MPLX (MPLX) 10-K 26 Feb 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Feb. 12, 2016	Jun. 30, 2015
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	FY
Trading Symbol	MPLX
Entity Registrant Name	MPLX LP
Entity Central Index Key	1,552,000
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 Public Float			$ 1,600
Common Units [Member]
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		296,697,253
Class B Units [Member]
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		7,981,756
General Partner Units [Member]
Entity Information [Line Items]
Entity Common Stock, Shares Outstanding		6,800,681

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:
Service revenue	$ 150	$ 69	$ 79
Service revenue to related parties	481	451	384
Product sales	36	0	0
Product sales to related parties	1	0	0
Other income	8	5	4
Other income - related parties	27	23	19
Total revenues and other income	703	548	486
Costs and expenses:
Cost of revenues (excludes items below)	172	145	136
Purchased product costs	20	0	0
Purchases from related parties	102	98	95
Depreciation and amortization	89	50	49
General and administrative expenses	104	65	53
Other taxes	10	7	6
Total costs and expenses	497	365	339
Income from operations	206	183	147
Interest expense, net	35	4	0
Other Nonoperating Income (Expense)	12	1	1
Income before income taxes	159	178	146
Provision for income taxes	2	0	0
Net income	157	178	146
Less: Net income attributable to noncontrolling interests	1	57	68
Net income attributable to MPLX LP	156	121	78
Less: General partner’s interest in net income attributable to MPLX LP	57	6	2
Limited partners’ interest in net income attributable to MPLX LP	$ 99	$ 115	$ 76
Weighted average limited partner units outstanding:
Weighted Average Limited Partnership Units Outstanding, Basic	99	76	75
Weighted Average Limited Partnership Units Outstanding, Diluted	100	76	75
MPC [Member]
Revenues and other income:
Service revenue to related parties	$ 481	$ 451	$ 384
Product sales to related parties	1	0	0
Other income - related parties	24	22	18
Limited Partners Common Units [Member]
Costs and expenses:
Net income attributable to MPLX LP	$ 97	$ 58	$ 39
Per Unit Data (See Note 7)
Basic (in USD per unit)	$ 1.23	$ 1.55	$ 1.05
Diluted (in USD per unit)	$ 1.22	$ 1.55	$ 1.05
Weighted average limited partner units outstanding:
Weighted Average Limited Partnership Units Outstanding, Basic	79	37.4	37
Weighted Average Limited Partnership Units Outstanding, Diluted	80	37.4	37
Distributions declared per limited partner common unit	$ 1.8200	$ 1.4100	$ 1.1675
Limited Partners Subordinated Units [Member] | MPC [Member]
Costs and expenses:
Net income attributable to MPLX LP	$ 2	$ 55	$ 37
Per Unit Data (See Note 7)
Basic (in USD per unit)	$ 0.11	$ 1.50	$ 1.01
Diluted (in USD per unit)	0.11	1.50	1.01
Basic and Diluted (in USD per unit)	$ 0.11	$ 1.50	$ 1.01
Weighted average limited partner units outstanding:
Weighted Average Limited Partnership Units Outstanding, Basic	18	37	37
Weighted Average Limited Partnership Units Outstanding, Diluted	18	37	37
Basic and Diluted Units (in units)	18	37	37

Consolidated Statements of Inc3

Consolidated Statements of Income Consolidated Statements of Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Statement [Abstract]
Interest Costs Capitalized	$ 5	$ 1	$ 1

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash and cash equivalents	$ 43	$ 27
Receivables, net	244	10
Receivables from related parties	88	41
Inventories	49	12
Other current assets	50	7
Total current assets	474	97
Equity method investments	2,458	0
Property, plant and equipment, net	9,683	1,008
Intangibles, net	466	0
Goodwill	2,559	105
Long-term receivables from related parties	25	0
Other noncurrent assets	12	4
Total assets	15,677	1,214
Current liabilities:
Accounts payable	89	14
Accrued liabilities	186	11
Payables to related parties	47	20
Deferred revenue - related parties	32	31
Accrued property, plant and equipment	166	17
Accrued taxes	26	5
Accrued interest payable	54	1
Other current liabilities	12	2
Total current liabilities	612	101
Long-term deferred revenue	4	0
Long-term deferred revenue - related parties	9	4
Long-term debt	5,255	644
