10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended March 31, 2014

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

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, Ohio	45840-3229
(Address of principal executive offices)	(Zip code)

(419) 422-2121

(Registrant’s telephone number, including area code)

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 (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes  x    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  x    No  ¨

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

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

There were 288,632,472 shares of Marathon Petroleum Corporation common stock outstanding as of April 30, 2014.

MARATHON PETROLEUM CORPORATION

Form 10-Q

Quarter Ended March 31, 2014

INDEX

	Page
PART I – FINANCIAL INFORMATION
Item 1.   Financial Statements:
Consolidated Statements of Income (Unaudited)	2
Consolidated Statements of Comprehensive Income (Unaudited)	3
Consolidated Balance Sheets (Unaudited)	4
Consolidated Statements of Cash Flows (Unaudited)	5
Consolidated Statements of Equity (Unaudited)	6
Notes to Consolidated Financial Statements (Unaudited)	7
Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.   Quantitative and Qualitative Disclosures about Market Risk	38
Item 4.   Controls and Procedures	39
Supplementary Statistics (Unaudited)	40
PART II – OTHER INFORMATION
Item 1.    Legal Proceedings	43
Item 1A. Risk Factors	43
Item 2.    Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 6.    Exhibits	45
Signatures	46

Unless otherwise stated or the context otherwise indicates, all references in this Form 10-Q to “MPC,” “us,” “our,” “we” or “the Company” mean Marathon Petroleum Corporation and its consolidated subsidiaries.

1

Part I – Financial Information

Item 1. Financial Statements

Marathon Petroleum Corporation

Consolidated Statements of Income (Unaudited)

	Three Months Ended   March 31,
(In millions, except per share data)	2014			2013
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$	23,285		$	23,330
Income from equity method investments	35			—
Net gain on disposal of assets	1			1
Other income	24			14
Total revenues and other income	23,345			23,345
Costs and expenses:
Cost of revenues (excludes items below)	20,540			20,034
Purchases from related parties	159			72
Consumer excise taxes	1,515			1,458
Depreciation and amortization	320			287
Selling, general and administrative expenses	346			249
Other taxes	104			89
Total costs and expenses	22,984			22,189
Income from operations	361			1,156
Net interest and other financial income (costs)	(46		)	(48		)
Income before income taxes	315			1,108
Provision for income taxes	108			378
Net income	207			730
Less net income attributable to noncontrolling interests	8			5
Net income attributable to MPC	$	199		$	725
Per Share Data (See Note 6)
Basic:
Net income attributable to MPC per share	$	0.68		$	2.19
Weighted average shares outstanding	293			331
Diluted:
Net income attributable to MPC per share	$	0.67		$	2.17
Weighted average shares outstanding	295			333
Dividends paid	$	0.42		$	0.35

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

2

Marathon Petroleum Corporation

Consolidated Statements of Comprehensive Income (Unaudited)

	Three Months Ended   March 31,
(In millions)	2014			2013
Net income	$	207		$	730
Other comprehensive income (loss):
Defined benefit postretirement and post-employment plans:
Actuarial changes, net of tax of $4 and $54	7			90
Prior service costs, net of tax of ($5) and ($5)	(8		)	(8		)
Other comprehensive income (loss)	(1		)	82
Comprehensive income	206			812
Less comprehensive income attributable to noncontrolling interests	8			5
Comprehensive income attributable to MPC	$	198		$	807

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

3

Marathon Petroleum Corporation

Consolidated Balance Sheets (Unaudited)

(In millions, except per share data)	March 31, 2014			December 31, 2013
Assets
Current assets:
Cash and cash equivalents	$	2,166		$	2,292
Receivables, less allowance for doubtful accounts of $9 and $9	5,420			5,559
Inventories	5,689			4,689
Other current assets	173			197
Total current assets	13,448			12,737
Equity method investments	602			463
Property, plant and equipment, net	13,854			13,921
Goodwill	938			938
Other noncurrent assets	317			326
Total assets	$	29,159		$	28,385
Liabilities
Current liabilities:
Accounts payable	$	9,313		$	8,234
Payroll and benefits payable	259			406
Consumer excise taxes payable	371			373
Accrued taxes	614			513
Long-term debt due within one year	24			23
Other current liabilities	265			275
Total current liabilities	10,846			9,824
Long-term debt	3,635			3,373
Deferred income taxes	2,290			2,304
Defined benefit postretirement plan obligations	855			771
Deferred credits and other liabilities	775			781
Total liabilities	18,401			17,053
Commitments and contingencies (see Note 20)
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 - 73 million and 65 million shares	(4,849		)	(4,155		)
Additional paid-in capital	9,803			9,768
Retained earnings	5,591			5,507
Accumulated other comprehensive loss	(205		)	(204		)
Total MPC stockholders’ equity	10,344			10,920
Noncontrolling interests	414			412
Total equity	10,758			11,332
Total liabilities and equity	$	29,159		$	28,385

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

4

Marathon Petroleum Corporation

Consolidated Statements of Cash Flows (Unaudited)

	Three Months Ended   March 31,
(In millions)	2014			2013
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	207		$	730
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	320			287
Pension and other postretirement benefits, net	82			28
Deferred income taxes	(14		)	6
Net gain on disposal of assets	(1		)	(1		)
Equity method investments, net	6			4
Changes in the fair value of derivative instruments	(25		)	(57		)
Changes in:
Current receivables	139			(884		)
Inventories	(1,000		)	(517		)
Current accounts payable and accrued liabilities	1,011			2,491
All other, net	41			(8		)
Net cash provided by operating activities	766			2,079
Investing activities:
Additions to property, plant and equipment	(267		)	(195		)
Acquisitions	—			(1,493		)
Disposal of assets	2			3
Investments—acquisitions, loans and contributions	(123		)	(21		)
—redemptions and repayments	—			11
All other, net	28			13
Net cash used in investing activities	(360		)	(1,682		)
Financing activities:
Long-term debt – borrowings	270			—
– repayments	(6		)	(5		)
Debt issuance costs	—			(2		)
Issuance of common stock	13			28
Common stock repurchased	(689		)	(431		)
Dividends paid	(123		)	(116		)
Distributions to noncontrolling interests	(6		)	(4		)
All other, net	9			10
Net cash used in financing activities	(532		)	(520		)
Net decrease in cash and cash equivalents	(126		)	(123		)
Cash and cash equivalents at beginning of period	2,292			4,860
Cash and cash equivalents at end of period	$	2,166		$	4,737

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

5

Marathon Petroleum Corporation

Consolidated Statements of Equity (Unaudited)

	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, 2012	$	4	$	(1,253	)	$	9,527	$	3,880		$	(464	)	$	411		$	12,105
Net income	—		—			—		725			—			5			730
Dividends declared	—		—			—		(116		)	—			—			(116		)
Distributions to noncontrolling interests	—		—			—		—			—			(4		)	(4		)
Other comprehensive income	—		—			—		—			82			—			82
Shares repurchased	—		(531		)	100		—			—			—			(431		)
Shares issued (returned) - stock based compensation	—		(3		)	27		—			—			—			24
Stock-based compensation	—		—			22		—			—			—			22
Balance as of March 31, 2013	$	4	$	(1,787	)	$	9,676	$	4,489		$	(382	)	$	412		$	12,412
Balance as of December 31, 2013	$	4	$	(4,155	)	$	9,768	$	5,507		$	(204	)	$	412		$	11,332
Net income	—		—			—		199			—			8			207
Dividends declared	—		—			—		(124		)	—			—			(124		)
Distributions to noncontrolling interests	—		—			—		—			—			(6		)	(6		)
Other comprehensive income	—		—			—		—			(1		)	—			(1		)
Shares repurchased	—		(689		)	—		—			—			—			(689		)
Shares issued (returned)—stock based compensation	—		(5		)	14		—			—			—			9
Stock-based compensation	—		—			21		—			—			—			21
Other	—		—			—		9			—			—			9
Balance as of March 31, 2014	$	4	$	(4,849	)	$	9,803	$	5,591		$	(205	)	$	414		$	10,758
(Shares in millions)	Common Stock		Treasury Stock
Balance as of December 31, 2012	361		(28		)
Shares repurchased	—		(6		)
Balance as of March 31, 2013	361		(34		)
Balance as of December 31, 2013	362		(65		)
Shares repurchased	—		(8		)
Shares issued—stock-based compensation	1		—
Balance as of March 31, 2014	363		(73		)

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

6

Notes to Consolidated Financial Statements (Unaudited)

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

See Note 8 for additional information about our operations.

Basis of Presentation—All significant intercompany transactions and accounts have been eliminated.

These interim consolidated financial statements are unaudited; however, in the opinion of our management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported. All such adjustments are of a normal, recurring nature unless otherwise disclosed. These interim consolidated financial statements, including the notes, have been prepared in accordance with the rules of the Securities and Exchange Commission applicable to interim period financial statements and do not include all of the information and disclosures required by United States generally accepted accounting principles (“US GAAP”) for complete financial statements.

These interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2013. The results of operations for the three months ended March 31, 2014 are not necessarily indicative of the results to be expected for the full year.

During the three months ended March 31, 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 three months ended March 31, 2014 and for the year ended December 31, 2013 was immaterial. We do not expect this adjustment to have a material impact to our results of operations for the year ended December 31, 2014.

2. Accounting Standards

Not Yet Adopted

In April 2014, the Financial Accounting Standards Board ("FASB") issued an accounting standards update which 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(s) of an entity or the classification of a component(s) of an entity as held for sale which 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.

3. 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. We own a 73.6 percent interest in MPLX, including the two percent general partner interest. We consolidate this entity for financial reporting purposes since we have a controlling financial interest, and we record a noncontrolling interest for the interest owned by the public.

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.

7

Effective March 1, 2014, we sold MPLX a 13 percent interest in Pipe Line Holdings for $310 million, increasing MPLX's ownership interest in Pipe Line Holdings to 69 percent. MPLX financed this transaction with $40 million of cash on-hand and $270 million of borrowings on its bank revolving credit agreement.

The sales of interests in Pipeline Holdings to MPLX resulted in a change of our ownership in Pipeline Holdings, but not a change in control. We accounted for the sales as equity transactions, with the excess cash paid over historical carrying value recorded as a change within equity. We did not record a gain or loss on the transactions.

4. Acquisitions and Investments

Acquisition of Refinery and Related Logistics and Marketing Assets

On February 1, 2013, we acquired from BP Products North America Inc. and BP Pipelines (North America) Inc. (collectively, “BP”) the 451,000 barrel per calendar day refinery in Texas City, Texas, three intrastate natural gas liquid pipelines originating at the refinery, four light product terminals, branded-jobber marketing contract assignments for the supply of approximately 1,200 branded sites, a 1,040 megawatt electric cogeneration facility and a 50,000 barrel per day allocation of space on 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, subject to certain conditions. During the second quarter of 2014, we expect to pay BP approximately $178 million for the first year's contingent earnout. See Note 13 for additional information on the contingent consideration.

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

(In millions, except per share data)	Three Months Ended March 31, 2013
Sales and other operating revenues (including consumer excise taxes)	$	25,296
Net income attributable to MPC	780
Net income attributable to MPC per share - basic	$	2.36
Net income attributable to MPC per share - diluted	2.34

The pro forma information includes adjustments to align accounting policies, an adjustment to depreciation expense to reflect the fair value of property, plant and equipment, increased amortization expense related to identifiable intangible assets and the related income tax effects.

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, which is deductible for income tax purposes.

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

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

Investments in Ethanol Companies

On August 1, 2013, we acquired from Mitsui & Co. (U.S.A.), Inc. its interests in three ethanol companies for $75 million. Under the purchase agreement, we acquired an additional 24 percent interest in The Andersons Clymers Ethanol LLC ("TACE"), bringing our ownership interest to 60 percent; a 34 percent interest in The Andersons Ethanol Investment LLC, 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.

8

Investments in Pipeline Companies

We made contributions of $37 million to North Dakota Pipeline Company LLC ("North Dakota Pipeline") during the three months ended March 31, 2014. We have contributed $61 million since project inception. These contributions funded 37.5 percent of the construction costs incurred to-date on the Sandpiper pipeline project. In conjunction with our commitment to be an anchor shipper for the Sandpiper pipeline and our investment in the project, we will earn an approximate 27 percent equity interest in Enbridge Energy Partner L.P.'s North Dakota System when the Sandpiper pipeline is placed into service, which is projected to occur in 2016. We also have the option to increase our ownership interest to approximately 30 percent through additional investments in future system improvements. We account for our interest in North Dakota Pipeline using the equity method of accounting. See Note 20 for information on future contributions to North Dakota Pipeline.

In March 2014, we acquired from Chevron Raven Ridge Pipe Line Company an additional 7 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.

5. Related Party Transactions

Our related parties include:

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

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

• 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.

• Other equity method investees.

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:

	Three Months Ended   March 31,
(In millions)	2014		2013
Other equity method investees	$	2	$	2

Purchases from related parties were as follows:

	Three Months Ended   March 31,
(In millions)	2014		2013
Centennial	$	9	$	—
Explorer	13		—
LOCAP	5		4
LOOP	53		10
TAAE	16		—
TACE	27		26
TAME	34		30
Other equity method investees	2		2
Total	$	159	$	72

9

Related party purchases from Centennial consist primarily of refinery feedstocks. 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 and crude oil purchases. Related party purchases from TAAE, TACE and TAME consist of ethanol.

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

(In millions)	March 31, 2014		December 31, 2013
Centennial	$	—	$	1
Explorer	5		—
TAME	—		1
Total	$	5	$	2

We also had a long-term receivable from Centennial of $2 million at March 31, 2014 and December 31, 2013, which is included in other noncurrent assets on the consolidated balance sheets.

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

(In millions)	March 31, 2014		December 31, 2013
Explorer	$	4	$	—
LOCAP	2		2
LOOP	4		3
TAAE	2		2
TACE	4		4
TAME	7		5
Total	$	23	$	16

6. 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.

Excluded from the diluted share calculation for both the three months ended March 31, 2014 and 2013 are less than one million shares related to stock-based compensation awards as their effect would be anti-dilutive.

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

10

	Three Months Ended   March 31,
(In millions, except per share data)	2014		2013
Basic earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	199	$	725
Income allocated to participating securities	—		1
Income available to common stockholders - basic	$	199	$	724
Weighted average common shares outstanding	293		331
Basic earnings per share	$	0.68	$	2.19
Diluted earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	199	$	725
Income allocated to participating securities	—		1
Income available to common stockholders - diluted	$	199	$	724
Weighted average common shares outstanding	293		331
Effect of dilutive securities	2		2
Weighted average common shares, including dilutive effect	295		333
Diluted earnings per share	$	0.67	$	2.17

7. Equity

Our board of directors has approved $6.0 billion in total share repurchase authorizations since January 1, 2012. As of March 31, 2014, we have repurchased a total of $4.83 billion of our common stock under these authorizations, leaving $1.17 billion available for repurchases through September 2015. Under these authorizations, we have acquired 73 million shares at an average cost per share of $66.19.

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.

Total share repurchases were as follows for the three months ended March 31, 2014 and 2013:

	Three Months Ended   March 31,
(In millions, except per share data)	2014		2013
Number of shares repurchased(a)	8		6
Cash paid for shares repurchased	$	689	$	431
Effective average cost per delivered share	$	87.60	$	80.95

^(a)  The three months ended March 31, 2013 includes one million shares received under the November 2012 accelerated share repurchase program, which were paid for in the fourth quarter of 2012.

At March 31, 2014, we had agreements to acquire additional common shares for $12 million, which were settled in early April 2014.

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8. Segment Information

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

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

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

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

On February 1, 2013, we acquired the Galveston Bay Refinery and Related Assets, which are part of the Refining & Marketing and Pipeline Transportation segments. Segment information for the period prior to the acquisition does not include amounts for these operations. See Note 4.

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
Three Months Ended March 31, 2014
Revenues:
Customer	$	19,810	$	3,458	$	17	$	23,285
Intersegment(a)	2,233		1		129		2,363
Segment revenues	$	22,043	$	3,459	$	146	$	25,648
Segment income from operations(b)	$	362	$	58	$	72	$	492
Income from equity method investments	24		—		11		35
Depreciation and amortization(c)	261		28		19		308
Capital expenditures and investments(d)	178		32		130		340

(In millions)	Refining & Marketing			Speedway		Pipeline Transportation		Total
Three Months Ended March 31, 2013
Revenues:
Customer	$	19,874		$	3,441	$	21	$	23,336
Intersegment(a)	2,199			1		104		2,304
Segment revenues	$	22,073		$	3,442	$	125	$	25,640
Segment income from operations(b)	$	1,105		$	67	$	51	$	1,223
Income (loss) from equity method investments	(4		)	—		4		—
Depreciation and amortization(c)	236			27		18		281
Capital expenditures and investments(d)(e)	1,420			36		90		1,546

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

^(b)  Corporate overhead costs attributable to MPLX are included in the Pipeline Transportation segment. These expenses are not allocated to the Refining & Marketing and Speedway segments.

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

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

^(e)  The Refining & Marketing and Pipeline Transportation segments include the acquisition of the Galveston Bay Refinery and Related Assets. See Note 4.

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

	Three Months Ended   March 31,
(In millions)	2014			2013
Segment income from operations	$	492		$	1,223
Items not allocated to segments:
Corporate and other unallocated items(a)(b)	(67		)	(67		)
Pension settlement expenses(c)	(64		)	—
Net interest and other financial income (costs)	(46		)	(48		)
Income before income taxes	$	315		$	1,108

^(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 costs attributable to MPLX are included in the Pipeline Transportation segment. These expenses are not allocated to the Refining & Marketing and Speedway segments.

^(c)  See Note 18.

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

	Three Months Ended   March 31,
(In millions)	2014		2013
Segment capital expenditures and investments	$	340	$	1,546
Less: Investments in equity method investees	123		5
Plus: Items not allocated to segments:
Capital expenditures not allocated to segments	25		24
Capitalized interest	6		4
Total capital expenditures(a)(b)	$	248	$	1,569

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

^(b)  See Note 16 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 customer revenues to sales and other operating revenues (including consumer excise taxes) as reported in the consolidated statements of income:

	Three Months Ended   March 31,
(In millions)	2014		2013
Customer revenues (as reported above)	$	23,285	$	23,336
Corporate and other unallocated items	—		(6		)
Sales and other operating revenues (including consumer excise taxes)	$	23,285	$	23,330

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9. Other Items

Net interest and other financial income (costs) was:

	Three Months Ended   March 31,
(In millions)	2014			2013
Interest:
Interest income	$	2		$	2
Interest expense	(49		)	(48		)
Interest capitalized	6			4
Total net interest	(41		)	(42		)
Other:
Net foreign currency losses	—			(1		)
Bank service and other fees	(5		)	(5		)
Total other	(5		)	(6		)
Net interest and other financial income (costs)	$	(46	)	$	(48	)

10. Income Taxes

The combined federal, state and foreign income tax rate was 34 percent for both the three months ended March 31, 2014 and 2013. The effective tax rate for the three months ended March 31, 2014 and 2013 is 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.

We are continuously undergoing examination of our income tax returns, which have been completed for our U.S. federal and state income tax returns through the 2009 and 2003 tax years, respectively. We had $16 million of unrecognized tax benefits as of March 31, 2014. Pursuant to our tax sharing agreement with Marathon Oil Corporation ("Marathon Oil"), the unrecognized tax benefits related to pre-spinoff operations for which Marathon Oil was the taxpayer remain the responsibility of Marathon Oil and we have indemnified Marathon Oil accordingly. See Note 20 for indemnification information.

11. Inventories

(In millions)	March 31, 2014		December 31, 2013
Crude oil and refinery feedstocks	$	2,734	$	1,797
Refined products	2,540		2,367
Materials and supplies	333		425
Merchandise	82		100
Total (at cost)	$	5,689	$	4,689

Inventories are carried at the lower of cost or market value. The cost of inventories of crude oil and refinery feedstocks, refined products and merchandise is determined primarily under the last-in, first-out (“LIFO”) method. There were no liquidations of LIFO inventories for the three months ended March 31, 2014 and 2013.

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12. Property, Plant and Equipment

(In millions)	March 31, 2014		December 31, 2013
Refining & Marketing	$	17,117	$	16,982
Speedway	2,374		2,344
Pipeline Transportation	1,926		1,921
Corporate and Other	570		546
Total	21,987		21,793
Less accumulated depreciation	8,133		7,872
Property, plant and equipment, net	$	13,854	$	13,921

13. Fair Value Measurements

Fair Values—Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of March 31, 2014 and December 31, 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.

	March 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	$	41	$	—	$	—	$	(39	)	$	2	$	82
Other assets	2		—		—		N/A			2		—
Total assets at fair value	$	43	$	—	$	—	$	(39	)	$	4	$	82
Commodity derivative instruments, liabilities	$	81	$	—	$	—	$	(81	)	$	—	$	—
Contingent consideration, liability(c)	—		—		639		N/A			639		—
Total liabilities at fair value	$	81	$	—	$	639	$	(81	)	$	639	$	—

	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 March 31, 2014 and December 31, 2013, cash collateral of $42 million and $32 million, respectively, was netted with mark-to-market derivative liabilities.

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

^(c)  Includes $178 million and $159 million classified as current at March 31, 2014 and December 31, 2013, respectively.

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Commodity derivatives in Level 1 are exchange-traded contracts for crude oil and refined products measured at fair value with a market approach using the close-of-day settlement prices for the market. 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 March 31, 2014 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 4. The fair value of the contingent consideration was estimated using an income approach and is therefore a Level 3 liability. The amount of cash to be paid under the arrangement is based on both a market-based crack spread and refinery throughput volumes for the months during which the contract applies, as well as established thresholds that cap the annual and total payment. The earnout payment cannot exceed $200 million per year for the first three years of the arrangement or $250 million per year for the last three years of the arrangement, with the total cumulative payment capped at $700 million over the six-year period. Any excess or shortfall from the annual cap for a current year’s earnout calculation will not affect subsequent years’ calculations. The fair value calculation used significant unobservable inputs, including (1) an estimate of refinery throughput volumes; (2) a range of internal and external crack spread forecasts from $13 to $18 per barrel; and (3) a range of risk-adjusted discount rates from 5 percent to 10 percent. An increase or decrease in crack spread forecasts or refinery throughput volume expectations will result in a corresponding increase or decrease in the fair value. Increases to the fair value as a result of increasing forecasts for both of these unobservable inputs, however, are limited as the earnout payment is subject to annual thresholds. An increase or decrease in the discount rate will result in a decrease or increase to the fair value, respectively. The fair value of the contingent consideration is reassessed each quarter, with changes in fair value recorded in cost of revenues.

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

	Three Months Ended   March 31,
(In millions)	2014		2013
Beginning balance	$	625	$	—
Contingent consideration agreement	—		600
Total realized and unrealized losses included in net income	14		—
Ending balance	$	639	$	600

We did not hold any Level 3 derivative instruments during the three months ended March 31, 2014 and 2013. See Note 14 for the income statement impacts of our derivative instruments. There was an unrealized loss of $14 million related to the contingent consideration agreement for the three months ended March 31, 2014.

Fair Values – Reported

The following table summarizes financial instruments on the basis of their nature, characteristics and risk at March 31, 2014 and December 31, 2013, excluding the derivative financial instruments and contingent consideration reported above.

	March 31, 2014				December 31, 2013
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial assets:
Investments	$	39	$	13	$	336	$	14
Other	30		28		31		30
Total financial assets	$	69	$	41	$	367	$	44
Financial liabilities:
Long-term debt(a)	$	3,670	$	3,270	$	3,306	$	3,001
Deferred credits and other liabilities	21		21		21		21
Total financial liabilities	$	3,691	$	3,291	$	3,327	$	3,022

^(a)  Excludes capital leases

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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. Fair value of variable-rate long-term debt approximates the carrying value.

