Marathon Petroleum (MPC) 10-Q 2013 Q2 Quarterly report

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 June 30, 2013

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 313,074,196 shares of Marathon Petroleum Corporation common stock outstanding as of July 31, 2013.

MARATHON PETROLEUM CORPORATION

Form 10-Q

Quarter Ended June 30, 2013

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		29
Item 3.     Quantitative and Qualitative Disclosures about Market Risk		45
Item 4.     Controls and Procedures		46
Supplementary Statistics (Unaudited)		47
PART II – OTHER INFORMATION
Item 1.     Legal Proceedings		49
Item 1A.  Risk Factors		49
Item 2.     Unregistered Sales of Equity Securities and Use of Proceeds		50
Item 6.     Exhibits		51
Signatures		52

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						Six Months Ended
	June 30,						June 30,
(In millions, except per share data)	2013			2012			2013			2012
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$	25,675		$	20,240		$	49,003		$	40,504
Sales to related parties		2			3			4			4
Income from equity method investments		7			9			7			11
Net gain on disposal of assets		1			1			2			3
Other income		18			4			32			10
Total revenues and other income		25,703			20,257			49,048			40,532
Costs and expenses:
Cost of revenues (excludes items below)		22,320			16,800			42,354			34,121
Purchases from related parties		79			57			151			120
Consumer excise taxes		1,596			1,428			3,054			2,808
Depreciation and amortization		302			236			589			466
Selling, general and administrative expenses		358			365			607			616
Other taxes		88			64			177			138
Total costs and expenses		24,743			18,950			46,932			38,269
Income from operations		960			1,307			2,116			2,263
Net interest and other financial income (costs)		(45	)		(17	)		(93	)		(39	)
Income before income taxes		915			1,290			2,023			2,224
Provision for income taxes		316			476			694			814
Net income		599			814			1,329			1,410
Less net income attributable to noncontrolling interests		6			—			11			—
Net income attributable to MPC	$	593		$	814		$	1,318		$	1,410
Per Share Data (See Note 7)
Basic:
Net income attributable to MPC per share	$	1.84		$	2.39		$	4.03		$	4.09
Weighted average shares outstanding		322			340			326			344
Diluted:
Net income attributable to MPC per share	$	1.83		$	2.38		$	4.01		$	4.07
Weighted average shares outstanding		324			341			328			346
Dividends paid	$	0.35		$	0.25		$	0.70		$	0.50

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					Six Months Ended
	June 30,					June 30,
(In millions)	2013			2012		2013			2012
Net income	$	599		$	814	$	1,329		$	1,410
Other comprehensive income (loss):
Defined benefit postretirement and post-employment plans:
Actuarial changes, net of tax of $81, $25, $135 and $33		135			39		225			55
Prior service costs, net of tax of ($4), $196, ($9) and $197		(7	)		326		(15	)		327
Other comprehensive income		128			365		210			382
Comprehensive income		727			1,179		1,539			1,792
Less comprehensive income attributable to noncontrolling interests		6			—		11			—
Comprehensive income attributable to MPC	$	721		$	1,179	$	1,528		$	1,792

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

3

Marathon Petroleum Corporation

Consolidated Balance Sheets (Unaudited)

	June 30,			December 31,
(In millions, except per share data)	2013			2012
Assets
Current assets:
Cash and cash equivalents	$	3,069		$	4,860
Receivables, less allowance for doubtful accounts of $9 and $10		6,163			4,610
Inventories		4,830			3,449
Other current assets		190			110
Total current assets		14,252			13,029
Equity method investments		328			321
Property, plant and equipment, net		13,799			12,643
Goodwill		938			930
Other noncurrent assets		378			300
Total assets	$	29,695		$	27,223
Liabilities
Current liabilities:
Accounts payable	$	8,601		$	6,785
Payroll and benefits payable		284			364
Consumer excise taxes payable		406			325
Accrued taxes		612			598
Long-term debt due within one year		23			19
Other current liabilities		315			112
Total current liabilities		10,241			8,203
Long-term debt		3,387			3,342
Deferred income taxes		2,187			2,050
Defined benefit postretirement plan obligations		929			1,266
Deferred credits and other liabilities		754			257
Total liabilities		17,498			15,118
Commitments and contingencies (see Note 22)
Equity
MPC stockholders’ equity:
Preferred stock, no shares issued and outstanding (par value $0.01 per share, 30 million shares authorized)		—			—
Common stock:
Issued—362 million and 361 million shares (par value $0.01 per share, 1 billion shares authorized)		4			4
Held in treasury, at cost—45 million and 28 million shares		(2,672	)		(1,253	)
Additional paid-in capital		9,737			9,527
Retained earnings		4,969			3,880
Accumulated other comprehensive loss		(254	)		(464	)
Total MPC stockholders’ equity		11,784			11,694
Noncontrolling interests		413			411
Total equity		12,197			12,105
Total liabilities and equity	$	29,695		$	27,223

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

4

Marathon Petroleum Corporation

Consolidated Statements of Cash Flows (Unaudited)

	Six Months Ended June 30,
(In millions)	2013			2012
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	1,329		$	1,410
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		589			466
Pension and other postretirement benefits, net		(42	)		183
Deferred income taxes		34			328
Net gain on disposal of assets		(2	)		(3	)
Equity method investments, net		3			8
Changes in the fair value of derivative instruments		(57	)		106
Changes in:
Current receivables		(1,539	)		753
Inventories		(455	)		(697	)
Current accounts payable and accrued liabilities		1,789			(2,022	)
All other, net		(6	)		84
Net cash provided by operating activities		1,643			616
Investing activities:
Additions to property, plant and equipment		(424	)		(635	)
Acquisitions		(1,515	)		(163	)
Disposal of assets		9			6
Investments—loans and advances		(38	)		(11	)
—redemptions and repayments		28			3
All other, net		22			2
Net cash used in investing activities		(1,918	)		(798	)
Financing activities:
Long-term debt—repayments		(10	)		(6	)
Debt issuance costs		(2	)		—
Issuance of common stock		34			32
Common stock repurchased		(1,313	)		(850	)
Dividends paid		(229	)		(172	)
Distributions to noncontrolling interests		(9	)		—
All other, net		13			(6	)
Net cash used in financing activities		(1,516	)		(1,002	)
Net decrease in cash and cash equivalents		(1,791	)		(1,184	)
Cash and cash equivalents at beginning of period		4,860			3,079
Cash and cash equivalents at end of period	$	3,069		$	1,895

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, 2011	$	4	$	—		$	9,482		$	898		$	(879	)	$	—		$	9,505
Net income		—		—			—			1,410			—			—			1,410
Dividends paid		—		—			—			(172	)		—			—			(172	)
Other comprehensive income		—		—			—			—			382			—			382
Shares repurchased		—		(742	)		(108	)		—			—			—			(850	)
Shares issued (returned)—stock based compensation		—		(1	)		33			—			—			—			32
Stock-based compensation		—		—��			28			—			—			—			28
Other		—		—			(9	)		—			—			—			(9	)
Balance as of June 30, 2012	$	4	$	(743	)	$	9,426		$	2,136		$	(497	)	$	—		$	10,326
Balance as of December 31, 2012	$	4	$	(1,253	)	$	9,527		$	3,880		$	(464	)	$	411		$	12,105
Net income		—		—			—			1,318			—			11			1,329
Dividends paid		—		—			—			(229	)		—			—			(229	)
Distributions to noncontrolling interests		—		—			—			—			—			(9	)		(9	)
Other comprehensive income		—		—			—			—			210			—			210
Shares repurchased		—		(1,413	)		100			—			—			—			(1,313	)
Shares issued (returned)—stock based compensation		—		(6	)		33			—			—			—			27
Stock-based compensation		—		—			38			—			—			—			38
Tax settlement with Marathon Oil Corporation		—		—			39			—			—			—			39
Balance as of June 30, 2013	$	4	$	(2,672	)	$	9,737		$	4,969		$	(254	)	$	413		$	12,197
(Shares in millions)	Common Stock		Treasury Stock
Balance as of December 31, 2011		357		—
Shares repurchased		—		(18	)
Shares issued—stock-based compensation		1		—
Balance as of June 30, 2012		358		(18	)
Balance as of December 31, 2012		361		(28	)
Shares repurchased		—		(17	)
Shares issued—stock-based compensation		1		—
Balance as of June 30, 2013		362		(45	)

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 9 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, 2012. The results of operations for the three and six months ended June 30, 2013 are not necessarily indicative of the results to be expected for the full year.

In the fourth quarter of 2012, we reclassified certain expenses from selling, general and administrative expenses to cost of revenues, which is consistent with expense classifications for MPLX, MPC’s consolidated subsidiary. Historical periods were also reclassified to conform to the current period presentation. This reclassification resulted in an increase in cost of revenues and a decrease in selling, general and administrative expenses of $11 million and $23 million in the three and six months ended June 30, 2012, respectively.

2. Accounting Standards

Recently Adopted

In February 2013, the Financial Accounting Standards Board (“FASB”) issued an accounting standards update that requires an entity to provide information about the amounts reclassified out of accumulated other comprehensive income by component. If the amount reclassified is required under US GAAP to be reclassified to net income in its entirety in the same reporting period, an entity is required to present, either on the face of the financial statements or in the notes, significant amounts reclassified out of accumulated other comprehensive income by the respective line items of net income. For other amounts not required to be reclassified in their entirety to net income, an entity is required to cross-reference to other disclosures that provide additional detail about those amounts. The accounting standards update was to be applied prospectively for interim and annual periods beginning with the first quarter of 2013. The adoption of this accounting standards update in the first quarter of 2013 did not have an impact on our consolidated results of operations, financial position or cash flows. The new required disclosures are included in Note 19.

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

7

In December 2011, the FASB issued an accounting standards update which was amended in January 2013 that requires disclosure of additional information related to recognized derivative instruments, repurchase agreements and reverse repurchase agreements, and securities borrowing and securities lending transactions that are offset or are not offset but are subject to an enforceable netting agreement. The purpose of the requirement is to help users evaluate the effect or potential effect of offsetting and related netting arrangements on an entity’s financial position. The update was to be applied retrospectively and was effective for interim and annual periods beginning with the first quarter of 2013. The adoption of this accounting standards update in the first quarter of 2013 did not have an impact on our consolidated results of operations, financial position or cash flows. The new required disclosures are included in Note 15.

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. MPLX’s initial assets consisted of a 51 percent general partner interest in MPLX Pipe Line Holdings LP (“Pipe Line Holdings”), which owns a network of common carrier crude oil and product pipeline systems and associated storage assets in the Midwest and Gulf Coast regions of the United States, and a 100 percent interest in a butane storage cavern in West Virginia. On May 1, 2013, we sold an additional five percent interest in Pipe Line Holdings to MPLX for $100 million. This increased MPLX’s ownership interest in Pipe Line Holdings to 56 percent and reduced our ownership interest to 44 percent.

