest issued, value assigned										200
Shares issued, price per share							$ 66.68
MPLX LP | MPLX Pipe Line Holdings LP
Noncontrolling Interest [Line Items]
Ownership interest (in percentage)								51.00%
MPLX LP | IPO
Noncontrolling Interest [Line Items]
Initial public offering date of MPLX LP									October 2012
Net proceeds from issuance of MPLX LP common units									$ 407
MPLX LP | IPO | Limited Partner
Noncontrolling Interest [Line Items]
Public offering of common units (in number of common units)									19,900,000

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Segment Information (Schedule Of Revenues By Product Line) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ 97,817	$ 100,160	$ 82,243
Refined products
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)	90,702	93,520	76,234
Merchandise
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)	3,817	3,308	3,229
Crude oil and refinery feedstocks
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)	2,917	2,988	2,514
Transportation and other
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ 381	$ 344	$ 266

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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, 2014	Dec. 31, 2013		Dec. 31, 2012
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$ 166	$ 161		$ 67
Net income taxes paid to taxing authorities	1,362	1,099		1,211	[1]
Non-cash investing and financing activities:
Capital lease obligations increase	0	61		62
Property, plant and equipment sold	4	43		0
Property, plant and equipment acquired	4	0		0
Preferred equity interest received in contract settlement	0	0		45	[2]
Preferred equity interest dividend received in-kind	0	0		1
Acquisition:
Contingent consideration	0	600	[3]	0
Payable to seller	0	6	[3]	0
Intangible asset acquired	0	0		3
Liability assumed	0	0		2
Marathon Oil Companies
Net cash provided by operating activities included:
Related party tax payments				$ 181

[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 26.

[2] See Note 6.

[3] See Note 5.

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Leases

12 Months Ended

Dec. 31, 2014

Leases [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, 2014, 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
2015	$	52	$	249
2016	51		209
2017	50		150
2018	49		136
2019	45		114
Later years	300		468
Total minimum lease payments	547		$	1,326
Less imputed interest costs	176
Present value of net minimum lease payments	$	371

Operating lease rental expense was:

(In millions)	2014		2013		2012
Rental expense	$	256	$	213	$	139

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Stock-Based Compensation Plans (Narrative) (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted units outstanding	411,093
Non-Employee Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted units vested	409,805
Weighted average fair value, vested	$ 37.16
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	0
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement by share-based payment award, expiration period	10 years
Vesting period of awards	3 years
Implied volatility rate weighting (in percentage)	50.00%
Historical volatility rate weighting (in percentage)	50.00%
Intrinsic value of options exercised	48,000,000	60,000,000	37,000,000
Unrecognized compensation cost	5,000,000
Weighted average recognition period, in years	1 year 1 month 6 days
Stock Appreciation Rights (SARs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement by share-based payment award, expiration period	10 years
Vesting period of awards	3 years
Restricted Stock Awards and Restricted Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of awards	3 years
Restricted stock and restricted stock unit awards granted in 2012, additional holding period	1 year
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	26,000,000
Weighted average recognition period, in years	1 year 1 month 6 days
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target payout	$ 1.00
Unrecognized compensation cost	$ 2,000,000
Weighted average recognition period, in years	1 year 6 months
Shares issued in period	64,168
Maximum | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Actual payout	$ 2.00
Target payout percentage	200.00%
MPC 2012 Plan | Maximum
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
MPC 2012 Plan | Maximum | Awards Other Than Stock Options Or Stock Appreciation Rights
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	10,000,000
MPC 2012 Plan | Maximum | Stock Options
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	10,000,000
MPC 2012 and 2011 Plans | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of awards	36 months
Pay-out percentage in MPC common stock (in percentage)	25.00%
Pay-out percentage in cash (in percentage)	75.00%

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Assets and Liabilities Accounted for at Fair Value on Recurring Basis

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2014 and 2013 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, 2014
	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	$	317	$	—	$	—	$	(258	)	$	59	$	—
Other assets	2		—		—		N/A			2		—
Total assets at fair value	$	319	$	—	$	—	$	(258	)	$	61	$	—
Commodity derivative instruments, liabilities	$	180	$	—	$	—	$	(180	)	$	—	$	—
Contingent consideration, liability(c)	—		—		478		N/A			478		—
Total liabilities at fair value	$	180	$	—	$	478	$	(180	)	$	478	$	—

	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	$	—

^(a)  Represents the impact of netting assets, liabilities and cash collateral when a legal right of offset exists. As of December 31, 2014, cash collateral of $78 million was netted with mark-to-market derivative assets. As of December 31, 2013, cash collateral of $32 million 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 $174 million at December 31, 2014 and $159 million at December 31, 2013 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 liabilities classified as Level 3 in the fair value hierarchy.

(In millions)	2014			2013		2012
Beginning balance	$	625		$	—	$	—
Contingent consideration agreement	—			600		—
Contingent consideration payment	(180		)	—		—
Unrealized and realized losses included in net income	33			25		2
Settlements of derivative instruments	—			—		(2		)
Ending balance	$	478		$	625	$	—

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,
	2014				2013				2012
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Property, plant and equipment, net	$	—	$	—	$	1	$	8	$	—	$	—
Other noncurrent assets	—		11		—		—		—		14

Financial Instruments at Fair Value, Excluding Derivative Financial Instruments and Contingent Consideration

The following table summarizes financial instruments on the basis of their nature, characteristics and risk at December 31, 2014 and 2013, excluding the derivative financial instruments and contingent consideration reported above.

