Marathon Petroleum (MPC) 10-K 26 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2015	Feb. 12, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus (Q1,Q2,Q3,FY)	FY
Trading Symbol	MPC
Entity Registrant Name	Marathon Petroleum Corp
Entity Central Index Key	1,510,295
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		529,227,453
Entity Public Float			$ 28

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Revenues and other income:
Sales and other operating revenues (including consumer excise taxes)	$ 72,051	$ 97,817	$ 100,160
Income from equity method investments	88	153	36
Net gain on disposal of assets	7	21	6
Other income	112	111	52
Total revenues and other income	72,258	98,102	100,254
Costs and expenses:
Cost of revenues (excludes items below)	55,583	83,770	87,401
Purchases from related parties	308	505	357
Inventory market valuation charge	370	0	0
Consumer excise taxes	7,692	6,685	6,263
Depreciation and amortization	1,646	1,326	1,220
Selling, general and administrative expenses	1,576	1,375	1,248
Other taxes	391	390	340
Total costs and expenses	67,566	94,051	96,829
Income from operations	4,692	4,051	3,425
Net interest and other financial income (costs)	(318)	(216)	(179)
Income before income taxes	4,374	3,835	3,246
Provision for income taxes	1,506	1,280	1,113
Net income	2,868	2,555	2,133
Less net income attributable to noncontrolling interests	16	31	21
Net income attributable to MPC	$ 2,852	$ 2,524	$ 2,112
Basic:
Net income attributable to MPC per share	$ 5.29	$ 4.42	$ 3.34
Weighted average shares outstanding (in shares)	538	570	630
Diluted:
Net income attributable to MPC per share	$ 5.26	$ 4.39	$ 3.32
Weighted average shares outstanding (in shares)	542	574	634
Dividends paid (in USD per share)	$ 1.14	$ 0.92	$ 0.77

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Net income	$ 2,868	$ 2,555	$ 2,133
Defined benefit postretirement and post-employment plans:
Actuarial changes, net of tax of $21, ($47) and $174	34	(78)	294
Prior service costs, net of tax of ($24), ($19) and ($19)	(39)	(31)	(34)
Other comprehensive income (loss)	(5)	(109)	260
Comprehensive income	2,863	2,446	2,393
Less comprehensive income attributable to noncontrolling interests	16	31	21
Comprehensive income attributable to MPC	$ 2,847	$ 2,415	$ 2,372

Consolidated Statements of Com4

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement of Comprehensive Income [Abstract]
Actuarial changes, tax	$ 21	$ (47)	$ 174
Prior service costs, tax	$ (24)	$ (19)	$ (19)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 1,127	$ 1,494
Receivables, less allowance for doubtful accounts of $12 and $13	2,927	4,058
Inventories	5,225	5,642
Other current assets	192	145
Total current assets	9,471	11,339
Equity method investments	3,622	865
Property, plant and equipment, net	25,164	16,261
Goodwill	4,019	1,566
Other noncurrent assets	839	394
Total assets	43,115	30,425
Current liabilities:
Accounts payable	4,743	6,661
Payroll and benefits payable	503	427
Consumer excise taxes payable	460	463
Accrued taxes	184	647
Long-term debt due within one year	29	27
Other current liabilities	426	354
Total current liabilities	6,345	8,579
Long-term debt	11,896	6,575
Deferred income taxes	3,285	2,014
Defined benefit postretirement plan obligations	1,179	1,099
Deferred credits and other liabilities	735	768
Total liabilities	$ 23,440	$ 19,035
Commitments and contingencies (see Note 25)
MPC stockholders’ equity:
Preferred stock, no shares issued and outstanding (par value $0.01 per share, 30 million shares authorized)	$ 0	$ 0
Common stock:
Issued – 729 million and 726 million shares (par value $0.01 per share, 1 billion shares authorized)	7	7
Held in treasury, at cost – 198 million and 179 million shares	(7,275)	(6,299)
Additional paid-in capital	11,071	9,841
Retained earnings	9,752	7,515
Accumulated other comprehensive loss	(318)	(313)
Total MPC stockholders’ equity	13,237	10,751
Noncontrolling interests	6,438	639
Total equity	19,675	11,390
Total liabilities and equity	$ 43,115	$ 30,425

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Allowance for doubtful accounts	$ 12	$ 13
Preferred stock:
Shares issued	0	0
Shares outstanding	0	0
Par value	$ 0.01
Shares authorized	30,000,000
Common stock:
Shares issued	729,000,000	726,000,000
Par value	$ 0.01
Shares authorized	1,000,000,000
Treasury stock	(198,000,000)	(179,000,000)

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating activities:
Net income	$ 2,868	$ 2,555	$ 2,133
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	1,646	1,326	1,220
Inventory market valuation charge	370	0	0
Pension and other postretirement benefits, net	80	151	(124)
Deferred income taxes	134	(242)	23
Net gain on disposal of assets	7	21	6
Equity method investments, net	25	17	(18)
Changes in the fair value of derivative instruments	4	(3)	(21)
Changes in:
Current receivables	1,292	1,642	(940)
Inventories	80	(786)	(305)
Current accounts payable and accrued liabilities	(2,400)	(1,547)	1,464
All other, net	(31)	18	(21)
Net cash provided by operating activities	4,061	3,110	3,405
Investing activities:
Additions to property, plant and equipment	(1,998)	(1,480)	(1,206)
Acquisitions, net of cash acquired	(1,218)	(2,821)	(1,515)
Disposal of assets	21	27	16
Investments – acquisitions, loans and contributions	(331)	(413)	(151)
Investments—redemptions, repayments and return of capital	4	9	77
All other, net	81	135	23
Net cash used in investing activities	(3,441)	(4,543)	(2,756)
Financing activities:
Long-term debt – borrowings	2,993	3,793	0
Long-term debt – repayments	(2,226)	(548)	(21)
Debt issuance costs	(21)	(22)	(4)
Issuance of common stock	33	26	48
Common stock repurchased	(965)	(2,131)	(2,793)
Dividends paid	(613)	(524)	(484)
Net proceeds from issuance of MPLX LP common units	0	221	0
Distributions to noncontrolling interests	(40)	(27)	(21)
Tax settlement with Marathon Oil Corporation	0	0	39
Contingent consideration payment	(175)	(172)	0
All other, net	27	19	19
Net cash provided by (used in) financing activities	(987)	635	(3,217)
Net decrease in cash and cash equivalents	(367)	(798)	(2,568)
Cash and cash equivalents at beginning of period	1,494	2,292	4,860
Cash and cash equivalents at end of period	$ 1,127	$ 1,494	$ 2,292

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) $ in Millions	Total	Common Stock	Treasury Stock	Additional Paid-in Capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Non- controlling Interests	Common Stock Units [Member]	Common Stock Units [Member]Additional Paid-in Capital	Common Stock Units [Member]Non- controlling Interests	Common Class B Units	Common Class B UnitsAdditional Paid-in Capital	Common Class B UnitsNon- controlling Interests
Beginning balance at Dec. 31, 2012	$ 12,105	$ 7	$ (1,253)	$ 9,524	$ 3,880	$ (464)	$ 411
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	2,133				2,112		21
Dividends declared	(485)				(485)
Distributions to noncontrolling interests	(21)						(21)
Other comprehensive income (loss)	260					260
Shares repurchased	(2,793)		(2,893)	(100)
Shares returned - stock based compensation			(9)
Shares issued - stock based compensation				47
Shares issued (returned) – stock-based compensation	38
Stock-based compensation	56			55			1
Tax settlement with Marathon Oil Corporation	39			39
Ending balance at Dec. 31, 2013	11,332	7	(4,155)	9,765	5,507	(204)	412
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	2,555				2,524		31
Dividends declared	(525)				(525)
Distributions to noncontrolling interests	(27)						(27)
Other comprehensive income (loss)	(109)					(109)
Shares repurchased	(2,131)		(2,131)	0
Shares returned - stock based compensation			(13)
Shares issued - stock based compensation				26
Shares issued (returned) – stock-based compensation	13
Stock-based compensation	52			50			2
Issuance of MPLX LP common units	221						221
Other	9				9
Ending balance at Dec. 31, 2014	11,390	7	(6,299)	9,841	7,515	(313)	639
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	2,868				2,852		16
Dividends declared	(615)				(615)
Distributions to noncontrolling interests	(40)						(40)
Other comprehensive income (loss)	(5)					(5)
Shares repurchased	(965)		(965)	0
Shares returned - stock based compensation			(11)
Shares issued - stock based compensation				33
Shares issued (returned) – stock-based compensation	22
Stock-based compensation	85			69			16
Issuance of MPLX LP common units	1						1
Other	(1)						(1)
Issuance of MPLX LP units - MarkWest Merger								$ 7,060	$ 1,481	$ 5,579	$ 266	$ 51	$ 215
Tax effect of issuance of MPLX units - MarkWest Merger	(404)			(404)
Noncontrolling interest - MarkWest Merger	13						13
Ending balance at Dec. 31, 2015	$ 19,675	$ 7	$ (7,275)	$ 11,071	$ 9,752	$ (318)	$ 6,438

Consolidated Statements of Equ9

Consolidated Statements of Equity - Shares - shares shares in Millions	Total		Common Stock	Treasury Stock
Number of shares issued (beginning balance) at Dec. 31, 2012			722
Number of shares issued - stock-based compensation			2
Number of shares issued (ending balance) at Dec. 31, 2013			724
Number of shares held in treasury (beginning balance) at Dec. 31, 2012				(56)
Number of shares repurchased	(74)	[1]		(74)
Number of shares held in treasury (ending balance) at Dec. 31, 2013				(130)
Number of shares issued - stock-based compensation			2
Number of shares issued (ending balance) at Dec. 31, 2014	726		726
Number of shares repurchased	(49)			(49)
Number of shares held in treasury (ending balance) at Dec. 31, 2014	(179)			(179)
Number of shares issued - stock-based compensation			3
Number of shares issued (ending balance) at Dec. 31, 2015	729		729
Number of shares repurchased	(19)			(19)
Number of shares held in treasury (ending balance) at Dec. 31, 2015	(198)			(198)
[1]	Shares repurchased in 2013 includes 2 million shares received under the November 2012 accelerated share repurchase program, which were paid for in 2012.

Description Of The Business And

Description Of The Business And Basis Of Presentation	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Description of the Business and Basis of Presentation	Description of the Business and Basis of Presentation Description of the Business – Our business consists of refining and marketing, retail and midstream services conducted primarily in the Midwest, Gulf Coast, East Coast, Northeast and Southeast regions of the United States, through subsidiaries, including Marathon Petroleum Company LP, Speedway LLC and its subsidiaries (“Speedway”) and MPLX LP and its subsidiaries (“MPLX”). See Note 10 for additional information about our operations. Spinoff – On May 25, 2011, the Marathon Oil board of directors approved the spinoff of its Refining, Marketing & Transportation Business (“RM&T Business”) into an independent, publicly traded company, MPC, through the distribution of MPC common stock to the stockholders of Marathon Oil common stock (the “Spinoff”). MPC became an independent, publicly traded company on July 1, 2011. Basis of Presentation – Our results of operations and cash flows consist of consolidated MPC activities. All significant intercompany transactions and accounts have been eliminated. We completed a two-for-one stock split in June 2015. All historical share and per share data included in these consolidated financial statements has been retroactively restated on a post-split basis. Additionally, we adopted the updated FASB debt issuance cost standard as of June 30, 2015 and applied the changes retrospectively to the prior period presented. We also adopted the updated FASB deferred tax simplification standard in the fourth quarter of 2015. Since we have elected to apply this standard prospectively, the prior period has not been retrospectively adjusted.

Summary Of Principal Accounting

Summary Of Principal Accounting Policies	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Summary Of Principal Accounting Policies	Summary of Principal Accounting Policies Principles applied in consolidation – These consolidated financial statements include the accounts of our majority-owned, controlled subsidiaries and MPLX. Changes in ownership interest in consolidated subsidiaries that do not result in a change in control are recorded as an equity transaction. We own 20.4 percent of MPLX, including the two percent general partner interest. Due to our 100 percent ownership of the general partner interest, we have determined that we control MPLX and therefore we consolidate MPLX and record a noncontrolling interest for the 79.6 percent interest owned by the public. Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. This includes entities in which we hold majority ownership but the minority shareholders have substantive participating rights. Income from equity method investments represents our proportionate share of net income generated by the equity method investees. Equity method investments are generally carried at our share of net assets plus loans and advances. Such investments are assessed for impairment whenever changes in the facts and circumstances indicate an other than temporary loss in value has occurred. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net income. Differences in the basis of the investments and the separate net asset values of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets and liabilities, except for the excess related to goodwill. Use of estimates – The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Revenue recognition – Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. Costs associated with revenues are recorded in cost of revenues. Shipping and other transportation costs billed to our customers are presented on a gross basis in revenues and cost of revenues. Rebates from vendors are recognized as a reduction of cost of revenues when the initiating transaction occurs. Incentives that are derived from contractual provisions are accrued based on past experience and recognized in cost of revenues. Rebates to customers are reflected as a reduction of revenue and are accrued for in accounts payable on the consolidated balance sheets. Crude oil and refined product exchanges and matching buy/sell transactions – We enter into exchange contracts and matching buy/sell arrangements whereby we agree to deliver a particular quantity and quality of crude oil or refined products at a specified location and date to a particular counterparty and to receive from the same counterparty the same commodity at a specified location on the same or another specified date. The exchange receipts and deliveries are nonmonetary transactions, with the exception of associated grade or location differentials that are settled in cash. The matching buy/sell purchase and sale transactions are settled in cash. Both exchange and matching buy/sell transactions are accounted for as exchanges of inventory and no revenues are recorded. The exchange transactions are recognized at the carrying amount of the inventory transferred. Consumer excise taxes – We are required by various governmental authorities, including countries, states and municipalities, to collect and remit taxes on certain consumer products. Such taxes are presented on a gross basis in revenues and costs and expenses in the consolidated statements of income. Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less. Restricted cash – Restricted cash consists of cash and investments that must be maintained as collateral for letters of credit issued to certain third party producer customers. The balances will be outstanding until certain capital projects are completed and the third party releases the restriction. Restricted cash also consists of cash advances to be used for the operation and maintenance of an operated pipeline system. At December 31, 2015 and 2014 , the amount of restricted cash included in other current assets on the consolidated balance sheets were $9 million and $4 million , which is currently reflected in our Midstream segment. Accounts receivable and allowance for doubtful accounts – Our receivables primarily consist of customer accounts receivable. Customer receivables are recorded at the invoiced amounts and generally do not bear interest. Allowances for doubtful accounts are generally recorded when it becomes probable the receivable will not be collected and are booked to bad debt expense. The allowance for doubtful accounts is the best estimate of the amount of probable credit losses in customer accounts receivable and is based on historical write-off experience. We review the allowance quarterly and past-due balances over 180 days are reviewed individually for collectability. Approximately 26 percent and 41 percent of our accounts receivable balances at December 31, 2015 and 2014 , respectively, are related to sales of crude oil or refinery feedstocks to customers with whom we have master netting agreements. We have master netting agreements with more than 100 companies engaged in the crude oil or refinery feedstock trading and supply business or the petroleum refining industry. A master netting agreement generally provides for a once per month net cash settlement of the accounts receivable from and the accounts payable to a particular counterparty. Inventories – Inventories are carried at the lower of cost or market value. Cost of inventories is determined primarily under the LIFO method. Costs for crude oil, refinery feedstocks and refined product inventories are aggregated on a consolidated basis for purposes of assessing if the LIFO cost basis of these inventories may have to be written down to market value. Derivative instruments – We use derivatives to economically hedge a portion of our exposure to commodity price risk and, historically, to interest rate risk. We also have limited authority to use selective derivative instruments that assume market risk. All derivative instruments (including derivative instruments embedded in other contracts) are recorded at fair value. Commodity derivatives are reflected on the consolidated balance sheets on a net basis by counterparty as they are governed by master netting agreements. Cash flows related to derivatives used to hedge commodity price risk and interest rate risk are classified in operating activities with the underlying transactions. Fair value accounting hedges – We used interest rate swaps to hedge our exposure to interest rate risk associated with fixed interest rate debt in our portfolio. These interest rate swap agreements were terminated in 2012. Changes in the fair values of both the hedged item and the related derivative were recognized immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect was to report in net income the extent to which the accounting hedge was not effective in achieving offsetting changes in fair value. There was a gain on the termination of the agreements, which has been accounted for as an adjustment to our long-term debt balance. The gain was being amortized over the remaining life of the associated debt as a reduction of our interest expense, until the December 2015 extinguishment of our obligation for the associated debt. At such time, the remaining unamortized gain was credited to net interest and other financial income (costs). 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, (4) the acquisition of ethanol for blending with refined products, (5) the sale of NGLs, (6) the purchase of natural gas and (6) the purchase of electricity. Changes in the fair value of derivatives not designated as accounting hedges are recognized immediately in net income. Concentrations of credit risk – All of our financial instruments, including derivatives, involve elements of credit and market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The counterparties to our financial instruments consist primarily of major financial institutions and companies within the energy industry. To manage counterparty risk associated with financial instruments, we select and monitor counterparties based on an assessment of their financial strength and on credit ratings, if available. Additionally, we limit the level of exposure with any single counterparty. Property, plant and equipment – Property, plant and equipment are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which range from two to 42 years. Such assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. When items of property, plant and equipment are sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale. Interest expense is capitalized for qualifying assets under construction. Capitalized interest costs are included in property, plant and equipment and are depreciated over the useful life of the related asset. Goodwill and intangible assets – Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, the implied fair value of goodwill is calculated. The excess, if any, of the book value over the implied fair value of goodwill is charged to net income. Amortization of intangibles with definite lives is calculated using the straight-line method which is reflective of the benefit pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible asset. Intangibles not subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the intangible may not be recoverable. If the sum of the expected undiscounted future cash flows related to the asset is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. Major maintenance activities – Costs for planned turnaround, major maintenance and engineered project activities are expensed in the period incurred. These types of costs include contractor repair services, materials and supplies, equipment rentals and our labor costs. Environmental costs – Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. We recognize remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed and determinable. If recoveries of remediation costs from third parties are probable, a receivable is recorded and is discounted when the estimated amount is reasonably fixed and determinable. Asset retirement obligations – The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. The majority of our recognized asset retirement liability relates to conditional asset retirement obligations for removal and disposal of fire-retardant material from certain refining facilities. The remaining recognized asset retirement liability relates to other refining assets, the removal of underground storage tanks at our leased convenience stores, certain pipelines and processing facilities and other related pipeline assets. The fair values recorded for such obligations are based on the most probable current cost projections. The recorded asset retirement obligations are not material to the consolidated financial statements. Asset retirement obligations have not been recognized for some assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate. Such obligations will be recognized in the period when sufficient information becomes available to estimate a range of potential settlement dates. The asset retirement obligations principally include the hazardous material disposal and removal or dismantlement requirements associated with the closure of certain refining, terminal, retail, pipeline and processing assets. Our practice is to keep our assets in good operating condition through routine repair and maintenance of component parts in the ordinary course of business and by continuing to make improvements based on technological advances. As a result, we believe that generally these assets have no expected settlement date for purposes of estimating asset retirement obligations since the dates or ranges of dates upon which we would retire these assets cannot be reasonably estimated at this time. Income taxes – Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several factors, primarily our expectation to generate sufficient future taxable income. Stock-based compensation arrangements – The fair value of stock options granted to our employees is estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions, based on management’s estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the vesting period of the stock option award. Of the required assumptions, the expected life of the stock option award and the expected volatility of our stock price have the most significant impact on the fair value calculation. The average expected life is based on our historical employee exercise behavior. The assumption for expected volatility of our stock price reflects a weighting of 50 percent of our common stock implied volatility and 50 percent of MPC’s common stock historical volatility. The fair value of restricted stock awards granted to our employees is determined based on the fair market value of our common stock on the date of grant. The fair value of performance unit awards granted to our employees is estimated on the date of grant using a Monte Carlo valuation model. Our stock-based compensation expense is recognized based on management’s estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods. Unearned stock-based compensation is charged to equity when restricted stock awards are granted. Compensation expense is recognized over the vesting period and is adjusted if conditions of the restricted stock award are not met. Business combinations - We recognize and measure the assets acquired and liabilities assumed in a business combination based on their estimated fair values at the acquisition date, with any remaining difference recorded as goodwill or gain from a bargain purchase. For all material acquisitions, management engages an independent valuation specialist to assist with the determination of fair value of the assets acquired, liabilities assumed, noncontrolling interest, if any, and goodwill, based on recognized business valuation methodologies. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later than one year from the acquisition date, we will record any material adjustments to the initial estimate based on new information obtained about facts and circumstances that existed as of the acquisition date. An income, market or cost valuation method may be utilized to estimate the fair value of the assets acquired, liabilities assumed, and noncontrolling interest, if any, in a business combination. The income valuation method represents the present value of future cash flows over the life of the asset using: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the market, with adjustments relating to any differences between the assets. The cost valuation method is based on the replacement cost of a comparable asset at prices at the time of the acquisition reduced for depreciation of the asset. Acquisition-related costs are expensed as incurred in connection with each business combination. Renewable fuel identification numbers – We purchase RINs to satisfy a portion of our RFS2 compliance. We record a short-term intangible asset, included in other current assets on the balance sheet, for RINs owned in excess of our anticipated current period compliance requirements. The asset value is based on the product of the excess RINs as of the balance sheet date, if any, and the average cost of our RINs. We record a current liability, included in other current liabilities on the balance sheet, when we are deficient RINs based on the product of the deficient RINs as of the balance sheet date, if any, and the market price of the RINs at the balance sheet date. The cost of RINs used for compliance is reflected in cost of revenues. Any gains or losses on the sale or expiration of RINs are classified as other income. Proceeds from RIN sales are included in investing activities - all other, net on the cash flow statement.

Accounting Standards

Accounting Standards	12 Months Ended
	Dec. 31, 2015
Accounting Changes and Error Corrections [Abstract]
Accounting Standards	Accounting Standards Recently Adopted In November 2015, the FASB issued an accounting standards update to simplify the balance sheet classification of deferred taxes. The update requires that deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The update does not change the existing requirement that only permits offsetting within a jurisdiction. The change is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2016. The guidance may be applied either prospectively or retrospectively with early adoption permitted. Our early adoption of this standard in the fourth quarter of 2015 did not have a material impact on our consolidated results of operations, financial position or cash flows. We have elected to apply this standard prospectively, therefore, prior periods have not been retrospectively adjusted. In April 2015, the FASB issued an accounting standards update to simplify the presentation of debt issuance costs. The update requires that debt issue costs for term debt are to be presented on the balance sheet as a direct reduction of the term debt liability as opposed to a deferred charge within other noncurrent assets. The change is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2015. Retrospective application is required and early adoption is permitted. Our early adoption of this standard in the second quarter of 2015 did not have a material impact on our consolidated results of operations, financial position or cash flows. In August 2015, the FASB subsequently issued a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows for the presentation of these costs as an asset. This clarification did not have any impact on our consolidated results of operations, financial position or cash flows. In June 2014, the FASB issued an accounting standards update for the elimination of the concept of development stage entity (“DSE”) from U.S. GAAP and removes the related incremental reporting. The standards update eliminates the additional financial statement requirements specific to a DSE and was adopted in the first quarter of 2015. In addition, the portion of the standard to amend the consolidation model that eliminates the special provisions in the VIE rules for assessing the sufficiency of the equity of a DSE is effective in the first quarter of 2016. Adoption of this standards update in the first quarter of 2015 and 2016 has not and is not expected to have an impact on our consolidated results of operations, financial position or cash flows. In April 2014, the FASB issued an accounting standards update that redefines the criteria for determining discontinued operations and introduces new disclosures related to these disposals. The updated definition of a discontinued operation is the disposal of a component (or components) of an entity or the classification of a component (or components) of an entity as held for sale that represents a strategic shift for an entity and has (or will have) a major impact on an entity’s operations and financial results. The standard requires disclosure of additional financial information for discontinued operations and individually material components not qualifying for discontinued operation presentation, as well as information regarding an entity’s continuing involvement with the discontinued operation. The accounting standards update was effective prospectively for annual periods beginning on or after December 15, 2014, and interim periods within those years. Adoption of this standards update in the first quarter of 2015 did not impact our consolidated results of operations, financial position or cash flows. Not Yet Adopted In January 2016, the FASB issued an accounting standards update requiring unconsolidated equity investments, not accounted for under the equity method, to be measured at fair value with changes in fair value recognized in net income. The update also requires the use of the exit price notion when measuring the fair value of financial instruments for disclosure purposes and the separate presentation of financial assets and liabilities by measurement category and form on the balance sheet and accompanying notes. The update eliminates the requirement to disclose the methods and assumptions used in estimating the fair value of financial instruments measured at amortized cost. Lastly, the update requires separate presentation in other comprehensive income of the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when electing to measure the liability at fair value in accordance with the fair value option for financial instruments. The changes are effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. Upon adoption, entities will be required to make a cumulative-effect adjustment to the consolidated results of operations as of the beginning of the first reporting period the guidance is effective. Early adoption is permitted only for the amendment regarding presentation of liability’s credit risk. We are in the process of determining the impact of the new standard on the consolidated financial statements. In September 2015, the FASB issued an accounting standard update that eliminates the requirement to restate prior period financial statements for measurement period adjustments for business combinations. This update requires that the cumulative impact of a measurement period adjustment be recognized in the reporting period in which the adjustment is identified. The standard is effective for interim and annual periods beginning after December 15, 2015 with early application permitted. Adoption of this standard is not expected to have a material impact on our consolidated results of operations, financial position or cash flows. In May 2015, the FASB issued an accounting standard update that eliminates the requirement to categorize in the fair value hierarchy investments that are measured at net asset value using the practical expedient. The standard is effective for fiscal years beginning after December 15, 2015 and interim periods within the fiscal year. Retrospective application is required and early adoption is permitted. While we expect adoption of this standard to affect our fair value hierarchy disclosures, we do not believe it will have an impact on our consolidated results of operations, financial position or cash flows. In April 2015, the FASB issued an accounting standards update clarifying whether a customer should account for a cloud computing arrangement as an acquisition of a software license or as a service arrangement by providing characteristics that a cloud computing arrangement must have in order to be accounted for as a software license acquisition. The change is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2015. Retrospective or prospective application is allowed and early adoption is permitted. Adoption of this standard is not expected to have a material impact on our consolidated results of operations, financial position or cash flows. In February 2015, the FASB issued an accounting standards update making targeted changes to the current consolidation guidance. The new standard changes the considerations related to substantive rights, related parties, and decision making fees when applying the VIE consolidation model and eliminates certain guidance for limited partnerships and similar entities under the voting interest consolidation model. The update is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2015. Early adoption is permitted. We expect to continue to consolidate our master limited partnership, MPLX, after implementing this standard, but it will impact the determination of whether MPLX is a VIE and related disclosures. Otherwise the standard is not expected to have a material impact on our results of operations, financial position or cash flows. In August 2014, the FASB issued an accounting standards update requiring management to assess an entity’s ability to continue as a going concern and to provide related footnote disclosures in certain circumstances. Management will be required to assess if there is substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. Disclosures will be required if conditions give rise to substantial doubt and the type of disclosure will be determined based on whether management’s plans will be able to alleviate the substantial doubt. The accounting standards update will be effective for the first annual period ending after December 15, 2016, and for annual periods and interim periods thereafter with early application permitted. We do not expect application of this standard to have an impact on our financial reporting. In May 2014, the FASB issued an accounting standards update for revenue recognition that is aligned with the International Accounting Standards Board’s revenue recognition standard. The guidance in the update states that revenue is recognized when a customer obtains control of a good or service. Recognition of the revenue will involve a multiple step approach including identifying the contract, identifying the separate performance obligations, determining the transaction price, allocating the price to the performance obligations and then recognizing the revenue as the obligations are satisfied. Additional disclosures will be required to provide adequate information to understand the nature, amount, timing and uncertainty of reported revenues and revenues expected to be recognized. The accounting standards update will be effective on a retrospective or modified retrospective basis for annual reporting periods beginning after December 15, 2017, and interim periods within those years, with early adoption permitted, no earlier than January 1, 2017. We are in the process of determining the impact of the new standard on our consolidated financial statements.

MPLX LP

MPLX LP	12 Months Ended
	Dec. 31, 2015
Noncontrolling Interest [Abstract]
MPLX LP	MPLX LP MPLX is a publicly traded master limited partnership 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. On December 4, 2015, MPLX and MarkWest Energy Partners, L.P. (“MarkWest”) completed a merger, whereby MarkWest became a wholly-owned subsidiary of MPLX (the “MarkWest Merger”). MarkWest’s operations include: natural gas gathering, processing and transportation; NGL gathering, transportation, fractionation, storage and marketing; and crude oil gathering and transportation. Prior to the MarkWest Merger, we owned a 71.5 percent interest in MPLX, which included the two percent general partner interest. Each common unit of MarkWest issued and outstanding at the time of the MarkWest Merger was converted into the right to receive 1.09 common units of MPLX and, as of December 31, 2015 , our ownership interest in MPLX was 20.4 percent , including the two percent general partner interest. Due to our 100 percent ownership of the general partner interest, we have determined that we control MPLX and therefore we consolidate MPLX and record a noncontrolling interest for the 79.6 percent interest owned by the public. Sales and Contributions to MPLX MPLX’s initial assets consisted of a 51 percent general partner interest in MPLX Pipe Line Holdings LLC (“Pipe Line Holdings”), which owns a network of common carrier crude oil and product pipeline systems and associated storage assets in the Midwest and Gulf Coast regions of the United States, and a 100 percent interest in a butane storage cavern in West Virginia. On May 1, 2013, we sold a five percent interest in Pipe Line Holdings to MPLX for $100 million , which was financed by MPLX with cash on-hand. On March 1, 2014, we sold MPLX a 13 percent interest in Pipe Line Holdings for $310 million . MPLX financed this transaction with $40 million of cash on-hand and $270 million of borrowings on its bank revolving credit facility. On December 1, 2014, we sold and contributed interests in Pipe Line Holdings totaling 30.5 percent to MPLX for $600 million in cash and 2.9 million MPLX common units valued at $200 million . MPLX financed the sales portion of this transaction with $600 million of borrowings on its bank revolving credit facility. On December 4, 2015, we sold our remaining 0.5 percent interest in Pipe Line Holdings to MPLX for $12 million . As a result, MPLX now owns 100 percent of Pipe Line Holdings. The sales and contribution of our interests in Pipe Line Holdings to MPLX resulted in a change of our ownership in Pipe Line Holdings, but not a change in control. We accounted for these sales as transactions between entities under common control and did not record a gain or loss. Public Offerings On December 8, 2014, MPLX completed a public offering of 3.5 million common units at a price to the public of $66.68 per MPLX common unit, with net proceeds of $221 million . MPLX used the net proceeds from this offering to repay borrowings under its bank revolving credit facility and for general partnership purposes. On December 10, 2014, we exercised our right to maintain our two percent general partner interest in MPLX by purchasing 130 thousand general partner units for $9 million . On February 12, 2015, MPLX completed a public offering of $500 million aggregate principal amount of four percent unsecured senior notes due February 15, 2025 . See Note 19 for more information. Agreements We have various long-term, fee-based transportation and storage services agreements with MPLX. Under these agreements, MPLX provides transportation and storage services to us, and we commit to provide MPLX with minimum quarterly throughput volumes on crude oil and refined products systems and minimum storage volumes of crude oil, refined products and butane. We also have agreements with MPLX which establish fees for operational and management services provided between us and MPLX and for executive management services and certain general and administrative services provided by us to MPLX. These transactions are eliminated in consolidation.

Acquisitions and Investments

Acquisitions and Investments	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisitions and Investments	Acquisitions and Investments Merger with MarkWest Energy Partners, L.P. On December 4, 2015, MPLX completed the MarkWest Merger. Each common unit of MarkWest issued and outstanding immediately prior to the effective time of the MarkWest Merger was converted into a right to receive 1.09 common units of MPLX representing limited partner interests in MPLX, plus a one-time cash payment of $6.20 per unit. We will contribute approximately $1.28 billion of cash to MPLX to pay the aggregate cash consideration to MarkWest unitholders, without receiving any new equity from MPLX in exchange. At closing, we made a payment of $1.23 billion to MarkWest common unitholders and the remaining $50 million will be paid in equal amounts in July 2016 and July 2017, respectively, in connection with the conversion of the MPLX Class B units to MPLX common units. Our financial results and operating statistics reflect the results of MarkWest from the date of the MarkWest Merger. The components of the fair value of consideration transferred are as follows: (In millions) Fair value of MPLX units issued $ 7,326 Cash payment to MarkWest unitholders 1,230 Payable to MarkWest Class B unitholders 50 Total fair value of consideration transferred $ 8,606 The following table summarizes the preliminary purchase price allocation. Due to the proximity of the MarkWest Merger to December 31, 2015, we are still completing our analysis of the final purchase price allocation for property, plant and equipment, intangibles and deferred taxes. The estimated fair value of assets acquired and liabilities and noncontrolling interests assumed at the acquisition date, are as follows: (In millions) Cash and cash equivalents $ 12 Receivables 164 Inventories 33 Other current assets 44 Equity method investments 2,457 Property, plant and equipment, net 8,474 Other noncurrent assets 473 Total assets acquired 11,657 Accounts payable 322 Payroll and benefits payable 13 Accrued taxes 21 Other current liabilities 44 Long-term debt 4,567 Deferred income taxes 374 Deferred credit and other liabilities 151 Noncontrolling interests 13 Total liabilities and noncontrolling interest assumed 5,505 Net assets acquired excluding goodwill 6,152 Goodwill 2,454 Net assets acquired $ 8,606 Included in noncurrent assets is a $468 million intangible asset related to customer contracts and relationships. Amortization of intangibles with definite lives is calculated using the straight-line method which is reflective of the benefit pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible asset. The estimated useful life of the customer contracts and relationships is 11 to 25 years. The purchase price allocation resulted in the recognition of $2.45 billion in goodwill by our Midstream segment, substantially all of which is not deductible for tax purposes. Goodwill represents the complimentary aspects of the highly diverse asset base of MarkWest and MPLX that will provide significant additional opportunities across the hydrocarbon value chain. In addition, the combination provides significant vertical integration opportunities, as MPC is a large consumer of NGLs. We recognized $36 million of transaction costs related to the MarkWest Merger. These costs were expensed and $30 million is included in selling, general and administrative expenses and $6 million is in net interest and other financial income (costs). The amounts of revenue and income from operations associated with the MarkWest Merger included in our consolidated statements of income for 2015 are as follows: (In millions) 2015 Sales and other operating revenues (including consumer excise taxes) $ 120 Income from operations 32 Acquisition of Hess’ Retail Operations and Related Assets On September 30, 2014 , we acquired from Hess Corporation (“Hess”) all of Hess’ retail locations, transport operations and shipper history on various pipelines, including approximately 40,000 barrels per day on Colonial Pipeline, for $2.82 billion . We refer to these assets as “Hess’ Retail Operations and Related Assets.” The transaction was funded with a combination of debt and available cash. The transaction provided for an adjustment for working capital, which was finalized with Hess during the first quarter of 2015, resulting in a $3 million reduction to our total consideration. The components of the fair value of consideration transferred are as follows: (In millions) Cash $ 2,824 Net working capital adjustment estimate (3 ) Total fair value of consideration transferred $ 2,821 During the fourth quarter of 2014, an independent appraisal of the assets acquired and liabilities assumed and other evaluations were completed and finalized. Updates to the preliminary fair value measurements of assets acquired and liabilities assumed were made during the fourth quarter of 2014. The following table summarizes the amounts assigned to the assets acquired and liabilities assumed as of the acquisition date. (In millions) Cash and cash equivalents $ 49 Receivables 123 Inventories 165 Other current assets 8 Property, plant and equipment, net 2,063 Other noncurrent assets 111 Total assets acquired 2,519 Accounts payable 77 Payroll and benefits payable 15 Consumer excise taxes payable 64 Accrued taxes 4 Other current liabilities 10 Defined benefit postretirement plan obligations 2 Deferred credits and other liabilities 155 Total liabilities assumed 327 Net assets acquired excluding goodwill 2,192 Goodwill 629 Net assets acquired $ 2,821 The purchase price allocation resulted in the recognition of $629 million in goodwill by our Speedway segment. The goodwill primarily relates to the expected benefits of a significantly expanded retail platform that should enable growth in new markets, as well as the potential for higher merchandise sales by utilizing Speedway’s marketing approach at the acquired locations. The goodwill is deductible for tax purposes. Other noncurrent assets includes a $22 million intangible asset related to a trade name and $72 million related to favorable lease contract terms. Deferred credits and other liabilities includes $90 million related to unfavorable lease contract terms. The trade name is being amortized over its estimated useful life of two years based on the utilization of the assets. The favorable and unfavorable lease contract amounts are being amortized over the terms of the leases. We recognized $14 million of acquisition-related costs associated with Hess’ Retail Operations and Related Assets acquisition. These costs were expensed and were included in selling, general and administrative expenses. The amounts of revenue and income from operations associated with Hess’ Retail Operations and Related Assets included in our consolidated statements of income for 2014 are as follows: (In millions) 2014 Sales and other operating revenues (including consumer excise taxes) $ 2,403 Income from operations 113 Acquisition of Refinery and Related Logistics and Marketing Assets On February 1, 2013, we acquired from BP Products North America Inc. and BP Pipelines (North America) Inc. (collectively, “BP”) the 451,000 barrel per calendar day refinery in Texas City, Texas, three intrastate natural gas liquid pipelines originating at the refinery, four light product terminals, branded-jobber marketing contract assignments for the supply of approximately 1,200 branded sites, a 1,040 megawatt electric cogeneration facility and a 50,000 barrel per day allocation of space on the Colonial Pipeline. We refer to these assets as the “Galveston Bay Refinery and Related Assets.” We paid $1.49 billion for these assets, which included $935 million for inventory. The transaction was funded with cash on-hand. Pursuant to the purchase and sale agreement, we may also be required to pay to BP a contingent earnout of up to an additional $700 million over six years . See Note 17 for additional information on the contingent consideration. Neither goodwill nor a gain from a bargain purchase was recognized in conjunction with the Galveston Bay Refinery and Related Assets acquisition. We recognized $7 million of acquisition-related costs associated with the Galveston Bay Refinery and Related Assets acquisition. These costs were expensed and were included in selling, general and administrative expenses. Our refineries and related assets are operated as an integrated system. As the information is not available by refinery, it is not practicable to disclose the revenues and net income associated with the acquisition that were included in our consolidated statements of income for 2013. Unaudited Pro Forma Financial Information The following unaudited pro forma financial information presents consolidated results assuming the MarkWest Merger occurred on January 1, 2014, the Hess’ Retail Operations and Related Assets acquisition occurred on January 1, 2013 and the Galveston Bay Refinery and Related Assets acquisition occurred on January 1, 2012. The unaudited pro forma financial information does not give effect to potential synergies that could result from the transactions and is not necessarily indicative of the results of future operations. (In millions, except per share data) 2015 2014 2013 Sales and other operating revenues (including consumer excise taxes) $ 73,760 $ 108,605 $ 114,148 Net income attributable to MPC 2,825 2,522 2,142 Net income attributable to MPC per share – basic $ 5.25 $ 4.42 $ 3.40 Net income attributable to MPC per share – diluted 5.21 4.39 3.38 The unaudited 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, adjustments to amortize the fair value adjustment for the debt assumed by MPLX, adjustments to reflect the change in our limited partner interest in MPLX resulting from the MarkWest Merger, additional interest expense related to financing the acquisition of Hess’ Retail Operations and Related Assets, as well as the related income tax effects. Acquisition of Biodiesel Facility On April 1, 2014, we purchased a facility in Cincinnati, Ohio from Felda Iffco Sdn Bhd, Malaysia for $40 million . The plant currently produces biodiesel, glycerin and other by-products. The production capacity of the plant is approximately 60 million gallons per year. Neither goodwill nor a gain from a bargain purchase was recognized in conjunction with the biodiesel facility acquisition. Assuming the acquisition of the biodiesel facility in 2014 had been made at the beginning of any period presented, the consolidated pro forma results would not be materially different from reported results. Investments in Ethanol Companies On August 1, 2013 , we acquired from Mitsui & Co. (U.S.A.), Inc. its interests in three ethanol companies for $75 million . Under the purchase agreement, we acquired an additional 24 percent interest in The Andersons Clymers Ethanol LLC (“TACE”), bringing our ownership interest to 60 percent ; a 34 percent interest in The Andersons Ethanol Investment LLC (“TAEI”), which holds a 50 percent ownership in The Andersons Marathon Ethanol LLC (“TAME”), bringing our direct and indirect ownership interest in TAME to 67 percent ; and a 40 percent interest in The Andersons Albion Ethanol LLC (“TAAE”), which owns an ethanol production facility in Albion, Michigan. On October 1, 2013, our ownership interest in TAAE increased to 43 percent as a result of TAAE acquiring one of the owner’s interest. We hold a noncontrolling interest in each of these entities and account for them using the equity method of accounting since the minority owners have substantive participating rights. Investment in Ocean Vessel Joint Venture In September 2015, we acquired a 50 percent ownership interest in a new joint venture with Crowley Maritime Corporation through our investment in Crowley Ocean Partners LLC (“Crowley Ocean Partners”), which is included in our Refining & Marketing segment. The joint venture will operate and charter four new Jones Act product tankers, most of which will be leased to MPC. Contributions to the joint venture with respect to each vessel will occur at the vessel’s delivery. During 2015, we contributed $72 million in connection with delivery of the first two vessels. The remaining two vessels are expected to be delivered by the third quarter of 2016. We account for our ownership interest in Crowley Ocean Partners as an equity method investment. See Note 25 for information on our conditional guarantee of the indebtedness of the joint venture and future contributions to Crowley Ocean Partners. Investments in Pipeline Companies In July 2014, we exercised our option to acquire a 35 percent ownership interest in Enbridge Inc.’s Southern Access Extension pipeline (“SAX”) through our investment in Illinois Extension Pipeline Company, LLC (“Illinois Extension Pipeline”). During 2015 , we made contributions of $147 million to Illinois Extension Pipeline to fund our portion of the construction costs for the SAX project. We have contributed $267 million since project inception. We account for our ownership interest in Illinois Extension Pipeline as an equity method investment. During the construction of the pipeline, our ownership interest in Illinois Extension Pipeline was considered a VIE. Upon completion and start up of the pipeline in December of 2015, a reassessment determined that our investment is no longer considered a VIE. Our investment in the pipeline and our share of its results are included in our Midstream segment. In March 2014, we acquired from Chevron Raven Ridge Pipe Line Company an additional seven percent interest in Explorer Pipeline Company (“Explorer”) for $77 million , bringing our ownership interest to 25 percent . As a result of this increase in our ownership, we now account for our investment in Explorer using the equity method of accounting rather than the cost method. The cumulative impact of the change was applied as an adjustment to 2014 retained earnings. In November 2013, we agreed to serve as an anchor shipper for the Sandpiper pipeline project and fund 37.5 percent of the construction costs of the project, which will become part of Enbridge Energy Partners L.P.’s (“Enbridge Energy Partners”) North Dakota System. In exchange for these commitments, we will earn an approximate 27 percent equity interest in Enbridge Energy Partners’ North Dakota System when the Sandpiper pipeline is placed into service. The anticipated in-service date for the pipeline is likely to be delayed to early 2019. The project schedule and cost estimates remain under review. We also have the option to increase our ownership interest to approximately 30 percent through additional investments in future system improvements. We made contributions of $71 million to North Dakota Pipeline Company LLC (“North Dakota Pipeline”) during 2015 and have contributed $287 million since project inception, which are reflected in our Midstream segment. We account for our interest in North Dakota Pipeline using the equity method of accounting. See Note 25 for information on future contributions to North Dakota Pipeline.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Variable Interest Entities	Variable Interest Entities MarkWest Utica EMG On January 1, 2012, MarkWest Utica Operating Company, LLC (“Utica Operating”), a wholly-owned and consolidated subsidiary of MarkWest, and EMG Utica, LLC ("EMG Utica") (together the "Members"), executed agreements to form a joint venture, MarkWest Utica EMG LLC (“MarkWest Utica EMG”), to develop significant natural gas gathering, processing and NGL fractionation, transportation and marketing infrastructure in eastern Ohio. MarkWest has a 60 percent legal ownership interest in MarkWest Utica EMG. MarkWest Utica EMG's inability to fund its planned activities without subordinated financial support qualify it as a VIE. Utica Operating is not deemed to be the primary beneficiary due to EMG Utica’s voting rights on significant matters. We account for our ownership interest in MarkWest Utica EMG as an equity method investment. MPLX receives engineering and construction and administrative management fee revenue and reimbursement for other direct personnel costs for operating MarkWest Utica EMG. Our maximum exposure to loss as a result of our involvement with MarkWest Utica EMG includes our equity investment, any additional capital contribution commitments and any operating expenses incurred by the subsidiary operator in excess of compensation received for the performance of the operating services. Our equity investment in MarkWest Utica EMG at December 31, 2015 was $2.16 billion . Ohio Gathering Ohio Gathering Company, L.L.C. (“Ohio Gathering”) is a subsidiary of MarkWest Utica EMG and is engaged in providing natural gas gathering services in the Utica Shale in eastern Ohio. Ohio Gathering is a joint venture between MarkWest Utica EMG and Summit Midstream Partners (“Summit”). As of December 31, 2015 , we had a 36 percent indirect ownership interest in Ohio Gathering. As this entity is a subsidiary of MarkWest Utica EMG, which is accounted for as an equity method investment, MPLX reports its portion of Ohio Gathering’s net assets as a component of its investment in MarkWest Utica EMG. MPLX receives engineering and construction and administrative management fee revenue and reimbursement for other direct personnel costs for operating Ohio Gathering.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions Our related parties included: • Centennial Pipeline LLC (“Centennial”), in which we have a 50 percent noncontrolling interest. Centennial owns a refined products pipeline and storage facility. • Crowley Ocean Partners, in which we have a 50 percent noncontrolling interest. Crowley Ocean Partners operates and charters Jones Act product tankers. • Explorer, in which we have a 25 percent interest. Explorer owns and operates a refined products pipeline. • Illinois Extension Pipeline, in which we have a 35 percent noncontrolling interest. Illinois Extension Pipeline owns and operates a crude oil pipeline. • LOCAP LLC (“LOCAP”), in which we have a 59 percent noncontrolling interest. LOCAP owns and operates a crude oil pipeline. • LOOP LLC (“LOOP”), in which we have a 51 percent noncontrolling interest. LOOP owns and operates the only U.S. deepwater oil port. • MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. (“MarkWest EMG Jefferson”), in which we have a 67 percent noncontrolling interest. Jefferson Dry Gas is engaged in dry natural gas gathering in the county of Jefferson, Ohio. • MarkWest Utica EMG, in which we have a 60 percent noncontrolling interest. MarkWest Utica EMG owns and operates an NGL pipeline and natural gas gathering system. • Ohio Condensate, in which we have a 60 percent noncontrolling interest. Ohio Condensate owns and operates wellhead condensate stabilization and gathering services for certain locations within Ohio. • Ohio Gathering, in which we have a 36 percent indirect noncontrolling interest. Ohio Gathering owns, operates and develops midstream gathering infrastructure in southeastern Ohio. • TAAE, in which we have a 43 percent noncontrolling interest, TACE, in which we have a 60 percent noncontrolling interest and TAME, in which we have a 67 percent direct and indirect noncontrolling interest. These companies each own an ethanol production facility. • Other equity method investees. We believe that transactions with related parties were conducted on terms comparable to those with unaffiliated parties. Sales to related parties, which are included in sales and other operating revenues (including consumer excise taxes) on the consolidated statements of income, were $6 million , $7 million and $8 million in 2015 , 2014 and 2013 , respectively. Other income from related parties, which is included in other income on the consolidated statements of income, were $4 million , $1 million and $1 million in 2015 , 2014 and 2013 , respectively. Other income from related parties consists primarily of operating revenue. Purchases from related parties were as follows: (In millions) 2015 2014 2013 Centennial $ — $ 7 $ 3 Crowley Ocean Partners 6 — — Explorer 20 39 — Illinois Extension Pipeline 4 — — LOCAP 23 21 17 LOOP 52 88 43 TAAE 52 79 24 TACE 54 121 130 TAME 87 141 131 Other equity method investees 10 9 9 Total $ 308 $ 505 $ 357 Related party purchases from Centennial consist primarily of refinery feedstocks and refined product transportation costs. Related party purchases from Crowley Ocean Partners consist primarily of leasing equipment. Related party purchases from Explorer consist primarily of refined product transportation costs. Related party purchases from Illinois Extension Pipeline, LOCAP, LOOP and other equity method investees consist primarily of crude oil transportation costs. Related party purchases from TAAE, TACE and TAME consist of ethanol purchases. Receivables from related parties, which are included in receivables, less allowance for doubtful accounts on the consolidated balance sheets, were as follows: December 31, (In millions) 2015 2014 Centennial $ 1 $ 2 Explorer — 2 MarkWest EMG Jefferson 2 — MarkWest Utica EMG 1 — Ohio Condensate 3 — Ohio Gathering 5 — TAME — 3 Other equity method investees 1 — Total $ 13 $ 7 Long-term receivable from Ohio Condensate, which is included in other noncurrent assets on the consolidated balance sheet, was $1 million at December 31, 2015 . Payables to related parties, which are included in accounts payable on the consolidated balance sheets, were as follows: December 31, (In millions) 2015 2014 Explorer $ 1 $ 3 Illinois Extension Pipeline 4 — LOCAP 2 2 LOOP 5 4 MarkWest Utica EMG 19 — Ohio Condensate 4 — TAAE 1 2 TACE 2 2 TAME 3 5 Other equity method investees 1 — Total $ 42 $ 18