On October 31, 2012, MPLX completed its initial public offering of 19,895,000 common units. Net proceeds to MPLX from the sale of the units were $407 million. We own a 73.6 percent interest in MPLX, including the two percent general partner interest. We consolidate this entity for financial reporting purposes since we have a controlling financial interest, and we record a noncontrolling interest for the interest owned by the public. The initial public offering represented the sale of a 26.4 percent interest in MPLX.

4. Related Party Transactions

Our related parties included:

• The Andersons Clymers Ethanol LLC (“TACE”), in which we had a 36 percent interest during the six months ended June 30, 2013 and 2012, and The Andersons Marathon Ethanol LLC (“TAME”), in which we had a 50 percent interest during the six months ended June 30, 2013 and 2012. These companies each own an ethanol production facility. Subsequent to June 30, 2013, we increased our ownership interests in TACE and TAME. See Note 23 for additional information.

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

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

• Other equity method investees.

Sales to related parties were as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2013		2012		2013		2012
Centennial	$	—	$	1	$	—	$	1
Other equity method investees		2		2		4		3
Total	$	2	$	3	$	4	$	4

8

Fees received for operating Centennial’s pipeline, which are included in other income on the consolidated statements of income, were $1 million for the three and six months ended June 30, 2013.

Purchases from related parties were as follows:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2013		2012		2013		2012
Centennial	$	—	$	—	$	—	$	9
LOOP		11		9		21		21
TAME		37		30		67		60
TACE		24		10		50		15
Other equity method investees		7		8		13		15
Total	$	79	$	57	$	151	$	120

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

Receivables from Centennial, which are included in receivables, less allowance for doubtful accounts on the consolidated balance sheets, were $1 million at June 30, 2013 and $2 million at December 31, 2012.

At June 30, 2013, we also had a $2 million long-term receivable from Centennial, which is included in other noncurrent assets on the consolidated balance sheet.

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

	June 30,		December 31,
(In millions)	2013		2012
LOOP	$	4	$	4
TAME		5		5
TACE		5		2
Other equity method investees		2		2
Total	$	16	$	13

We had a throughput and deficiency agreement with Centennial, which expired on March 31, 2012. During the first quarter of 2012, we impaired our $14 million prepaid tariff with Centennial. For additional information on the impairment, see Note 15.

5. Acquisitions

Acquisition of Refinery and Related Logistics and Marketing Assets

On February 1, 2013, we paid $1.49 billion to acquire from BP Products North America Inc. and BP Pipelines (North America) Inc. (collectively, “BP”) the 451,000 barrel per calendar day refinery in Texas City, Texas, three intrastate natural gas liquid pipelines originating at the refinery, an allocation of BP’s Colonial Pipeline Company shipper history, four light product terminals, branded-jobber marketing contract assignments for the supply of approximately 1,200 branded sites and a 1,040 megawatt electric cogeneration facility, as well as the inventory associated with these assets. We refer to these assets as the “Galveston Bay Refinery and Related Assets”. Pursuant to the purchase and sale agreement, we may also be required to pay to BP a contingent earnout of up to an additional $700 million over six years, subject to certain conditions as discussed below. These assets complement our current geographic footprint and align with our strategic initiative of growing in existing and contiguous markets to enhance our portfolio. The transaction was funded with cash on hand.

9

As of the acquisition date, we recorded a contingent liability of $600 million, representing the preliminary fair value of contingent consideration we expect to pay to BP related to the earnout provision. The fair value of the contingent consideration was estimated using an income approach. The amount of cash to be paid under the arrangement is based on both a market-based crack spread and refinery throughput volumes for the months during which the contract applies, as well as established thresholds that cap the annual and total payment. The earnout payment cannot exceed $200 million per year for the first three years of the arrangement or $250 million per year for the last three years of the arrangement, with the total cumulative payment capped at $700 million over the six-year period. Any excess or shortfall from the annual cap for a current year’s earnout calculation will not affect subsequent years’ calculations. We used internal and external forecasts for the crack spread and internal forecasts for refinery throughput volumes and applied an appropriate risk-adjusted discount rate to the range of cash flows indicated by various scenarios to determine the fair value of the arrangement. The fair value of the contingent consideration is reassessed each quarter, with changes in fair value recorded in cost of revenues. The fair value of the contingent consideration was $611 million at June 30, 2013, which includes $190 million classified as current. See Note 15 for additional information.

The transaction provides for a post-closing adjustment for inventory, which as of June 30, 2013 had not been finalized with the seller. If a change is made for the inventory adjustment, the fair value of the assets acquired will be revised.

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

(In millions)
Cash	$	1,491
Fair value of contingent consideration as of acquisition date		600
Liability assumed to seller		6
Estimated post-closing adjustment		(14	)
Total consideration	$	2,083

The following table summarizes the estimated fair values of the assets acquired and liabilities assumed as of the acquisition date, pending completion of an independent appraisal and other evaluations. During the second quarter of 2013, we made minor updates to the preliminary fair value measurements of assets acquired and liabilities assumed, with the revised balances shown in the table below.

(In millions)
Inventories	$	925
Other current assets		1
Property, plant and equipment, net		1,279
Other noncurrent assets		88
Accounts payable		(12	)
Payroll and benefits payable		(14	)
Long-term debt due within one year(a)		(2	)
Other current liabilities		(6	)
Long-term debt(a)		(58	)
Defined benefit postretirement plan obligations		(43	)
Deferred credits and other liabilities		(75	)
Total	$	2,083

^(a) Represents a capital lease obligation assumed.

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

10

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

We recognized $6 million of acquisition-related costs associated with the Galveston Bay Refinery and Related Assets acquisition through June 30, 2013. These costs were expensed and were included in selling, general and administrative expenses.

Our refineries and related assets are operated as an integrated system. As the information is not available by refinery, it is not practicable to disclose the revenues and net income associated with the acquisition that were included in our consolidated statements of income for the three and six months ended June 30, 2013.

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

	Three Months Ended June 30,		Six Months Ended June 30,
(In millions, except per share data)	2012		2013		2012
Sales and other operating revenues (including consumer excise taxes)	$	25,508	$	50,971	$	50,826
Net income attributable to MPC		804		1,373		1,268
Net income attributable to MPC per share—basic	$	2.36	$	4.21	$	3.69
Net income attributable to MPC per share—diluted		2.36		4.19		3.66

The pro forma information includes adjustments to align accounting policies, an adjustment to depreciation expense to reflect the fair value of property, plant and equipment, increased amortization expense related to identifiable intangible assets and the related income tax effects. The pro forma information for the six months ended June 30, 2013 and 2012 reflect revisions made during the second quarter of 2013 to the estimated fair values of assets acquired and liabilities assumed.

Acquisitions of Convenience Stores

During the six months ended June 30, 2013, Speedway LLC acquired 9 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.

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

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

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

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

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6. Variable Interest Entity

On December 1, 2010, we completed the sale of most of our Minnesota assets. These assets included the 74,000 barrel per calendar day St. Paul Park refinery and associated terminals, 166 convenience stores primarily branded SuperAmerica^®, along with the SuperMom’s bakery and certain associated trademarks, SuperAmerica Franchising LLC, interests in pipeline assets in Minnesota and associated inventories. We refer to these assets as the “Minnesota Assets.” Certain terms of the transaction and the subsequent settlement agreement with the buyer resulted in the creation of variable interests in a variable interest entity (“VIE”) that owns the Minnesota Assets. At June 30, 2013, our variable interests in this VIE included our preferred security, which was reflected at $48 million in other noncurrent assets on our consolidated balance sheet, and store lease guarantees of $5 million. Our maximum exposure to loss due to this VIE at June 30, 2013 was $53 million.

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

7. 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 stock options and stock appreciation rights, provided the effect is not anti-dilutive.

Shares related to stock-based compensation awards excluded from the diluted share calculation as their effect would be anti-dilutive are approximately one million and five million shares for the three months ended June 30, 2013 and 2012 and one million and four million shares for the six months ended June 30, 2013 and 2012, respectively.

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				Six Months Ended
	June 30,				June 30,
(In millions, except per share data)	2013		2012		2013		2012
Basic earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	593	$	814	$	1,318	$	1,410
Income allocated to participating securities		1		2		2		3
Income available to common stockholders—basic	$	592	$	812	$	1,316	$	1,407
Weighted average common shares outstanding		322		340		326		344
Basic earnings per share	$	1.84	$	2.39	$	4.03	$	4.09
Diluted earnings per share:
Allocation of earnings:
Net income attributable to MPC	$	593	$	814	$	1,318	$	1,410
Income allocated to participating securities		1		2		2		3
Income available to common stockholders—diluted	$	592	$	812	$	1,316	$	1,407
Weighted average common shares outstanding		322		340		326		344
Effect of dilutive securities		2		1		2		2
Weighted average common shares, including dilutive effect		324		341		328		346
Diluted earnings per share	$	1.83	$	2.38	$	4.01	$	4.07

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8. Equity

On February 1, 2012, we announced that our board of directors authorized a share repurchase plan, enabling us to purchase up to $2.0 billion of MPC common stock over a two-year period. Through January 30, 2013, we had acquired $1.35 billion of shares under the initial $2.0 billion authorization. On January 30, 2013, we announced that our board of directors approved an additional $2.0 billion share repurchase authorization. The board also extended the remaining $650 million share repurchase authorization, for a total outstanding authorization of $2.65 billion through December 2014. After the effects of the accelerated share repurchase (“ASR”) programs and open market repurchases shown below, $1.34 billion of the amount authorized by our board of directors was available for repurchases at June 30, 2013. We may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, accelerated share repurchases or open market solicitations for shares, some of which may be effected through Rule 10b5-1 plans. The timing and amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.

In February 2012 and November 2012, we entered into $850 million and $500 million ASR programs, respectively, to repurchase shares of MPC common stock under the approved share repurchase plan authorized by our board of directors. The total number of shares repurchased under these ASR programs was based generally on the volume-weighted average price of our common stock during the repurchase periods. The shares repurchased under the ASR programs were accounted for as treasury stock purchase transactions, reducing the weighted average number of basic and diluted common shares outstanding by the shares repurchased, and as forward contracts indexed to our common stock. The forward contracts were accounted for as equity instruments.

Total share repurchases transacted through ASR programs and open market transactions were as follows for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions, except per share data)	2013		2012		2013		2012
Number of shares repurchased(a)		11		—		17		18
Cash paid for shares repurchased	$	882	$	—	$	1,313	$	850
Effective average cost per delivered share	$	80.31	$	—	$	80.54	$	41.75

^(a)  The six months ended June 30, 2013 includes one million shares received under the November 2012 ASR program, which were paid for in 2012.