Deferred income taxes	377	0
Deferred credits and other liabilities	166	2
Total liabilities	$ 6,423	$ 751
Commitments and contingencies (see Note 22)
Equity
Total MPLX LP partners' capital	$ 9,241	$ 457
Noncontrolling interest	13	6
Total equity	9,254	463
Total liabilities and equity	15,677	1,214
MPC [Member]
Current assets:
Receivables from related parties	76	41
Long-term receivables from related parties	25	0
Current liabilities:
Payables to related parties	26	20
Limited Partners Common Units [Member] | MPC [Member]
Equity
Total MPLX LP partners' capital	465	261
Limited Partners Class B Units [Member]
Equity
Total MPLX LP partners' capital	266	0
Limited Partners Subordinated Units [Member] | MPC [Member]
Equity
Total MPLX LP partners' capital	0	217
General Partner [Member] | MPC [Member]
Equity
Total MPLX LP partners' capital	819	(660)
Public [Member] | Limited Partners Common Units [Member]
Equity
Total MPLX LP partners' capital	$ 7,691	$ 639

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - shares	Dec. 31, 2015	Dec. 31, 2014
Units outstanding	6,800,475
Limited Partners Common Units [Member] | Public [Member]
Units issued	240,000,000	23,000,000
Units outstanding	240,000,000	23,000,000
Limited Partners Class B Units [Member]
Units issued	8,000,000	0
Units outstanding	8,000,000	0
MPC [Member] | Limited Partners Common Units [Member]
Units issued	57,000,000	20,000,000
Units outstanding	57,000,000	20,000,000
MPC [Member] | Limited Partners Subordinated Units [Member]
Units issued	0	37,000,000
Units outstanding	0	37,000,000
MPC [Member] | General Partner [Member]
Units issued	7,000,000	2,000,000
Units outstanding	7,000,000	2,000,000

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	$ 157	$ 178	$ 146
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	89	50	49
Deferred income taxes	2	0	0
Asset retirement expenditures	(1)	(2)	(8)
Net loss on disposal of assets	1	0	0
Equity in earnings from unconsolidated affiliates	(3)	0	0
Distributions from unconsolidated affiliates	15	0	0
Changes in:
Current receivables	(29)	2	5
Increase (Decrease) in Inventories	1	1	1
Change in fair value of derivatives	(6)	0	0
Current accounts payable and accrued liabilities	4	1	(3)
Receivables from / liabilities to related parties	(8)	15	19
All other, net	17	2	3
Net cash provided by operating activities	239	247	212
Investing activities:
Additions to property, plant and equipment	(264)	(79)	(107)
Acquisitions, net of cash acquired	(1,218)	0	0
Investments in unconsolidated affiliates	(14)	0	0
All other, net	(2)	4	(7)
Net cash used in investing activities	(1,498)	(75)	(114)
Financing activities:
Long-term debt - borrowings	1,490	1,160	0
Long-term debt - repayments	(1,441)	(526)	(1)
Related party debt - borrowings	301	0	0
Related party debt - repayments	(293)	0	0
Debt issuance costs	(11)	(3)	0
Net proceeds from equity offerings	1	230	0
Issuance of units in MarkWest Merger	169	0	0
Contributions from MPC - MarkWest Merger	1,230	0	0
Distributions to unitholders and general partner	(158)	(103)	(78)
Distributions to noncontrolling interests	(1)	(47)	(82)
Distributions related to purchase of additional interest in Pipe Line Holdings	(12)	(910)	(100)
Net cash provided by (used in) financing activities	1,275	(199)	(261)
Net increase (decrease) in cash and cash equivalents	16	(27)	(163)
Cash and cash equivalents at beginning of period	27	54	217
Cash and cash equivalents at end of period	$ 43	$ 27	$ 54

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) $ in Millions	Total	MPC [Member]	Limited Partners Common Units [Member]Public [Member]	Limited Partners Common Units [Member]MPC [Member]	Limited Partners Class B Units [Member]	Limited Partners Subordinated Units [Member]MPC [Member]	General Partner [Member]MPC [Member]	Noncontrolling Interest [Member]	Noncontrolling Interest [Member]MPC [Member]
Beginning Balance at Dec. 31, 2012	$ 1,227		$ 411	$ 57		$ 209	$ 14		$ 536
Purchase of additional interest in Pipe Line Holdings	(100)						(46)		(54)
Net income	146		20	18		38	2		68
Quarterly distributions to unitholders and general partner	(78)		(20)	(18)		(38)	(2)
Quarterly distributions to noncontrolling interest		$ (82)							(82)