14. Derivatives

For further information regarding the fair value measurement of derivative instruments, including any effect of master netting agreements or collateral, see Note 13. We do not designate any of our commodity derivative instruments as hedges for accounting purposes.

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

	March 31, 2014
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	41	$	81	Other current assets
	December 31, 2013
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	21	$	53	Other current assets

The table below summarizes open commodity derivative contracts as of March 31, 2014.

	Position	Total Barrels (In thousands)
Crude oil(a)
Exchange-traded	Long	9,640
Exchange-traded	Short	(35,375	)
Refined Products(a)
Exchange-traded	Long	2,317
Exchange-traded	Short	(3,658	)

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

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

	Gain (Loss)
(In millions)	Three Months Ended March 31,
Income Statement Location	2014			2013
Sales and other operating revenues	$	10		$	1
Cost of revenues	(61		)	(60		)
Total	$	(51	)	$	(59	)

15. Debt

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

(In millions)	March 31, 2014			December 31, 2013
Marathon Petroleum Corporation:
Revolving credit agreement due 2017	$	—		$	—
3.500% senior notes due March 1, 2016	750			750
5.125% senior notes due March 1, 2021	1,000			1,000
6.500% senior notes due March 1, 2041	1,250			1,250
Consolidated subsidiaries:
Capital lease obligations due 2014-2028	389			395
MPLX Operations LLC revolving credit agreement due 2017	270			—
Trade receivables securitization facility due 2016	—			—
Total	3,659			3,395
Unamortized discount	(10		)	(10		)
Fair value adjustments(a)	10			11
Amounts due within one year	(24		)	(23		)
Total long-term debt due after one year	$	3,635		$	3,373

^(a)  The $20 million gain on the termination of our interest rate swap agreements in 2012 is being amortized over the remaining life of the 3.50 percent senior notes.

There were no borrowings or letters of credit outstanding under the MPC revolving credit agreement or the trade receivables securitization facility at March 31, 2014. During the three months ended March 31, 2014, MPLX borrowed $270 million under the MPLX Operations LLC revolving credit agreement (the "MPLX Credit Agreement") at an average interest rate of 1.5 percent per annum. The borrowings were used to fund MPLX's acquisition of an additional interest in Pipe Line Holdings. At March 31, 2014, MPLX had $270 million of borrowings and no letters of credit outstanding under the MPLX Credit Agreement, resulting in total unused loan availability of $230 million, or 46 percent of the borrowing capacity. The MPLX Credit Agreement is scheduled to mature on October 31, 2017.

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16. Supplemental Cash Flow Information

	Three Months Ended   March 31,
(In millions)	2014		2013
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	80	$	83
Net income taxes paid to (refunded from) taxing authorities	5		(5		)
Non-cash investing and financing activities:
Capital lease obligations increase	$	—	$	61
Acquisition:
Contingent consideration(a)	—		600
Payable to seller(a)	—		6

^(a)  Acquisition-date fair value of non-cash consideration associated with the Galveston Bay Refinery and Related Assets acquisition.

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:

	Three Months Ended   March 31,
(In millions)	2014			2013
Additions to property, plant and equipment	$	267		$	195
Acquisitions(a)	—			1,377
Decrease in capital accruals	(19		)	(3		)
Total capital expenditures	$	248		$	1,569

^(a)  The three months ended March 31, 2013 includes the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, plus assumed liabilities. Total consideration includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 4.

17. 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	67			9			—		—		76
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit(a)	(11		)	(2		)	—		—		(13		)
– actuarial loss(a)	21			1			—		—		22
Tax effect	(4		)	1			—		—		(3		)
Other comprehensive income	73			9			—		—		82
Balance as of March 31, 2013	$	(359	)	$	(27	)	$	4	$	—	$	(382	)

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(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	(43		)	1			—		—		(42		)
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit(a)	(12		)	(1		)	—		—		(13		)
– actuarial loss(a)	13			1			—		—		14
– settlement loss(a)	64			—			—		—		64
Tax effect	(24		)	—			—		—		(24		)
Other comprehensive income (loss)	(2		)	1			—		—		(1		)
Balance as of March 31, 2014	$	(163	)	$	(49	)	$	4	$	3	$	(205	)

^(a)  These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 18.

18. Defined Benefit Pension and Other Postretirement Plans

The following summarizes the components of net periodic benefit costs:

	Three Months Ended March 31,
	Pension Benefits						Other Benefits
(In millions)	2014			2013			2014			2013
Components of net periodic benefit cost:
Service cost	$	23		$	23		$	7		$	6
Interest cost	20			18			8			7
Expected return on plan assets	(28		)	(27		)	—			—
Amortization – prior service credit	(12		)	(11		)	(1		)	(2		)
– actuarial loss	13			21			1			1
– net settlement loss	64			—			—			—
Net periodic benefit cost	$	80		$	24		$	15		$	12

During the three months ended March 31, 2014, we made no contributions to our funded pension plans. We have no required funding for 2014 but may do so at our discretion. Current benefit payments related to unfunded pension and other postretirement benefit plans were $8 million and $5 million, respectively, during the three months ended March 31, 2014.

During the three months ended March 31, 2014, we determined that lump sum payments to employees retiring in 2014 will exceed the plans’ total service and interest costs for the year. Settlement losses are required to be recorded when lump sum payments exceed total service and interest costs. As a result, during the three months ended March 31, 2014, we recorded pension settlement expenses of $64 million related to our cumulative lump sum payments made during the first three months of 2014.

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19. Stock-Based Compensation Plans

Stock Option Awards

The following table presents a summary of our stock option award activity for the three months ended March 31, 2014:

	Number of Shares(a)		Weighted Average Exercise Price
Outstanding at December 31, 2013	5,147,837		$	40.08
Granted	327,100		83.37
Exercised	(455,999	)	30.65
Forfeited, canceled or expired	(19,293	)	50.05
Outstanding at March 31, 2014	4,999,645		43.73

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

The grant date fair value of stock option awards granted during the three months ended March 31, 2014 was $24.87 per share. The fair value of stock options granted to our employees is estimated on the date of the grant using the Black Scholes option-pricing model, which employs various assumptions. The assumption for expected volatility of our stock price was refined for the three months ended March 31, 2014 to reflect a weighting of 50 percent of MPC’s common stock implied volatility and 50 percent of MPC's common stock historical volatility.

Restricted Stock Awards

The following table presents a summary of restricted stock award activity for the three months ended March 31, 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	51,594		83.45		5,939	89.96
RS's Vested/RSU's Issued	(117,980	)	54.43		—	—
Forfeited	(14,840	)	64.31		—	—
Outstanding at March 31, 2014	542,896		64.60		391,018	34.81

Performance Unit Awards

The following table presents a summary of the activity for performance unit awards to be settled in shares for the three months ended March 31, 2014:

	Number of Units
Outstanding at December 31, 2013	3,822,500
Granted	2,033,700
Settled	—
Canceled	—
Outstanding at March 31, 2014	5,856,200

The performance unit awards granted in 2014 have a grant date fair value of $1.02 per unit, as calculated using a Monte Carlo valuation model.

MPLX Awards

During the three months ended March 31, 2014, MPLX granted equity-based compensation awards under the MPLX LP 2012 Incentive Compensation Plan. The compensation expense for these awards is not material to our consolidated financial statements.

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20. Commitments and Contingencies

We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. Some of these matters are discussed below. For matters for which we have not recorded an accrued liability, we are unable to estimate a range of possible loss because the issues involved have not been fully developed through pleadings and discovery. However, the ultimate resolution of some of these contingencies could, individually or in the aggregate, be material.

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

At both March 31, 2014 and December 31, 2013, accrued liabilities for remediation totaled $123 million. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties if any that may be imposed. Receivables for recoverable costs from certain states, under programs to assist companies in clean-up efforts related to underground storage tanks at presently or formerly owned or operated retail marketing sites, were $50 million and $51 million at March 31, 2014 and December 31, 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. Both LOOP and LOCAP have secured various project financings with throughput and deficiency agreements. Under the agreements, we are required to advance funds if the investees are unable to service their debt. Any such advances are considered prepayments of future transportation charges. The duration of the agreements vary but tend to follow the terms of the underlying debt, which extend through 2037. Our maximum potential undiscounted payments under these agreements for the debt principal totaled $172 million as of March 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 $41 million as of March 31, 2014.

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We hold an interest in an ethanol production facility through our investment in TAME, and through our participation as a lender under TAME’s revolving credit agreement, have agreed to reimburse the bank for 50 percent of any amounts drawn on a letter of credit that has been issued to secure TAME’s repayment of the tax exempt bonds. The credit agreement expires in 2018. Our maximum potential undiscounted payments under this arrangement were $25 million at March 31, 2014.

Marathon Oil indemnifications—In conjunction with our spinoff from Marathon Oil, we have entered into arrangements with Marathon Oil providing indemnities and guarantees with recorded values of $2 million as of March 31, 2014, which consist of unrecognized tax benefits related to MPC, its consolidated subsidiaries and the refining, marketing and transportation business operations prior to our spinoff which are not already reflected in the unrecognized tax benefits described in Note 10, 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 our spinoff provide for cross-indemnities between Marathon Oil and us. In general, Marathon Oil is required to indemnify us for any liabilities relating to Marathon Oil’s historical oil and gas exploration and production operations, oil sands mining operations and integrated gas operations, and we are required to indemnify Marathon Oil for any liabilities relating to Marathon Oil’s historical refining, marketing and transportation operations. The terms of these indemnifications are indefinite and the amounts are not capped.

Other guarantees—We have entered into other guarantees with maximum potential undiscounted payments totaling $122 million as of March 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, an indemnity to the co-lenders associated with an equity method investee’s credit agreement, and leases of assets containing general lease indemnities and guaranteed residual values.

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

Contractual commitments—At March 31, 2014, our contractual commitments to acquire property, plant and equipment and advance funds to equity method investees totaled $1.8 billion, which includes $700 million of contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets and $854 million for contributions to North Dakota Pipeline. See Notes 4 and 13 for additional information on the contingent consideration. See Note 4 for additional information on our investment in North Dakota Pipeline.

21. Subsequent Event

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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Item 2: 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 unaudited financial statements and accompanying footnotes included under Item 1. Financial Statements and in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2013.

Management’s Discussion and Analysis of Financial Condition and Results of Operations includes various forward-looking statements concerning trends or events potentially affecting our business. You can identify our forward-looking statements by words such as “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “plan,” “predict,” “project,” “seek,” “target,” “could,” “may,” “should,” “would,” "will" or other similar expressions that convey the uncertainty of future events or outcomes. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2013.

Corporate Overview

We are an independent petroleum refining, marketing and transportation company. We currently own and operate seven refineries, all located in the United States, with an aggregate crude oil refining capacity of approximately 1.7 million barrels per calendar day. Our refineries supply refined products to resellers and consumers within our market areas, including the Midwest, Gulf Coast and Southeast regions of the United States. We distribute refined products to our customers through one of the largest private domestic fleets of inland petroleum product barges, one of the largest terminal operations in the United States, and a combination of MPC-owned and third-party-owned trucking and rail assets. We currently own, lease or have ownership interests in approximately 8,300 miles of crude oil and refined product pipelines to deliver crude oil to our refineries and other locations and refined products to wholesale and retail market areas. We are one of the largest petroleum pipeline companies in the United States on the basis of total volumes delivered.

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

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

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

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

Executive Summary

Net income attributable to MPC was $199 million, or $0.67 per diluted share, for the first quarter of 2014 compared to $725 million, or $2.17 per diluted share, for the first quarter of 2013. The decrease was primarily due to our Refining & Marketing segment, which generated income from operations of $362 million in the first quarter of 2014 compared to $1.11 billion in the first quarter of 2013. The decrease in Refining & Marketing segment income from operations was primarily due to narrower crude oil differentials and higher turnaround costs, partially offset by higher crack spreads and more favorable net product price realizations.

Speedway segment income from operations decreased$9 million in the first quarter of 2014 compared to the first quarter of 2013, primarily due to a lower gasoline and distillate gross margin and higher operating expenses, partially offset by a higher merchandise gross margin.

Pipeline Transportation segment income from operations increased$21 million in the first quarter of 2014 compared to the first quarter of 2013. The increase primarily reflects an increase in pipeline transportation revenue and equity affiliate income, partially offset by higher operating expenses.

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 thousand barrel per day ("mbpd") allocation of space on the Colonial Pipeline. We refer to these assets as the “Galveston Bay

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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. During the second quarter of 2014, we expect to pay BP approximately $178 million for the first year's contingent earnout. These assets are part of our Refining & Marketing and Pipeline Transportation segments. Our financial results and operating statistics for the period prior to the acquisition does not include amounts for the Galveston Bay Refinery and Related Assets. See Note 4 to the unaudited consolidated financial statements for additional information on this acquisition.

Effective March 1, 2014, we sold MPLX a 13 percent interest in Pipe Line Holdings for $310 million, increasing MPLX's ownership interest in Pipe Line Holdings to 69 percent. MPLX financed this transaction with $40 million of cash on-hand and $270 million of borrowings on its bank revolving credit agreement. See Note 3 to the unaudited consolidated financial statements for additional information on MPLX.

In March 2014, we acquired from Chevron Raven Ridge Pipe Line Company an additional 7 percent interest in Explorer for $77 million, bringing our ownership interest to 25 percent. This increase in our ownership percentage requires us to now account for our investment in Explorer using the equity method of accounting and begin reporting Explorer as a related party. Explorer owns approximately 1,900 miles of refined products pipeline from Lake Charles, Louisiana to Hammond, Indiana.

In 2013, we agreed with Enbridge Energy Partners, L.P. ("Enbridge") to serve as an anchor shipper for the Sandpiper pipeline, which will run from Beaver Lodge, North Dakota to Superior, Wisconsin and is targeted to be operational in early 2016. We also agreed to fund 37.5 percent of the construction of the Sandpiper pipeline project, which is currently estimated to cost $2.6 billion, of which approximately $1.0 billion is our share. We made contributions of $37 million during the first quarter of 2014 and have contributed $61 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's North Dakota System when the Sandpiper pipeline is placed into service. Enbridge's North Dakota System currently includes approximately 240 miles of crude oil gathering pipelines connected to a transportation pipeline that is approximately 730 miles long. We will also have the option to increase our ownership interest to approximately 30 percent through additional investments in future system improvements. See Notes 4 and 20 to the unaudited consolidated financial statements.

During the first three months of 2014, we paid $689 million to acquire 8 million common shares through open market share repurchases. The effective average cost was $87.60 per delivered share. At March 31, 2014, we also had agreements to repurchase additional common shares for $12 million, which were settled in early April 2014. As of March 31, 2014, we had an outstanding repurchase authorization of $1.17 billion, which expires in September 2015. See Note 7 to the unaudited consolidated financial 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 purchased products. The crack spread is a measure of the difference between market prices for refined products and crude oil, commonly used by the industry as a proxy for the refining margin. Crack spreads can fluctuate significantly, particularly when prices of refined products do not move in the same relationship as the cost of crude oil. As a performance benchmark and a comparison with other industry participants, we calculate Midwest (Chicago) and U.S. Gulf Coast (“USGC”) crack spreads that we believe most closely track our operations and slate of products. Light Louisiana Sweet crude oil ("LLS") prices and a 6-3-2-1 ratio of products (6 barrels of LLS crude oil producing 3 barrels of unleaded regular gasoline, 2 barrels of ultra-low sulfur diesel and 1 barrel of 3 percent residual fuel oil) are used for these crack-spread calculations.

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

Historically, West Texas Intermediate crude oil ("WTI") has traded at prices similar to LLS. During 2011 and continuing through the first half of 2013, WTI traded at prices significantly less than LLS, which favorably impacted our Refining & Marketing gross margin. Logistical constraints in the U.S. mid-continent markets and other market factors acted to keep the price of WTI from rising with the prices of crude oil produced in other regions. However, the differential between WTI and LLS significantly narrowed during the second half of 2013 before widening modestly late in the first quarter of 2014 due to a

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variety of domestic and international market conditions. Future crude oil differentials will be dependent on a variety of market and economic factors.

The following table provides sensitivities showing an estimated change in annual net income due to potential changes in market conditions.

(In millions, after-tax)
LLS 6-3-2-1 crack spread sensitivity(a) (per $1.00/barrel change)	$	450
Sweet/sour differential sensitivity(b)(per $1.00/barrel change)	200
LLS-WTI differential sensitivity(c)(per $1.00/barrel change)	85
Natural gas price sensitivity (per $1.00/million British thermal unit change)	125

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

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

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

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

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

• our refinery yields;

• the selling prices realized for refined products;

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

• the cost of products purchased for resale.

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. We had significant planned turnaround and major maintenance activities at our Galveston Bay; Garyville, Louisiana; Robinson, Illinois and Catlettsburg, Kentucky refineries during the first quarter of 2014 compared to activities at our Catlettsburg, Garyville and Galveston Bay refineries during the first quarter of 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. Market demand increases for gasoline and distillate generally increase the product margin we can realize. The gross margin on merchandise sold at convenience stores historically has been less volatile and has contributed substantially to Speedway's gross margin. Approximately two-thirds of Speedway’s gross margin was derived from merchandise sales in the first quarter of 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. 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

	Three Months Ended   March 31,
(In millions)	2014			2013			Variance
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$	23,285		$	23,330		$	(45	)
Income from equity method investments	35			—			35
Net gain on disposal of assets	1			1			—
Other income	24			14			10
Total revenues and other income	23,345			23,345			—
Costs and expenses:
Cost of revenues (excludes items below)	20,540			20,034			506
Purchases from related parties	159			72			87
Consumer excise taxes	1,515			1,458			57
Depreciation and amortization	320			287			33
Selling, general and administrative expenses	346			249			97
Other taxes	104			89			15
Total costs and expenses	22,984			22,189			795
Income from operations	361			1,156			(795		)
Net interest and other financial income (costs)	(46		)	(48		)	2
Income before income taxes	315			1,108			(793		)
Provision for income taxes	108			378			(270		)
Net income	207			730			(523		)
Less net income attributable to noncontrolling interests	8			5			3
Net income attributable to MPC	$	199		$	725		$	(526	)

Net income attributable to MPC decreased$526 million in the first quarter of 2014 compared to the first quarter of 2013, primarily due to a decrease in our Refining & Marketing segment income from operations of $743 million in the first quarter of 2014 compared to the first quarter of 2013. The decrease in Refining & Marketing segment income from operations was primarily due to narrower crude oil differentials and higher turnaround costs, partially offset by higher crack spreads and more favorable net product price realizations.

Sales and other operating revenues (including consumer excise taxes) remained flat in the first quarter of 2014 compared to the first quarter of 2013, primarily due to the offsetting impacts of higher refined product sales volumes and lower refined product selling prices. Our consolidated refined product sales increased69 mbpd in the first quarter of 2014 compared to the first quarter of 2013.

Income from equity method investments increased$35 million in the first quarter of 2014 compared to the first quarter of 2013, primarily due to an increase in income from our ethanol investments of $24 million and an increase in income from our pipeline affiliates, including Explorer, of $11 million. The increase in income from our ethanol investments was primarily related to lower corn prices in the first quarter of 2014 compared to the first quarter of 2013 and the acquisition of interests in TAAE, TACE and TAEI in 2013.

Centennial experienced a significant reduction in shipment volumes in the second half of 2011 that has continued through the first three months of 2014. At March 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 current business conditions remain unchanged and the owners of Centennial are unable to find an alternative use for the assets, there could be a future impairment of our Centennial interest. As of March 31, 2014, our equity investment in Centennial was $39 million and we had a $41 million guarantee associated with 50 percent of Centennial's outstanding debt. See Note 20 to the unaudited consolidated financial statements for additional information on the debt guarantee.

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Other income increased$10 million in the first quarter of 2014 compared to the first quarter of 2013, primarily due to an increase in sales of Renewable Identification Numbers (“RINs”), partially offset by a decrease in dividends received from a pipeline affiliate.

Cost of revenues increased$506 million in the first quarter of 2014 compared to the first quarter of 2013, primarily due to higher refinery direct operating costs, including costs associated with significant turnaround activity at the Galveston Bay refinery, and an increase in purchased refined product volumes. These higher costs were partially offset by lower crude oil acquisition prices and a decrease in purchased charge and blendstocks volumes. Refinery direct operating costs increased$4.27 per barrel of throughput, and refined product purchase volumes increased13 percent in the first quarter of 2014 compared to the first quarter of 2013. Crude oil acquisition prices decreased3 percent and charge and blendstocks volumes decreased16 percent compared to the same quarter last year.

Purchases from related parties increased$87 million in the first quarter of 2014 compared to the first quarter of 2013, primarily due to an increase in purchases from LOOP of $43 million, largely related to higher crude oil purchases in the first quarter of 2014, purchases totaling $16 million from TAAE and $13 million from Explorer in the first quarter of 2014, which were not related parties during the first quarter of 2013, and an increase in feedstock purchases from Centennial of $9 million.

Depreciation and amortization increased$33 million in the first quarter of 2014 compared to the first quarter of 2013, primarily due to accelerated depreciation of a unit at our Garyville refinery, the implementation of corporate-level information technology projects and our acquisition of the Galveston Bay Refinery and Related Assets.

Selling, general and administrative expenses increased$97 million in the first quarter of 2014 compared to the first quarter of 2013, primarily due to pension settlement expenses of $64 million in the first quarter of 2014 resulting from the level of employee lump sum retirement distributions that occurred during the period and an increase in refinery and information technology contract services.

Other taxes increased$15 million in the first quarter of 2014 compared to the first quarter of 2013, primarily due to increases in payroll taxes and sales and use tax expense. These increases were attributable to a number of factors including the acquisition of the Galveston Bay Refinery and Related Assets.

Provision for income taxes decreased$270 million in the first quarter of 2014 compared to the first quarter of 2013, primarily due to the $793 milliondecrease in income before income taxes. The effective tax rate was 34 percent in the first quarter of 2014 and 2013. The effective tax rate for both periods is 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.

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.

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Segment Results

Revenues, including intersegment sales, are summarized by segment in the following table.

	Three Months Ended   March 31,
(In millions)	2014		2013
Refining & Marketing	$	22,043	$	22,073
Speedway	3,459		3,442
Pipeline Transportation	146		125
Segment revenues	$	25,648	$	25,640
Items included in both revenues and costs:
Consumer excise taxes	$	1,515	$	1,458

Refining & Marketing segment revenues remained flat in the first quarter of 2014 compared to the first quarter of 2013, due to offsetting impacts of an increase in refined product sales volumes of 71 mbpd and a decrease in average refined product selling prices of $0.10 per gallon. The table below shows our Refining & Marketing segment refined product sales volumes, sales destined for export and average sales prices.

	Three Months Ended   March 31,
	2014		2013
Refining & Marketing segment:
Refined product sales volumes (thousands of barrels per day)(a)	1,951		1,880
Refined product sales destined for export (thousands of barrels per day)	223		135
Average refined product sales prices (dollars per gallon)	$	2.88	$	2.98

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

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

	Three Months Ended   March 31,
(Dollars per gallon)	2014		2013
Chicago spot unleaded regular gasoline	$	2.68	$	2.79
Chicago spot ultra-low sulfur diesel	2.99		3.08
USGC spot unleaded regular gasoline	2.65		2.83
USGC spot ultra-low sulfur diesel	2.93		3.08

Refining & Marketing intersegment sales to our Speedway segment increased$34 million in the first quarter of 2014 compared to the first quarter of 2013, primarily due to higher intersegment refined product sales volumes, partially offset by a decrease in average refined product sales prices of $0.11 per gallon. The increase in volumes was primarily related to higher Speedway sales volumes per convenience store. The table below shows our Refining & Marketing intersegment sales to our Speedway segment.