As of June 30, 2013, the total number of shares we have repurchased cumulatively through the ASR programs and open market repurchases since February 2012 was 45 million shares at an average cost per share of $59.55. The cash paid for shares repurchased was $2.66 billion. In addition, at June 30, 2013, we had agreements to acquire additional common shares for $36 million, which were settled in early July 2013.

9. 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 dealers and jobbers who operate Marathon^® retail outlets;

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

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

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

Segment income represents income from operations attributable to the reportable segments. Corporate administrative expenses 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 June 30, 2013
Revenues:
Customer	$	21,888		$	3,768		$	19		$	25,675
Intersegment(a)		2,434			1			119			2,554
Related parties		2			—			—			2
Segment revenues		24,324			3,769			138			28,231
Elimination of intersegment revenues		(2,434	)		(1	)		(119	)		(2,554	)
Total revenues	$	21,890		$	3,768		$	19		$	25,677
Segment income from operations(b)	$	903		$	123		$	58		$	1,084
Income from equity method investments		3			—			4			7
Depreciation and amortization(c)		252			27			18			297
Capital expenditures and investments(d)(e)		134			76			41			251
(In millions)	Refining & Marketing			Speedway			Pipeline Transportation			Total
Three Months Ended June 30, 2012
Revenues:
Customer	$	16,589		$	3,632		$	21		$	20,242
Intersegment(a)		2,214			1			87			2,302
Related parties		2			—			1			3
Segment revenues		18,805			3,633			109			22,547
Elimination of intersegment revenues		(2,214	)		(1	)		(87	)		(2,302	)
Total revenues	$	16,591		$	3,632		$	22		$	20,245
Segment income from operations	$	1,325		$	107		$	50		$	1,482
Income (loss) from equity method investments		(1	)		—			10			9
Depreciation and amortization(c)		191			28			12			231
Capital expenditures and investments(d)(e)		178			187			60			425

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(In millions)	Refining & Marketing			Speedway			Pipeline Transportation			Total
Six Months Ended June 30, 2013
Revenues:
Customer	$	41,760		$	7,209		$	40		$	49,009
Intersegment(a)		4,633			2			223			4,858
Related parties		4			—			—			4
Segment revenues		46,397			7,211			263			53,871
Elimination of intersegment revenues		(4,633	)		(2	)		(223	)		(4,858	)
Total revenues	$	41,764		$	7,209		$	40		$	49,013
Segment income from operations(b)	$	2,008		$	190		$	109		$	2,307
Income (loss) from equity method investments		(1	)		—			8			7
Depreciation and amortization(c)		488			54			36			578
Capital expenditures and investments(d)(e)(f)		1,554			112			131			1,797

(In millions)	Refining & Marketing			Speedway			Pipeline Transportation			Total
Six Months Ended June 30, 2012
Revenues:
Customer	$	33,552		$	6,916		$	38		$	40,506
Intersegment(a)		4,173			2			169			4,344
Related parties		3			—			1			4
Segment revenues		37,728			6,918			208			44,854
Elimination of intersegment revenues		(4,173	)		(2	)		(169	)		(4,344	)
Total revenues	$	33,555		$	6,916		$	39		$	40,510
Segment income from operations	$	2,268		$	157		$	92		$	2,517
Income (loss) from equity method investments		(1	)		—			12			11
Depreciation and amortization(c)		376			55			24			455
Capital expenditures and investments(d)(e)		331			198			98			627

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

^(b)  Included in the Pipeline Transportation segment for the three and six months ended June 30, 2013 are $5 million and $10 million of corporate overhead costs attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. These expenses are not currently allocated to other segments.

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

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

^(e)  Includes Speedway’s acquisitions of convenience stores. See Note 5.

^(f)  The Refining & Marketing and Pipeline Transportation segments include $1.30 billion and $70 million, respectively, for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2013			2012			2013			2012
Segment income from operations	$	1,084		$	1,482		$	2,307		$	2,517
Items not allocated to segments:
Corporate and other unallocated items(a)(b)		(64	)		(92	)		(131	)		(171	)
Pension settlement expenses		(60	)		(83	)		(60	)		(83	)
Net interest and other financial income (costs)		(45	)		(17	)		(93	)		(39	)
Income before income taxes	$	915		$	1,290		$	2,023		$	2,224

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

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(In millions)	2013		2012		2013		2012
Segment capital expenditures and investments	$	251	$	425	$	1,797	$	627
Less: Investments in equity method investees		6		—		11		7
Plus: Items not allocated to segments:
Capital expenditures not allocated to segments		28		20		52		28
Capitalized interest		4		36		8		66
Total capital expenditures(a)(b)	$	277	$	481	$	1,846	$	714

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

^(b)  See Note 18 for a reconciliation of total capital expenditures to additions to property, plant and equipment as reported in the consolidated statements of cash flows.

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2013		2012			2013			2012
Total revenues (as reported above)	$	25,677	$	20,245		$	49,013		$	40,510
Plus: Corporate and other unallocated items		—		(2	)		(6	)		(2	)
Less: Sales to related parties		2		3			4			4
Sales and other operating revenues (including consumer excise taxes)	$	25,675	$	20,240		$	49,003		$	40,504

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Total assets by reportable segment were:

(In millions)	June 30, 2013		December 31, 2012
Refining & Marketing	$	19,784	$	17,052
Speedway		2,019		1,947
Pipeline Transportation		1,943		1,950
Corporate and Other		5,949		6,274
Total consolidated assets	$	29,695	$	27,223

10. Other Items

Net interest and other financial income (costs) was:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2013			2012			2013			2012
Interest:
Net interest expense	$	(46	)	$	(46	)	$	(92	)	$	(91	)
Interest capitalized		4			36			8			66
Total net interest		(42	)		(10	)		(84	)		(25	)
Other:
Bank service and other fees		(3	)		(7	)		(9	)		(14	)
Net interest and other financial income (costs)	$	(45	)	$	(17	)	$	(93	)	$	(39	)

11. Income Taxes

The combined federal, state and foreign income tax rate was 35 percent and 37 percent for the three months ended June 30, 2013 and 2012, respectively, and 34 percent and 37 percent for the six months ended June 30, 2013 and 2012, respectively. The effective tax rate for the three and six months ended June 30, 2013 is equivalent to or slightly less than the U.S. statutory rate of 35 percent primarily due to certain permanent benefit differences, partially offset by state and local tax expense. The effective tax rate for the three and six months ended June 30, 2012 exceeded the U.S. statutory rate of 35 percent due to state and local tax expense, partially offset by permanent benefit differences.

Prior to the June 30, 2011 spinoff transaction from Marathon Oil Corporation (“Marathon Oil”), we were included in Marathon Oil’s income tax returns for all applicable years. During 2011, we anticipated a future settlement between Marathon Oil and us upon the filing of Marathon Oil’s consolidated U.S. federal and state income tax returns for the period prior to June 30, 2011. During the three months ended June 30, 2013, we settled with Marathon Oil for the 2011 period, resulting in a $39 million increase to additional paid in capital.

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 $22 million of unrecognized tax benefits as of June 30, 2013. Pursuant to our tax sharing agreement with 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 22 for indemnification information. During the three months ended June 30, 2013, we settled with Marathon Oil our U.S. federal and related state return liabilities for the 2008-2009 tax years, resulting in a reduction in unrecognized tax benefits of $21 million.

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12. Inventories

	June 30,		December 31,
(In millions)	2013		2012
Crude oil and refinery feedstocks	$	1,958	$	1,383
Refined products		2,471		1,761
Merchandise		80		74
Supplies and sundry items		321		231
Total (at cost)	$	4,830	$	3,449

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 six months ended June 30, 2013 and 2012.

13. Property, Plant and Equipment

	June 30,		December 31,
(In millions)	2013		2012
Refining & Marketing	$	16,536	$	15,089
Speedway		2,183		2,100
Pipeline Transportation		1,862		1,747
Corporate and Other		525		473
Total		21,106		19,409
Less accumulated depreciation		7,307		6,766
Net property, plant and equipment	$	13,799	$	12,643

14. Goodwill

The changes in the carrying amount of goodwill for the six months ended June 30, 2013 were as follows:

(In millions)	Refining & Marketing		Speedway		Pipeline Transportation		Total
Balance as of December 31, 2012	$	551	$	217	$	162	$	930
Acquisitions(a)		—		8		—		8
Balance as of June 30, 2013	$	551	$	225	$	162	$	938

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

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15. Fair Value Measurements

Fair Values—Recurring

The following tables present assets and liabilities accounted for at fair value on a recurring basis as of June 30, 2013 and December 31, 2012 by fair value hierarchy level. We have elected to offset the fair value amounts recognized for multiple derivative contracts executed with the same counterparty, including any related cash collateral as shown below; however, fair value amounts by hierarchy level are presented on a gross basis in the tables below.

	June 30, 2013
	Fair Value Hierarchy						Netting			Net Carrying		Collateral
(In millions)	Level 1		Level 2		Level 3		and Collateral(a)			Value on Balance Sheet(b)		Pledged Not Offset
Commodity derivative instruments, assets	$	58	$	—	$	—	$	(30	)	$	28	$	71
Other assets		2		—		—		N/A			2		—
Total assets at fair value	$	60	$	—	$	—	$	(30	)	$	30	$	71
Commodity derivative instruments, liabilities	$	30	$	—	$	—	$	(30	)	$	—	$	—
Contingent consideration, liability(c)		—		—		611		N/A			611		—
Total liabilities at fair value	$	30	$	—	$	611	$	(30	)	$	611	$	—

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

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

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

^(c)  Includes $190 million that is classified as current.

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

The contingent consideration represents the fair value as of June 30, 2013 of the amount we expect to pay to BP related to the earnout provision for the Galveston Bay Refinery and Related Assets acquisition. See Note 5. The fair value of the contingent consideration was estimated using an income approach and is therefore a Level 3 liability. The amount of cash to be paid under the arrangement is based on both a market-based crack spread and refinery throughput volumes for the months during which the contract applies, as well as established thresholds that cap the annual and total payment. The earnout payment cannot exceed $200 million per year for the first three years of the arrangement or $250 million per year for the last three years of the arrangement, with the total cumulative payment capped at $700 million over the six-year period. Any excess or shortfall from the annual cap for a current year’s earnout calculation will not affect subsequent years’ calculations. The fair value calculation included significant unobservable inputs, including (1) an estimate of refinery throughput volumes; (2) a range of internal and external crack spread forecasts from $14 to $18 per barrel; and (3) a range of risk-adjusted discount rates from 5 percent to 10 percent. An increase or decrease in crack spread forecasts or refinery throughput volume expectations will result in a corresponding increase or decrease in the fair value. Increases to the fair value as a result of increasing forecasts for both of these unobservable inputs, however, are limited as the earnout payment is subject to annual thresholds. An increase or decrease in the discount rate will result in a decrease or increase to the fair value, respectively. The fair value of the contingent consideration is reassessed each quarter, with changes in fair value recorded in cost of revenues.