Income per Common Share

Income per Common Share	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Income per Common Share	Income per Common Share We compute basic earnings per share by dividing net income attributable to MPC by the weighted average number of shares of common stock outstanding. The average number of shares of common stock and per share amounts have been retroactively restated to reflect the two-for-one stock split completed in June 2015. Diluted income per share assumes exercise of certain stock based compensation awards, provided the effect is not anti-dilutive. MPC grants certain incentive compensation awards to employees and non-employee directors that are considered to be participating securities. Due to the presence of participating securities, we have calculated our earnings per share using the two-class method. (In millions, except per share data) 2015 2014 2013 Basic earnings per share: Allocation of earnings: Net income attributable to MPC $ 2,852 $ 2,524 $ 2,112 Income allocated to participating securities 4 4 4 Income available to common stockholders – basic $ 2,848 $ 2,520 $ 2,108 Weighted average common shares outstanding 538 570 630 Basic earnings per share $ 5.29 $ 4.42 $ 3.34 Diluted earnings per share: Allocation of earnings: Net income attributable to MPC $ 2,852 $ 2,524 $ 2,112 Income allocated to participating securities 4 4 4 Income available to common stockholders – diluted $ 2,848 $ 2,520 $ 2,108 Weighted average common shares outstanding 538 570 630 Effect of dilutive securities 4 4 4 Weighted average common shares, including dilutive effect 542 574 634 Diluted earnings per share $ 5.26 $ 4.39 $ 3.32 The following table summarizes the shares that were anti-dilutive, and therefore, were excluded from the diluted share calculation. (In millions) 2015 2014 2013 Shares issued under stock-based compensation plans 1 1 1

Equity

Equity	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Equity	Equity On April 29, 2015, our board of directors approved a two-for-one stock split in the form of a stock dividend, which was distributed on June 10, 2015 to shareholders of record at the close of business on May 20, 2015. The total number of authorized shares of common stock and common stock par value per share remain unchanged. All historical share and per share data included in this report have been retroactively restated on a post-split basis. On July 29, 2015, our board of directors approved an additional $2.0 billion share repurchase authorization expiring in July 2017 . Since January 1, 2012, our board of directors had approved $10.0 billion in total share repurchase authorizations and we have repurchased a total of $7.24 billion of our common stock under these authorizations, leaving $2.76 billion available for repurchases as of December 31, 2015 . Under these authorizations, we have acquired 198 million shares at an average cost per share of $36.65 . We may utilize various methods to effect the repurchases, which could include open market repurchases, negotiated block transactions, accelerated share repurchases or open market solicitations for shares, some of which may be effected through Rule 10b5-1 plans. The timing and amount of future repurchases, if any, will depend upon several factors, including market and business conditions, and such repurchases may be discontinued at any time. Total share repurchases were as follows for the respective periods: (In millions, except per share data) 2015 2014 2013 Number of shares repurchased (a) 19 49 74 Cash paid for shares repurchased $ 965 $ 2,131 $ 2,793 Effective average cost per delivered share $ 50.31 $ 44.31 $ 38.07 (a) Shares repurchased in 2013 includes 2 million shares received under the November 2012 accelerated share repurchase program, which were paid for in 2012. At December 31, 2015 , we had agreements to acquire 172,200 common shares for $9 million , which were settled in early January 2016 .

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Segment Information	Segment Information We have three reportable segments: Refining & Marketing; Speedway; and Midstream . Each of these segments is organized and managed based upon the nature of the products and services it offers. • Refining & Marketing – refines crude oil and other feedstocks at our refineries in the Gulf Coast and Midwest regions of the United States, purchases ethanol and refined products for resale and distributes refined products through various means, including barges, terminals and trucks that we own or operate. We sell refined products to wholesale marketing customers domestically and internationally, to buyers on the spot market, to our Speedway segment and to independent entrepreneurs who operate Marathon ® retail outlets. • Speedway – sells transportation fuels and convenience merchandise in retail markets in the Midwest, East Coast and Southeast regions of the United States. • Midstream – includes the operations of MPLX and certain other related operations. Following the MarkWest Merger, we changed the name of this segment from Pipeline Transportation to Midstream to reflect its expanded business activities. There were no changes to the historical financial information reported for this segment. The Midstream segment gathers, processes and transports natural gas; gathers, transports, fractionates, stores and markets natural gas liquids and transports and stores crude oil and refined products. On December 4, 2015, MPLX completed a merger with MarkWest and its results are included in the Midstream segment. On September 30, 2014, we acquired Hess’ Retail Operations and Related Assets, substantially all of which is part of the Speedway segment. On February 1, 2013, we acquired the Galveston Bay Refinery and Related Assets, which is part of the Refining & Marketing and Midstream segments. Segment information for periods prior to each acquisition or the MarkWest Merger 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 Midstream Total Year Ended December 31, 2015 Revenues: Customer $ 52,174 $ 19,690 $ 187 $ 72,051 Intersegment (a) 12,018 3 564 12,585 Segment revenues $ 64,192 $ 19,693 $ 751 $ 84,636 Segment income from operations (b)(c) $ 4,186 $ 673 $ 289 $ 5,148 Income from equity method investments 26 — 62 88 Depreciation and amortization (d) 1,079 254 117 1,450 Capital expenditures and investments (e)(f) 1,143 501 14,447 16,091 (In millions) Refining & Marketing Speedway Midstream Total Year Ended December 31, 2014 Revenues: Customer $ 80,822 $ 16,927 $ 70 $ 97,819 Intersegment (a) 10,912 5 527 11,444 Segment revenues $ 91,734 $ 16,932 $ 597 $ 109,263 Segment income from operations (b) $ 3,609 $ 544 $ 280 $ 4,433 Income from equity method investments 96 — 57 153 Depreciation and amortization (d) 1,045 152 77 1,274 Capital expenditures and investments (e)(g) 1,104 2,981 543 4,628 (In millions) Refining & Marketing Speedway Midstream Total Year Ended December 31, 2013 Revenues: Customer $ 85,616 $ 14,471 $ 79 $ 100,166 Intersegment (a) 9,294 4 458 9,756 Segment revenues $ 94,910 $ 14,475 $ 537 $ 109,922 Segment income from operations (b) $ 3,206 $ 375 $ 210 $ 3,791 Income from equity method investments 28 — 8 36 Depreciation and amortization (d) 1,011 112 74 1,197 Capital expenditures and investments (e)(h) 2,094 296 234 2,624 (a) Management believes intersegment transactions were conducted under terms comparable to those with unaffiliated parties. (b) Included in the Midstream segment for 2015 , 2014 and 2013 are $20 million , $19 million and $20 million , respectively, of corporate overhead expenses attributable to MPLX. Corporate overhead expenses are not currently allocated to other segments. Also included in the Midstream segment for 2015 are $36 million of transaction costs related to the MarkWest Merger. (c) The Refining & Marketing and Speedway segments include inventory lower of cost or market charge of $345 million and $25 million , respectively. (d) 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. (e) Capital expenditures include changes in capital accruals, acquisitions and investments in affiliates. (f) The Midstream segment includes $13.85 billion for the MarkWest Merger. See Note 5 . (g) The Speedway and Refining & Marketing segments include $2.66 billion and $52 million , respectively, for the acquisition of Hess’ Retail Operations and Related Assets. See Note 5 . (h) The Refining & Marketing and Midstream segments include $1.29 billion and $70 million , respectively, for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5 . The following reconciles segment income from operations to income before income taxes as reported in the consolidated statements of income: (In millions) 2015 2014 2013 Segment income from operations $ 5,148 $ 4,433 $ 3,791 Items not allocated to segments: Corporate and other unallocated items (a)(b) (308 ) (286 ) (271 ) Pension settlement expenses (c) (4 ) (96 ) (95 ) Impairment (d) (144 ) — — Net interest and other financial income (costs) (318 ) (216 ) (179 ) Income before income taxes $ 4,374 $ 3,835 $ 3,246 (a) Corporate and other unallocated items consists primarily of MPC’s corporate administrative expenses and costs related to certain non-operating assets. (b) Corporate overhead expenses attributable to MPLX are included in the Midstream segment. Corporate overhead expenses are not allocated to the Refining & Marketing and Speedway segments. (c) See Note 22 . (d) Related to the cancellation of the ROUX project at our Garyville, LA refinery. See Note 15 . The following reconciles segment capital expenditures and investments to total capital expenditures: (In millions) 2015 2014 2013 Segment capital expenditures and investments $ 16,091 $ 4,628 $ 2,624 Less: Investments in equity method investees (a) 2,788 413 124 Plus: Items not allocated to segments: Capital expenditures not allocated to segments 155 83 137 Capitalized interest 37 27 28 Total capital expenditures (b) $ 13,495 $ 4,325 $ 2,665 (a) 2015 includes $2.46 billion for the MarkWest Merger. See Note 5 . (b) Capital expenditures include changes in capital accruals. See Note 20 for a reconciliation of total capital expenditures to additions to property, plant and equipment as reported in the consolidated statements of cash flows. The following reconciles total segment customer revenues to sales and other operating revenues (including consumer excise taxes) as reported in the consolidated statements of income: (In millions) 2015 2014 2013 Customer revenues $ 72,051 $ 97,819 $ 100,166 Corporate and other unallocated items — (2 ) (6 ) Sales and other operating revenues (including consumer excise taxes) $ 72,051 $ 97,817 $ 100,160 Revenues by product line were: (In millions) 2015 2014 2013 Refined products $ 63,708 $ 90,702 $ 93,520 Merchandise 5,188 3,817 3,308 Crude oil and refinery feedstocks 2,718 2,917 2,988 Transportation and other 437 381 344 Sales and other operating revenues (including consumer excise taxes) $ 72,051 $ 97,817 $ 100,160 No single customer accounted for more than 10 percent of annual revenues for the years ended December 31, 2015 and 2014 . Revenue from BP p.l.c. included in the Refining & Marketing segment represented 10 percent of our total annual revenues for the year ended December 31, 2013 . We do not have significant operations in foreign countries. Therefore, revenues in foreign countries and long-lived assets located in foreign countries, including property, plant and equipment and investments, are not material to our operations. Total assets by reportable segment were: December 31, (In millions) 2015 2014 Refining & Marketing $ 17,780 $ 19,751 Speedway 5,349 5,296 Midstream 17,061 2,407 Corporate and Other 2,925 2,971 Total consolidated assets $ 43,115 $ 30,425

Other Items

Other Items	12 Months Ended
	Dec. 31, 2015
Other Income and Expenses [Abstract]
Other Items	Other Items Net interest and other financial income (costs) was: (In millions) 2015 2014 2013 Interest income $ 6 $ 7 $ 9 Interest expense (325 ) (229 ) (195 ) Interest capitalized 37 27 28 Loss on extinguishment of debt (5 ) — — Other financial costs (a) (31 ) (21 ) (21 ) Net interest and other financial income (costs) $ (318 ) $ (216 ) $ (179 ) (a) 2015 includes $6 million of transaction costs related to the MarkWest Merger.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes Income tax provisions (benefits) were: 2015 2014 2013 (In millions) Current Deferred Total Current Deferred Total Current Deferred Total Federal $ 1,210 $ 134 $ 1,344 $ 1,382 $ (199 ) $ 1,183 $ 954 $ 20 $ 974 State and local 152 9 161 135 (37 ) 98 131 8 139 Foreign 10 (9 ) 1 5 (6 ) (1 ) 5 (5 ) — Total $ 1,372 $ 134 $ 1,506 $ 1,522 $ (242 ) $ 1,280 $ 1,090 $ 23 $ 1,113 A reconciliation of the federal statutory income tax rate ( 35 percent ) applied to income before income taxes to the provision for income taxes follows: 2015 2014 2013 Statutory rate applied to income before income taxes 35 % 35 % 35 % State and local income taxes, net of federal income tax effects 2 2 3 Domestic manufacturing deduction (2 ) (2 ) (2 ) Other (1 ) (2 ) (2 ) Provision for income taxes 34 % 33 % 34 % Deferred tax assets and liabilities resulted from the following: December 31, (In millions) 2015 2014 Deferred tax assets: Employee benefits $ 631 $ 616 Environmental 44 54 Investments in subsidiaries and affiliates — 24 Net operating loss carryforwards 73 12 Other 73 58 Total deferred tax assets 821 764 Deferred tax liabilities: Property, plant and equipment 2,512 2,411 Inventories 579 614 Investments in subsidiaries and affiliates (a) 909 — Other 89 101 Total deferred tax liabilities 4,089 3,126 Net deferred tax liabilities $ 3,268 $ 2,362 (a) 2015 includes $443 million acquired in the MarkWest Merger. See Note 5 for total net deferred income taxes acquired. 2015 also includes $404 million tax effect related to MPC’s $1.5 billion share of the MPLX equity issued in connection with the MarkWest Merger. See Consolidated Statements of Equity. Net deferred tax liabilities were classified in the consolidated balance sheets as follows: December 31, (In millions) 2015 2014 Assets: Other noncurrent assets $ 17 $ 7 Liabilities: Accrued taxes (a) — 355 Deferred income taxes 3,285 2,014 Net deferred tax liabilities $ 3,268 $ 2,362 (a) We adopted the updated FASB balance classification of deferred taxes standard and applied the changes prospectively. We reclassified current deferred taxes from current accrued taxes to long-term deferred income taxes. See Note 3 . Tax carryforwards – At December 31, 2015, federal operating loss carryforwards were $66 million , including $58 million from a subsidiary acquired with the MarkWest Merger which is not included in MPC’s consolidated federal income tax return, which expire in 2022 through 2035 . State and local operating loss carryforwards of $7 million , including $4 million acquired with the MarkWest Merger, expire in 2016 through 2035 . Valuation allowances – As of December 31, 2015 and 2014 , $4 million of valuation allowances were recognized primarily due to the expected realizability of foreign tax credits and based on estimates of future financial income and expected realizability of state and local tax operating losses. MPC is continuously undergoing examination of its U.S. federal income tax returns by the Internal Revenue Service. Such audits have been completed through the 2009 tax year. We believe adequate provision has been made for federal income taxes and interest which may become payable for years not yet settled. Further, we are routinely involved in U.S. state income tax audits. We believe all other audits will be resolved with the amounts paid and/or provided for these liabilities. As of December 31, 2015 , our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated: United States Federal 2010 - 2014 States 2004 - 2014 As a result of the Spinoff and pursuant to the tax sharing agreement by Marathon Oil and MPC, the unrecognized tax benefits related to MPC operations for which Marathon Oil was the taxpayer remain the responsibility of Marathon Oil and MPC has indemnified Marathon Oil. During 2013, we settled with Marathon Oil our U.S. federal and related state return liabilities for the 2008-2009 tax years, resulting in a reduction in unrecognized tax benefits of $21 million , which are also reflected in the table below as settlements. During 2013, we settled with Marathon Oil for the 2011 period prior to the Spinoff based on filed tax returns and in accordance with the tax sharing agreement, resulting in a $39 million increase to additional paid-in capital. The following table summarizes the activity in unrecognized tax benefits: (In millions) 2015 2014 2013 January 1 balance $ 12 $ 13 $ 40 Additions for tax positions of prior years — 7 30 Reductions for tax positions of prior years — (10 ) (25 ) Settlements — 2 (30 ) Statute of limitations — — (2 ) December 31 balance $ 12 $ 12 $ 13 If the unrecognized tax benefits as of December 31, 2015 were recognized, $5 million would affect our effective income tax rate. There were $4 million of uncertain tax positions as of December 31, 2015 for which it is reasonably possible that the amount of unrecognized tax benefits would significantly decrease during the next twelve months. Interest and penalties related to income taxes are recorded as part of the provision for income taxes. Such interest and penalties were net expenses of $3 million , less than $1 million and $11 million in 2015 , 2014 and 2013 , respectively. As of December 31, 2015 and 2014 , $18 million and $14 million of interest and penalties were accrued related to income taxes.

Inventories

Inventories	12 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Inventories	Inventories December 31, (In millions) 2015 2014 Crude oil and refinery feedstocks $ 2,180 $ 2,219 Refined products 2,804 2,955 Materials and supplies 438 302 Merchandise 173 166 Lower of cost or market reserve (370 ) — Total $ 5,225 $ 5,642 The LIFO method accounted for 91 percent and 94 percent of total inventory value at December 31, 2015 and 2014 , respectively. Costs of crude oil, refinery feedstocks and refined products are aggregated on a consolidated basis for purposes of assessing if the LIFO cost basis of these inventories may have to be written down to market values. At December 31, 2015 , market values for these inventories were lower than their LIFO cost basis and, as a result, we recorded an inventory valuation charge of $370 million to cost of revenues to value these inventories at the lower of cost or market. Based on movements of refined product prices, future inventory valuation adjustments could have a negative or positive effect to earnings. Such losses are subject to reversal in subsequent periods if prices recover. In 2016, inventory market values have continued to decline and if they do not recover to December 31, 2015 levels by March 31, 2016, an additional inventory valuation charge would be required in first quarter 2016. At December 31, 2014 , current acquisition costs of inventories were estimated to exceed the LIFO inventory value by $684 million . During 2015 , we recorded LIFO liquidations caused by permanently decreased levels in crude oil and refined products inventory volumes. Cost of revenues increased and income from operations decreased by $78 million for the year ended December 31, 2015 . There were no liquidations of LIFO inventories in 2014 and 2013 .

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	Equity Method Investments Ownership as of Carrying value at December 31, December 31, (In millions) 2015 2015 2014 Centennial 50% $ 37 $ 36 Centrahoma Processing LLC 40% 111 — Crowley Ocean Partners 50% 72 — Explorer 25% 91 95 Illinois Extension Pipeline 35% 267 120 LOCAP 59% 22 23 LOOP 51% 243 230 MarkWest Utica EMG 60% 2,160 — North Dakota Pipeline (a) 38% 287 216 Ohio Condensate 60% 101 — TAAE 43% 27 22 TACE 60% 49 61 TAEI 34% 18 19 TAME (b) 50% 27 24 Other MPLX investments 86 — Other 24 19 Total $ 3,622 $ 865 (a) We own a 38 percent interest in the Class B units of this entity. Our Class B units will be converted to an approximate 27 percent ownership interest in the Class A units of this entity upon completion of the Sandpiper pipeline construction project, which is expected to be in early 2019. (b) Excludes TAEI’s investment in TAME. Summarized financial information for equity method investees is as follows: (In millions) 2015 2014 2013 Income statement data: Revenues and other income $ 1,390 $ 1,430 $ 1,067 Income from operations 332 379 87 Net income 239 316 63 Balance sheet data – December 31: Current assets $ 906 $ 990 Noncurrent assets 6,418 2,166 Current liabilities 468 280 Noncurrent liabilities 1,130 957 As of December 31, 2015 , the carrying value of our equity method investments was $1.07 billion higher than the underlying net assets of investees. This basis difference is being amortized or accreted into net income over the remaining estimated useful lives of the underlying net assets, except for $426 million of excess related to goodwill. Centennial experienced a significant reduction in shipment volumes in the second half of 2011 that has continued through 2015. At December 31, 2015, Centennial was not shipping product. As a result, we continued to evaluate the carrying value of our equity investment in Centennial. We concluded that no impairment was required given our assessment of its fair value based on market participant assumptions for various potential uses and future cash flows of Centennial’s assets. If market conditions were to change and the owners of Centennial are unable to find an alternative use for the assets, there could be a future impairment of our Centennial interest. As of December 31, 2015 , our equity investment in Centennial was $37 million and we had a $34 million guarantee associated with 50 percent of Centennial’s outstanding debt. See Note 25 for additional information on the debt guarantee. Dividends and partnership distributions received from equity method investees (excluding distributions that represented a return of capital previously contributed) were $113 million , $170 million and $18 million in 2015 , 2014 and 2013 .

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment (In millions) Estimated Useful Lives December 31, 2015 2014 Refining & Marketing 2 - 30 years $ 18,925 $ 18,001 Speedway 4 - 25 years 5,067 4,639 Midstream 10 - 42 years 10,850 2,044 Corporate and Other 4 - 40 years 762 618 Total 35,604 25,302 Less accumulated depreciation 10,440 9,041 Property, plant and equipment, net $ 25,164 $ 16,261 Property, plant and equipment includes gross assets acquired under capital leases of $511 million and $510 million at December 31, 2015 and 2014 , respectively, with related amounts in accumulated depreciation of $176 million and $144 million at December 31, 2015 and 2014 . Property, plant and equipment includes construction in progress of $2,263 million and $1,043 million at December 31, 2015 and 2014 , respectively, which primarily relates to capital projects at our refineries. In the third quarter of 2015, we decided to cancel the ROUX project at our Garyville, Louisiana refinery due to the implications of current market conditions. The project was intended to increase margins by upgrading residual fuel to ultra-low sulfur diesel and gas oil. As a result, we recorded a $144 million impairment charge to write off the costs incurred through September 30, 2015 on the project. This impairment charge is included in depreciation and amortization on the consolidated statements of income.

Goodwill and Intangibles

Goodwill and Intangibles	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill	Goodwill and Intangibles Goodwill Goodwill is tested for impairment on an annual basis and when events or changes in circumstances indicate the fair value of a reporting unit with goodwill has been reduced below the carrying value of the net assets of the reporting unit. We performed our annual impairment tests for 2015 and 2014 , and no impairment was required. The carrying values of certain reporting units in our Midstream segment equaled their fair values as of the date of the MarkWest Merger. Any decrease in the fair value of these reporting units going forward could result in an impairment charge to the approximate $2.5 billion of goodwill recorded in connection with the MarkWest Merger. In February of 2016, MPLX common units were trading at a price per unit which is significantly lower than the price per unit used to calculate the merger consideration and the resulting goodwill that was assigned to certain reporting units in our Midstream segment. The significant assumptions which were used to develop the estimates of the fair values recorded in acquisition accounting and the resulting goodwill assigned to the reporting units included discount rates, growth rates, and customer attrition rates. If MPLX experiences negative events related to these assumptions or if the market price of MPLX common units continues to trade at a low level in 2016, MPLX may need to assess whether this is a change in circumstances that indicates it is more likely than not that the fair value of the reporting units to which MPLX assigned goodwill in connection with the MarkWest Merger is less than their carrying value and, if so, evaluate goodwill for impairment. The changes in the carrying amount of goodwill for 2015 and 2014 were as follows: (In millions) Refining & Marketing Speedway Midstream Total Balance at January 1, 2014 $ 551 $ 225 $ 162 $ 938 Acquisitions (a) — 629 — 629 Disposition (1 ) — — (1 ) Balance at December 31, 2014 $ 550 $ 854 $ 162 $ 1,566 Acquisitions (a) — — 2,454 2,454 Disposition — (1 ) — (1 ) Balance at December 31, 2015 $ 550 $ 853 $ 2,616 $ 4,019 (a) See Note 5 for information on the acquisitions. Intangible Assets Our intangible assets as of December 31, 2015 and 2014 are as follows: (In millions) Refining & Marketing Speedway Midstream Total Balance at December 31, 2015 Customer contracts and relationships $ 91 $ 1 $ 468 $ 560 Royalty agreements 122 — — 122 Favorable lease contract terms 1 70 — 71 Other (a) 28 75 — 103 Gross $ 242 $ 146 $ 468 $ 856 Accumulated amortization (104 ) (31 ) (2 ) (137 ) Net $ 138 $ 115 $ 466 $ 719 Balance at December 31, 2014 Customer contracts and relationships $ 105 $ 1 $ — $ 106 Royalty agreements 121 — — 121 Favorable lease contract terms 1 71 — 72 Other (a) 30 74 — 104 Gross $ 257 $ 146 $ — $ 403 Accumulated amortization (106 ) (10 ) — (116 ) Net $ 151 $ 136 $ — $ 287 (a) The Refining & Marketing and Speedway segments include unamortized intangible assets of $3 million and $46 million , respectively, which are primarily trademarks. Amortization expense for 2015 and 2014 was $29 million and $18 million , respectively. Estimated future amortization expense related to the intangible assets at December 31, 2015 is as follows: (In millions) 2016 $ 48 2017 45 2018 45 2019 44 2020 47

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Fair Value Measurements	Fair Value Measurements Fair Values – Recurring The following tables present assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 by fair value hierarchy level. We have elected to offset the fair value amounts recognized for multiple derivative contracts executed with the same counterparty, including any related cash collateral as shown below; however, fair value amounts by hierarchy level are presented on a gross basis in the following tables. December 31, 2015 Fair Value Hierarchy (In millions) Level 1 Level 2 Level 3 Netting and Collateral (a) Net Carrying Value on Balance Sheet (b) Collateral Pledged Not Offset Commodity derivative instruments, assets $ 104 $ 2 $ 7 $ (62 ) $ 51 $ — Other assets 2 — — N/A 2 — Total assets at fair value $ 106 $ 2 $ 7 $ (62 ) $ 53 $ — Commodity derivative instruments, liabilities $ 39 $ — $ — $ (39 ) $ — $ — Embedded derivatives in commodity contracts (c) — — 32 — 32 — Contingent consideration, liability (d) — — 317 N/A 317 — Total liabilities at fair value $ 39 $ — $ 349 $ (39 ) $ 349 $ — December 31, 2014 Fair Value Hierarchy (In millions) Level 1 Level 2 Level 3 Netting and Collateral (a) Net Carrying Value on Balance Sheet (b) Collateral Pledged Not Offset Commodity derivative instruments, assets $ 317 $ — $ — $ (258 ) $ 59 $ — Other assets 2 — — N/A 2 — Total assets at fair value $ 319 $ — $ — $ (258 ) $ 61 $ — Commodity derivative instruments, liabilities $ 180 $ — $ — $ (180 ) $ — $ — Contingent consideration, liability (d) — — 478 N/A 478 — Total liabilities at fair value $ 180 $ — $ 478 $ (180 ) $ 478 $ — (a) Represents the impact of netting assets, liabilities and cash collateral when a legal right of offset exists. As of December 31, 2015 , cash collateral of $23 million was netted with mark-to-market derivative assets. As of December 31, 2014 , cash collateral of $78 million was netted with mark-to-market derivative assets. (b) We have no derivative contracts that are subject to master netting arrangements that are reflected gross on the balance sheet. (c) Includes $5 million at December 31, 2015 classified as current. (d) Includes $196 million and $174 million classified as current as of December 31, 2015 and 2014 , respectively. Commodity derivatives in Level 1 are exchange-traded contracts for crude oil and refined products measured at fair value with a market approach using the close-of-day settlement prices for the market. Commodity derivatives are covered under master netting agreements with an unconditional right to offset. Collateral deposits in futures commission merchant accounts covered by master netting agreements related to Level 1 commodity derivatives are classified as Level 1 in the fair value hierarchy. Commodity derivatives in Level 2 include crude oil and natural gas swap contracts and are measured at fair value with a market approach. The valuations are based on the appropriate commodity prices and contain no significant unobservable inputs. LIBO Rates are an observable input for the measurement of these derivative contracts. The measurements for commodity contracts contain observable inputs in the form of forward prices based on WTI crude oil prices; and Columbia Appalachia, Henry Hub, PEPL and Houston Ship Channel natural gas prices. MPLX settled natural gas swaps during the year ended December 31, 2015 ; however, no such instruments were outstanding as of December 31, 2015 . Level 3 instruments include OTC NGL contracts and embedded derivatives in commodity contracts. The fair value calculation for these Level 3 instruments used significant unobservable inputs including: (1) NGL prices interpolated and extrapolated due to inactive markets ranging from approximately $0.15 to $3.40 per gallon, (2) electricity prices ranging from approximately $23 to $45 per megawatt hour and (3) the probability of renewal of 50 percent . For these contracts, increases in forward NGL prices result in a decrease in the fair value of the derivative assets and an increase in the fair value of the derivative liabilities. The forward prices for the individual NGL products generally increase or decrease in a positive correlation with one another. The embedded derivative liability relates to a natural gas purchase agreement embedded in a keep‑whole processing agreement. Increases or decreases in forward NGL prices result in an increase or decrease in the fair value of the embedded derivative. An increase in the probability of renewal would result in an increase in the fair value of the related embedded derivative liability. The contingent consideration represents the fair value as of December 31, 2015 and 2014 of the remaining 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 remaining 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 earnout 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 commencing in 2014. Any excess or shortfall from the annual cap for a current year’s earnout calculation will not affect subsequent years’ calculations. The fair value calculation used significant unobservable inputs including: (1) an estimate of monthly refinery throughput volumes; (2) a range of internal and external monthly crack spread forecasts from approximately $7 to $16 per barrel; and (3) a range of risk-adjusted discount rates from five percent to 10 percent . An increase or decrease in crack spread forecasts or refinery throughput volume expectations may 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 caps. An increase or decrease in the discount rate may result in a decrease or increase to the fair value, respectively. The fair value of the contingent consideration is reassessed each quarter, with changes in fair value recorded in cost of revenues. The following is a reconciliation of the net beginning and ending balances recorded for net assets and liabilities classified as Level 3 in the fair value hierarchy. (In millions) 2015 2014 2013 Beginning balance $ 478 $ 625 $ — Contingent consideration agreement — — 600 Contingent consideration payment (a) (189 ) (180 ) — Net derivative positions assumed - MarkWest Merger 31 — — Unrealized and realized (gains) losses included in net income 20 33 25 Settlements of derivative instruments 2 — — Ending balance $ 342 $ 478 $ 625 (a) On the consolidated statements of cash flows for 2015 and 2014, $175 million and $172 million , respectively, of the contingent earnout payment to BP is included as a financing activity with the remainder included as an operating activity. We held Level 3 derivative instruments in 2015 in conjunction with the MarkWest Merger, but we did not hold any Level 3 derivative instruments in 2014 and 2013. See Note 18 for the income statement impacts of our derivative instruments. There was an unrealized gain of $7 million in 2015 related to derivatives. There was an unrealized loss of $28 million , $33 million , and $25 million in 2015, 2014 and 2013, respectively, related to the contingent consideration. Fair Values – Nonrecurring The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition. Year Ended December 31, 2015 2014 2013 (In millions) Fair Value Impairment Fair Value Impairment Fair Value Impairment Property, plant and equipment, net $ — $ 144 $ — $ — $ 1 $ 8 Other noncurrent assets — — — 11 — — In the third quarter of 2015, we decided to cancel the ROUX project at our Garyville, LA refinery. The work completed on the project through September 30, 2015 had no alternate use or net salvage value; therefore, we fully impaired the $144 million of cost capitalized for the project through that date. The fair value of our investment in the project was determined using an income approach and is classified as Level 3. Based on the financial and operational status of a company in which we have an interest, we fully impaired our $11 million investment in that company in 2014. Our investment in this company was accounted for using the cost method and was included in our Refining & Marketing segment. The impairment charge is included in other income on the consolidated statements of income. The fair value of our investment in this cost company was measured using an income approach. This measurement is classified as Level 3. Due to changing market conditions, we assessed one of our light products terminals for impairment. The terminal is operated by our Refining & Marketing segment. We recorded an impairment charge of $8 million for this terminal in 2013. The impairment charge 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. Fair Values – Reported The following table summarizes financial instruments on the basis of their nature, characteristics and risk at December 31, 2015 and 2014 , excluding the derivative financial instruments and contingent consideration reported above. December 31, 2015 2014 (In millions) Fair Value Carrying Value Fair Value Carrying Value Financial assets: Investments $ 33 $ 2 $ 26 $ 2 Other 35 33 32 32 Total financial assets $ 68 $ 35 $ 58 $ 34 Financial liabilities: Long-term debt (a) $ 11,366 $ 11,628 $ 6,571 $ 6,265 Deferred credits and other liabilities 136 135 17 17 Total financial liabilities $ 11,502 $ 11,763 $ 6,588 $ 6,282 (a) Excludes capital leases and debt issuance costs, however, includes amount classified as short-term debt. 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 a liability related to SMR, a payable for merger cash consideration due to MPLX’s Class B unitholders to be paid upon conversion, insurance liabilities and environmental remediation liabilities. Fair value of fixed-rate long-term debt is measured using a market approach, based upon the average of quotes from major financial institutions and a third-party service for our debt. Because these quotes cannot be independently verified to the market, they are considered Level 3 inputs. Fair value of variable-rate long-term debt approximates the carrying value.