	December 31,
	2014				2013
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial assets:
Investments	$	26	$	2	$	336	$	14
Other	32		32		31		30
Total financial assets	$	58	$	34	$	367	$	44
Financial liabilities:
Long-term debt(a)	$	6,571	$	6,265	$	3,306	$	3,001
Deferred credits and other liabilities	17		17		21		21
Total financial liabilities	$	6,588	$	6,282	$	3,327	$	3,022

^(a)  Excludes capital leases

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Other Items

12 Months Ended

Dec. 31, 2014

Other Income and Expenses [Abstract]

Other Items

Other Items

Net interest and other financial income (costs) was:

(In millions)	2014			2013			2012
Interest income	$	7		$	9		$	6
Interest expense	(229		)	(195		)	(191		)
Interest capitalized	27			28			101
Other financial costs	(21		)	(21		)	(25		)
Net interest and other financial income (costs)	$	(216	)	$	(179	)	$	(109	)

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Fair Value Measurements (Assets Measured At Fair Value On Nonrecurring Basis) (Detail) (Fair Value, Measurements, Nonrecurring, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, plant and equipment, net, fair value	$ 0	$ 1	$ 0
Property, plant and equipment, net, impairment	0	8	0
Other noncurrent assets, fair value	0	0	0
Other noncurrent assets, impairment	11	0
Centennial
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Other noncurrent assets, impairment			$ 14

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Goodwill

12 Months Ended

Dec. 31, 2014

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 2014 and 2013, and no impairment was required.

The changes in the carrying amount of goodwill for 2014 and 2013 were as follows:

(In millions)	Refining & Marketing			Speedway		Pipeline Transportation		Total
2013
Beginning balance	$	551		$	217	$	162	$	930
Acquisitions(a)	—			8		—		8
Ending balance	$	551		$	225	$	162	$	938
2014
Beginning balance	$	551		$	225	$	162	$	938
Acquisitions(a)	—			629		—		629
Disposition	(1		)	—		—		(1		)
Ending balance	$	550		$	854	$	162	$	1,566

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

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Income Taxes (Components Of Income Tax Provisions (Benefits)) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current
Federal	$ 1,382	$ 954	$ 1,185
State and local	135	131	169
Foreign	5	5	(1)
Total	1,522	1,090	1,353
Deferred
Federal	(199)	20	432
State and local	(37)	8	57
Foreign	(6)	(5)	3
Total	(242)	23	492
Total
Federal	1,183	974	1,617
State and local	98	139	226
Foreign	(1)		2
Total	$ 1,280	$ 1,113	$ 1,845

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2014

Property, Plant and Equipment [Abstract]

Summary Of Property, Plant And Equipment

(In millions)	Estimated Useful Lives	December 31,
		2014		2013
Refining & Marketing	4 - 25 years	$	18,001	$	16,982
Speedway	4 - 25 years	4,639		2,344
Pipeline Transportation	16 - 42 years	2,044		1,921
Corporate and Other	4 - 40 years	618		546
Total		25,302		21,793
Less accumulated depreciation		9,041		7,872
Property, plant and equipment, net		$	16,261	$	13,921

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Equity Method Investments (Schedule Of Equity Method Investments) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013	Jul. 01, 2014	Jan. 01, 2017
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 865		$ 463
Centennial
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	50.00%
Equity method investments	36		29
Explorer
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	25.00%
Equity method investments	95		0
Illinois Extension Pipeline Company LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	35.00%			35.00%
Equity method investments	120		0
LOCAP
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	59.00%
Equity method investments	23		24
LOOP
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	51.00%
Equity method investments	230		214
North Dakota Pipeline Class B Units
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	38.00%	[1]
Equity method investments	216	[1]	24
TAAE
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	43.00%
Equity method investments	22		29
TACE
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	60.00%
Equity method investments	61		70
TAEI
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	34.00%
Equity method investments	19		23
TAME
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	67.00%
Equity method investments	24	[2]	35
TAME | Direct Ownership Interest
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	50.00%	[2]
Other equity method investees
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 19		$ 15
North Dakota Pipeline Class A Units | Scenario, Forecast
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage					27.00%

[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, which is expected to be in 2017.

[2] Excludes TAEI’s investment in TAME.

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2014

Related Party Transactions [Abstract]

Sales To Related Parties

Sales to related parties, which are included in sales and other operating revenues (including consumer excise taxes) on the consolidated statements of income, were as follows:

(In millions)	2014		2013		2012
Centennial	$	—	$	—	$	1
Other equity method investees	7		8		7
Total	$	7	$	8	$	8

Purchases From Related Parties

Purchases from related parties were as follows:

(In millions)	2014		2013		2012
Centennial	$	7	$	3	$	7
Explorer	39		—		—
LOCAP	21		17		24
LOOP	88		43		44
TAAE	79		24		—
TACE	121		130		73
TAME	141		131		124
Other equity method investees	9		9		8
Total	$	505	$	357	$	280

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)	2014		2013
Centennial	$	2	$	1
Explorer	2		—
TAME	3		1
Total	$	7	$	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)	2014		2013
Explorer	$	3	$	—
LOCAP	2		2
LOOP	4		3
TAAE	2		2
TACE	2		4
TAME	5		5
Total	$	18	$	16

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Equity Method Investments (Narrative) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Schedule of Equity Method Investments [Line Items]
Equity method investment difference between carrying amount and underlying equity	$ 110
Equity method investment difference between carrying amount and underlying equity, portion related to goodwill which is not being amortized	55
Equity method investments	865	463
Dividends and partnership distributions received from equity method investees	170	18	37
Centennial
Schedule of Equity Method Investments [Line Items]
Equity method investments	36	29
Percent of debt outstanding	50.00%
Master Shelf Agreement | Financial Guarantee | Centennial
Schedule of Equity Method Investments [Line Items]
Maximum potential undiscounted payments	$ 38