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
(In millions)	2013		2012			2013		2012
Beginning balance	$	600	$	—		$	—	$	—
Contingent consideration agreement		—		—			600		—
Total realized and unrealized losses included in net income		11		2			11		2
Settlements of derivative instruments		—		(2	)		—		(2	)
Ending balance	$	611	$	—		$	611	$	—

There were no unrealized gains or losses recorded in net income for the three and six months ended June 30, 2013 and 2012 related to Level 3 derivative instruments held at June 30, 2013 and 2012, respectively. See Note 16 for the income statement impacts of our derivative instruments.

Fair Values – Nonrecurring

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

	Six Months Ended June 30,
	2013				2012
(In millions)	Fair Value		Impairment		Fair Value		Impairment
Property, plant and equipment, net	$	1	$	8	$	—	$	—
Other noncurrent assets		—		—		—		14

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

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

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Fair Values – Reported

The following table summarizes financial instruments on the basis of their nature, characteristics and risk at June 30, 2013 and December 31, 2012, excluding the derivative financial instruments and contingent consideration reported above.

	June 30, 2013				December 31, 2012
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Financial assets:
Investments	$	255	$	61	$	263	$	59
Other		30		29		33		31
Total financial assets	$	285	$	90	$	296	$	90
Financial liabilities:
Long-term debt(a)	$	3,322	$	3,004	$	3,559	$	3,006
Deferred credits and other liabilities		24		24		23		23
Total financial liabilities	$	3,346	$	3,028	$	3,582	$	3,029

^(a)  Excludes capital leases

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

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

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

16. Derivatives

For further information regarding the fair value measurement of derivative instruments, including any effect of master netting agreements or collateral, see Note 15. We do not designate any of our commodity derivative instruments as hedges for accounting purposes. Our interest rate derivative instruments were designated as fair value accounting hedges.

The following table presents the gross fair values of derivative instruments, excluding cash collateral, and where they appear on the consolidated balance sheets as of June 30, 2013 and December 31, 2012:

	June 30, 2013
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	58	$	30	Other current assets
	December 31, 2012
(In millions)	Asset		Liability		Balance Sheet Location
Commodity derivatives	$	49	$	88	Other current assets

Derivatives Designated as Fair Value Accounting Hedges

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

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Derivatives not Designated as Accounting Hedges

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

The table below summarizes open commodity derivative contracts as of June 30, 2013.

	Position		Total Barrels (In  thousands)
Crude oil(a)
Exchange-traded		Long		9,830
Exchange-traded		Short		(26,622	)
Refined Products(a)
Exchange-traded		Long		3,412
Exchange-traded		Short		(5,992	)

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

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

	Gain (Loss)				Gain (Loss)
	Three Months Ended				Six Months Ended
(In millions)	June 30,				June 30,
Income Statement Location	2013		2012		2013			2012
Sales and other operating revenues	$	3	$	44	$	4		$	38
Cost of revenues		51		356		(9	)		309
Total	$	54	$	400	$	(5	)	$	347

17. Debt

Our outstanding borrowings at June 30, 2013 and December 31, 2012 consisted of the following:

(In millions)	June 30, 2013			December 31, 2012
Marathon Petroleum Corporation:
Revolving credit agreement due 2017	$	—		$	—
3.500% senior notes due March 1, 2016		750			750
5.125% senior notes due March 1, 2021		1,000			1,000
6.500% senior notes due March 1, 2041		1,250			1,250
Consolidated subsidiaries:
Capital lease obligations due 2013-2028		406			355
MPLX Operations LLC revolving credit agreement due 2017		—			—
Trade receivables securitization facility due 2014		—			—
Total		3,406			3,355
Unamortized discount		(10	)		(10	)
Fair value adjustments(a)		14			16
Amounts due within one year		(23	)		(19	)
Total long-term debt due after one year	$	3,387		$	3,342

^(a)  See Note 16 for information on interest rate swaps.

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There were no borrowings or letters of credit outstanding under the revolving credit agreements or the trade receivable securitization facility at June 30, 2013.

18. Supplemental Cash Flow Information

	Six Months Ended June 30,
(In millions)	2013		2012
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	86	$	16
Net income taxes paid to taxing authorities		719		384
Non-cash investing and financing activities:
Capital lease obligations increase	$	61	$	30
Acquisitions:
Contingent consideration(a)		600		—
Liability assumed to seller(a)		6		—
Intangible asset acquired		—		3
Liability assumed		—		2

^(a)  See Note 5.

The consolidated statements of cash flows exclude changes to the consolidated balance sheets that did not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures:

	Six Months Ended June 30,
(In millions)	2013		2012
Additions to property, plant and equipment	$	424	$	635
Acquisitions(a)		1,391		155
Increase (decrease) in capital accruals		31		(76	)
Total capital expenditures	$	1,846	$	714

^(a)  Includes $1.37 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, of $1.16 billion plus assumed liabilities of $210 million. The 2012 acquisitions exclude the inventory acquired and liability assumed. See Note 5.

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19. 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		158			3			—		2		163
Amounts reclassified from accumulated other comprehensive loss:
Amortization – prior service credit(a)		(22	)		(2	)		—		—		(24	)
– actuarial loss(a)		39			1			—		—		40
– settlement loss(a)		60			—			—		—		60
Tax benefit		(29	)		—			—		—		(29	)
Other comprehensive income		206			2			—		2		210
Balance as of June 30, 2013	$	(226	)	$	(34	)	$	4	$	2	$	(254	)

^(a)  These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 20.

20. Defined Benefit Pension and Other Postretirement Plans

The following summarizes the components of net periodic benefit costs:

	Three Months Ended June 30,
	Pension Benefits						Other Benefits
(In millions)	2013			2012			2013		2012
Components of net periodic benefit cost:
Service cost	$	23		$	15		$	6	$	5
Interest cost		18			28			6		6
Expected return on plan assets		(26	)		(25	)		—		—
Amortization – prior service cost (credit)		(11	)		2			—		—
– actuarial loss		18			22			—		—
– net settlement/curtailment loss		60			83			—		—
Net periodic benefit cost	$	82		$	125		$	12	$	11

	Six Months Ended June 30,
	Pension Benefits						Other Benefits
(In millions)	2013			2012			2013			2012
Components of net periodic benefit cost:
Service cost	$	46		$	32		$	12		$	10
Interest cost		36			55			13			13
Expected return on plan assets		(53	)		(51	)		—			—
Amortization – prior service cost (credit)		(22	)		4			(2	)		—
– actuarial loss		39			46			1			—
– net settlement/curtailment loss		60			83			—			—
Net periodic benefit cost	$	106		$	169		$	24		$	23

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During the six months ended June 30, 2013, we made contributions of $158 million to our funded pension plans. We may make additional contributions to our pension plans in 2013 depending upon the anticipated funding status and plan asset performance. Current benefit payments related to unfunded pension and other postretirement benefit plans were $4 million and $10 million, respectively, during the six months ended June 30, 2013.

Due to the Galveston Bay Refinery and Related Assets acquisition, during the first quarter of 2013, we remeasured certain pension and retiree medical plans resulting in a $122 million decrease in liabilities. The decrease in liabilities was due to a 0.2 percent increase in discount rates and an increase in pension plan asset value from December 31, 2012 to the remeasurement date. The net periodic benefit costs for the six months ended June 30, 2013 reflect these remeasurements. The purchase accounting for the Galveston Bay Refinery and Related Assets acquisition includes a $43 million liability related to retiree medical assumed at the acquisition date. See Note 5.

During the three months ended June 30, 2013 and 2012, we determined that lump sum payments to employees retiring in the respective year would 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 June 30, 2013 and 2012, we recorded pension settlement expenses related to our cumulative lump sum payments made during the first six months of 2013 and 2012, respectively.

On May 17, 2012, we communicated to our employees changes in the defined benefit pension plans for Speedway and the legacy portion of the Marathon Petroleum Retirement Plan effective January 1, 2013. Final average pensionable earnings used to calculate pension benefits under these plans were fixed as of December 31, 2012. In addition, cap protection was added to limit potential annual lump sum distribution discount rate increases. These plan amendments resulted in an overall decrease in pension liabilities of approximately $537 million, with the offset primarily to other comprehensive income, which was recorded in the three months ended June 30, 2012. The benefit of this liability reduction is being amortized into income through 2024.

21. Stock-Based Compensation Plans

Stock Option Awards

The following table presents a summary of our stock option award activity for the six months ended June 30, 2013:

	Number of  Shares(a)			Weighted Average Exercise Price
Outstanding at December 31, 2012		6,172,194		$	36.17
Granted		408,603			84.65
Exercised		(948,149	)		35.42
Forfeited, canceled or expired		(43,508	)		37.61
Outstanding at June 30, 2013		5,589,140			39.83

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

The grant date fair value of stock option awards granted during the six months ended June 30, 2013 was $27.13 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 six months ended June 30, 2013 to reflect a weighting of 33 percent of MPC’s common stock implied volatility and 67 percent of the historical volatility for a selected group of peer companies.

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Restricted Stock Awards

The following table presents a summary of restricted stock award activity for the six months ended June 30, 2013:

	Shares of Restricted Stock (“RS”)					Restricted Stock Units (“RSU”)
	Number of Shares			Weighted Average Grant Date Fair Value		Number of Units			Weighted Average Grant Date Fair Value
Outstanding at December 31, 2012		638,073		$	40.83		359,111		$	31.07
Granted		249,158			87.78		11,568			78.00
RS’s Vested/RSU’s Issued		(196,628	)		37.21		(252	)		43.44
Forfeited		(12,833	)		55.25		—			—
Outstanding at June 30, 2013		677,770			58.87		370,427			32.52

Performance Unit Awards

The following table presents a summary of the activity for performance unit awards to be settled in shares for the six months ended June 30, 2013:

	Number of Units
Outstanding at December 31, 2012		2,040,000
Granted		1,782,500
Settled		—
Canceled		—
Outstanding at June 30, 2013		3,822,500

The performance unit awards granted in 2013 have a grant date fair value of $1.12 per unit, as calculated using a Monte Carlo valuation model.

MPLX Awards

During the six months ended June 30, 2013, 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.

22. 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 June 30, 2013 and December 31, 2012, accrued liabilities for remediation totaled $132 million and $123 million, respectively. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties if any that may be imposed. Receivables for recoverable costs from certain states, under programs to assist companies in clean-up efforts related to underground storage tanks at presently or formerly owned or operated retail marketing sites, were $49 million and $51 million at June 30, 2013 and December 31, 2012, respectively.