Derivatives

Derivatives	12 Months Ended
	Dec. 31, 2015
Summary of Derivative Instruments [Abstract]
Derivatives	Derivatives For further information regarding the fair value measurement of derivative instruments, including any effect of master netting agreements or collateral, see Note 17 . See Note 2 for a discussion of the types of derivatives we use and the reasons for them. We do not designate any of our commodity derivative instruments as hedges for accounting purposes. Our interest rate derivative instruments that were terminated in 2012 had been designated as fair value accounting hedges. The following table presents the gross fair values of derivative instruments, excluding cash collateral, and where they appear on the consolidated balance sheets as of December 31, 2015 and 2014 : (In millions) December 31, 2015 Balance Sheet Location Asset Liability Commodity derivatives Other current assets $ 113 $ 39 Other current liabilities — 5 Deferred credits and other liabilities (a) — 27 (In millions) December 31, 2014 Balance Sheet Location Asset Liability Commodity derivatives Other current assets $ 317 $ 180 (a) Includes embedded derivatives. 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, (4) the acquisition of ethanol for blending with refined products, (5) sale of NGLs, (6) the purchase of natural gas and (7) purchase of electricity. The table below summarizes open commodity derivative contracts for crude oil and refined products as of December 31, 2015 . Position Total Barrels (In thousands) Crude oil (a) Exchange-traded Long 14,517 Exchange-traded Short (22,989 ) OTC Short (110 ) (a ) 100 percent of the exchange-traded contracts expire in the first quarter of 2016. Position Total Gallons (In thousands) Refined Products (a) Exchange-traded Long 221,256 Exchange-traded Short (203,700 ) OTC Short (43,838 ) (a ) 100 percent of the exchange-traded contracts expire in the first quarter of 2016. The following table summarizes the effect of all commodity derivative instruments in our consolidated statements of income: (In millions) Gain (Loss) Income Statement Location 2015 2014 2013 Sales and other operating revenues $ 19 $ 37 $ 12 Cost of revenues 294 456 (180 ) Total $ 313 $ 493 $ (168 )

Debt

Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt	Debt Our outstanding borrowings at December 31, 2015 and 2014 consisted of the following: December 31, (In millions) 2015 2014 Marathon Petroleum Corporation: Senior notes, 3.500%, due March 2016 $ — $ 750 Bank revolving credit facility due 2017 — — Term loan agreement due 2019 700 700 Senior notes, 2.700% due December 2018 600 — Senior notes, 3.400% due December 2020 650 — Senior notes, 5.125% due March 2021 1,000 1,000 Senior notes, 3.625%, due September 2024 750 750 Senior notes, 6.500%, due March 2041 1,250 1,250 Senior notes, 4.750%, due September 2044 800 800 Senior notes, 5.850% due December 2045 250 — Senior notes, 5.000%, due September 2054 400 400 MPLX LP: MPLX term loan facility due 2019 250 250 MPLX bank revolving credit facility due 2020 877 385 MPLX senior notes, 5.500%, due February 2023 710 — MPLX senior notes, 4.500%, due July 2023 989 — MPLX senior notes, 4.875%, due December 2024 1,149 — MPLX senior notes, 4.000%, due February 2025 500 — MPLX senior notes, 4.875%, due June 2025 1,189 — MarkWest senior notes, 4.500% - 5.500% 63 — Capital lease obligations due 2016-2028 348 372 Trade receivables securitization facility due December 2016 — — Total 12,475 6,657 Unamortized debt issuance costs (a) (51 ) (35 ) Unamortized discount (b) (499 ) (26 ) Fair value adjustments (c) — 6 Amounts due within one year (29 ) (27 ) Total long-term debt due after one year $ 11,896 $ 6,575 (a) We adopted the updated FASB debt issuance cost standard as of June 30, 2015 and applied the changes retrospectively to the prior period presented. We reclassified unamortized debt issuance costs from other noncurrent assets to long-term debt. (b) 2015 includes $465 million discount related to the difference between the fair value and the principal amount of the assumed MarkWest debt. (c) In 2012, we terminated our 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. The $20 million gain on the termination of our interest rate swap agreements was amortized over the remaining life of the 3.50 percent senior notes. As a result of the December 2015 extinguishment of our obligation for the 3.50 percent senior notes, the remaining unamortized gain was credited to net interest and other financial income (costs). The following table shows five years of scheduled debt payments. (In millions) 2016 $ 29 2017 28 2018 630 2019 977 2020 1,560 MPC Bank Revolving Credit Facility We have a $2.5 billion unsecured bank revolving credit facility (“revolving credit facility”) in place with a maturity date of September 14, 2017. Our revolving credit facility includes letter of credit issuing capacity of up to $2.0 billion and swingline loan capacity of up to $100 million . We may increase our borrowing capacity under our revolving credit facility by up to an additional $500 million , subject to certain conditions including the consent of the lenders whose commitments would be increased. In addition, the maturity date may be extended for up to two additional one -year periods subject to the approval of lenders holding greater than 50 percent of the commitments then outstanding, provided that the commitments of any non-consenting lenders will terminate on the then-effective maturity date. Borrowings under our revolving credit facility bear interest, at our election, at either the Adjusted LIBO Rate (as defined in our revolving credit facility) plus a margin or the Alternate Base Rate (as defined in our revolving credit facility), plus a margin . We are charged various fees and expenses in connection with our revolving credit facility, including administrative agent fees, commitment fees on the unused portion of our borrowing capacity and fees related to issued and outstanding letters of credit. The applicable margin to the benchmark interest rates and the margin to the benchmark commitment fees payable under our revolving credit facility fluctuate from time-to-time based on our credit ratings. Our revolving credit facility contains certain representations and warranties, affirmative and restrictive covenants and events of default that we consider to be usual and customary for arrangements of this type, including a financial covenant that requires us to maintain a ratio of Consolidated Net Debt to Total Capitalization (each as defined in our revolving credit facility) of no greater than 0.65 to 1.00 as of the last day of each fiscal quarter. Other covenants, among other things, restrict our ability to incur debt, create liens on our assets or enter into transactions with affiliates. As of December 31, 2015 , we were in compliance with the covenants contained in the revolving credit facility. There were no borrowings or letters of credit outstanding at December 31, 2015 . MPC Term Loan Agreement On August 26, 2014 , we entered into a $700 million five -year senior unsecured term loan credit agreement (“term loan agreement”) with a syndicate of lenders to fund a portion of the purchase price for the acquisition of Hess’ Retail Operations and Related Assets. The term loan was drawn in full on September 24, 2014. The term loan agreement matures on September 24, 2019 and may be prepaid at any time without premium or penalty. We pay certain customary fees under the term loan agreement, including an annual administrative fee to the administrative agent. Borrowings under the term loan agreement bear interest, at our election, at either the Adjusted LIBO Rate (as defined in the term loan agreement) plus a margin or the Alternate Base Rate (as defined in the term loan agreement) plus a margin . The applicable margin to the benchmark interest rates fluctuate from time-to-time based on our credit ratings. The borrowings under this facility during 2015 were at an average interest rate of 1.3 percent . The term loan agreement contains representation and warranties, affirmative and negative covenants and events of default that are substantially similar to those contained in our revolving credit facility, which we consider to be usual and customary for an agreement of this type. Among other things, our term loan agreement requires us to maintain, as of the last day of each fiscal quarter, a ratio of Consolidated Net Debt to Total Capitalization (as defined in the term loan agreement) of no greater than 0.65 to 1.00. As of December 31, 2015 , we were in compliance with the covenants contained in the term loan agreement. MPC Senior Notes On December 14, 2015, we completed a public offering of $1.5 billion in aggregate principal amount of unsecured senior notes (“MPC senior notes”), consisting of $600 million aggregate principal amount of senior notes due 2018, $650 million aggregate principal amount of senior notes due 2020 and $250 million aggregate principal amount of senior notes due 2045. The net proceeds from the offering of the MPC senior notes were $1.49 billion , after deducting underwriting discounts and offering expenses. We used a majority of the net proceeds from this offering to fund the extinguishment of our obligation for the $750 million aggregate principal amount of our 3.500% senior notes due 2016. During December 2015, $763 million was deposited with the trustee and under the terms of the senior notes indenture we relieved our obligation related to these notes, including principal and interest to the maturity date. As a result, we recorded a loss on extinguishment of debt of $5 million . We intend to use the remaining net proceeds for general corporate purposes, which may include investments in and advances to our affiliates and subsidiaries, including MPLX. Interest on each series of MPC senior notes is payable semi-annually in arrears on June 15 and December 15, commencing on June 15, 2016. The MPC senior notes are unsecured and unsubordinated obligations of ours and rank equally with all our other existing and future unsecured and unsubordinated indebtedness. MPLX Credit Agreement MPLX is party to a credit agreement, dated as of November 20, 2014, and amended as of October 27, 2015 (“MPLX credit agreement”), providing for a $2 billion bank revolving credit facility with a maturity date of December 4, 2020 and an outstanding $250 million term loan facility with a maturity date of November 20, 2019 . The MPLX credit agreement includes letter of credit issuing capacity of up to $250 million and swingline loan capacity of up to $100 million . The revolving borrowing capacity under the MPLX credit agreement may be increased by up to an additional $500 million , subject to certain conditions, including the consent of the lenders whose commitments would increase. In addition, the maturity date of the bank revolving credit facility may be extended up from time-to-time during its term to a date that is one year after the then-effective maturity date, subject to the approval of lenders holding the majority of the loans and commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the then-effective maturity date. The maturity date for the term loan facility may be extended for up to two additional one -year periods subject to the consent of the lenders holding a majority of the outstanding term loan borrowings, provided that the portion of the term loan borrowings held by any non-consenting lenders will continue to be due and payable on the then-effective maturity date. The borrowings under this facility during 2015 were at an average interest rate of 1.7 percent . Borrowings under the MPLX credit agreement bear interest, at our election, at the Adjusted LIBO Rate or the Alternate Base Rate (as defined in the MPLX credit agreement) plus a specified margin. MPLX is charged various fees and expenses in connection with the agreement, including administrative agent fees, commitment fees on the unused portion of the borrowing capacity and fees with respect to issued and outstanding letters of credit. The applicable margins to the benchmark interest rates and the commitment fees payable under the MPLX credit agreement fluctuate from time-to-time based on MPLX’s credit ratings. The MPLX credit agreement includes certain representations and warranties, affirmative and restrictive covenants and events of default that we consider to be usual and customary for an agreement of this type, including a financial covenant that requires MPLX to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA (both as defined in the MPLX credit agreement) for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 for up to two fiscal quarters following certain acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period. Other covenants, among other things, restrict MPLX and certain of its subsidiaries from incurring debt, creating liens on its assets and entering into transactions with affiliates. As of December 31, 2015 , MPLX was in compliance with the covenants contained in the MPLX credit agreement. In connection with the closing of the MarkWest Merger, MarkWest’s existing credit facility was terminated and the approximately $943 million outstanding under MarkWest’s bank revolving credit facility was repaid with $850 million of borrowings under MPLX’s bank revolving credit facility and $93 million in cash. During 2015 , MPLX borrowed $992 million under the bank revolving credit facility, at an average interest rate of 1.6 percent , per annum, and repaid $500 million of these borrowings. At December 31, 2015 , MPLX had $877 million of borrowings and $8 million of letters of credit outstanding under the bank revolving credit facility, resulting in total unused loan availability of $1.1 billion . MPLX and MarkWest Senior Notes In connection with the MarkWest Merger, MPLX assumed MarkWest’s outstanding debt, which included $4.1 billion aggregate principal amount of senior notes. On December 22, 2015, approximately $4.04 billion aggregate principal amount of MarkWest’s outstanding senior notes were exchanged for an aggregate principal amount of approximately $4.04 billion of new unsecured senior notes issued by MPLX and cash of $1 for each $1,000 of principal amount exchanged in an exchange offer and consent solicitation undertaken by MPLX and MarkWest. The new MPLX senior notes consist of approximately $710 million aggregate principal amount of 5.500% senior notes due February 15, 2023, approximately $989 million aggregate principal amount of 4.500% senior notes due July 15, 2023, approximately $1.15 billion aggregate principal amount of 4.875% senior notes due December 1, 2024 and approximately $1.19 billion aggregate principal amount of 4.875% senior notes due June 1, 2025. Interest on each series of new MPLX senior notes is payable semi-annually in arrears on February 15 th and August 15 th of each year with respect to the 5.500% 2023 senior notes, on January 15 th and July 15 th of each year with respect to the 4.500% 2023 senior notes and on June 1 st and December 1 st of each year with respect to the 4.875% 2024 senior notes and the 4.875% 2025 senior notes. After giving effect to the exchange offer and consent solicitation referred to above, as of December 31, 2015, MarkWest had outstanding approximately $40 million aggregate principal amount of 5.500% senior notes due February 15, 2023, approximately $11 million aggregate principal amount of 4.500% senior notes due July 15, 2023, approximately $1 million aggregate principal amount of 4.875% senior notes due December 1, 2024 and approximately $11 million aggregate principal amount of 4.875% senior notes due June 1, 2025. Interest on each series of the MarkWest senior notes is payable semi-annually in arrears on February 15 th and August 15 th of each year with respect to the 5.500% 2023 senior notes, on January 15 th and July 15 th of each year with respect to the 4.500% 2023 senior notes and on June 1 st and December 1 st of each year with respect to the 4.875% 2024 senior notes and the 4.875% 2025 senior notes. The new MPLX notes are unsecured senior obligations of MPLX and rank equally in right of payment with all of its other senior unsecured debt and are structurally subordinate to the secured and unsecured debt of MPLX’s subsidiaries, including any debt of MarkWest that remains outstanding. On February 12, 2015, MPLX completed a public offering of $500 million aggregate principal amount of four percent unsecured senior notes due February 15, 2025 . The net proceeds, which were approximately $495 million after deducting underwriting discounts, were used to repay the amounts outstanding under the MPLX bank revolving credit facility, as well as for general partnership purposes. Interest is payable semi-annually in arrears on February 15 th and August 15 th of each year. Trade Receivables Securitization Facility On December 18, 2013, we entered into a three -year, $1.3 billion trade receivables securitization facility (“trade receivables facility”), with a group of financial institutions that act as committed purchasers, conduit purchasers, letter of credit issuers and managing agents under the trade receivables facility. The trade receivables facility is evidenced by a Receivables Purchase Agreement and a Second Amended and Restated Receivables Sale Agreement. In October 2015, we reduced the maximum capacity under the trade receivables facility from $1.3 billion to $1.0 billion . The trade receivables facility consists of one of our wholly-owned subsidiaries, Marathon Petroleum Company LP (“MPC LP”), selling or contributing on an on-going basis all of its trade receivables (including trade receivables acquired from Marathon Petroleum Trading Canada LLC, a wholly-owned subsidiary of MPC LP), together with all related security and interests in the proceeds thereof, without recourse, to another wholly-owned, bankruptcy-remote special purpose subsidiary, MPC Trade Receivables Company LLC (“TRC”), in exchange for a combination of cash, equity or a subordinated note issued by TRC to MPC LP. TRC, in turn, has the ability to finance its purchase of the receivables from MPC LP by selling undivided ownership interests in qualifying trade receivables, together with all related security and interests in the proceeds thereof, without recourse, to the purchasing group in exchange for cash proceeds. The trade receivables facility also provides for the issuance of letters of credit up to $1.0 billion , provided that the aggregate credit exposure of the purchasing group, including outstanding letters of credit, may not exceed the lessor of $1.0 billion or the balance of our eligible trade receivables at any one time. To the extent that TRC retains an ownership interest in the receivables it has purchased or received from MPC LP, such interest will be included in our consolidated financial statements solely as a result of the consolidation of the financial statements of TRC with those of MPC. The receivables sold or contributed to TRC are available first and foremost to satisfy claims of the creditors of TRC and are not available to satisfy the claims of creditors of MPC. TRC has granted a security interest in all of its assets to the purchasing group to secure its obligations under the Receivables Purchase Agreement. Proceeds from the sale of undivided percentage ownership interests in qualifying receivables under the trade receivables facility will be reflected as debt on our consolidated balance sheet. We will remain responsible for servicing the receivables sold to the purchasing group. TRC pays floating-rate interest charges and usage fees on amounts outstanding under the trade receivables facility, if any, and certain other fees related to the administration of the facility and letters of credit that are issued and outstanding under the trade receivables facility. The Receivables Purchase Agreement and Second Amended and Restated Receivables Sale Agreement include representations and covenants that we consider usual and customary for arrangements of this type. Trade receivables are subject to customary criteria, limits and reserves before being deemed to qualify for sale by TRC pursuant to the trade receivables facility. In addition, further purchases of qualified trade receivables under the trade receivables facility are subject to termination, and TRC may be subject to default fees, upon the occurrence of certain amortization events that are included in the Receivables Purchase Agreement, which we consider to be usual and customary for arrangements of this type. At December 31, 2015 , we were in compliance with the covenants contained in the Receivables Purchase Agreement and Second Amended and Restated Receivables Sale Agreement. As of December 31, 2015 , eligible trade receivables supported borrowings and letter of credit issuances of $668 million . There were no borrowings or letters of credit outstanding under the trade receivables facility at December 31, 2015 .

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Supplemental Cash Flow Information	Supplemental Cash Flow Information (In millions) 2015 2014 2013 Net cash provided by operating activities included: Interest paid (net of amounts capitalized) $ 272 $ 166 $ 161 Net income taxes paid to taxing authorities 1,605 1,362 1,099 Non-cash investing and financing activities: Capital lease obligations increase $ 1 $ — $ 61 Property, plant and equipment sold 5 4 43 Property, plant and equipment acquired 5 4 — Acquisition: Fair value of MPLX units issued (a) 7,326 — — Payable to MPLX Class B unitholders 50 — — Contingent consideration — — 600 Payable to seller — — 6 (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: (In millions) 2015 2014 2013 Additions to property, plant and equipment per consolidated statements of cash flows $ 1,998 $ 1,480 $ 1,206 Non-cash additions to property, plant and equipment 5 4 — Asset retirement expenditures (a) 1 2 — Increase in capital accruals 94 95 73 Total capital expenditures before acquisitions 2,098 1,581 1,279 Acquisitions (b) 11,397 2,744 1,386 Total capital expenditures $ 13,495 $ 4,325 $ 2,665 (a) Included in All other, net – Operating activities on the consolidated statements of cash flows. (b) The 2015 acquisitions include the MarkWest Merger. The 2014 acquisitions include the acquisition of Hess’ Retail Operations and Related Assets. The 2013 acquisitions include the acquisition of the Galveston Bay Refinery and Related Assets. The acquisition numbers above include property, plant and equipment, intangibles and goodwill. See Note 5 .

Accumulated Other Comprehensive

Accumulated Other Comprehensive Loss	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss The following table shows the changes in accumulated other comprehensive loss by component. Amounts in parentheses indicate debits. (In millions) Pension Benefits Other Benefits Gain on Cash Flow Hedge Workers Compensation Total Balance as of December 31, 2013 $ (161 ) $ (50 ) $ 4 $ 3 $ (204 ) Other comprehensive income (loss) before reclassifications (119 ) (53 ) — 2 (170 ) Amounts reclassified from accumulated other comprehensive loss: Amortization – prior service credit (a) (46 ) (4 ) — — (50 ) – actuarial loss (a) 51 2 — — 53 – settlement loss (a) 96 — — — 96 Other (b) — — — (1 ) (1 ) Tax effect (38 ) 1 — — (37 ) Other comprehensive income (loss) (56 ) (54 ) — 1 (109 ) Balance as of December 31, 2014 $ (217 ) $ (104 ) $ 4 $ 4 $ (313 ) (In millions) Pension Benefits Other Benefits Gain on Cash Flow Hedge Workers Compensation Total Balance as of December 31, 2014 $ (217 ) $ (104 ) $ 4 $ 4 $ (313 ) Other comprehensive income (loss) before reclassifications (44 ) 31 — (1 ) (14 ) Amounts reclassified from accumulated other comprehensive loss: Amortization – prior service credit (a) (46 ) (4 ) — — (50 ) – actuarial loss (a) 51 8 — — 59 – settlement loss (a) 4 — — — 4 Tax effect (3 ) (1 ) — — (4 ) Other comprehensive income (loss) (38 ) 34 — (1 ) (5 ) Balance as of December 31, 2015 $ (255 ) $ (70 ) $ 4 $ 3 $ (318 ) (a) These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 22 . (b) This amount was reclassified out of accumulated other comprehensive loss and is included in selling, general and administrative expenses on the consolidated statements of income.

Defined Benefit Pension and Oth

Defined Benefit Pension and Other Postretirement Plans	12 Months Ended
	Dec. 31, 2015
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Defined Benefit Pension and Other Postretirement Plans	Defined Benefit Pension and Other Postretirement Plans We have noncontributory defined benefit pension plans covering substantially all employees. Benefits under these plans have been based primarily on age, years of service and final average pensionable earnings. The years of service component of this formula was frozen as of December 31, 2009. Benefits for service beginning January 1, 2010 are based on a cash balance formula with an annual percentage of eligible pay credited based upon age and years of service. Eligible Speedway employees accrue benefits under a defined contribution plan for service years beginning January 1, 2010. We also have other postretirement benefits covering most employees. Health care benefits are provided through comprehensive hospital, surgical and major medical benefit provisions subject to various cost-sharing features. Retiree life insurance benefits are provided to a closed group of retirees. Other postretirement benefits are not funded in advance. Obligations and funded status – The accumulated benefit obligation for all defined benefit pension plans was $1,918 million and $2,009 million as of December 31, 2015 and 2014 . The following summarizes our defined benefit pension plans that have accumulated benefit obligations in excess of plan assets. December 31, (In millions) 2015 2014 Projected benefit obligations $ 1,997 $ 2,075 Accumulated benefit obligations 1,918 2,009 Fair value of plan assets 1,570 1,744 The following summarizes the projected benefit obligations and funded status for our defined benefit pension and other postretirement plans: Pension Benefits Other Benefits (In millions) 2015 2014 2015 2014 Change in benefit obligations: Benefit obligations at January 1 $ 2,075 $ 1,927 $ 812 $ 687 Service cost 101 88 31 27 Interest cost 71 74 32 33 Actuarial (gain) loss (63 ) 257 (63 ) 86 Benefits paid (187 ) (271 ) (24 ) (23 ) Other (a) — — 12 2 Benefit obligations at December 31 1,997 2,075 800 812 Change in plan assets: Fair value of plan assets at January 1 1,744 1,800 — — Actual return on plan assets (33 ) 175 — — Employer contributions 46 40 — — Benefits paid from plan assets (187 ) (271 ) — — Fair value of plan assets at December 31 1,570 1,744 — — Funded status of plans at December 31 $ (427 ) $ (331 ) $ (800 ) $ (812 ) Amounts recognized in the consolidated balance sheets: Current liabilities $ (19 ) $ (17 ) $ (29 ) $ (27 ) Noncurrent liabilities (408 ) (314 ) (771 ) (785 ) Accrued benefit cost $ (427 ) $ (331 ) $ (800 ) $ (812 ) Pretax amounts recognized in accumulated other comprehensive loss: (b) Net loss $ 723 $ 710 $ 120 $ 191 Prior service credit (323 ) (369 ) (9 ) (26 ) (a) Includes adjustments related to the MarkWest Merger in 2015 and the acquisition of Hess’ Retail Operations and Related Assets in 2014. (b) Amounts exclude those related to LOOP and Explorer, equity method investees with defined benefit pension and postretirement plans for which net losses of $19 million and $2 million were recorded in accumulated other comprehensive loss in 2015 , reflecting our ownership share. Components of net periodic benefit cost and other comprehensive loss – The following summarizes the net periodic benefit costs and the amounts recognized as other comprehensive loss for our defined benefit pension and other postretirement plans. Pension Benefits Other Benefits (In millions) 2015 2014 2013 2015 2014 2013 Components of net periodic benefit cost: Service cost $ 101 $ 88 $ 93 $ 31 $ 27 $ 25 Interest cost 71 74 73 32 33 26 Expected return on plan assets (98 ) (107 ) (107 ) — — — Amortization – prior service credit (46 ) (46 ) (45 ) (4 ) (4 ) (4 ) – actuarial loss 51 51 66 8 2 3 – settlement loss 4 96 95 — — — Net periodic benefit cost (a) $ 83 $ 156 $ 175 $ 67 $ 58 $ 50 Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax): Actuarial (gain) loss $ 69 $ 188 $ (317 ) $ (63 ) $ 86 $ 17 Prior service cost (credit) (b) — — — 13 — 4 Amortization of actuarial loss (55 ) (147 ) (161 ) (8 ) (2 ) (3 ) Amortization of prior service cost 46 46 45 4 4 4 Other — — — — — — Total recognized in other comprehensive loss $ 60 $ 87 $ (433 ) $ (54 ) $ 88 $ 22 Total recognized in net periodic benefit cost and other comprehensive loss $ 143 $ 243 $ (258 ) $ 13 $ 146 $ 72 (a) Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years. (b) Includes adjustments related to the MarkWest Merger in 2015, plan amendments approved in 2013 and adjustments due to changes made to the defined pension plans and the post-65 medical plan coverage effective January 1, 2013. Lump sum payments to employees retiring in 2015 , 2014 and 2013 exceeded the plan’s total service and interest costs expected for those years. Settlement losses are required to be recorded when lump sum payments exceed total service and interest costs. As a result, pension settlement expenses were recorded in 2015 , 2014 and 2013 related to our cumulative lump sum payments made during those years. The estimated net gain/loss and prior service credit for our defined benefit pension plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2016 are $38 million and $46 million . The estimated net loss and prior service credit for our other defined benefit postretirement plans that will be amortized from accumulated other comprehensive loss into net periodic benefit cost in 2016 is $3 million and $3 million , respectively. Plan assumptions – The following summarizes the assumptions used to determine the benefit obligations at December 31, and net periodic benefit cost for the defined benefit pension and other postretirement plans for 2015 , 2014 and 2013 . Pension Benefits Other Benefits 2015 2014 2013 2015 2014 2013 Weighted-average assumptions used to determine benefit obligation: Discount rate 4.00 % 3.65 % 4.30 % 4.50 % 4.15 % 4.95 % Rate of compensation increase 3.70 % 3.70 % 3.70 % 3.70 % 3.70 % 3.70 % Weighted-average assumptions used to determine net periodic benefit cost: Discount rate 3.70 % 4.05 % 3.88 % 4.30 % 4.95 % 4.11 % Expected long-term return on plan assets (a) 6.75 % 7.00 % 7.50 % — % — % — % Rate of compensation increase 3.70 % 3.70 % 5.00 % 3.70 % 3.70 % 5.00 % (a) Effective January 1, 2016, the expected long-term rate of return on plan assets is 6.50 percent due to a continuation of a change in our primary plan investment strategy, which began January 1, 2014. Expected long-term return on plan assets The overall expected long-term return on plan assets assumption is determined based on an asset rate-of-return modeling tool developed by a third-party investment group. The tool utilizes underlying assumptions based on actual returns by asset category and inflation and takes into account our asset allocation to derive an expected long-term rate of return on those assets. Capital market assumptions reflect the long-term capital market outlook. The assumptions for equity and fixed income investments are developed using a building-block approach, reflecting observable inflation information and interest rate information available in the fixed income markets. Long-term assumptions for other asset categories are based on historical results, current market characteristics and the professional judgment of our internal and external investment teams. Assumed health care cost trend The following summarizes the assumed health care cost trend rates. December 31, 2015 2014 2013 Health care cost trend rate assumed for the following year: Medical: Pre-65 7.50 % 8.00 % 8.00 % Prescription drugs 7.00 % 7.00 % 7.00 % Rate to which the cost trend rate is assumed to decline (the ultimate trend rate): Medical: Pre-65 5.00 % 5.00 % 5.00 % Prescription drugs 5.00 % 5.00 % 5.00 % Year that the rate reaches the ultimate trend rate: Medical: Pre-65 2021 2021 2020 Prescription drugs 2021 2021 2018 Effective 2013, as a result of changes in the post-65 medical plan coverage of the Marathon Petroleum Health Plan and the Marathon Petroleum Retiree Health Plan, increases are the lower of the trend rate or four percent . Assumed health care cost trend rates have a significant effect on the amounts reported for defined benefit retiree health care plans. A one percentage point change in assumed health care cost trend rates would have the following effects: 1-Percentage- 1-Percentage- (In millions) Point Increase Point Decrease Effect on total of service and interest cost components $ 6 $ (5 ) Effect on other postretirement benefit obligations 45 (39 ) Plan investment policies and strategies The investment policies for our pension plan assets reflect the funded status of the plans and expectations regarding our future ability to make further contributions. Long-term investment goals are to: (1) manage the assets in accordance with the legal requirements of all applicable laws; (2) diversify plan investments across asset classes to achieve an optimal balance between risk and return and between income and growth of assets through capital appreciation; and (3) source benefit payments primarily through existing plan assets and anticipated future returns. The investment goals are implemented to manage the plans’ funded status volatility and minimize future cash contributions. The asset allocation strategy will change over time in response to changes primarily in funded status, which is dictated by current and anticipated market conditions, the independent actions of our investment committee, required cash flows to and from the plans and other factors deemed appropriate. Such changes in asset allocation are intended to allocate additional assets to the fixed income asset class should the funded status improve. The fixed income asset class shall be invested in such a manner that its interest rate sensitivity correlates highly with that of the plans’ liabilities. Other asset classes are intended to provide additional return with associated higher levels of risk. Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies. At December 31, 2015 , the primary plan’s targeted asset allocation was 51 percent equity, private equity, real estate, and timber securities and 49 percent fixed income securities. Fair value measurements Plan assets are measured at fair value. The following provides a description of the valuation techniques employed for each major plan asset category at December 31, 2015 and 2014 . Cash and cash equivalents – Cash and cash equivalents include a collective fund serving as the investment vehicle for the cash reserves and cash held by third-party investment managers. The collective fund is valued at net asset value (“NAV”) on a scheduled basis using a cost approach, and is considered a Level 2 asset. Cash and cash equivalents held by third-party investment managers are valued using a cost approach and are considered Level 2. Equity – Equity investments includes common stock, mutual and pooled funds. Common stock investments are valued using a market approach, which are priced daily in active markets and are considered Level 1. Mutual and pooled equity funds are well diversified portfolios, representing a mix of strategies in domestic, international and emerging market strategies. Mutual funds are publicly registered, valued at NAV on a daily basis using a market approach and are considered Level 1 assets. Pooled funds are valued at NAV using a market approach and are considered Level 2 assets. Fixed Income – Fixed income investments include corporate bonds, U.S. dollar treasury bonds and municipal bonds. These securities are priced on observable inputs using a combination of market, income and cost approaches. These securities are considered Level 2 assets. Fixed income also includes a well diversified bond portfolio structured as a pooled fund. This fund is valued at NAV on a daily basis using a combination of market, income and cost approaches. It is considered a Level 2 asset. Private Equity – Private equity investments include interests in limited partnerships which are valued using information provided by external managers for each individual investment held in the fund. These holdings are considered Level 3. Real Estate – Real estate investments consist of interests in limited partnerships. These holdings are either appraised or valued using investment manager’s assessment of assets held. These holdings are considered Level 3. Other – Other investments include two limited liability companies (“LLCs”) with no public market. The LLCs were formed to acquire timberland in the northwest U.S. These holdings are either appraised or valued using investment manager’s assessment of assets held. These holdings are considered Level 3. Other investments classified as Level 1 include publicly traded depository receipts. The following tables present the fair values of our defined benefit pension plans’ assets, by level within the fair value hierarchy, as of December 31, 2015 and 2014 . December 31, 2015 (In millions) Level 1 Level 2 Level 3 Total Cash and cash equivalents $ — $ 27 $ — $ 27 Equity: Common stocks 57 — — 57 Mutual funds 142 — — 142 Pooled funds — 399 — 399 Fixed income: Corporate — 516 — 516 Government — 103 — 103 Pooled funds — 193 — 193 Private equity — — 62 62 Real estate — — 50 50 Other 2 — 19 21 Total investments, at fair value $ 201 $ 1,238 $ 131 $ 1,570 December 31, 2014 (In millions) Level 1 Level 2 Level 3 Total Cash and cash equivalents $ — $ 29 $ — $ 29 Equity: Common stocks 63 — — 63 Mutual funds 155 — — 155 Pooled funds — 442 — 442 Fixed income: Corporate — 554 — 554 Government — 99 — 99 Pooled funds — 254 — 254 Private equity — — 66 66 Real estate — — 57 57 Other 2 2 21 25 Total investments, at fair value $ 220 $ 1,380 $ 144 $ 1,744 The following is a reconciliation of the beginning and ending balances recorded for plan assets classified as Level 3 in the fair value hierarchy: 2015 (In millions) Private Equity Real Estate Other Total Beginning balance $ 66 $ 57 $ 21 $ 144 Actual return on plan assets: Realized 12 6 — 18 Unrealized (1 ) (3 ) (2 ) (6 ) Purchases 5 5 — 10 Sales (20 ) (15 ) — (35 ) Ending balance $ 62 $ 50 $ 19 $ 131 2014 (In millions) Private Equity Real Estate Other Total Beginning balance $ 57 $ 60 $ 20 $ 137 Actual return on plan assets: Realized 6 4 — 10 Unrealized 6 4 1 11 Purchases 10 5 — 15 Sales (13 ) (16 ) — (29 ) Ending balance $ 66 $ 57 $ 21 $ 144 Cash Flows Contributions to defined benefit plans – Our funding policy with respect to the funded pension plans is to contribute amounts necessary to satisfy minimum pension funding requirements, including requirements of the Pension Protection Act of 2006, plus such additional, discretionary, amounts from time to time as determined appropriate by management. In 2015 , we made pension contributions totaling $35 million . We have no required funding for 2016, but may make voluntary contributions at our discretion. Cash contributions to be paid from our general assets for the unfunded pension and postretirement plans are estimated to be approximately $145 million and $28 million in 2016 . Estimated future benefit payments – The following gross benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated. (In millions) Pension Benefits Other Benefits 2016 $ 185 $ 28 2017 184 32 2018 185 36 2019 183 39 2020 175 43 2021 through 2025 834 253 Contributions to defined contribution plans – We also contribute to several defined contribution plans for eligible employees. Contributions to these plans totaled $94 million , $86 million and $76 million in 2015 , 2014 and 2013 , respectively. Multiemployer Pension Plan We contribute to one multiemployer defined benefit pension plan under the terms of a collective-bargaining agreement that covers some of our union-represented employees. The risks of participating in this multiemployer plan are different from single-employer plans in the following aspects: • Assets contributed to the multiemployer plan by one employer may be used to provide benefits to employees of other participating employers. • If a participating employer stops contributing to the plan, the unfunded obligations of the plan may be borne by the remaining participating employers. • If we choose to stop participating in the multiemployer plan, we may be required to pay that plan an amount based on the underfunded status of the plan, referred to as a withdrawal liability. Our participation in this plan for 2015 , 2014 and 2013 is outlined in the table below. The “EIN” column provides the Employee Identification Number for the plan. The most recent Pension Protection Act zone status available in 2015 and 2014 is for the plan’s year ended December 31, 2013 and December 31, 2012, respectively. The zone status is based on information that we received from the plan and is certified by the plan’s actuary. Among other factors, plans in the red zone are generally less than 65 percent funded. The “FIP/RP Status Pending/Implemented” column indicates a financial improvement plan or a rehabilitation plan has been implemented. The last column lists the expiration date of the collective-bargaining agreement to which the plan is subject. There have been no significant changes that affect the comparability of 2015 , 2014 and 2013 contributions. Our portion of the contributions does not make up more than five percent of total contributions to the plan. Pension Protection Act Zone Status FIP/RP Status Pending/Implemented MPC Contributions In millions ) Surcharge Expiration Date of Collective – Bargaining Pension Fund EIN 2015 2014 2015 2014 2013 Central States, Southeast and Southwest Areas Pension Plan (a) 36-6044243 Red Red Implemented $ 4 $ 4 $ 3 No January 31, 2019 (a) This agreement has a minimum contribution requirement of $291 per week per employee for 2016 . A total of 272 employees participated in the plan as of December 31, 2015 . Multiemployer Health and Welfare Plan We contribute to one multiemployer health and welfare plan that covers both active employees and retirees. Through the health and welfare plan employees receive medical, dental, vision, prescription and disability coverage. Our contributions to this plan totaled $7 million , $6 million and $5 million for 2015 , 2014 and 2013 .

Stock-Based Compensation Plans

Stock-Based Compensation Plans	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation Plans	Stock-Based Compensation Plans Description of the Plans Effective April 26, 2012, our employees and non-employee directors became eligible to receive equity awards under the Marathon Petroleum Corporation 2012 Incentive Compensation Plan (“MPC 2012 Plan”). The MPC 2012 Plan authorizes the Compensation Committee of our board of directors (“Committee”) to grant non-qualified or incentive stock options, stock appreciation rights, stock awards (including restricted stock and restricted stock unit awards), cash awards and performance awards to our employees and non-employee directors. Under the MPC 2012 Plan, no more than 50 million shares of our common stock may be delivered and no more than 20 million shares of our common stock may be the subject of awards that are not stock options or stock appreciation rights. In the sole discretion of the Committee, 20 million shares of our common stock may be granted as incentive stock options. Shares issued as a result of awards granted under these plans are funded through the issuance of new MPC common shares. Prior to April 26, 2012, our employees and non-employee directors were eligible to receive equity awards under the Marathon Petroleum Corporation 2011 Second Amended and Restated Incentive Compensation Plan (“MPC 2011 Plan”). Stock-based awards under the Plans We expense all share-based payments to employees and non-employee directors based on the grant date fair value of the awards over the requisite service period, adjusted for estimated forfeitures. Stock Options – We grant stock options to certain officer and non-officer employees. All of the stock options granted in 2015 fell under the MPC 2012 Plan. Stock options awarded under the MPC 2011 Plan and the MPC 2012 Plan represent the right to purchase shares of our common stock at its fair market value, which is the closing price of MPC’s common stock on the date of grant. Stock options have a maximum term of ten years from the date they are granted, and vest over a requisite service period of three years . We use the Black Scholes option-pricing model to estimate the fair value of stock options granted, which requires the input of subjective assumptions. Restricted Stock and Restricted Stock Units – We grant restricted stock and restricted stock units to employees and non-employee directors. In general, restricted stock and restricted stock units granted to employees vest over a requisite service period of three years . Restricted stock and restricted stock unit awards granted after 2011 to officers are subject to an additional one year holding period after the completion of the three-year requisite service period. Prior to vesting, restricted stock recipients who received grants prior to 2012 have the right to vote such stock and receive dividends at the same time regular shareholders are paid. Restricted stock recipients who received grants in 2012 and after have the right to vote such stock; however, dividends are accrued and will be paid upon vesting. Restricted stock units granted to non-employee directors are considered to vest immediately at the time of the grant for accounting purposes, as they are non-forfeitable, but are not issued until the director’s departure from the board of directors. Restricted stock unit recipients do not have the right to vote such shares and receive dividend equivalents payable upon vesting. The non-vested shares are not transferable and are held by our transfer agent. The fair values of restricted stock are equal to the market price of our common stock on the grant date. Performance Units – We grant performance unit awards to certain officer employees. Performance units are dollar dominated. The target value of all performance units is $1.00 , with actual payout up to $2.00 per unit (up to 200% of target). Performance units issued under the MPC 2012 Plan have a 36 -month requisite service period. The payout value of these awards will be determined by the relative ranking of the total shareholder return (“TSR” ) of MPC common stock compared to the TSR of a select group of peer companies, as well as the Standard & Poor’s 500 Energy Index fund over an average of four measurement periods. These awards will be settled 25 percent in MPC common stock and 75 percent in cash. The number of shares actually distributed will be determined by dividing 25 percent of the final payout by the closing price of MPC common stock on the day the Committee certifies the final TSR rankings, or the next trading day if the certification is made outside of normal trading hours. The performance units paying out in cash are accounted for as liability awards and recorded at fair value with a mark-to-market adjustment made each quarter. The performance units that settle in shares are accounted for as equity awards. Total Stock-Based Compensation Expense The following table reflects activity related to our stock-based compensation arrangements: (In millions) 2015 2014 2013 Stock-based compensation expense $ 42 $ 40 $ 42 Tax benefit recognized on stock-based compensation expense 16 15 15 Cash received by MPC upon exercise of stock option awards 33 26 48 Tax benefit received for tax deductions for stock awards exercised 26 19 18 Stock Option Awards The Black Scholes option-pricing model values used to value stock option awards granted were determined based on the following weighted average assumptions: 2015 2014 2013 Weighted average exercise price per share $ 50.85 $ 42.51 $ 42.32 Expected life in years 6.0 5.8 6.0 Expected volatility 33 % 36 % 40 % Expected dividend yield 2.0 % 1.9 % 2.0 % Risk-free interest rate 1.7 % 1.8 % 1.0 % Weighted average grant date fair value of stock option awards granted $ 13.44 $ 12.69 $ 13.57 The expected life of stock options granted is based on historical data and represents the period of time that options granted are expected to be held prior to exercise. The 2015 assumption for expected volatility of our stock price reflects a weighting of 50 percent of our common stock implied volatility and 50 percent of MPC’s common stock historical volatility. Prior to 2014, we used a weighting of our common stock implied volatility and the historical volatility of a selected group of peers. Expected dividend yield is based on annualized dividends at the date of grant. The risk-free interest rate for periods within the expected life of the option is based on the U.S. Treasury yield curve in effect at the time of the grant. The following is a summary of our common stock option activity in 2015 : Number of of Shares (a) Weighted Average Exercise Price Weighted Average Remaining Contractual Terms (in years) Aggregate Intrinsic Value (in millions) Outstanding at December 31, 2014 9,502,876 $ 22.74 Granted 1,103,684 50.85 Exercised (1,827,245 ) 18.06 Forfeited, canceled or expired (54,684 ) 40.67 Outstanding at December 31, 2015 8,724,631 27.16 Vested and expected to vest at December 31, 2015 8,718,834 27.11 6.0 $ 216 Exercisable at December 31, 2015 6,806,015 21.47 5.0 207 (a) Includes an immaterial number of stock appreciation rights. The intrinsic value of options exercised by MPC employees during 2015 , 2014 and 2013 was $60 million , $48 million and $60 million , respectively. As of December 31, 2015 , unrecognized compensation cost related to stock option awards was $7 million , which is expected to be recognized over a weighted average period of 1.5 years. Restricted Stock Awards The following is a summary of restricted stock award activity of our common stock in 2015 : 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, 2014 1,030,146 $ 38.62 822,186 $ 18.65 Granted 627,135 50.64 81,685 49.87 RS’s Vested/RSU’s Issued (537,020 ) 34.25 (389,801 ) 17.32 Forfeited (45,718 ) 41.41 (850 ) 44.77 Outstanding at December 31, 2015 1,074,543 47.70 513,220 24.59 Of the 513,220 restricted stock units outstanding, 491,287 are vested and have a weighted average grant date fair value of $23.44 . These vested but unissued units are held by our non-employee directors and certain officers, are non-forfeitable and are issuable upon the director’s departure from our board of directors or officers end of employment with the company. The following is a summary of the values related to restricted stock and restricted stock unit awards held by MPC employees and non-employee directors: Restricted Stock Restricted Stock Units Intrinsic Value of Awards Vested During the Period (in millions) Weighted Average Grant Date Fair Value of Awards Granted During the Period Intrinsic Value of Awards Vested During the Period (in millions) Weighted Average Grant Date Fair Value of Awards Granted During the Period 2015 $ 27 $ 50.64 $ 21 $ 49.87 2014 28 43.82 — 42.95 2013 20 43.53 — 36.74 As of December 31, 2015 , unrecognized compensation cost related to restricted stock awards was $35 million , which is expected to be recognized over a weighted average period of 1.5 years. There was no material unrecognized compensation cost related to restricted stock unit awards. Performance Unit Awards The following table presents a summary of the 2015 activity for performance unit awards to be settled in shares: Number of Units Weighted Average Grant Date Fair Value Outstanding at December 31, 2014 5,791,825 $ 0.88 Granted 2,389,450 0.95 Exercised (2,035,833 ) 0.85 Canceled — — Outstanding at December 31, 2015 6,145,442 0.92 The number of shares that would be issued upon target vesting, using the closing price of our common stock on December 31, 2015 would be 118,546 shares. As of December 31, 2015 , unrecognized compensation cost related to equity-classified performance unit awards was $2 million , which is expected to be recognized over a weighted average period of 1.6 years. Performance units paying out in units have a grant date fair value calculated using a Monte Carlo valuation model, which requires the input of subjective assumptions. The following table provides a summary of these assumptions: 2015 2014 2013 Risk-free interest rate 0.95 % 0.63 % 0.35 % Look-back period 2.84 years 2.84 years 2.84 years Expected volatility 30.38 % 38.51 % 41.67 % Grant date fair value of performance units granted $ 0.95 $ 0.85 $ 0.95 The risk-free interest rate for the remaining performance period as of the grant date is based on the U.S. Treasury yield curve in effect at the time of the grant. The look-back period reflects the remaining performance period at the grant date. The assumption for the expected volatility of our stock price reflects the average MPC common stock historical volatility. MPLX Awards Our wholly-owned subsidiary and the general partner of MPLX, MPLX GP LLC (“MPLX GP”), maintains a unit-based compensation plan for officers, directors and employees (including any other individual who may be considered an “employee” under a Registration Statement on Form S-8 or any successor form) of MPLX GP. The MPLX 2012 Incentive Compensation Plan (“MPLX Plan”) permits various types of equity awards including but not limited to grants of phantom units and performance units. Awards granted under the MPLX Plan will be settled with MPLX units. Compensation expense for these awards were not material to our consolidated financial statements for the years ended December 31, 2015 , 2014 and 2013 .