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 1,494	$ 2,292
Receivables, less allowance for doubtful accounts of $13 and $9	4,058	5,559
Inventories	5,642	4,689
Other current assets	145	197
Total current assets	11,339	12,737
Equity method investments	865	463
Property, plant and equipment, net	16,261	13,921
Goodwill	1,566	938
Other noncurrent assets	429	326
Total assets	30,460	28,385
Current liabilities:
Accounts payable	6,661	8,234
Payroll and benefits payable	427	406
Consumer excise taxes payable	463	373
Accrued taxes	647	513
Long-term debt due within one year	27	23
Other current liabilities	354	275
Total current liabilities	8,579	9,824
Long-term debt	6,610	3,373
Deferred income taxes	2,014	2,304
Defined benefit postretirement plan obligations	1,099	771
Deferred credits and other liabilities	768	781
Total liabilities	19,070	17,053
Commitments and contingencies (see Note 26)
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 – 363 million and 362 million shares (par value $0.01 per share, 1 billion shares authorized)	4	4
Held in treasury, at cost – 89 million and 65 million shares	(6,299)	(4,155)
Additional paid-in capital	9,844	9,768
Retained earnings	7,515	5,507
Accumulated other comprehensive loss	(313)	(204)
Total MPC stockholders’ equity	10,751	10,920
Noncontrolling interests	639	412
Total equity	11,390	11,332
Total liabilities and equity	$ 30,460	$ 28,385

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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						0 Months Ended	1 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012		Sep. 30, 2014	Feb. 01, 2013
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)									$ 97,817		$ 100,160		$ 82,243
Income from operations	1,259	1,062	1,369	361	1,008	301	960	1,156	4,051		3,425		5,347
Income (loss) from equity method investments									153		36		26
Depreciation and amortization									1,326		1,220		995
Segment capital expenditures and investments									4,738	[1],[2]	2,789	[1],[2]	1,460	[1],[2]
Hess Retail Operations and Related Assets
Segment Reporting Information [Line Items]
Segment capital expenditures and investments									2,710
Galveston Bay Refinery and Related Assets
Segment Reporting Information [Line Items]
Segment capital expenditures and investments											1,360
Refining & Marketing
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)									80,822		85,616		67,928
Speedway
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)									16,927		14,471		14,239
Pipeline Transportation
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)									70		79		78
Reportable Segment
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)									97,819		100,166		82,245
Intersegment Eliminations
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)									11,444	[3]	9,756	[3]	9,167	[3]
Intersegment Eliminations | Refining & Marketing
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)									10,912	[3]	9,294	[3]	8,782	[3]
Intersegment Eliminations | Speedway
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)									5	[3]	4	[3]	4	[3]
Intersegment Eliminations | Pipeline Transportation
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)									527	[3]	458	[3]	381	[3]
Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)									109,263		109,922		91,412
Income from operations									4,433	[4]	3,791	[4]	5,624	[4]
Income (loss) from equity method investments									153		36		26
Depreciation and amortization									1,274	[5]	1,197	[5]	972	[5]
Segment capital expenditures and investments									4,628	[6],[7]	2,624	[6],[8]	1,256	[6]
Operating Segments | Refining & Marketing
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)									91,734		94,910		76,710
Income from operations									3,609	[4]	3,206	[4]	5,098	[4]
Income (loss) from equity method investments									96		28		(6)
Depreciation and amortization									1,045	[5]	1,011	[5]	804	[5]
Segment capital expenditures and investments									1,104	[6],[7]	2,094	[6],[8]	705	[6]
Operating Segments | Refining & Marketing | Hess Retail Operations and Related Assets
Segment Reporting Information [Line Items]
Segment capital expenditures and investments															52
Operating Segments | Refining & Marketing | Galveston Bay Refinery and Related Assets
Segment Reporting Information [Line Items]
Segment capital expenditures and investments																1,290
Operating Segments | Speedway
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)									16,932		14,475		14,243
Income from operations									544	[4]	375	[4]	310	[4]
Income (loss) from equity method investments									0		0		0
Depreciation and amortization									152	[5]	112	[5]	114	[5]
Segment capital expenditures and investments									2,981	[6],[7]	296	[6],[8]	340	[6]
Operating Segments | Speedway | Hess Retail Operations and Related Assets
Segment Reporting Information [Line Items]
Segment capital expenditures and investments															2,660
Operating Segments | Pipeline Transportation
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)									597		537		459
Income from operations									280	[4]	210	[4]	216	[4]
Income (loss) from equity method investments									57		8		32
Depreciation and amortization									77	[5]	74	[5]	54	[5]
Segment capital expenditures and investments									543	[6],[7]	234	[6],[8]	211	[6]
Operating Segments | Pipeline Transportation | Galveston Bay Refinery and Related Assets
Segment Reporting Information [Line Items]
Segment capital expenditures and investments																70
Operating Segments | Pipeline Transportation | MPLX LP
Segment Reporting Information [Line Items]
Cost of services, overhead									$ 19		$ 20		$ 4

[1] Capital expenditures include changes in capital accruals.

[2] Includes $2.71 billion in 2014 for the acquisition of Hess’ Retail Operations and Related Assets and $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5 to the audited consolidated financial statements.

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

[4] Included in the Pipeline Transportation segment for 2014, 2013 and 2012 are $19 million, $20 million and $4 million of corporate overhead expenses attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. Corporate overhead expenses are not currently allocated to other segments.

[5] 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.

[6] Capital expenditures include changes in capital accruals, acquisitions and investments in affiliates.