	Three Months Ended   March 31,
	2014		2013
Refining & Marketing intersegment sales to Speedway:
Intersegment sales (in millions)	$	2,233	$	2,199
Refined product sales volumes (millions of gallons)	723		688
Average refined product sales prices (dollars per gallon)	$	3.08	$	3.19

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Speedway segment revenues increased$17 million in the first quarter of 2014 compared to the first quarter of 2013, primarily due to an increase in merchandise sales of $11 million and an increase in gasoline and distillate sales of $6 million. The higher merchandise sales was primarily due to an increase in the number of convenience stores. The higher gasoline and distillate sales were primarily due to an increase in gasoline and distillate sales volumes of 28 million gallons related to higher average sales volumes per convenience store and an increase in the number of convenience stores, partially offset by a decrease in gasoline and distillate selling prices of $0.12 per gallon.

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

	Three Months Ended   March 31,
	2014			2013
Convenience stores at period-end	1,482			1,463
Gasoline & distillate sales (millions of gallons)	773			745
Average gasoline & distillate sales prices (dollars per gallon)	$	3.39		$	3.51
Merchandise sales (in millions)	$	722		$	711
Same store gasoline sales volume (period over period)	(0.7		)%	0.7		%
Same store merchandise sales (period over period)(a)	5.3		%	0.8		%

^(a) Excludes cigarettes.

Pipeline Transportation segment revenue increased$21 million in the first quarter of 2014 compared to the first quarter of 2013, primarily due to a $17 million increase in revenue related to volume deficiency credits, as well as higher transportation tariffs resulting from higher average tariff rates on crude oil and refined products volumes transported. These increases were partially offset by decreases in crude oil and refined products volumes transported. Crude oil pipeline throughput volumes decreased128 mbpd and refined products pipeline throughput volumes decreased98 mbpd in the first quarter of 2014 compared to the first quarter of 2013.

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

	Three Months Ended   March 31,
	2014	2013
Pipeline Throughputs (thousands of barrels per day):(a)
Crude oil pipelines	1,144	1,272
Refined products pipelines	819	917
Total	1,963	2,189

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

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

	Three Months Ended   March 31,
(In millions)	2014			2013
Income from Operations by segment
Refining & Marketing	$	362		$	1,105
Speedway	58			67
Pipeline Transportation(a)	72			51
Items not allocated to segments:
Corporate and other unallocated items(a)	(67		)	(67		)
Pension settlement expenses	(64		)	—
Income from operations	361			1,156
Net interest and other financial income (costs)	(46		)	(48		)
Income before income taxes	$	315		$	1,108

^(a)  Corporate overhead costs attributable to MPLX are included in the Pipeline Transportation segment. These expenses are not allocated to the Refining & Marketing and Speedway segments.

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

	Three Months Ended   March 31,
(Dollars per barrel)	2014		2013
Chicago LLS 6-3-2-1(a)(b)	$	8.80	$	3.99
USGC LLS 6-3-2-1(a)	7.27		4.87
Blended 6-3-2-1(a)(c)	7.85		4.54
LLS	104.29		113.87
WTI	98.61		94.36
LLS—WTI crude oil differential(a)	5.68		19.51
Sweet/Sour crude oil differential(a)(d)	8.23		12.12

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

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

^(c)  Blended Chicago/USGC crack spread is 38%/62% based on MPC’s refining capacity by region.

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

Refining & Marketing segment income from operations decreased$743 million in the first quarter of 2014 compared to the first quarter of 2013, primarily due to narrower crude oil differentials and higher turnaround costs, partially offset by higher crack spreads and more favorable net product price realizations.

The LLS-WTI crude oil differential narrowed by $13.83 per barrel and the sweet/sour crude oil differential narrowed by $3.89 per barrel in the first quarter of 2014 compared to the first quarter of 2013, which we estimate had negative impacts on segment income of $397 million and $320 million, respectively. The Chicago LLS 6-3-2-1 crack spread increased$4.81 per barrel and the USGC 6-3-2-1 crack spread increased $2.40 per barrel in the first quarter of 2014 compared to the first quarter of 2013, which we estimate had positive impacts on segment income of $269 million and $215 million, respectively.

The following table summarizes our refinery throughputs.

	Three Months Ended   March 31,
	2014	2013
Refinery Throughputs (thousands of barrels per day):
Crude oil refined	1,450	1,433
Other charge and blendstocks	200	238
Total	1,650	1,671
Sour crude oil throughput percent	49	54
WTI-priced crude oil throughput percent	21	22

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

	Three Months Ended   March 31,
	2014		2013
Refining & Marketing gross margin (dollars per barrel)(a)	$	14.46	$	15.29
Refinery direct operating costs (dollars per barrel):(b)
Planned turnaround and major maintenance	$	3.15	$	1.15
Depreciation and amortization	1.55		1.42
Other manufacturing(c)	5.95		3.81
Total	$	10.65	$	6.38

^(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$4.27 per barrel of total refinery throughputs in the first quarter of 2014 compared to the first quarter of 2013, which includes an increase in other manufacturing costs of $2.14 per barrel and an increase in turnaround and major maintenance costs of $2.00 per barrel. These increases were primarily attributable to the Galveston Bay refinery acquired in February 2013, which had significant turnaround and major maintenance activities during the first quarter of 2014 and higher operating costs per barrel of throughput than the average of our other six refineries.

We purchase RINs to satisfy a portion of our Renewable Fuel Standard compliance. Our expense associated with purchased RINs increased to $71 million in the first quarter of 2014 from $43 million in the first quarter of 2013.

Speedway segment income from operations decreased$9 million in the first quarter of 2014 compared to the first quarter of 2013. The severe weather conditions in the Midwest impacted all aspects of the business for the first quarter of 2014. The decrease in segment income was primarily due to a decrease in the gasoline and distillate gross margin of $0.0145 per gallon and higher operating expenses resulting from an increase in the number of stores and due to the difficult weather conditions in the first quarter of 2014. The negative impacts to segment income were partially offset by an increase in merchandise gross margin related to higher merchandise and food sales along with an increase in the number of convenience stores.

The following table includes margin statistics for the Speedway segment.

	Three Months Ended   March 31,
	2014		2013
Gasoline & distillate gross margin (dollars per gallon)(a)	$	0.1156	$	0.1301
Merchandise gross margin (in millions)	$	192	$	184

^(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$21 million in the first quarter of 2014 compared to the first quarter of 2013. The increase primarily reflects an increase in pipeline transportation revenue and equity affiliate income, partially offset by higher operating expenses.

We recorded pretax pension settlement expense of $64 million in the first quarter of 2014 resulting from the level of employee lump-sum retirement distributions that occurred during the period.

Liquidity and Capital Resources

Cash Flows

Our cash and cash equivalents balance was $2.17 billion at March 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 first quarters of 2014 and 2013 are presented in the following table.

	Three Months Ended   March 31,
(In millions)	2014			2013
Net cash provided by (used in):
Operating activities	$	766		$	2,079
Investing activities	(360		)	(1,682		)
Financing activities	(532		)	(520		)
Total	$	(126	)	$	(123	)

Net cash provided by operating activities decreased$1.31 billion in the first quarter of 2014 compared to the first quarter of 2013, primarily due to unfavorable changes in working capital of $908 million and the $523 milliondecrease in net income compared to the first quarter of 2013. Changes in working capital were a net $125 millionsource of cash in the first quarter of 2014 compared to a net $1.03 billionsource of cash in the first quarter of 2013. The $125 million source of cash from working capital changes in the first quarter of 2014 was primarily due to an increase in accounts payable and accrued liabilities and a decrease in current receivables, partially offset by an increase in inventories. Accounts payable increased$1.08 billion from year-end 2013, primarily due to higher crude oil payable volumes and prices at the end of the first quarter of 2014 compared to year-end 2013. Current receivables decreased$139 million from year-end 2013, primarily due to lower refined product and crude oil receivable volumes, partially offset by higher refined product and crude oil prices. Inventories increased$1.00 billion from year-end 2013, primarily due to an increase in crude oil inventory volumes.

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The $1.03 billion source of cash in the first quarter of 2013 was primarily due to an increase in accounts payable and accrued liabilities. Accounts payable increased $2.09 billion from year-end 2012, primarily due to higher crude oil payable volumes related to the addition of the Galveston Bay refinery in the first quarter of 2013 and lower crude oil purchases at the end of 2012 in preparation for turnaround and major maintenance activity. In addition, accounts payable increased due to higher crude oil prices at the end of the first quarter of 2013 compared to year-end 2012. Accrued liabilities increased $404 million from year-end 2012, primarily due to an increase in accrued taxes associated with timing of federal income tax payments. The increase in accounts payable and accrued liabilities was partially offset by higher refined product receivable volumes attributable to an increase in refined product sales volumes and increases in crude oil and refined product inventory volumes.

Net cash used in investing activities decreased$1.32 billion in the first quarter of 2014 compared to the first quarter of 2013, primarily due to the Galveston Bay Refinery and Related Assets acquisition in February 2013, partially offset by higher capital expenditures in our Refining & Marketing and Pipeline Transportation segments in the first quarter of 2014.

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

	Three Months Ended   March 31,
(In millions)	2014			2013
Additions to property, plant and equipment	$	267		$	195
Acquisitions(a)	—			1,377
Decrease in capital accruals	(19		)	(3		)
Total capital expenditures	248			1,569
Investments in equity method investees	123			5
Total capital expenditures and investments	$	371		$	1,574

^(a)  The three months ended March 31, 2013 includes the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, plus assumed liabilities. Total consideration includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 4 to the unaudited consolidated financial statements.

Capital expenditures and investments are summarized by segment below.

	Three Months Ended   March 31,
(In millions)	2014		2013
Refining & Marketing(a)	$	178	$	1,420
Speedway	32		36
Pipeline Transportation(a)	130		90
Corporate and Other(b)	31		28
Total	$	371	$	1,574

^(a)  The three months ended March 31, 2013 includes the acquisition of the Galveston Bay Refinery and Related Assets. See Note 4 to the unaudited consolidated financial statements.

^(b)  Includes capitalized interest of $6 million and $4 million for the three months ended March 31, 2014 and 2013, respectively.

The acquisition of the Galveston Bay Refinery and Related Assets comprised 87 percent of our total capital spending in the first quarter of 2013.

Net cash used in investments in affiliates increased$113 million in the first quarter of 2014 compared to the first quarter of 2013, primarily due to our acquisition of an additional 7 percent interest in Explorer for $77 million and our contributions to North Dakota Pipeline of $37 million to fund our portion of the Sandpiper pipeline project in the first quarter of 2014.

Net cash used in financing activities increased$12 million in the first quarter of 2014 compared to the first quarter of 2013. The uses of cash for both periods were primarily for common stock repurchases under our share repurchase plans and dividend payments, partially offset in the first quarter of 2014 by long-term debt borrowings by MPLX.

Cash provided by long-term debt borrowings was $270 million in the first quarter of 2014. MPLX borrowed $270 million under its revolving credit agreement to fund MPLX's acquisition of an additional interest in Pipe Line Holdings.

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Cash used in common stock repurchases under the share repurchase plans authorized by our board of directors increased$258 million in the first quarter of 2014 compared to the first quarter of 2013. During the first quarter of 2014, we paid $689 million to repurchase 8 million common shares compared to $431 million paid to repurchase 5 million shares through open market repurchases during the first quarter of 2013. See Note 7 to the unaudited consolidated financial statements for further discussion of the share repurchase plans.

Cash used in dividend payments increased$7 million in the first quarter of 2014 compared to the first quarter of 2013, primarily due to a 7 cent per share increase in our quarterly dividend payment, partially offset by a decrease in the number of outstanding shares of our common stock attributable to share repurchases. Our dividend payments were $0.42 per common share in the first quarter of 2014 compared to $0.35 per common share in the first quarter of 2013.

Derivative Instruments

See Item 3. Quantitative and Qualitative Disclosures about Market Risk for a discussion of derivative instruments and associated market risk.

Capital Resources

As of March 31, 2014, we had no borrowings or letters of credit outstanding under our revolving credit agreement or our trade receivables securitization facility. MPLX had $270 million in borrowings outstanding under its revolving credit agreement at March 31, 2014. Our liquidity totaled $5.97 billion at March 31, 2014 consisting of:

(In millions)	March 31, 2014
Cash and cash equivalents	$	2,166
Revolving credit agreement(a)	2,500
Trade receivables securitization facility	1,300
Total	$	5,966

^(a)  Excludes MPLX’s $500 million revolving credit agreement, which had $230 million available as of March 31, 2014.

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.

Our revolving credit agreement (the “MPC 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 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 MPC Credit Agreement) of no greater than 0.65 to 1.00. As of March 31, 2014, we were in compliance with this debt covenant with a ratio of Consolidated Net Debt to Total Capitalization of 0.17 to 1.00, as well as the other covenants contained in the MPC Credit Agreement.

The financial covenant included in the MPLX Credit Agreement requires MPLX to maintain a ratio of Consolidated Total Debt (as defined in the MPLX Credit Agreement) as of the end of each fiscal quarter to Consolidated EBITDA (as defined in the MPLX Credit Agreement) for the prior four fiscal quarters of not greater than 5.0 to 1.0 (or 5.5 to 1.0 during the six-month period following certain acquisitions). As of March 31, 2014, MPLX was in compliance with this debt covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of 2.2 to 1.0, as well as the other covenants contained in the MPLX Credit Agreement.

Our intention is to maintain an investment grade credit profile. As of March 31, 2014, the credit ratings on our senior unsecured debt were at or above investment grade level as follows.

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

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

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

Debt-to-Total-Capital Ratio

Our debt-to-total capital ratio (total debt to total debt-plus-equity) was 25 percent at March 31, 2014 and 23 percent at December 31, 2013.

(In millions)	March 31, 2014			December 31, 2013
Long-term debt due within one year	$	24		$	23
Long-term debt	3,635			3,373
Total debt	$	3,659		$	3,396
Calculation of debt-to-total-capital ratio:
Total debt	$	3,659		$	3,396
Total equity	10,758			11,332
Total capital	$	14,417		$	14,728
Debt-to-total-capital ratio	25		%	23		%

Capital Requirements

We have a capital and investment budget for 2014 of $2.43 billion, excluding capitalized interest. The budget includes spending on refining, retail marketing, transportation, logistics and brand marketing projects as well as amounts designated for corporate activities. During the three months ended March 31, 2014, our capital expenditures and investments were $365 million, excluding capitalized interest. There have been no material changes to our 2014 capital and investment budget since our Annual Report on Form 10-K for the year ended December 31, 2013 was filed. We continuously evaluate our capital budget and make changes as conditions warrant.

Pursuant to the purchase and sale agreement for the Galveston Bay Refinery and Related Assets, we may be required to pay to the seller a contingent earnout of up to an additional $700 million over six years, subject to certain conditions. During the second quarter of 2014, we expect to pay BP approximately $178 million for the first year's contingent earnout. See Notes 4 and 13 to the unaudited consolidated financial statements.

MPLX had $270 million in borrowings outstanding under its revolving credit agreement at March 31, 2014.

During the three months ended March 31, 2014, we made no contributions to our funded pension plans. We have no required funding for 2014 but may do so at our discretion.

On April 30, 2014, our board of directors approved a 42 cents per share dividend, payable June 10, 2014 to stockholders of record at the close of business on May 21, 2014.

During the first three months of 2014, we paid $689 million to acquire 8 million common shares through open market share repurchases. We also entered into agreements to acquire additional common shares for $12 million, which were settled in early April 2014. As of March 31, 2014, we had total outstanding repurchase authorizations pursuant to the authorization announced on September 26, 2013 of $1.17 billion, which expires in September 2015.

We may utilize various methods to effect additional repurchases, which could include open market purchases, 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

As of March 31, 2014, our contractual cash obligations included long-term debt, capital and operating lease obligations, purchase obligations and other long-term liabilities. During the first three months of 2014, the MPLX Credit Agreement committed payments increased $282 million due to borrowing on the MPLX Credit Agreement to purchase the additional interest in Pipe Line Holdings, including interest and fees. There were no other material changes to our contractual cash obligations outside the ordinary course of business.

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 our spinoff from Marathon Oil, we entered into various indemnities and guarantees to Marathon Oil. These arrangements are described in Note 20 to the unaudited consolidated financial statements.

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. 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.

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.

On March 3, 2014, the U.S. Environmental Protection Agency 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.

There have been no other significant changes to our environmental matters and compliance costs during the three months ended March 31, 2014.

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Critical Accounting Estimates

There have been no significant changes to our critical accounting estimates during the three months ended March 31, 2014.

Accounting Standards Not Yet Adopted

In April 2014, the FASB issued an accounting standards update which 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(s) of an entity or the classification of a component(s) of an entity as held for sale which 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 3. Quantitative and Qualitative Disclosures about Market Risk

For a detailed discussion of our risk management strategies and our derivative instruments, see Item 7A. Quantitative and Qualitative Disclosures about Market Risk in our Annual Report on Form 10-K for the year ended December 31, 2013.

See Notes 13 and 14 to the unaudited consolidated financial statements 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.

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 March 31, 2014 is provided in the following table.

	Incremental Change in IFO from a Hypothetical Price Increase of						Incremental Change in IFO from a Hypothetical Price Decrease of
(In millions)	10%			25%			10%		25%
As of March 31, 2014
Crude	$	(238	)	$	(595	)	$	251	$	626
Refined products	—			4			13		34

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 March 31, 2014 would cause future IFO effects to differ from those presented above.

Sensitivity analysis of the projected incremental effect of a hypothetical 100-basis-point change in interest rates on long-term debt as of March 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)		Incremental Change in Fair Value			Incremental Change in Net Income
Long-term debt(a)
Fixed-rate	$	3,400	$	315	(c)	n/a
Variable-rate	270		n/a			—	(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 March 31, 2014.

^(d)  Assumes a 100-basis-point increase in interest rates for the three months ended March 31, 2014.

At March 31, 2014, our portfolio of long-term debt was comprised of fixed-rate instruments and variable-rate borrowings under 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 MPLX Credit Agreement, but may affect our results of operations and cash flows.

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Item 4. 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 March 31, 2014, the end of the period covered by this report.

Internal Control over Financial Reporting and Changes in Internal Control over Financial Reporting

During the quarter ended March 31, 2014, we implemented an Enterprise Resource Planning system for core financial and procurement processes. As a result of the implementation, certain internal controls have changed. There were 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.

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Supplementary Statistics (Unaudited)

	Three Months Ended   March 31,
(In millions)	2014			2013
Income from Operations by segment
Refining & Marketing	$	362		$	1,105
Speedway	58			67
Pipeline Transportation(a)	72			51
Items not allocated to segments:
Corporate and other unallocated items(a)	(67		)	(67		)
Pension settlement expenses	(64		)	—
Income from operations	$	361		$	1,156
Capital Expenditures and Investments(b)(c)
Refining & Marketing	$	178		$	1,420
Speedway	32			36
Pipeline Transportation	130			90
Corporate and Other(d)	31			28
Total	$	371		$	1,574

^(a)  Corporate overhead costs attributable to MPLX are included in the Pipeline Transportation segment. These expenses are not allocated to the Refining & Marketing and Speedway segments.

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

^(c)  The three months ended March 31, 2013 includes the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, plus assumed liabilities. Total consideration includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 4 to the unaudited consolidated financial statements.

^(d)  Includes capitalized interest $6 million and $4 million for the three months ended March 31, 2014 and 2013, respectively.

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Supplementary Statistics (Unaudited)

	Three Months Ended   March 31,
	2014		2013
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)(a)(b)	1,964		1,895
Refining & Marketing Operating Statistics(b)
Refining & Marketing Refined Product Sales Volume (thousands of barrels per day)(c)	1,951		1,880
Refining & Marketing Gross Margin (dollars per barrel)(d)	$	14.46	$	15.29
Crude Oil Capacity Utilization percent(e)	85		93
Refinery Throughputs (thousands of barrels per day):(f)
Crude oil refined	1,450		1,433
Other charge and blendstocks	200		238
Total	1,650		1,671
Sour Crude Oil Throughput percent	49		54
WTI-Priced Crude Oil Throughput percent	21		22
Refined Product Yields (thousands of barrels per day):(f)
Gasoline	837		889
Distillates	514		523
Propane	34		32
Feedstocks and special products	220		184
Heavy fuel oil	30		30
Asphalt	43		46
Total	1,678		1,704
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	3.15	$	1.15
Depreciation and amortization	1.55		1.42
Other manufacturing(h)	5.95		3.81
Total	$	10.65	$	6.38
Refining & Marketing Operating Statistics By Region
Gulf Coast:(b)
Refinery Throughputs (thousands of barrels per day):(i)
Crude oil refined	860		837
Other charge and blendstocks	211		211
Total	1,071		1,048
Sour Crude Oil Throughput percent	60		68
WTI-Priced Crude Oil Throughput percent	3		6
Refined Product Yields (thousands of barrels per day):(i)
Gasoline	489		531
Distillates	319		322
Propane	21		19
Feedstocks and special products	245		179
Heavy fuel oil	15		18
Asphalt	7		6
Total	1,096		1,075
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	3.83	$	0.87
Depreciation and amortization	1.25		1.13
Other manufacturing(h)	5.87		3.29
Total	$	10.95	$	5.29

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Supplementary Statistics (Unaudited)
	Three Months Ended   March 31,
	2014			2013
Refining & Marketing Operating Statistics By Region
Midwest:
Refinery Throughputs (thousands of barrels per day):(i)
Crude oil refined	590			596
Other charge and blendstocks	48			56
Total	638			652
Sour Crude Oil Throughput percent	34			35
WTI-Priced Crude Oil Throughput percent	47			45
Refined Product Yields (thousands of barrels per day):(i)
Gasoline	348			358
Distillates	195			201
Propane	13			13
Feedstocks and special products	33			34
Heavy fuel oil	16			12
Asphalt	36			40
Total	641			658
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.71		$	1.56
Depreciation and amortization	1.91			1.82
Other manufacturing(h)	5.54			4.47
Total	$	9.16		$	7.85
Speedway Operating Statistics
Convenience stores at period-end	1,482			1,463
Gasoline and distillate sales (millions of gallons)	773			745
Gasoline and distillate gross margin (dollars per gallon)(j)	$	0.1156		$	0.1301
Merchandise sales (in millions)	$	722		$	711
Merchandise gross margin (in millions)	$	192		$	184
Same store gasoline sales volume (period over period)	(0.7		)%	0.7		%
Same store merchandise sales (period over period)(k)	5.3		%	0.8		%
Pipeline Transportation Operating Statistics
Pipeline Throughputs (thousands of barrels per day):(l)
Crude oil pipelines	1,144			1,272
Refined products pipelines	819			917
Total	1,963			2,189

^(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.

^(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 59 mbpd and 29 mbpd for the three months ended March 31, 2014 and 2013, respectively.

^(g)  Per barrel of total refinery throughputs.

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

⁽ⁱ⁾  Includes inter-refinery transfer volumes.

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

^(k)  Excludes cigarettes.

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

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Part II – Other Information

Item 1. 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.

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.

Environmental Proceedings

We are involved in a number of environmental proceedings arising in the ordinary course of business. While the 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 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. The discussion of such risks and uncertainties may be found under Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2013.