Leases

Leases	12 Months Ended
	Dec. 31, 2015
Leases [Abstract]
Leases of Lessee Disclosure	Lessee We lease a wide variety of facilities and equipment under operating leases, including land and building space, office equipment, storage facilities and transportation equipment. Most long-term leases include renewal options and, in certain leases, purchase options. Future minimum commitments as of December 31, 2015 , for capital lease obligations and for operating lease obligations having initial or remaining non-cancelable lease terms in excess of one year are as follows: (In millions) Capital Lease Obligations Operating Lease Obligations 2016 $ 53 $ 282 2017 50 212 2018 50 186 2019 45 161 2020 49 138 Later years 251 475 Total minimum lease payments 498 $ 1,454 Less imputed interest costs 150 Present value of net minimum lease payments $ 348 Operating lease rental expense was: (In millions) 2015 2014 2013 Rental expense $ 331 $ 256 $ 213
Leases of Lessor Disclosure	Lessor As a result of the MarkWest Merger, there are certain natural gas gathering, transportation and processing agreements in which MPLX is considered to be the lessor under several implicit operating lease arrangements in accordance with US GAAP. MPLX’s primary implicit lease operations relate to a natural gas gathering agreement in the Marcellus region for which it earns a fixed-fee for providing gathering services to a single producer using a dedicated gathering system. As the gathering system is expanded, the fixed-fee charged to the producer is adjusted to include the additional gathering assets in the lease. The primary term of the natural gas gathering arrangement expires in 2024 and will continue thereafter on a year to year basis until terminated by either party. Other significant implicit leases relate to a natural gas processing agreement in the Marcellus region and a natural gas processing agreement in the Northeast region for which we earn minimum monthly fees for providing processing services to a single producer using a dedicated processing plant. The primary term of these natural gas processing agreements expire during 2023. Our revenue from implicit lease arrangements, excluding executory costs, totaled approximately $16 million in 2015 and nothing in 2014 and 2013. The implicit lease arrangements related to the processing facilities contain contingent rental provisions whereby we receive additional fees if the producer customer exceeds the monthly minimum processed volumes. During the year ended December 31, 2015 , we received less than $1 million in contingent lease payments and none for the year ended December 31, 2014 . The following is a schedule of minimum future rentals on the non‑cancelable operating leases as of December 31, 2015 : (In millions) 2016 $ 174 2017 184 2018 185 2019 186 2020 185 Later years 588 Total minimum lease payments $ 1,502 The following schedule summarizes our investment in assets held for operating lease by major classes as of December 31, 2015 : (In millions) Natural gas gathering and NGL transportation pipelines and facilities $ 619 Natural gas processing facilities 753 Construction in progress 110 Property, plant and equipment 1,482 Less accumulated depreciation 5 Total property, plant and equipment $ 1,477

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. Some of these matters are discussed below. For matters for which we have not recorded an accrued liability, we are unable to estimate a range of possible loss because the issues involved have not been fully developed through pleadings and discovery. However, the ultimate resolution of some of these contingencies could, individually or in the aggregate, be material. Environmental matters – We are subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites and certain other locations including presently or formerly owned or operated retail marketing sites. Penalties may be imposed for noncompliance. At December 31, 2015 and 2014 , accrued liabilities for remediation totaled $163 million and $185 million . It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties if any that may be imposed. Receivables for recoverable costs from certain states, under programs to assist companies in clean-up efforts related to underground storage tanks at presently or formerly owned or operated retail marketing sites, were $70 million and $67 million at December 31, 2015 and 2014 , respectively. We are involved in a number of environmental enforcement matters arising in the ordinary course of business. While the outcome and impact on us cannot be predicted with certainty, management believes the resolution of these environmental matters will not, individually or collectively, have a material adverse effect on our consolidated results of operations, financial position or cash flows. Litigation Relating to the MarkWest Merger —In July 2015, a purported class action lawsuit asserting claims challenging the MarkWest Merger was filed in the Court of Chancery of the State of Delaware by a purported unitholder of MarkWest. In August 2015, two similar putative class action lawsuits were filed in the Court of Chancery of the State of Delaware by plaintiffs who purport to be unitholders of MarkWest. On September 9, 2015, these lawsuits were consolidated into one action pending in the Court of Chancery of the State of Delaware, now captioned In re MarkWest Energy Partners, L.P. Unitholder Litigation . On October 1, 2015, the plaintiffs filed a consolidated complaint against the individual members of the board of directors of MarkWest Energy GP, L.L.C. (the “MarkWest GP Board”), MPLX, MPLX GP, MPC and Sapphire Holdco LLC, a wholly-owned subsidiary of MPLX, asserting in connection with the MarkWest Merger and related disclosures that, among other things, (i) the MarkWest GP Board breached its duties in approving the MarkWest Merger with MPLX and (ii) MPC, MPLX, MPLX GP, and Sapphire Holdco LLC aided and abetted such breaches. On February 4, 2016, the Court approved a stipulation and proposed order to dismiss all claims with prejudice as to the named plaintiffs, but for the Court to retain jurisdiction to adjudicate an application for a mootness fee by the plaintiffs’ counsel for an award of attorneys’ fees and reimbursement of expenses. We intend to vigorously defend against any application for a mootness fee and do not expect the resolution of such matter to have a material adverse effect. MarkWest Environmental Proceeding – On July 6, 2015, officials from the United States Environmental Protection Agency and the United States Department of Justice entered a pipeline launcher/receiver site utilized for pipeline pigging operations in Washington County, Pennsylvania of MarkWest Liberty Midstream & Resources, L.L.C., a wholly-owned subsidiary of MPLX (“MarkWest Liberty Midstream”), pursuant to a search warrant issued by the United States District Court for the Western District of Pennsylvania. At the conclusion of the search, the governmental officials presented MarkWest Liberty Midstream with a subpoena to provide documents related to the design, construction, operation, maintenance, modification, inspection, assessment, repair of, and/or emissions from MarkWest Liberty Midstream’s pipeline facilities located in Pennsylvania. MarkWest Liberty Midstream is providing information in response to the subpoena and related requests for information from the relevant agencies, and is in discussions with the relevant agencies regarding issues associated with the search and subpoena and its operations of, or supplementary permitting obligations for, its pipeline facilities in the Northeast. Immediately following the July 6, 2015 search, MarkWest Liberty Midstream commenced its own assessment of its operations of launcher/receiver facilities. MarkWest Liberty Midstream’s review to date has determined that other than potentially having to obtain minor source permits at a relatively small number of individual sites, MarkWest Liberty Midstream’s operations have been conducted in a manner fully protective of its employees and the public, and in substantial compliance with applicable laws and regulations. It is possible that, in connection with any potential civil or criminal enforcement action associated with this matter, MarkWest Liberty Midstream will incur material assessments, penalties or fines, incur material defense costs and expenses, be required to modify our operations or construction activities which could increase operating costs and capital expenditures, or be subject to other obligations or restrictions that could restrict or prohibit our activities, any or all of which could adversely affect our consolidated results of operations, financial position or cash flows. The amount of any potential assessments, penalties, fines, requirements, modifications, costs or expenses that may be incurred in connection with any potential enforcement action cannot be reasonably estimated at this time. Other Lawsuits – In May 2015, the Kentucky attorney general filed a lawsuit against our wholly-owned subsidiary, MPC LP, in the United States District Court for the Western District of Kentucky asserting claims under federal and state antitrust statutes, the Kentucky Consumer Protection Act, and state common law. The complaint, as amended in July 2015, alleges that MPC LP used deed restrictions, supply agreements with customers and exchange agreements with competitors to unreasonably restrain trade in areas within Kentucky and seeks declaratory relief, unspecified damages, civil penalties, restitution and disgorgement of profits. At this early stage, the ultimate outcome of this litigation remains uncertain, and neither the likelihood of an unfavorable outcome nor the ultimate liability, if any, can be determined, and we are unable to estimate a reasonably possible loss (or range of loss) for this matter. We intend to vigorously defend ourselves in this matter. 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 also a party to a number of other lawsuits and other proceedings arising in the ordinary course of business. While the ultimate outcome and impact to us cannot be predicted with certainty, we believe that the resolution of these other lawsuits and proceedings will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. Guarantees – We have provided certain guarantees, direct and indirect, of the indebtedness of other companies. Under the terms of most of these guarantee arrangements, we would be required to perform should the guaranteed party fail to fulfill its obligations under the specified arrangements. In addition to these financial guarantees, we also have various performance guarantees related to specific agreements. Guarantees related to indebtedness of equity method investees – We hold interests in an offshore oil port, LOOP, and a crude oil pipeline system, LOCAP. Both LOOP and LOCAP have secured various project financings with throughput and deficiency agreements. Under the agreements, we are required to advance funds if the investees are unable to service their debt. Any such advances are considered prepayments of future transportation charges. The duration of the agreements vary but tend to follow the terms of the underlying debt, which extend through 2037 . Our maximum potential undiscounted payments under these agreements for the debt principal totaled $172 million as of December 31, 2015 . We hold an interest in a refined products pipeline through our investment in Centennial, and have guaranteed our portion of 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 $34 million as of December 31, 2015 . In connection with our 50 percent ownership in Crowley Ocean Partners, we have agreed to conditionally guarantee our portion of the obligations of the joint venture and its subsidiaries under a senior secured term loan agreement. The term loan agreement provides for loans of up to $325 million to finance the acquisition of four product tankers. MPC’s liability under the guarantee for each vessel is conditioned upon the occurrence of certain events, including if we cease to maintain an investment grade credit rating or the charter for the relevant product tanker ceases to be in effect and is not replaced by a charter with an investment grade company on certain defined commercial terms. As of December 31, 2015 , our maximum potential undiscounted payments under this agreement for debt principal associated with the first two vessels totaled $81 million . Marathon Oil indemnifications – In conjunction with the Spinoff, we have entered into arrangements with Marathon Oil providing indemnities and guarantees with recorded values of $2 million as of December 31, 2015 , which consist of unrecognized tax benefits related to MPC, its consolidated subsidiaries and the RM&T Business operations prior to the Spinoff which are not already reflected in the unrecognized tax benefits described in Note 12 , and other contingent liabilities Marathon Oil may incur related to taxes. Furthermore, the separation and distribution agreement and other agreements with Marathon Oil to effect the Spinoff provide for cross-indemnities between Marathon Oil and us. In general, Marathon Oil is required to indemnify us for any liabilities relating to Marathon Oil’s historical oil and gas exploration and production operations, oil sands mining operations and integrated gas operations, and we are required to indemnify Marathon Oil for any liabilities relating to Marathon Oil’s historical refining, marketing and transportation operations. The terms of these indemnifications are indefinite and the amounts are not capped. Other guarantees – We have entered into other guarantees with maximum potential undiscounted payments totaling $83 million as of December 31, 2015 , which primarily consist of a commitment to contribute cash to an equity method investee for certain catastrophic events, up to $50 million per event, in lieu of procuring insurance coverage and leases of assets containing general lease indemnities and guaranteed residual values. General guarantees associated with dispositions – Over the years, we have sold various assets in the normal course of our business. Certain of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require us to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling assets. We are typically not able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the underlying triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based. Contractual commitments and contingencies – At December 31, 2015 and 2014 , our contractual commitments to acquire property, plant and equipment and advance funds to equity method investees totaled $1.6 billion and $1.7 billion . The contractual commitments at December 31, 2015 includes $331 million of contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets, $630 million for contributions to North Dakota Pipeline and $69 million for contributions to Crowley Ocean Partners. The contractual commitments at December 31, 2014 included the $520 million contingent consideration associated with the acquisition of the Galveston Bay Refinery and Related Assets, $703 million for contributions to North Dakota Pipeline and $185 million for contributions to Illinois Extension Pipeline. See Note 5 for additional information on our investments on our investments in North Dakota Pipeline, Illinois Extension Pipeline and Crowley Ocean Partners. See Note 17 for additional information on the contingent consideration. Certain natural gas processing and gathering arrangements require us to construct new natural gas processing plants, natural gas gathering pipelines and NGL pipelines and contain certain fees and charges if specified construction milestones are not achieved for reasons other than force majeure. In certain cases, certain producers may have the right to cancel the processing arrangements if there are significant delays that are not due to force majeure. As of December 31, 2015 , management does not believe there are any indications that we will not be able to meet the construction milestones, that force majeure does not apply, or that such fees and charges will otherwise be triggered.

Subsequent Event

Subsequent Event	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Event	Subsequent Event On February 3, 2016, we announced that we have offered to contribute our inland marine business to MPLX in exchange for MPLX securities. The transaction is expected to close in the second quarter of 2016, pending requisite approvals.

Selected Quarterly Financial Da

Selected Quarterly Financial Data	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Selected Quarterly Financial Data	Selected Quarterly Financial Data (Unaudited) 2015 2014 (In millions, except per share data) 1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr. 1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr. Revenues $ 17,191 $ 20,537 $ 18,716 $ 15,607 $ 23,285 $ 26,844 $ 25,438 $ 22,250 Income from operations 1,470 1,335 1,549 338 361 1,369 1,062 1,259 Net income 903 839 958 168 207 864 679 805 Net income attributable to MPC 891 826 948 187 199 855 672 798 Net income attributable to MPC per share: (a) Basic $ 1.63 $ 1.52 $ 1.77 $ 0.35 $ 0.34 $ 1.49 $ 1.19 $ 1.44 Diluted 1.62 1.51 1.76 0.35 0.34 1.48 1.18 1.43 Dividends paid per share 0.25 0.25 0.32 0.32 0.21 0.21 0.25 0.25 (a) We completed a two-for-one stock split in June 2015. All historical per share data has been retroactively restated on a post-split basis.

Supplementary Statistics

Supplementary Statistics	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Supplementary Statistics	Supplementary Statistics (Unaudited) (In millions) 2015 2014 2013 Income from Operations by segment Refining & Marketing (a) $ 4,186 $ 3,609 $ 3,206 Speedway (a) 673 544 375 Midstream (b) 289 280 210 Items not allocated to segments: Corporate and other unallocated items (b) (308 ) (286 ) (271 ) Pension settlement expenses (4 ) (96 ) (95 ) Impairment (144 ) — — Income from operations $ 4,692 $ 4,051 $ 3,425 Capital Expenditures and Investments (c)(d) Refining & Marketing $ 1,143 $ 1,104 $ 2,094 Speedway 501 2,981 296 Midstream 14,447 543 234 Corporate and Other (e) 192 110 165 Total $ 16,283 $ 4,738 $ 2,789 (a) The Refining & Marketing and Speedway segments in 2015 include inventory lower of cost or market charge of $345 million and $25 million , respectively. (b) Included in the Midstream segment for 2015 , 2014 and 2013 are $20 million , $19 million and $20 million of corporate overhead expenses attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. Corporate overhead expenses are not currently allocated to other segments. (c) Capital expenditures include changes in capital accruals. (d) Includes $13.85 billion in 2015 for the MarkWest Merger, $2.71 billion in 2014 for the acquisition of Hess’ Retail Operations and Related Assets and $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5 . (e) Includes capitalized interest of $37 million , $27 million and $28 million for 2015 , 2014 and 2013 , respectively. Supplementary Statistics (Unaudited) 2015 2014 2013 MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day) (a)(b) 2,301 2,138 2,086 Refining & Marketing Operating Statistics (b) Refining & Marketing refined product sales volume (thousands of barrels per day) (c) 2,289 2,125 2,075 Refining & Marketing gross margin (dollars per barrel) (d)(e) $ 15.25 $ 15.05 $ 13.24 Crude oil capacity utilization percent (f) 99 95 96 Refinery throughputs (thousands of barrels per day): (g) Crude oil refined 1,711 1,622 1,589 Other charge and blendstocks 177 184 213 Total 1,888 1,806 1,802 Sour crude oil throughput percent 55 52 53 WTI-priced crude oil throughput percent 20 19 21 Refined product yields (thousands of barrels per day): (g) Gasoline 913 869 921 Distillates 603 580 572 Propane 36 35 37 Feedstocks and special products 281 276 221 Heavy fuel oil 31 25 31 Asphalt 55 54 54 Total 1,919 1,839 1,836 Refinery direct operating costs (dollars per barrel): (h) Planned turnaround and major maintenance $ 1.13 $ 1.80 $ 1.20 Depreciation and amortization 1.39 1.41 1.36 Other manufacturing (i) 4.15 4.86 4.14 Total $ 6.67 $ 8.07 $ 6.70 Refining & Marketing Operating Statistics By Region – Gulf Coast (b) Refinery throughputs (thousands of barrels per day): (j) Crude oil refined 1,060 991 964 Other charge and blendstocks 184 182 195 Total 1,244 1,173 1,159 Sour crude oil throughput percent 68 64 65 WTI-priced crude oil throughput percent 6 3 7 Refined product yields (thousands of barrels per day): (j) Gasoline 534 508 551 Distillates 392 368 365 Propane 26 23 23 Feedstocks and special products 286 274 215 Heavy fuel oil 15 13 19 Asphalt 16 13 13 Total 1,269 1,199 1,186 Refinery direct operating costs (dollars per barrel): (h) Planned turnaround and major maintenance $ 0.81 $ 1.82 $ 1.00 Depreciation and amortization 1.09 1.15 1.09 Other manufacturing (i) 3.88 4.73 3.98 Total $ 5.78 $ 7.70 $ 6.07 Supplementary Statistics (Unaudited) 2015 2014 2013 Refining & Marketing Operating Statistics By Region – Midwest Refinery throughputs (thousands of barrels per day): (j) Crude oil refined 651 631 625 Other charge and blendstocks 39 45 54 Total 690 676 679 Sour crude oil throughput percent 34 33 35 WTI-priced crude oil throughput percent 43 44 42 Refined product yields (thousands of barrels per day): (j) Gasoline 379 361 371 Distillates 211 212 207 Propane 12 13 14 Feedstocks and special products 38 43 41 Heavy fuel oil 17 13 12 Asphalt 39 41 41 Total 696 683 686 Refinery direct operating costs (dollars per barrel): (h) Planned turnaround and major maintenance $ 1.64 $ 1.66 $ 1.47 Depreciation and amortization 1.83 1.78 1.74 Other manufacturing (i) 4.36 4.76 4.21 Total $ 7.83 $ 8.20 $ 7.42 Speedway Operating Statistics (k) Convenience stores at period-end 2,766 2,746 1,478 Gasoline and distillate sales (millions of gallons) 6,038 3,942 3,146 Gasoline & distillate gross margin (dollars per gallon) (e)(l) $ 0.1823 $ 0.1775 $ 0.1441 Merchandise sales (in millions) $ 4,879 $ 3,611 $ 3,135 Merchandise gross margin (in millions) $ 1,368 $ 975 $ 825 Merchandise gross margin percent 28.0 % 27.0 % 26.3 % Same store gasoline sales volume (period over period) (0.3 )% (0.7 )% 0.5 % Same store merchandise sales (period over period) (m) 4.1 % 5.0 % 4.3 % Midstream Operating Statistics Crude oil and refined product pipeline throughputs (thousands of barrels per day) (n) 2,191 2,119 2,204 Gathering system throughput (million cubic feet per day) (o) 3,075 Natural gas processed (million cubic feet per day) (o) 5,468 C2 (ethane) + NGLs (natural gas liquids) fractionated (mbpd) (o) 307 (a) Total average daily volumes of refined product sales to wholesale, branded and retail (Speedway segment) customers. (b) Includes the results of the Galveston Bay Refinery and Related Assets from the February 1, 2013 acquisition date. (c) Includes intersegment sales. (d) Sales revenue less cost of refinery inputs and purchased products, divided by total refinery throughputs. (e) Excludes the lower of cost or market adjustment. (f) Based on calendar day capacity, which is an annual average that includes downtime for planned maintenance and other normal operating activities. (g) Excludes inter-refinery volumes of 46 mbpd, 43 mbpd and 36 mbpd for 2015 , 2014 and 2013 , respectively. (h) Per barrel of total refinery throughputs. (i) Includes utilities, labor, routine maintenance and other operating costs. (j) Includes inter-refinery transfer volumes. (k) Includes the impact of Hess’ Retail Operations and Related Assets from the September 30, 2014 acquisition date. (l) 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. (m) Excludes cigarettes. Same store comparison includes only locations owned at least 13 months. (n) On owned common-carrier pipelines, excluding equity method investments. (o) Includes amounts related to unconsolidated equity method investments. Includes the results of the MarkWest assets beginning on the Dec. 4, 2015 acquisition date.

Summary Of Principal Accounti38

Summary Of Principal Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Principles applied in consolidation	Principles applied in consolidation – These consolidated financial statements include the accounts of our majority-owned, controlled subsidiaries and MPLX. Changes in ownership interest in consolidated subsidiaries that do not result in a change in control are recorded as an equity transaction. We own 20.4 percent of MPLX, including the two percent general partner interest. Due to our 100 percent ownership of the general partner interest, we have determined that we control MPLX and therefore we consolidate MPLX and record a noncontrolling interest for the 79.6 percent interest owned by the public. Investments in entities over which we have significant influence, but not control, are accounted for using the equity method of accounting. This includes entities in which we hold majority ownership but the minority shareholders have substantive participating rights. Income from equity method investments represents our proportionate share of net income generated by the equity method investees. Equity method investments are generally carried at our share of net assets plus loans and advances. Such investments are assessed for impairment whenever changes in the facts and circumstances indicate an other than temporary loss in value has occurred. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net income. Differences in the basis of the investments and the separate net asset values of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets and liabilities, except for the excess related to goodwill.
Use of estimates	Use of estimates – The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods.
Revenue recognition	Revenue recognition – Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. Costs associated with revenues are recorded in cost of revenues. Shipping and other transportation costs billed to our customers are presented on a gross basis in revenues and cost of revenues. Rebates from vendors are recognized as a reduction of cost of revenues when the initiating transaction occurs. Incentives that are derived from contractual provisions are accrued based on past experience and recognized in cost of revenues. Rebates to customers are reflected as a reduction of revenue and are accrued for in accounts payable on the consolidated balance sheets.
Crude oil and refined product exchanges and matching buy/sell transactions	Crude oil and refined product exchanges and matching buy/sell transactions – We enter into exchange contracts and matching buy/sell arrangements whereby we agree to deliver a particular quantity and quality of crude oil or refined products at a specified location and date to a particular counterparty and to receive from the same counterparty the same commodity at a specified location on the same or another specified date. The exchange receipts and deliveries are nonmonetary transactions, with the exception of associated grade or location differentials that are settled in cash. The matching buy/sell purchase and sale transactions are settled in cash. Both exchange and matching buy/sell transactions are accounted for as exchanges of inventory and no revenues are recorded. The exchange transactions are recognized at the carrying amount of the inventory transferred.
Consumer excise taxes	Consumer excise taxes – We are required by various governmental authorities, including countries, states and municipalities, to collect and remit taxes on certain consumer products. Such taxes are presented on a gross basis in revenues and costs and expenses in the consolidated statements of income.
Cash and cash equivalents	Cash and cash equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with maturities of three months or less.
Restricted cash	Restricted cash – Restricted cash consists of cash and investments that must be maintained as collateral for letters of credit issued to certain third party producer customers. The balances will be outstanding until certain capital projects are completed and the third party releases the restriction. Restricted cash also consists of cash advances to be used for the operation and maintenance of an operated pipeline system. At December 31, 2015 and 2014 , the amount of restricted cash included in other current assets on the consolidated balance sheets were $9 million and $4 million , which is currently reflected in our Midstream segment
Accounts receivable and allowance for doubtful accounts	Accounts receivable and allowance for doubtful accounts – Our receivables primarily consist of customer accounts receivable. Customer receivables are recorded at the invoiced amounts and generally do not bear interest. Allowances for doubtful accounts are generally recorded when it becomes probable the receivable will not be collected and are booked to bad debt expense. The allowance for doubtful accounts is the best estimate of the amount of probable credit losses in customer accounts receivable and is based on historical write-off experience. We review the allowance quarterly and past-due balances over 180 days are reviewed individually for collectability. Approximately 26 percent and 41 percent of our accounts receivable balances at December 31, 2015 and 2014 , respectively, are related to sales of crude oil or refinery feedstocks to customers with whom we have master netting agreements. We have master netting agreements with more than 100 companies engaged in the crude oil or refinery feedstock trading and supply business or the petroleum refining industry. A master netting agreement generally provides for a once per month net cash settlement of the accounts receivable from and the accounts payable to a particular counterparty.
Inventories	Inventories – Inventories are carried at the lower of cost or market value. Cost of inventories is determined primarily under the LIFO method. Costs for crude oil, refinery feedstocks and refined product inventories are aggregated on a consolidated basis for purposes of assessing if the LIFO cost basis of these inventories may have to be written down to market value.
Derivative instruments	Derivative instruments – We use derivatives to economically hedge a portion of our exposure to commodity price risk and, historically, to interest rate risk. We also have limited authority to use selective derivative instruments that assume market risk. All derivative instruments (including derivative instruments embedded in other contracts) are recorded at fair value. Commodity derivatives are reflected on the consolidated balance sheets on a net basis by counterparty as they are governed by master netting agreements. Cash flows related to derivatives used to hedge commodity price risk and interest rate risk are classified in operating activities with the underlying transactions. Fair value accounting hedges – We used interest rate swaps to hedge our exposure to interest rate risk associated with fixed interest rate debt in our portfolio. These interest rate swap agreements were terminated in 2012. Changes in the fair values of both the hedged item and the related derivative were recognized immediately in net income with an offsetting effect included in the basis of the hedged item. The net effect was to report in net income the extent to which the accounting hedge was not effective in achieving offsetting changes in fair value. There was a gain on the termination of the agreements, which has been accounted for as an adjustment to our long-term debt balance. The gain was being amortized over the remaining life of the associated debt as a reduction of our interest expense, until the December 2015 extinguishment of our obligation for the associated debt. At such time, the remaining unamortized gain was credited to net interest and other financial income (costs). 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, (4) the acquisition of ethanol for blending with refined products, (5) the sale of NGLs, (6) the purchase of natural gas and (6) the purchase of electricity. Changes in the fair value of derivatives not designated as accounting hedges are recognized immediately in net income. Concentrations of credit risk – All of our financial instruments, including derivatives, involve elements of credit and market risk. The most significant portion of our credit risk relates to nonperformance by counterparties. The counterparties to our financial instruments consist primarily of major financial institutions and companies within the energy industry. To manage counterparty risk associated with financial instruments, we select and monitor counterparties based on an assessment of their financial strength and on credit ratings, if available. Additionally, we limit the level of exposure with any single counterparty.
Property, plant and equipment	Property, plant and equipment – Property, plant and equipment are recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets, which range from two to 42 years. Such assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. When items of property, plant and equipment are sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale. Interest expense is capitalized for qualifying assets under construction. Capitalized interest costs are included in property, plant and equipment and are depreciated over the useful life of the related asset.
Goodwill and intangible assets	Goodwill and intangible assets – Goodwill represents the excess of the purchase price over the estimated fair value of the net assets acquired in the acquisition of a business. Goodwill is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate that the fair value of a reporting unit with goodwill has been reduced below carrying value. The impairment test requires allocating goodwill and other assets and liabilities to reporting units. The fair value of each reporting unit is determined and compared to the book value of the reporting unit. If the fair value of the reporting unit is less than the book value, including goodwill, the implied fair value of goodwill is calculated. The excess, if any, of the book value over the implied fair value of goodwill is charged to net income. Amortization of intangibles with definite lives is calculated using the straight-line method which is reflective of the benefit pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible asset. Intangibles not subject to amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the intangible may not be recoverable. If the sum of the expected undiscounted future cash flows related to the asset is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset.
Major maintenance activities	Major maintenance activities – Costs for planned turnaround, major maintenance and engineered project activities are expensed in the period incurred. These types of costs include contractor repair services, materials and supplies, equipment rentals and our labor costs.
Environmental costs	Environmental costs – Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. We recognize remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed and determinable. If recoveries of remediation costs from third parties are probable, a receivable is recorded and is discounted when the estimated amount is reasonably fixed and determinable.
Asset retirement obligations	Asset retirement obligations – The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. The majority of our recognized asset retirement liability relates to conditional asset retirement obligations for removal and disposal of fire-retardant material from certain refining facilities. The remaining recognized asset retirement liability relates to other refining assets, the removal of underground storage tanks at our leased convenience stores, certain pipelines and processing facilities and other related pipeline assets. The fair values recorded for such obligations are based on the most probable current cost projections. The recorded asset retirement obligations are not material to the consolidated financial statements. Asset retirement obligations have not been recognized for some assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate. Such obligations will be recognized in the period when sufficient information becomes available to estimate a range of potential settlement dates. The asset retirement obligations principally include the hazardous material disposal and removal or dismantlement requirements associated with the closure of certain refining, terminal, retail, pipeline and processing assets. Our practice is to keep our assets in good operating condition through routine repair and maintenance of component parts in the ordinary course of business and by continuing to make improvements based on technological advances. As a result, we believe that generally these assets have no expected settlement date for purposes of estimating asset retirement obligations since the dates or ranges of dates upon which we would retire these assets cannot be reasonably estimated at this time.
Income taxes	Income taxes – Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their tax bases. Deferred tax assets are recorded when it is more likely than not that they will be realized. The realization of deferred tax assets is assessed periodically based on several factors, primarily our expectation to generate sufficient future taxable income.
Stock-based compensation arrangements	Stock-based compensation arrangements – The fair value of stock options granted to our employees is estimated on the date of grant using the Black-Scholes option pricing model. The model employs various assumptions, based on management’s estimates at the time of grant, which impact the calculation of fair value and ultimately, the amount of expense that is recognized over the vesting period of the stock option award. Of the required assumptions, the expected life of the stock option award and the expected volatility of our stock price have the most significant impact on the fair value calculation. The average expected life is based on our historical employee exercise behavior. The assumption for expected volatility of our stock price reflects a weighting of 50 percent of our common stock implied volatility and 50 percent of MPC’s common stock historical volatility. The fair value of restricted stock awards granted to our employees is determined based on the fair market value of our common stock on the date of grant. The fair value of performance unit awards granted to our employees is estimated on the date of grant using a Monte Carlo valuation model. Our stock-based compensation expense is recognized based on management’s estimate of the awards that are expected to vest, using the straight-line attribution method for all service-based awards with a graded vesting feature. If actual forfeiture results are different than expected, adjustments to recognized compensation expense may be required in future periods. Unearned stock-based compensation is charged to equity when restricted stock awards are granted. Compensation expense is recognized over the vesting period and is adjusted if conditions of the restricted stock award are not met.
Business combinations	Business combinations - We recognize and measure the assets acquired and liabilities assumed in a business combination based on their estimated fair values at the acquisition date, with any remaining difference recorded as goodwill or gain from a bargain purchase. For all material acquisitions, management engages an independent valuation specialist to assist with the determination of fair value of the assets acquired, liabilities assumed, noncontrolling interest, if any, and goodwill, based on recognized business valuation methodologies. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later than one year from the acquisition date, we will record any material adjustments to the initial estimate based on new information obtained about facts and circumstances that existed as of the acquisition date. An income, market or cost valuation method may be utilized to estimate the fair value of the assets acquired, liabilities assumed, and noncontrolling interest, if any, in a business combination. The income valuation method represents the present value of future cash flows over the life of the asset using: (i) discrete financial forecasts, which rely on management’s estimates of revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the market, with adjustments relating to any differences between the assets. The cost valuation method is based on the replacement cost of a comparable asset at prices at the time of the acquisition reduced for depreciation of the asset. Acquisition-related costs are expensed as incurred in connection with each business combination.
Renewable fuel identification numbers (RINs)	Renewable fuel identification numbers – We purchase RINs to satisfy a portion of our RFS2 compliance. We record a short-term intangible asset, included in other current assets on the balance sheet, for RINs owned in excess of our anticipated current period compliance requirements. The asset value is based on the product of the excess RINs as of the balance sheet date, if any, and the average cost of our RINs. We record a current liability, included in other current liabilities on the balance sheet, when we are deficient RINs based on the product of the deficient RINs as of the balance sheet date, if any, and the market price of the RINs at the balance sheet date. The cost of RINs used for compliance is reflected in cost of revenues. Any gains or losses on the sale or expiration of RINs are classified as other income. Proceeds from RIN sales are included in investing activities - all other, net on the cash flow statement.

Acquisitions and Investments (T

Acquisitions and Investments (Tables)	12 Months Ended
	Dec. 31, 2015
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Information [Table Text Block]	The following unaudited pro forma financial information presents consolidated results assuming the MarkWest Merger occurred on January 1, 2014, the Hess’ Retail Operations and Related Assets acquisition occurred on January 1, 2013 and the Galveston Bay Refinery and Related Assets acquisition occurred on January 1, 2012. The unaudited pro forma financial information does not give effect to potential synergies that could result from the transactions and is not necessarily indicative of the results of future operations. (In millions, except per share data) 2015 2014 2013 Sales and other operating revenues (including consumer excise taxes) $ 73,760 $ 108,605 $ 114,148 Net income attributable to MPC 2,825 2,522 2,142 Net income attributable to MPC per share – basic $ 5.25 $ 4.42 $ 3.40 Net income attributable to MPC per share – diluted 5.21 4.39 3.38
MarkWest
Business Acquisition [Line Items]
Components Of The Fair Value Of Consideration Transferred [Table Text Block]	The components of the fair value of consideration transferred are as follows: (In millions) Fair value of MPLX units issued $ 7,326 Cash payment to MarkWest unitholders 1,230 Payable to MarkWest Class B unitholders 50 Total fair value of consideration transferred $ 8,606
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	The estimated fair value of assets acquired and liabilities and noncontrolling interests assumed at the acquisition date, are as follows: (In millions) Cash and cash equivalents $ 12 Receivables 164 Inventories 33 Other current assets 44 Equity method investments 2,457 Property, plant and equipment, net 8,474 Other noncurrent assets 473 Total assets acquired 11,657 Accounts payable 322 Payroll and benefits payable 13 Accrued taxes 21 Other current liabilities 44 Long-term debt 4,567 Deferred income taxes 374 Deferred credit and other liabilities 151 Noncontrolling interests 13 Total liabilities and noncontrolling interest assumed 5,505 Net assets acquired excluding goodwill 6,152 Goodwill 2,454 Net assets acquired $ 8,606
Business Acquisition, Pro Forma Information [Table Text Block]	The amounts of revenue and income from operations associated with the MarkWest Merger included in our consolidated statements of income for 2015 are as follows: (In millions) 2015 Sales and other operating revenues (including consumer excise taxes) $ 120 Income from operations 32
Hess Retail Operations and Related Assets
Business Acquisition [Line Items]
Components Of The Fair Value Of Consideration Transferred [Table Text Block]	The components of the fair value of consideration transferred are as follows: (In millions) Cash $ 2,824 Net working capital adjustment estimate (3 ) Total fair value of consideration transferred $ 2,821
Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]	During the fourth quarter of 2014, an independent appraisal of the assets acquired and liabilities assumed and other evaluations were completed and finalized. Updates to the preliminary fair value measurements of assets acquired and liabilities assumed were made during the fourth quarter of 2014. The following table summarizes the amounts assigned to the assets acquired and liabilities assumed as of the acquisition date. (In millions) Cash and cash equivalents $ 49 Receivables 123 Inventories 165 Other current assets 8 Property, plant and equipment, net 2,063 Other noncurrent assets 111 Total assets acquired 2,519 Accounts payable 77 Payroll and benefits payable 15 Consumer excise taxes payable 64 Accrued taxes 4 Other current liabilities 10 Defined benefit postretirement plan obligations 2 Deferred credits and other liabilities 155 Total liabilities assumed 327 Net assets acquired excluding goodwill 2,192 Goodwill 629 Net assets acquired $ 2,821
Business Acquisition, Pro Forma Information [Table Text Block]	The amounts of revenue and income from operations associated with Hess’ Retail Operations and Related Assets included in our consolidated statements of income for 2014 are as follows: (In millions) 2014 Sales and other operating revenues (including consumer excise taxes) $ 2,403 Income from operations 113

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Purchases From Related Parties	Purchases from related parties were as follows: (In millions) 2015 2014 2013 Centennial $ — $ 7 $ 3 Crowley Ocean Partners 6 — — Explorer 20 39 — Illinois Extension Pipeline 4 — — LOCAP 23 21 17 LOOP 52 88 43 TAAE 52 79 24 TACE 54 121 130 TAME 87 141 131 Other equity method investees 10 9 9 Total $ 308 $ 505 $ 357
Receivables From Related Parties	Receivables from related parties, which are included in receivables, less allowance for doubtful accounts on the consolidated balance sheets, were as follows: December 31, (In millions) 2015 2014 Centennial $ 1 $ 2 Explorer — 2 MarkWest EMG Jefferson 2 — MarkWest Utica EMG 1 — Ohio Condensate 3 — Ohio Gathering 5 — TAME — 3 Other equity method investees 1 — Total $ 13 $ 7
Payables To Related Parties	Payables to related parties, which are included in accounts payable on the consolidated balance sheets, were as follows: December 31, (In millions) 2015 2014 Explorer $ 1 $ 3 Illinois Extension Pipeline 4 — LOCAP 2 2 LOOP 5 4 MarkWest Utica EMG 19 — Ohio Condensate 4 — TAAE 1 2 TACE 2 2 TAME 3 5 Other equity method investees 1 — Total $ 42 $ 18

Income per Common Share (Tables

Income per Common Share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Summary of Earnings Per Common Share	(In millions, except per share data) 2015 2014 2013 Basic earnings per share: Allocation of earnings: Net income attributable to MPC $ 2,852 $ 2,524 $ 2,112 Income allocated to participating securities 4 4 4 Income available to common stockholders – basic $ 2,848 $ 2,520 $ 2,108 Weighted average common shares outstanding 538 570 630 Basic earnings per share $ 5.29 $ 4.42 $ 3.34 Diluted earnings per share: Allocation of earnings: Net income attributable to MPC $ 2,852 $ 2,524 $ 2,112 Income allocated to participating securities 4 4 4 Income available to common stockholders – diluted $ 2,848 $ 2,520 $ 2,108 Weighted average common shares outstanding 538 570 630 Effect of dilutive securities 4 4 4 Weighted average common shares, including dilutive effect 542 574 634 Diluted earnings per share $ 5.26 $ 4.39 $ 3.32
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share	The following table summarizes the shares that were anti-dilutive, and therefore, were excluded from the diluted share calculation. (In millions) 2015 2014 2013 Shares issued under stock-based compensation plans 1 1 1

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Share Repurchases	Total share repurchases were as follows for the respective periods: (In millions, except per share data) 2015 2014 2013 Number of shares repurchased (a) 19 49 74 Cash paid for shares repurchased $ 965 $ 2,131 $ 2,793 Effective average cost per delivered share $ 50.31 $ 44.31 $ 38.07 (a) Shares repurchased in 2013 includes 2 million shares received under the November 2012 accelerated share repurchase program, which were paid for in 2012.