[7] The Speedway and Refining & Marketing segments include $2.66 billion and $52 million, respectively, for the acquisition of Hess’ Retail Operations and Related Assets. 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.

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Description Of The Business And Basis Of Presentation

12 Months Ended

Dec. 31, 2014

Accounting Policies [Abstract]

Description of the Business and Basis of Presentation

Description of the Business 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 and pipeline transportation operations conducted primarily in the Midwest, Gulf Coast, East Coast and Southeast regions of the United States, through subsidiaries, including Marathon Petroleum Company LP, Speedway LLC and its subsidiaries (“Speedway”) and MPLX LP and its subsidiaries (“MPLX”).

See Note 11 for additional information about our operations.

Spinoff– 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 (the “Spinoff”). MPC became an independent, publicly traded company on July 1, 2011.

Basis of Presentation – Our results of operations and cash flows consist of consolidated MPC activities. All significant intercompany transactions and accounts have been eliminated.

During the first quarter of 2014, we recorded an out-of-period adjustment for additional expenses related to the prior year’s bonus programs of $29 million, included in total costs and expenses on the consolidated statements of income. The impact to our consolidated results of operations for the year ended December 31, 2014 and for the year ended December 31, 2013 was immaterial.

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Leases (Tables)

12 Months Ended

Dec. 31, 2014

Leases [Abstract]

Schedule Of Future Minimum Commitments

Future minimum commitments as of December 31, 2014, 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
2015	$	52	$	249
2016	51		209
2017	50		150
2018	49		136
2019	45		114
Later years	300		468
Total minimum lease payments	547		$	1,326
Less imputed interest costs	176
Present value of net minimum lease payments	$	371

Schedule Of Operating Lease Rental Expense

Operating lease rental expense was:

(In millions)	2014		2013		2012
Rental expense	$	256	$	213	$	139

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Related Party Transactions (Payables To Related Parties) (Detail) (USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Payables to related parties	$ 18	$ 16
Explorer
Related Party Transaction [Line Items]
Payables to related parties	3	0
LOCAP
Related Party Transaction [Line Items]
Payables to related parties	2	2
LOOP
Related Party Transaction [Line Items]
Payables to related parties	4	3
TAAE
Related Party Transaction [Line Items]
Payables to related parties	2	2
TACE
Related Party Transaction [Line Items]
Payables to related parties	2	4
TAME
Related Party Transaction [Line Items]
Payables to related parties	$ 5	$ 5

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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, 2014	Dec. 31, 2013	Dec. 31, 2012
Income statement data:
Revenues and other income	$ 1,430	$ 1,067	$ 1,025
Income from operations	379	87	73
Net income	316	63	47
Balance sheet data – December 31:
Current assets	990	339
Noncurrent assets	2,166	1,238
Current liabilities	280	145
Noncurrent liabilities	$ 957	$ 618

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Acquisitions and Investments (Fair Value of Consideration Transferred - Galveston Bay) (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended				1 Months Ended
	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2012	Feb. 01, 2013
Business Acquisition [Line Items]
Fair value of contingent consideration as of acquisition date	$ 0	$ 600	[1]	$ 0
Payable to seller	0	6	[1]	0
Galveston Bay Refinery and Related Assets
Business Acquisition [Line Items]
Cash paid for acquisition	180				1,491
Fair value of contingent consideration as of acquisition date					600
Payable to seller					6
Post-closing adjustment					(9)
Total fair value of consideration transferred					$ 2,088

[1] See Note 5.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2014

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

Fair Values – Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2014 and 2013 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, 2014
	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	$	317	$	—	$	—	$	(258	)	$	59	$	—
Other assets	2		—		—		N/A			2		—
Total assets at fair value	$	319	$	—	$	—	$	(258	)	$	61	$	—
Commodity derivative instruments, liabilities	$	180	$	—	$	—	$	(180	)	$	—	$	—
Contingent consideration, liability(c)	—		—		478		N/A			478		—
Total liabilities at fair value	$	180	$	—	$	478	$	(180	)	$	478	$	—

	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	$	—

^(a)  Represents the impact of netting assets, liabilities and cash collateral when a legal right of offset exists. As of December 31, 2014, cash collateral of $78 million was netted with mark-to-market derivative assets. As of December 31, 2013, cash collateral of $32 million 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 $174 million at December 31, 2014 and $159 million at December 31, 2013 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, 2014 and 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 $15 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 liabilities classified as Level 3 in the fair value hierarchy.

(In millions)	2014			2013		2012
Beginning balance	$	625		$	—	$	—
Contingent consideration agreement	—			600		—
Contingent consideration payment	(180		)	—		—
Unrealized and realized losses included in net income	33			25		2
Settlements of derivative instruments	—			—		(2		)
Ending balance	$	478		$	625	$	—

We did not hold any Level 3 derivative instruments during 2014, 2013 and 2012. See Note 19 for the income statement impacts of our derivative instruments. There was an unrealized loss of $33 million and $25 million in 2014 and 2013, respectively, 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,
	2014				2013				2012
(In millions)	Fair Value		Impairment		Fair Value		Impairment		Fair Value		Impairment
Property, plant and equipment, net	$	—	$	—	$	1	$	8	$	—	$	—
Other noncurrent assets	—		11		—		—		—		14

Based on the financial and operational status of a company in which we have an interest, we fully impaired our $11 million investment in that company in 2014. Our investment in this company was accounted for using the cost method and was included in our Refining & Marketing segment. The impairment is included in other income on the consolidated statements of income. The fair value of our investment in this cost company was measured using an income approach. This measurement is classified as Level 3.