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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table sets forth a summary of our purchases during the quarter ended March 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)
01/01/2014-01/31/2014	968,989	$	87.46	959,300	$	1,773,147,021
02/01/2014-02/28/2014	3,059,067	$	85.95	3,035,300	1,512,294,007
03/01/2014-03/31/2014	3,880,356	$	88.93	3,865,900	1,168,445,346
Total	7,908,412	$	87.60	7,860,500

^(a)  The amounts in this column include 9,689, 23,767 and 14,456 shares of our common stock delivered by employees to MPC, upon vesting of restricted stock, to satisfy tax withholding requirements in January, February and March, respectively.

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

^(c)  On September 26, 2013, we announced that our board of directors approved an additional $2.0 billion share repurchase authorization through September 30, 2015, resulting in $6.0 billion of total share repurchase authorizations since January 1, 2012. As of March 31, 2014, we had approximately $1.17 billion of share repurchase authorization remaining.

44

Item 6. Exhibits

			Incorporated by Reference			Filed Herewith	Furnished Herewith
Exhibit Number	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.
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
10.1	Form of Marathon Petroleum Corporation Performance Unit Award Agreement - 2014-2016 Performance Cycle					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

45

SIGNATURES

Pursuant to the requirements 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.

May 5, 2014	MARATHON PETROLEUM CORPORATION
	By:	/s/ Michael G. Braddock
		Michael G. Braddock Vice President and Controller

46

EX-10.1

Exhibit 10.1

MARATHON PETROLEUM CORPORATION

PERFORMANCE UNIT AWARD AGREEMENT

2014-2016 PERFORMANCE CYCLE

Pursuant to this Award Agreement and the Marathon Petroleum Corporation 2012 Incentive Compensation Plan (the “Plan”), MARATHON PETROLEUM CORPORATION (the “Corporation”) hereby grants to [NAME] (the “Participant”), an employee of the Corporation or a Subsidiary, on [DATE] (the “Grant Date”), [NUMBER] performance units (“Performance Units”), conditioned upon the Corporation’s TSR ranking relative the Peer Group for the Performance Cycle as established by the Compensation Committee of the Board of Directors of the Corporation (the “Committee”), and as set forth herein. The Performance Units are subject to the following terms and conditions:

1.    Relationship to the Plan. This grant of Performance Units is subject to all of the terms, conditions and provisions of the Plan and administrative interpretations thereunder, if any, that have been adopted by the Committee. Except as otherwise defined in this Award Agreement, capitalized terms shall have the same meanings given to them under the Plan. To the extent that any provision of this Award Agreement conflicts with the express terms of the Plan, the terms of the Plan shall control and, if necessary, the applicable provisions of this Award Agreement shall be hereby deemed amended so as to carry out the purpose and intent of the Plan. References to the Participant also include the heirs or other legal representatives of the Participant.

2.    Determination of Payout Percentage. As soon as practical following the close of the Performance Cycle, the Committee shall determine and certify the TSR Performance Percentile. The final Payout Percentage will be the simple average of the Payout Percentage of the four performance periods, which are as follows:

(i) January 1, 2014 through December 31, 2014

(ii) January 1, 2015 through December 31, 2015

(iii) January 1, 2016 through December 31, 2016

(iv) January 1, 2014 through December 31, 2016

The Committee shall determine the Payout Percentage for each performance period as follows:

(a)     If the TSR Performance Percentile is below the 25^th percentile, the Payout Percentage for that period shall be zero.

(b)     If the TSR Performance Percentile is at or above the 25^th percentile, the Payout Percentage shall be equal to the TSR Performance Percentile multiplied by 2.

1

Exhibit 10.1

(c)    Notwithstanding anything herein to the contrary, if the TSR calculated for the performance period is negative, then the Payout Percentage for that performance period shall not exceed 100% regardless of the TSR Performance Percentile for the performance period.

(d)    Notwithstanding anything herein to the contrary, the Committee has sole and absolute authority and discretion to reduce the Payout Percentage as it may deem appropriate.

3.    Vesting of Performance Units. Unless the Participant’s right to the Performance Units is previously forfeited or vested in accordance with Paragraphs 4, 5, 6 or 7, following the Committee’s determinations pursuant to Paragraph 2, the Participant shall vest in and be entitled to receive a payment equal to the Payout Value. The Payout Value shall be distributed 75% in cash and 25% in common stock. The number of shares of common stock distributed shall be calculated by dividing 25% of the Payout Value by the closing price as defined in the Plan as of the closing on the date on which the Payout Percentage is determined and certified by the Committee, rounding the shares down to the nearest whole share. The remainder shall be paid in cash. Such payments shall be made as soon as administratively feasible following the Committee’s determination under Paragraph 2 and, in any event, on or before March 15^th following the end of the Performance Cycle. If, in accordance with the Committee’s determination under Paragraph 2, the Payout Value is zero, the Participant shall immediately forfeit any and all rights to the Performance Units. Upon the vesting and/or forfeiture of the Performance Units pursuant to this Paragraph 3 and the making of the related cash payment, if any, the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be satisfied in full.

4.    Termination of Employment. If Participant’s Employment is terminated prior to the close of the Performance Cycle for any reason other than death or Retirement as set forth in Paragraphs 5 and 6 below (or as set forth in Paragraph 7), the Participant’s right to the Performance Units shall be forfeited in its entirety as of such termination, and the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be terminated.

5.    Termination of Employment due to Death. If Participant’s Employment is terminated by reason of death prior to the close of the Performance Cycle, the Participant’s right to receive the Performance Units shall vest in full as of the date of death and the Payout Percentage shall be 100%. The payment equal to the vested value of the Performance Units shall be made in accordance with Paragraph 3 on the first day of the third month following the death of the Participant. Such vesting shall satisfy the rights of the Participant and the obligations of the Corporation under this Award Agreement in full.

6.    Termination of Employment due to Retirement. In the event of the Retirement of the Participant after 50% of the Performance Cycle has elapsed, the Participant’s Performance Units shall be paid-out based on the performance for the Performance Cycle and payable on a pro-rata basis as determined and certified by the Committee at the close of the Performance Cycle as described below. Subject to the negative discretion of the Committee, the Participant will be entitled to receive a payment equal to the product of (i) the pro-rata vesting percentage equal to the days of Participant’s Employment during the Performance Cycle divided by the total days in the Performance Cycle and (ii) the Payout Value. Such payment shall be made as soon as administratively practical following the Committee’s determination under Paragraph 2 and, in any event, on or before March 15^th following the end of the Performance Cycle. If, in accordance with the Committee’s determination under Paragraph 2, the Payout Value is zero, the Participant shall immediately forfeit any and all rights to the Performance Units. Upon the vesting and/or forfeiture of the Performance Units pursuant to this Paragraph 6 and the making of the related cash payment, if any, the rights of the Participant and the obligations of the Corporation under this Award Agreement shall be

2

Exhibit 10.1

satisfied in full. The death of the Participant following Retirement but prior to the close of the Performance Cycle shall have no effect on this Paragraph 6.

7.    Vesting Upon a Qualified Termination. Notwithstanding anything herein to the contrary, upon a Participant’s Qualified Termination as defined under the Marathon Petroleum Corporation Amended and Restated Executive Change in Control Severance Benefits Plan prior to the end of the Performance Cycle, the Participant’s right to receive the Performance Units, unless previously forfeited pursuant to Paragraph 4, shall vest in full and the Payout Percentage shall be 100%. A payment equal to the vested value of the Performance Units shall be made in accordance with Paragraph 3 on the first day of the third month following the Qualified Termination. Such vesting shall satisfy the rights of the Participant and the obligations of the Corporation under this Award Agreement in full.

8.    Notwithstanding the foregoing, if the Participant is a “specified employee” as determined by the Corporation in accordance with its established policy, any settlement of Awards described in the previous paragraph or elsewhere in this Award Agreement which would be a payment of deferred compensation within the meaning of Section 409A of the Code with respect to the Participant as a result of the Participant’s “separation from service” as defined under Section 409A of the Code (other than as a result of death) and which would otherwise be paid within six months of the Participant’s separation from service shall be payable on the date that is one day after the earlier of (i) the date that is six months after the Employee’s separation from service or (ii) the date that otherwise complies with the requirements of Section 409A of the Code. In addition, notwithstanding any provision of the Plan or this Award Agreement to the contrary, any settlement of this Award which would be a payment of deferred compensation within the meaning of Section 409A of the Code with respect to the Participant and is a settlement as a result of the Participant’s separation from service in connection with a Change in Control, the term “Change in Control” under the Plan shall mean a change in ownership or change in effective control for purposes of Section 409A of the Code. The payment of Award amounts under this Award Agreement described herein is hereby designated as a “separate payment” for purposes of Section 409A of the Code.

9.    Repayment or Forfeiture Resulting from Forfeiture Event.

(a)    If there is a Forfeiture Event either while the Participant is employed or within three years after termination of the Participant’s Employment, then the Committee may, but is not obligated to, cause some or all of the Participant’s outstanding Performance Units to be forfeited by the Participant.

(b)    If there is a Forfeiture Event either while the Participant is employed or within three years after termination of the Participant’s Employment and a payment has previously been made in settlement of Performance Units granted under this Award Agreement, the Committee may, but is not obligated to, require that the Participant pay to the Corporation an amount in cash (the “Forfeiture Amount”) up to (but not in excess of) the amount paid in settlement of the Performance Units.

(c)     This Paragraph 9 shall apply notwithstanding any provision of this Award Agreement to the contrary and is meant to provide the Corporation with rights in addition to any other remedy which may exist in law or in equity. This Paragraph 9 shall not apply to the Participant following the effective time of a Change in Control.

(d)    Notwithstanding the foregoing or any other provision of this Award Agreement to the contrary, the Participant agrees that the Corporation may also require that the Participant repay to the Corporation any compensation paid to the Participant under this Award Agreement, 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.

3

Exhibit 10.1

10.    Taxes. Pursuant to the applicable provisions of the Plan, the Corporation or its designated representative shall have the right to withhold applicable taxes from the cash otherwise payable to the Participant, or from other compensation payable to the Participant, at the time of the vesting and delivery of such cash payment.

11.    No Shareholder Rights. The Participant shall in no way be entitled to any of the rights of a shareholder as a result of this Award Agreement.

12.    Nonassignability. Upon the Participant’s death, the Performance Units may be transferred by will or by the laws governing the descent and distribution of the Participant’s estate. Otherwise, the Participant may not sell, transfer, assign, pledge or otherwise encumber any portion of the Performance Units, and any attempt to sell, transfer, assign, pledge, or encumber any portion of the Performance Units shall have no effect.

13.    No Employment Guaranteed. Nothing in this Award Agreement shall give the Participant any rights to (or impose any obligations for) continued Employment by the Corporation or any affiliate thereof or successor thereto, nor shall it give such entities any rights (or impose any obligations) with respect to continued performance of duties by the Participant.

14.    Modification of Agreement. Any modification of this Award Agreement shall be binding only if evidenced in writing and signed by an authorized representative of the Corporation, provided that no modification may, without the consent of the Participant, adversely affect the rights of the Participant hereunder.

15.    Officer Holding Requirement. Participant agrees that any shares received by the Participant in settlement of this Award shall be subject an additional holding period of one year from the date on which the Award is settled, during which holding period such shares (net of shares used to satisfy the applicable tax withholding requirements) may not be sold or transferred by the Participant. This holding requirement shall cease to apply upon the death, retirement or other separation from service of the Participant during the holding period.

16.    Definitions. For purposes of this Award Agreement:

“Beginning Stock Price” means the average of the daily closing price of common stock for the twenty (20) trading days immediately prior to the commencement of the Performance Cycle, historically adjusted, if necessary, for any stock split, stock dividend, recapitalizations, or similar corporate events that occur during the measurement period.

“Employment” means employment with the Corporation or any of its Subsidiaries. For purposes of this Award Agreement, Employment shall also include any period of time during which the Participant is on Disability status. The length of any period of Employment shall be determined by the Corporation or the Subsidiary that either (i) employs the Participant or (ii) employed the Participant immediately prior to the Participant’s termination of Employment.

“Ending Stock Price” means the average of the daily closing price of common stock for the twenty (20) trading days prior to the end of the Performance Cycle.

“Forfeiture Event” means the occurrence of at least one of the following (a) the Corporation is required, pursuant to a determination made by the Securities and Exchange Commission or by the Audit

4

Exhibit 10.1

Committee of the Board, to prepare a material accounting restatement due to the noncompliance of the Corporation with any financial reporting requirement under applicable securities laws as a result of misconduct, and the Committee determines that (1) the Participant knowingly engaged in the misconduct, (2) the Participant was grossly negligent with respect to such misconduct or (3) the Participant knowingly or grossly negligently failed to prevent the misconduct or (b) the Committee concludes that the Participant engaged in fraud, embezzlement or other similar misconduct materially detrimental to the Corporation.

“Payout Percentage” means the percentage (between 0% and 200%) determined by the Committee in accordance with the procedures set forth in Paragraph 2, which shall be used to determine the value of each Performance Unit.

“Payout Value” means the product of the Payout Percentage and the number of Performance Units.

“Peer Group” means the group of companies that are pre-established by the Committee which principally represent a group of selected peers, or such other group of companies as selected and pre-established by the Committee. Such pre-established Peer Group is subject to the following adjustments:

(a) If a member of the Peer Group is substantially acquired by another company, the acquired Peer Group company will be removed from the Peer Group for the performance periods not yet completed and for the entire 36-month Performance Cycle.

(b) If a member of the Peer Group sells, spins-off, or disposes of a portion of its business, then such Peer Group company will remain in the Peer Group for the Performance Cycle unless such disposition(s) results in the disposition of more than 50% of such company’s total assets during the Performance Cycle.

(c) If a member of the Peer Group acquires another company, the acquiring Peer Group company will remain in the Peer Group for the Performance Cycle, unless the newly formed company’s primary business no longer satisfies the criteria for which such member was originally selected as a member of the Peer Group, then in such case the company shall be removed from the Peer Group.

(d) If a member of the Peer Group is delisted on all major U.S. stock exchanges, or is no longer publically traded, such company will be removed from the Peer Group for the Performance Cycle.

(e) If any member of the Peer Group splits its stock, such company’s TSR performance will be adjusted for the stock split so as not to give an advantage or disadvantage to such company by comparison to the other companies.

(f) Members of the Peer Group that file for bankruptcy, liquidation or reorganization during the Performance Cycle will remain in the Peer Group positioned below the lowest performing non-bankrupt member of the Peer Group for performance periods not yet completed and for the entire 36-month Performance Cycle.

In addition, the Committee shall have the discretionary authority to make other appropriate adjustments, consistent with Section 162(m) of the Code, in response to a change in circumstances after the commencement of the Performance Cycle that results in a member of the Peer Group no longer satisfying the criteria for which such member was originally selected. In applying the described adjustments, the event that any adjustment is made to the Peer Group during any Performance Cycle, the Corporation’s relative TSR ranking within the Peer Group will be calculated for any incomplete or future performance periods (including the entire 36-month Performance Cycle) as if that company was not a peer at the start of each

5

Exhibit 10.1

incomplete performance period. Relative TSR ranking for performance periods completed prior to the removal of the peer will not be recalculated.

“Performance Cycle” means the period from January 1, 2014 to December 31, 2016.

“Qualified Termination” for purposes of this Award Agreement shall have the same definition as under the Marathon Petroleum Corporation Amended and Restated Executive Change in Control Severance Benefits Plan, as in effect on the Grant Date, and such definition and associated terms are hereby incorporated into this Award Agreement by reference.

"Retirement" means (a) for an Employee with ten or more years of Employment, termination on or after the Employee's 50th birthday, or (b) termination on or after the Employee's 65th birthday.

“Total Shareholder Return” or “TSR” means the number derived using the following formula:

(End Stock Price – Beginning Stock Price) + Cumulative Dividends

Beginning Stock Price.

6

Exhibit 10.1

“TSR Performance Percentile” means the relative ranking of the Corporation’s Total Shareholder Return for the Performance Cycle as compared to the Total Shareholder Return of the Peer Group companies during the Performance Cycle.

Marathon Petroleum Corporation

By ___________________________

                         Authorized Officer

7

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-Q 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:	May 5, 2014	/s/ Gary R. Heminger
		Gary R. Heminger
		President and Chief Executive Officer

EX-31.2

Exhibit 31.2

MARATHON PETROLEUM CORPORATION

CERTIFICATION PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

I, Donald C. Templin, certify that:

1. I have reviewed this report on Form 10-Q 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:	May 5, 2014	/s/ Donald C. Templin
		Donald C. Templin
		Senior Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Marathon Petroleum Corporation (the “Company”) on Form 10-Q for the period ending March 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.

May 5, 2014

/s/ Gary R. Heminger

Gary R. Heminger

President and Chief Executive Officer

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Marathon Petroleum Corporation (the “Company”) on Form 10-Q for the period ending March 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.

May 5, 2014

/s/ Donald C. Templin

Donald C. Templin

Senior Vice President and Chief Financial Officer

XML

Fair Value Measurements (Tables)

3 Months Ended

Mar. 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 March 31, 2014 and December 31, 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.

	March 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	$	41	$	—	$	—	$	(39	)	$	2	$	82
Other assets	2		—		—		N/A			2		—
Total assets at fair value	$	43	$	—	$	—	$	(39	)	$	4	$	82
Commodity derivative instruments, liabilities	$	81	$	—	$	—	$	(81	)	$	—	$	—
Contingent consideration, liability(c)	—		—		639		N/A			639		—
Total liabilities at fair value	$	81	$	—	$	639	$	(81	)	$	639	$	—

	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 March 31, 2014 and December 31, 2013, cash collateral of $42 million and $32 million, respectively, was netted with mark-to-market derivative liabilities.

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

^(c)  Includes $178 million and $159 million classified as current at March 31, 2014 and December 31, 2013, respectively.

Reconciliation of Net Beginning and Ending Balances Recorded for Net Assets and Liabilities Classified as Level 3

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

	Three Months Ended   March 31,
(In millions)	2014		2013
Beginning balance	$	625	$	—
Contingent consideration agreement	—		600
Total realized and unrealized losses included in net income	14		—
Ending balance	$	639	$	600

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

	March 31, 2014				December 31, 2013
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial assets:
Investments	$	39	$	13	$	336	$	14
Other	30		28		31		30
Total financial assets	$	69	$	41	$	367	$	44
Financial liabilities:
Long-term debt(a)	$	3,670	$	3,270	$	3,306	$	3,001
Deferred credits and other liabilities	21		21		21		21
Total financial liabilities	$	3,691	$	3,291	$	3,327	$	3,022

^(a)  Excludes capital leases

XML

Related Party Transactions - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014 TAAE	Oct. 02, 2013 TAAE	Mar. 31, 2014 TACE	Mar. 31, 2014 TAME	Mar. 31, 2014 Centennial	Dec. 31, 2013 Centennial	Mar. 31, 2014 Explorer	Mar. 31, 2014 LOCAP	Mar. 31, 2014 LOOP
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	43.00%	43.00%	60.00%	67.00%	50.00%		25.00%	59.00%	51.00%
Long-term receivable from related party					$ 2	$ 2

XML

MPLX LP (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		0 Months Ended					0 Months Ended			6 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 01, 2014 MPLX Pipe Line Holdings LP	May 01, 2013 MPLX Pipe Line Holdings LP	Mar. 01, 2014 MPLX LP MPLX Revolver	Mar. 01, 2014 MPLX LP Cash and cash equivalents	Oct. 31, 2012 MPLX LP Butane Cavern	Mar. 01, 2014 MPLX LP MPLX Pipe Line Holdings LP	Mar. 31, 2014 MPLX LP General Partner and Limited Partner	Mar. 31, 2014 MPLX LP General Partner	Apr. 30, 2013 MPLX LP General Partner MPLX Pipe Line Holdings LP
Noncontrolling Interest [Line Items]
MPC's partnership interest in MPLX (in percentage)									73.60%	2.00%
Ownership interest (in percentage)								69.00%			51.00%
Ownership interest in assets owned by company in affiliate							100.00%
Additional interest sold			13.00%	5.00%
Proceeds from sale of ownership interest			$ 310	$ 100
Cash paid for acquisition	$ 0	$ 1,493			$ 270	$ 40

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Inventories - Summary Of Inventories (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Inventory Disclosure [Abstract]
Crude oil and refinery feedstocks	$ 2,734	$ 1,797
Refined products	2,540	2,367
Materials and supplies	333	425
Merchandise	82	100
Total (at cost)	$ 5,689	$ 4,689

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Related Party Transactions - Sales to Related Parties (Detail) (Other equity method investees, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Other equity method investees
Related Party Transaction [Line Items]
Sales to related parties	$ 2	$ 2

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Derivatives - Open Commodity Derivative Contracts (Detail)	3 Months Ended
	Mar. 31, 2014
Crude Oil Exchange-Traded
Derivative [Line Items]
Percentage of derivative contracts expiring in the period	100.00%
Derivative contract expiration date	Jun. 30, 2014
Crude Oil Exchange-Traded | Long
Derivative [Line Items]
Notional Contracts (in thousands of Total Barrels)	9,640,000	[1]
Crude Oil Exchange-Traded | Short
Derivative [Line Items]
Notional Contracts (in thousands of Total Barrels)	35,375,000	[1]
Refined Products Exchange-Traded
Derivative [Line Items]
Percentage of derivative contracts expiring in the period	100.00%
Derivative contract expiration date	Jun. 30, 2014
Refined Products Exchange-Traded | Long
Derivative [Line Items]
Notional Contracts (in thousands of Total Barrels)	2,317,000	[1]
Refined Products Exchange-Traded | Short
Derivative [Line Items]
Notional Contracts (in thousands of Total Barrels)	3,658,000	[1]

[1] 100 percent of these contracts expire in the second quarter of 2014.

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Supplementary Statistics (Tables)

3 Months Ended

Mar. 31, 2014

Text Block [Abstract]

Supplementary Statistics

Supplementary Statistics (Unaudited)

	Three Months Ended   March 31,
(In millions)	2014			2013
Income from Operations by segment
Refining & Marketing	$	362		$	1,105
Speedway	58			67
Pipeline Transportation(a)	72			51
Items not allocated to segments:
Corporate and other unallocated items(a)	(67		)	(67		)
Pension settlement expenses	(64		)	—
Income from operations	$	361		$	1,156
Capital Expenditures and Investments(b)(c)
Refining & Marketing	$	178		$	1,420
Speedway	32			36
Pipeline Transportation	130			90
Corporate and Other(d)	31			28
Total	$	371		$	1,574

^(a)  Corporate overhead costs attributable to MPLX are included in the Pipeline Transportation segment. These expenses are not allocated to the Refining & Marketing and Speedway segments.

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

^(c)  The three months ended March 31, 2013 includes the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, plus assumed liabilities. Total consideration includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 4 to the unaudited consolidated financial statements.

^(d)  Includes capitalized interest $6 million and $4 million for the three months ended March 31, 2014 and 2013, respectively.