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Income From Operations Attributable To Operating Segments	(In millions) Refining & Marketing Speedway Midstream Total Year Ended December 31, 2015 Revenues: Customer $ 52,174 $ 19,690 $ 187 $ 72,051 Intersegment (a) 12,018 3 564 12,585 Segment revenues $ 64,192 $ 19,693 $ 751 $ 84,636 Segment income from operations (b)(c) $ 4,186 $ 673 $ 289 $ 5,148 Income from equity method investments 26 — 62 88 Depreciation and amortization (d) 1,079 254 117 1,450 Capital expenditures and investments (e)(f) 1,143 501 14,447 16,091 (In millions) Refining & Marketing Speedway Midstream Total Year Ended December 31, 2014 Revenues: Customer $ 80,822 $ 16,927 $ 70 $ 97,819 Intersegment (a) 10,912 5 527 11,444 Segment revenues $ 91,734 $ 16,932 $ 597 $ 109,263 Segment income from operations (b) $ 3,609 $ 544 $ 280 $ 4,433 Income from equity method investments 96 — 57 153 Depreciation and amortization (d) 1,045 152 77 1,274 Capital expenditures and investments (e)(g) 1,104 2,981 543 4,628 (In millions) Refining & Marketing Speedway Midstream Total Year Ended December 31, 2013 Revenues: Customer $ 85,616 $ 14,471 $ 79 $ 100,166 Intersegment (a) 9,294 4 458 9,756 Segment revenues $ 94,910 $ 14,475 $ 537 $ 109,922 Segment income from operations (b) $ 3,206 $ 375 $ 210 $ 3,791 Income from equity method investments 28 — 8 36 Depreciation and amortization (d) 1,011 112 74 1,197 Capital expenditures and investments (e)(h) 2,094 296 234 2,624 (a) Management believes intersegment transactions were conducted under terms comparable to those with unaffiliated parties. (b) Included in the Midstream segment for 2015 , 2014 and 2013 are $20 million , $19 million and $20 million , respectively, of corporate overhead expenses attributable to MPLX. Corporate overhead expenses are not currently allocated to other segments. Also included in the Midstream segment for 2015 are $36 million of transaction costs related to the MarkWest Merger. (c) The Refining & Marketing and Speedway segments include inventory lower of cost or market charge of $345 million and $25 million , respectively. (d) 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. (e) Capital expenditures include changes in capital accruals, acquisitions and investments in affiliates. (f) The Midstream segment includes $13.85 billion for the MarkWest Merger. See Note 5 . (g) The Speedway and Refining & Marketing segments include $2.66 billion and $52 million , respectively, for the acquisition of Hess’ Retail Operations and Related Assets. See Note 5 . (h) The Refining & Marketing and Midstream segments include $1.29 billion and $70 million , respectively, for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5 .
Reconciliation Of Segment Income From Operations To Income Before Income Taxes	The following reconciles segment income from operations to income before income taxes as reported in the consolidated statements of income: (In millions) 2015 2014 2013 Segment income from operations $ 5,148 $ 4,433 $ 3,791 Items not allocated to segments: Corporate and other unallocated items (a)(b) (308 ) (286 ) (271 ) Pension settlement expenses (c) (4 ) (96 ) (95 ) Impairment (d) (144 ) — — Net interest and other financial income (costs) (318 ) (216 ) (179 ) Income before income taxes $ 4,374 $ 3,835 $ 3,246 (a) Corporate and other unallocated items consists primarily of MPC’s corporate administrative expenses and costs related to certain non-operating assets. (b) Corporate overhead expenses attributable to MPLX are included in the Midstream segment. Corporate overhead expenses are not allocated to the Refining & Marketing and Speedway segments. (c) See Note 22 . (d) Related to the cancellation of the ROUX project at our Garyville, LA refinery. See Note 15 .
Reconciliation Of Segment Capital Expenditures And Investments To Total Capital Expenditures	The following reconciles segment capital expenditures and investments to total capital expenditures: (In millions) 2015 2014 2013 Segment capital expenditures and investments $ 16,091 $ 4,628 $ 2,624 Less: Investments in equity method investees (a) 2,788 413 124 Plus: Items not allocated to segments: Capital expenditures not allocated to segments 155 83 137 Capitalized interest 37 27 28 Total capital expenditures (b) $ 13,495 $ 4,325 $ 2,665 (a) 2015 includes $2.46 billion for the MarkWest Merger. See Note 5 . (b) Capital expenditures include changes in capital accruals. See Note 20 for a reconciliation of total capital expenditures to additions to property, plant and equipment as reported in the consolidated statements of cash flows.
Reconciliation Of Total Revenues To Sales And Other Operating Revenues	The following reconciles total segment customer revenues to sales and other operating revenues (including consumer excise taxes) as reported in the consolidated statements of income: (In millions) 2015 2014 2013 Customer revenues $ 72,051 $ 97,819 $ 100,166 Corporate and other unallocated items — (2 ) (6 ) Sales and other operating revenues (including consumer excise taxes) $ 72,051 $ 97,817 $ 100,160
Schedule Of Revenues By Product Line	Revenues by product line were: (In millions) 2015 2014 2013 Refined products $ 63,708 $ 90,702 $ 93,520 Merchandise 5,188 3,817 3,308 Crude oil and refinery feedstocks 2,718 2,917 2,988 Transportation and other 437 381 344 Sales and other operating revenues (including consumer excise taxes) $ 72,051 $ 97,817 $ 100,160
Total Assets by Reportable Segment	Total assets by reportable segment were: December 31, (In millions) 2015 2014 Refining & Marketing $ 17,780 $ 19,751 Speedway 5,349 5,296 Midstream 17,061 2,407 Corporate and Other 2,925 2,971 Total consolidated assets $ 43,115 $ 30,425

Other Items (Tables)

Other Items (Tables)	12 Months Ended
	Dec. 31, 2015
Other Income and Expenses [Abstract]
Net Interest And Other Financial Income (Costs)	Net interest and other financial income (costs) was: (In millions) 2015 2014 2013 Interest income $ 6 $ 7 $ 9 Interest expense (325 ) (229 ) (195 ) Interest capitalized 37 27 28 Loss on extinguishment of debt (5 ) — — Other financial costs (a) (31 ) (21 ) (21 ) Net interest and other financial income (costs) $ (318 ) $ (216 ) $ (179 ) (a) 2015 includes $6 million of transaction costs related to the MarkWest Merger.

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Components Of Income Tax Provisions (Benefits)	Income tax provisions (benefits) were: 2015 2014 2013 (In millions) Current Deferred Total Current Deferred Total Current Deferred Total Federal $ 1,210 $ 134 $ 1,344 $ 1,382 $ (199 ) $ 1,183 $ 954 $ 20 $ 974 State and local 152 9 161 135 (37 ) 98 131 8 139 Foreign 10 (9 ) 1 5 (6 ) (1 ) 5 (5 ) — Total $ 1,372 $ 134 $ 1,506 $ 1,522 $ (242 ) $ 1,280 $ 1,090 $ 23 $ 1,113
Reconciliation Of Federal Statutory Income Tax Rate	A reconciliation of the federal statutory income tax rate ( 35 percent ) applied to income before income taxes to the provision for income taxes follows: 2015 2014 2013 Statutory rate applied to income before income taxes 35 % 35 % 35 % State and local income taxes, net of federal income tax effects 2 2 3 Domestic manufacturing deduction (2 ) (2 ) (2 ) Other (1 ) (2 ) (2 ) Provision for income taxes 34 % 33 % 34 %
Components Of Deferred Tax Assets And Liabilities	Deferred tax assets and liabilities resulted from the following: December 31, (In millions) 2015 2014 Deferred tax assets: Employee benefits $ 631 $ 616 Environmental 44 54 Investments in subsidiaries and affiliates — 24 Net operating loss carryforwards 73 12 Other 73 58 Total deferred tax assets 821 764 Deferred tax liabilities: Property, plant and equipment 2,512 2,411 Inventories 579 614 Investments in subsidiaries and affiliates (a) 909 — Other 89 101 Total deferred tax liabilities 4,089 3,126 Net deferred tax liabilities $ 3,268 $ 2,362
Components Of Net Deferred Tax Liabilities Classified In Consolidated Balance Sheets	Net deferred tax liabilities were classified in the consolidated balance sheets as follows: December 31, (In millions) 2015 2014 Assets: Other noncurrent assets $ 17 $ 7 Liabilities: Accrued taxes (a) — 355 Deferred income taxes 3,285 2,014 Net deferred tax liabilities $ 3,268 $ 2,362 (a) We adopted the updated FASB balance classification of deferred taxes standard and applied the changes prospectively. We reclassified current deferred taxes from current accrued taxes to long-term deferred income taxes. See Note 3 .
Summary Of Income Tax Returns Subject To Examination	As of December 31, 2015 , our income tax returns remain subject to examination in the following major tax jurisdictions for the tax years indicated: United States Federal 2010 - 2014 States 2004 - 2014
Summary Of Activity In Unrecognized Tax Benefits	The following table summarizes the activity in unrecognized tax benefits: (In millions) 2015 2014 2013 January 1 balance $ 12 $ 13 $ 40 Additions for tax positions of prior years — 7 30 Reductions for tax positions of prior years — (10 ) (25 ) Settlements — 2 (30 ) Statute of limitations — — (2 ) December 31 balance $ 12 $ 12 $ 13

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Summary Of Inventories	December 31, (In millions) 2015 2014 Crude oil and refinery feedstocks $ 2,180 $ 2,219 Refined products 2,804 2,955 Materials and supplies 438 302 Merchandise 173 166 Lower of cost or market reserve (370 ) — Total $ 5,225 $ 5,642

Equity Method Investments (Tabl

Equity Method Investments (Tables)	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Schedule Of Equity Method Investments	Ownership as of Carrying value at December 31, December 31, (In millions) 2015 2015 2014 Centennial 50% $ 37 $ 36 Centrahoma Processing LLC 40% 111 — Crowley Ocean Partners 50% 72 — Explorer 25% 91 95 Illinois Extension Pipeline 35% 267 120 LOCAP 59% 22 23 LOOP 51% 243 230 MarkWest Utica EMG 60% 2,160 — North Dakota Pipeline (a) 38% 287 216 Ohio Condensate 60% 101 — TAAE 43% 27 22 TACE 60% 49 61 TAEI 34% 18 19 TAME (b) 50% 27 24 Other MPLX investments 86 — Other 24 19 Total $ 3,622 $ 865 (a) We own a 38 percent interest in the Class B units of this entity. Our Class B units will be converted to an approximate 27 percent ownership interest in the Class A units of this entity upon completion of the Sandpiper pipeline construction project, which is expected to be in early 2019. (b) Excludes TAEI’s investment in TAME.
Summarized Financial Information For Equity Method Investees	Summarized financial information for equity method investees is as follows: (In millions) 2015 2014 2013 Income statement data: Revenues and other income $ 1,390 $ 1,430 $ 1,067 Income from operations 332 379 87 Net income 239 316 63 Balance sheet data – December 31: Current assets $ 906 $ 990 Noncurrent assets 6,418 2,166 Current liabilities 468 280 Noncurrent liabilities 1,130 957

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
Property, Plant and Equipment [Abstract]
Summary Of Property, Plant And Equipment	(In millions) Estimated Useful Lives December 31, 2015 2014 Refining & Marketing 2 - 30 years $ 18,925 $ 18,001 Speedway 4 - 25 years 5,067 4,639 Midstream 10 - 42 years 10,850 2,044 Corporate and Other 4 - 40 years 762 618 Total 35,604 25,302 Less accumulated depreciation 10,440 9,041 Property, plant and equipment, net $ 25,164 $ 16,261

Goodwill and Intangibles (Table

Goodwill and Intangibles (Tables)	12 Months Ended
	Dec. 31, 2015
Acquired Finite-Lived Intangible Assets [Line Items]
Changes in Carrying Amount of Goodwill	The changes in the carrying amount of goodwill for 2015 and 2014 were as follows: (In millions) Refining & Marketing Speedway Midstream Total Balance at January 1, 2014 $ 551 $ 225 $ 162 $ 938 Acquisitions (a) — 629 — 629 Disposition (1 ) — — (1 ) Balance at December 31, 2014 $ 550 $ 854 $ 162 $ 1,566 Acquisitions (a) — — 2,454 2,454 Disposition — (1 ) — (1 ) Balance at December 31, 2015 $ 550 $ 853 $ 2,616 $ 4,019 (a) See Note 5 for information on the acquisitions.
Schedule of Acquired Finite-Lived Intangible Assets by Major Class [Table Text Block]	Our intangible assets as of December 31, 2015 and 2014 are as follows: (In millions) Refining & Marketing Speedway Midstream Total Balance at December 31, 2015 Customer contracts and relationships $ 91 $ 1 $ 468 $ 560 Royalty agreements 122 — — 122 Favorable lease contract terms 1 70 — 71 Other (a) 28 75 — 103 Gross $ 242 $ 146 $ 468 $ 856 Accumulated amortization (104 ) (31 ) (2 ) (137 ) Net $ 138 $ 115 $ 466 $ 719 Balance at December 31, 2014 Customer contracts and relationships $ 105 $ 1 $ — $ 106 Royalty agreements 121 — — 121 Favorable lease contract terms 1 71 — 72 Other (a) 30 74 — 104 Gross $ 257 $ 146 $ — $ 403 Accumulated amortization (106 ) (10 ) — (116 ) Net $ 151 $ 136 $ — $ 287 (a) The Refining & Marketing and Speedway segments include unamortized intangible assets of $3 million and $46 million , respectively
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense [Table Text Block]	Estimated future amortization expense related to the intangible assets at December 31, 2015 is as follows: (In millions) 2016 $ 48 2017 45 2018 45 2019 44 2020 47

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Assets and Liabilities Accounted for at Fair Value on Recurring Basis	The following tables present assets and liabilities accounted for at fair value on a recurring basis as of December 31, 2015 and 2014 by fair value hierarchy level. We have elected to offset the fair value amounts recognized for multiple derivative contracts executed with the same counterparty, including any related cash collateral as shown below; however, fair value amounts by hierarchy level are presented on a gross basis in the following tables. December 31, 2015 Fair Value Hierarchy (In millions) Level 1 Level 2 Level 3 Netting and Collateral (a) Net Carrying Value on Balance Sheet (b) Collateral Pledged Not Offset Commodity derivative instruments, assets $ 104 $ 2 $ 7 $ (62 ) $ 51 $ — Other assets 2 — — N/A 2 — Total assets at fair value $ 106 $ 2 $ 7 $ (62 ) $ 53 $ — Commodity derivative instruments, liabilities $ 39 $ — $ — $ (39 ) $ — $ — Embedded derivatives in commodity contracts (c) — — 32 — 32 — Contingent consideration, liability (d) — — 317 N/A 317 — Total liabilities at fair value $ 39 $ — $ 349 $ (39 ) $ 349 $ — December 31, 2014 Fair Value Hierarchy (In millions) Level 1 Level 2 Level 3 Netting and Collateral (a) Net Carrying Value on Balance Sheet (b) Collateral Pledged Not Offset Commodity derivative instruments, assets $ 317 $ — $ — $ (258 ) $ 59 $ — Other assets 2 — — N/A 2 — Total assets at fair value $ 319 $ — $ — $ (258 ) $ 61 $ — Commodity derivative instruments, liabilities $ 180 $ — $ — $ (180 ) $ — $ — Contingent consideration, liability (d) — — 478 N/A 478 — Total liabilities at fair value $ 180 $ — $ 478 $ (180 ) $ 478 $ — (a) Represents the impact of netting assets, liabilities and cash collateral when a legal right of offset exists. As of December 31, 2015 , cash collateral of $23 million was netted with mark-to-market derivative assets. As of December 31, 2014 , cash collateral of $78 million was netted with mark-to-market derivative assets. (b) We have no derivative contracts that are subject to master netting arrangements that are reflected gross on the balance sheet. (c) Includes $5 million at December 31, 2015 classified as current. (d) Includes $196 million and $174 million classified as current as of December 31, 2015 and 2014 , respectively.
Reconciliation of Net Beginning and Ending Balances Recorded for Net Assets and Liabilities Classified as Level 3	The following is a reconciliation of the net beginning and ending balances recorded for net assets and liabilities classified as Level 3 in the fair value hierarchy. (In millions) 2015 2014 2013 Beginning balance $ 478 $ 625 $ — Contingent consideration agreement — — 600 Contingent consideration payment (a) (189 ) (180 ) — Net derivative positions assumed - MarkWest Merger 31 — — Unrealized and realized (gains) losses included in net income 20 33 25 Settlements of derivative instruments 2 — — Ending balance $ 342 $ 478 $ 625 (a) On the consolidated statements of cash flows for 2015 and 2014, $175 million and $172 million , respectively, of the contingent earnout payment to BP is included as a financing activity with the remainder included as an operating activity.
Assets Measured at Fair Value on a Nonrecurring Basis	The following table shows the values of assets, by major category, measured at fair value on a nonrecurring basis in periods subsequent to their initial recognition. Year Ended December 31, 2015 2014 2013 (In millions) Fair Value Impairment Fair Value Impairment Fair Value Impairment Property, plant and equipment, net $ — $ 144 $ — $ — $ 1 $ 8 Other noncurrent assets — — — 11 — —
Financial Instruments at Fair Value, Excluding Derivative Financial Instruments and Contingent Consideration	The following table summarizes financial instruments on the basis of their nature, characteristics and risk at December 31, 2015 and 2014 , excluding the derivative financial instruments and contingent consideration reported above. December 31, 2015 2014 (In millions) Fair Value Carrying Value Fair Value Carrying Value Financial assets: Investments $ 33 $ 2 $ 26 $ 2 Other 35 33 32 32 Total financial assets $ 68 $ 35 $ 58 $ 34 Financial liabilities: Long-term debt (a) $ 11,366 $ 11,628 $ 6,571 $ 6,265 Deferred credits and other liabilities 136 135 17 17 Total financial liabilities $ 11,502 $ 11,763 $ 6,588 $ 6,282 (a) Excludes capital leases and debt issuance costs, however, includes amount classified as short-term debt.

Derivatives (Tables)

Derivatives (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative [Line Items]
Classification of Fair Values of Derivative Instruments, Excluding Cash Collateral	The following table presents the gross fair values of derivative instruments, excluding cash collateral, and where they appear on the consolidated balance sheets as of December 31, 2015 and 2014 : (In millions) December 31, 2015 Balance Sheet Location Asset Liability Commodity derivatives Other current assets $ 113 $ 39 Other current liabilities — 5 Deferred credits and other liabilities (a) — 27 (In millions) December 31, 2014 Balance Sheet Location Asset Liability Commodity derivatives Other current assets $ 317 $ 180
Effect of Commodity Derivative Instruments in Statements of Income	The following table summarizes the effect of all commodity derivative instruments in our consolidated statements of income: (In millions) Gain (Loss) Income Statement Location 2015 2014 2013 Sales and other operating revenues $ 19 $ 37 $ 12 Cost of revenues 294 456 (180 ) Total $ 313 $ 493 $ (168 )
Crude oil
Derivative [Line Items]
Open Commodity Derivative Contracts	The table below summarizes open commodity derivative contracts for crude oil and refined products as of December 31, 2015 . Position Total Barrels (In thousands) Crude oil (a) Exchange-traded Long 14,517 Exchange-traded Short (22,989 ) OTC Short (110 ) (a ) 100 percent of the exchange-traded contracts expire in the first quarter of 2016.
Refined products
Derivative [Line Items]
Open Commodity Derivative Contracts	Position Total Gallons (In thousands) Refined Products (a) Exchange-traded Long 221,256 Exchange-traded Short (203,700 ) OTC Short (43,838 ) (a ) 100 percent of the exchange-traded contracts expire in the first quarter of 2016.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Outstanding Borrowings	Our outstanding borrowings at December 31, 2015 and 2014 consisted of the following: December 31, (In millions) 2015 2014 Marathon Petroleum Corporation: Senior notes, 3.500%, due March 2016 $ — $ 750 Bank revolving credit facility due 2017 — — Term loan agreement due 2019 700 700 Senior notes, 2.700% due December 2018 600 — Senior notes, 3.400% due December 2020 650 — Senior notes, 5.125% due March 2021 1,000 1,000 Senior notes, 3.625%, due September 2024 750 750 Senior notes, 6.500%, due March 2041 1,250 1,250 Senior notes, 4.750%, due September 2044 800 800 Senior notes, 5.850% due December 2045 250 — Senior notes, 5.000%, due September 2054 400 400 MPLX LP: MPLX term loan facility due 2019 250 250 MPLX bank revolving credit facility due 2020 877 385 MPLX senior notes, 5.500%, due February 2023 710 — MPLX senior notes, 4.500%, due July 2023 989 — MPLX senior notes, 4.875%, due December 2024 1,149 — MPLX senior notes, 4.000%, due February 2025 500 — MPLX senior notes, 4.875%, due June 2025 1,189 — MarkWest senior notes, 4.500% - 5.500% 63 — Capital lease obligations due 2016-2028 348 372 Trade receivables securitization facility due December 2016 — — Total 12,475 6,657 Unamortized debt issuance costs (a) (51 ) (35 ) Unamortized discount (b) (499 ) (26 ) Fair value adjustments (c) — 6 Amounts due within one year (29 ) (27 ) Total long-term debt due after one year $ 11,896 $ 6,575 (a) We adopted the updated FASB debt issuance cost standard as of June 30, 2015 and applied the changes retrospectively to the prior period presented. We reclassified unamortized debt issuance costs from other noncurrent assets to long-term debt. (b) 2015 includes $465 million discount related to the difference between the fair value and the principal amount of the assumed MarkWest debt. (c) In 2012, we terminated our 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. The $20 million gain on the termination of our interest rate swap agreements was amortized over the remaining life of the 3.50 percent senior notes. As a result of the December 2015 extinguishment of our obligation for the 3.50 percent senior notes, the remaining unamortized gain was credited to net interest and other financial income (costs).
Schedule Of Debt Payments	The following table shows five years of scheduled debt payments. (In millions) 2016 $ 29 2017 28 2018 630 2019 977 2020 1,560

Supplemental Cash Flow Inform53

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Information [Abstract]
Summary of Supplemental Cash Flow Information	(In millions) 2015 2014 2013 Net cash provided by operating activities included: Interest paid (net of amounts capitalized) $ 272 $ 166 $ 161 Net income taxes paid to taxing authorities 1,605 1,362 1,099 Non-cash investing and financing activities: Capital lease obligations increase $ 1 $ — $ 61 Property, plant and equipment sold 5 4 43 Property, plant and equipment acquired 5 4 — Acquisition: Fair value of MPLX units issued (a) 7,326 — — Payable to MPLX Class B unitholders 50 — — Contingent consideration — — 600 Payable to seller — — 6 (a) See Note 5 .
Schedule Of Reconciliation Of Additions To Property Plant And Equipment To Total Capital Expenditures	The consolidated statements of cash flows exclude changes to the consolidated balance sheets that did not affect cash. The following is a reconciliation of additions to property, plant and equipment to total capital expenditures: (In millions) 2015 2014 2013 Additions to property, plant and equipment per consolidated statements of cash flows $ 1,998 $ 1,480 $ 1,206 Non-cash additions to property, plant and equipment 5 4 — Asset retirement expenditures (a) 1 2 — Increase in capital accruals 94 95 73 Total capital expenditures before acquisitions 2,098 1,581 1,279 Acquisitions (b) 11,397 2,744 1,386 Total capital expenditures $ 13,495 $ 4,325 $ 2,665 (a) Included in All other, net – Operating activities on the consolidated statements of cash flows. (b) The 2015 acquisitions include the MarkWest Merger. The 2014 acquisitions include the acquisition of Hess’ Retail Operations and Related Assets. The 2013 acquisitions include the acquisition of the Galveston Bay Refinery and Related Assets. The acquisition numbers above include property, plant and equipment, intangibles and goodwill. See Note 5 .

Accumulated Other Comprehensi54

Accumulated Other Comprehensive Loss (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Changes in Accumulated Other Comprehensive Loss by Component	The following table shows the changes in accumulated other comprehensive loss by component. Amounts in parentheses indicate debits. (In millions) Pension Benefits Other Benefits Gain on Cash Flow Hedge Workers Compensation Total Balance as of December 31, 2013 $ (161 ) $ (50 ) $ 4 $ 3 $ (204 ) Other comprehensive income (loss) before reclassifications (119 ) (53 ) — 2 (170 ) Amounts reclassified from accumulated other comprehensive loss: Amortization – prior service credit (a) (46 ) (4 ) — — (50 ) – actuarial loss (a) 51 2 — — 53 – settlement loss (a) 96 — — — 96 Other (b) — — — (1 ) (1 ) Tax effect (38 ) 1 — — (37 ) Other comprehensive income (loss) (56 ) (54 ) — 1 (109 ) Balance as of December 31, 2014 $ (217 ) $ (104 ) $ 4 $ 4 $ (313 ) (In millions) Pension Benefits Other Benefits Gain on Cash Flow Hedge Workers Compensation Total Balance as of December 31, 2014 $ (217 ) $ (104 ) $ 4 $ 4 $ (313 ) Other comprehensive income (loss) before reclassifications (44 ) 31 — (1 ) (14 ) Amounts reclassified from accumulated other comprehensive loss: Amortization – prior service credit (a) (46 ) (4 ) — — (50 ) – actuarial loss (a) 51 8 — — 59 – settlement loss (a) 4 — — — 4 Tax effect (3 ) (1 ) — — (4 ) Other comprehensive income (loss) (38 ) 34 — (1 ) (5 ) Balance as of December 31, 2015 $ (255 ) $ (70 ) $ 4 $ 3 $ (318 ) (a) These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 22 . (b) This amount was reclassified out of accumulated other comprehensive loss and is included in selling, general and administrative expenses on the consolidated statements of income.

Defined Benefit Pension and O55

Defined Benefit Pension and Other Postretirement Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Summary Of Defined Benefit Plans With Accumulated Benefit Obligations In Excess Of Plan Assets	The following summarizes our defined benefit pension plans that have accumulated benefit obligations in excess of plan assets. December 31, (In millions) 2015 2014 Projected benefit obligations $ 1,997 $ 2,075 Accumulated benefit obligations 1,918 2,009 Fair value of plan assets 1,570 1,744
Summary Of Projected Benefit Obligations And Funded Status For Defined Benefit Pension And Other Postretirement Plans	The following summarizes the projected benefit obligations and funded status for our defined benefit pension and other postretirement plans: Pension Benefits Other Benefits (In millions) 2015 2014 2015 2014 Change in benefit obligations: Benefit obligations at January 1 $ 2,075 $ 1,927 $ 812 $ 687 Service cost 101 88 31 27 Interest cost 71 74 32 33 Actuarial (gain) loss (63 ) 257 (63 ) 86 Benefits paid (187 ) (271 ) (24 ) (23 ) Other (a) — — 12 2 Benefit obligations at December 31 1,997 2,075 800 812 Change in plan assets: Fair value of plan assets at January 1 1,744 1,800 — — Actual return on plan assets (33 ) 175 — — Employer contributions 46 40 — — Benefits paid from plan assets (187 ) (271 ) — — Fair value of plan assets at December 31 1,570 1,744 — — Funded status of plans at December 31 $ (427 ) $ (331 ) $ (800 ) $ (812 ) Amounts recognized in the consolidated balance sheets: Current liabilities $ (19 ) $ (17 ) $ (29 ) $ (27 ) Noncurrent liabilities (408 ) (314 ) (771 ) (785 ) Accrued benefit cost $ (427 ) $ (331 ) $ (800 ) $ (812 ) Pretax amounts recognized in accumulated other comprehensive loss: (b) Net loss $ 723 $ 710 $ 120 $ 191 Prior service credit (323 ) (369 ) (9 ) (26 ) (a) Includes adjustments related to the MarkWest Merger in 2015 and the acquisition of Hess’ Retail Operations and Related Assets in 2014. (b) Amounts exclude those related to LOOP and Explorer, equity method investees with defined benefit pension and postretirement plans for which net losses of $19 million and $2 million were recorded in accumulated other comprehensive loss in 2015 , reflecting our ownership share.
Components of Net Periodic Benefit Costs	Components of net periodic benefit cost and other comprehensive loss – The following summarizes the net periodic benefit costs and the amounts recognized as other comprehensive loss for our defined benefit pension and other postretirement plans. Pension Benefits Other Benefits (In millions) 2015 2014 2013 2015 2014 2013 Components of net periodic benefit cost: Service cost $ 101 $ 88 $ 93 $ 31 $ 27 $ 25 Interest cost 71 74 73 32 33 26 Expected return on plan assets (98 ) (107 ) (107 ) — — — Amortization – prior service credit (46 ) (46 ) (45 ) (4 ) (4 ) (4 ) – actuarial loss 51 51 66 8 2 3 – settlement loss 4 96 95 — — — Net periodic benefit cost (a) $ 83 $ 156 $ 175 $ 67 $ 58 $ 50 Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax): Actuarial (gain) loss $ 69 $ 188 $ (317 ) $ (63 ) $ 86 $ 17 Prior service cost (credit) (b) — — — 13 — 4 Amortization of actuarial loss (55 ) (147 ) (161 ) (8 ) (2 ) (3 ) Amortization of prior service cost 46 46 45 4 4 4 Other — — — — — — Total recognized in other comprehensive loss $ 60 $ 87 $ (433 ) $ (54 ) $ 88 $ 22 Total recognized in net periodic benefit cost and other comprehensive loss $ 143 $ 243 $ (258 ) $ 13 $ 146 $ 72 (a) Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years. (b) Includes adjustments related to the MarkWest Merger in 2015, plan amendments approved in 2013 and adjustments due to changes made to the defined pension plans and the post-65 medical plan coverage effective January 1, 2013.
Other Changes in Plan Assets and Benefit Obligations Recognized in Other Comprehensive Loss (Pretax)	Components of net periodic benefit cost and other comprehensive loss – The following summarizes the net periodic benefit costs and the amounts recognized as other comprehensive loss for our defined benefit pension and other postretirement plans. Pension Benefits Other Benefits (In millions) 2015 2014 2013 2015 2014 2013 Components of net periodic benefit cost: Service cost $ 101 $ 88 $ 93 $ 31 $ 27 $ 25 Interest cost 71 74 73 32 33 26 Expected return on plan assets (98 ) (107 ) (107 ) — — — Amortization – prior service credit (46 ) (46 ) (45 ) (4 ) (4 ) (4 ) – actuarial loss 51 51 66 8 2 3 – settlement loss 4 96 95 — — — Net periodic benefit cost (a) $ 83 $ 156 $ 175 $ 67 $ 58 $ 50 Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax): Actuarial (gain) loss $ 69 $ 188 $ (317 ) $ (63 ) $ 86 $ 17 Prior service cost (credit) (b) — — — 13 — 4 Amortization of actuarial loss (55 ) (147 ) (161 ) (8 ) (2 ) (3 ) Amortization of prior service cost 46 46 45 4 4 4 Other — — — — — — Total recognized in other comprehensive loss $ 60 $ 87 $ (433 ) $ (54 ) $ 88 $ 22 Total recognized in net periodic benefit cost and other comprehensive loss $ 143 $ 243 $ (258 ) $ 13 $ 146 $ 72 (a) Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years. (b) Includes adjustments related to the MarkWest Merger in 2015, plan amendments approved in 2013 and adjustments due to changes made to the defined pension plans and the post-65 medical plan coverage effective January 1, 2013.
Plan Assumptions	Plan assumptions – The following summarizes the assumptions used to determine the benefit obligations at December 31, and net periodic benefit cost for the defined benefit pension and other postretirement plans for 2015 , 2014 and 2013 . Pension Benefits Other Benefits 2015 2014 2013 2015 2014 2013 Weighted-average assumptions used to determine benefit obligation: Discount rate 4.00 % 3.65 % 4.30 % 4.50 % 4.15 % 4.95 % Rate of compensation increase 3.70 % 3.70 % 3.70 % 3.70 % 3.70 % 3.70 % Weighted-average assumptions used to determine net periodic benefit cost: Discount rate 3.70 % 4.05 % 3.88 % 4.30 % 4.95 % 4.11 % Expected long-term return on plan assets (a) 6.75 % 7.00 % 7.50 % — % — % — % Rate of compensation increase 3.70 % 3.70 % 5.00 % 3.70 % 3.70 % 5.00 % (a) Effective January 1, 2016, the expected long-term rate of return on plan assets is 6.50 percent due to a continuation of a change in our primary plan investment strategy, which began January 1, 2014.
Assumed Health Care Cost Trend Rates	The following summarizes the assumed health care cost trend rates. December 31, 2015 2014 2013 Health care cost trend rate assumed for the following year: Medical: Pre-65 7.50 % 8.00 % 8.00 % Prescription drugs 7.00 % 7.00 % 7.00 % Rate to which the cost trend rate is assumed to decline (the ultimate trend rate): Medical: Pre-65 5.00 % 5.00 % 5.00 % Prescription drugs 5.00 % 5.00 % 5.00 % Year that the rate reaches the ultimate trend rate: Medical: Pre-65 2021 2021 2020 Prescription drugs 2021 2021 2018
Effects Of One Percentage Point Change In Assumed Health Care Cost Trend Rates	A one percentage point change in assumed health care cost trend rates would have the following effects: 1-Percentage- 1-Percentage- (In millions) Point Increase Point Decrease Effect on total of service and interest cost components $ 6 $ (5 ) Effect on other postretirement benefit obligations 45 (39 )
Fair Values Of Defined Benefit Pension Plan Assets	The following tables present the fair values of our defined benefit pension plans’ assets, by level within the fair value hierarchy, as of December 31, 2015 and 2014 . December 31, 2015 (In millions) Level 1 Level 2 Level 3 Total Cash and cash equivalents $ — $ 27 $ — $ 27 Equity: Common stocks 57 — — 57 Mutual funds 142 — — 142 Pooled funds — 399 — 399 Fixed income: Corporate — 516 — 516 Government — 103 — 103 Pooled funds — 193 — 193 Private equity — — 62 62 Real estate — — 50 50 Other 2 — 19 21 Total investments, at fair value $ 201 $ 1,238 $ 131 $ 1,570 December 31, 2014 (In millions) Level 1 Level 2 Level 3 Total Cash and cash equivalents $ — $ 29 $ — $ 29 Equity: Common stocks 63 — — 63 Mutual funds 155 — — 155 Pooled funds — 442 — 442 Fixed income: Corporate — 554 — 554 Government — 99 — 99 Pooled funds — 254 — 254 Private equity — — 66 66 Real estate — — 57 57 Other 2 2 21 25 Total investments, at fair value $ 220 $ 1,380 $ 144 $ 1,744
Reconciliation Of Beginning And Ending Balances Of Plan Assets Classified As Level 3	The following is a reconciliation of the beginning and ending balances recorded for plan assets classified as Level 3 in the fair value hierarchy: 2015 (In millions) Private Equity Real Estate Other Total Beginning balance $ 66 $ 57 $ 21 $ 144 Actual return on plan assets: Realized 12 6 — 18 Unrealized (1 ) (3 ) (2 ) (6 ) Purchases 5 5 — 10 Sales (20 ) (15 ) — (35 ) Ending balance $ 62 $ 50 $ 19 $ 131 2014 (In millions) Private Equity Real Estate Other Total Beginning balance $ 57 $ 60 $ 20 $ 137 Actual return on plan assets: Realized 6 4 — 10 Unrealized 6 4 1 11 Purchases 10 5 — 15 Sales (13 ) (16 ) — (29 ) Ending balance $ 66 $ 57 $ 21 $ 144
Estimated Future Benefit Payment	Estimated future benefit payments – The following gross benefit payments, which reflect expected future service, as appropriate, are expected to be paid in the years indicated. (In millions) Pension Benefits Other Benefits 2016 $ 185 $ 28 2017 184 32 2018 185 36 2019 183 39 2020 175 43 2021 through 2025 834 253
Multi Employer Pension Plan	Our participation in this plan for 2015 , 2014 and 2013 is outlined in the table below. The “EIN” column provides the Employee Identification Number for the plan. The most recent Pension Protection Act zone status available in 2015 and 2014 is for the plan’s year ended December 31, 2013 and December 31, 2012, respectively. The zone status is based on information that we received from the plan and is certified by the plan’s actuary. Among other factors, plans in the red zone are generally less than 65 percent funded. The “FIP/RP Status Pending/Implemented” column indicates a financial improvement plan or a rehabilitation plan has been implemented. The last column lists the expiration date of the collective-bargaining agreement to which the plan is subject. There have been no significant changes that affect the comparability of 2015 , 2014 and 2013 contributions. Our portion of the contributions does not make up more than five percent of total contributions to the plan. Pension Protection Act Zone Status FIP/RP Status Pending/Implemented MPC Contributions In millions ) Surcharge Expiration Date of Collective – Bargaining Pension Fund EIN 2015 2014 2015 2014 2013 Central States, Southeast and Southwest Areas Pension Plan (a) 36-6044243 Red Red Implemented $ 4 $ 4 $ 3 No January 31, 2019 (a) This agreement has a minimum contribution requirement of $291 per week per employee for 2016 . A total of 272 employees participated in the plan as of December 31, 2015 .

Stock-Based Compensation Plans

Stock-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Disclosure of Share-based Compensation Arrangements by Share-based Payment Award	The following table reflects activity related to our stock-based compensation arrangements: (In millions) 2015 2014 2013 Stock-based compensation expense $ 42 $ 40 $ 42 Tax benefit recognized on stock-based compensation expense 16 15 15 Cash received by MPC upon exercise of stock option awards 33 26 48 Tax benefit received for tax deductions for stock awards exercised 26 19 18
Weighted Average Assumptions Used To Value Stock Options Awards	The Black Scholes option-pricing model values used to value stock option awards granted were determined based on the following weighted average assumptions: 2015 2014 2013 Weighted average exercise price per share $ 50.85 $ 42.51 $ 42.32 Expected life in years 6.0 5.8 6.0 Expected volatility 33 % 36 % 40 % Expected dividend yield 2.0 % 1.9 % 2.0 % Risk-free interest rate 1.7 % 1.8 % 1.0 % Weighted average grant date fair value of stock option awards granted $ 13.44 $ 12.69 $ 13.57
Summary of Stock Option Award Activity	The following is a summary of our common stock option activity in 2015 : Number of of Shares (a) Weighted Average Exercise Price Weighted Average Remaining Contractual Terms (in years) Aggregate Intrinsic Value (in millions) Outstanding at December 31, 2014 9,502,876 $ 22.74 Granted 1,103,684 50.85 Exercised (1,827,245 ) 18.06 Forfeited, canceled or expired (54,684 ) 40.67 Outstanding at December 31, 2015 8,724,631 27.16 Vested and expected to vest at December 31, 2015 8,718,834 27.11 6.0 $ 216 Exercisable at December 31, 2015 6,806,015 21.47 5.0 207 (a) Includes an immaterial number of stock appreciation rights.
Summary of Restricted Stock Award Activity	The following is a summary of restricted stock award activity of our common stock in 2015 : 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, 2014 1,030,146 $ 38.62 822,186 $ 18.65 Granted 627,135 50.64 81,685 49.87 RS’s Vested/RSU’s Issued (537,020 ) 34.25 (389,801 ) 17.32 Forfeited (45,718 ) 41.41 (850 ) 44.77 Outstanding at December 31, 2015 1,074,543 47.70 513,220 24.59
Schedule of Share-based Compensation, Restricted Stock and Restricted Stock Units Activity, Vested And Unvested	The following is a summary of the values related to restricted stock and restricted stock unit awards held by MPC employees and non-employee directors: Restricted Stock Restricted Stock Units Intrinsic Value of Awards Vested During the Period (in millions) Weighted Average Grant Date Fair Value of Awards Granted During the Period Intrinsic Value of Awards Vested During the Period (in millions) Weighted Average Grant Date Fair Value of Awards Granted During the Period 2015 $ 27 $ 50.64 $ 21 $ 49.87 2014 28 43.82 — 42.95 2013 20 43.53 — 36.74
Schedule of Performance Unit Awards	The following table presents a summary of the 2015 activity for performance unit awards to be settled in shares: Number of Units Weighted Average Grant Date Fair Value Outstanding at December 31, 2014 5,791,825 $ 0.88 Granted 2,389,450 0.95 Exercised (2,035,833 ) 0.85 Canceled — — Outstanding at December 31, 2015 6,145,442 0.92
Schedule of Share-based Compensation, Performance Unit Awards, Valuation Assumptions	Performance units paying out in units have a grant date fair value calculated using a Monte Carlo valuation model, which requires the input of subjective assumptions. The following table provides a summary of these assumptions: 2015 2014 2013 Risk-free interest rate 0.95 % 0.63 % 0.35 % Look-back period 2.84 years 2.84 years 2.84 years Expected volatility 30.38 % 38.51 % 41.67 % Grant date fair value of performance units granted $ 0.95 $ 0.85 $ 0.95

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2015
Leases [Abstract]
Schedule Of Future Minimum Commitments	Future minimum commitments as of December 31, 2015 , for capital lease obligations and for operating lease obligations having initial or remaining non-cancelable lease terms in excess of one year are as follows: (In millions) Capital Lease Obligations Operating Lease Obligations 2016 $ 53 $ 282 2017 50 212 2018 50 186 2019 45 161 2020 49 138 Later years 251 475 Total minimum lease payments 498 $ 1,454 Less imputed interest costs 150 Present value of net minimum lease payments $ 348
Schedule Of Operating Lease Rental Expense	Operating lease rental expense was: (In millions) 2015 2014 2013 Rental expense $ 331 $ 256 $ 213
Schedule of Future Minimum Rental Payments for Operating Leases	The following is a schedule of minimum future rentals on the non‑cancelable operating leases as of December 31, 2015 : (In millions) 2016 $ 174 2017 184 2018 185 2019 186 2020 185 Later years 588 Total minimum lease payments $ 1,502
Schedule of Property Subject to or Available for Operating Lease	The following schedule summarizes our investment in assets held for operating lease by major classes as of December 31, 2015 : (In millions) Natural gas gathering and NGL transportation pipelines and facilities $ 619 Natural gas processing facilities 753 Construction in progress 110 Property, plant and equipment 1,482 Less accumulated depreciation 5 Total property, plant and equipment $ 1,477

Selected Quarterly Financial 58

Selected Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Data [Abstract]
Schedule Of Quarterly Financial Information	2015 2014 (In millions, except per share data) 1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr. 1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr. Revenues $ 17,191 $ 20,537 $ 18,716 $ 15,607 $ 23,285 $ 26,844 $ 25,438 $ 22,250 Income from operations 1,470 1,335 1,549 338 361 1,369 1,062 1,259 Net income 903 839 958 168 207 864 679 805 Net income attributable to MPC 891 826 948 187 199 855 672 798 Net income attributable to MPC per share: (a) Basic $ 1.63 $ 1.52 $ 1.77 $ 0.35 $ 0.34 $ 1.49 $ 1.19 $ 1.44 Diluted 1.62 1.51 1.76 0.35 0.34 1.48 1.18 1.43 Dividends paid per share 0.25 0.25 0.32 0.32 0.21 0.21 0.25 0.25 (a) We completed a two-for-one stock split in June 2015. All historical per share data has been retroactively restated on a post-split basis.