Equity-based compensation	1		1
Ending Balance at Dec. 31, 2013	1,114		412	57		209	(32)		468
Purchase of additional interest in Pipe Line Holdings	(910)			200			(638)		(472)
Issuance of units	230		221				9
Net income	178		31	27		58	5		57
Quarterly distributions to unitholders and general partner	(103)		(26)	(23)		(50)	(4)
Quarterly distributions to noncontrolling interest		$ (47)							(47)
Equity-based compensation	1		1
Ending Balance at Dec. 31, 2014	463		639	261		217	(660)		6
Purchase of additional interest in Pipe Line Holdings	(12)						(6)		(6)
Contributions from MPC - MarkWest Merger	1,280						1,280
Issuance of units	1		1
Net income	157		15	36		48	57		1
Quarterly distributions to unitholders and general partner	(158)		(40)	(52)		(45)	(21)
Quarterly distributions to noncontrolling interest	(1)							$ (1)
Subordinated unit conversion				220		(220)
Equity-based compensation	17		17
Deferred income tax impact from changes in equity	(1)		(1)
Issuance of units in MarkWest Merger	7,495		7,060		$ 266		169
Noncontrolling interest assumed in MarkWest Merger	13							$ 13
Ending Balance at Dec. 31, 2015	$ 9,254		$ 7,691	$ 465	$ 266	$ 0	$ 819		$ 13

Description of the Business and

Description of the Business and Basis of Presentation	12 Months Ended
	Dec. 31, 2015
Text Block [Abstract]
Description of the Business and Basis of Presentation	Description of the Business and Basis of Presentation Description of the Business – MPLX LP is a diversified, growth-oriented master limited partnership formed by Marathon Petroleum Corporation. MPLX LP and its subsidiaries (collectively, the “Partnership”) are engaged in the gathering, processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of NGLs and the gathering, transportation and storage of crude oil and refined petroleum products. The Partnership’s principal executive office is located in Findlay, Ohio. The Partnership was formed on March 27, 2012 as a Delaware limited partnership and completed its initial public offering (the “Initial Offering”) on October 31, 2012 . On December 4, 2015 , a wholly-owned subsidiary of the Partnership merged with MarkWest Energy Partners L.P. (the “MarkWest Merger”), which is one of the largest processors of natural gas in the United States and the largest processor and fractionator in the Marcellus and Utica shale plays. This acquisition is discussed further in Note 4 . Unless the context otherwise requires, references in this report to “MPLX LP,” the “Partnership,” or like terms refer to MPLX LP and its subsidiaries, including MPLX Operations LLC (“MPLX Operations”), MPLX Terminal and Storage LLC (“MPLX Terminal and Storage”), MarkWest Energy Partners, L.P. (“MarkWest”) and MPLX Pipe Line Holdings LLC (“Pipe Line Holdings”). Pipe Line Holdings owns Marathon Pipe Line LLC (“MPL”) and Ohio River Pipe Line LLC (“ORPL”). References to “MPC” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other than the Partnership. The Partnership’s business consists of two segments: Logistics and Storage (“ L&S ”) and Gathering and Processing (“ G&P ”). See Note 9 for additional information regarding operations. Basis of Presentation – The Partnership’s consolidated financial statements include all majority-owned and controlled subsidiaries. For non-wholly-owned consolidated subsidiaries, the interests owned by third parties, including MPC, have been recorded as Noncontrolling interest in the accompanying Consolidated Balance Sheets. Intercompany investments, accounts and transactions have been eliminated. The Partnership’s investments in which the Partnership exercises significant influence but does not control and does not have a controlling financial interest, are accounted for using the equity method. The Partnership’s investments in a VIE in which the Partnership exercises significant influence but does not control and is not the primary beneficiary are accounted for using the equity method. The accompanying consolidated financial statements of the Partnership have been prepared in accordance with GAAP. Reclassifications have been made in connection with the MarkWest Merger to conform to current classifications.