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We are involved in a number of environmental enforcement matters arising in the ordinary course of business. While the outcome and impact on us cannot be predicted with certainty, management believes the resolution of these environmental matters will not, individually or collectively, have a material adverse effect on our consolidated results of operations, financial position or cash flows.

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

We are a defendant in a number of other lawsuits and other proceedings arising in the ordinary course of business. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that the resolution of these other lawsuits and proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Guarantees—We have provided certain guarantees, direct and indirect, of the indebtedness of other companies. Under the terms of most of these guarantee arrangements, we would be required to perform should the guaranteed party fail to fulfill its obligations under the specified arrangements. In addition to these financial guarantees, we also have various performance guarantees related to specific agreements.

Guarantees related to indebtedness of equity method investees—We hold interests in an offshore oil port, LOOP, and a crude oil pipeline system, LOCAP LLC. Both LOOP and LOCAP LLC have secured various project financings with throughput and deficiency agreements. Under the agreements, we are required to advance funds if the investees are unable to service their debt. Any such advances are considered prepayments of future transportation charges. The duration of the agreements vary but tend to follow the terms of the underlying debt. Our maximum potential undiscounted payments under these agreements for the debt principal totaled $172 million as of June 30, 2013.

We hold an interest in a refined products pipeline through our investment in Centennial, and have guaranteed the payment of Centennial’s principal, interest and prepayment costs, if applicable, under a Master Shelf Agreement, which is scheduled to expire in 2024. The guarantee arose in order for Centennial to obtain adequate financing. Our maximum potential undiscounted payments under this agreement for debt principal totaled $44 million as of June 30, 2013.

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 June 30, 2013.

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 $9 million as of June 30, 2013, 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 11, 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.

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Other guarantees—We have entered into other guarantees with maximum potential undiscounted payments totaling $122 million as of June 30, 2013, which primarily consist of a commitment to contribute cash to an equity method investee for certain catastrophic events, up to $50 million per event, in lieu of procuring insurance coverage, an indemnity to the co-lenders associated with an equity method investee’s credit agreement, and leases of assets containing general lease indemnities and guaranteed residual values.

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

Contractual commitments—At June 30, 2013, our contractual commitments to acquire property, plant and equipment and advance funds to equity method investees totaled $870 million, which includes $700 million of contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5 for additional information on the contingent consideration.

23. Subsequent Event

On August 1, 2013, we acquired from Mitsui & Co. (U.S.A.), Inc. its interests in three ethanol companies for $75 million in cash. Under the agreement, we acquired an additional 24 percent interest in 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 TAME, bringing our direct and indirect ownership interest in TAME to 67 percent; and a 40 percent interest in The Andersons Albion Ethanol LLC, which owns an ethanol production facility in Albion, Michigan. We expect to hold a noncontrolling interest in each of these entities and account for them using the equity method of accounting.

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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, 2012.

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” or “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, 2012.

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 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, to buyers on the spot market, to our Speedway business segment and to dealers and jobbers who operate Marathon^® retail outlets;

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

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

Executive Summary

Net income attributable to MPC was $593 million and $1.32 billion, or $1.83 and $4.01 per diluted share, for the second quarter and first six months of 2013 compared to $814 million and $1.41 billion, or $2.38 and $4.07 per diluted share, for the second quarter and first six months of 2012. The decreases were primarily due to our Refining & Marketing segment, which generated income from operations of $903 million and $2.01 billion in the second quarter and first six months of 2013 compared to $1.33 billion and $2.27 billion in the second quarter and first six months of 2012.

The decreases in Refining & Marketing segment income from operations were primarily due to lower refining and marketing gross margins, which were $6.18 per barrel and $6.99 per barrel in the second quarter and first six months of 2013 compared to $11.13 per barrel and $9.76 per barrel in the second quarter and first six months of 2012. These impacts were partially offset by increases in refined product sales volumes related to the Galveston Bay refinery acquired in February 2013.

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Speedway segment income from operations increased $16 million and $33 million in the second quarter and first six months of 2013 compared to the second quarter and first six months of 2012, primarily due to increases in our gasoline and distillate gross margin and our merchandise gross margin, partially offset by higher expenses attributable to an increase in the number of convenience stores.

Pipeline Transportation segment income from operations increased $8 million and $17 million in the second quarter and first six months of 2013 compared to the second quarter and first six months of 2012. The increases primarily reflect higher transportation tariffs, partially offset by higher operating, including mechanical integrity, and depreciation expenses.

On February 1, 2013, we paid $1.49 billion to acquire from BP the 451,000 barrel per calendar day refinery in Texas City, Texas, three intrastate natural gas liquid pipelines originating at the refinery, an allocation of BP’s Colonial Pipeline Company shipper history, four light product terminals, branded-jobber marketing contract assignments for the supply of approximately 1,200 branded sites and a 1,040 megawatt electric cogeneration facility, as well as the inventory associated with these assets. We refer to these assets as the “Galveston Bay Refinery and Related Assets”. Pursuant to the purchase and sale agreement, we may also be required to pay BP a contingent earnout of up to an additional $700 million over six years, subject to certain conditions. These assets are part of our Refining & Marketing and Pipeline Transportation segments. Information for periods prior to the acquisition does not include amounts for these operations. See Note 5 to the unaudited consolidated financial statements for additional information on this acquisition.

On January 30, 2013, we announced that our board of directors approved an additional $2.0 billion share repurchase authorization. The board also extended the remaining $650 million share repurchase authorization announced on February 1, 2012, for a total outstanding authorization of $2.65 billion through December 2014. During the six months ended June 30, 2013, we paid $1.31 billion to repurchase our common shares, and received 17 million common shares through open market share repurchases and the final shares received under our November 2012 ASR program. The effective average cost was $80.54 per delivered share. At June 30, 2013, we also had agreements to repurchase additional common shares for $36 million, which were settled in early July 2013.

Overview of Segments

Refining & Marketing

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

Our refining and marketing gross margin is the difference between the prices of refined products sold and the costs of crude oil and other charge and blendstocks refined, including the costs to transport these inputs to our refineries, the costs of purchased products and refinery direct operating costs, including turnaround and major maintenance, depreciation and amortization and other manufacturing expenses. 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 sulfur residual fuel) are used for these crack-spread calculations.

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

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Historically, West Texas Intermediate crude oil (“WTI”) has traded at prices similar to LLS. During the first six months of 2012 and in early 2013, WTI traded at prices significantly less than LLS, which favorably impacted our refining and 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 in the second quarter of 2013 due to a variety of domestic and international market conditions along with changes in logistical infrastructure. Future crude oil differentials will be dependent on a variety of market and economic factors.

The following table provides sensitivities showing the 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)	$	425
Sweet/sour differential sensitivity(b) (per $1.00/barrel change)		225
LLS-WTI spread sensitivity(c) (per $1.00/barrel change)		75
Natural gas price sensitivity(per $1.00/million British thermal unit change)		140

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

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

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

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

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

• the selling prices realized for refined products;

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

• the cost of products purchased for resale; and

• changes in 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 Catlettsburg, Kentucky; Garyville, Louisiana; and Galveston Bay refineries during the first six months of 2013 compared to activities at our Garyville and Robinson, Illinois refineries during the first six months of 2012.

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. Approximately two-thirds of Speedway’s gross margin was derived from merchandise sales in the second quarter and first six months of 2013.

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Pipeline Transportation

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

Results of Operations

Consolidated Results of Operations

	Three Months Ended									Six Months Ended
	June 30,									June 30,
(In millions)	2013			2012			Variance			2013			2012			Variance
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$	25,675		$	20,240		$	5,435		$	49,003		$	40,504		$	8,499
Sales to related parties		2			3			(1	)		4			4			—
Income from equity method investments		7			9			(2	)		7			11			(4	)
Net gain on disposal of assets		1			1			—			2			3			(1	)
Other income		18			4			14			32			10			22
Total revenues and other income		25,703			20,257			5,446			49,048			40,532			8,516
Costs and expenses:
Cost of revenues (excludes items below)		22,320			16,800			5,520			42,354			34,121			8,233
Purchases from related parties		79			57			22			151			120			31
Consumer excise taxes		1,596			1,428			168			3,054			2,808			246
Depreciation and amortization		302			236			66			589			466			123
Selling, general and administrative expenses		358			365			(7	)		607			616			(9	)
Other taxes		88			64			24			177			138			39
Total costs and expenses		24,743			18,950			5,793			46,932			38,269			8,663
Income from operations		960			1,307			(347	)		2,116			2,263			(147	)
Net interest and other financial income (costs)		(45	)		(17	)		(28	)		(93	)		(39	)		(54	)
Income before income taxes		915			1,290			(375	)		2,023			2,224			(201	)
Provision for income taxes		316			476			(160	)		694			814			(120	)
Net income		599			814			(215	)		1,329			1,410			(81	)
Less net income attributable to noncontrolling interests		6			—			6			11			—			11
Net income attributable to MPC	$	593		$	814		$	(221	)	$	1,318		$	1,410		$	(92	)

Net income attributable to MPC decreased $221 million in the second quarter and $92 million in the first six months of 2013 compared to the second quarter and first six months of 2012, primarily due to decreases in refining and marketing gross margins, which were $6.18 per barrel and $6.99 per barrel in the second quarter and first six months of 2013 compared to $11.13 per barrel and $9.76 per barrel in the second quarter and first six months of 2012. These impacts were partially offset by increases in refined product sales volumes related to the Galveston Bay refinery acquired in February 2013.

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Sales and other operating revenues (including consumer excise taxes) increased $5.44 billion in the second quarter and $8.50 billion in the first six months of 2013 compared to the second quarter and first six months of 2012, primarily due to higher refined product sales volumes, which increased to 2,135 thousand barrels per day (“mbpd”) and 2,016 mbpd in the second quarter and first six months of 2013 from 1,591 mbpd and 1,574 mbpd in the second quarter and first six months of 2012, primarily due to the Galveston Bay refinery acquired in February 2013. This impact was partially offset by decreases in refined product selling prices.

Other income increased $14 million in the second quarter and $22 million in the first six months of 2013 compared to the second quarter and first six months of 2012, primarily due to increases in sales of Renewable Identification Numbers (“RINs”) and dividends received from pipeline affiliates.

Cost of revenues increased $5.52 billion in the second quarter and $8.23 billion in the first six months of 2013 compared to the second quarter and first six months of 2012. The increases were primarily due to increases in purchased crude oil volumes in the Refining & Marketing segment. Crude oil volumes increased 40 percent in the second quarter and 32 percent in the first six months of 2013 compared to the second quarter and first six months of 2012, primarily associated with the Galveston Bay refinery acquired in February 2013.