Supplementary Statistics (Table

Supplementary Statistics (Tables)	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Supplementary Statistics	(In millions) 2015 2014 2013 Income from Operations by segment Refining & Marketing (a) $ 4,186 $ 3,609 $ 3,206 Speedway (a) 673 544 375 Midstream (b) 289 280 210 Items not allocated to segments: Corporate and other unallocated items (b) (308 ) (286 ) (271 ) Pension settlement expenses (4 ) (96 ) (95 ) Impairment (144 ) — — Income from operations $ 4,692 $ 4,051 $ 3,425 Capital Expenditures and Investments (c)(d) Refining & Marketing $ 1,143 $ 1,104 $ 2,094 Speedway 501 2,981 296 Midstream 14,447 543 234 Corporate and Other (e) 192 110 165 Total $ 16,283 $ 4,738 $ 2,789 (a) The Refining & Marketing and Speedway segments in 2015 include inventory lower of cost or market charge of $345 million and $25 million , respectively. (b) Included in the Midstream segment for 2015 , 2014 and 2013 are $20 million , $19 million and $20 million of corporate overhead expenses attributable to MPLX, which were included in items not allocated to segments prior to MPLX’s October 31, 2012 initial public offering. Corporate overhead expenses are not currently allocated to other segments. (c) Capital expenditures include changes in capital accruals. (d) Includes $13.85 billion in 2015 for the MarkWest Merger, $2.71 billion in 2014 for the acquisition of Hess’ Retail Operations and Related Assets and $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5 . (e) Includes capitalized interest of $37 million , $27 million and $28 million for 2015 , 2014 and 2013 , respectively.
Operating Statistics	2015 2014 2013 MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day) (a)(b) 2,301 2,138 2,086 Refining & Marketing Operating Statistics (b) Refining & Marketing refined product sales volume (thousands of barrels per day) (c) 2,289 2,125 2,075 Refining & Marketing gross margin (dollars per barrel) (d)(e) $ 15.25 $ 15.05 $ 13.24 Crude oil capacity utilization percent (f) 99 95 96 Refinery throughputs (thousands of barrels per day): (g) Crude oil refined 1,711 1,622 1,589 Other charge and blendstocks 177 184 213 Total 1,888 1,806 1,802 Sour crude oil throughput percent 55 52 53 WTI-priced crude oil throughput percent 20 19 21 Refined product yields (thousands of barrels per day): (g) Gasoline 913 869 921 Distillates 603 580 572 Propane 36 35 37 Feedstocks and special products 281 276 221 Heavy fuel oil 31 25 31 Asphalt 55 54 54 Total 1,919 1,839 1,836 Refinery direct operating costs (dollars per barrel): (h) Planned turnaround and major maintenance $ 1.13 $ 1.80 $ 1.20 Depreciation and amortization 1.39 1.41 1.36 Other manufacturing (i) 4.15 4.86 4.14 Total $ 6.67 $ 8.07 $ 6.70 Refining & Marketing Operating Statistics By Region – Gulf Coast (b) Refinery throughputs (thousands of barrels per day): (j) Crude oil refined 1,060 991 964 Other charge and blendstocks 184 182 195 Total 1,244 1,173 1,159 Sour crude oil throughput percent 68 64 65 WTI-priced crude oil throughput percent 6 3 7 Refined product yields (thousands of barrels per day): (j) Gasoline 534 508 551 Distillates 392 368 365 Propane 26 23 23 Feedstocks and special products 286 274 215 Heavy fuel oil 15 13 19 Asphalt 16 13 13 Total 1,269 1,199 1,186 Refinery direct operating costs (dollars per barrel): (h) Planned turnaround and major maintenance $ 0.81 $ 1.82 $ 1.00 Depreciation and amortization 1.09 1.15 1.09 Other manufacturing (i) 3.88 4.73 3.98 Total $ 5.78 $ 7.70 $ 6.07 Supplementary Statistics (Unaudited) 2015 2014 2013 Refining & Marketing Operating Statistics By Region – Midwest Refinery throughputs (thousands of barrels per day): (j) Crude oil refined 651 631 625 Other charge and blendstocks 39 45 54 Total 690 676 679 Sour crude oil throughput percent 34 33 35 WTI-priced crude oil throughput percent 43 44 42 Refined product yields (thousands of barrels per day): (j) Gasoline 379 361 371 Distillates 211 212 207 Propane 12 13 14 Feedstocks and special products 38 43 41 Heavy fuel oil 17 13 12 Asphalt 39 41 41 Total 696 683 686 Refinery direct operating costs (dollars per barrel): (h) Planned turnaround and major maintenance $ 1.64 $ 1.66 $ 1.47 Depreciation and amortization 1.83 1.78 1.74 Other manufacturing (i) 4.36 4.76 4.21 Total $ 7.83 $ 8.20 $ 7.42 Speedway Operating Statistics (k) Convenience stores at period-end 2,766 2,746 1,478 Gasoline and distillate sales (millions of gallons) 6,038 3,942 3,146 Gasoline & distillate gross margin (dollars per gallon) (e)(l) $ 0.1823 $ 0.1775 $ 0.1441 Merchandise sales (in millions) $ 4,879 $ 3,611 $ 3,135 Merchandise gross margin (in millions) $ 1,368 $ 975 $ 825 Merchandise gross margin percent 28.0 % 27.0 % 26.3 % Same store gasoline sales volume (period over period) (0.3 )% (0.7 )% 0.5 % Same store merchandise sales (period over period) (m) 4.1 % 5.0 % 4.3 % Midstream Operating Statistics Crude oil and refined product pipeline throughputs (thousands of barrels per day) (n) 2,191 2,119 2,204 Gathering system throughput (million cubic feet per day) (o) 3,075 Natural gas processed (million cubic feet per day) (o) 5,468 C2 (ethane) + NGLs (natural gas liquids) fractionated (mbpd) (o) 307 (a) Total average daily volumes of refined product sales to wholesale, branded and retail (Speedway segment) customers. (b) Includes the results of the Galveston Bay Refinery and Related Assets from the February 1, 2013 acquisition date. (c) Includes intersegment sales. (d) Sales revenue less cost of refinery inputs and purchased products, divided by total refinery throughputs. (e) Excludes the lower of cost or market adjustment. (f) Based on calendar day capacity, which is an annual average that includes downtime for planned maintenance and other normal operating activities. (g) Excludes inter-refinery volumes of 46 mbpd, 43 mbpd and 36 mbpd for 2015 , 2014 and 2013 , respectively. (h) Per barrel of total refinery throughputs. (i) Includes utilities, labor, routine maintenance and other operating costs. (j) Includes inter-refinery transfer volumes. (k) Includes the impact of Hess’ Retail Operations and Related Assets from the September 30, 2014 acquisition date. (l) 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. (m) Excludes cigarettes. Same store comparison includes only locations owned at least 13 months. (n) On owned common-carrier pipelines, excluding equity method investments. (o) Includes amounts related to unconsolidated equity method investments. Includes the results of the MarkWest assets beginning on the Dec. 4, 2015 acquisition date.

Summary Of Principal Accounti60

Summary Of Principal Accounting Policies (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Company	Dec. 31, 2014USD ($)	Sep. 30, 2015
Summary Of Principal Accounting Policies [Line Items]
Restricted cash and cash equivalents | $	$ 9	$ 4
Accounts receivable number of days past-due evaluated for doubtful accounts	180 days
Stock Options
Summary Of Principal Accounting Policies [Line Items]
Implied volatility rate weighting (in percentage)	50.00%
Historical volatility rate weighting (in percentage)	50.00%
Minimum
Summary Of Principal Accounting Policies [Line Items]
Number of companies engaged in crude oil or refinery feedstock trading agreement | Company	100
Estimated useful lives (in years)	2 years
Maximum
Summary Of Principal Accounting Policies [Line Items]
Estimated useful lives (in years)	42 years
Accounts Receivable with Master Netting Arrangements | Customer Concentration Risk
Summary Of Principal Accounting Policies [Line Items]
Percentage of accounts receivable related to sales of crude oil refinery feed stocks to customers with master netting agreements	26.00%	41.00%
MPLX LP
Summary Of Principal Accounting Policies [Line Items]
MPC's ownership percentage of the general partner interest	100.00%
Noncontrolling interest (in percentage)	79.60%
General Partner and Limited Partner | MPLX LP
Summary Of Principal Accounting Policies [Line Items]
MPC's partnership interest in MPLX (in percentage)	20.40%		71.50%
General Partner | MPLX LP
Summary Of Principal Accounting Policies [Line Items]
MPC's partnership interest in MPLX (in percentage)	2.00%		2.00%

MPLX LP (Narrative) (Detail)

MPLX LP (Narrative) (Detail) - MPLX LP	Dec. 04, 2015	Dec. 31, 2015	Sep. 30, 2015
Noncontrolling Interest [Line Items]
MPC's ownership percentage of the general partner interest		100.00%
Noncontrolling interest (in percentage)		79.60%
MarkWest
Noncontrolling Interest [Line Items]
Common units conversion ratio	1.09
General Partner and Limited Partner
Noncontrolling Interest [Line Items]
MPC's partnership interest in MPLX (in percentage)		20.40%	71.50%
General Partner
Noncontrolling Interest [Line Items]
MPC's partnership interest in MPLX (in percentage)		2.00%	2.00%

MPLX LP (Sales and Contribution

MPLX LP (Sales and Contributions to MPLX) (Details) - USD ($) shares in Millions, $ in Millions	Dec. 04, 2015	Dec. 01, 2014	Mar. 01, 2014	May. 01, 2013	Apr. 30, 2013	Oct. 31, 2012
MPLX Pipe Line Holdings LP
Noncontrolling Interest [Line Items]
Additional interest sold	0.50%	30.50%	13.00%	5.00%
Proceeds from sale of ownership interest In Assets By Company In Affiliate	$ 12	$ 600	$ 310	$ 100
MPLX LP | Limited Partner
Noncontrolling Interest [Line Items]
Equity interest issued or issuable, number of shares		2.9
Equity interest issued or issuable, value assigned		$ 200
MPLX LP | MPLX bank revolving credit facility due 2020
Noncontrolling Interest [Line Items]
Cash payment for acquisition		$ 600	270
MPLX LP | Cash and cash equivalents
Noncontrolling Interest [Line Items]
Cash payment for acquisition			$ 40
MPLX LP | Butane Cavern
Noncontrolling Interest [Line Items]
MPLX's partnership percent indirect interest in assets						100.00%
MPLX LP | MPLX Pipe Line Holdings LP
Noncontrolling Interest [Line Items]
Ownership interest (in percentage)					51.00%

MPLX LP (Public Offerings) (Det

MPLX LP (Public Offerings) (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	Feb. 12, 2015	Dec. 08, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 22, 2015	Dec. 14, 2015	Dec. 10, 2014
Noncontrolling Interest [Line Items]
Net proceeds from issuance of MPLX LP common units			$ 0	$ 221	$ 0
Senior Notes
Noncontrolling Interest [Line Items]
Debt instrument, face amount							$ 1,500
MPLX LP
Noncontrolling Interest [Line Items]
Net proceeds from issuance of MPLX LP common units		$ 221
General partners' capital account, units issued								130
General partners' contributed capital								$ 9
MPLX LP | Senior Notes
Noncontrolling Interest [Line Items]
Debt instrument, face amount						$ 4,040
MPLX LP | MPLX senior notes, 4.000%, due February 2025 | Senior Notes
Noncontrolling Interest [Line Items]
Debt instrument, face amount	$ 500
Debt instrument, interest rate	4.00%		4.00%
Debt instrument, maturity date	Feb. 15, 2025		Feb. 15, 2025
MPLX LP | Limited Partner
Noncontrolling Interest [Line Items]
Public offering of common units (in number of common units)		3,500
Shares issued, price per share		$ 66.68

Acquisitions and Investments (M

Acquisitions and Investments (Merger with MarkWest Energy Partners, L.P.) (Details) $ / shares in Units, $ in Millions	Dec. 04, 2015USD ($)$ / shares	Dec. 31, 2015USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Business Acquisition [Line Items]
Payable to seller			$ 50	$ 0	$ 6
Goodwill		$ 4,019	$ 4,019	$ 1,566	$ 938
MarkWest
Business Acquisition [Line Items]
Cash consideration to unitholders (per unit) | $ / shares	$ 6.20
Cash payment to MarkWest unitholders	$ 1,230	$ 1,280
Payable to seller	50
Goodwill	2,454
Transaction costs	6
MarkWest | Selling, General and Administrative Expenses
Business Acquisition [Line Items]
Transaction costs	30
MarkWest | Net Interest and Other Financial Income
Business Acquisition [Line Items]
Transaction costs	6
MarkWest | Customer contracts and relationships
Business Acquisition [Line Items]
Intangibles	$ 468
MarkWest | Customer contracts and relationships | Minimum
Business Acquisition [Line Items]
Finite-lived intangible asset, useful life (in years)	11 years
MarkWest | Customer contracts and relationships | Maximum
Business Acquisition [Line Items]
Finite-lived intangible asset, useful life (in years)	25 years
MarkWest | MPLX LP
Business Acquisition [Line Items]
Common units conversion ratio	1.09

Acquisitions and Investments (F

Acquisitions and Investments (Fair Value of Consideration Transferred - MarkWest) (Details) - USD ($) $ in Millions	Dec. 04, 2015	Dec. 31, 2015	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Fair value of MPLX units issued			$ 7,326	[1]	$ 0	$ 0
Payable to seller			$ 50		$ 0	$ 6
MarkWest
Business Acquisition [Line Items]
Fair value of MPLX units issued	$ 7,326
Cash payment to MarkWest unitholders	1,230	$ 1,280
Payable to seller	50
Total fair value of consideration transferred	$ 8,606
[1]	See Note 5.

Acquisitions and Investments (S

Acquisitions and Investments (Schedule of Assets Acquired and Liabilities Assumed - MarkWest) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 04, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Goodwill	$ 4,019		$ 1,566	$ 938
MarkWest
Business Acquisition [Line Items]
Cash and cash equivalents		$ 12
Receivables		164
Inventories		33
Other current assets		44
Equity method investments		2,457
Property, plant and equipment, net		8,474
Other noncurrent assets		473
Total assets acquired		11,657
Accounts payable		322
Payroll and benefits payable		13
Accrued taxes		21
Other current liabilities		44
Long-term debt		4,567
Deferred income taxes		374
Deferred credits and other liabilities		151
Noncontrolling interests		13
Total liabilities assumed		5,505
Net assets acquired excluding goodwill		6,152
Goodwill		2,454
Net assets acquired		$ 8,606

Acquisitions and Investments (R

Acquisitions and Investments (Revenues and Earnings of MarkWest Included in Consolidated Statements of Income) (Details) - MarkWest $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Business Acquisition [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ 120
Income from operations	$ 32

Acquisitions and Investments (A

Acquisitions and Investments (Acquisition of Hess' Retail Operations and Related Assets) (Details) $ in Millions	Sep. 30, 2014USD ($)bbl / d	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Business Acquisition [Line Items]
Goodwill		$ 4,019	$ 1,566	$ 938
Hess Retail Operations and Related Assets
Business Acquisition [Line Items]
Allocation of space on Colonial Pipeline (in barrels per day) | bbl / d	40,000
Cash payment for acquisition	$ 2,824
Goodwill	629
Other noncurrent assets	111
Deferred credits and other liabilities	155
Transaction costs	14
Hess Retail Operations and Related Assets | Trade Names
Business Acquisition [Line Items]
Finite-lived intangibles	$ 22
Finite-lived intangible asset, useful life (in years)	2 years
Hess Retail Operations and Related Assets | Favorable lease contract terms
Business Acquisition [Line Items]
Other noncurrent assets	$ 72
Hess Retail Operations and Related Assets | Unfavorable Leases
Business Acquisition [Line Items]
Deferred credits and other liabilities	$ 90

Acquisitions and Investments 69

Acquisitions and Investments (Fair Value of Consideration Transferred - Hess Retail) (Details) - Hess Retail Operations and Related Assets $ in Millions	Sep. 30, 2014USD ($)
Business Acquisition [Line Items]
Cash payment for acquisition	$ 2,824
Net working capital adjustment estimate	(3)
Total fair value of consideration transferred	$ 2,821

Acquisitions and Investments 70

Acquisitions and Investments (Schedule of Assets Acquired and Liabilities Assumed - Hess Retail) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Goodwill	$ 4,019	$ 1,566		$ 938
Hess Retail Operations and Related Assets
Business Acquisition [Line Items]
Cash and cash equivalents			$ 49
Receivables			123
Inventories			165
Other current assets			8
Property, plant and equipment, net			2,063
Other noncurrent assets			111
Total assets acquired			2,519
Accounts payable			77
Payroll and benefits payable			15
Consumer excise taxes payable			64
Accrued taxes			4
Other current liabilities			10
Defined benefit postretirement plan obligations			2
Deferred credits and other liabilities			155
Total liabilities assumed			327
Net assets acquired excluding goodwill			2,192
Goodwill			629
Net assets acquired			$ 2,821

Acquisitions and Investments 71

Acquisitions and Investments (Revenues and Earnings of Hess Retail Included in Consolidated Statement of Income) (Details) - Hess Retail Operations and Related Assets $ in Millions	12 Months Ended
	Dec. 31, 2014USD ($)
Business Acquisition [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ 2,403
Income from operations	$ 113

Acquisitions and Investments 72

Acquisitions and Investments (Acquisition of Refinery and Related Logistics and Marketing Assets) (Detail) - Galveston Bay Refinery and Related Assets	1 Months Ended
	Feb. 01, 2013USD ($)bbl / dsiteTerminalBPCDPipelineMW	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Business Acquisition [Line Items]
Refinery capacity (in barrels per calendar day) | BPCD	451,000
Intrastate natural gas liquid pipelines (in number of pipelines) | Pipeline	3
Number of light product terminals (in number of terminals) | Terminal	4
Number of branded sites (in number of sites) | site	1,200
Electric cogeneration capacity, megawatt | MW	1,040
Allocation of space on Colonial Pipeline (in barrels per day) | bbl / d	50,000
Cash payment for acquisition	$ 1,490,000,000
Inventories	935,000,000
Maximum earnout provision payable to the company	$ 700,000,000	$ 331,000,000	$ 520,000,000
Term of payment of maximum earnout provision payable to the company, years	6 years
Acquisition related costs	$ 7,000,000

Acquisitions and Investments 73

Acquisitions and Investments (Schedule of Acquisition Related Pro Forma Financial Information (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Combinations [Abstract]
Sales and other operating revenues (including consumer excise taxes)	$ 73,760	$ 108,605	$ 114,148
Net income attributable to MPC	$ 2,825	$ 2,522	$ 2,142
Net income attributable to MPC per share – basic	$ 5.25	$ 4.42	$ 3.40
Net income attributable to MPC per share – diluted	$ 5.21	$ 4.39	$ 3.38

Acquisitions and Investments 74

Acquisitions and Investments (Acquisition of Biodiesel Facility) (Details) - Felda Iffco Sdn Bhd gallons_per_year in Millions, $ in Millions	1 Months Ended
	Apr. 30, 2014USD ($)	Apr. 01, 2014gallons_per_year
Business Acquisition [Line Items]
Cash payment for acquisition | $	$ 40
Plant capacity volume | gallons_per_year		60

Acquisitions and Investments (I

Acquisitions and Investments (Investments in Ethanol Companies) (Details) $ in Millions	1 Months Ended
	Aug. 01, 2013USD ($)Company	Dec. 31, 2015
TACE
Business Acquisition [Line Items]
Equity method investments, ownership percentage		60.00%
TAEI
Business Acquisition [Line Items]
Equity method investments, ownership percentage		34.00%
TAME
Business Acquisition [Line Items]
Equity method investments, ownership percentage		67.00%
TAME | TAEI
Business Acquisition [Line Items]
Equity method investments, ownership percentage		50.00%
TAAE
Business Acquisition [Line Items]
Equity method investments, ownership percentage		43.00%
Ethanol Interests From Mitsui
Business Acquisition [Line Items]
Number of businesses in which ownership interests acquired | Company	3
Cash paid to acquire equity method investments | $	$ 75
Ethanol Interests From Mitsui | TACE
Business Acquisition [Line Items]
Ownership percentage acquired	24.00%
Ethanol Interests From Mitsui | TAEI
Business Acquisition [Line Items]
Ownership percentage acquired	34.00%
Ethanol Interests From Mitsui | TAAE
Business Acquisition [Line Items]
Ownership percentage acquired	40.00%

Acquisitions and Investments 76

Acquisitions and Investments (Investment in Ocean Vessel Joint Venture) (Details) - Crowley Ocean Partners $ in Millions	1 Months Ended
	Sep. 30, 2015USD ($)vessel	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	50.00%	50.00%
Number of vessels | vessel	4
Cash paid to acquire equity method investments | $	$ 72

Acquisitions and Investments 77

Acquisitions and Investments (Investment in Pipeline Companies) (Details) - USD ($) $ in Millions	Mar. 04, 2014	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2015	Jan. 01, 2019	Jan. 01, 2017	Jul. 01, 2014
Illinois Extension Pipeline
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage		35.00%	35.00%	35.00%			35.00%
Cash paid to acquire equity method investments		$ 147	$ 267
Explorer
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage		25.00%	25.00%	25.00%
Cash paid to acquire equity method investments	$ 77
Ownership percentage acquired	7.00%
North Dakota Pipeline
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage		37.50%	37.50%	37.50%
Cash paid to acquire equity method investments		$ 71		$ 287
North Dakota Pipeline Class A Units | Scenario, Forecast
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage					27.00%	27.00%
North Dakota Pipeline Class A Units | Scenario, Forecast | Maximum
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage					30.00%

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions	Dec. 31, 2015USD ($)
MarkWest Utica EMG
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	60.00%
Maximum loss exposure, amount	$ 2,160
Ohio Gathering
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage	36.00%

Related Party Transactions (Nar

Related Party Transactions (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Sep. 30, 2015	Jul. 01, 2014
Related Party Transaction [Line Items]
Other income from related parties	$ 4	$ 1	$ 1
Centennial
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	50.00%
Crowley Ocean Partners
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	50.00%			50.00%
Explorer
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	25.00%
Illinois Extension Pipeline
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	35.00%				35.00%
LOCAP
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	59.00%
LOOP
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	51.00%
MarkWest EMG Jefferson
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	67.00%
MarkWest Utica EMG
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	60.00%
Ohio Condensate
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	60.00%
Long-term receivable from related party	$ 1
Ohio Gathering
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	36.00%
TAAE
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	43.00%
TACE
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	60.00%
TAME
Related Party Transaction [Line Items]
Equity method investments, ownership percentage	67.00%
Other equity method investees
Related Party Transaction [Line Items]
Sales to related parties	$ 6	$ 7	$ 8

Related Party Transactions (Pur

Related Party Transactions (Purchases From Related Parties) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Purchases from related parties	$ 308	$ 505	$ 357
Centennial
Related Party Transaction [Line Items]
Purchases from related parties	0	7	3
Crowley Ocean Partners
Related Party Transaction [Line Items]
Purchases from related parties	6	0	0
Explorer
Related Party Transaction [Line Items]
Purchases from related parties	20	39	0
Illinois Extension Pipeline
Related Party Transaction [Line Items]
Purchases from related parties	4	0	0
LOCAP
Related Party Transaction [Line Items]
Purchases from related parties	23	21	17
LOOP
Related Party Transaction [Line Items]
Purchases from related parties	52	88	43
TAAE
Related Party Transaction [Line Items]
Purchases from related parties	52	79	24
TACE
Related Party Transaction [Line Items]
Purchases from related parties	54	121	130
TAME
Related Party Transaction [Line Items]
Purchases from related parties	87	141	131
Other equity method investees
Related Party Transaction [Line Items]
Purchases from related parties	$ 10	$ 9	$ 9

Related Party Transactions (Rec

Related Party Transactions (Receivables From Related Parties) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Current receivables from related parties	$ 13	$ 7
Centennial
Related Party Transaction [Line Items]
Current receivables from related parties	1	2
Explorer
Related Party Transaction [Line Items]
Current receivables from related parties	0	2
MarkWest EMG Jefferson
Related Party Transaction [Line Items]
Current receivables from related parties	2	0
MarkWest Utica EMG
Related Party Transaction [Line Items]
Current receivables from related parties	1	0
Ohio Condensate
Related Party Transaction [Line Items]
Current receivables from related parties	3	0
Ohio Gathering
Related Party Transaction [Line Items]
Current receivables from related parties	5	0
TAME
Related Party Transaction [Line Items]
Current receivables from related parties	0	3
Other equity method investees
Related Party Transaction [Line Items]
Current receivables from related parties	$ 1	$ 0

Related Party Transactions (Pay

Related Party Transactions (Payables To Related Parties) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Payables to related parties	$ 42	$ 18
Explorer
Related Party Transaction [Line Items]
Payables to related parties	1	3
Illinois Extension Pipeline
Related Party Transaction [Line Items]
Payables to related parties	4	0
LOCAP
Related Party Transaction [Line Items]
Payables to related parties	2	2
LOOP
Related Party Transaction [Line Items]
Payables to related parties	5	4
MarkWest Utica EMG
Related Party Transaction [Line Items]
Payables to related parties	19	0
Ohio Condensate
Related Party Transaction [Line Items]
Payables to related parties	4	0
TAAE
Related Party Transaction [Line Items]
Payables to related parties	1	2
TACE
Related Party Transaction [Line Items]
Payables to related parties	2	2
TAME
Related Party Transaction [Line Items]
Payables to related parties	3	5
Other equity method investees
Related Party Transaction [Line Items]
Payables to related parties	$ 1	$ 0

Income per Common Share (Summar

Income per Common Share (Summary Of Earnings Per Common Share) (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	3 Months Ended													12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015		Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Basic earnings per share:
Net income attributable to MPC	$ 187	$ 948	$ 826	$ 891		$ 798		$ 672		$ 855		$ 199		$ 2,852	$ 2,524	$ 2,112
Income allocated to participating securities, basic														4	4	4
Income available to common stockholders – basic														$ 2,848	$ 2,520	$ 2,108
Weighted average common shares outstanding (in shares)														538	570	630
Basic (in USD per share)	$ 0.35	$ 1.77	$ 1.52	$ 1.63	[1]	$ 1.44	[1]	$ 1.19	[1]	$ 1.49	[1]	$ 0.34	[1]	$ 5.29	$ 4.42	$ 3.34
Diluted earnings per share:
Net income attributable to MPC	$ 187	$ 948	$ 826	$ 891		$ 798		$ 672		$ 855		$ 199		$ 2,852	$ 2,524	$ 2,112
Income allocated to participating securities, diluted														4	4	4
Income available to common stockholders – diluted														$ 2,848	$ 2,520	$ 2,108
Weighted average common shares outstanding (in shares)														538	570	630
Effect of dilutive securities (in shares)														4	4	4
Weighted average common shares, including dilutive effect (in shares)														542	574	634
Diluted (in USD per share)	$ 0.35	$ 1.76	$ 1.51	$ 1.62	[1]	$ 1.43	[1]	$ 1.18	[1]	$ 1.48	[1]	$ 0.34	[1]	$ 5.26	$ 4.39	$ 3.32
[1]	We completed a two-for-one stock split in June 2015. All historical per share data has been retroactively restated on a post-split basis.

Income Per Common Share (Anti-d

Income Per Common Share (Anti-dilutive Shares) (Detail) - shares shares in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Shares issued under stock-based compensation plans
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive securities excluded from computation of earnings per share, amount	1	1	1

Equity (Narrative) (Detail)

Equity (Narrative) (Detail) - USD ($) $ / shares in Units, $ in Millions	Jul. 29, 2015	Jan. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2015
Stockholders Equity [Line Items]
Stock repurchase plan authorized amount			$ 10,000				$ 10,000
Cash paid for shares repurchased			965	$ 2,131	$ 2,793		7,240
Stock repurchase plan remaining authorized amount			$ 2,760				$ 2,760
Number of shares repurchased			19,000,000	49,000,000	74,000,000	[1]	198,000,000
Effective average cost per delivered share			$ 50.31	$ 44.31	$ 38.07		$ 36.65
Scenario, Forecast
Stockholders Equity [Line Items]
Cash paid for shares repurchased		$ 9
Number of shares repurchased		172,200
Share Repurchase Authorization July 2015
Stockholders Equity [Line Items]
Stock repurchase plan authorized amount	$ 2,000
Ending date of share repurchase authorization	Jul. 29, 2017
[1]	Shares repurchased in 2013 includes 2 million shares received under the November 2012 accelerated share repurchase program, which were paid for in 2012.

Equity (Share Repurchases) (Det

Equity (Share Repurchases) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended				48 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013		Dec. 31, 2015
Stockholders Equity [Line Items]
Number of shares repurchased	19	49	74	[1]	198
Cash paid for shares repurchased	$ 965	$ 2,131	$ 2,793		$ 7,240
Effective average cost per delivered share	$ 50.31	$ 44.31	$ 38.07		$ 36.65
Accelerated Share Repurchase Program November 2012
Stockholders Equity [Line Items]
Number of shares repurchased			2
[1]	Shares repurchased in 2013 includes 2 million shares received under the November 2012 accelerated share repurchase program, which were paid for in 2012.

Segment Information (Narrative)

Segment Information (Narrative) (Detail) - Segment	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Number of reportable segments	3
None | Maximum
Segment Reporting Information [Line Items]
Percent of annual revenues	10.00%	10.00%
BP plc
Segment Reporting Information [Line Items]
Percent of annual revenues			10.00%

Segment Information (Income Fro

Segment Information (Income From Operations Attributable To Operating Segments) (Detail) - USD ($) $ in Millions		Dec. 04, 2015	Sep. 30, 2014	Feb. 01, 2013	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)													$ 72,051		$ 97,817		$ 100,160
Income from operations					$ 338	$ 1,549	$ 1,335	$ 1,470	$ 1,259	$ 1,062	$ 1,369	$ 361	4,692		4,051		3,425
Income from equity method investments													88		153		36
Depreciation and amortization													1,646		1,326		1,220
Segment capital expenditures and investments	[1],[2]												16,283		4,738		2,789
Inventory market valuation charge													370		0		0
MarkWest
Segment Reporting Information [Line Items]
Transaction costs		$ 6
Hess Retail Operations and Related Assets
Segment Reporting Information [Line Items]
Segment capital expenditures and investments															2,710
Transaction costs			$ 14							$ 14
Galveston Bay Refinery and Related Assets
Segment Reporting Information [Line Items]
Segment capital expenditures and investments																	1,360
Refining & Marketing
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)													52,174		80,822		85,616
Inventory market valuation charge	[3]												345
Speedway
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)													19,690		16,927		14,471
Inventory market valuation charge	[3]												25
Midstream
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)													187		70		79
Midstream | MarkWest
Segment Reporting Information [Line Items]
Transaction costs		36
Reportable Segment
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)													72,051		97,819		100,166
Intersegment Eliminations
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)	[4]												12,585		11,444		9,756
Intersegment Eliminations | Refining & Marketing
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)	[4]												12,018		10,912		9,294
Intersegment Eliminations | Speedway
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)	[4]												3		5		4
Intersegment Eliminations | Midstream
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)	[4]												564		527		458
Operating Segments
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)													84,636		109,263		109,922
Income from operations	[5]												5,148	[6]	4,433		3,791
Income from equity method investments													88		153		36
Depreciation and amortization	[7]												1,450		1,274		1,197
Segment capital expenditures and investments	[8]												16,091	[9]	4,628	[10]	2,624	[11]
Operating Segments | Refining & Marketing
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)													64,192		91,734		94,910
Income from operations	[5]												4,186	[6]	3,609		3,206
Income from equity method investments													26		96		28
Depreciation and amortization	[7]												1,079		1,045		1,011
Segment capital expenditures and investments	[8]												1,143	[9]	1,104	[10]	2,094	[11]
Operating Segments | Refining & Marketing | Hess Retail Operations and Related Assets
Segment Reporting Information [Line Items]
Segment capital expenditures and investments			52
Operating Segments | Refining & Marketing | Galveston Bay Refinery and Related Assets
Segment Reporting Information [Line Items]
Segment capital expenditures and investments				$ 1,290
Operating Segments | Speedway
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)													19,693		16,932		14,475
Income from operations	[5]												673	[6]	544		375
Income from equity method investments													0		0		0
Depreciation and amortization	[7]												254		152		112
Segment capital expenditures and investments	[8]												501	[9]	2,981	[10]	296
Operating Segments | Speedway | Hess Retail Operations and Related Assets
Segment Reporting Information [Line Items]
Segment capital expenditures and investments			$ 2,660
Operating Segments | Midstream
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)													751		597		537
Income from operations	[5]												289	[6]	280		210
Income from equity method investments													62		57		8
Depreciation and amortization	[7]												117		77		74
Segment capital expenditures and investments	[8]												14,447	[9]	543		234	[11]
Operating Segments | Midstream | MarkWest
Segment Reporting Information [Line Items]
Segment capital expenditures and investments		$ 13,850
Operating Segments | Midstream | Galveston Bay Refinery and Related Assets
Segment Reporting Information [Line Items]
Segment capital expenditures and investments				$ 70
Operating Segments | Midstream | MPLX LP
Segment Reporting Information [Line Items]
Cost of services, overhead													$ 20		$ 19		$ 20
[1]	Capital expenditures include changes in capital accruals.
[2]	Includes $13.85 billion in 2015 for the MarkWest Merger, $2.71 billion in 2014 for the acquisition of Hess’ Retail Operations and Related Assets and $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5.
[3]	Related to the cancellation of the ROUX project at our Garyville, LA refinery. See Note
[4]	Management believes intersegment transactions were conducted under terms comparable to those with unaffiliated parties.
[5]	Included in the Midstream segment for 2015, 2014 and 2013 are $20 million, $19 million and $20 million, respectively, of corporate overhead expenses attributable to MPLX. Corporate overhead expenses are not currently allocated to other segments. Also included in the Midstream segment for 2015 are $36 million of transaction costs related to the MarkWest Merger.
[6]	The Refining & Marketing and Speedway segments include inventory lower of cost or market charge of $345 million and $25 million, respectively.
[7]	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.
[8]	Capital expenditures include changes in capital accruals, acquisitions and investments in affiliates.
[9]	The Midstream segment includes $13.85 billion for the MarkWest Merger. See Note 5.
[10]	The Speedway and Refining & Marketing segments include $2.66 billion and $52 million, respectively, for the acquisition of Hess’ Retail Operations and Related Assets. See Note 5.
[11]	The Refining & Marketing and Midstream segments include $1.29 billion and $70 million, respectively, for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5.

Segment Information (Reconcilia

Segment Information (Reconciliation Of Segment Income From Operations To Income Before Income Taxes) (Detail) - USD ($) $ in Millions

3 Months Ended

12 Months Ended

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]

Income from operations

$ 338

$ 1,549

$ 1,335

$ 1,470

$ 1,259

$ 1,062

$ 1,369

$ 361

$ 4,692

$ 4,051

$ 3,425

Net interest and other financial income (costs)

318

216

179

Income before income taxes

4,374

3,835

3,246

Operating Segments

Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]

Income from operations

[1]

5,148

[2]

4,433

3,791

Corporate and Other

Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]

Income from operations

[3],[4]

(308)

(286)

(271)

Segment Reconciling Items

Segment Reporting, Reconciling Item for Operating Profit (Loss) from Segment to Consolidated [Line Items]

Pension settlement expenses

[5]

(4)

(96)

(95)

Impairment

$ (144)

[6]

$ 0

$ 0

[1]

Included in the Midstream segment for 2015, 2014 and 2013 are $20 million, $19 million and $20 million, respectively, of corporate overhead expenses attributable to MPLX. Corporate overhead expenses are not currently allocated to other segments. Also included in the Midstream segment for 2015 are $36 million of transaction costs related to the MarkWest Merger.

[2]

The Refining & Marketing and Speedway segments include inventory lower of cost or market charge of $345 million and $25 million, respectively.

[3]

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

[4]

Corporate overhead expenses attributable to MPLX are included in the Midstream segment. Corporate overhead expenses are not allocated to the Refining & Marketing and Speedway segments.

[5]

See Note 22.

[6]

Related to the cancellation of the ROUX project at our Garyville, LA refinery. See Note

Segment Information (Reconcil90

Segment Information (Reconciliation Of Segment Capital Expenditures And Investments To Total Capital Expenditures) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013		Dec. 04, 2015
Segment Reporting, Other Significant Reconciling Item [Line Items]
Segment capital expenditures and investments	[1],[2]	$ 16,283		$ 4,738		$ 2,789
Plus: Items not allocated to segments:
Total capital expenditures	[3]	13,495		4,325		2,665
Operating Segments
Segment Reporting, Other Significant Reconciling Item [Line Items]
Segment capital expenditures and investments	[4]	16,091	[5]	4,628	[6]	2,624	[7]
Less: Investments in equity method investees(a)		2,788	[8]	413		124
Corporate and Other
Segment Reporting, Other Significant Reconciling Item [Line Items]
Segment capital expenditures and investments	[9]	192		110		165
Plus: Items not allocated to segments:
Capital expenditures not allocated to segments		155		83		137
Capitalized interest		$ 37		$ 27		$ 28
MarkWest
Plus: Items not allocated to segments:
Equity method investments								$ 2,457
[1]	Capital expenditures include changes in capital accruals.
[2]	Includes $13.85 billion in 2015 for the MarkWest Merger, $2.71 billion in 2014 for the acquisition of Hess’ Retail Operations and Related Assets and $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5.
[3]	Capital expenditures include changes in capital accruals. See Note 20 for a reconciliation of total capital expenditures to additions to property, plant and equipment as reported in the consolidated statements of cash flows.
[4]	Capital expenditures include changes in capital accruals, acquisitions and investments in affiliates.
[5]	The Midstream segment includes $13.85 billion for the MarkWest Merger. See Note 5.
[6]	The Speedway and Refining & Marketing segments include $2.66 billion and $52 million, respectively, for the acquisition of Hess’ Retail Operations and Related Assets. See Note 5.
[7]	The Refining & Marketing and Midstream segments include $1.29 billion and $70 million, respectively, for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5.
[8]	2015 includes $2.46 billion for the MarkWest Merger. See Note 5
[9]	Includes capitalized interest of $37 million, $27 million and $28 million for 2015, 2014 and 2013, respectively.

Segment Information (Reconcil91

Segment Information (Reconciliation Of Total Segment Customer Revenues To Sales And Other Operating Revenues) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ 72,051	$ 97,817	$ 100,160
Corporate and Other
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales and other operating revenues (including consumer excise taxes)	0	(2)	(6)
Reportable Segment
Segment Reporting, Revenue Reconciling Item [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ 72,051	$ 97,819	$ 100,166

Segment Information (Schedule O

Segment Information (Schedule Of Revenues By Product Line) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ 72,051	$ 97,817	$ 100,160
Refined products
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)	63,708	90,702	93,520
Merchandise
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)	5,188	3,817	3,308
Crude oil and refinery feedstocks
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)	2,718	2,917	2,988
Transportation and other
Segment Reporting Information [Line Items]
Sales and other operating revenues (including consumer excise taxes)	$ 437	$ 381	$ 344

Segment Information (Total Asse

Segment Information (Total Assets By Reportable Segment) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	$ 43,115	$ 30,425
Operating Segments | Refining & Marketing
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	17,780	19,751
Operating Segments | Speedway
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	5,349	5,296
Operating Segments | Midstream
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	17,061	2,407
Corporate and Other
Segment Reporting, Asset Reconciling Item [Line Items]
Total consolidated assets	$ 2,925	$ 2,971

Other Items (Net Interest And O

Other Items (Net Interest And Other Financial Income (Costs)) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013	Dec. 04, 2015
Interest income	$ 6		$ 7	$ 9
Interest expense	(325)		(229)	(195)
Interest capitalized	37		27	28
Loss on extinguishment of debt	(5)	[1]	0	0
Other financial costs	(31)		(21)	(21)
Net interest and other financial income (costs)	$ (318)		$ (216)	$ (179)
MarkWest
Transaction costs					$ 6
[1]	2015 includes $6 million of transaction costs related to the MarkWest Merger.

Income Taxes (Components Of Inc

Income Taxes (Components Of Income Tax Provisions (Benefits)) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Current
Federal	$ 1,210	$ 1,382	$ 954
State and local	152	135	131
Foreign	10	5	5
Total	1,372	1,522	1,090
Deferred
Federal	134	(199)	20
State and local	9	(37)	8
Foreign	(9)	(6)	(5)
Total	134	(242)	23
Total
Federal	1,344	1,183	974
State and local	161	98	139
Foreign	1	(1)
Total	$ 1,506	$ 1,280	$ 1,113

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Statutory rate applied to income before income taxes	35.00%	35.00%	35.00%
Unrecognized tax benefits, increase (decrease)			$ (21)
Tax settlement with Marathon Oil Corporation			39
Unrecognized tax benefits that would impact effective income tax rate	$ 5
Uncertain tax positions, reasonably possible increase or decrease during the next twelve months	4
Unrecognized tax benefits income tax net penalties and interest expenses	3	$ 1	$ 11
Interest and penalties accrued	$ 18	$ 14

Income Taxes (Reconciliation Of

Income Taxes (Reconciliation Of Federal Statutory Income Tax Rate) (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Statutory rate applied to income before income taxes	35.00%	35.00%	35.00%
State and local income taxes, net of federal income tax effects	2.00%	2.00%	3.00%
Domestic manufacturing deduction	(2.00%)	(2.00%)	(2.00%)
Other	(1.00%)	(2.00%)	(2.00%)
Provision for income taxes	34.00%	33.00%	34.00%

Income Taxes (Components Of Def

Income Taxes (Components Of Deferred Tax Assets And Liabilities) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 04, 2015	Dec. 31, 2014
Deferred tax assets:
Employee benefits	$ 631		$ 616
Environmental	44		54
Investments in subsidiaries and affiliates	0		24
Net operating loss carryforwards	73		12
Other	73		58
Total deferred tax assets	821		764
Deferred tax liabilities:
Property, plant and equipment	2,512		2,411
Inventories	579		614
Investments in subsidiaries and affiliates	909		0
Other	89		101
Total deferred tax liabilities	4,089		3,126
Net deferred tax liabilities	3,268		$ 2,362
Tax effect of issuance of MPLX units - MarkWest Merger	404
MarkWest
Deferred tax liabilities:
Deferred tax liabilities assumed		$ 443
Tax effect of issuance of MPLX units - MarkWest Merger	404
Issuance of MPLX LP units - MarkWest Merger	$ 1,500

Income Taxes (Components Of Net

Income Taxes (Components Of Net Deferred Tax Liabilities Classified In Consolidated Balance Sheets (Detail) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Assets
Other noncurrent assets		$ 17	$ 7
Liabilities
Accrued taxes	[1]	0	355
Deferred income taxes		3,285	2,014
Net deferred tax liabilities		$ 3,268	$ 2,362
[1]	We adopted the updated FASB balance classification of deferred taxes standard and applied the changes prospectively. We reclassified current deferred taxes from current accrued taxes to long-term deferred income taxes. See Note 3.