Operating Statistics

Supplementary Statistics (Unaudited)

	Three Months Ended   March 31,
	2014		2013
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)(a)(b)	1,964		1,895
Refining & Marketing Operating Statistics(b)
Refining & Marketing Refined Product Sales Volume (thousands of barrels per day)(c)	1,951		1,880
Refining & Marketing Gross Margin (dollars per barrel)(d)	$	14.46	$	15.29
Crude Oil Capacity Utilization percent(e)	85		93
Refinery Throughputs (thousands of barrels per day):(f)
Crude oil refined	1,450		1,433
Other charge and blendstocks	200		238
Total	1,650		1,671
Sour Crude Oil Throughput percent	49		54
WTI-Priced Crude Oil Throughput percent	21		22
Refined Product Yields (thousands of barrels per day):(f)
Gasoline	837		889
Distillates	514		523
Propane	34		32
Feedstocks and special products	220		184
Heavy fuel oil	30		30
Asphalt	43		46
Total	1,678		1,704
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	3.15	$	1.15
Depreciation and amortization	1.55		1.42
Other manufacturing(h)	5.95		3.81
Total	$	10.65	$	6.38
Refining & Marketing Operating Statistics By Region
Gulf Coast:(b)
Refinery Throughputs (thousands of barrels per day):(i)
Crude oil refined	860		837
Other charge and blendstocks	211		211
Total	1,071		1,048
Sour Crude Oil Throughput percent	60		68
WTI-Priced Crude Oil Throughput percent	3		6
Refined Product Yields (thousands of barrels per day):(i)
Gasoline	489		531
Distillates	319		322
Propane	21		19
Feedstocks and special products	245		179
Heavy fuel oil	15		18
Asphalt	7		6
Total	1,096		1,075
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	3.83	$	0.87
Depreciation and amortization	1.25		1.13
Other manufacturing(h)	5.87		3.29
Total	$	10.95	$	5.29

Supplementary Statistics (Unaudited)
	Three Months Ended   March 31,
	2014			2013
Refining & Marketing Operating Statistics By Region
Midwest:
Refinery Throughputs (thousands of barrels per day):(i)
Crude oil refined	590			596
Other charge and blendstocks	48			56
Total	638			652
Sour Crude Oil Throughput percent	34			35
WTI-Priced Crude Oil Throughput percent	47			45
Refined Product Yields (thousands of barrels per day):(i)
Gasoline	348			358
Distillates	195			201
Propane	13			13
Feedstocks and special products	33			34
Heavy fuel oil	16			12
Asphalt	36			40
Total	641			658
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.71		$	1.56
Depreciation and amortization	1.91			1.82
Other manufacturing(h)	5.54			4.47
Total	$	9.16		$	7.85
Speedway Operating Statistics
Convenience stores at period-end	1,482			1,463
Gasoline and distillate sales (millions of gallons)	773			745
Gasoline and distillate gross margin (dollars per gallon)(j)	$	0.1156		$	0.1301
Merchandise sales (in millions)	$	722		$	711
Merchandise gross margin (in millions)	$	192		$	184
Same store gasoline sales volume (period over period)	(0.7		)%	0.7		%
Same store merchandise sales (period over period)(k)	5.3		%	0.8		%
Pipeline Transportation Operating Statistics
Pipeline Throughputs (thousands of barrels per day):(l)
Crude oil pipelines	1,144			1,272
Refined products pipelines	819			917
Total	1,963			2,189

^(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.

^(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 59 mbpd and 29 mbpd for the three months ended March 31, 2014 and 2013, respectively.

^(g)  Per barrel of total refinery throughputs.

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

⁽ⁱ⁾  Includes inter-refinery transfer volumes.

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

^(k)  Excludes cigarettes.

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

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Income per Common Share (Tables)

3 Months Ended

Mar. 31, 2014

Earnings Per Share [Abstract]

Summary of Earnings Per Common Share

	Three Months Ended   March 31,
(In millions, except per share data)	2014		2013
Basic earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	199	$	725
Income allocated to participating securities	—		1
Income available to common stockholders - basic	$	199	$	724
Weighted average common shares outstanding	293		331
Basic earnings per share	$	0.68	$	2.19
Diluted earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	199	$	725
Income allocated to participating securities	—		1
Income available to common stockholders - diluted	$	199	$	724
Weighted average common shares outstanding	293		331
Effect of dilutive securities	2		2
Weighted average common shares, including dilutive effect	295		333
Diluted earnings per share	$	0.67	$	2.17

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Derivatives - Effect of Commodity Derivative Instruments in Statements of Income (Detail) (Commodity derivatives, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ (51)	$ (59)
Sales and other operating revenues
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	10	1
Cost of revenues
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ (61)	$ (60)

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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	Mar. 31, 2014		Dec. 31, 2013
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash collateral	$ 42		$ 32
Liabilities, current	178		159
Fair Value, Measurements, Recurring
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets	2	[1]	0	[1]
Other assets	2		2
Total assets at fair value	4		2
Commodity derivative instruments, liabilities	0	[1]	0	[1]
Contingent consideration, liability	639	[2]	625	[2]
Total liabilities at fair value	639		625
Level 1 | Fair Value, Measurements, Recurring
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets	41		21
Other assets	2		2
Total assets at fair value	43		23
Commodity derivative instruments, liabilities	81		53
Contingent consideration, liability	0		0
Total liabilities at fair value	81		53
Level 2 | Fair Value, Measurements, Recurring
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets	0		0
Other assets	0		0
Total assets at fair value	0		0
Commodity derivative instruments, liabilities	0		0
Contingent consideration, liability	0		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	0		0
Other assets	0		0
Total assets at fair value	0		0
Commodity derivative instruments, liabilities	0		0
Contingent consideration, liability	639	[2]	625	[2]
Total liabilities at fair value	639		625
Netting and Collateral | Fair Value, Measurements, Recurring
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets	(39)	[3]	(21)	[3]
Total assets at fair value	(39)	[3]	(21)	[3]
Commodity derivative instruments, liabilities	(81)	[3]	(53)	[3]
Total liabilities at fair value	(81)	[3]	(53)	[3]
Collateral Pledged Not Offset | Fair Value, Measurements, Recurring
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets	82		61
Other assets	0		0
Total assets at fair value	82		61
Commodity derivative instruments, liabilities	0		0
Contingent consideration, liability	0		0
Total liabilities at fair value	$ 0		$ 0

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

[2] Includes $178 million and $159 million classified as current at March 31, 2014 and December 31, 2013, respectively.

[3] Represents the impact of netting assets, liabilities and cash collateral when a legal right of offset exists. As of March 31, 2014 and December 31, 2013, cash collateral of $42 million and $32 million, respectively, was netted with mark-to-market derivative liabilities.

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Stock-Based Compensation Plans - Summary of Restricted Stock Award Activity (Detail) (USD $)	3 Months Ended
	Mar. 31, 2014
Restricted Stock
Number of Shares
Outstanding, beginning balance	624,122
Granted	51,594
RS's Vested/RSU's Issued	(117,980)
Forfeited	(14,840)
Outstanding, ending balance	542,896
Weighted Average Grant Date Fair Value
Outstanding, beginning balance (in USD per share)	$ 61.11
Granted (in USD per share)	$ 83.45
RS's Vested/RSU's Issued (in USD per share)	$ 54.43
Forfeited (in USD per share)	$ 64.31
Outstanding, ending balance (in USD per share)	$ 64.60
Restricted Stock Units
Number of Shares
Outstanding, beginning balance	385,079
Granted	5,939
RS's Vested/RSU's Issued	0
Forfeited	0
Outstanding, ending balance	391,018
Weighted Average Grant Date Fair Value
Outstanding, beginning balance (in USD per share)	$ 33.96
Granted (in USD per share)	$ 89.96
RS's Vested/RSU's Issued (in USD per share)	$ 0.00
Forfeited (in USD per share)	$ 0.00
Outstanding, ending balance (in USD per share)	$ 34.81

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Related Party Transactions Related Party Transactions - Receivables From Related Parties (Details) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Current receivables from related parties	$ 5	$ 2
Centennial
Related Party Transaction [Line Items]
Current receivables from related parties	0	1
Explorer
Related Party Transaction [Line Items]
Current receivables from related parties	5	0
TAME
Related Party Transaction [Line Items]
Current receivables from related parties	$ 0	$ 1

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Fair Value Measurements - Financial Instruments at Fair Value, Excluding Derivative Financial Instruments and Contingent Consideration (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013
Fair Value
Financial assets:
Investments	$ 39		$ 336
Other	30		31
Total financial assets	69		367
Financial liabilities:
Long-term debt	3,670	[1]	3,306	[1]
Deferred credits and other liabilities	21		21
Total financial liabilities	3,691		3,327
Carrying Value
Financial assets:
Investments	13		14
Other	28		30
Total financial assets	41		44
Financial liabilities:
Long-term debt	3,270	[1]	3,001	[1]
Deferred credits and other liabilities	21		21
Total financial liabilities	$ 3,291		$ 3,022

[1] Excludes capital leases

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Defined Benefit Pension and Other Postretirement Plans - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension settlement expenses	$ (64)	$ 0
Pension Benefits | Funded Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Employer contributions	0
Pension Benefits | Unfunded Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, benefits paid	8
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension settlement expenses	0	0
Other Benefits | Unfunded Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, benefits paid	$ 5

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Debt - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
MPC Revolver
Line of Credit Facility [Line Items]
Borrowings outstanding	$ 0	$ 0
Line of credit facility, expiration date	Sep. 14, 2017
MPLX Operations LLC | MPLX Revolver
Line of Credit Facility [Line Items]
Borrowings outstanding	270	0
Line of credit facilitiy, borrowings during period	270
Interest rate during period	1.50%
Remaining borrowing capacity	230
Remaining borrowing capacity, percentage	46.00%
Line of credit facility, expiration date	Oct. 31, 2017
Revolving Credit Facility | MPLX Operations LLC | MPLX Revolver
Line of Credit Facility [Line Items]
Borrowings outstanding	270
Letter of Credit | MPLX Operations LLC | MPLX Revolver
Line of Credit Facility [Line Items]
Borrowings outstanding	$ 0

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Stock-Based Compensation Plans - Summary of Stock Option Award Activity (Detail) (Stock Options, USD $)	3 Months Ended
	Mar. 31, 2014
Stock Options
Number of Shares
Outstanding, beginning balance	5,147,837	[1]
Granted	327,100	[1]
Exercised	(455,999)	[1]
Forfeited, canceled or expired	(19,293)	[1]
Outstanding, ending balance	4,999,645	[1]
Weighted Average Exercise Price
Outstanding, beginning balance (in USD per share)	$ 40.08
Granted (in USD per share)	$ 83.37
Exercised (in USD per share)	$ 30.65
Forfeited, canceled or expired (in USD per share)	$ 50.05
Outstanding, ending balance (in USD per share)	$ 43.73

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

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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	Mar. 31, 2014	Dec. 31, 2013
Commodity derivatives | Other current assets
Derivatives, Fair Value [Line Items]
Asset	$ 41	$ 21
Liability	$ 81	$ 53

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Inventories - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Inventory Disclosure [Abstract]
Impact on revenues and costs as a result of LIFO liquidations	$ 0	$ 0

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Accumulated Other Comprehensive Loss

3 Months Ended

Mar. 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	67			9			—		—		76
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit(a)	(11		)	(2		)	—		—		(13		)
– actuarial loss(a)	21			1			—		—		22
Tax effect	(4		)	1			—		—		(3		)
Other comprehensive income	73			9			—		—		82
Balance as of March 31, 2013	$	(359	)	$	(27	)	$	4	$	—	$	(382	)

(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	(43		)	1			—		—		(42		)
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit(a)	(12		)	(1		)	—		—		(13		)
– actuarial loss(a)	13			1			—		—		14
– settlement loss(a)	64			—			—		—		64
Tax effect	(24		)	—			—		—		(24		)
Other comprehensive income (loss)	(2		)	1			—		—		(1		)
Balance as of March 31, 2014	$	(163	)	$	(49	)	$	4	$	3	$	(205	)

^(a)  These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 18.

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Acquisitions and Investments Acquisition and Investments (Schedule of Acquisition Related Pro Forma Financial Information) (Details) (Galveston Bay Refinery and Related Assets, USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2013
Galveston Bay Refinery and Related Assets
Business Acquisition [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ 25,296
Net income attributable to MPC	$ 780
Net income attributable to MPC per share - basic	$ 2.36
Net income attributable to MPC per share - diluted	$ 2.34

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Supplemental Cash Flow Information (Tables)

3 Months Ended

Mar. 31, 2014

Supplemental Cash Flow Elements [Abstract]

Summary of Supplemental Cash Flow Information

	Three Months Ended   March 31,
(In millions)	2014		2013
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	80	$	83
Net income taxes paid to (refunded from) taxing authorities	5		(5		)
Non-cash investing and financing activities:
Capital lease obligations increase	$	—	$	61
Acquisition:
Contingent consideration(a)	—		600
Payable to seller(a)	—		6

^(a)  Acquisition-date fair value of non-cash consideration associated with the Galveston Bay Refinery and Related Assets acquisition.

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:

	Three Months Ended   March 31,
(In millions)	2014			2013
Additions to property, plant and equipment	$	267		$	195
Acquisitions(a)	—			1,377
Decrease in capital accruals	(19		)	(3		)
Total capital expenditures	$	248		$	1,569

^(a)  The three months ended March 31, 2013 includes the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, plus assumed liabilities. Total consideration includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 4.

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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	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning balance	$ 625	$ 0
Contingent consideration agreement	0	600
Total realized and unrealized losses included in net income	14	0
Ending balance	$ 639	$ 600

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Inventories (Tables)

3 Months Ended

Mar. 31, 2014

Inventory Disclosure [Abstract]

Summary Of Inventories

(In millions)	March 31, 2014		December 31, 2013
Crude oil and refinery feedstocks	$	2,734	$	1,797
Refined products	2,540		2,367
Materials and supplies	333		425
Merchandise	82		100
Total (at cost)	$	5,689	$	4,689

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Acquisitions and Investments Acquisitions and Investments (Investments in Ethanol Companies) (Details) (USD $) In Millions, unless otherwise specified						1 Months Ended
	Mar. 31, 2014 TACE	Mar. 31, 2014 TAME	Mar. 31, 2014 TAME TAEI	Mar. 31, 2014 TAAE	Oct. 02, 2013 TAAE	Aug. 01, 2013 Ethanol Interests From Mitsui Companies	Aug. 01, 2013 Ethanol Interests From Mitsui TACE	Aug. 01, 2013 Ethanol Interests From Mitsui TAEI	Aug. 01, 2013 Ethanol Interests From Mitsui TAAE
Schedule of Equity Method Investments [Line Items]
Number of businesses in which ownership interests acquired						3
Cash paid to acquire equity method investments						$ 75
Ownership percentage acquired							24.00%	34.00%	40.00%
Equity method investments, ownership percentage	60.00%	67.00%	50.00%	43.00%	43.00%

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Segment Information - Reconciliation Of Total Revenues To Sales And Other Operating Revenues (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ 23,285	$ 23,330
Corporate and Other
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales and other operating revenues (including consumer excise taxes)	0	(6)
Reportable Segment
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ 23,285	$ 23,336

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Equity - Additional Information (Detail) (USD $) Share data in Millions, except Per Share data, unless otherwise specified	1 Months Ended	3 Months Ended			27 Months Ended	1 Months Ended	3 Months Ended
	Sep. 26, 2013	Mar. 31, 2014	Mar. 31, 2013		Mar. 31, 2014	Apr. 30, 2014 Scenario, Forecast	Mar. 31, 2013 Accelerated Share Repurchase Program November 2012
Stockholders Equity Note [Line Items]
Stock repurchase plan authorized amount					$ 6,000,000,000
Cash paid for shares repurchased		689,000,000	431,000,000		4,830,000,000	12,000,000
Stock repurchase plan remaining authorized amount					$ 1,170,000,000
Ending date of share repurchase authorization	September 2015
Number of shares repurchased		8	6	[1]	73		1
Effective average cost per delivered share		$ 87.60	$ 80.95		$ 66.19

[1] The three months ended March 31, 2013 includes one million shares received under the November 2012 accelerated share repurchase program, which were paid for in the fourth quarter of 2012.

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Description of the Business and Basis of Presentation Basis of Presentation (Details) (Total costs and expenses, Increase in prior year bonus expense, USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014
Total costs and expenses | Increase in prior year bonus expense
Quantifying Misstatement in Current Year Financial Statements [Line Items]
Quantifying misstatement in current year financial statements, amount	$ 29

XML

Description of the Business and Basis of Presentation

3 Months Ended

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

See Note 8 for additional information about our operations.

Basis of Presentation—All significant intercompany transactions and accounts have been eliminated.

These interim consolidated financial statements are unaudited; however, in the opinion of our management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported. All such adjustments are of a normal, recurring nature unless otherwise disclosed. These interim consolidated financial statements, including the notes, have been prepared in accordance with the rules of the Securities and Exchange Commission applicable to interim period financial statements and do not include all of the information and disclosures required by United States generally accepted accounting principles (“US GAAP”) for complete financial statements.

These interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2013. The results of operations for the three months ended March 31, 2014 are not necessarily indicative of the results to be expected for the full year.

During the three months ended March 31, 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 three months ended March 31, 2014 and for the year ended December 31, 2013 was immaterial. We do not expect this adjustment to have a material impact to our results of operations for the year ended December 31, 2014.

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Equity - Share Repurchases Transacted Through ASR Programs and Open Market Transactions (Detail) (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended			27 Months Ended
	Mar. 31, 2014	Mar. 31, 2013		Mar. 31, 2014
Stockholders Equity [Line Items]
Number of shares repurchased	8	6	[1]	73
Cash paid for shares repurchased	$ 689	$ 431		$ 4,830
Effective average cost per delivered share	$ 87.60	$ 80.95		$ 66.19
Accelerated Share Repurchase Program November 2012
Stockholders Equity [Line Items]
Number of shares repurchased		1

[1] The three months ended March 31, 2013 includes one million shares received under the November 2012 accelerated share repurchase program, which were paid for in the fourth quarter of 2012.

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Accumulated Other Comprehensive Loss (Tables)

3 Months Ended

Mar. 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	67			9			—		—		76
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit(a)	(11		)	(2		)	—		—		(13		)
– actuarial loss(a)	21			1			—		—		22
Tax effect	(4		)	1			—		—		(3		)
Other comprehensive income	73			9			—		—		82
Balance as of March 31, 2013	$	(359	)	$	(27	)	$	4	$	—	$	(382	)

(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	(43		)	1			—		—		(42		)
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit(a)	(12		)	(1		)	—		—		(13		)
– actuarial loss(a)	13			1			—		—		14
– settlement loss(a)	64			—			—		—		64
Tax effect	(24		)	—			—		—		(24		)
Other comprehensive income (loss)	(2		)	1			—		—		(1		)
Balance as of March 31, 2014	$	(163	)	$	(49	)	$	4	$	3	$	(205	)

^(a)  These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 18.

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Subsequent Event Subsequent Event

3 Months Ended

Mar. 31, 2014

Subsequent Event [Abstract]

Subsequent Events

Subsequent Event

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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Commitments and Contingencies

3 Months Ended

Mar. 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. For matters for which we have not recorded an accrued liability, we are unable to estimate a range of possible loss because the issues involved have not been fully developed through pleadings and discovery. However, the ultimate resolution of some of these contingencies could, individually or in the aggregate, be material.

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

At both March 31, 2014 and December 31, 2013, accrued liabilities for remediation totaled $123 million. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties if any that may be imposed. Receivables for recoverable costs from certain states, under programs to assist companies in clean-up efforts related to underground storage tanks at presently or formerly owned or operated retail marketing sites, were $50 million and $51 million at March 31, 2014 and December 31, 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. Both LOOP and LOCAP have secured various project financings with throughput and deficiency agreements. Under the agreements, we are required to advance funds if the investees are unable to service their debt. Any such advances are considered prepayments of future transportation charges. The duration of the agreements vary but tend to follow the terms of the underlying debt, which extend through 2037. Our maximum potential undiscounted payments under these agreements for the debt principal totaled $172 million as of March 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 $41 million as of March 31, 2014.

We hold an interest in an ethanol production facility through our investment in TAME, and through our participation as a lender under TAME’s revolving credit agreement, have agreed to reimburse the bank for 50 percent of any amounts drawn on a letter of credit that has been issued to secure TAME’s repayment of the tax exempt bonds. The credit agreement expires in 2018. Our maximum potential undiscounted payments under this arrangement were $25 million at March 31, 2014.

Marathon Oil indemnifications—In conjunction with our spinoff from Marathon Oil, we have entered into arrangements with Marathon Oil providing indemnities and guarantees with recorded values of $2 million as of March 31, 2014, which consist of unrecognized tax benefits related to MPC, its consolidated subsidiaries and the refining, marketing and transportation business operations prior to our spinoff which are not already reflected in the unrecognized tax benefits described in Note 10, 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 our spinoff provide for cross-indemnities between Marathon Oil and us. In general, Marathon Oil is required to indemnify us for any liabilities relating to Marathon Oil’s historical oil and gas exploration and production operations, oil sands mining operations and integrated gas operations, and we are required to indemnify Marathon Oil for any liabilities relating to Marathon Oil’s historical refining, marketing and transportation operations. The terms of these indemnifications are indefinite and the amounts are not capped.

Other guarantees—We have entered into other guarantees with maximum potential undiscounted payments totaling $122 million as of March 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, an indemnity to the co-lenders associated with an equity method investee’s credit agreement, and leases of assets containing general lease indemnities and guaranteed residual values.

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

Contractual commitments—At March 31, 2014, our contractual commitments to acquire property, plant and equipment and advance funds to equity method investees totaled $1.8 billion, which includes $700 million of contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets and $854 million for contributions to North Dakota Pipeline. See Notes 4 and 13 for additional information on the contingent consideration. See Note 4 for additional information on our investment in North Dakota Pipeline.

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Related Party Transactions - Purchases from Related Parties (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Related Party Transaction [Line Items]
Purchases from related parties	$ 159	$ 72
Centennial
Related Party Transaction [Line Items]
Purchases from related parties	9	0
Explorer
Related Party Transaction [Line Items]
Purchases from related parties	13	0
LOCAP
Related Party Transaction [Line Items]
Purchases from related parties	5	4
LOOP
Related Party Transaction [Line Items]
Purchases from related parties	53	10
TAAE
Related Party Transaction [Line Items]
Purchases from related parties	16	0
TACE
Related Party Transaction [Line Items]
Purchases from related parties	27	26
TAME
Related Party Transaction [Line Items]
Purchases from related parties	34	30
Other equity method investees
Related Party Transaction [Line Items]
Purchases from related parties	$ 2	$ 2

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Defined Benefit Pension and Other Postretirement Plans (Tables)

3 Months Ended

Mar. 31, 2014

Compensation and Retirement Disclosure [Abstract]

Components of Net Periodic Benefit Costs

The following summarizes the components of net periodic benefit costs:

	Three Months Ended March 31,
	Pension Benefits						Other Benefits
(In millions)	2014			2013			2014			2013
Components of net periodic benefit cost:
Service cost	$	23		$	23		$	7		$	6
Interest cost	20			18			8			7
Expected return on plan assets	(28		)	(27		)	—			—
Amortization – prior service credit	(12		)	(11		)	(1		)	(2		)
– actuarial loss	13			21			1			1
– net settlement loss	64			—			—			—
Net periodic benefit cost	$	80		$	24		$	15		$	12

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Supplementary Statistics

3 Months Ended

Mar. 31, 2014

Text Block [Abstract]

Supplementary Statistics

Supplementary Statistics (Unaudited)

	Three Months Ended   March 31,
(In millions)	2014			2013
Income from Operations by segment
Refining & Marketing	$	362		$	1,105
Speedway	58			67
Pipeline Transportation(a)	72			51
Items not allocated to segments:
Corporate and other unallocated items(a)	(67		)	(67		)
Pension settlement expenses	(64		)	—
Income from operations	$	361		$	1,156
Capital Expenditures and Investments(b)(c)
Refining & Marketing	$	178		$	1,420
Speedway	32			36
Pipeline Transportation	130			90
Corporate and Other(d)	31			28
Total	$	371		$	1,574

^(a)  Corporate overhead costs attributable to MPLX are included in the Pipeline Transportation segment. These expenses are not allocated to the Refining & Marketing and Speedway segments.