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 expired March 31, 2014. 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, 2014 and 2013, excluding the derivative financial instruments and contingent consideration reported above.

	December 31,
	2014				2013
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial assets:
Investments	$	26	$	2	$	336	$	14
Other	32		32		31		30
Total financial assets	$	58	$	34	$	367	$	44
Financial liabilities:
Long-term debt(a)	$	6,571	$	6,265	$	3,306	$	3,001
Deferred credits and other liabilities	17		17		21		21
Total financial liabilities	$	6,588	$	6,282	$	3,327	$	3,022

^(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 fixed-rate 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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Derivatives (Classification Of Gross Fair Values Of Derivative Instruments, Excluding Cash Collateral) (Detail) (Commodity derivatives, Other current assets, USD $) In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Commodity derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Asset	$ 317	$ 21
Liability	$ 180	$ 53

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Supplemental Cash Flow Information (Reconciliation Of Additions To Property, Plant And Equipment To Total Capital Expenditures) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Supplemental Cash Flow Information [Abstract]
Additions to property, plant and equipment per consolidated statements of cash flows	$ 1,480		$ 1,206		$ 1,369
Non-cash additions to property, plant and equipment	4		0		0
Asset retirement expenditures	2	[1]	0		0
Increase (decrease) in capital accruals	95		73		(117)
Total capital expenditures before acquisitions	1,581		1,279		1,252
Acquisitions	2,744	[2]	1,386	[2]	180
Total capital expenditures	$ 4,325	[3],[4]	$ 2,665	[3],[4]	$ 1,432	[3],[4]

[1] Included in All other, net – Operating activities on the consolidated statements of cash flows.

[2] The 2014 acquisitions include the acquisition of Hess’ Retail Operations and Related Assets. The 2013 acquisitions include the acquisition of the Galveston Bay Refinery and Related Assets. The acquisition numbers above include property, plant and equipment and intangibles. See Note 5.

[3] See Note 21 for a reconciliation of total capital expenditures to additions to property, plant and equipment as reported in the consolidated statements of cash flows.

[4] Capital expenditures include changes in capital accruals.

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Debt Senior Notes (Details) (Senior Notes, USD $)	12 Months Ended
	Dec. 31, 2014	Sep. 05, 2014
Debt Instrument [Line Items]
Debt instrument, face amount		$ 1,950,000,000
Proceeds from debt	1,920,000,000
3.625% senior notes due September 15, 2024
Debt Instrument [Line Items]
Debt instrument, face amount		750,000,000
4.750% senior notes due September 15, 2044
Debt Instrument [Line Items]
Debt instrument, face amount		800,000,000
5.000% senior notes due September 15, 2054
Debt Instrument [Line Items]
Debt instrument, face amount		$ 400,000,000

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Acquisitions and Investments (Investments in Ethanol Companies) (Details) (USD $) In Millions, unless otherwise specified	1 Months Ended
	Aug. 01, 2013 Company	Dec. 31, 2014
TACE
Business Acquisition [Line Items]
Equity method investments, ownership percentage		60.00%
TAEI
Business Acquisition [Line Items]
Equity method investments, ownership percentage		34.00%
TAME
Business Acquisition [Line Items]
Equity method investments, ownership percentage		67.00%
TAME | TAEI
Business Acquisition [Line Items]
Equity method investments, ownership percentage		50.00%
TAAE
Business Acquisition [Line Items]
Equity method investments, ownership percentage		43.00%
Ethanol Interests From Mitsui
Business Acquisition [Line Items]
Number of businesses in which ownership interests acquired	3
Cash paid to acquire equity method investments	$ 75
Ethanol Interests From Mitsui | TACE
Business Acquisition [Line Items]
Ownership percentage acquired	24.00%
Ethanol Interests From Mitsui | TAEI
Business Acquisition [Line Items]
Ownership percentage acquired	34.00%
Ethanol Interests From Mitsui | TAAE
Business Acquisition [Line Items]
Ownership percentage acquired	40.00%