Income Taxes (Tax Carryforwards

Income Taxes (Tax Carryforwards) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
United States Federal
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	$ 66
United States Federal | Minimum
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards, expiration date	Jan. 1, 2022
United States Federal | Maximum
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards, expiration date	Dec. 31, 2035
United States Federal | MarkWest
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	$ 58
States
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	$ 7
States | Minimum
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards, expiration date	Jan. 1, 2016
States | Maximum
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards, expiration date	Dec. 31, 2035
States | MarkWest
Operating Loss Carryforwards [Line Items]
Operating loss carryforwards	$ 4

Income Taxes (Valuation Allowan

Income Taxes (Valuation Allowances) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Valuation allowance	$ 4	$ 4

Income Taxes (Summary Of Income

Income Taxes (Summary Of Income Tax Returns Subject To Examination) (Detail)	12 Months Ended
	Dec. 31, 2015
United States Federal | Minimum
Income Tax Examination [Line Items]
Tax years	2,010
United States Federal | Maximum
Income Tax Examination [Line Items]
Tax years	2,014
States | Minimum
Income Tax Examination [Line Items]
Tax years	2,004
States | Maximum
Income Tax Examination [Line Items]
Tax years	2,014

Income Taxes (Summary Of Activi

Income Taxes (Summary Of Activity In Unrecognized Tax Benefits) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
January 1 balance	$ 12	$ 13	$ 40
Additions for tax positions of prior years	0	7	30
Reductions for tax positions of prior years	0	(10)	(25)
Settlements	0	2	(30)
Statute of limitations	0	0	(2)
December 31 balance	$ 12	$ 12	$ 13

Inventories (Summary Of Invento

Inventories (Summary Of Inventories) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Inventory Disclosure [Abstract]
Crude oil and refinery feedstocks	$ 2,180	$ 2,219
Refined products	2,804	2,955
Materials and supplies	438	302
Merchandise	173	166
Lower of cost or market reserve	(370)	0
Total	$ 5,225	$ 5,642

Inventories (Narrative) (Detail

Inventories (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Inventory Disclosure [Abstract]
Total inventory LIFO percentage	91.00%	94.00%
Inventory market valuation charge	$ 370	$ 0	$ 0
Excess of current acquisition costs over stated LIFO value		684
Impact on revenues and costs as a result of LIFO liquidations	$ (78)	$ 0	$ 0

Equity Method Investments (Sche

Equity Method Investments (Schedule Of Equity Method Investments) (Detail) - USD ($) $ in Millions		Jan. 01, 2019	Jan. 01, 2017	Dec. 31, 2015	Sep. 30, 2015	Dec. 31, 2014	Jul. 01, 2014
Schedule of Equity Method Investments [Line Items]
Equity method investments				$ 3,622		$ 865
Centennial
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage				50.00%
Equity method investments				$ 37		36
Centrahoma Processing LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage				40.00%
Equity method investments				$ 111		0
Crowley Ocean Partners
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage				50.00%	50.00%
Equity method investments				$ 72		0
Explorer
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage				25.00%
Equity method investments				$ 91		95
Illinois Extension Pipeline
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage				35.00%			35.00%
Equity method investments				$ 267		120
LOCAP
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage				59.00%
Equity method investments				$ 22		23
LOOP
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage				51.00%
Equity method investments				$ 243		230
MarkWest Utica EMG
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage				60.00%
Equity method investments				$ 2,160		0
North Dakota Pipeline Class B Units
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage				38.00%
Equity method investments	[1]			$ 287		216
Ohio Condensate
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage				60.00%
Equity method investments				$ 101		0
TAAE
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage				43.00%
Equity method investments				$ 27		22
TACE
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage				60.00%
Equity method investments				$ 49		61
TAEI
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage				34.00%
Equity method investments				$ 18		19
TAME
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage				67.00%
Equity method investments	[2]			$ 27		24
TAME | Direct Ownership Interest
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage				50.00%
Other equity method investees
Schedule of Equity Method Investments [Line Items]
Equity method investments				$ 24		19
Other equity method investees | MPLX LP
Schedule of Equity Method Investments [Line Items]
Equity method investments				$ 86		$ 0
North Dakota Pipeline Class A Units | Scenario, Forecast
Schedule of Equity Method Investments [Line Items]
Equity method investments, ownership percentage		27.00%	27.00%
[1]	We own a 38 percent interest in the Class B units of this entity. Our Class B units will be converted to an approximate 27 percent ownership interest in the Class A units of this entity upon completion of the Sandpiper pipeline construction project, which is expected to be in early 2019.
[2]	Excludes TAEI’s investment in TAME.

Equity Method Investments (Summ

Equity Method Investments (Summarized Financial Information For Equity Method Investees) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income statement data:
Revenues and other income	$ 1,390	$ 1,430	$ 1,067
Income from operations	332	379	87
Net income	239	316	$ 63
Balance sheet data – December 31:
Current assets	906	990
Noncurrent assets	6,418	2,166
Current liabilities	468	280
Noncurrent liabilities	$ 1,130	$ 957

Equity Method Investments (Narr

Equity Method Investments (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Schedule of Equity Method Investments [Line Items]
Equity method investment difference between carrying amount and underlying equity	$ 1,070
Equity method investment difference between carrying amount and underlying equity, portion related to goodwill which is not being amortized	426
Equity method investments	3,622	$ 865
Dividends and partnership distributions received from equity method investees	113	170	$ 18
Centennial
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 37	$ 36
Percent of debt outstanding	50.00%
Centennial | Financial Guarantee | Master Shelf Agreement
Schedule of Equity Method Investments [Line Items]
Maximum potential undiscounted payments	$ 34

Property, Plant And Equipmen109

Property, Plant And Equipment (Summary Of Property, Plant And Equipment) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 35,604	$ 25,302
Less accumulated depreciation	10,440	9,041
Net property, plant and equipment	$ 25,164	16,261
Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	2 years
Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	42 years
Operating Segments | Refining & Marketing
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 18,925	18,001
Operating Segments | Refining & Marketing | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	2 years
Operating Segments | Refining & Marketing | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	30 years
Operating Segments | Speedway
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 5,067	4,639
Operating Segments | Speedway | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	4 years
Operating Segments | Speedway | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	25 years
Operating Segments | Midstream
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 10,850	2,044
Operating Segments | Midstream | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	10 years
Operating Segments | Midstream | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	42 years
Corporate and Other
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 762	$ 618
Corporate and Other | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	4 years
Corporate and Other | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful lives (in years)	40 years

Property, Plant And Equipmen110

Property, Plant And Equipment (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 35,604	$ 25,302
Property, plant and equipment, accumulated depreciation	10,440	9,041
Residual Oil Upgrader Expansion project - Garyville [Member]
Property, Plant and Equipment [Line Items]
Impairment charge	144
Assets Held Under Capital Leases
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	511	510
Property, plant and equipment, accumulated depreciation	176	144
Construction in progress
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	$ 2,263	$ 1,043

Goodwill (Narrative) (Detail)

Goodwill (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 04, 2015	Dec. 31, 2013
Goodwill [Line Items]
Amount of required impairment	$ 0	$ 0
Goodwill	$ 4,019	$ 1,566		$ 938
MarkWest
Goodwill [Line Items]
Goodwill			$ 2,454

Goodwill (Changes In Carrying A

Goodwill (Changes In Carrying Amount Of Goodwill) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014
Goodwill [Line Items]
Beginning balance		$ 1,566	$ 938
Goodwill acquired during period	[1]	2,454	629
Goodwill, disposition		(1)	(1)
Ending balance		4,019	1,566
Refining & Marketing
Goodwill [Line Items]
Beginning balance		550	551
Goodwill acquired during period		0	0
Goodwill, disposition		0	(1)
Ending balance		550	550
Speedway
Goodwill [Line Items]
Beginning balance		854	225
Goodwill acquired during period	[1]	0	629
Goodwill, disposition		(1)	0
Ending balance		853	854
Midstream
Goodwill [Line Items]
Beginning balance		162	162
Goodwill acquired during period		2,454	0
Goodwill, disposition		0	0
Ending balance		$ 2,616	$ 162
[1]	See Note 5 for information on the acquisitions.

Intangibles (Intangible Assets

Intangibles (Intangible Assets by Major Class) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		$ 856	$ 403
Accumulated amortization		(137)	(116)
Net		719	287
Customer contracts and relationships
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		560	106
Royalty agreements
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		122	121
Favorable lease contract terms
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		71	72
Other intangible assets
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		103	104
Refining & Marketing
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		242	257
Accumulated amortization		(104)	(106)
Net		138	151
Indefinite-lived intangible assets		3	3
Refining & Marketing | Customer contracts and relationships
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		91	105
Refining & Marketing | Royalty agreements
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		122	121
Refining & Marketing | Favorable lease contract terms
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		1	1
Refining & Marketing | Other intangible assets
Acquired Finite-Lived Intangible Assets [Line Items]
Gross	[1]	28	30
Speedway
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		146	146
Accumulated amortization		(31)	(10)
Net		115	136
Indefinite-lived intangible assets		46	46
Speedway | Customer contracts and relationships
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		1	1
Speedway | Royalty agreements
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		0	0
Speedway | Favorable lease contract terms
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		70	71
Speedway | Other intangible assets
Acquired Finite-Lived Intangible Assets [Line Items]
Gross	[1]	75	74
Midstream
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		468	0
Accumulated amortization		(2)	0
Net		466	0
Midstream | Customer contracts and relationships
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		468	0
Midstream | Royalty agreements
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		0	0
Midstream | Favorable lease contract terms
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		0	0
Midstream | Other intangible assets
Acquired Finite-Lived Intangible Assets [Line Items]
Gross		$ 0	$ 0
[1]	Refining & Marketing and Speedway segments include unamortized intangible assets of $3 million and $46 million, respectively

Intangibles (Narrative) (Detail

Intangibles (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization expense	$ 29	$ 18

Intangibles (Estimated Future A

Intangibles (Estimated Future Amortization Expense) (Details) $ in Millions	Dec. 31, 2015USD ($)
Goodwill and Intangible Assets Disclosure [Abstract]
2,016	$ 48
2,017	45
2,018	45
2,019	44
2,020	$ 47

Fair Value Measurements (Assets

Fair Value Measurements (Assets And Liabilities Accounted For At Fair Value On Recurring Basis) (Detail) - USD ($) $ in Millions		Dec. 31, 2015		Dec. 31, 2014
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Cash collateral netted with derivative assets		$ (23)		$ (78)
Contingent consideration, current		196		174
Embedded derivative in commodity contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Embedded derivative instruments, current		5
Fair Value, Measurements, Recurring
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets - collateral and netting		(62)		(258)
Commodity derivative instruments, assets - collateral pledged not offset		0		0
Other assets		2		2
Total assets at fair value		53		61
Commodity derivative instruments, liabilities - netting and collateral		(39)		(180)
Commodity derivative instruments, liabilities - collateral pledged not offset		0		0
Contingent consideration, liability	[1]	317		478
Total liabilities at fair value		349		478
Fair Value, Measurements, Recurring | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other assets		2		2
Total assets at fair value		106		319
Contingent consideration, liability		0		0
Total liabilities at fair value		39		180
Fair Value, Measurements, Recurring | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other assets		0		0
Total assets at fair value		2		0
Contingent consideration, liability		0		0
Total liabilities at fair value		0		0
Fair Value, Measurements, Recurring | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Other assets		0		0
Total assets at fair value		7		0
Contingent consideration, liability		317	[1]	478
Total liabilities at fair value		349		478
Fair Value, Measurements, Recurring | Commodity derivative instruments
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets - collateral and netting	[2]	(62)		(258)
Commodity derivative instruments, assets - net	[3]	51		59
Commodity derivative instruments, assets - collateral pledged not offset		0		0
Commodity derivative instruments, liabilities - netting and collateral	[2]	(39)		(180)
Commodity derivative instruments, liabilities, net	[3]	0		0
Commodity derivative instruments, liabilities - collateral pledged not offset		0		0
Fair Value, Measurements, Recurring | Commodity derivative instruments | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets - gross		104		317
Commodity derivative instruments, liabilities - gross		39		180
Fair Value, Measurements, Recurring | Commodity derivative instruments | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets - gross		2		0
Commodity derivative instruments, liabilities - gross		0		0
Fair Value, Measurements, Recurring | Commodity derivative instruments | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, assets - gross		7		0
Commodity derivative instruments, liabilities - gross		0		$ 0
Fair Value, Measurements, Recurring | Embedded derivative in commodity contracts
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, liabilities - netting and collateral	[2],[4]	0
Commodity derivative instruments, liabilities, net	[3]	32
Commodity derivative instruments, liabilities - collateral pledged not offset		0
Fair Value, Measurements, Recurring | Embedded derivative in commodity contracts | Level 1
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, liabilities - gross		0
Fair Value, Measurements, Recurring | Embedded derivative in commodity contracts | Level 2
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, liabilities - gross		0
Fair Value, Measurements, Recurring | Embedded derivative in commodity contracts | Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Commodity derivative instruments, liabilities - gross		$ 32
[1]	Includes $196 million and $174 million classified as current as of December 31, 2015 and 2014, respectively.
[2]	Represents the impact of netting assets, liabilities and cash collateral when a legal right of offset exists. As of December 31, 2015, cash collateral of $23 million was netted with mark-to-market derivative assets. As of December 31, 2014, cash collateral of $78 million was netted with mark-to-market derivative assets.
[3]	We have no derivative contracts that are subject to master netting arrangements that are reflected gross on the balance sheet.
[4]	Includes $5 million at December 31, 2015 classified as current.

Fair Value Measurements (Narrat

Fair Value Measurements (Narrative) (Detail)	12 Months Ended
	Dec. 31, 2015USD ($)$ / bbl	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)	Feb. 01, 2013USD ($)
Galveston Bay Refinery and Related Assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Maximum earnout payment, year one				$ 200,000,000
Maximum earnout payment, year two				200,000,000
Maximum earnout payment, year three				200,000,000
Maximum earnout payment, year four				250,000,000
Maximum earnout payment, year five				250,000,000
Maximum earnout payment, year six				250,000,000
Maximum earnout provision payable to the company	$ 331,000,000	$ 520,000,000		$ 700,000,000
Level 3 | Commodity derivative instruments | Ethanol prices | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Forward commodity price	0.15
Level 3 | Commodity derivative instruments | Ethanol prices | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Forward commodity price	$ 3.40
Level 3 | Embedded derivative in commodity contracts
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Probability of renewal	50.00%
Level 3 | Embedded derivative in commodity contracts | ERCOT Pricing | Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity price	$ 23
Level 3 | Embedded derivative in commodity contracts | ERCOT Pricing | Maximum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Commodity price	$ 45
Fair Value, Measurements, Recurring | Minimum | Galveston Bay Refinery and Related Assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range of internal and external crack spread forecast per barrel | $ / bbl	7
Discount rate	5.00%
Fair Value, Measurements, Recurring | Maximum | Galveston Bay Refinery and Related Assets
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Range of internal and external crack spread forecast per barrel | $ / bbl	16
Discount rate	10.00%
Fair Value, Measurements, Recurring | Derivative
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized (gains) losses included in net income	$ (7,000,000)	0	$ 0
Fair Value, Measurements, Recurring | Contingent Consideration
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Unrealized (gains) losses included in net income	28,000,000	33,000,000	25,000,000
Fair Value, Measurements, Nonrecurring
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Impairment charge	144,000,000	0	8,000,000
Other noncurrent assets, impairment	$ 0	$ 11,000,000	$ 0

Fair Value Measurements (Reconc

Fair Value Measurements (Reconciliation Of Net Beginning And Ending Balances Recorded For Net Assets And Liabilities Classified As Level 3) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Fair Value Disclosures [Abstract]
Beginning balance	$ 478		$ 625		$ 0
Contingent consideration agreement	0		0		600
Contingent consideration payment	(189)	[1]	(180)	[1]	0
Net derivative positions assumed - MarkWest Merger	31		0		0
Unrealized and realized (gains) losses included in net income	20		33		25
Settlements of derivative instruments	2		0		0
Ending balance	342		478		625
Contingent consideration payment included on statements of cash flows	$ (175)		$ (172)		$ 0
[1]	On the consolidated statements of cash flows for 2015 and 2014, $175 million and $172 million, respectively, of the contingent earnout payment to BP is included as a financing activity with the remainder included as an operating activity.

Fair Value Measurements (Ass119

Fair Value Measurements (Assets Measured At Fair Value On Nonrecurring Basis) (Detail) - Fair Value, Measurements, Nonrecurring - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Property, plant and equipment, net, fair value	$ 0	$ 0	$ 1
Property, plant and equipment, net, impairment	144	0	8
Other noncurrent assets, fair value	0	0	0
Other noncurrent assets, impairment	$ 0	$ 11	$ 0

Fair Value Measurements (Financ

Fair Value Measurements (Financial Instruments At Fair Value, Excluding Derivative Financial Instruments) (Detail) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Fair Value
Financial assets:
Investments		$ 33	$ 26
Other		35	32
Total financial assets		68	58
Financial liabilities:
Long-term debt	[1]	11,366	6,571
Deferred credits and other liabilities		136	17
Total financial liabilities		11,502	6,588
Carrying Value
Financial assets:
Investments		2	2
Other		33	32
Total financial assets		35	34
Financial liabilities:
Long-term debt	[1]	11,628	6,265
Deferred credits and other liabilities		135	17
Total financial liabilities		$ 11,763	$ 6,282
[1]	Excludes capital leases and debt issuance costs, however, includes amount classified as short-term debt.

Derivatives (Classification Of

Derivatives (Classification Of Gross Fair Values Of Derivative Instruments, Excluding Cash Collateral) (Detail) - Commodity derivative instruments - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Other current assets
Derivatives, Fair Value [Line Items]
Asset		$ 113	$ 317
Liability		39	$ 180
Other current liabilities
Derivatives, Fair Value [Line Items]
Asset		0
Liability		5
Deferred credits and other liabilities
Derivatives, Fair Value [Line Items]
Asset		0
Liability	[1]	$ 27
[1]	Includes embedded derivatives.

Derivatives (Open Commodity Der

Derivatives (Open Commodity Derivative Contracts - Crude Oil) (Detail) bbl in Thousands	12 Months Ended
	Dec. 31, 2015bbl
Crude Oil Exchange Traded
Derivative [Line Items]
Percentage of derivative contracts expiring in the period	100.00%
Derivative contract expiration date	Mar. 31, 2016
Long | Crude Oil Exchange Traded
Derivative [Line Items]
Notional contracts (in thousands of total barrels)	14,517	[1]
Short | Crude Oil Exchange Traded
Derivative [Line Items]
Notional contracts (in thousands of total barrels)	22,989	[1]
Short | Crude Oil OTC
Derivative [Line Items]
Notional contracts (in thousands of total barrels)	110
[1]	100 percent of the exchange-traded contracts expire in the first quarter of 2016.

Derivatives Derivatives (Open C

Derivatives Derivatives (Open Commodity Derivative Contracts - Refined Product) (Details) gal in Thousands	12 Months Ended
	Dec. 31, 2015gal
Refined Products Exchange Traded
Derivative [Line Items]
Percentage of derivative contracts expiring in the period	100.00%
Derivative contract expiration date	Mar. 31, 2016
Long | Refined Products Exchange Traded
Derivative [Line Items]
Notional contracts (in thousands of total gallons)	221,256	[1]
Short | Refined Products Exchange Traded
Derivative [Line Items]
Notional contracts (in thousands of total gallons)	203,700	[1]
Short | Refined Products OTC
Derivative [Line Items]
Notional contracts (in thousands of total gallons)	43,838
[1]	of the exchange-traded contracts expire in the first quarter of 2016.

Derivatives (Effect Of Commodit

Derivatives (Effect Of Commodity Derivative Instruments In Statements Of Income) (Detail) - Commodity derivative instruments - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ 313	$ 493	$ (168)
Sales and other operating revenues
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	19	37	12
Cost of revenues
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss)	$ 294	$ 456	$ (180)

Debt (Outstanding Borrowings) (

Debt (Outstanding Borrowings) (Detail) - USD ($) $ in Millions		Feb. 12, 2015	Nov. 21, 2014	Aug. 26, 2014	Dec. 31, 2015		Dec. 31, 2014
Debt Instrument [Line Items]
Total					$ 12,475		$ 6,657
Unamortized debt issuance costs	[1]				(51)		(35)
Unamortized discount					(499)	[2]	(26)
Fair value adjustments	[3]				0		6
Amounts due within one year					(29)		(27)
Total long-term debt due after one year					11,896		6,575
Senior Notes | MPLX LP | MarkWest
Debt Instrument [Line Items]
Long-term debt, gross					63		0
Unamortized discount					(465)
Capital Lease Obligations [Member] | Consolidated subsidiaries:
Debt Instrument [Line Items]
Capital lease obligations					$ 348		372
Debt instrument maturity year, start					Jan. 1, 2016
Debt instrument maturity year, end					Dec. 31, 2028
Senior notes, 3.500%, due March 2016 | Interest Rate Swap
Debt Instrument [Line Items]
Debt instrument, interest rate					3.50%
Notional amount of interest rate swap agreements					$ 500
Deferred gain on discontinuation of interest rate fair value hedge					20
Senior notes, 3.500%, due March 2016 | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross					$ 0		750
Debt instrument, maturity date					Mar. 1, 2016
Debt instrument, interest rate					3.50%
Bank revolving credit facility due 2017 | Line of Credit
Debt Instrument [Line Items]
Long-term debt, gross					$ 0		0
Line of credit facility, expiration date					Sep. 14, 2017
Term loan agreement due 2019
Debt Instrument [Line Items]
Debt instrument, term				5 years
Term loan agreement due 2019 | Unsecured Debt
Debt Instrument [Line Items]
Long-term debt, gross					$ 700		700
Line of credit facility, expiration date					Sep. 30, 2019
Senior notes, 2.700% due December 2018 | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross					$ 600		0
Debt instrument, maturity date					Dec. 14, 2018
Debt instrument, interest rate					2.70%
Senior notes, 3.400% due December 2020 | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross					$ 650		0
Debt instrument, maturity date					Dec. 15, 2020
Debt instrument, interest rate					3.40%
Senior notes, 5.125% due March 2021 | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross					$ 1,000		1,000
Debt instrument, maturity date					Mar. 1, 2021
Debt instrument, interest rate					5.125%
Senior notes, 3.625%, due September 2024 | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross					$ 750		750
Debt instrument, maturity date					Sep. 15, 2024
Debt instrument, interest rate					3.625%
Senior notes, 6.500%, due March 2041 | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross					$ 1,250		1,250
Debt instrument, maturity date					Mar. 1, 2041
Debt instrument, interest rate					6.50%
Senior notes, 4.750%, due September 2044 | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross					$ 800		800
Debt instrument, maturity date					Sep. 15, 2044
Debt instrument, interest rate					4.75%
Senior notes, 5.850% due December 2045 | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross					$ 250		0
Debt instrument, maturity date					Dec. 15, 2045
Debt instrument, interest rate					5.85%
Senior notes, 5.000%, due September 2054 | Senior Notes
Debt Instrument [Line Items]
Long-term debt, gross					$ 400		400
Debt instrument, maturity date					Sep. 15, 2054
Debt instrument, interest rate					5.00%
MPLX term loan facility due 2019 | MPLX LP
Debt Instrument [Line Items]
Debt instrument, term			5 years
MPLX term loan facility due 2019 | Unsecured Debt | MPLX LP
Debt Instrument [Line Items]
Long-term debt, gross					$ 250		250
Line of credit facility, expiration date					Nov. 20, 2019
MPLX bank revolving credit facility due 2020 | Line of Credit | MPLX LP
Debt Instrument [Line Items]
Long-term debt, gross					$ 877		385
Line of credit facility, expiration date					Dec. 4, 2020
MPLX senior notes, 5.500%, due February 2023 | Senior Notes | MPLX LP
Debt Instrument [Line Items]
Long-term debt, gross					$ 710		0
Debt instrument, maturity date					Feb. 15, 2023
Debt instrument, interest rate					5.50%
MPLX senior notes, 5.500%, due February 2023 | Senior Notes | MPLX LP | MarkWest
Debt Instrument [Line Items]
Long-term debt, gross					$ 40
Debt instrument, maturity date					Feb. 15, 2023
Debt instrument, interest rate					5.50%
MPLX senior notes, 4.500%, due July 2023 | Senior Notes | MPLX LP
Debt Instrument [Line Items]
Long-term debt, gross					$ 989		0
Debt instrument, maturity date					Jul. 15, 2023
Debt instrument, interest rate					4.50%
MPLX senior notes, 4.500%, due July 2023 | Senior Notes | MPLX LP | MarkWest
Debt Instrument [Line Items]
Long-term debt, gross					$ 11
Debt instrument, maturity date					Jul. 15, 2023
Debt instrument, interest rate					4.50%
MPLX senior notes, 4.875%, due December 2024 | Senior Notes | MPLX LP
Debt Instrument [Line Items]
Long-term debt, gross					$ 1,149		0
Debt instrument, maturity date					Dec. 1, 2024
Debt instrument, interest rate					4.875%
MPLX senior notes, 4.875%, due December 2024 | Senior Notes | MPLX LP | MarkWest
Debt Instrument [Line Items]
Long-term debt, gross					$ 1
Debt instrument, maturity date					Dec. 1, 2024
Debt instrument, interest rate					4.875%
MPLX senior notes, 4.000%, due February 2025 | Senior Notes | MPLX LP
Debt Instrument [Line Items]
Long-term debt, gross					$ 500		0
Debt instrument, maturity date		Feb. 15, 2025			Feb. 15, 2025
Debt instrument, interest rate		4.00%			4.00%
MPLX senior notes, 4.875%, due June 2025 | Senior Notes | MPLX LP
Debt Instrument [Line Items]
Long-term debt, gross					$ 1,189		0
Debt instrument, maturity date					Jun. 1, 2025
Debt instrument, interest rate					4.875%
MPLX senior notes, 4.875%, due June 2025 | Senior Notes | MPLX LP | MarkWest
Debt Instrument [Line Items]
Long-term debt, gross					$ 11
Debt instrument, maturity date					Jun. 1, 2025
Debt instrument, interest rate					4.875%
Trade receivables securitization facility due December 2016 | Secured Debt | Consolidated subsidiaries:
Debt Instrument [Line Items]
Long-term debt, gross					$ 0		$ 0
Line of credit facility, expiration date					Dec. 31, 2016
[1]	We adopted the updated FASB debt issuance cost standard as of June 30, 2015 and applied the changes retrospectively to the prior period presented. We reclassified unamortized debt issuance costs from other noncurrent assets to long-term debt.
[2]	2015 includes $465 million discount related to the difference between the fair value and the principal amount of the assumed MarkWest debt.
[3]	In 2012, we terminated our 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. The $20 million gain on the termination of our interest rate swap agreements was amortized over the remaining life of the 3.50 percent senior notes. As a result of the December 2015 extinguishment of our obligation for the 3.50 percent senior notes, the remaining unamortized gain was credited to net interest and other financial income (costs).

Debt (Schedule Of Debt Payments

Debt (Schedule Of Debt Payments) (Detail) $ in Millions	Dec. 31, 2015USD ($)
Debt Disclosure [Abstract]
2,016	$ 29
2,017	28
2,018	630
2,019	977
2,020	$ 1,560

MPC Revolving Credit Agreement

MPC Revolving Credit Agreement (Detail) - Bank revolving credit facility due 2017 $ in Millions	Sep. 14, 2012USD ($)Period	Dec. 31, 2015USD ($)
Line of Credit Facility [Line Items]
Line of credit facility, current borrowing capacity	$ 2,500
Number of renewal periods | Period	2
Line of credit facility duration of renewal period	1 year
Debt instrument, description of variable rate basis	at either the Adjusted LIBO Rate (as defined in our revolving credit facility) plus a margin or the Alternate Base Rate (as defined in our revolving credit facility), plus a margin
Letter of Credit
Line of Credit Facility [Line Items]
Letters of credit outstanding		$ 0
Maximum
Line of Credit Facility [Line Items]
Line of credit facility additional borrowing capacity	$ 500
Ratio of indebtedness to net capital	0.65
Maximum | Letter of Credit
Line of Credit Facility [Line Items]
Line of credit facility, current borrowing capacity	$ 2,000
Maximum | Bridge Loan
Line of Credit Facility [Line Items]
Line of credit facility, current borrowing capacity	$ 100
Minimum
Line of Credit Facility [Line Items]
Lender holding percentage of outstanding commitments needed to approve increase in borrowing capacity	50.00%

Debt MPC Term Loan (Details)

Debt MPC Term Loan (Details) - MPC Term Loan $ in Millions	Aug. 26, 2014USD ($)	Dec. 31, 2015
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 700
Debt instrument, term	5 years
Debt instrument, description of variable rate basis	Adjusted LIBO Rate (as defined in the term loan agreement) plus a margin or the Alternate Base Rate (as defined in the term loan agreement) plus a margin
Line of credit facility, interest rate during period		1.30%
Ratio of indebtedness to net capital	0.65

Debt MPC Senior Notes (Details)

Debt MPC Senior Notes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013	Dec. 14, 2015
Debt Instrument [Line Items]
Loss on extinguishment of debt	$ (5)	[1]	$ 0	$ 0
Senior Notes
Debt Instrument [Line Items]
Debt instrument, face amount					$ 1,500
Proceeds from debt	1,490
Senior Notes | Senior notes, 2.700% due December 2018
Debt Instrument [Line Items]
Debt instrument, face amount					600
Senior Notes | Senior notes, 3.400% due December 2020
Debt Instrument [Line Items]
Debt instrument, face amount					650
Senior Notes | Senior notes, 5.850% due December 2045
Debt Instrument [Line Items]
Debt instrument, face amount					$ 250
Senior Notes | Senior notes, 3.500%, due March 2016
Debt Instrument [Line Items]
Repayments of debt	750
Early repayment of senior debt	$ 763
[1]	2015 includes $6 million of transaction costs related to the MarkWest Merger.

Debt MPLX Credit Agreement (Det

Debt MPLX Credit Agreement (Details) $ in Millions	Dec. 04, 2015USD ($)	Oct. 27, 2015USD ($)Period	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
MarkWest
Debt Instrument [Line Items]
Line of credit facility, repayments during period	$ 93
MPLX bank revolving credit facility due 2020 | MarkWest
Debt Instrument [Line Items]
Line of credit facility, repayments during period	850
MPLX LP | Line of Credit | MarkWest
Debt Instrument [Line Items]
Line of credit facility, repayments during period	$ 943
MPLX LP | MPLX bank revolving credit facility due 2020
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity		$ 2,000
Line of credit facility, interest rate during period			1.60%
Debt instrument, description of variable rate basis		Adjusted LIBO Rate or the Alternate Base Rate (as defined in the MPLX credit agreement)
Line of credit facility, repayments during period			$ 500
Line of credit facility, borrowings during period			992
Remaining borrowing capacity			1,100
MPLX LP | MPLX bank revolving credit facility due 2020 | Maximum
Debt Instrument [Line Items]
Line of credit facility additional borrowing capacity		$ 500
Number of prior quarterly reporting periods covenant		4
Covenant ratio debt to EBITDA		5
Covenant ratio debt to EBITDA post acquisition		5.5
MPLX LP | MPLX bank revolving credit facility due 2020 | Letter of Credit
Debt Instrument [Line Items]
Letters of credit outstanding			$ 8
MPLX LP | MPLX bank revolving credit facility due 2020 | Letter of Credit | Maximum
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity		$ 250
MPLX LP | MPLX bank revolving credit facility due 2020 | Bridge Loan | Maximum
Debt Instrument [Line Items]
Line of credit facility, current borrowing capacity		100
MPLX LP | MPLX bank revolving credit facility due 2020 | Line of Credit
Debt Instrument [Line Items]
Line of credit facility, expiration date			Dec. 4, 2020
Long-term debt, gross			$ 877	$ 385
MPLX LP | MPLX term loan facility due 2019
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity		$ 250
Number of renewal periods | Period		2
Line of credit facility duration of renewal period		1 year
Line of credit facility, interest rate during period			1.70%
Debt instrument, description of variable rate basis		Adjusted LIBO Rate or the Alternate Base Rate (as defined in the MPLX Credit Agreement)
MPLX LP | MPLX term loan facility due 2019 | Maximum
Debt Instrument [Line Items]
Number of prior quarterly reporting periods covenant		4
Covenant ratio debt to EBITDA		5
Covenant ratio debt to EBITDA post acquisition		5.5
MPLX LP | MPLX term loan facility due 2019 | Unsecured Debt
Debt Instrument [Line Items]
Line of credit facility, expiration date			Nov. 20, 2019
Long-term debt, gross			$ 250	$ 250

Debt MPLX and MarkWest Senior N

Debt MPLX and MarkWest Senior Notes (Details) - USD ($) $ in Millions	Feb. 12, 2015	Dec. 31, 2015	Dec. 22, 2015	Dec. 14, 2015	Dec. 04, 2015	Dec. 31, 2014
MarkWest
Debt Instrument [Line Items]
Long-term debt assumed					$ 4,567
Senior Notes
Debt Instrument [Line Items]
Debt instrument, face amount				$ 1,500
Proceeds from debt		$ 1,490
Senior Notes | MPLX LP
Debt Instrument [Line Items]
Debt instrument, face amount			$ 4,040
Proceeds from debt		495
Senior Notes | MPLX LP | MPLX senior notes, 5.500%, due February 2023
Debt Instrument [Line Items]
Long-term debt, gross		$ 710				$ 0
Debt instrument, interest rate		5.50%
Debt instrument, maturity date		Feb. 15, 2023
Senior Notes | MPLX LP | MPLX senior notes, 4.500%, due July 2023
Debt Instrument [Line Items]
Long-term debt, gross		$ 989				0
Debt instrument, interest rate		4.50%
Debt instrument, maturity date		Jul. 15, 2023
Senior Notes | MPLX LP | MPLX senior notes, 4.875%, due December 2024
Debt Instrument [Line Items]
Long-term debt, gross		$ 1,149				0
Debt instrument, interest rate		4.875%
Debt instrument, maturity date		Dec. 1, 2024
Senior Notes | MPLX LP | MPLX senior notes, 4.875%, due June 2025
Debt Instrument [Line Items]
Long-term debt, gross		$ 1,189				0
Debt instrument, interest rate		4.875%
Debt instrument, maturity date		Jun. 1, 2025
Senior Notes | MPLX LP | MPLX senior notes, 4.000%, due February 2025
Debt Instrument [Line Items]
Debt instrument, face amount	$ 500
Long-term debt, gross		$ 500				0
Debt instrument, interest rate	4.00%	4.00%
Debt instrument, maturity date	Feb. 15, 2025	Feb. 15, 2025
Senior Notes | MarkWest
Debt Instrument [Line Items]
Long-term debt assumed					$ 4,100
Debt instrument, face amount			$ 4,040
Senior Notes | MarkWest | MPLX LP
Debt Instrument [Line Items]
Long-term debt, gross		$ 63				$ 0
Senior Notes | MarkWest | MPLX LP | MPLX senior notes, 5.500%, due February 2023
Debt Instrument [Line Items]
Long-term debt, gross		$ 40
Debt instrument, interest rate		5.50%
Debt instrument, maturity date		Feb. 15, 2023
Senior Notes | MarkWest | MPLX LP | MPLX senior notes, 4.500%, due July 2023
Debt Instrument [Line Items]
Long-term debt, gross		$ 11
Debt instrument, interest rate		4.50%
Debt instrument, maturity date		Jul. 15, 2023
Senior Notes | MarkWest | MPLX LP | MPLX senior notes, 4.875%, due December 2024
Debt Instrument [Line Items]
Long-term debt, gross		$ 1
Debt instrument, interest rate		4.875%
Debt instrument, maturity date		Dec. 1, 2024
Senior Notes | MarkWest | MPLX LP | MPLX senior notes, 4.875%, due June 2025
Debt Instrument [Line Items]
Long-term debt, gross		$ 11
Debt instrument, interest rate		4.875%
Debt instrument, maturity date		Jun. 1, 2025

Debt Trade Receivables Securiti

Debt Trade Receivables Securitization Facility (Details) - Trade receivables securitization facility due December 2016 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Oct. 14, 2015	Dec. 18, 2013
Debt Instrument [Line Items]
Line of credit facility, expiration period	3 years
Line of credit facility, maximum borrowing capacity		$ 1,000	$ 1,300
Line of credit facility, current borrowing capacity	$ 668
Letter of Credit
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity		$ 1,000

Supplemental Cash Flow Infor133

Supplemental Cash Flow Information (Summary Of Supplemental Cash Flow Information) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015		Dec. 31, 2014	Dec. 31, 2013
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$ 272		$ 166	$ 161
Net income taxes paid to taxing authorities	1,605		1,362	1,099
Non-cash investing and financing activities:
Capital lease obligations increase	1		0	61
Property, plant and equipment sold	5		4	43
Property, plant and equipment acquired	5		4	0
Acquisition:
Fair value of MPLX units issued	7,326	[1]	0	0
Payable to seller	50		0	6
Contingent consideration	$ 0		$ 0	$ 600
[1]	See Note 5.

Supplemental Cash Flow Infor134

Supplemental Cash Flow Information (Reconciliation Of Additions To Property, Plant And Equipment To Total Capital Expenditures) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Supplemental Cash Flow Information [Abstract]
Additions to property, plant and equipment per consolidated statements of cash flows		$ 1,998		$ 1,480		$ 1,206
Non-cash additions to property, plant and equipment		5		4		0
Asset retirement expenditures		1	[1]	2	[1]	0
Increase in capital accruals		94		95		73
Total capital expenditures before acquisitions		2,098		1,581		1,279
Acquisitions		11,397	[2]	2,744	[2]	1,386
Total capital expenditures	[3]	$ 13,495		$ 4,325		$ 2,665
[1]	Included in All other, net – Operating activities on the consolidated statements of cash flows.
[2]	The 2014 acquisitions include the acquisition of Hess’ Retail Operations and Related Assets. The 2013 acquisitions include the acquisition of the Galveston Bay Refinery and Related Assets. The acquisition numbers above include property, plant and equipment, intangibles and goodwill. See Note 5.
[3]	Capital expenditures include changes in capital accruals. See Note 20 for a reconciliation of total capital expenditures to additions to property, plant and equipment as reported in the consolidated statements of cash flows.

Accumulated Other Comprehens135

Accumulated Other Comprehensive Loss (Changes in Accumulated Other Comprehensive Loss by Component) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance		$ (313)	$ (204)
Other comprehensive income (loss) before reclassifications		(14)	(170)
Amounts reclassified from accumulated other comprehensive loss:
Amortization - prior service credit	[1]	(50)	(50)
Amortization– actuarial loss	[1]	59	53
Amortization– settlement loss	[1]	4	96
Other	[2]		(1)
Tax effect		(4)	(37)
Other comprehensive income (loss)		(5)	(109)	$ 260
Ending balance		(318)	(313)	(204)
Pension Benefits
Amounts reclassified from accumulated other comprehensive loss:
Amortization - prior service credit		(46)	(46)	(45)
Other Benefits
Amounts reclassified from accumulated other comprehensive loss:
Amortization - prior service credit		(4)	(4)	(4)
Accumulated Defined Benefit Plans Adjustment | Pension Benefits
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance		(217)	(161)
Other comprehensive income (loss) before reclassifications		(44)	(119)
Amounts reclassified from accumulated other comprehensive loss:
Amortization - prior service credit		(46)	(46)
Amortization– actuarial loss		51	51
Amortization– settlement loss		4	96
Tax effect		(3)	(38)
Other comprehensive income (loss)		(38)	(56)
Ending balance		(255)	(217)	(161)
Accumulated Defined Benefit Plans Adjustment | Other Benefits
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance		(104)	(50)
Other comprehensive income (loss) before reclassifications		31	(53)
Amounts reclassified from accumulated other comprehensive loss:
Amortization - prior service credit		(4)	(4)
Amortization– actuarial loss		8	2
Amortization– settlement loss		0	0
Tax effect		(1)	1
Other comprehensive income (loss)		34	(54)
Ending balance		(70)	(104)	(50)
Gain on Cash Flow Hedge
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance		4	4
Other comprehensive income (loss) before reclassifications		0	0
Amounts reclassified from accumulated other comprehensive loss:
Tax effect		0	0
Other comprehensive income (loss)		0	0
Ending balance		4	4	4
Workers Compensation
Accumulated Other Comprehensive Income (Loss) [Roll Forward]
Beginning balance		4	3
Other comprehensive income (loss) before reclassifications		(1)	2
Amounts reclassified from accumulated other comprehensive loss:
Other			(1)
Tax effect		0	0
Other comprehensive income (loss)		(1)	1
Ending balance		$ 3	$ 4	$ 3
[1]	These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 22.
[2]	This amount was reclassified out of accumulated other comprehensive loss and is included in selling, general and administrative expenses on the consolidated statements of income.