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

^(c)  The three months ended March 31, 2013 includes the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, plus assumed liabilities. Total consideration includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 4 to the unaudited consolidated financial statements.

^(d)  Includes capitalized interest $6 million and $4 million for the three months ended March 31, 2014 and 2013, respectively.

Supplementary Statistics (Unaudited)

	Three Months Ended   March 31,
	2014		2013
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)(a)(b)	1,964		1,895
Refining & Marketing Operating Statistics(b)
Refining & Marketing Refined Product Sales Volume (thousands of barrels per day)(c)	1,951		1,880
Refining & Marketing Gross Margin (dollars per barrel)(d)	$	14.46	$	15.29
Crude Oil Capacity Utilization percent(e)	85		93
Refinery Throughputs (thousands of barrels per day):(f)
Crude oil refined	1,450		1,433
Other charge and blendstocks	200		238
Total	1,650		1,671
Sour Crude Oil Throughput percent	49		54
WTI-Priced Crude Oil Throughput percent	21		22
Refined Product Yields (thousands of barrels per day):(f)
Gasoline	837		889
Distillates	514		523
Propane	34		32
Feedstocks and special products	220		184
Heavy fuel oil	30		30
Asphalt	43		46
Total	1,678		1,704
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	3.15	$	1.15
Depreciation and amortization	1.55		1.42
Other manufacturing(h)	5.95		3.81
Total	$	10.65	$	6.38
Refining & Marketing Operating Statistics By Region
Gulf Coast:(b)
Refinery Throughputs (thousands of barrels per day):(i)
Crude oil refined	860		837
Other charge and blendstocks	211		211
Total	1,071		1,048
Sour Crude Oil Throughput percent	60		68
WTI-Priced Crude Oil Throughput percent	3		6
Refined Product Yields (thousands of barrels per day):(i)
Gasoline	489		531
Distillates	319		322
Propane	21		19
Feedstocks and special products	245		179
Heavy fuel oil	15		18
Asphalt	7		6
Total	1,096		1,075
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	3.83	$	0.87
Depreciation and amortization	1.25		1.13
Other manufacturing(h)	5.87		3.29
Total	$	10.95	$	5.29

Supplementary Statistics (Unaudited)
	Three Months Ended   March 31,
	2014			2013
Refining & Marketing Operating Statistics By Region
Midwest:
Refinery Throughputs (thousands of barrels per day):(i)
Crude oil refined	590			596
Other charge and blendstocks	48			56
Total	638			652
Sour Crude Oil Throughput percent	34			35
WTI-Priced Crude Oil Throughput percent	47			45
Refined Product Yields (thousands of barrels per day):(i)
Gasoline	348			358
Distillates	195			201
Propane	13			13
Feedstocks and special products	33			34
Heavy fuel oil	16			12
Asphalt	36			40
Total	641			658
Refinery Direct Operating Costs (dollars per barrel):(g)
Planned turnaround and major maintenance	$	1.71		$	1.56
Depreciation and amortization	1.91			1.82
Other manufacturing(h)	5.54			4.47
Total	$	9.16		$	7.85
Speedway Operating Statistics
Convenience stores at period-end	1,482			1,463
Gasoline and distillate sales (millions of gallons)	773			745
Gasoline and distillate gross margin (dollars per gallon)(j)	$	0.1156		$	0.1301
Merchandise sales (in millions)	$	722		$	711
Merchandise gross margin (in millions)	$	192		$	184
Same store gasoline sales volume (period over period)	(0.7		)%	0.7		%
Same store merchandise sales (period over period)(k)	5.3		%	0.8		%
Pipeline Transportation Operating Statistics
Pipeline Throughputs (thousands of barrels per day):(l)
Crude oil pipelines	1,144			1,272
Refined products pipelines	819			917
Total	1,963			2,189

^(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.

^(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 59 mbpd and 29 mbpd for the three months ended March 31, 2014 and 2013, respectively.

^(g)  Per barrel of total refinery throughputs.

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

⁽ⁱ⁾  Includes inter-refinery transfer volumes.

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

^(k)  Excludes cigarettes.

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

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Description of the Business and Basis of Presentation (Policies)

3 Months Ended

Mar. 31, 2014

Accounting Policies [Abstract]

Use of Estimates

These interim consolidated financial statements are unaudited; however, in the opinion of our management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported. All such adjustments are of a normal, recurring nature unless otherwise disclosed. These interim consolidated financial statements, including the notes, have been prepared in accordance with the rules of the Securities and Exchange Commission applicable to interim period financial statements and do not include all of the information and disclosures required by United States generally accepted accounting principles (“US GAAP”) for complete financial statements.

Inventories

Inventories are carried at the lower of cost or market value. The cost of inventories of crude oil and refinery feedstocks, refined products and merchandise is determined primarily under the last-in, first-out (“LIFO”) method.

Derivative Instruments

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.

Stock-Based Compensation Arrangements

The fair value of stock options granted to our employees is estimated on the date of the grant using the Black Scholes option-pricing model, which employs various assumptions. The assumption for expected volatility of our stock price was refined for the three months ended March 31, 2014 to reflect a weighting of 50 percent of MPC’s common stock implied volatility and 50 percent of MPC's common stock historical volatility.

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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, 2012		$ 12,105	$ 4	$ (1,253)	$ 9,527	$ 3,880	$ (464)	$ 411
Number of shares held in treasury (beginning balance) at Dec. 31, 2012		(28)
Number of common shares issued (beginning balance) at Dec. 31, 2012		361
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		730				725		5
Dividends declared		(116)				(116)
Distributions to noncontrolling interests		(4)						(4)
Other comprehensive income		82					82
Shares repurchased		(431)		(531)	100
Shares issued (returned)—stock based compensation		24		(3)	27
Stock-based compensation		22			22			0
Number of shares repurchased	[1]	(6)
Ending balance at Mar. 31, 2013		12,412	4	(1,787)	9,676	4,489	(382)	412
Number of shares held in treasury (ending balance) at Mar. 31, 2013		(34)
Number of common shares issued (ending balance) at Mar. 31, 2013		361
Beginning balance at Dec. 31, 2013		11,332	4	(4,155)	9,768	5,507	(204)	412
Number of shares held in treasury (beginning balance) at Dec. 31, 2013		(65)
Number of common shares issued (beginning balance) at Dec. 31, 2013		362
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		207				199		8
Dividends declared		(124)				(124)
Distributions to noncontrolling interests		(6)						(6)
Other comprehensive income		(1)					(1)
Shares repurchased		(689)		(689)	0
Shares issued (returned)—stock based compensation		9		(5)	14
Stock-based compensation		21			21			0
Other		9				9
Number of shares issued - stock-based compensation		1
Number of shares repurchased		(8)
Ending balance at Mar. 31, 2014		$ 10,758	$ 4	$ (4,849)	$ 9,803	$ 5,591	$ (205)	$ 414
Number of shares held in treasury (ending balance) at Mar. 31, 2014		(73)
Number of common shares issued (ending balance) at Mar. 31, 2014		363

[1] The three months ended March 31, 2013 includes one million shares received under the November 2012 accelerated share repurchase program, which were paid for in the fourth quarter of 2012.

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Related Party Transactions (Tables)

3 Months Ended

Mar. 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:

	Three Months Ended   March 31,
(In millions)	2014		2013
Other equity method investees	$	2	$	2

Purchases From Related Parties

Purchases from related parties were as follows:

	Three Months Ended   March 31,
(In millions)	2014		2013
Centennial	$	9	$	—
Explorer	13		—
LOCAP	5		4
LOOP	53		10
TAAE	16		—
TACE	27		26
TAME	34		30
Other equity method investees	2		2
Total	$	159	$	72

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:

(In millions)	March 31, 2014		December 31, 2013
Centennial	$	—	$	1
Explorer	5		—
TAME	—		1
Total	$	5	$	2

Payables To Related Parties

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

(In millions)	March 31, 2014		December 31, 2013
Explorer	$	4	$	—
LOCAP	2		2
LOOP	4		3
TAAE	2		2
TACE	4		4
TAME	7		5
Total	$	23	$	16

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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	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Supplemental Cash Flow Elements [Abstract]
Additions to property, plant and equipment	$ 267	$ 195
Acquisitions	0	1,377	[1]
Decrease in capital accruals	(19)	(3)
Total capital expenditures	$ 248	$ 1,569

[1] The three months ended March 31, 2013 includes the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, plus assumed liabilities. Total consideration includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 4.

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Derivatives (Tables)

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [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 March 31, 2014 and December 31, 2013:

	March 31, 2014
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	41	$	81	Other current assets
	December 31, 2013
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	21	$	53	Other current assets

Open Commodity Derivative Contracts

The table below summarizes open commodity derivative contracts as of March 31, 2014.

	Position	Total Barrels (In thousands)
Crude oil(a)
Exchange-traded	Long	9,640
Exchange-traded	Short	(35,375	)
Refined Products(a)
Exchange-traded	Long	2,317
Exchange-traded	Short	(3,658	)

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

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:

	Gain (Loss)
(In millions)	Three Months Ended March 31,
Income Statement Location	2014			2013
Sales and other operating revenues	$	10		$	1
Cost of revenues	(61		)	(60		)
Total	$	(51	)	$	(59	)

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Acquisitions and Investments Acquisitions and Investments (Investments in Pipeline Companies) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended	6 Months Ended			0 Months Ended
	Mar. 31, 2014 North Dakota Pipeline	Mar. 31, 2014 North Dakota Pipeline	Jan. 02, 2016 North Dakota Pipeline Class A Units Scenario, Forecast	Jan. 02, 2016 North Dakota Pipeline Class A Units Scenario, Forecast Maximum	Mar. 04, 2014 Explorer Pipeline	Mar. 31, 2014 Explorer Pipeline
Schedule of Equity Method Investments [Line Items]
Cash paid to acquire equity method investments	$ 37	$ 61			$ 77
Equity method investments, ownership percentage	37.50%	37.50%	27.00%	30.00%		25.00%
Ownership percentage acquired					7.00%

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Property, Plant And Equipment - Summary Of Property, Plant And Equipment (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 21,987	$ 21,793
Less accumulated depreciation	8,133	7,872
Net property, plant and equipment	13,854	13,921
Operating Segments | Refining & Marketing
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	17,117	16,982
Operating Segments | Speedway
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	2,374	2,344
Operating Segments | Pipeline Transportation
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	1,926	1,921
Corporate and Other
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 570	$ 546

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Consolidated Statements of Income (USD $) In Millions, except Per Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$ 23,285	$ 23,330
Income from equity method investments	35	0
Net gain on disposal of assets	1	1
Other income	24	14
Total revenues and other income	23,345	23,345
Costs and expenses:
Cost of revenues (excludes items below)	20,540	20,034
Purchases from related parties	159	72
Consumer excise taxes	1,515	1,458
Depreciation and amortization	320	287
Selling, general and administrative expenses	346	249
Other taxes	104	89
Total costs and expenses	22,984	22,189
Income from operations	361	1,156
Net interest and other financial income (costs)	(46)	(48)
Income before income taxes	315	1,108
Provision for income taxes	108	378
Net income	207	730
Less net income attributable to noncontrolling interests	8	5
Net income attributable to MPC	$ 199	$ 725
Basic:
Net income attributable to MPC per share	$ 0.68	$ 2.19
Weighted average shares outstanding (in shares)	293	331
Diluted:
Net income attributable to MPC per share	$ 0.67	$ 2.17
Weighted average shares outstanding (in shares)	295	333
Dividends paid (in USD per share)	$ 0.42	$ 0.35

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Stock-Based Compensation Plans (Tables)

3 Months Ended

Mar. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Summary of Stock Option Award Activity

The following table presents a summary of our stock option award activity for the three months ended March 31, 2014:

	Number of Shares(a)		Weighted Average Exercise Price
Outstanding at December 31, 2013	5,147,837		$	40.08
Granted	327,100		83.37
Exercised	(455,999	)	30.65
Forfeited, canceled or expired	(19,293	)	50.05
Outstanding at March 31, 2014	4,999,645		43.73

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

Summary of Restricted Stock Award Activity

The following table presents a summary of restricted stock award activity for the three months ended March 31, 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	51,594		83.45		5,939	89.96
RS's Vested/RSU's Issued	(117,980	)	54.43		—	—
Forfeited	(14,840	)	64.31		—	—
Outstanding at March 31, 2014	542,896		64.60		391,018	34.81

Schedule of Performance Unit Awards

The following table presents a summary of the activity for performance unit awards to be settled in shares for the three months ended March 31, 2014:

	Number of Units
Outstanding at December 31, 2013	3,822,500
Granted	2,033,700
Settled	—
Canceled	—
Outstanding at March 31, 2014	5,856,200

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Consolidated Balance Sheets (Parenthetical) (USD $) In Millions, except Share data, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 9	$ 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	(73,000,000)	(65,000,000)

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Supplementary Statistics - Operating Statistics (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014 BPD		Mar. 31, 2013 BPD
Operating Statistics [Line Items ]
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)	1,964,000	[1],[2]	1,895,000	[1],[2]
Refining & Marketing
Refining & Marketing Operating Statistics
Refining & Marketing Refined Product Sales Volume (thousands of barrels per day)	1,951,000	[2],[3]	1,880,000	[2],[3]
Refining & Marketing Gross Margin (dollars per barrel)	14.46	[2],[4]	15.29	[2],[4]
Crude Oil Capacity Utilization percent	85.00%	[2],[5]	93.00%	[2],[5]
Refinery Throughputs (thousands of barrels per day)	1,650,000	[2],[6]	1,671,000	[2],[6]
Sour Crude Oil Throughput percent	49.00%	[2]	54.00%	[2]
WTI-Priced Crude Oil Throughput percent	21.00%	[2]	22.00%	[2]
Refined Product Yields (thousands of barrels per day)	1,678,000	[2],[6]	1,704,000	[2],[6]
Inter-refinery transfers	59,000		29,000
Refinery Direct Operating Costs (dollars per barrel):
Planned turnaround and major maintenance	3.15	[2],[7]	1.15	[2],[7]
Depreciation and amortization	1.55	[2],[7]	1.42	[2],[7]
Other manufacturing	5.95	[2],[7],[8]	3.81	[2],[7],[8]
Total	10.65	[2],[7]	6.38	[2],[7]
Refining & Marketing | Crude oil refined
Refining & Marketing Operating Statistics
Refinery Throughputs (thousands of barrels per day)	1,450,000	[2],[6]	1,433,000	[2],[6]
Refining & Marketing | Other charge and blendstocks
Refining & Marketing Operating Statistics
Refinery Throughputs (thousands of barrels per day)	200,000	[2],[6]	238,000	[2],[6]
Refining & Marketing | Gasoline
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	837,000	[2],[6]	889,000	[2],[6]
Refining & Marketing | Distillates
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	514,000	[2],[6]	523,000	[2],[6]
Refining & Marketing | Propane
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	34,000	[2],[6]	32,000	[2],[6]
Refining & Marketing | Feedstocks and special products
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	220,000	[2],[6]	184,000	[2],[6]
Refining & Marketing | Heavy fuel oil
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	30,000	[2],[6]	30,000	[2],[6]
Refining & Marketing | Asphalt
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	43,000	[2],[6]	46,000	[2],[6]
Refining & Marketing | Gulf Coast:
Refining & Marketing Operating Statistics
Refinery Throughputs (thousands of barrels per day)	1,071,000	[2],[9]	1,048,000	[2],[9]
Sour Crude Oil Throughput percent	60.00%	[2]	68.00%	[2]
WTI-Priced Crude Oil Throughput percent	3.00%	[2]	6.00%	[2]
Refined Product Yields (thousands of barrels per day)	1,096,000	[2],[9]	1,075,000	[2],[9]
Refinery Direct Operating Costs (dollars per barrel):
Planned turnaround and major maintenance	3.83	[2],[7]	0.87	[2],[7]
Depreciation and amortization	1.25	[2],[7]	1.13	[2],[7]
Other manufacturing	5.87	[2],[7],[8]	3.29	[2],[7],[8]
Total	10.95	[2],[7]	5.29	[2],[7]
Refining & Marketing | Gulf Coast: | Crude oil refined
Refining & Marketing Operating Statistics
Refinery Throughputs (thousands of barrels per day)	860,000	[2],[9]	837,000	[2],[9]
Refining & Marketing | Gulf Coast: | Other charge and blendstocks
Refining & Marketing Operating Statistics
Refinery Throughputs (thousands of barrels per day)	211,000	[2],[9]	211,000	[2],[9]
Refining & Marketing | Gulf Coast: | Gasoline
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	489,000	[2],[9]	531,000	[2],[9]
Refining & Marketing | Gulf Coast: | Distillates
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	319,000	[2],[9]	322,000	[2],[9]
Refining & Marketing | Gulf Coast: | Propane
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	21,000	[2],[9]	19,000	[2],[9]
Refining & Marketing | Gulf Coast: | Feedstocks and special products
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	245,000	[2],[9]	179,000	[2],[9]
Refining & Marketing | Gulf Coast: | Heavy fuel oil
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	15,000	[2],[9]	18,000	[2],[9]
Refining & Marketing | Gulf Coast: | Asphalt
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	7,000	[2],[9]	6,000	[2],[9]
Refining & Marketing | Midwest:
Refining & Marketing Operating Statistics
Refinery Throughputs (thousands of barrels per day)	638,000	[9]	652,000	[9]
Sour Crude Oil Throughput percent	34.00%		35.00%
WTI-Priced Crude Oil Throughput percent	47.00%		45.00%
Refined Product Yields (thousands of barrels per day)	641,000	[9]	658,000	[9]
Refinery Direct Operating Costs (dollars per barrel):
Planned turnaround and major maintenance	1.71	[7]	1.56	[7]
Depreciation and amortization	1.91	[7]	1.82	[7]
Other manufacturing	5.54	[7],[8]	4.47	[7],[8]
Total	9.16	[7]	7.85	[7]
Refining & Marketing | Midwest: | Crude oil refined
Refining & Marketing Operating Statistics
Refinery Throughputs (thousands of barrels per day)	590,000	[9]	596,000	[9]
Refining & Marketing | Midwest: | Other charge and blendstocks
Refining & Marketing Operating Statistics
Refinery Throughputs (thousands of barrels per day)	48,000	[9]	56,000	[9]
Refining & Marketing | Midwest: | Gasoline
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	348,000	[9]	358,000	[9]
Refining & Marketing | Midwest: | Distillates
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	195,000	[9]	201,000	[9]
Refining & Marketing | Midwest: | Propane
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	13,000	[9]	13,000	[9]
Refining & Marketing | Midwest: | Feedstocks and special products
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	33,000	[9]	34,000	[9]
Refining & Marketing | Midwest: | Heavy fuel oil
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	16,000	[9]	12,000	[9]
Refining & Marketing | Midwest: | Asphalt
Refining & Marketing Operating Statistics
Refined Product Yields (thousands of barrels per day)	36,000	[9]	40,000	[9]
Speedway
Speedway Operating Statistics
Convenience stores at period-end	1,482		1,463
Gasoline and distillate sales (millions of gallons)	773,000,000		745,000,000
Gasoline and distillate gross margin (dollars per gallon)	0.1156	[10]	0.1301	[10]
Merchandise sales (in millions)	$ 722		$ 711
Merchandise gross margin (in millions)	$ 192		$ 184
Same store gasoline sales volume (period over period) percentage	(0.70%)		0.70%
Merchandise sales excluding cigarettes (period over period) percentage	5.30%	[11]	0.80%	[11]
Pipeline Transportation
Pipeline Transportation Operating Statistics
Pipeline Throughputs (thousands of barrels per day)	1,963,000	[12]	2,189,000	[12]
Pipeline Transportation | Crude oil pipelines
Pipeline Transportation Operating Statistics
Pipeline Throughputs (thousands of barrels per day)	1,144,000	[12]	1,272,000	[12]
Pipeline Transportation | Refined products pipelines
Pipeline Transportation Operating Statistics
Pipeline Throughputs (thousands of barrels per day)	819,000	[12]	917,000	[12]

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

[2] Includes the impact of the Galveston Bay Refinery and Related Assets beginning on the February 1, 2013 acquisition date.

[3] Includes intersegment sales.

[4] Sales revenue less cost of refinery inputs and purchased products, divided by total refinery throughputs.

[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 59 mbpd and 29 mbpd for the three months ended March 31, 2014 and 2013, respectively.

[7] Per barrel of total refinery throughputs.

[8] Includes utilities, labor, routine maintenance and other operating costs.

[9] Includes inter-refinery transfer volumes.

[10] The price paid by consumers less the cost of refined products, including transportation, consumer excise taxes and bankcard processing fees, divided by gasoline and distillate sales volume.

[11] Excludes cigarettes.

[12] On owned common-carrier pipelines, excluding equity method investments.

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Income Per Common Share - Additional Information (Detail) (Stock Based Compensation Award) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Stock Based Compensation Award
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Excluded from diluted share calculation	1	1

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Income From Operations Attributable To Operating Segments

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
Three Months Ended March 31, 2014
Revenues:
Customer	$	19,810	$	3,458	$	17	$	23,285
Intersegment(a)	2,233		1		129		2,363
Segment revenues	$	22,043	$	3,459	$	146	$	25,648
Segment income from operations(b)	$	362	$	58	$	72	$	492
Income from equity method investments	24		—		11		35
Depreciation and amortization(c)	261		28		19		308
Capital expenditures and investments(d)	178		32		130		340

(In millions)	Refining & Marketing			Speedway		Pipeline Transportation		Total
Three Months Ended March 31, 2013
Revenues:
Customer	$	19,874		$	3,441	$	21	$	23,336
Intersegment(a)	2,199			1		104		2,304
Segment revenues	$	22,073		$	3,442	$	125	$	25,640
Segment income from operations(b)	$	1,105		$	67	$	51	$	1,223
Income (loss) from equity method investments	(4		)	—		4		—
Depreciation and amortization(c)	236			27		18		281
Capital expenditures and investments(d)(e)	1,420			36		90		1,546

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

^(b)  Corporate overhead costs attributable to MPLX are included in the Pipeline Transportation segment. These expenses are not allocated to the Refining & Marketing and Speedway segments.

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

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

^(e)  The Refining & Marketing and Pipeline Transportation segments include the acquisition of the Galveston Bay Refinery and Related Assets. See Note 4.

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:

	Three Months Ended   March 31,
(In millions)	2014			2013
Segment income from operations	$	492		$	1,223
Items not allocated to segments:
Corporate and other unallocated items(a)(b)	(67		)	(67		)
Pension settlement expenses(c)	(64		)	—
Net interest and other financial income (costs)	(46		)	(48		)
Income before income taxes	$	315		$	1,108

^(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 costs attributable to MPLX are included in the Pipeline Transportation segment. These expenses are not allocated to the Refining & Marketing and Speedway segments.

^(c)  See Note 18.

Reconciliation Of Segment Capital Expenditures And Investments To Total Capital Expenditures

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

	Three Months Ended   March 31,
(In millions)	2014		2013
Segment capital expenditures and investments	$	340	$	1,546
Less: Investments in equity method investees	123		5
Plus: Items not allocated to segments:
Capital expenditures not allocated to segments	25		24
Capitalized interest	6		4
Total capital expenditures(a)(b)	$	248	$	1,569

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

^(b)  See Note 16 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 customer revenues to sales and other operating revenues (including consumer excise taxes) as reported in the consolidated statements of income:

	Three Months Ended   March 31,
(In millions)	2014		2013
Customer revenues (as reported above)	$	23,285	$	23,336
Corporate and other unallocated items	—		(6		)
Sales and other operating revenues (including consumer excise taxes)	$	23,285	$	23,330

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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
	Mar. 31, 2014		Mar. 31, 2013
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income from operations	$ 361		$ 1,156
Net interest and other financial income (costs)	(46)		(48)
Income before income taxes	315		1,108
Operating Segments
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income from operations	492	[1]	1,223	[1]
Corporate and Other
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Income from operations	(67)	[1],[2]	(67)	[1],[2]
Segment Reconciling Items
Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]
Pension settlement expenses	$ (64)	[3]	$ 0

[1] Corporate overhead costs attributable to MPLX are included in the Pipeline Transportation segment. These expenses are not allocated to the Refining & Marketing and Speedway segments.