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Supplementary Statistics (Operating Statistics) (Detail) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Operating Statistics [Line Items ]
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)	2,138,000	[1],[2]	2,086,000	[1],[2]	1,618,000	[1],[2]
Refining & Marketing
Refining & Marketing Operating Statistics
Refining & Marketing refined product sales volume (thousands of barrels per day)	2,125,000	[1],[3]	2,075,000	[1],[3]	1,599,000	[1],[3]
Refining & Marketing gross margin (dollars per barrel)	15.05	[1],[4]	13.24	[1],[4]	17.85	[1],[4]
Crude oil capacity utilization percent	95.00%	[1],[5]	96.00%	[1],[5]	100.00%	[1],[5]
Refinery throughputs (thousands of barrels per day)	1,806,000	[1],[6]	1,802,000	[1],[6]	1,363,000	[1],[6]
Sour crude oil throughput percent	52.00%	[1]	53.00%	[1]	53.00%	[1]
WTI-priced crude oil throughput percent	19.00%	[1]	21.00%	[1]	28.00%	[1]
Refined product yields (thousands of barrels per day)	1,839,000	[1],[6]	1,836,000	[1],[6]	1,386,000	[1],[6]
Refinery direct operating costs (dollars per barrel):
Planned turnaround and major maintenance	1.80	[1],[7]	1.20	[1],[7]	1.00	[1],[7]
Depreciation and amortization	1.41	[1],[7]	1.36	[1],[7]	1.44	[1],[7]
Other manufacturing	4.86	[1],[7],[8]	4.14	[1],[7],[8]	3.15	[1],[7],[8]
Total	8.07	[1],[7]	6.70	[1],[7]	5.59	[1],[7]
Pipeline Transportation Operating Statistics
Inter-refinery transfers	43,000		36,000		25,000
Refining & Marketing | Gulf Coast:
Refining & Marketing Operating Statistics
Refinery throughputs (thousands of barrels per day)	1,173,000	[1],[9]	1,159,000	[1],[9]
Sour crude oil throughput percent	64.00%	[1]	65.00%	[1]
WTI-priced crude oil throughput percent	3.00%	[1]	7.00%	[1]
Refined product yields (thousands of barrels per day)	1,199,000	[1],[9]	1,186,000	[1],[9]
Refinery direct operating costs (dollars per barrel):
Planned turnaround and major maintenance	1.82	[1],[7]	1.00	[1],[7]
Depreciation and amortization	1.15	[1],[7]	1.09	[1],[7]
Other manufacturing	4.73	[1],[7],[8]	3.98	[1],[7],[8]
Total	7.70	[1],[7]	6.07	[1],[7]
Refining & Marketing | Midwest:
Refining & Marketing Operating Statistics
Refinery throughputs (thousands of barrels per day)	676,000	[9]	679,000	[9]
Sour crude oil throughput percent	33.00%		35.00%
WTI-priced crude oil throughput percent	44.00%		42.00%
Refined product yields (thousands of barrels per day)	683,000	[9]	686,000	[9]
Refinery direct operating costs (dollars per barrel):
Planned turnaround and major maintenance	1.66	[7]	1.47	[7]
Depreciation and amortization	1.78	[7]	1.74	[7]
Other manufacturing	4.76	[7],[8]	4.21	[7],[8]
Total	8.20	[7]	7.42	[7]
Refining & Marketing | Crude oil refined
Refining & Marketing Operating Statistics
Refinery throughputs (thousands of barrels per day)	1,622,000	[1],[5]	1,589,000	[1],[5]	1,195,000	[1],[5]
Refining & Marketing | Crude oil refined | Gulf Coast:
Refining & Marketing Operating Statistics
Refinery throughputs (thousands of barrels per day)	991,000	[1],[9]	964,000	[1],[9]
Refining & Marketing | Crude oil refined | Midwest:
Refining & Marketing Operating Statistics
Refinery throughputs (thousands of barrels per day)	631,000	[9]	625,000	[9]
Refining & Marketing | Other charge and blendstocks
Refining & Marketing Operating Statistics
Refinery throughputs (thousands of barrels per day)	184,000	[1],[5]	213,000	[1],[5]	168,000	[1],[5]
Refining & Marketing | Other charge and blendstocks | Gulf Coast:
Refining & Marketing Operating Statistics
Refinery throughputs (thousands of barrels per day)	182,000	[1],[9]	195,000	[1],[9]
Refining & Marketing | Other charge and blendstocks | Midwest:
Refining & Marketing Operating Statistics
Refinery throughputs (thousands of barrels per day)	45,000	[9]	54,000	[9]
Refining & Marketing | Gasoline
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	869,000	[1],[6]	921,000	[1],[6]	738,000	[1],[6]
Refining & Marketing | Gasoline | Gulf Coast:
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	508,000	[1],[9]	551,000	[1],[9]
Refining & Marketing | Gasoline | Midwest:
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	361,000	[9]	371,000	[9]
Refining & Marketing | Distillates
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	580,000	[1],[6]	572,000	[1],[6]	433,000	[1],[6]
Refining & Marketing | Distillates | Gulf Coast:
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	368,000	[1],[9]	365,000	[1],[9]
Refining & Marketing | Distillates | Midwest:
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	212,000	[9]	207,000	[9]
Refining & Marketing | Propane
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	35,000	[1],[6]	37,000	[1],[6]	26,000	[1],[6]
Refining & Marketing | Propane | Gulf Coast:
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	23,000	[1],[9]	23,000	[1],[9]
Refining & Marketing | Propane | Midwest:
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	13,000	[9]	14,000	[9]
Refining & Marketing | Feedstocks and special products
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	276,000	[1],[6]	221,000	[1],[6]	109,000	[1],[6]
Refining & Marketing | Feedstocks and special products | Gulf Coast:
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	274,000	[1],[9]	215,000	[1],[9]
Refining & Marketing | Feedstocks and special products | Midwest:
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	43,000	[9]	41,000	[9]
Refining & Marketing | Heavy fuel oil
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	25,000	[1],[6]	31,000	[1],[6]	18,000	[1],[6]
Refining & Marketing | Heavy fuel oil | Gulf Coast:
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	13,000	[1],[9]	19,000	[1],[9]
Refining & Marketing | Heavy fuel oil | Midwest:
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	13,000	[9]	12,000	[9]
Refining & Marketing | Asphalt
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	54,000	[1],[6]	54,000	[1],[6]	62,000	[1],[6]
Refining & Marketing | Asphalt | Gulf Coast:
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	13,000	[1],[9]	13,000	[1],[9]
Refining & Marketing | Asphalt | Midwest:
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	41,000	[9]	41,000	[9]
Speedway
Speedway Operating Statistics(j)
Convenience stores at period-end	2,746	[10]	1,478		1,464
Gasoline and distillate sales (millions of gallons)	3,942,000,000	[10]	3,146,000,000		3,027,000,000
Gasoline and distillate gross margin (dollars per gallon)	0.1775	[10],[11]	0.1441	[11]	0.1318	[11]
Merchandise sales (in millions)	3,611	[10]	3,135		3,058
Merchandise gross margin (in millions)	975	[10]	825		795
Merchandise margin percent	27.00%	[10]	26.30%		26.00%
Same store gasoline sales volume (period over period) percentage	(0.70%)	[10]	0.50%		(0.80%)
Merchandise sales excluding cigarettes (period over period) percentage	5.00%	[10],[12]	4.30%	[12]	7.00%	[12]
Pipeline Transportation
Pipeline Transportation Operating Statistics
Pipeline throughputs (thousands of barrels per day)	2,119,000	[13]	2,204,000	[13]	2,171,000	[13]
Pipeline Transportation | Crude oil pipelines
Pipeline Transportation Operating Statistics
Pipeline throughputs (thousands of barrels per day)	1,241,000	[13]	1,293,000	[13]	1,191,000	[13]
Pipeline Transportation | Refined products pipelines
Pipeline Transportation Operating Statistics
Pipeline throughputs (thousands of barrels per day)	878,000	[13]	911,000	[13]	980,000	[13]