Defined Benefit Pension And 136

Defined Benefit Pension And Other Postretirement Plans (Summary Of Defined Benefit Plans With Accumulated Benefit Obligations In Excess Of Plan Assets) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Projected benefit obligations	$ 1,997	$ 2,075
Accumulated benefit obligations	1,918	2,009
Fair value of plan assets	$ 1,570	$ 1,744

Defined Benefit Pension And 137

Defined Benefit Pension And Other Postretirement Plans (Summary Of Projected Benefit Obligations And Funded Status For Defined Benefit Pension And Other Postretirement Plans) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Change in plan assets:
Fair value of plan assets at January 1		$ 1,744
Fair value of plan assets at December 31		1,570	$ 1,744
Amounts recognized in the consolidated balance sheets:
Noncurrent liabilities		(1,179)	(1,099)
Pension Benefits
Change in benefit obligations:
Benefit obligations at January 1		2,075	1,927
Service cost		101	88	$ 93
Interest cost		71	74	73
Actuarial (gain) loss		(63)	257
Benefits paid		(187)	(271)
Other		0	0
Benefit obligations at December 31		1,997	2,075	1,927
Change in plan assets:
Fair value of plan assets at January 1		1,744	1,800
Actual return on plan assets		(33)	175
Employer contributions		46	40
Benefits paid		(187)	(271)
Fair value of plan assets at December 31		1,570	1,744	1,800
Funded status of plans at December 31		(427)	(331)
Amounts recognized in the consolidated balance sheets:
Current liabilities		(19)	(17)
Noncurrent liabilities		(408)	(314)
Accrued benefit cost		(427)	(331)
Pretax amounts recognized in accumulated other comprehensive loss:
Net loss	[1]	723	710
Prior service credit	[1]	(323)	(369)
Pension Benefits | LOOP LLC and Explorer Pipeline [Member]
Pretax amounts recognized in accumulated other comprehensive loss:
Net loss	[1]	19
Other Benefits
Change in benefit obligations:
Benefit obligations at January 1		812	687
Service cost		31	27	25
Interest cost		32	33	26
Actuarial (gain) loss		(63)	86
Benefits paid		(24)	(23)
Other	[2]	12	2
Benefit obligations at December 31		800	812	$ 687
Change in plan assets:
Benefits paid		(24)	(23)
Funded status of plans at December 31		(800)	(812)
Amounts recognized in the consolidated balance sheets:
Current liabilities		(29)	(27)
Noncurrent liabilities		(771)	(785)
Accrued benefit cost		(800)	(812)
Pretax amounts recognized in accumulated other comprehensive loss:
Net loss	[1]	120	191
Prior service credit	[1]	(9)	$ (26)
Other Benefits | LOOP LLC and Explorer Pipeline [Member]
Pretax amounts recognized in accumulated other comprehensive loss:
Net loss	[1]	$ 2
[1]	Amounts exclude those related to LOOP and Explorer, equity method investees with defined benefit pension and postretirement plans for which net losses of $19 million and $2 million were recorded in accumulated other comprehensive loss in 2015, reflecting our ownership share.
[2]	Includes adjustments related to the MarkWest Merger in 2015 and the acquisition of Hess’ Retail Operations and Related Assets in 2014.

Defined Benefit Pension And 138

Defined Benefit Pension And Other Postretirement Plans (Components Of Net Periodic Benefit Cost And Other Comprehensive Loss) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Amortization of prior service cost	[1]	$ 50	$ 50
Pension Benefits
Components of net periodic benefit cost:
Service cost		101	88	$ 93
Interest cost		71	74	73
Expected return on plan assets		(98)	(107)	(107)
Amortization – prior service credit		(46)	(46)	(45)
Amortization – actuarial loss		51	51	66
Amortization – settlement loss		4	96	95
Net periodic benefit cost	[2]	83	156	175
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial (gain) loss		69	188	(317)
Prior service cost (credit)	[3]	0	0	0
Amortization of actuarial loss		(55)	(147)	(161)
Amortization of prior service cost		46	46	45
Other		0	0	0
Total recognized in other comprehensive loss		60	87	(433)
Total recognized in net periodic benefit cost and other comprehensive loss		143	243	(258)
Estimated net gain (loss) that will be amortized from accumulated other comprehensive loss in 2016		38
Estimated prior service cost that will be amortized from accumulated other comprehensive loss in 2016		46
Other Benefits
Components of net periodic benefit cost:
Service cost		31	27	25
Interest cost		32	33	26
Expected return on plan assets		0	0	0
Amortization – prior service credit		(4)	(4)	(4)
Amortization – actuarial loss		8	2	3
Amortization – settlement loss		0	0	0
Net periodic benefit cost	[2]	67	58	50
Other changes in plan assets and benefit obligations recognized in other comprehensive loss (pretax):
Actuarial (gain) loss		(63)	86	17
Prior service cost (credit)	[3]	13	0	4
Amortization of actuarial loss		(8)	(2)	(3)
Amortization of prior service cost		4	4	4
Other		0	0	0
Total recognized in other comprehensive loss		(54)	88	22
Total recognized in net periodic benefit cost and other comprehensive loss		13	$ 146	$ 72
Estimated net gain (loss) that will be amortized from accumulated other comprehensive loss in 2016		3
Estimated prior service cost that will be amortized from accumulated other comprehensive loss in 2016		$ 3
[1]	These accumulated other comprehensive loss components are included in the computation of net periodic benefit cost. See Note 22.
[2]	Net periodic benefit cost reflects a calculated market-related value of plan assets which recognizes changes in fair value over three years.
[3]	Includes adjustments related to the MarkWest Merger in 2015, plan amendments approved in 2013 and adjustments due to changes made to the defined pension plans and the post-65 medical plan coverage effective January 1, 2013.

Defined Benefit Pension And 139

Defined Benefit Pension And Other Postretirement Plans (Summary Of Assumptions Used To Determine Benefit Obligations And Net Periodic Benefit Cost) (Detail)		1 Months Ended	12 Months Ended
		Jan. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Benefits
Weighted-average assumptions used to determine benefit obligation:
Discount rate			4.00%	3.65%	4.30%
Rate of compensation increase			3.70%	3.70%	3.70%
Weighted-average assumptions used to determine net periodic benefit cost:
Discount rate			3.70%	4.05%	3.88%
Expected long-term return on plan assets	[1]		6.75%	7.00%	7.50%
Rate of compensation increase			3.70%	3.70%	5.00%
Pension Benefits | Scenario, Forecast
Weighted-average assumptions used to determine net periodic benefit cost:
Expected long-term return on plan assets	[1]	6.50%
Other Benefits
Weighted-average assumptions used to determine benefit obligation:
Discount rate			4.50%	4.15%	4.95%
Rate of compensation increase			3.70%	3.70%	3.70%
Weighted-average assumptions used to determine net periodic benefit cost:
Discount rate			4.30%	4.95%	4.11%
Expected long-term return on plan assets	[1]		0.00%	0.00%	0.00%
Rate of compensation increase			3.70%	3.70%	5.00%
Maximum | Medical Post-65
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for the following year:			4.00%
[1]	Effective January 1, 2016, the expected long-term rate of return on plan assets is 6.50 percent due to a continuation of a change in our primary plan investment strategy, which began January 1, 2014.

Defined Benefit Pension and 140

Defined Benefit Pension and Other Postretirement Plans (Expected Long-Term Return on Plan Assets) (Details)	12 Months Ended
	Dec. 31, 2015
Defined Benefit Pension Plans and Defined Benefit Postretirement Plans Disclosure [Abstract]
Defined benefit plan, investment goals	The overall expected long-term return on plan assets assumption is determined based on an asset rate-of-return modeling tool developed by a third-party investment group. The tool utilizes underlying assumptions based on actual returns by asset category and inflation and takes into account our asset allocation to derive an expected long-term rate of return on those assets. Capital market assumptions reflect the long-term capital market outlook. The assumptions for equity and fixed income investments are developed using a building-block approach, reflecting observable inflation information and interest rate information available in the fixed income markets. Long-term assumptions for other asset categories are based on historical results, current market characteristics and the professional judgment of our internal and external investment teams.

Defined Benefit Pension And 141

Defined Benefit Pension And Other Postretirement Plans (Summarizes Assumed Health Care Cost Trend Rates) (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Medical Pre-65
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for the following year:	7.50%	8.00%	8.00%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):	5.00%	5.00%	5.00%
Year that the rate reaches the ultimate trend rate:	2,021	2,021	2,020
Prescription drugs
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for the following year:	7.00%	7.00%	7.00%
Rate to which the cost trend rate is assumed to decline (the ultimate trend rate):	5.00%	5.00%	5.00%
Year that the rate reaches the ultimate trend rate:	2,021	2,021	2,018
Maximum | Medical Post-65
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for the following year:	4.00%

Defined Benefit Pension And 142

Defined Benefit Pension And Other Postretirement Plans (Effects Of One Percentage Point Change In Assumed Health Care Cost Trend Rates) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Disclosures [Abstract]
Effect on total of service and interest cost components, 1-Percentage-Point-Increase	$ 6
Effect on other postretirement benefit obligations, 1-Percentage-Point-Increase	45
Effect on total of service and interest cost components, 1-Percentage-Point Decrease	(5)
Effect on other postretirement benefit obligations, 1-Percentage-Point-Decrease	$ (39)

Defined Benefit Pension and 143

Defined Benefit Pension and Other Postretirement Plans (Plan Investment Policies And Strategies) (Details)	12 Months Ended
	Dec. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined benefit plan, diversification	The asset allocation strategy will change over time in response to changes primarily in funded status, which is dictated by current and anticipated market conditions, the independent actions of our investment committee, required cash flows to and from the plans and other factors deemed appropriate. Such changes in asset allocation are intended to allocate additional assets to the fixed income asset class should the funded status improve. The fixed income asset class shall be invested in such a manner that its interest rate sensitivity correlates highly with that of the plans’ liabilities. Other asset classes are intended to provide additional return with associated higher levels of risk.
Plan investment policies and strategies	Investment performance and risk is measured and monitored on an ongoing basis through quarterly investment meetings and periodic asset and liability studies.
Equity Securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Targeted asset allocation	51.00%
Fixed Income Securities
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Targeted asset allocation	49.00%

Defined Benefit Pension And 144

Defined Benefit Pension And Other Postretirement Plans (Fair Values Of Defined Benefit Pension Plan Assets) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	$ 1,570	$ 1,744
Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	27	29
Equity investments, common stocks
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	57	63
Equity funds, mutual funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	142	155
Equity funds, pooled funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	399	442
Fixed income, corporate
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	516	554
Fixed income, government
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	103	99
Fixed income, pooled funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	193	254
Private equity
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	62	66
Real estate
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	50	57
Other
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	21	25
Level 1
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	201	220
Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 1 | Equity investments, common stocks
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	57	63
Level 1 | Equity funds, mutual funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	142	155
Level 1 | Equity funds, pooled funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 1 | Fixed income, corporate
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 1 | Fixed income, government
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 1 | Fixed income, pooled funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 1 | Private equity
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 1 | Real estate
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 1 | Other
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	2	2
Level 2
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	1,238	1,380
Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	27	29
Level 2 | Equity investments, common stocks
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 2 | Equity funds, mutual funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 2 | Equity funds, pooled funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	399	442
Level 2 | Fixed income, corporate
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	516	554
Level 2 | Fixed income, government
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	103	99
Level 2 | Fixed income, pooled funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	193	254
Level 2 | Private equity
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 2 | Real estate
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 2 | Other
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	2
Level 3
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	131	144	$ 137
Level 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 3 | Equity investments, common stocks
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 3 | Equity funds, mutual funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 3 | Equity funds, pooled funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 3 | Fixed income, corporate
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 3 | Fixed income, government
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 3 | Fixed income, pooled funds
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	0	0
Level 3 | Private equity
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	62	66	57
Level 3 | Real estate
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	50	57	60
Level 3 | Other
Defined Benefit Plan Disclosure [Line Items]
Plan asset investments, at fair value	$ 19	$ 21	$ 20

Defined Benefit Pension And 145

Defined Benefit Pension And Other Postretirement Plans (Reconciliation Of Beginning And Ending Balances Of Plan Assets Classified As Level 3) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	$ 1,744
Actual return on plan assets:
Fair value of plan assets at December 31	1,570	$ 1,744
Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	144	137
Actual return on plan assets:
Realized	18	10
Unrealized	(6)	11
Purchases	10	15
Sales	(35)	(29)
Fair value of plan assets at December 31	131	144
Private equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	66
Actual return on plan assets:
Fair value of plan assets at December 31	62	66
Private equity | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	66	57
Actual return on plan assets:
Realized	12	6
Unrealized	(1)	6
Purchases	5	10
Sales	(20)	(13)
Fair value of plan assets at December 31	62	66
Real estate
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	57
Actual return on plan assets:
Fair value of plan assets at December 31	50	57
Real estate | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	57	60
Actual return on plan assets:
Realized	6	4
Unrealized	(3)	4
Purchases	5	5
Sales	(15)	(16)
Fair value of plan assets at December 31	50	57
Other
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	25
Actual return on plan assets:
Fair value of plan assets at December 31	21	25
Other | Level 3
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets at January 1	21	20
Actual return on plan assets:
Realized	0	0
Unrealized	(2)	1
Purchases	0	0
Sales	0	0
Fair value of plan assets at December 31	$ 19	$ 21

Defined Benefit Pension and 146

Defined Benefit Pension and Other Postretirement Plans (Contributions To Defined Plans) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Contributions to defined contribution plans	$ 94	$ 86	$ 76
Pension Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Pension contributions	35
Unfunded Pension Plan
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined benefit plans, estimated future employer contributions in next fiscal year	145
Other Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined benefit plans, estimated future employer contributions in next fiscal year	$ 28

Defined Benefit Pension And 147

Defined Benefit Pension And Other Postretirement Plans (Estimated Future Benefit Payments) (Detail) $ in Millions	Dec. 31, 2015USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2,016	$ 185
2,017	184
2,018	185
2,019	183
2,020	175
2021 through 2025	834
Other Benefits
Defined Benefit Plan Disclosure [Line Items]
2,016	28
2,017	32
2,018	36
2,019	39
2,020	43
2021 through 2025	$ 253

Defined Benefit Pension And 148

Defined Benefit Pension And Other Postretirement Plans (Multiemployee Plans) (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Plan	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Defined Benefit Plan Disclosure [Line Items]
Multiemployer pension plans percentage funded	65.00%
Marathon Petroleum's contributions as a percentage of total contributions to the multi-employer pension plan, maximum	5.00%
Multiemployer Plans, Pension
Defined Benefit Plan Disclosure [Line Items]
Number of multiemployer defined benefit pension or health and welfare plan	1
Multi employer pension plans	There have been no significant changes that affect the comparability of 2015 , 2014 and 2013 contributions.
Multiemployer Plans, Postretirement Benefit
Defined Benefit Plan Disclosure [Line Items]
Number of multiemployer defined benefit pension or health and welfare plan	1
MPC contributions | $	$ 7	$ 6	$ 5

Defined Benefit Pension And 149

Defined Benefit Pension And Other Postretirement Plans (Multi Employer Pension Plan) (Detail) - Multiemployer Plans, Pension		12 Months Ended
		Dec. 31, 2015USD ($)Employees	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Multiemployer Plans [Line Items]
Multiemployer pension plan, minimum contribution requirement per week per employee		$ 291
Number of employees participated in the plan | Employees		272
Central States, Southeast and Southwest Pension Plan [Member]
Multiemployer Plans [Line Items]
MPC contributions	[1]	$ 4,000,000	$ 4,000,000	$ 3,000,000
[1]	This agreement has a minimum contribution requirement of $291 per week per employee for 2016. A total of 272 employees participated in the plan as of December 31, 2015.

Stock-Based Compensation Pla150

Stock-Based Compensation Plans (Narrative) (Detail) shares in Millions	12 Months Ended
	Dec. 31, 2015$ / sharesshares
Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement by share-based payment award, expiration period	10 years
Vesting period of awards	3 years
Restricted Stock Awards and Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of awards	3 years
Restricted stock and restricted stock unit awards granted in 2012, additional holding period	1 year
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Target payout | $ / shares	$ 1
Maximum | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Actual payout | $ / shares	$ 2
Target payout percentage	200.00%
MPC 2012 Plan | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of common stock authorized to be delivered under the compensation plan	50
MPC 2012 Plan | Maximum | Awards Other Than Stock Options Or Stock Appreciation Rights
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of common stock authorized to be delivered under the compensation plan	20
MPC 2012 Plan | Maximum | Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares of common stock authorized to be delivered under the compensation plan	20
MPC 2012 and 2011 Plans | Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting period of awards	36 months
Pay-out percentage in MPC common stock (in percentage)	25.00%
Pay-out percentage in cash (in percentage)	75.00%

Stock-Based Compensation Pla151

Stock-Based Compensation Plans (Stock-Based Compensation Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-based compensation expense	$ 42	$ 40	$ 42
Tax benefit recognized on stock-based compensation expense	16	15	15
Cash received by MPC upon exercise of stock option awards	33	26	48
Tax benefit received for tax deductions for stock awards exercised	$ 26	$ 19	$ 18

Stock-Based Compensation Pla152

Stock-Based Compensation Plans (Weighted Average Assumptions Used To Value Stock Options Awards) (Detail) - Stock Options - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average exercise price per share	$ 50.85	$ 42.51	$ 42.32
Expected life in years	6 years	5 years 9 months 19 days	6 years
Expected volatility	33.00%	36.00%	40.00%
Expected dividend yield	2.00%	1.90%	2.00%
Risk-free interest rate	1.70%	1.80%	1.00%
Weighted average grant date fair value of stock option awards granted	$ 13.44	$ 12.69	$ 13.57
Implied volatility rate weighting (in percentage)	50.00%
Historical volatility rate weighting (in percentage)	50.00%

Stock-Based Compensation Pla153

Stock-Based Compensation Plans (Summary Of Stock Option Award Activity) (Detail) - Stock Options - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic value of options exercised		$ 60	$ 48	$ 60
Unrecognized compensation cost		$ 7
Weighted average recognition period, in years		1 year 6 months
Number of Shares
Outstanding, beginning balance	[1]	9,502,876
Granted	[1]	1,103,684
Exercised	[1]	(1,827,245)
Forfeited, canceled or expired	[1]	(54,684)
Outstanding, ending balance	[1]	8,724,631	9,502,876
Vested and expected to vest at December 31, 2015 (in shares)	[1]	8,718,834
Exercisable at December 31, 2015 (in shares)	[1]	6,806,015
Weighted Average Exercise Price
Outstanding, beginning balance (in USD per share)		$ 22.74
Granted (in USD per share)		50.85	$ 42.51	$ 42.32
Exercised (in USD per share)		18.06
Forfeited, canceled or expired (in USD per share)		40.67
Outstanding, ending balance (in USD per share)		27.16	$ 22.74
Vested and expected to vest at December 31, 2015 (in USD per share)		27.11
Exercisable at December 31, 2015 (in USD per share)		$ 21.47
Weighted Average Remaining Contractual Terms (in years)
Vested and expected to vest at December 31, 2015 (in years)		6 years
Exercisable at December 31, 2015 (in years)		5 years
Aggregate Intrinsic Value (in millions)
Vested and expected to vest at December 31, 2015 (in USD)		$ 216
Exercisable at December 31, 2015 (in USD)		$ 207
[1]	Includes an immaterial number of stock appreciation rights.

Stock-Based Compensation Pla154

Stock-Based Compensation Plans (Summary Of Restricted Stock Award Activity) (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted units outstanding	513,220
Restricted Stock
Number of Shares
Outstanding, beginning balance	1,030,146
Granted	627,135
RS’s Vested/RSU’s Issued	(537,020)
Forfeited	(45,718)
Outstanding, ending balance	1,074,543	1,030,146
Weighted Average Grant Date Fair Value
Outstanding, beginning balance (in USD per share)	$ 38.62
Granted (in USD per share)	50.64	$ 43.82	$ 43.53
RS's Vested/RSU's Issued (in USD per share)	34.25
Forfeited (in USD per share)	41.41
Outstanding, ending balance (in USD per share)	$ 47.70	$ 38.62
Restricted Stock Units
Number of Shares
Outstanding, beginning balance	822,186
Granted	81,685
RS’s Vested/RSU’s Issued	(389,801)
Forfeited	(850)
Outstanding, ending balance	513,220	822,186
Weighted Average Grant Date Fair Value
Outstanding, beginning balance (in USD per share)	$ 18.65
Granted (in USD per share)	49.87	$ 42.95	$ 36.74
RS's Vested/RSU's Issued (in USD per share)	17.32
Forfeited (in USD per share)	44.77
Outstanding, ending balance (in USD per share)	$ 24.59	$ 18.65
Non-Employee Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Restricted units vested	491,287
Weighted average fair value, vested	$ 23.44

Stock-Based Compensation Pla155

Stock-Based Compensation Plans (Summary Of Values Related To Vested And Unvested Restricted Stock Awards) (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic Value of Awards Vested During the Period (in millions)	$ 27	$ 28	$ 20
Weighted Average Grant Date Fair Value of Awards Granted During the Period	$ 50.64	$ 43.82	$ 43.53
Unrecognized compensation cost	$ 35
Weighted average recognition period, in years	1 year 5 months 13 days
Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Intrinsic Value of Awards Vested During the Period (in millions)	$ 21	$ 0	$ 0
Weighted Average Grant Date Fair Value of Awards Granted During the Period	$ 49.87	$ 42.95	$ 36.74
Unrecognized compensation cost	$ 0

Stock-Based Compensation Pla156

Stock-Based Compensation Plans (Summary Of Performance Unit Awards) (Detail) - Performance Shares - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares issued in period	118,546
Unrecognized compensation cost	$ 2
Weighted average recognition period, in years	1 year 6 months 20 days
Number of Shares
Outstanding, beginning balance	5,791,825
Granted	2,389,450
Exercised	(2,035,833)
Canceled	0
Outstanding, ending balance	6,145,442	5,791,825
Weighted Average Grant Date Fair Value
Outstanding, beginning balance (in USD per share)	$ 0.88
Granted (in USD per share)	0.95	$ 0.85	$ 0.95
Exercised (in USD per share)	0.85
Canceled (in USD per share)	0
Outstanding, ending balance (in USD per share)	$ 0.92	$ 0.88

Stock-Based Compensation Pla157

Stock-Based Compensation Plans (Weighted Average Assumptions Used to Value Performance Unit Awards) (Details) - Performance Shares - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	0.95%	0.63%	0.35%
Look-back period	2 years 10 months 3 days	2 years 10 months 3 days	2 years 10 months 3 days
Expected volatility	30.38%	38.51%	41.67%
Grant date fair value of performance units granted	$ 0.95	$ 0.85	$ 0.95

Leases (Schedule Of Future Mini

Leases (Schedule Of Future Minimum Commitments) (Detail) $ in Millions	Dec. 31, 2015USD ($)
Capital Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,016	$ 53
2,017	50
2,018	50
2,019	45
2,020	49
Later years	251
Total minimum lease payments	498
Less imputed interest costs	(150)
Present value of net minimum lease payments	348
Operating Leases, Future Minimum Payments Due, Fiscal Year Maturity [Abstract]
2,016	282
2,017	212
2,018	186
2,019	161
2,020	138
Later years	475
Total minimum lease payments	$ 1,454

Leases (Schedule Of Operating L

Leases (Schedule Of Operating Lease Rental Expense) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Leases [Abstract]
Rental expense	$ 331	$ 256	$ 213

Leases (Narrative) (Details)

Leases (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Leases [Abstract]
Operating lease revenue	$ 16	$ 0	$ 0
Contingent lease payments received	$ 1	$ 0

Leases (Minimum Future Rentals

Leases (Minimum Future Rentals On The Non-Cancellable Operating Leases) (Details) $ in Millions	Dec. 31, 2015USD ($)
Leases [Abstract]
2,016	$ 174
2,017	184
2,018	185
2,019	186
2,020	185
Later years	588
Total minimum lease payments	$ 1,502

Leases (Investments In Assets H

Leases (Investments In Assets Held For Operating Lease By Major Classes) (Details) $ in Millions	Dec. 31, 2015USD ($)
Operating Leased Assets [Line Items]
Property, plant and equipment, gross	$ 1,482
Less accumulated depreciation	5
Property, plant and equipment, net	1,477
Natural gas gathering and NGL transportation pipelines and facilities
Operating Leased Assets [Line Items]
Property, plant and equipment, gross	619
Natural gas processing facilities
Operating Leased Assets [Line Items]
Property, plant and equipment, gross	753
Construction in progress
Operating Leased Assets [Line Items]
Property, plant and equipment, gross	$ 110

Commitments and Contingencies (

Commitments and Contingencies (Detail)	12 Months Ended
	Dec. 31, 2015
Pending Litigation
Loss Contingencies [Line Items]
Loss contingency, inestimable loss	For matters for which we have not recorded an accrued liability, we are unable to estimate a range of possible loss because the issues involved have not been fully developed through pleadings and discovery.

Commitments and Contingencie164

Commitments and Contingencies (Environmental Matters) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Commitments and Contingencies Disclosure [Abstract]
Accrued liabilities for remediation	$ 163	$ 185
Receivables for recoverable costs	$ 70	$ 67

Commitments and Contingencie165

Commitments and Contingencies (Lawsuits) (Details) - Emergency Pricing And Consumer Protection Laws - Pending Litigation $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Loss Contingencies [Line Items]
Plaintiff	Commonwealth of Kentucky
Alleged amount overcharged from customers	$ 89
Loss contingency, period of occurrence	during September and October 2005

Commitments and Contingencie166

Commitments and Contingencies (Guarantees) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Financial Guarantee | LOOP and LOCAP LLC | Guarantee of Indebtedness of Others
Loss Contingencies [Line Items]
Line of credit facility, expiration date	Dec. 31, 2037
Maximum potential undiscounted payments	$ 172
Financial Guarantee | Centennial | Master Shelf Agreement
Loss Contingencies [Line Items]
Line of credit facility, expiration date	Dec. 31, 2024
Maximum potential undiscounted payments	$ 34
Financial Guarantee | Crowley Ocean Partners | Guarantee of Indebtedness of Others
Loss Contingencies [Line Items]
Maximum potential undiscounted payments	81
Financial Guarantee | Crowley Ocean Partners | Guarantee of Indebtedness of Others | Crowley Term Loan [Member]
Loss Contingencies [Line Items]
Line of credit facility, maximum borrowing capacity	325
Indemnification Agreement | Marathon Oil Companies
Loss Contingencies [Line Items]
Guarantee obligation current carrying value	2
Other Guarantees | Equity Method Investees
Loss Contingencies [Line Items]
Maximum potential undiscounted payments	83
Guarantee obligations maximum exposure per event	$ 50

Commitments and Contingences (C

Commitments and Contingences (Contractual Commitments and Contingencies) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Feb. 01, 2013
Loss Contingencies [Line Items]
Contractual commitments to acquire property, plant and equipment and advance funds to equity method investees	$ 1,600,000,000	$ 1,700,000,000
Galveston Bay Refinery and Related Assets
Loss Contingencies [Line Items]
Maximum earnout provision payable to the company	331,000,000	520,000,000	$ 700,000,000
North Dakota Pipeline
Loss Contingencies [Line Items]
Contractual commitments to acquire property, plant and equipment and advance funds to equity method investees	630,000,000	703,000,000
Crowley Ocean Partners
Loss Contingencies [Line Items]
Contractual commitments to acquire property, plant and equipment and advance funds to equity method investees	$ 69,000,000
Illinois Extension Pipeline
Loss Contingencies [Line Items]
Contractual commitments to acquire property, plant and equipment and advance funds to equity method investees		$ 185,000,000

Selected Quarterly Financial168

Selected Quarterly Financial Data (Schedule Of Quarterly Financial Information) (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended													12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015		Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Data [Abstract]
Revenues	$ 15,607	$ 18,716	$ 20,537	$ 17,191		$ 22,250		$ 25,438		$ 26,844		$ 23,285
Income from operations	338	1,549	1,335	1,470		1,259		1,062		1,369		361		$ 4,692	$ 4,051	$ 3,425
Net income	168	958	839	903		805		679		864		207		2,868	2,555	2,133
Net income attributable to MPC	$ 187	$ 948	$ 826	$ 891		$ 798		$ 672		$ 855		$ 199		$ 2,852	$ 2,524	$ 2,112
Net income attributable to MPC per share:
Basic (in USD per share)	$ 0.35	$ 1.77	$ 1.52	$ 1.63	[1]	$ 1.44	[1]	$ 1.19	[1]	$ 1.49	[1]	$ 0.34	[1]	$ 5.29	$ 4.42	$ 3.34
Diluted (in USD per share)	0.35	1.76	1.51	1.62	[1]	1.43	[1]	1.18	[1]	1.48	[1]	0.34	[1]	5.26	4.39	3.32
Dividends paid per share (in USD per share)	$ 0.32	$ 0.32	$ 0.25	$ 0.25	[1]	$ 0.25	[1]	$ 0.25	[1]	$ 0.21	[1]	$ 0.21	[1]	$ 1.14	$ 0.92	$ 0.77
[1]	We completed a two-for-one stock split in June 2015. All historical per share data has been retroactively restated on a post-split basis.

Supplementary Statistics (Suppl

Supplementary Statistics (Supplementary Statistics) (Detail) - USD ($) $ in Millions

Dec. 04, 2015

Sep. 30, 2014

Feb. 01, 2013

Dec. 31, 2015

Sep. 30, 2015

Jun. 30, 2015

Mar. 31, 2015

Dec. 31, 2014

Sep. 30, 2014

Jun. 30, 2014

Mar. 31, 2014

Dec. 31, 2015

Dec. 31, 2014

Dec. 31, 2013

Supplementary Statistics [Line Items]

Income from operations

$ 338

$ 1,549

$ 1,335

$ 1,470

$ 1,259

$ 1,062

$ 1,369

$ 361

$ 4,692

$ 4,051

$ 3,425

Segment capital expenditures and investments

[1],[2]

16,283

4,738

2,789

Inventory market valuation charge

370

0

0

Operating Segments

Supplementary Statistics [Line Items]

Income from operations

[3]

5,148

[4]

4,433

3,791

Segment capital expenditures and investments

[5]

16,091

[6]

4,628

[7]

2,624

[8]

Corporate and Other

Supplementary Statistics [Line Items]

Income from operations

[9],[10]

(308)

(286)

(271)

Segment capital expenditures and investments

[11]

192

110

165

Capitalized interest

37

27

28

Segment Reconciling Items

Supplementary Statistics [Line Items]

Pension settlement expenses

[12]

(4)

(96)

(95)

Impairment

(144)

[13]

0

0

Refining & Marketing

Supplementary Statistics [Line Items]

Inventory market valuation charge

[13]

345

Refining & Marketing | Operating Segments

Supplementary Statistics [Line Items]

Income from operations

[3]

4,186

[4]

3,609

3,206

Segment capital expenditures and investments

[5]

1,143

[6]

1,104

[7]

2,094

[8]

Speedway

Supplementary Statistics [Line Items]

Inventory market valuation charge

[13]

25

Speedway | Operating Segments

Supplementary Statistics [Line Items]

Income from operations

[3]

673

[4]

544

375

Segment capital expenditures and investments

[5]

501

[6]

2,981

[7]

296

Midstream | Operating Segments

Supplementary Statistics [Line Items]

Income from operations

[3]

289

[4]

280

210

Segment capital expenditures and investments

[5]

14,447

[6]

543

234

[8]

MPLX LP | Midstream | Operating Segments

Supplementary Statistics [Line Items]

Cost of services, overhead

$ 20

19

20

MarkWest | Midstream | Operating Segments

Supplementary Statistics [Line Items]

Segment capital expenditures and investments

$ 13,850

Hess Retail Operations and Related Assets

Supplementary Statistics [Line Items]

Segment capital expenditures and investments

$ 2,710

Hess Retail Operations and Related Assets | Refining & Marketing | Operating Segments

Supplementary Statistics [Line Items]

Segment capital expenditures and investments

$ 52

Hess Retail Operations and Related Assets | Speedway | Operating Segments

Supplementary Statistics [Line Items]

Segment capital expenditures and investments

$ 2,660

Galveston Bay Refinery and Related Assets

Supplementary Statistics [Line Items]

Segment capital expenditures and investments

$ 1,360

Galveston Bay Refinery and Related Assets | Refining & Marketing | Operating Segments

Supplementary Statistics [Line Items]

Segment capital expenditures and investments

$ 1,290

Galveston Bay Refinery and Related Assets | Midstream | Operating Segments

Supplementary Statistics [Line Items]

Segment capital expenditures and investments

$ 70

[1]

Capital expenditures include changes in capital accruals.

[2]

Includes $13.85 billion in 2015 for the MarkWest Merger, $2.71 billion in 2014 for the acquisition of Hess’ Retail Operations and Related Assets and $1.36 billion in 2013 for the acquisition of the Galveston Bay Refinery and Related Assets. See Note 5.

[3]

Included in the Midstream segment for 2015, 2014 and 2013 are $20 million, $19 million and $20 million, respectively, of corporate overhead expenses attributable to MPLX. Corporate overhead expenses are not currently allocated to other segments. Also included in the Midstream segment for 2015 are $36 million of transaction costs related to the MarkWest Merger.

[4]

The Refining & Marketing and Speedway segments include inventory lower of cost or market charge of $345 million and $25 million, respectively.

[5]

Capital expenditures include changes in capital accruals, acquisitions and investments in affiliates.

[6]

The Midstream segment includes $13.85 billion for the MarkWest Merger. See Note 5.

[7]

The Speedway and Refining & Marketing segments include $2.66 billion and $52 million, respectively, for the acquisition of Hess’ Retail Operations and Related Assets. See Note 5.

[8]

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

[9]

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

[10]

Corporate overhead expenses attributable to MPLX are included in the Midstream segment. Corporate overhead expenses are not allocated to the Refining & Marketing and Speedway segments.

[11]

Includes capitalized interest of $37 million, $27 million and $28 million for 2015, 2014 and 2013, respectively.

[12]

See Note 22.

[13]

Related to the cancellation of the ROUX project at our Garyville, LA refinery. See Note

Supplementary Statistics (Opera

Supplementary Statistics (Operating Statistics) (Detail) bbl / d in Thousands, gal in Millions, CFPD in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2015USD ($)bbl / dStoreCFPD$ / bbl$ / galgal		Dec. 31, 2014USD ($)bbl / dStore$ / bbl$ / galgal		Dec. 31, 2013USD ($)bbl / dStore$ / bbl$ / galgal
Operating Statistics [Line Items ]
MPC Consolidated Refined Product Sales Volumes (thousands of barrels per day)	[1],[2]	2,301		2,138		2,086
Refining & Marketing
Refining & Marketing Operating Statistics
Refining & Marketing refined product sales volume (thousands of barrels per day)	[1],[3]	2,289		2,125		2,075
Refining & Marketing gross margin (dollars per barrel) | $ / bbl	[1],[5]	15.25	[4]	15.05		13.24
Crude oil capacity utilization percent	[1],[6]	99.00%		95.00%		96.00%
Refinery throughputs (thousands of barrels per day)	[1],[7]	1,888		1,806		1,802
Sour crude oil throughput percent	[1]	55.00%		52.00%		53.00%
WTI-priced crude oil throughput percent	[1]	20.00%		19.00%		21.00%
Refined product yields (thousands of barrels per day)	[1],[7]	1,919		1,839		1,836
Refinery direct operating costs (dollars per barrel):
Planned turnaround and major maintenance | $ / bbl	[1],[8]	1.13		1.80		1.20
Depreciation and amortization | $ / bbl	[1],[8]	1.39		1.41		1.36
Other manufacturing | $ / bbl	[1],[8],[9]	4.15		4.86		4.14
Total | $ / bbl	[1],[8]	6.67		8.07		6.70
Midstream Operating Statistics
Inter-refinery transfers		46		43		36
Refining & Marketing | Crude oil refined
Refining & Marketing Operating Statistics
Refinery throughputs (thousands of barrels per day)	[1],[7]	1,711		1,622		1,589
Refining & Marketing | Other charge and blendstocks
Refining & Marketing Operating Statistics
Refinery throughputs (thousands of barrels per day)	[1],[7]	177		184		213
Refining & Marketing | Gasoline
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[1],[7]	913		869		921
Refining & Marketing | Distillates
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[1],[7]	603		580		572
Refining & Marketing | Propane
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[1],[7]	36		35		37
Refining & Marketing | Feedstocks and special products
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[1],[7]	281		276		221
Refining & Marketing | Heavy fuel oil
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[1],[7]	31		25		31
Refining & Marketing | Asphalt
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[1],[7]	55		54		54
Refining & Marketing | Gulf Coast:
Refining & Marketing Operating Statistics
Refinery throughputs (thousands of barrels per day)	[1],[10]	1,244		1,173		1,159
Sour crude oil throughput percent	[1]	68.00%		64.00%		65.00%
WTI-priced crude oil throughput percent	[1]	6.00%		3.00%		7.00%
Refined product yields (thousands of barrels per day)	[1],[10]	1,269		1,199		1,186
Refinery direct operating costs (dollars per barrel):
Planned turnaround and major maintenance | $ / bbl	[1],[8]	0.81		1.82		1
Depreciation and amortization | $ / bbl	[1],[8]	1.09		1.15		1.09
Other manufacturing | $ / bbl	[1],[8],[9]	3.88		4.73		3.98
Total | $ / bbl	[1],[8]	5.78		7.70		6.07
Refining & Marketing | Gulf Coast: | Crude oil refined
Refining & Marketing Operating Statistics
Refinery throughputs (thousands of barrels per day)	[1],[10]	1,060		991		964
Refining & Marketing | Gulf Coast: | Other charge and blendstocks
Refining & Marketing Operating Statistics
Refinery throughputs (thousands of barrels per day)	[1],[10]	184		182		195
Refining & Marketing | Gulf Coast: | Gasoline
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[1],[10]	534		508		551
Refining & Marketing | Gulf Coast: | Distillates
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[1],[10]	392		368		365
Refining & Marketing | Gulf Coast: | Propane
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[1],[10]	26		23		23
Refining & Marketing | Gulf Coast: | Feedstocks and special products
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[1],[10]	286		274		215
Refining & Marketing | Gulf Coast: | Heavy fuel oil
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[1],[10]	15		13		19
Refining & Marketing | Gulf Coast: | Asphalt
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[1],[10]	16		13		13
Refining & Marketing | Midwest:
Refining & Marketing Operating Statistics
Refinery throughputs (thousands of barrels per day)	[10]	690		676		679
Sour crude oil throughput percent		34.00%		33.00%		35.00%
WTI-priced crude oil throughput percent		43.00%		44.00%		42.00%
Refined product yields (thousands of barrels per day)	[10]	696		683		686
Refinery direct operating costs (dollars per barrel):
Planned turnaround and major maintenance | $ / bbl	[8]	1.64		1.66		1.47
Depreciation and amortization | $ / bbl	[8]	1.83		1.78		1.74
Other manufacturing | $ / bbl	[8],[9]	4.36		4.76		4.21
Total | $ / bbl	[8]	7.83		8.20		7.42
Refining & Marketing | Midwest: | Crude oil refined
Refining & Marketing Operating Statistics
Refinery throughputs (thousands of barrels per day)	[10]	651		631		625
Refining & Marketing | Midwest: | Other charge and blendstocks
Refining & Marketing Operating Statistics
Refinery throughputs (thousands of barrels per day)	[10]	39		45		54
Refining & Marketing | Midwest: | Gasoline
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[10]	379		361		371
Refining & Marketing | Midwest: | Distillates
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[10]	211		212		207
Refining & Marketing | Midwest: | Propane
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[10]	12		13		14
Refining & Marketing | Midwest: | Feedstocks and special products
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[10]	38		43		41
Refining & Marketing | Midwest: | Heavy fuel oil
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[10]	17		13		12
Refining & Marketing | Midwest: | Asphalt
Refining & Marketing Operating Statistics
Refined product yields (thousands of barrels per day)	[10]	39		41		41
Speedway
Speedway Operating Statistics(k)
Convenience stores at period-end | Store		2,766	[11]	2,746	[11]	1,478
Gasoline and distillate sales (millions of gallons) | gal		6,038	[11]	3,942	[11]	3,146
Gasoline and distillate gross margin (dollars per gallon) | $ / gal	[12]	0.1823	[4],[11]	0.1775	[11]	0.1441
Merchandise sales (in millions) | $		$ 4,879	[11]	$ 3,611	[11]	$ 3,135
Merchandise gross margin (in millions) | $		$ 1,368	[11]	$ 975	[11]	$ 825
Merchandise margin percent		28.00%	[11]	27.00%	[11]	26.30%
Same store gasoline sales volume (period over period) percentage		(0.30%)	[11]	(0.70%)	[11]	0.50%
Merchandise sales excluding cigarettes (period over period) percentage	[13]	4.10%	[11]	5.00%	[11]	4.30%
Midstream
Midstream Operating Statistics
Crude oil and refined product pipeline throughputs (thousands of barrels per day)	[14]	2,191		2,119		2,204
Gathering system throughput (million cubic feet per day) | CFPD	[15]	3,075
Natural gas processed (million cubic feet per day) | CFPD	[15]	5,468
C2 (ethane) and NGLs (natural gas liquids) fractionated (mbpd)	[15]	307
[1]	Includes the results of the Galveston Bay Refinery and Related Assets from the February 1, 2013 acquisition date.
[2]	Total average daily volumes of refined product sales to wholesale, branded and retail (Speedway segment) customers.
[3]	Includes intersegment sales.
[4]	Excludes the lower of cost or market adjustment.
[5]	Sales revenue less cost of refinery inputs and purchased products, divided by total refinery throughputs.
[6]	Based on calendar day capacity, which is an annual average that includes downtime for planned maintenance and other normal operating activities.
[7]	Excludes inter-refinery volumes of 46 mbpd, 43 mbpd and 36 mbpd for 2015, 2014 and 2013, respectively
[8]	Per barrel of total refinery throughputs.
[9]	Includes utilities, labor, routine maintenance and other operating costs.
[10]	Includes inter-refinery transfer volumes.
[11]	Includes the impact of Hess’ Retail Operations and Related Assets from the September 30, 2014 acquisition date.
[12]	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.
[13]	Excludes cigarettes.
[14]	On owned common-carrier pipelines, excluding equity method investments.
[15]	Includes amounts related to unconsolidated equity method investments. Includes the results of the MarkWest assets beginning on the Dec. 4, 2015 acquisition date.