Purchases from related parties increased $22 million in the second quarter and $31 million in the first six months of 2013 compared to the second quarter and first six months of 2012, primarily due to higher acquisition costs of ethanol from our ethanol investments due to increases in ethanol volumes purchased and higher ethanol prices, partially offset by a decrease in purchases from Centennial in the first six months of 2013.

Centennial experienced a significant reduction in shipment volumes in the second half of 2011 that continued through the first six months of 2013. At June 30, 2013, Centennial was not shipping product. As a result, we continued to evaluate the carrying value of our equity investment in Centennial and concluded that no impairment was required given our assessment of its fair value based on various uses of Centennial’s assets.

Consumer excise taxes increased $168 million in the second quarter and $246 million in the first six months of 2013 compared to the same periods of 2012, primarily due to the increase in refined product sales volumes related to the Galveston Bay refinery acquired in February 2013.

Depreciation and amortization increased $66 million in the second quarter and $123 million in the first six months of 2013 compared to the second quarter and first six months of 2012, primarily due to the completion of the heavy oil upgrading and expansion project at our Detroit, Michigan refinery and our acquisition of the Galveston Bay Refinery and Related Assets.

Other taxes increased $24 million in the second quarter and $39 million in the first six months of 2013 compared to the second quarter and first six months of 2012, primarily due to increases in personal property taxes and payroll taxes. These increases were attributable to a number of factors including the completion of the heavy oil upgrading and expansion project at our Detroit refinery, the acquisition of the Galveston Bay Refinery and Related Assets and Speedway’s acquisition of 97 convenience stores in 2012.

Net interest and other financial costs increased $28 million in the second quarter and $54 million in the first six months of 2013 compared to the second quarter and first six months of 2012, primarily reflecting a decrease in capitalized interest due to the completion of the Detroit refinery heavy oil upgrading and expansion project in late 2012. We capitalized interest of $4 million in the second quarter and $8 million in the first six months of 2013 compared to $36 million in the second quarter and $66 million in the first six months of 2012.

Provision for income taxes decreased $160 million in the second quarter and $120 million in the first six months of 2013 compared to the second quarter and first six months of 2012, primarily due to the $375 million and $201 million decreases in income before income taxes and decreases in the effective tax rates, which were 35 percent and 34 percent in the second quarter and first six months of 2013 compared to 37 percent in the same periods of 2012. The effective tax rates in the second quarter and first six months of 2013 is equivalent to or slightly less than the U.S. statutory rate of 35 percent primarily due to certain permanent benefit differences, partially offset by state and local tax expense. See Note 11 to the unaudited consolidated financial statements for further details.

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Segment Results

Revenues are summarized by segment in the following table.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2013			2012			2013			2012
Refining & Marketing	$	24,324		$	18,805		$	46,397		$	37,728
Speedway		3,769			3,633			7,211			6,918
Pipeline Transportation		138			109			263			208
Segment revenues		28,231			22,547			53,871			44,854
Elimination of intersegment revenues		(2,554	)		(2,302	)		(4,858	)		(4,344	)
Total revenues	$	25,677		$	20,245		$	49,013		$	40,510
Items included in both revenues and costs:
Consumer excise taxes	$	1,596		$	1,428		$	3,054		$	2,808

Refining & Marketing segment revenues increased $5.52 billion in the second quarter and $8.67 billion in the first six months of 2013 compared to the second quarter and first six months of 2012, primarily due to increases in refined product sales volumes related to the Galveston Bay refinery acquired in February 2013, partially offset by lower refined product selling prices. The table below shows our Refining & Marketing segment refined product sales volumes and prices.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Refining & Marketing segment:
Refined product sales volumes (thousands of barrels per day)(a)		2,125		1,571		2,004		1,551
Average refined product sales prices (dollars per gallon)	$	2.89	$	3.01	$	2.93	$	3.04

^(a) Includes intersegment sales

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

	Three Months Ended				Six Months Ended
	June 30,				June 30,
(Dollars per gallon)	2013		2012		2013		2012
Chicago spot unleaded regular gasoline	$	2.95	$	2.89	$	2.87	$	2.88
Chicago spot ultra-low sulfur diesel		3.03		2.89		3.05		2.93
USGC spot unleaded regular gasoline		2.69		2.79		2.76		2.88
USGC spot ultra-low sulfur diesel		2.86		2.94		2.97		3.05

Refining & Marketing intersegment sales to our Speedway segment were $2.43 billion in the second quarter and $4.63 billion in the first six months of 2013 compared to $2.21 billion in the second quarter and $4.17 billion in the first six months of 2012. Intersegment refined product sales volumes were 745 million gallons in the second quarter and 1.43 billion gallons in the first six months of 2013 compared to 678 million gallons in the second quarter and 1.29 billion gallons in the first six months of 2012, with the increased volumes primarily due to Speedway’s acquisitions of convenience stores in 2013 and 2012.

Speedway segment revenues increased $136 million in the second quarter and $293 million in the first six months of 2013 compared to the second quarter and first six months of 2012, primarily due to increases in gasoline and distillate sales volumes of 25 million gallons and 64 million gallons, respectively. Gasoline and distillate selling prices averaged $3.63 per gallon and $3.57 per gallon in

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the second quarter and first six months of 2013 compared to $3.62 per gallon and $3.57 per gallon in the second quarter and first six months of 2012. The Speedway segment also had higher merchandise sales in the second quarter and first six months of 2013. The increases in gasoline and distillate sales volumes and merchandise sales were primarily due to the acquisitions of convenience stores in 2013 and 2012.

Pipeline Transportation segment revenue increased $29 million in the second quarter and $55 million in the first six months of 2013 compared to the second quarter and first six months of 2012, primarily due to higher transportation tariffs from our crude oil pipelines, resulting from higher crude oil volumes transported and increased tariff rates in the last half of 2012. Crude oil pipeline throughput volumes increased 141 mbpd in the second quarter and 146 mbpd for the six months of 2013 compared to the corresponding 2012 periods.

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

	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2013			2012			2013			2012
Income from operations by segment:
Refining & Marketing	$	903		$	1,325		$	2,008		$	2,268
Speedway		123			107			190			157
Pipeline Transportation (a)		58			50			109			92
Items not allocated to segments:
Corporate and other unallocated items(a)(b)		(64	)		(92	)		(131	)		(171	)
Pension settlement expenses		(60	)		(83	)		(60	)		(83	)
Income from operations		960			1,307			2,116			2,263
Net interest and other financial income (costs)		(45	)		(17	)		(93	)		(39	)
Income before income taxes	$	915		$	1,290		$	2,023		$	2,224

^(a)  Corporate overhead costs attributable to MPLX are included in the Pipeline Transportation segment subsequent to MPLX’s October 31, 2012 initial public offering.

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

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 June 30,				Six Months Ended June 30,
(Dollars per barrel)	2013		2012		2013		2012
Chicago LLS 6-3-2-1(a)(b)	$	14.62	$	9.11	$	9.48	$	4.76
USGC LLS 6-3-2-1(a)		6.93		7.76		5.93		6.51
Blended 6-3-2-1(a)(c)		9.85		8.46		7.28		5.60
LLS		104.82		108.22		109.20		113.89
WTI		94.17		93.35		94.26		98.15
LLS—WTI differential (a)		10.65		14.87		14.94		15.74
Sweet/Sour differential(a)(d)		6.28		10.50		9.11		12.09

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

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

^(c)  Blended Chicago/USGC crack spread is 38%/62% in 2013 and 52%/48% in 2012 based on MPC’s refining capacity by region in each period.

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

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Refining & Marketing segment income from operations decreased $422 million in the second quarter and $260 million in the first six months of 2013 compared to the second quarter and first six months of 2012, primarily due to lower refining and marketing gross margins, which averaged $6.18 per barrel and $6.99 per barrel in the second quarter and first six months of 2013 compared to $11.13 per barrel and $9.76 per barrel in the second quarter and first six months of 2012.

Our realized Refining & Marketing gross margin for the second quarter and first six months of 2013 benefited from increases in the Chicago and USGC LLS 6-3-2-1 blended crack spread of $1.39 per barrel and $1.68 per barrel, respectively. However, we experienced lower product price realizations compared to the spot market product prices used in the LLS crack spread calculation. We believe the product price realizations were impacted by volatility in the Chicago market and compliance with the Renewable Fuel Standard (“RFS2”). In addition, our average crude oil acquisition discount narrowed compared to LLS in 2013. These impacts were partially offset by increases in refined product sales volumes related to the Galveston Bay refinery acquired in February 2013.

The following table summarizes our refinery throughputs.

	Three Months Ended June 30,				Six Months Ended June 30,
(thousands of barrels per day)	2013		2012		2013		2012
Refinery Throughputs:
Crude oil refined		1,690		1,208		1,562		1,177
Other charge and blendstocks		174		131		206		153
Total		1,864		1,339		1,768		1,330

The increases in crude oil throughput and other charge and blendstocks throughput in the second quarter and first six months of 2013 compared to the same periods of 2012 were primarily due to the Galveston Bay refinery acquired in February 2013.

Within our refining system, sour crude accounted for 52 percent and 53 percent of our crude oil processed in the second quarter and first six months of 2013 compared to 54 percent and 50 percent in the same periods of 2012.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Refining & Marketing gross margin(dollars per barrel)(a)	$	6.18	$	11.13	$	6.99	$	9.76
Refinery direct operating costs in Refining & Marketing gross margin(dollars per barrel):(b)
Turnaround and major maintenance	$	0.73	$	0.88	$	0.93	$	0.96
Depreciation and amortization		1.28		1.39		1.35		1.39
Other manufacturing(c)		4.06		3.05		3.94		3.11
Total	$	6.07	$	5.32	$	6.22	$	5.46
Refined product sales volumes(thousands of barrels per day)(d)		2,125		1,571		2,004		1,551

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

^(b)  Per barrel of total refinery throughputs.

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

^(d)  Includes intersegment sales.

Refinery direct operating costs in the Refining & Marketing gross margin increased $0.75 per barrel and $0.76 per barrel of total refinery throughputs in the second quarter and first six months of 2013 compared to the same periods of 2012, which includes increases in other manufacturing costs of $1.01 per barrel and $0.83 per barrel, respectively. The increases were primarily attributable to the addition of the Galveston Bay refinery, which had higher operating costs per barrel of throughput than the average of our other six refineries due to its greater level of complexity.

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We purchase RINs to satisfy a portion of our RFS compliance. Our cost of purchasing RINs increased to $65 million and $107 million in the second quarter and first six months of 2013 from $34 million and $66 million in the same periods of 2012, primarily due to higher ethanol RIN prices.