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 Use of Estimates – The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates affect, among other items, valuing identified intangible assets; determining the fair value of derivative instruments; valuing inventory; evaluating impairments of long-lived assets, goodwill and equity investments; establishing estimated useful lives for long-lived assets; acquisition accounting; recognizing share-based compensation expense; estimating revenues, expense accruals and capital expenditures; valuing AROs; and determining liabilities, if any, for environmental and legal contingencies. Revenue Recognition – The Partnership’s assessment of each of the revenue recognition criteria as they relate to its revenue producing activities are as follows: persuasive evidence of an arrangement exists, delivery, the fee is fixed or determinable and collectability is reasonably assured. It is upon delivery or title transfer to the customer that the Partnership meets all four revenue recognition criteria and it is at such time that the Partnership recognizes Product sales . It is upon completion of services provided that the Partnership meets all four criteria and it is at such time that the Partnership recognizes Service revenue . L&S Segment Revenues are recognized in the L&S segment for crude oil and product pipeline transportation based on the delivery of actual volumes transported at regulated tariff rates. When MPC ships volumes on our pipeline systems under a joint tariff with a third party, those revenues are recorded as sales and other operating revenues, and not as sales to related parties, because we receive payment from the third party. Revenues are recognized for crude oil and refined product storage as performed based on contractual rates. Operating fees received for operating pipeline systems are recognized as a component of other income in the period the service is performed. All such amounts are reported as Service revenue on the Consolidated Statements of Income. Under our MPC transportation services agreements, if MPC fails to transport its minimum throughput volumes during any quarter, then MPC will pay us a deficiency payment equal to the volume of the deficiency multiplied by the tariff rate then in effect. MPC may then apply the amount of any such deficiency payments as a credit for volumes transported on the applicable pipeline system in excess of its minimum volume commitment during the following four or eight quarters under the terms of the applicable transportation services agreement. The deficiency payments are initially recorded as Deferred revenue - related parties in the Consolidated Balance Sheets. The Partnership recognizes revenues for the deficiency payments at the earlier of when credits are used for volumes transported in excess of minimum volume commitments, when it becomes impossible to physically transport volumes necessary to utilize the credits or upon the expiration of the applicable four or eight quarter period. The use or expiration of the credits is a decrease in Deferred revenue - related parties . In addition, capital projects the Partnership undertakes at the request of MPC are reimbursed in cash and recognized in income over the remaining term of the applicable transportation services agreements. G&P Segment The Partnership generates the majority of its G&P segment revenues from natural gas gathering, transportation and processing; NGL gathering, transportation, fractionation, marketing and storage; and crude oil gathering and transportation. The Partnership disaggregates revenue as Product sales and Service revenue on the Consolidated Statements of Income. Revenue is reported as follows: • Product sales – Product sales represent the sale of NGLs, condensate and natural gas. The product is primarily obtained as consideration for or related to providing midstream services. • Service revenue – Service revenue represents all other revenue generated as the result of performing the services listed above. The Partnership enters into a variety of contract types in order to generate Product sales and Service revenue . The Partnership provides services under the following different types of arrangements: • Fee-based arrangements – Under fee-based arrangements, the Partnership receives a fee or fees for one or more of the following services: gathering, processing and transportation of natural gas; gathering, transportation, fractionation, exchange and storage of NGLs; and gathering and transportation of crude oil. The revenue the Partnership earns from these arrangements is generally directly related to the volume of natural gas, NGLs or crude oil that flows through the Partnership’s systems and facilities and is not normally directly dependent on commodity prices. In certain cases, the Partnership’s arrangements provide for minimum annual payments or fixed demand charges. ◦ Fee-based arrangements are reported as Service revenue on the Consolidated Statements of Income. In certain instances when specifically stated in the contract terms, the Partnership purchases product after fee-based services have been provided. Revenue from the sale of products purchased after services are