[1] Includes the impact of the Galveston Bay Refinery and Related Assets beginning on the February 1, 2013 acquisition date.

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

[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 43 thousand barrels per day (“mbpd”), 36 mbpd and 25 mbpd for 2014, 2013 and 2012, 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] Includes the impact of Hess’ Retail Operations and Related Assets beginning on the September 30, 2014 acquisition date.

[11] 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.

[12] Excludes cigarettes.

[13] On owned common-carrier pipelines, excluding equity method investments.

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Supplementary Statistics

12 Months Ended

Dec. 31, 2014

Text Block [Abstract]

Supplementary Statistics

Supplementary Statistics (Unaudited)

(In millions)	2014			2013			2012
Income from Operations by segment
Refining & Marketing	$	3,609		$	3,206		$	5,098
Speedway	544			375			310
Pipeline Transportation(a)	280			210			216
Items not allocated to segments:
Corporate and other unallocated items(a)	(286		)	(271		)	(336		)
Minnesota Assets sale settlement gain	—			—			183
Pension settlement expenses	(96		)	(95		)	(124		)
Income from operations	$	4,051		$	3,425		$	5,347
Capital Expenditures and Investments(b)(c)
Refining & Marketing	$	1,104		$	2,094		$	705
Speedway	2,981			296			340
Pipeline Transportation	543			234			211
Corporate and Other(d)	110			165			204
Total	$	4,738		$	2,789		$	1,460

^(a)  Included in the Pipeline Transportation segment for 2014, 2013 and 2012 are $19 million, $20 million and $4 million of corporate overhead expenses attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. Corporate overhead expenses are not currently allocated to other segments.

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

^(c)  Includes $2.71 billion in 2014 for the acquisition of Hess’ Retail Operations and Related Assets and $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5 to the audited consolidated financial statements.

^(d)  Includes capitalized interest of $27 million, $28 million and $101 million for 2014, 2013 and 2012, respectively.

Supplementary Statistics (Unaudited)

	2014		2013		2012
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)(a)(b)	2,138		2,086		1,618
Refining & Marketing Operating Statistics(b)
Refining & Marketing refined product sales volume (thousands of barrels per day)(c)	2,125		2,075		1,599
Refining & Marketing gross margin (dollars per barrel)(d)	$	15.05	$	13.24	$	17.85
Crude oil capacity utilization percent(e)	95		96		100
Refinery throughputs (thousands of barrels per day):(f)
Crude oil refined	1,622		1,589		1,195
Other charge and blendstocks	184		213		168
Total	1,806		1,802		1,363
Sour crude oil throughput percent	52		53		53
WTI-priced crude oil throughput percent	19		21		28
Refined product yields (thousands of barrels per day):(f)
Gasoline	869		921		738
Distillates	580		572		433
Propane	35		37		26
Feedstocks and special products	276		221		109
Heavy fuel oil	25		31		18
Asphalt	54		54		62
Total	1,839		1,836		1,386
Refinery direct operating costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.80	$	1.20	$	1.00
Depreciation and amortization	1.41		1.36		1.44
Other manufacturing(h)	4.86		4.14		3.15
Total	$	8.07	$	6.70	$	5.59
Refining & Marketing Operating Statistics By Region – Gulf Coast(b)
Refinery throughputs (thousands of barrels per day):(i)
Crude oil refined	991		964
Other charge and blendstocks	182		195
Total	1,173		1,159
Sour crude oil throughput percent	64		65
WTI-priced crude oil throughput percent	3		7
Refined product yields (thousands of barrels per day):(i)
Gasoline	508		551
Distillates	368		365
Propane	23		23
Feedstocks and special products	274		215
Heavy fuel oil	13		19
Asphalt	13		13
Total	1,199		1,186
Refinery direct operating costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.82	$	1.00
Depreciation and amortization	1.15		1.09
Other manufacturing(h)	4.73		3.98
Total	$	7.70	$	6.07

Supplementary Statistics (Unaudited)
	2014			2013			2012
Refining & Marketing Operating Statistics By Region – Midwest
Refinery throughputs (thousands of barrels per day):(i)
Crude oil refined	631			625
Other charge and blendstocks	45			54
Total	676			679
Sour crude oil throughput percent	33			35
WTI-priced crude oil throughput percent	44			42
Refined product yields (thousands of barrels per day):(i)
Gasoline	361			371
Distillates	212			207
Propane	13			14
Feedstocks and special products	43			41
Heavy fuel oil	13			12
Asphalt	41			41
Total	683			686
Refinery direct operating costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.66		$	1.47
Depreciation and amortization	1.78			1.74
Other manufacturing(h)	4.76			4.21
Total	$	8.20		$	7.42
Speedway Operating Statistics(j)
Convenience stores at period-end	2,746			1,478			1,464
Gasoline and distillate sales (millions of gallons)	3,942			3,146			3,027
Gasoline & distillate gross margin (dollars per gallon)(k)	$	0.1775		$	0.1441		$	0.1318
Merchandise sales (in millions)	$	3,611		$	3,135		$	3,058
Merchandise gross margin (in millions)	$	975		$	825		$	795
Merchandise gross margin percent	27.0		%	26.3		%	26.0		%
Same store gasoline sales volume (period over period)	(0.7		)%	0.5		%	(0.8		)%
Same store merchandise sales (period over period)(l)	5.0		%	4.3		%	7.0		%
Pipeline Transportation Operating Statistics
Pipeline throughputs (thousands of barrels per day):(m)
Crude oil pipelines	1,241			1,293			1,191
Refined products pipelines	878			911			980
Total	2,119			2,204			2,171