Speedway segment income from operations increased $16 million in the second quarter and $33 million in the first six months of 2013 compared to the second quarter and first six months of 2012, primarily due to increases in our gasoline and distillate gross margin and our merchandise gross margin, partially offset by higher expenses attributable to an increase in the number of convenience stores. The increases in our gasoline and distillate gross margin were primarily due to $0.0099 and $0.0148 increases in our gross margin per gallon along with higher sales volumes related to the increase in the number of convenience stores. The increases in the merchandise gross margin were primarily due to higher merchandise sales resulting from an increase in the number of convenience stores.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2013			2012			2013			2012
Convenience stores at period-end		1,468			1,455
Gasoline & distillate sales (millions of gallons)		781			756			1,526			1,462
Gasoline & distillate gross margin (dollars per gallon)(a)	$	0.1738		$	0.1639		$	0.1525		$	0.1377
Merchandise sales (in millions)	$	806		$	776		$	1,517		$	1,471
Merchandise gross margin (in millions)	$	212		$	203		$	396		$	382
Same store gasoline sales volume (period over period)		0.0	%		2.1	%		0.3	%		0.5	%
Same store merchandise sales excluding cigarettes (period over period)		4.5	%		10.1	%		2.8	%		10.3	%

^(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 $8 million in the second quarter and $17 million in the first six months of 2013 compared to the second quarter and first six months of 2012. The increases primarily reflect higher transportation tariffs, partially offset by higher operating, including mechanical integrity, and depreciation expenses.

Corporate and other unallocated expenses decreased $28 million in the second quarter and $40 million in the first six months of 2013 compared to the second quarter and first six months of 2012. The decreases were primarily due to a reduction in net employee benefit expenses, including lower pension expenses resulting from a pension plan amendment adopted in May 2012.

During the second quarter of 2013, we recorded pretax pension settlement expenses of $60 million resulting from the level of employee lump sum retirement distributions occurring during the first six months of 2013, compared to $83 million during the second quarter of 2012.

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Liquidity and Capital Resources

Cash Flows

Our cash and cash equivalents balance was $3.07 billion at June 30, 2013 compared to $4.86 billion at December 31, 2012. Net cash provided by (used in) operating activities, investing activities and financing activities for the first six months of 2013 and 2012 are presented in the following table.

	Six Months Ended June 30,
(In millions)	2013			2012
Net cash provided by (used in):
Operating activities	$	1,643		$	616
Investing activities		(1,918	)		(798	)
Financing activities		(1,516	)		(1,002	)
Total	$	(1,791	)	$	(1,184	)

Net cash provided by operating activities increased $1.03 billion in the first six months of 2013 compared to the first six months of 2012, primarily due to favorable changes in working capital. Changes in working capital were a net $262 million use of cash in the first six months of 2013 compared to a net $1.86 billion use of cash in the first six months of 2012. The $262 million use of cash in the first six months of 2013 was primarily due to increases in current receivables and crude oil and refined product inventory volumes, partially offset by an increase in accounts payable and accrued liabilities. Current receivables increased $1.55 billion from year-end 2012, primarily due to higher refined product receivable volumes attributable to an increase in refined product sales volumes. Changes in inventories were a $455 million use of cash in the first six months of 2013, primarily due to increases in crude oil and refined product inventory volumes. Accounts payable increased $1.82 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 second quarter of 2013 compared to year-end 2012. The $1.86 billion use of cash in the first six months of 2012 was primarily due to a decrease in accounts payable and accrued liabilities resulting primarily from decreases in crude oil payable volumes and prices, and an increase in inventories resulting primarily from increases in crude oil and refined product inventory volumes. Partially offsetting these uses of cash was a decrease in accounts receivable primarily caused by lower crude oil receivable volumes and prices.

Net cash used in investing activities totaled $1.92 billion in the first six months of 2013, compared to $798 million in the first six months of 2012. The higher use of cash in the first six months of 2013 was primarily due to the Galveston Bay Refinery and Related Assets acquisition in February 2013, partially offset by lower capital expenditures in 2013 due to the completion of the Detroit refinery heavy oil upgrading and expansion project in late 2012.

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.

	Six Months Ended June 30,
(In millions)	2013		2012
Additions to property, plant and equipment	$	424	$	635
Acquisitions(a)		1,391		155
Increase (decrease) in capital accruals		31		(76	)
Total capital expenditures		1,846		714
Investments in equity method investees		11		7
Total capital expenditures and investments	$	1,857	$	721

^(a) Includes $1.37 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory and other current assets, of $1.16 billion plus assumed liabilities of $210 million. The 2012 acquisitions exclude the inventory acquired and liability assumed. See Note 5 to the unaudited consolidated financial statements.

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Capital expenditures and investments are summarized by segment below.

	Six Months Ended June 30,
(In millions)	2013		2012
Refining & Marketing(a)	$	1,554	$	331
Speedway(b)		112		198
Pipeline Transportation(c)		131		98
Corporate and Other(d)		60		94
Total	$	1,857	$	721

^(a)  Includes $1.30 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5 to the unaudited consolidated financial statements.

^(b)  Includes acquisitions of 9 convenience stores in 2013 and 87 convenience stores in 2012.

^(c)  Includes $70 million in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5 to the unaudited consolidated financial statements.

^(d)  Includes capitalized interest of $8 million and $66 million for the six months ended June 30, 2013 and 2012, respectively.

The acquisition of the Galveston Bay Refinery and Related Assets comprised 74 percent of our total capital spending in the first six months of 2013. The Detroit refinery heavy oil upgrading and expansion project, which we completed in 2012, comprised 60 percent (excluding capitalized interest associated with this project) of our Refining & Marketing segment capital spending in the first six months of 2012.

Net cash used in financing activities totaled $1.52 billion in the first six months of 2013 and $1.00 billion in the first six months of 2012. The uses of cash for both periods were primarily for common stock repurchases under our share repurchase plans and dividend payments.

Cash used in common stock repurchases under the share repurchase plans authorized by our board of directors increased $463 million in the first six months of 2013 compared to the first six months of 2012. During the first six months of 2013, we paid $1.31 billion to repurchase 16 million common shares through open market repurchases compared to $850 million paid to repurchase 18 million shares under an ASR program during the six months of 2012. See Note 8 to the unaudited consolidated financial statements for further discussion of the share repurchase plans.

Cash used in dividend payments increased $57 million in the first six months of 2013 compared to the first six months of 2012, primarily due to a 10 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 totaled 70 cents per common share in the first six months of 2013 compared to 50 cents per common share in the first six months of 2012.

Derivative Instruments

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

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Capital Resources

As of June 30, 2013, we had no borrowings or letters of credit outstanding under our revolving credit agreements or our trade receivables securitization facility and our liquidity totaled $6.57 billion consisting of:

	June 30,
(In millions)	2013
Cash and cash equivalents	$	3,069
Revolving credit agreement(a)		2,500
Trade receivables securitization facility		1,000
Total	$	6,569

^(a) Excludes MPLX’s $500 million revolving credit agreement, which was also undrawn.

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 MPLX’s revolving credit agreement (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 June 30, 2013, we were in compliance with this debt covenant with a ratio of Consolidated Net Debt to Total Capitalization of 0.10 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 June 30, 2013, MPLX was in compliance with this debt covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of 0.1 to 1.0, as well as the other covenants contained in the MPLX Credit Agreement.

Our intention is to maintain an investment grade credit profile. As of June 30, 2013, the credit ratings on our senior unsecured debt were at or above investment grade level as follows.

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

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

Neither the 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 a letter of credit under an existing transportation services agreement.

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Debt-to-Total-Capital Ratio

Our debt-to-total capital ratio (total debt to total debt-plus-equity) was 22 percent at June 30, 2013 and December 31, 2012.

	June 30,			December 31,
(In millions)	2013			2012
Long-term debt due within one year	$	23		$	19
Long-term debt		3,387			3,342
Total debt	$	3,410		$	3,361
Calculation of debt-to-total-capital ratio:
Total debt	$	3,410		$	3,361
Total equity		12,197			12,105
Total capital	$	15,607		$	15,466
Debt-to-total-capital ratio		22	%		22	%

Capital Requirements

We have a capital and investment budget for 2013 of $1.62 billion, excluding capitalized interest and the purchase price for the Galveston Bay Refinery and Related Assets. The budget includes spending on refining, retail marketing, transportation, logistics and brand marketing projects as well as amounts designated for corporate activities. There have been no material changes to our 2013 capital and investment budget since our Annual Report on Form 10-K for the year ended December 31, 2012 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. See Note 5 to the unaudited consolidated financial statements.

During the six months ended June 30, 2013, we made contributions of $158 million to our funded pension plans. We may make additional contributions to our funded pension plans in 2013 depending on the anticipated funding status and plan asset performance.

On July 31, 2013, our board of directors approved a 42 cents per share dividend, payable September 10, 2013 to stockholders of record at the close of business on August 21, 2013.

On January 30, 2013, we announced that our board of directors approved an additional $2.0 billion share repurchase authorization. The board also extended the remaining $650 million share repurchase authorization for a total outstanding authorization of $2.65 billion through December 2014. During the first six months of 2013, the final shares from the $500 million ASR program were delivered to us and we paid $1.31 billion to acquire 16 million common shares through open market share repurchases. During the second quarter of 2013, we also entered into agreements to acquire additional common shares for $36 million, which were settled in early July 2013. At June 30, 2013, the initial $2.0 billion repurchase authorization announced on February 1, 2012 and extended on January 30, 2013 had been exhausted. As of June 30, 2013, we had a total outstanding repurchase authorization pursuant to the additional $2.0 billion repurchase authorization announced on January 30, 2013 of approximately $1.34 billion through December 2014.

We may utilize various methods to effect additional repurchases, which could include open market purchases, negotiated block transactions, ASRs or open market solicitations for shares, some of which may be effected through Rule 10b5-1 plans. The timing and amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time.

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

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Contractual Cash Obligations

The following table provides aggregated information on our consolidated obligations to make future payments under existing contracts as of June 30, 2013.

(In millions)	Total		2013		2014-2015		2016-2017		Later Years
Long-term debt(a)	$	5,794	$	84	$	332	$	1,039	$	4,339
Capital lease obligations		539		23		93		90		333
Operating lease obligations		665		94		306		154		111
Purchase obligations:(b)
Crude oil, feedstock, refined product and renewable fuel contracts(c)		16,139		13,327		1,790		764		258
Transportation and related contracts		1,886		114		372		388		1,012
Contracts to acquire property, plant and equipment(d)(e)		870		154		416		300		—
Service, materials and other contracts(f)		1,541		282		490		281		488
Total purchase obligations		20,436		13,877		3,068		1,733		1,758
Other long-term liabilities reported in the consolidated balance sheet(g)		905		43		283		144		435
Total contractual cash obligations	$	28,339	$	14,121	$	4,082	$	3,160	$	6,976

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

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

^(c)  These contracts include variable price arrangements with estimated prices to be paid primarily based on current market conditions. We are in the process of implementing systems that will allow us to estimate prices based on futures curves, which as of June 30, 2013, has been implemented for contracts with purchase obligations of $1.17 billion.