[2] Corporate and other unallocated items consists primarily of MPC’s corporate administrative expenses and costs related to certain non-operating assets.

[3] See Note 18.

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Derivatives

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [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 13. We do not designate any of our commodity derivative instruments as hedges for accounting purposes.

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

	March 31, 2014
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	41	$	81	Other current assets
	December 31, 2013
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	21	$	53	Other current assets

The table below summarizes open commodity derivative contracts as of March 31, 2014.

	Position	Total Barrels (In thousands)
Crude oil(a)
Exchange-traded	Long	9,640
Exchange-traded	Short	(35,375	)
Refined Products(a)
Exchange-traded	Long	2,317
Exchange-traded	Short	(3,658	)

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

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

	Gain (Loss)
(In millions)	Three Months Ended March 31,
Income Statement Location	2014			2013
Sales and other operating revenues	$	10		$	1
Cost of revenues	(61		)	(60		)
Total	$	(51	)	$	(59	)

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Other Items (Tables)

3 Months Ended

Mar. 31, 2014

Other Income and Expenses [Abstract]

Net Interest And Other Financial Income (Costs)

Net interest and other financial income (costs) was:

	Three Months Ended   March 31,
(In millions)	2014			2013
Interest:
Interest income	$	2		$	2
Interest expense	(49		)	(48		)
Interest capitalized	6			4
Total net interest	(41		)	(42		)
Other:
Net foreign currency losses	—			(1		)
Bank service and other fees	(5		)	(5		)
Total other	(5		)	(6		)
Net interest and other financial income (costs)	$	(46	)	$	(48	)

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Supplemental Cash Flow Information

3 Months Ended

Mar. 31, 2014

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

Supplemental Cash Flow Information

	Three Months Ended   March 31,
(In millions)	2014		2013
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	80	$	83
Net income taxes paid to (refunded from) taxing authorities	5		(5		)
Non-cash investing and financing activities:
Capital lease obligations increase	$	—	$	61
Acquisition:
Contingent consideration(a)	—		600
Payable to seller(a)	—		6

^(a)  Acquisition-date fair value of non-cash consideration associated with the Galveston Bay Refinery and Related Assets acquisition.

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:

	Three Months Ended   March 31,
(In millions)	2014			2013
Additions to property, plant and equipment	$	267		$	195
Acquisitions(a)	—			1,377
Decrease in capital accruals	(19		)	(3		)
Total capital expenditures	$	248		$	1,569

^(a)  The three months ended March 31, 2013 includes the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, plus assumed liabilities. Total consideration includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 4.

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Other Items - Net Interest And Other Financial Income (Costs) (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Interest:
Interest income	$ 2	$ 2
Interest expense	(49)	(48)
Interest capitalized	6	4
Total net interest	(41)	(42)
Other:
Net foreign currency losses	0	(1)
Bank service and other fees	(5)	(5)
Total other	(5)	(6)
Net interest and other financial income (costs)	$ (46)	$ (48)

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Consolidated Statements of Cash Flows (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating activities:
Net income	$ 207	$ 730
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	320	287
Pension and other postretirement benefits, net	82	28
Deferred income taxes	(14)	6
Net gain on disposal of assets	(1)	(1)
Equity method investments, net	6	4
Changes in the fair value of derivative instruments	(25)	(57)
Changes in:
Current receivables	139	(884)
Inventories	(1,000)	(517)
Current accounts payable and accrued liabilities	1,011	2,491
All other, net	41	(8)
Net cash provided by operating activities	766	2,079
Investing activities:
Additions to property, plant and equipment	(267)	(195)
Acquisitions	0	(1,493)
Disposal of assets	2	3
Investments—acquisitions, loans and contributions	(123)	(21)
Investments—redemptions and repayments	0	11
All other, net	28	13
Net cash used in investing activities	(360)	(1,682)
Financing activities:
Long-term debt – borrowings	270	0
Long-term debt – repayments	(6)	(5)
Debt issuance costs	0	(2)
Issuance of common stock	13	28
Common stock repurchased	(689)	(431)
Dividends paid	(123)	(116)
Distributions to noncontrolling interests	(6)	(4)
All other, net	9	10
Net cash used in financing activities	(532)	(520)
Net decrease in cash and cash equivalents	(126)	(123)
Cash and cash equivalents at beginning of period	2,292	4,860
Cash and cash equivalents at end of period	$ 2,166	$ 4,737

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Consolidated Statements of Comprehensive Income (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Statement of Comprehensive Income [Abstract]
Net income	$ 207	$ 730
Defined benefit postretirement and post-employment plans:
Actuarial changes, net of tax of $4 and $54	7	90
Prior service costs, net of tax of ($5) and ($5)	(8)	(8)
Other comprehensive income (loss)	(1)	82
Comprehensive income	206	812
Less comprehensive income attributable to noncontrolling interests	8	5
Comprehensive income attributable to MPC	$ 198	$ 807

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Other Items

3 Months Ended

Mar. 31, 2014

Other Income and Expenses [Abstract]

Other Items

Other Items

Net interest and other financial income (costs) was:

	Three Months Ended   March 31,
(In millions)	2014			2013
Interest:
Interest income	$	2		$	2
Interest expense	(49		)	(48		)
Interest capitalized	6			4
Total net interest	(41		)	(42		)
Other:
Net foreign currency losses	—			(1		)
Bank service and other fees	(5		)	(5		)
Total other	(5		)	(6		)
Net interest and other financial income (costs)	$	(46	)	$	(48	)

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Supplementary Statistics - Supplementary Statistics (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Supplementary Statistics [Line Items]
Income from operations	$ 361		$ 1,156
Capital expenditures and investments	371	[1],[2],[3]	1,574	[1],[2],[3]
Galveston Bay Refinery and Related Assets
Supplementary Statistics [Line Items]
Fair value of contingent consideration as of acquisition date			600
Operating Segments
Supplementary Statistics [Line Items]
Income from operations	492	[4]	1,223	[4]
Capital expenditures and investments	340	[1]	1,546	[1],[5]
Operating Segments | Refining & Marketing
Supplementary Statistics [Line Items]
Income from operations	362		1,105
Capital expenditures and investments	178	[1]	1,420	[1],[5]
Operating Segments | Speedway
Supplementary Statistics [Line Items]
Income from operations	58		67
Capital expenditures and investments	32	[1]	36	[1],[5]
Operating Segments | Pipeline Transportation
Supplementary Statistics [Line Items]
Income from operations	72	[4]	51	[4]
Capital expenditures and investments	130	[1]	90	[1],[5]
Corporate and Other
Supplementary Statistics [Line Items]
Income from operations	(67)	[4],[6]	(67)	[4],[6]
Capital expenditures and investments	31	[1],[3]	28	[1],[3]
Capitalized interest	6		4
Segment Reconciling Items
Supplementary Statistics [Line Items]
Pension settlement expenses	$ (64)	[7]	$ 0

[1] Capital expenditures include changes in capital accruals.

[2] The three months ended March 31, 2013 includes the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, plus assumed liabilities. Total consideration includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 4 to the unaudited consolidated financial statements.

[3] Includes capitalized interest $6 million and $4 million for the three months ended March 31, 2014 and 2013, respectively.

[4] Corporate overhead costs attributable to MPLX are included in the Pipeline Transportation segment. These expenses are not allocated to the Refining & Marketing and Speedway segments.

[5] The Refining & Marketing and Pipeline Transportation segments include the acquisition of the Galveston Bay Refinery and Related Assets. See Note 4.

[6] Corporate and other unallocated items consists primarily of MPC’s corporate administrative expenses and costs related to certain non-operating assets.

[7] See Note 18.

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Commitments and Contingencies (Detail) (USD $)	3 Months Ended				3 Months Ended			3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Mar. 31, 2014 Galveston Bay Refinery and Related Assets	Feb. 01, 2013 Galveston Bay Refinery and Related Assets	Mar. 31, 2014 North Dakota Pipeline	Mar. 31, 2014 Indemnification Agreement Marathon Oil Companies	Mar. 31, 2014 Other Guarantees Equity Method Investees	Mar. 31, 2014 Guarantee of Indebtedness of Others [Member] Financial Guarantee LOOP and LOCAP LLC	Mar. 31, 2014 Master Shelf Agreement [Member] Financial Guarantee Centennial	Mar. 31, 2014 Standby Letters of Credit [Member] Financial Guarantee TAME	Mar. 31, 2014 Pending Litigation [Member]	Mar. 31, 2014 Pending Litigation [Member] Emergency Pricing And Consumer Protection Laws
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.
Accrued liabilities for remediation	$ 123,000,000	$ 123,000,000
Receivables for recoverable costs	50,000,000	51,000,000
Alleged amount overcharged from customers												89,000,000
Loss contingency, period of occurrence												during September and October 2005
Plaintiff												Commonwealth of Kentucky
Line of credit facility, expiration date								Dec. 31, 2037	Dec. 31, 2024	Dec. 31, 2018
Maximum potential undiscounted payments							122,000,000	172,000,000	41,000,000	25,000,000
Percentage of credit agreement agreed to reimburse										50.00%
Guarantee obligation current carrying value						2,000,000
Guarantee obligations maximum exposure per event							50,000,000
Contractual commitments to acquire property, plant and equipment and advance funds to equity method investees	1,800,000,000				854,000,000
Maximum earnout provision payable to the company			$ 700,000,000	$ 700,000,000

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Document and Entity Information	3 Months Ended
	Mar. 31, 2014	Apr. 30, 2014
Document Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus (Q1,Q2,Q3,FY)	Q1
Trading Symbol	MPC
Entity Registrant Name	Marathon Petroleum Corp
Entity Central Index Key	0001510295
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		288,632,472

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Income Taxes

3 Months Ended

Mar. 31, 2014

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The combined federal, state and foreign income tax rate was 34 percent for both the three months ended March 31, 2014 and 2013. The effective tax rate for the three months ended March 31, 2014 and 2013 is 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.

We are continuously undergoing examination of our income tax returns, which have been completed for our U.S. federal and state income tax returns through the 2009 and 2003 tax years, respectively. We had $16 million of unrecognized tax benefits as of March 31, 2014. Pursuant to our tax sharing agreement with Marathon Oil Corporation ("Marathon Oil"), the unrecognized tax benefits related to pre-spinoff operations for which Marathon Oil was the taxpayer remain the responsibility of Marathon Oil and we have indemnified Marathon Oil accordingly. See Note 20 for indemnification information.

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Debt - Outstanding Borrowings (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Dec. 31, 2013
Debt Instrument [Line Items]
Total	$ 3,659		$ 3,395
Unamortized discount	(10)		(10)
Fair value adjustments	10	[1]	11	[1]
Amounts due within one year	(24)		(23)
Total long-term debt due after one year	3,635		3,373
Interest Rate Swap
Debt Instrument [Line Items]
Deferred gain on discontinuation of interest rate fair value hedge	20
Consolidated subsidiaries: | Capital Lease Obligations
Debt Instrument [Line Items]
Capital lease obligations	389		395
Debt instrument maturity year, start	Jan. 01, 2014
Debt instrument maturity year, end	Dec. 31, 2028
Consolidated subsidiaries: | Trade Receivables Securitization
Debt Instrument [Line Items]
Line of credit facility, expiration date	Dec. 31, 2016
MPC Revolver
Debt Instrument [Line Items]
Borrowings outstanding	0		0
Line of credit facility, expiration date	Sep. 14, 2017
3.500% senior notes due March 1, 2016 | Senior Notes
Debt Instrument [Line Items]
Senior notes	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]
Senior notes	1,000		1,000
Debt instrument, maturity date	Mar. 01, 2021
Debt instrument, interest rate	5.125%
6.500% senior notes due March 1, 2041 | Senior Notes
Debt Instrument [Line Items]
Senior notes	1,250		1,250
Debt instrument, maturity date	Mar. 01, 2041
Debt instrument, interest rate	6.50%
MPLX Revolver | MPLX Operations LLC
Debt Instrument [Line Items]
Borrowings outstanding	270		0
Line of credit facility, expiration date	Oct. 31, 2017
Trade Receivables Securitization | Consolidated subsidiaries:
Debt Instrument [Line Items]
Trade receivables securitization facility	$ 0		$ 0

[1] The $20 million gain on the termination of our interest rate swap agreements in 2012 is being amortized over the remaining life of the 3.50 percent senior notes.

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Stock-Based Compensation Plans - Summary of Performance Unit Awards (Detail) (Performance Unit Awards)	3 Months Ended
	Mar. 31, 2014
Performance Unit Awards
Number of Units
Outstanding, beginning balance	3,822,500
Granted	2,033,700
Settled	0
Canceled	0
Outstanding, ending balance	5,856,200

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Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Statement of Comprehensive Income [Abstract]
Actuarial changes, tax	$ 4	$ 54
Prior service costs, tax	$ (5)	$ (5)

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Acquisitions

3 Months Ended

Mar. 31, 2014

Business Combinations [Abstract]

Acquisitions and Investments

Acquisitions and Investments

Acquisition of Refinery and Related Logistics and Marketing Assets

On February 1, 2013, we acquired from BP Products North America Inc. and BP Pipelines (North America) Inc. (collectively, “BP”) the 451,000 barrel per calendar day refinery in Texas City, Texas, three intrastate natural gas liquid pipelines originating at the refinery, four light product terminals, branded-jobber marketing contract assignments for the supply of approximately 1,200 branded sites, a 1,040 megawatt electric cogeneration facility and a 50,000 barrel per day allocation of space on 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, subject to certain conditions. During the second quarter of 2014, we expect to pay BP approximately $178 million for the first year's contingent earnout. See Note 13 for additional information on the contingent consideration.

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

(In millions, except per share data)	Three Months Ended March 31, 2013
Sales and other operating revenues (including consumer excise taxes)	$	25,296
Net income attributable to MPC	780
Net income attributable to MPC per share - basic	$	2.36
Net income attributable to MPC per share - diluted	2.34

The pro forma information includes adjustments to align accounting policies, an adjustment to depreciation expense to reflect the fair value of property, plant and equipment, increased amortization expense related to identifiable intangible assets and the related income tax effects.

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, which is deductible for income tax purposes.

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

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

Investments in Ethanol Companies

On August 1, 2013, we acquired from Mitsui & Co. (U.S.A.), Inc. its interests in three ethanol companies for $75 million. Under the purchase agreement, we acquired an additional 24 percent interest in The Andersons Clymers Ethanol LLC ("TACE"), bringing our ownership interest to 60 percent; a 34 percent interest in The Andersons Ethanol Investment LLC, 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.

Investments in Pipeline Companies

We made contributions of $37 million to North Dakota Pipeline Company LLC ("North Dakota Pipeline") during the three months ended March 31, 2014. We have contributed $61 million since project inception. These contributions funded 37.5 percent of the construction costs incurred to-date on the Sandpiper pipeline project. In conjunction with our commitment to be an anchor shipper for the Sandpiper pipeline and our investment in the project, we will earn an approximate 27 percent equity interest in Enbridge Energy Partner L.P.'s North Dakota System when the Sandpiper pipeline is placed into service, which is projected to occur in 2016. We also have the option to increase our ownership interest to approximately 30 percent through additional investments in future system improvements. We account for our interest in North Dakota Pipeline using the equity method of accounting. See Note 20 for information on future contributions to North Dakota Pipeline.

In March 2014, we acquired from Chevron Raven Ridge Pipe Line Company an additional 7 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.

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MPLX LP

3 Months Ended

Mar. 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. We own a 73.6 percent interest in MPLX, including the two percent general partner interest. We consolidate this entity for financial reporting purposes since we have a controlling financial interest, and we record a noncontrolling interest for the interest owned by the public.

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.

Effective March 1, 2014, we sold MPLX a 13 percent interest in Pipe Line Holdings for $310 million, increasing MPLX's ownership interest in Pipe Line Holdings to 69 percent. MPLX financed this transaction with $40 million of cash on-hand and $270 million of borrowings on its bank revolving credit agreement.

The sales of interests in Pipeline Holdings to MPLX resulted in a change of our ownership in Pipeline Holdings, but not a change in control. We accounted for the sales as equity transactions, with the excess cash paid over historical carrying value recorded as a change within equity. We did not record a gain or loss on the transactions.

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Debt

3 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Debt

Debt

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

(In millions)	March 31, 2014			December 31, 2013
Marathon Petroleum Corporation:
Revolving credit agreement due 2017	$	—		$	—
3.500% senior notes due March 1, 2016	750			750
5.125% senior notes due March 1, 2021	1,000			1,000
6.500% senior notes due March 1, 2041	1,250			1,250
Consolidated subsidiaries:
Capital lease obligations due 2014-2028	389			395
MPLX Operations LLC revolving credit agreement due 2017	270			—
Trade receivables securitization facility due 2016	—			—
Total	3,659			3,395
Unamortized discount	(10		)	(10		)
Fair value adjustments(a)	10			11
Amounts due within one year	(24		)	(23		)
Total long-term debt due after one year	$	3,635		$	3,373

^(a)  The $20 million gain on the termination of our interest rate swap agreements in 2012 is being amortized over the remaining life of the 3.50 percent senior notes.

There were no borrowings or letters of credit outstanding under the MPC revolving credit agreement or the trade receivables securitization facility at March 31, 2014. During the three months ended March 31, 2014, MPLX borrowed $270 million under the MPLX Operations LLC revolving credit agreement (the "MPLX Credit Agreement") at an average interest rate of 1.5 percent per annum. The borrowings were used to fund MPLX's acquisition of an additional interest in Pipe Line Holdings. At March 31, 2014, MPLX had $270 million of borrowings and no letters of credit outstanding under the MPLX Credit Agreement, resulting in total unused loan availability of $230 million, or 46 percent of the borrowing capacity. The MPLX Credit Agreement is scheduled to mature on October 31, 2017.

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Inventories

3 Months Ended

Mar. 31, 2014

Inventory Disclosure [Abstract]

Inventories

Inventories

(In millions)	March 31, 2014		December 31, 2013
Crude oil and refinery feedstocks	$	2,734	$	1,797
Refined products	2,540		2,367
Materials and supplies	333		425
Merchandise	82		100
Total (at cost)	$	5,689	$	4,689

Inventories are carried at the lower of cost or market value. The cost of inventories of crude oil and refinery feedstocks, refined products and merchandise is determined primarily under the last-in, first-out (“LIFO”) method. There were no liquidations of LIFO inventories for the three months ended March 31, 2014 and 2013.

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Accumulated Other Comprehensive Loss - Changes in Accumulated Other Comprehensive Loss by Component (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	$ (204)		$ (464)
Other comprehensive income (loss) before reclassifications	(42)		76
Amounts reclassified from accumulated other comprehensive loss:
Amortization - prior service credit	(13)	[1]	(13)	[1]
Amortization of actuarial loss	14	[1]	22	[1]
Amortization of settlement loss	64	[1]
Tax effect	(24)		(3)
Other comprehensive income (loss)	(1)		82
Ending balance	(205)		(382)
Accumulated Defined Benefit Plans Adjustment | Pension Benefits
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	(161)		(432)
Other comprehensive income (loss) before reclassifications	(43)		67
Amounts reclassified from accumulated other comprehensive loss:
Amortization - prior service credit	(12)	[1]	(11)	[1]
Amortization of actuarial loss	13	[1]	21	[1]
Amortization of settlement loss	64	[1]
Tax effect	(24)		(4)
Other comprehensive income (loss)	(2)		73
Ending balance	(163)		(359)
Accumulated Defined Benefit Plans Adjustment | Other Benefits
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance	(50)		(36)
Other comprehensive income (loss) before reclassifications	1		9
Amounts reclassified from accumulated other comprehensive loss:
Amortization - prior service credit	(1)	[1]	(2)	[1]
Amortization of actuarial loss	1	[1]	1	[1]
Amortization of settlement loss	0	[1]
Tax effect	0		1
Other comprehensive income (loss)	1		9
Ending balance	(49)		(27)
Gain on Cash Flow Hedge
Accumulated Other Comprehensive Income (Loss) [Line Items]
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) [Line Items]
Beginning balance	3		0
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	$ 3		$ 0

[1] These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 18.

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Equity

3 Months Ended

Mar. 31, 2014

Equity [Abstract]

Equity

Equity

Our board of directors has approved $6.0 billion in total share repurchase authorizations since January 1, 2012. As of March 31, 2014, we have repurchased a total of $4.83 billion of our common stock under these authorizations, leaving $1.17 billion available for repurchases through September 2015. Under these authorizations, we have acquired 73 million shares at an average cost per share of $66.19.

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.

Total share repurchases were as follows for the three months ended March 31, 2014 and 2013:

	Three Months Ended   March 31,
(In millions, except per share data)	2014		2013
Number of shares repurchased(a)	8		6
Cash paid for shares repurchased	$	689	$	431
Effective average cost per delivered share	$	87.60	$	80.95

^(a)  The three months ended March 31, 2013 includes one million shares received under the November 2012 accelerated share repurchase program, which were paid for in the fourth quarter of 2012.

At March 31, 2014, we had agreements to acquire additional common shares for $12 million, which were settled in early April 2014.

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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
	Mar. 31, 2014	Mar. 31, 2013
Basic earnings per share:
Net income attributable to MPC	$ 199	$ 725
Income allocated to participating securities	0	1
Income available to common stockholders - basic	199	724
Weighted average common shares outstanding (in shares)	293	331
Basic (in USD per share)	$ 0.68	$ 2.19
Diluted earnings per share:
Net income attributable to MPC	199	725
Income allocated to participating securities	0	1
Income available to common stockholders - diluted	$ 199	$ 724
Weighted average common shares outstanding (in shares)	293	331
Effect of dilutive securities (in shares)	2	2
Weighted average common shares, including dilutive effect (in shares)	295	333
Diluted (in USD per share)	$ 0.67	$ 2.17

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Related Party Transactions

3 Months Ended

Mar. 31, 2014

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

Our related parties include:

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

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

• 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.

• Other equity method investees.

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:

	Three Months Ended   March 31,
(In millions)	2014		2013
Other equity method investees	$	2	$	2

Purchases from related parties were as follows:

	Three Months Ended   March 31,
(In millions)	2014		2013
Centennial	$	9	$	—
Explorer	13		—
LOCAP	5		4
LOOP	53		10
TAAE	16		—
TACE	27		26
TAME	34		30
Other equity method investees	2		2
Total	$	159	$	72

Related party purchases from Centennial consist primarily of refinery feedstocks. 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 and crude oil purchases. Related party purchases from TAAE, TACE and TAME consist of ethanol.

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

(In millions)	March 31, 2014		December 31, 2013
Centennial	$	—	$	1
Explorer	5		—
TAME	—		1
Total	$	5	$	2

We also had a long-term receivable from Centennial of $2 million at March 31, 2014 and December 31, 2013, which is included in other noncurrent assets on the consolidated balance sheets.

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

(In millions)	March 31, 2014		December 31, 2013
Explorer	$	4	$	—
LOCAP	2		2
LOOP	4		3
TAAE	2		2
TACE	4		4
TAME	7		5
Total	$	23	$	16

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Income per Common Share

3 Months Ended

Mar. 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.