provided is reported as Product sales and recognized on a gross basis as the Partnership is the principal in the transaction. • Percent-of-proceeds arrangements – Under percent-of-proceeds arrangements, the Partnership gathers and processes natural gas on behalf of producers, sells the resulting residue gas, condensate and NGLs at market prices and remits to producers an agreed-upon percentage of the proceeds. In other cases, instead of remitting cash payments to the producer, the Partnership delivers an agreed-upon percentage of the residue gas and NGLs to the producer (take-in-kind arrangements) and sells the volumes the Partnership retains to third parties. Revenue from these arrangements is reported on a gross basis where the Partnership acts as the principal, as the Partnership has physical inventory risk and does not earn a fixed dollar amount. The agreed-upon percentage paid to the producer is reported as Purchased product costs on the Consolidated Statements of Income. Revenue is recognized on a net basis when the Partnership acts as an agent and earns a fixed dollar amount of physical product and does not have risk of loss of the gross amount of gas and/or NGLs. Percent-of-proceeds revenue is reported as Product sales on the Consolidated Statements of Income. • Keep-whole arrangements – Under keep-whole arrangements, the Partnership gathers natural gas from the producer, processes the natural gas and sells the resulting condensate and NGLs to third parties at market prices. Because the extraction of the condensate and NGLs from the natural gas during processing reduces the Btu content of the natural gas, the Partnership must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the energy content of this natural gas. Certain keep-whole arrangements also have provisions that require the Partnership to share a percentage of the keep-whole profits with the producers based on the oil to gas ratio or the NGL to gas ratio. Sales of NGLs under these arrangements are reported as Product sales on the Consolidated Statements of Income and are reported on a gross basis as the Partnership is the principal in the arrangement. Natural gas purchased to return to the producer and shared NGL profits are recorded as Purchased product costs in the Consolidated Statements of Income. • Percent-of-index arrangements – Under percent-of-index arrangements, the Partnership purchases natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount. The Partnership then gathers and delivers the natural gas to pipelines where the Partnership resells the natural gas at the index price or at a different percentage discount to the index price. Revenue generated from percent-of-index arrangements are reported as Product sales on the Consolidated Statements of Income and are recognized on a gross basis as the Partnership purchases and takes title to the product prior to sale and is the principal in the transaction. In many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements described above. When fees are charged (in addition to product received) under keep-whole arrangements, percent-of-proceeds arrangements or percent-of-index arrangements, the Partnership records such fees as Service revenue on the Consolidated Statements of Income. The terms of the Partnership’s contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. Amounts billed to customers for shipping and handling, including fuel costs, are included in Product sales on the Consolidated Statements of Income, except under contracts where we are acting as an agent. Shipping and handling costs associated with product sales are included in Purchased product costs on the Consolidated Statements of Income. Taxes collected from customers and remitted to the appropriate taxing authority are excluded from revenue. Facility expenses and depreciation represent those expenses related to operating our various facilities and are necessary to provide both Product sales and Service revenue . Revenue and Expense Accruals – The Partnership routinely makes accruals based on estimates for both revenues and expenses due to the timing of compiling billing information, receiving certain third party information and reconciling the Partnership’s records with those of third parties. The delayed information from third parties includes, among other things, actual volumes purchased, transported or sold, adjustments to inventory and invoices for purchases, actual natural gas and NGL deliveries and other operating expenses. The Partnership makes accruals to reflect estimates for these items based on its internal records and information from third parties. Estimated accruals are adjusted when actual information is received from third parties and the Partnership’s internal records have been reconciled. Cash and Cash Equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with initial 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 in the Consolidated Balance Sheets was $9 million and $4 million , respectively. Receivables – Receivables primarily consist of customer accounts receivable, which are recorded at the invoiced amount and generally do not bear interest. Management reviews the allowance quarterly. Past-due balances over 90 days