^(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 43 thousand barrels per day (“mbpd”), 36 mbpd and 25 mbpd for 2014, 2013 and 2012, 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)  Includes the impact of Hess’ Retail Operations and Related Assets beginning on the September 30, 2014 acquisition date.

^(k)  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.

^(l)  Excludes cigarettes.

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

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Segment Information

12 Months Ended

Dec. 31, 2014

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 it offers.

• 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, East Coast and Southeast.

• 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.

On September 30, 2014, we acquired Hess’ Retail Operations and Related Assets, which are part of the Speedway and Refining & Marketing segments. 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 each 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 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, 2014
Revenues:
Customer	$	80,822	$	16,927	$	70	$	97,819
Intersegment(a)	10,912		5		527		11,444
Segment revenues	$	91,734	$	16,932	$	597	$	109,263
Segment income from operations(b)	$	3,609	$	544	$	280	$	4,433
Income from equity method investments	96		—		57		153
Depreciation and amortization(c)	1,045		152		77		1,274
Capital expenditures and investments(d)(e)	1,104		2,981		543		4,628

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
Year Ended December 31, 2013
Revenues:
Customer	$	85,616	$	14,471	$	79	$	100,166
Intersegment(a)	9,294		4		458		9,756
Segment revenues	$	94,910	$	14,475	$	537	$	109,922
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)(f)	2,094		296		234		2,624

(In millions)	Refining & Marketing			Speedway		Pipeline Transportation		Total
Year Ended December 31, 2012
Revenues:
Customer	$	67,928		$	14,239	$	78	$	82,245
Intersegment(a)	8,782			4		381		9,167
Segment revenues	$	76,710		$	14,243	$	459	$	91,412
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)	705			340		211		1,256

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

^(b)  Included in the Pipeline Transportation segment for 2014, 2013 and 2012 are $19 million, $20 million and $4 million of corporate overhead expenses attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. Corporate overhead 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, acquisitions and investments in affiliates.

^(e)  The Speedway and Refining & Marketing segments include $2.66 billion and $52 million, respectively, for the acquisition of Hess’ Retail Operations and Related Assets. 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)	2014			2013			2012
Segment income from operations	$	4,433		$	3,791		$	5,624
Items not allocated to segments:
Corporate and other unallocated items(a)(b)	(286		)	(271		)	(336		)
Minnesota Assets sale settlement gain(c)	—			—			183
Pension settlement expenses(d)	(96		)	(95		)	(124		)
Net interest and other financial income (costs)	(216		)	(179		)	(109		)
Income before income taxes	$	3,835		$	3,246		$	5,238

^(a)  Corporate and other unallocated items consists primarily of MPC’s corporate administrative expenses and costs related to certain non-operating assets.

^(b)  Corporate overhead expenses attributable to MPLX were included in the Pipeline Transportation segment subsequent to MPLX’s October 31, 2012 initial public offering. Corporate overhead expenses are not allocated to the Refining & Marketing and Speedway segments.

^(c)  See Note 6.

^(d)  See Note 23.

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

(In millions)	2014		2013		2012
Segment capital expenditures and investments	$	4,628	$	2,624	$	1,256
Less: Investments in equity method investees	413		124		28
Plus: Items not allocated to segments:
Capital expenditures not allocated to segments	83		137		103
Capitalized interest	27		28		101
Total capital expenditures(a)(b)	$	4,325	$	2,665	$	1,432

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

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

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

(In millions)	2014			2013			2012
Customer revenues	$	97,819		$	100,166		$	82,245
Corporate and other unallocated items	(2		)	(6		)	(2		)
Sales and other operating revenues (including consumer excise taxes)	$	97,817		$	100,160		$	82,243

Revenues by product line were:

(In millions)	2014		2013		2012
Refined products	$	90,702	$	93,520	$	76,234
Merchandise	3,817		3,308		3,229
Crude oil and refinery feedstocks	2,917		2,988		2,514
Transportation and other	381		344		266
Sales and other operating revenues (including consumer excise taxes)	$	97,817	$	100,160	$	82,243

No single customer accounted for more than 10 percent of annual revenues for the years ended December 31, 2014 and 2012. 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.

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)	2014		2013
Refining & Marketing	$	19,751	$	19,573
Speedway	5,296		2,064
Pipeline Transportation	2,407		1,947
Corporate and Other	3,006		4,801
Total consolidated assets	$	30,460	$	28,385

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Income Taxes (Summary Of Income Tax Returns Subject To Examination) (Detail)	12 Months Ended
	Dec. 31, 2014
United States Federal | Minimum
Income Tax Examination [Line Items]
Tax years	2010
United States Federal | Maximum
Income Tax Examination [Line Items]
Tax years	2013
States | Minimum
Income Tax Examination [Line Items]
Tax years	2004
States | Maximum
Income Tax Examination [Line Items]
Tax years	2013