Excluded from the diluted share calculation for both the three months ended March 31, 2014 and 2013 are less than one million shares related to stock-based compensation awards as their effect would be anti-dilutive.

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

	Three Months Ended   March 31,
(In millions, except per share data)	2014		2013
Basic earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	199	$	725
Income allocated to participating securities	—		1
Income available to common stockholders - basic	$	199	$	724
Weighted average common shares outstanding	293		331
Basic earnings per share	$	0.68	$	2.19
Diluted earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	199	$	725
Income allocated to participating securities	—		1
Income available to common stockholders - diluted	$	199	$	724
Weighted average common shares outstanding	293		331
Effect of dilutive securities	2		2
Weighted average common shares, including dilutive effect	295		333
Diluted earnings per share	$	0.67	$	2.17

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Segment Information

3 Months Ended

Mar. 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 they offer.

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

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

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

On February 1, 2013, we acquired the Galveston Bay Refinery and Related Assets, which are part of the Refining & Marketing and Pipeline Transportation segments. Segment information for the period prior to the acquisition does not include amounts for these operations. See Note 4.

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
Three Months Ended March 31, 2014
Revenues:
Customer	$	19,810	$	3,458	$	17	$	23,285
Intersegment(a)	2,233		1		129		2,363
Segment revenues	$	22,043	$	3,459	$	146	$	25,648
Segment income from operations(b)	$	362	$	58	$	72	$	492
Income from equity method investments	24		—		11		35
Depreciation and amortization(c)	261		28		19		308
Capital expenditures and investments(d)	178		32		130		340

(In millions)	Refining & Marketing			Speedway		Pipeline Transportation		Total
Three Months Ended March 31, 2013
Revenues:
Customer	$	19,874		$	3,441	$	21	$	23,336
Intersegment(a)	2,199			1		104		2,304
Segment revenues	$	22,073		$	3,442	$	125	$	25,640
Segment income from operations(b)	$	1,105		$	67	$	51	$	1,223
Income (loss) from equity method investments	(4		)	—		4		—
Depreciation and amortization(c)	236			27		18		281
Capital expenditures and investments(d)(e)	1,420			36		90		1,546

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

^(b)  Corporate overhead costs attributable to MPLX are included in the Pipeline Transportation segment. These expenses are not allocated to the Refining & Marketing and Speedway segments.

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

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

^(e)  The Refining & Marketing and Pipeline Transportation segments include the acquisition of the Galveston Bay Refinery and Related Assets. See Note 4.

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

	Three Months Ended   March 31,
(In millions)	2014			2013
Segment income from operations	$	492		$	1,223
Items not allocated to segments:
Corporate and other unallocated items(a)(b)	(67		)	(67		)
Pension settlement expenses(c)	(64		)	—
Net interest and other financial income (costs)	(46		)	(48		)
Income before income taxes	$	315		$	1,108

^(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 costs attributable to MPLX are included in the Pipeline Transportation segment. These expenses are not allocated to the Refining & Marketing and Speedway segments.

^(c)  See Note 18.

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

	Three Months Ended   March 31,
(In millions)	2014		2013
Segment capital expenditures and investments	$	340	$	1,546
Less: Investments in equity method investees	123		5
Plus: Items not allocated to segments:
Capital expenditures not allocated to segments	25		24
Capitalized interest	6		4
Total capital expenditures(a)(b)	$	248	$	1,569

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

^(b)  See Note 16 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 customer revenues to sales and other operating revenues (including consumer excise taxes) as reported in the consolidated statements of income:

	Three Months Ended   March 31,
(In millions)	2014		2013
Customer revenues (as reported above)	$	23,285	$	23,336
Corporate and other unallocated items	—		(6		)
Sales and other operating revenues (including consumer excise taxes)	$	23,285	$	23,330

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Segment Information - Income From Operations Attributable To Operating Segments (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Segment Reporting Information [Line Items]
Revenues	$ 23,285		$ 23,330
Income from operations	361		1,156
Income (loss) from equity method investments	35		0
Depreciation and amortization	320		287
Capital expenditures and investments	371	[1],[2],[3]	1,574	[1],[2],[3]
Refining & Marketing
Segment Reporting Information [Line Items]
Revenues	19,810		19,874
Speedway
Segment Reporting Information [Line Items]
Revenues	3,458		3,441
Pipeline Transportation
Segment Reporting Information [Line Items]
Revenues	17		21
Reportable Segment
Segment Reporting Information [Line Items]
Revenues	23,285		23,336
Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	(2,363)	[4]	(2,304)	[4]
Intersegment Eliminations | Refining & Marketing
Segment Reporting Information [Line Items]
Revenues	(2,233)	[4]	(2,199)	[4]
Intersegment Eliminations | Speedway
Segment Reporting Information [Line Items]
Revenues	(1)	[4]	(1)	[4]
Intersegment Eliminations | Pipeline Transportation
Segment Reporting Information [Line Items]
Revenues	(129)	[4]	(104)	[4]
Operating Segments
Segment Reporting Information [Line Items]
Revenues	25,648		25,640
Income from operations	492	[5]	1,223	[5]
Income (loss) from equity method investments	35		0
Depreciation and amortization	308	[6]	281	[6]
Capital expenditures and investments	340	[1]	1,546	[1],[7]
Operating Segments | Refining & Marketing
Segment Reporting Information [Line Items]
Revenues	22,043		22,073
Income from operations	362		1,105
Income (loss) from equity method investments	24		(4)
Depreciation and amortization	261	[6]	236	[6]
Capital expenditures and investments	178	[1]	1,420	[1],[7]
Operating Segments | Speedway
Segment Reporting Information [Line Items]
Revenues	3,459		3,442
Income from operations	58		67
Income (loss) from equity method investments	0		0
Depreciation and amortization	28	[6]	27	[6]
Capital expenditures and investments	32	[1]	36	[1],[7]
Operating Segments | Pipeline Transportation
Segment Reporting Information [Line Items]
Revenues	146		125
Income from operations	72	[5]	51	[5]
Income (loss) from equity method investments	11		4
Depreciation and amortization	19	[6]	18	[6]
Capital expenditures and investments	$ 130	[1]	$ 90	[1],[7]

[1] Capital expenditures include changes in capital accruals.

[2] The three months ended March 31, 2013 includes the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, plus assumed liabilities. Total consideration includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 4 to the unaudited consolidated financial statements.

[3] Includes capitalized interest $6 million and $4 million for the three months ended March 31, 2014 and 2013, respectively.

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

[5] Corporate overhead costs attributable to MPLX are included in the Pipeline Transportation segment. These expenses are not allocated to the Refining & Marketing and Speedway segments.

[6] Differences between segment totals and MPC totals represent amounts related to unallocated items and are included in “Items not allocated to segments” in the reconciliation below.

[7] The Refining & Marketing and Pipeline Transportation segments include the acquisition of the Galveston Bay Refinery and Related Assets. See Note 4.

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Defined Benefit Pension and Other Postretirement Plans - Components of Net Periodic Benefit Costs (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Pension Benefits
Components of net periodic benefit cost:
Service cost	$ 23	$ 23
Interest cost	20	18
Expected return on plan assets	(28)	(27)
Amortization – prior service credit	(12)	(11)
Amortization – actuarial loss	13	21
Amortization – net settlement loss	64	0
Net periodic benefit cost	80	24
Other Benefits
Components of net periodic benefit cost:
Service cost	7	6
Interest cost	8	7
Expected return on plan assets	0	0
Amortization – prior service credit	(1)	(2)
Amortization – actuarial loss	1	1
Amortization – net settlement loss	0	0
Net periodic benefit cost	$ 15	$ 12

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Segment Information - Reconciliation Of Segment Capital Expenditures And Investments To Total Capital Expenditures (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Reconciliation Of Segment Capital Expenditures And Investments To Total Capital Expenditures [Line Items]
Capital expenditures and investments	$ 371	[1],[2],[3]	$ 1,574	[1],[2],[3]
Plus: Items not allocated to segments:
Total capital expenditures	248	[1],[4]	1,569	[1],[4]
Operating Segments
Reconciliation Of Segment Capital Expenditures And Investments To Total Capital Expenditures [Line Items]
Capital expenditures and investments	340	[1]	1,546	[1],[5]
Less: Investments in equity method investees	123		5
Corporate and Other
Reconciliation Of Segment Capital Expenditures And Investments To Total Capital Expenditures [Line Items]
Capital expenditures and investments	31	[1],[3]	28	[1],[3]
Plus: Items not allocated to segments:
Capital expenditures not allocated to segments	25		24
Capitalized interest	$ 6		$ 4

[1] Capital expenditures include changes in capital accruals.

[2] The three months ended March 31, 2013 includes the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, plus assumed liabilities. Total consideration includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 4 to the unaudited consolidated financial statements.

[3] Includes capitalized interest $6 million and $4 million for the three months ended March 31, 2014 and 2013, respectively.

[4] See Note 16 for a reconciliation of total capital expenditures to additions to property, plant and equipment as reported in the consolidated statements of cash flows.

[5] The Refining & Marketing and Pipeline Transportation segments include the acquisition of the Galveston Bay Refinery and Related Assets. See Note 4.

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Segment Information - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2014 Segment
Segment Reporting [Abstract]
Number of reportable segments	3

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Subsequent Event Subsequent Event (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended		1 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Apr. 30, 2014 Felda Iffco Sdn Bhd [Member] Subsequent Event [Member]	Apr. 02, 2014 Felda Iffco Sdn Bhd [Member] Subsequent Event [Member] gallons_per_year
Subsequent Event [Line Items]
Cash paid for acquisition	$ 0	$ 1,493	$ 40
Plant capacity (in gallons per year)				60,000,000

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Equity (Tables)

3 Months Ended

Mar. 31, 2014

Equity [Abstract]

Share Repurchases Transacted Through ASR Programs and Open Market Transactions

Total share repurchases were as follows for the three months ended March 31, 2014 and 2013:

	Three Months Ended   March 31,
(In millions, except per share data)	2014		2013
Number of shares repurchased(a)	8		6
Cash paid for shares repurchased	$	689	$	431
Effective average cost per delivered share	$	87.60	$	80.95

^(a)  The three months ended March 31, 2013 includes one million shares received under the November 2012 accelerated share repurchase program, which were paid for in the fourth quarter of 2012.

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Acquisitions and Investments Acquisitions and Investments (Acquisitions of Convenience Stores) (Details) (Speedway, USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2013 Store
Speedway
Business Acquisition [Line Items]
Number of convenience stores acquired	9
Goodwill acquired during period	$ 8

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Fair Value Measurements

3 Months Ended

Mar. 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 March 31, 2014 and December 31, 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.

	March 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	$	41	$	—	$	—	$	(39	)	$	2	$	82
Other assets	2		—		—		N/A			2		—
Total assets at fair value	$	43	$	—	$	—	$	(39	)	$	4	$	82
Commodity derivative instruments, liabilities	$	81	$	—	$	—	$	(81	)	$	—	$	—
Contingent consideration, liability(c)	—		—		639		N/A			639		—
Total liabilities at fair value	$	81	$	—	$	639	$	(81	)	$	639	$	—

	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 March 31, 2014 and December 31, 2013, cash collateral of $42 million and $32 million, respectively, was netted with mark-to-market derivative liabilities.

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

^(c)  Includes $178 million and $159 million classified as current at March 31, 2014 and December 31, 2013, respectively.

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 March 31, 2014 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 4. The fair value of the contingent consideration was estimated using an income approach and is therefore a Level 3 liability. The amount of cash to be paid under the arrangement is based on both a market-based crack spread and refinery throughput volumes for the months during which the contract applies, as well as established thresholds that cap the annual and total payment. The earnout payment cannot exceed $200 million per year for the first three years of the arrangement or $250 million per year for the last three years of the arrangement, with the total cumulative payment capped at $700 million over the six-year period. Any excess or shortfall from the annual cap for a current year’s earnout calculation will not affect subsequent years’ calculations. The fair value calculation used significant unobservable inputs, including (1) an estimate of refinery throughput volumes; (2) a range of internal and external crack spread forecasts from $13 to $18 per barrel; and (3) a range of risk-adjusted discount rates from 5 percent to 10 percent. An increase or decrease in crack spread forecasts or refinery throughput volume expectations will result in a corresponding increase or decrease in the fair value. Increases to the fair value as a result of increasing forecasts for both of these unobservable inputs, however, are limited as the earnout payment is subject to annual thresholds. An increase or decrease in the discount rate will result in a decrease or increase to the fair value, respectively. The fair value of the contingent consideration is reassessed each quarter, with changes in fair value recorded in cost of revenues.

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

	Three Months Ended   March 31,
(In millions)	2014		2013
Beginning balance	$	625	$	—
Contingent consideration agreement	—		600
Total realized and unrealized losses included in net income	14		—
Ending balance	$	639	$	600

We did not hold any Level 3 derivative instruments during the three months ended March 31, 2014 and 2013. See Note 14 for the income statement impacts of our derivative instruments. There was an unrealized loss of $14 million related to the contingent consideration agreement for the three months ended March 31, 2014.

Fair Values – Reported

The following table summarizes financial instruments on the basis of their nature, characteristics and risk at March 31, 2014 and December 31, 2013, excluding the derivative financial instruments and contingent consideration reported above.

	March 31, 2014				December 31, 2013
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial assets:
Investments	$	39	$	13	$	336	$	14
Other	30		28		31		30
Total financial assets	$	69	$	41	$	367	$	44
Financial liabilities:
Long-term debt(a)	$	3,670	$	3,270	$	3,306	$	3,001
Deferred credits and other liabilities	21		21		21		21
Total financial liabilities	$	3,691	$	3,291	$	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. Fair value of variable-rate long-term debt approximates the carrying value.

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Defined Benefit Pension and Other Postretirement Plans

3 Months Ended

Mar. 31, 2014

Compensation and Retirement Disclosure [Abstract]

Defined Benefit Pension and Other Postretirement Plans

Defined Benefit Pension and Other Postretirement Plans

The following summarizes the components of net periodic benefit costs:

	Three Months Ended March 31,
	Pension Benefits						Other Benefits
(In millions)	2014			2013			2014			2013
Components of net periodic benefit cost:
Service cost	$	23		$	23		$	7		$	6
Interest cost	20			18			8			7
Expected return on plan assets	(28		)	(27		)	—			—
Amortization – prior service credit	(12		)	(11		)	(1		)	(2		)
– actuarial loss	13			21			1			1
– net settlement loss	64			—			—			—
Net periodic benefit cost	$	80		$	24		$	15		$	12

During the three months ended March 31, 2014, we made no contributions to our funded pension plans. We have no required funding for 2014 but may do so at our discretion. Current benefit payments related to unfunded pension and other postretirement benefit plans were $8 million and $5 million, respectively, during the three months ended March 31, 2014.

During the three months ended March 31, 2014, we determined that lump sum payments to employees retiring in 2014 will exceed the plans’ total service and interest costs for the year. Settlement losses are required to be recorded when lump sum payments exceed total service and interest costs. As a result, during the three months ended March 31, 2014, we recorded pension settlement expenses of $64 million related to our cumulative lump sum payments made during the first three months of 2014.

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Acquisitions and Investments (Acquisition of Refinery and Related Logistics and Marketing Assets) (Detail) (USD $)	3 Months Ended		1 Months Ended		3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Feb. 01, 2013 Galveston Bay Refinery and Related Assets site Pipeline Terminal BPCD BPD MW	Mar. 31, 2014 Galveston Bay Refinery and Related Assets	Jun. 30, 2014 Scenario, Forecast 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	$ 0	$ 1,493,000,000	$ 1,490,000,000		$ 178,000,000
Inventories			935,000,000
Total cumulative payment capped over six-year period			$ 700,000,000	$ 700,000,000
Term of payment of maximum earnout provision payable to the company, years			6 years

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Debt (Tables)

3 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Outstanding Borrowings

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

(In millions)	March 31, 2014			December 31, 2013
Marathon Petroleum Corporation:
Revolving credit agreement due 2017	$	—		$	—
3.500% senior notes due March 1, 2016	750			750
5.125% senior notes due March 1, 2021	1,000			1,000
6.500% senior notes due March 1, 2041	1,250			1,250
Consolidated subsidiaries:
Capital lease obligations due 2014-2028	389			395
MPLX Operations LLC revolving credit agreement due 2017	270			—
Trade receivables securitization facility due 2016	—			—
Total	3,659			3,395
Unamortized discount	(10		)	(10		)
Fair value adjustments(a)	10			11
Amounts due within one year	(24		)	(23		)
Total long-term debt due after one year	$	3,635		$	3,373

^(a)  The $20 million gain on the termination of our interest rate swap agreements in 2012 is being amortized over the remaining life of the 3.50 percent senior notes.

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Consolidated Balance Sheets (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 2,166	$ 2,292
Receivables, less allowance for doubtful accounts of $9 and $9	5,420	5,559
Inventories	5,689	4,689
Other current assets	173	197
Total current assets	13,448	12,737
Equity method investments	602	463
Property, plant and equipment, net	13,854	13,921
Goodwill	938	938
Other noncurrent assets	317	326
Total assets	29,159	28,385
Current liabilities:
Accounts payable	9,313	8,234
Payroll and benefits payable	259	406
Consumer excise taxes payable	371	373
Accrued taxes	614	513
Long-term debt due within one year	24	23
Other current liabilities	265	275
Total current liabilities	10,846	9,824
Long-term debt	3,635	3,373
Deferred income taxes	2,290	2,304
Defined benefit postretirement plan obligations	855	771
Deferred credits and other liabilities	775	781
Total liabilities	18,401	17,053
Commitments and contingencies (see Note 20)
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 - 73 million and 65 million shares	(4,849)	(4,155)
Additional paid-in capital	9,803	9,768
Retained earnings	5,591	5,507
Accumulated other comprehensive loss	(205)	(204)
Total MPC stockholders’ equity	10,344	10,920
Noncontrolling interests	414	412
Total equity	10,758	11,332
Total liabilities and equity	$ 29,159	$ 28,385

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Stock-Based Compensation Plans - Narrative (Detail) (USD $)	3 Months Ended
	Mar. 31, 2014
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant date fair value (in USD per share)	$ 24.87
Implied volatility rate weighting (in percentage)	50.00%
Historical volatility rate weighting (in percentage)	50.00%
Performance Unit Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Grant date fair value (in USD per unit)	$ 1.02

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Accounting Standards

3 Months Ended

Mar. 31, 2014

Accounting Changes and Error Corrections [Abstract]

Accounting Standards

Accounting Standards

Not Yet Adopted

In April 2014, the Financial Accounting Standards Board ("FASB") issued an accounting standards update which 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(s) of an entity or the classification of a component(s) of an entity as held for sale which 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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Related Party Transactions - Payables To Related Parties (Detail) (USD $) In Millions, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Payables to related parties	$ 23	$ 16
Explorer
Related Party Transaction [Line Items]
Payables to related parties	4	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	4	4
TAME
Related Party Transaction [Line Items]
Payables to related parties	$ 7	$ 5

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Supplemental Cash Flow Information - Summary of Supplemental Cash Flow Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$ 80	$ 83
Net income taxes paid to (refunded from) taxing authorities	5	(5)
Non-cash investing and financing activities:
Capital lease obligations increase	0	61
Acquisition:
Contingent consideration	0	600	[1]
Payable to seller	$ 0	$ 6	[1]

[1] Acquisition-date fair value of non-cash consideration associated with the Galveston Bay Refinery and Related Assets acquisition.

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Income Taxes - Additional Information (Detail) (USD $) In Millions, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Income Tax Disclosure [Abstract]
Combined federal, state and foreign income tax rate	34.00%	34.00%
Statutory rate applied to income before income taxes	35.00%
Unrecognized benefits	$ 16

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Stock-Based Compensation Plans

3 Months Ended

Mar. 31, 2014

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

Stock-Based Compensation Plans

Stock-Based Compensation Plans

Stock Option Awards

The following table presents a summary of our stock option award activity for the three months ended March 31, 2014:

	Number of Shares(a)		Weighted Average Exercise Price
Outstanding at December 31, 2013	5,147,837		$	40.08
Granted	327,100		83.37
Exercised	(455,999	)	30.65
Forfeited, canceled or expired	(19,293	)	50.05
Outstanding at March 31, 2014	4,999,645		43.73

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

The grant date fair value of stock option awards granted during the three months ended March 31, 2014 was $24.87 per share. The fair value of stock options granted to our employees is estimated on the date of the grant using the Black Scholes option-pricing model, which employs various assumptions. The assumption for expected volatility of our stock price was refined for the three months ended March 31, 2014 to reflect a weighting of 50 percent of MPC’s common stock implied volatility and 50 percent of MPC's common stock historical volatility.

Restricted Stock Awards

The following table presents a summary of restricted stock award activity for the three months ended March 31, 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	51,594		83.45		5,939	89.96
RS's Vested/RSU's Issued	(117,980	)	54.43		—	—
Forfeited	(14,840	)	64.31		—	—
Outstanding at March 31, 2014	542,896		64.60		391,018	34.81

Performance Unit Awards

The following table presents a summary of the activity for performance unit awards to be settled in shares for the three months ended March 31, 2014:

	Number of Units
Outstanding at December 31, 2013	3,822,500
Granted	2,033,700
Settled	—
Canceled	—
Outstanding at March 31, 2014	5,856,200

The performance unit awards granted in 2014 have a grant date fair value of $1.02 per unit, as calculated using a Monte Carlo valuation model.

MPLX Awards

During the three months ended March 31, 2014, MPLX granted equity-based compensation awards under the MPLX LP 2012 Incentive Compensation Plan. The compensation expense for these awards is not material to our consolidated financial statements.

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Fair Value Measurements - Narrative (Detail) (USD $)	3 Months Ended						3 Months Ended
	Mar. 31, 2014 Fair Value, Measurements, Recurring Derivative	Mar. 31, 2013 Fair Value, Measurements, Recurring Derivative	Mar. 31, 2014 Fair Value, Measurements, Recurring Contingent Consideration	Mar. 31, 2013 Fair Value, Measurements, Recurring Contingent Consideration	Mar. 31, 2014 Galveston Bay Refinery and Related Assets	Feb. 01, 2013 Galveston Bay Refinery and Related Assets	Mar. 31, 2014 Galveston Bay Refinery and Related Assets Fair Value, Measurements, Recurring Minimum	Mar. 31, 2014 Galveston Bay Refinery and Related Assets Fair Value, Measurements, Recurring Maximum
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
Total cumulative payment capped over six-year period					700,000,000	700,000,000
Range of internal and external crack spread forecast per barrel							13	18
Discount rate							5.00%	10.00%
Unrealized losses included in net income	$ 0	$ 0	$ 14,000,000	$ 0

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Property, Plant and Equipment (Tables)

3 Months Ended

Mar. 31, 2014

Property, Plant and Equipment [Abstract]

Summary Of Property, Plant And Equipment

(In millions)	March 31, 2014		December 31, 2013
Refining & Marketing	$	17,117	$	16,982
Speedway	2,374		2,344
Pipeline Transportation	1,926		1,921
Corporate and Other	570		546
Total	21,987		21,793
Less accumulated depreciation	8,133		7,872
Property, plant and equipment, net	$	13,854	$	13,921

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Property, Plant and Equipment

3 Months Ended

Mar. 31, 2014

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

(In millions)	March 31, 2014		December 31, 2013
Refining & Marketing	$	17,117	$	16,982
Speedway	2,374		2,344
Pipeline Transportation	1,926		1,921
Corporate and Other	570		546
Total	21,987		21,793
Less accumulated depreciation	8,133		7,872
Property, plant and equipment, net	$	13,854	$	13,921