and other higher risk amounts are reviewed individually for collectability. Balances that remain outstanding after reasonable collection efforts have been unsuccessful are written off through a charge to the valuation allowance and a credit to accounts receivable. Inventories – Inventories consist primarily of natural gas, propane, other NGLs and materials and supplies to be used in operations. Natural gas, propane, and other NGLs are valued at the lower of weighted-average cost or net realizable value. Materials and supplies are stated at the lower of cost or net realizable value. Cost for materials and supplies is determined primarily using the weighted-average cost method. Processed natural gas and NGL inventories include material, labor and overhead. Shipping and handling costs related to purchases of natural gas and NGLs are included in inventory. Imbalances – Within our pipelines and storage assets we experience volume gains and losses due to pressure and temperature changes, evaporation and variances in meter readings and other measurement methods. Until settled, positive imbalances are recorded as other current assets and negative imbalances are recorded as accounts payable. Positive and negative product imbalances are settled in cash, settled by physical delivery of gas from a different source, or tracked and settled in the future. Property, Plant and Equipment – Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of assets are capitalized. Repairs, maintenance and renewals that do not extend the useful lives of the assets are expensed as incurred. Interest costs for the construction or development of long-lived assets are capitalized and amortized over the related asset’s estimated useful life. Leasehold improvements are amortized over the shorter of the useful life or lease term. When items of property, plant and equipment are sold or otherwise disposed of, any gains or losses are reported in the Consolidated Statements of Income. Gains on the disposal of property, plant and equipment are recognized when they occur, 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. The Partnership evaluates transactions involving the sale of property, plant and equipment to determine if they are, in-substance, the sale of real estate. Tangible assets may be considered real estate if the costs to relocate them for use in a different location exceed 10 percent of the asset’s fair value. Financial assets, primarily in the form of ownership interests in an entity, may be in-substance real estate based on the significance of the real estate in the entity. Sales of real estate are not considered consummated if the Partnership maintains an interest in the asset after it is sold or has certain other forms of continuing involvement. Significant judgment is required to determine if a transaction is a sale of real estate and if a transaction has been consummated. If a sale of real estate is not considered consummated, the Partnership cannot record the transaction as a sale and must account for the transaction under an alternative method of accounting such as a financing or leasing arrangement. The Partnership’s policy is to evaluate whether there has been an impairment in the value of long-lived assets when certain events indicate that the remaining balance may not be recoverable. The Partnership evaluates the carrying value of its property, plant and equipment on at least a segment level and at lower levels where the cash flows for specific assets can be identified, which generally is the business unit level for our G&P segment and the pipeline system level for our L&S segment, and are largely independent from other asset groups. A long-lived asset group is considered impaired when the estimated undiscounted cash flows from such asset group are less than the asset group’s carrying value. In that event, a loss is recognized to the extent that the carrying value exceeds the fair value of the long-lived asset group. Fair value is determined primarily using estimated discounted cash flows. Management considers the volume of producer customers’ reserves behind the asset and future NGL product and natural gas prices to estimate cash flows. The amount of additional producer customers’ reserves developed by future drilling activity depends, in part, on expected natural gas prices. Projections of producer customers’ reserves, drilling activity and future commodity prices are inherently subjective and contingent upon a number of variable factors, many of which are difficult to forecast. Any significant variance in any of these assumptions or factors could materially affect future cash flows, which could result in the impairment of an asset group. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value, less the cost to sell, to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is redetermined when related events or circumstances change. Intangibles – The Partnership’s intangibles are mainly comprised of customer contracts and related relationships acquired in business combinations and recorded under the acquisition method of accounting at their estimated fair values at the date of acquisition. Using relevant information and assumptions, management determines the fair value of acquired identifiable intangible assets. Fair value was calculated using the multi-period excess earnings method under the income approach for each reporting unit. This valuation method is based on first forecasting gross profit for the existing customer base and then applying expected attrition rates. The operating cash flows are calculated by determining the costs required to generate gross profit from the existing customer base. The key assumptions include overall gross profit growth, attrition rate of existing customers over time and the discount rate. Amortization of intangibles with definite lives is calculated using the straight-line method which is reflective of benefit pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible asset. The estimated economic life is determined by assessing the life of the assets related to the contracts and relationships, likelihood of renewals, the projected reserves, competitive factors, regulatory or legal provisions and maintenance and renewal costs. Intangibles with indefinite lives 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. Goodwill – Goodwill is the cost of an acquisition less the fair value of the net identifiable assets and noncontrolling interest, if any, of the acquired business. The Partnership evaluates goodwill for impairment annually as of November 30, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The Partnership may first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Partnership may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step process goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit to which goodwill has been allocated, with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss. There were no impairments as a result of the Partnership’s 2015 and 2014 goodwill impairment analyses. Other Taxes – Other taxes primarily include real estate taxes. 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. The Partnership recognizes 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. A receivable is recorded for environmental costs indemnified by MPC. Asset Retirement Obligations – An ARO is a legal obligation associated with the retirement of tangible long-lived assets that generally result from the acquisition, construction, development or normal operation of the asset. AROs are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a risk free interest rate and increases due to the passage of time based on the time value of money until the obligation is settled. The Partnership recognizes a liability of a conditional ARO as soon as the fair value of the liability can be reasonably estimated. A conditional ARO is defined as an unconditional legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. AROs have not been recognized for certain 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. Investment in Unconsolidated Affiliates – Equity investments in which the Partnership exercises significant influence, but does not control and is not the primary beneficiary, are accounted for using the equity method and are reported in Equity method investments in the accompanying Consolidated Balance Sheets. 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. The Partnership believes the equity method is an appropriate means for it to recognize increases or decreases measured by GAAP in the economic resources underlying the investments. Regular evaluation of these investments is appropriate to evaluate any potential need for impairment. The Partnership uses evidence of a loss in value to identify if an investment has an other than a temporary decline. Deferred Financing Costs – Deferred financing costs are an asset for credit facility costs and netted in debt for senior notes. These costs are amortized over the contractual term of the related obligations using the effective interest method or, in certain circumstances, accelerated if the obligation is refinanced. Derivative Instruments – Derivative instruments (including derivative instruments embedded in other contracts) are recorded at fair value and are reflected in the Consolidated Balance Sheets on a net basis, as either an asset or liability, as they are governed by the master netting agreements. The Partnership discloses the fair value of all of its derivative instruments under the captions Other noncurrent assets , Other current liabilities and Deferred credits and other liabilities in the Consolidated Balance Sheets, inclusive of option premiums, if any. Changes in the fair value of derivative instruments are reported in the Consolidated Statements of Income in accounts related to the item whose value or cash flows are being managed. All derivative instruments were marked to market through Product sales , Purchased product costs , or Cost of revenues . Revenue gains and losses relate to contracts utilized to manage the cash flow for the sale of a product. Purchased product costs gains and losses relate to contracts utilized to manage the cost of natural gas purchases, typically related to keep‑whole arrangements. Cost of revenues gains and losses relate to a contract utilized to manage electricity costs. Changes in risk management for unrealized activities are reported as an adjustment to