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

^(e)  Includes $700 million of contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5 to the unaudited consolidated financial statements.

^(f)  Primarily includes contracts to purchase services such as utilities, supplies and various other maintenance and operating services.

^(g)  Primarily includes obligations for pension and other postretirement benefits including medical and life insurance, which we have estimated through 2022. See Note 20 to the unaudited consolidated financial statements.

Off-Balance Sheet Arrangements

Off-balance sheet arrangements comprise those arrangements that may potentially impact our liquidity, capital resources and results of operations, even though such arrangements are not recorded as liabilities under accounting principles generally accepted in the United States. Although off-balance sheet arrangements serve a variety of our business purposes, we are not dependent on these arrangements to maintain our liquidity and capital resources, and we are not aware of any circumstances that are reasonably likely to cause the off-balance sheet arrangements to have a material adverse effect on liquidity and capital resources.

We have provided various guarantees related to equity method investees. In conjunction with our spinoff from Marathon Oil, we entered into various indemnities and guarantees to Marathon Oil. These arrangements are described in Note 22 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

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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 January 25, 2013, the U.S. Court of Appeals for the D.C. circuit vacated the 2012 cellulosic biofuel requirements under the RFS2 program. In light of this ruling, the Environmental Protection Agency (“EPA”) is reconsidering and is anticipated to lower the 2011 and has subsequently eliminated the 2012 cellulosic biofuel requirements under the RFS2 program. The EPA also has proposed a rule establishing a quality assurance program for RINs purchased to help meet the annual biofuel requirements under the RFS2 program. This rule should be finalized later this year and is aimed at reducing the chances that RINs are fraudulently created or sold.

On March 29, 2013, the EPA announced its proposed Tier 3 fuel standards. The proposed Tier 3 fuel standards require, among other things, a lower annual average sulfur level in gasoline to no more than 10 parts per million beginning in calendar year 2017. MPC and its trade organizations have submitted public comments on the standards and the agency is expected to finalize the Tier 3 fuel standards later this year. Our cost of compliance may be material; however, we will likely not be able to reasonably estimate our compliance costs until we have had time to review the final standards and develop our compliance plans.

There have been no other significant changes to our environmental matters and compliance costs during the six months ended June 30, 2013.

Critical Accounting Estimates

The preparation of financial statements in accordance with US GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used. The following critical accounting estimates have been updated since our Annual Report on Form 10-K for the year ended December 31, 2012 was filed.

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Fair Value Estimates

Acquisitions

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

The fair value of assets and liabilities as of the acquisition date are often estimated using a combination of approaches, including the income approach, which requires us to project related future cash inflows and outflows and apply an appropriate discount rate; the cost approach, which requires estimates of replacement costs and depreciation and obsolescence estimates; and the market approach which uses market data and adjusts for entity specific differences. The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine fair value. See Note 5 to the unaudited consolidated financial statements for additional information on our acquisitions.

Derivatives

We record all derivative instruments at fair value. All of our commodity derivatives are cleared through exchanges which provide active trading information for identical derivatives and do not require any assumptions in arriving at fair value.

Accounting Standards Not Yet Adopted

As of June 30, 2013, there are no accounting standards that have not yet been adopted.

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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, 2012.

See Notes 15 and 16 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 June 30, 2013 is provided in the following table.

	Incremental Change in IFO from a Hypothetical Price Increase of						Incremental Change in IFO from a Hypothetical Price Decrease of
(In millions)	10%			25%			10%		25%
As of June 30, 2013
Crude	$	(162	)	$	(402	)	$	175	$	434
Refined products		(25	)		(58	)		28		69

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 June 30, 2013 would cause future IFO effects to differ from those presented above.

Sensitivity analysis of the projected incremental effect of a hypothetical 100-basis-point shift in interest rates on financial assets and liabilities as of June 30, 2013 is provided in the following table.

(In millions)	Fair Value			Incremental Change in Fair Value
Financial assets (liabilities)(a)
Long-term debt(b)	$	(3,322	) (c)	$	(311	) (d)

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

^(b)  Excludes capital leases.

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

^(d)  Assumes a 100-basis-point decrease in the weighted average yield-to-maturity at June 30, 2013.

At June 30, 2013, our portfolio of long-term debt was substantially comprised of fixed-rate instruments. Therefore, the fair value of the portfolio is relatively sensitive to interest rate fluctuations. Our sensitivity to interest rate declines and corresponding increases in the fair value of our debt portfolio unfavorably affects our results of operations and cash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices above carrying value.

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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 inRules 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 June 30, 2013, 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 June 30, 2013, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Supplementary Statistics (Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(In millions)	2013			2012			2013			2012
Income from Operations by segment
Refining & Marketing	$	903		$	1,325		$	2,008		$	2,268
Speedway		123			107			190			157
Pipeline Transportation(a)		58			50			109			92
Items not allocated to segments:
Corporate and other unallocated items(a)		(64	)		(92	)		(131	)		(171	)
Pension settlement expenses		(60	)		(83	)		(60	)		(83	)
Income from operations	$	960		$	1,307		$	2,116		$	2,263
Capital Expenditures and Investments(b)(c)
Refining & Marketing	$	134		$	178		$	1,554		$	331
Speedway(d)		76			187			112			198
Pipeline Transportation		41			60			131			98
Corporate and Other(e)		32			56			60			94
Total	$	283		$	481		$	1,857		$	721

^(a)  Included in the Pipeline Transportation segment for the three and six months ended June 30, 2013 are $5 million and $10 million, respectively, of corporate overhead costs attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. These expenses are not currently allocated to other segments.

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

^(c)  The six months ended June 30, 2013 includes $1.37 billion for the acquisition of the Galveston Bay Refinery and Related Assets, comprised of total consideration, excluding inventory, of $1.16 billion plus assumed liabilities of $210 million. The total consideration amount of $1.16 billion includes the base purchase price and a fair-value estimate of $600 million for the contingent consideration. See Note 5 to the unaudited consolidated financial statements.

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

^(e)  Includes capitalized interest of $4 million and $36 million for the three months ended June 30, 2013 and 2012, respectively, and $8 million and $66 million for the six months ended June 30, 2013 and 2012, respectively.

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Supplementary Statistics (Unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)(a)(b)		2,135			1,591			2,016			1,574
Refining & Marketing Operating Statistics(b)
Refinery Throughputs (thousands of barrels per day):
Crude oil refined		1,690			1,208			1,562			1,177
Other charge and blendstocks		174			131			206			153
Total		1,864			1,339			1,768			1,330
Crude Oil Capacity Utilization percent(c)		99			101			96			99
Refined Product Yields (thousands of barrels per day):
Gasoline		923			724			906			720
Distillates		609			422			566			409
Propane		40			26			36			26
Feedstocks and special products		240			102			212			116
Heavy fuel oil		31			18			31			17
Asphalt		54			71			50			62
Total		1,897			1,363			1,801			1,350
Refining & Marketing Refined Product Sales Volume (thousands of barrels per day)(d)		2,125			1,571			2,004			1,551
Refining & Marketing Gross Margin (dollars per barrel)(e)	$	6.18		$	11.13		$	6.99		$	9.76
Refinery Direct Operating Costs in Refining & Marketing Gross Margin (dollars per barrel):(f)
Turnaround and major maintenance	$	0.73		$	0.88		$	0.93		$	0.96
Depreciation and amortization		1.28			1.39			1.35			1.39
Other manufacturing(g)		4.06			3.05			3.94			3.11
Total	$	6.07		$	5.32		$	6.22		$	5.46
Speedway Operating Statistics
Convenience stores at period-end		1,468			1,455
Gasoline & distillate sales (millions of gallons)		781			756			1,526			1,462
Gasoline & distillate gross margin (dollars per gallon)(h)	$	0.1738		$	0.1639		$	0.1525		$	0.1377
Merchandise sales (in millions)	$	806		$	776		$	1,517		$	1,471
Merchandise gross margin (in millions)	$	212		$	203		$	396		$	382
Same store gasoline sales volume (period over period)		0.0	%		2.1	%		0.3	%		0.5	%
Same store merchandise sales excluding cigarettes (period over period)		4.5	%		10.1	%		2.8	%		10.3	%
Pipeline Transportation Operating Statistics
Pipeline throughput (thousands of barrels per day)(i):
Crude oil pipelines		1,334			1,193			1,303			1,157
Refined products pipelines		959			954			939			935
Total		2,293			2,147			2,242			2,092

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

^(d)  Includes intersegment sales.

^(e)  Sales revenue less cost of refinery inputs, purchased products and refinery direct operating costs (including turnaround and major maintenance, depreciation and amortization and other manufacturing expenses), divided by Refining & Marketing segment refined product sales volume.

^(f)  Per barrel of total refinery throughputs.

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

^(h)  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.

⁽ⁱ⁾  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, 2012.

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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 June 30, 2013, of equity securities that are registered by MPC pursuant to Section 12 of the Securities Exchange Act of 1934, as amended.

Period	Total Number of Shares Purchased(a)		Average Price Paid  per Share(b)		Total Number of Shares Purchased as Part of Publicly Announced  Plans or Programs(c)		Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs(d)
04/01/13—04/30/13		3,025,137	$	82.53		2,989,711	$	1,972,288,753
05/01/13—05/31/13		4,010,328	$	79.35		4,010,328		1,654,082,629
06/01/13—06/30/13		3,980,358	$	79.68		3,975,425		1,337,340,389
Total		11,015,823	$	80.34		10,975,464

^(a)  The amounts in this column include 35,426 and 4,933 shares of our common stock delivered by employees to MPC, upon vesting of restricted stock, to satisfy tax withholding requirements in April and June, respectively.

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

^(c)  On February 1, 2012, we announced that our board of directors authorized a share repurchase plan, enabling us to purchase up to $2.0 billion of our common stock over a two-year period to expire on January 31, 2014. Through January 30, 2013, the total value of share repurchases completed pursuant to this initial repurchase authorization was $1.35 billion. On January 30, 2013, we announced that our board of directors extended the duration of the existing $650 million repurchase authorization and approved an additional $2.0 billion share repurchase authorization, both to expire on December 31, 2014, for a total of $2.65 billion in outstanding share repurchase authorization through December 2014.

^(d)  As of June 30, 2013, the initial $2.0 billion repurchase authorization announced on February 1, 2012 and extended on January 30, 2013, had been exhausted. As of June 30, 2013, we had a total outstanding repurchase authorization pursuant to the additional $2.0 billion repurchase authorization announced on January 30, 2013, of approximately $1.34 billion through December 2014.

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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
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

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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.

August 8, 2013	MARATHON PETROLEUM CORPORATION
	By:	/s/ Michael G. Braddock
		Michael G. Braddock
		Vice President and Controller

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