net income in computing cash flow from operating activities on the accompanying Consolidated Statements of Cash Flows. During the years ended December 31, 2015 , 2014 and 2013 , the Partnership did not designate any hedges or designate any contracts as normal purchases and normal sales (except for electricity contracts, for which the normal purchases and normal sales designation has been elected during the year ended December 31, 2015). Fair Value of Financial Instruments – Management believes the carrying amount of financial instruments, including cash and cash equivalents, receivables, receivables from related parties, other current assets, accounts payable, accounts payable to related parties and accrued liabilities approximate fair value because of the short-term maturity of these instruments. The recorded value of the amounts outstanding under the bank revolving credit facility, if any, approximate fair value due to the variable interest rate that approximates current market rates (see Note 14 ). Derivative instruments are recorded at fair value, based on available market information (see Note 15 ). Fair Value Measurement – Financial assets and liabilities recorded at fair value in the Consolidated Balance Sheets are categorized based upon a fair value hierarchy established by GAAP, which classifies the inputs used to measure fair value into the following levels: • Level 1-inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2-inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. • Level 3-inputs to the valuation methodology are unobservable and significant to the fair value measurement. A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The determination to classify a financial instrument within Level 3 of the valuation hierarchy is based upon the significance of the unobservable inputs to the overall fair value measurement. However, Level 3 financial instruments typically include, in addition to the unobservable or Level 3 inputs, observable inputs (that is, inputs that are actively quoted and can be validated to external sources); accordingly, the gains and losses for Level 3 financial instruments include changes in fair value due in part to observable inputs that are part of the valuation methodology. Level 3 financial instruments include crude oil options, all NGL derivatives and the embedded derivatives in commodity contracts discussed in Note 14 as they have significant unobservable inputs. The methods and assumptions described above may produce a fair value that may not be realized in future periods upon settlement. Furthermore, while the Partnership believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. For further discussion see Note 14 . Employee Benefit Plans – Neither we nor our subsidiaries have any employees as of January 1, 2016. The Partnership entered into an employee services agreement, effective December 28, 2015, with a subsidiary of MPC for the services provided by the employees from the MarkWest Merger. The Partnership also has two other employee services agreements with MPC. Equity-Based Compensation Arrangements – The Partnership issues phantom units under its share-based compensation plan as described further in Note 19 . A phantom unit entitles the grantee a right to receive a common unit upon the issuance of the phantom unit. The fair value of phantom unit awards granted to employees and non-employee directors is based on the fair market value of MPLX LP common units on the date of grant. The fair value of the units awarded is amortized into earnings using a straight-line amortization schedule over the period of service corresponding with the vesting period. For phantom units that vest immediately and are not forfeitable, equity-based compensation expense is recognized at the time of grant. 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 paying out in units are accounted for as equity awards and use a Monte Carlo valuation model to calculate a grant date fair value. To satisfy common unit awards, the Partnership may issue new common units, acquire common units in the open market or use common units already owned by the general partner. Tax Effects of Share-Based Compensation – The Partnership elected to adopt the simplified method to establish the beginning balance of the additional paid-in capital pool (“APIC Pool”) related to the tax effects of employee share-based compensation and to determine the subsequent impact on the APIC Pool and Consolidated Statements of Cash Flows of the tax effects of share-based compensation awards that were outstanding upon adoption. Additional paid-in capital is reported as Common unitholders - public in the accompanying Consolidated Balance Sheets. Income Taxes – The Partnership is not a taxable entity for federal income tax purposes. As a result of the MarkWest Merger, discussed further in Note 4 , MarkWest was the surviving entity for tax purposes. MarkWest is not a taxable entity for federal income tax purposes. As such, the Partnership does not directly pay federal income tax. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the Consolidated Statements of Income, is includable in the federal income tax returns of each partner. The Partnership is, however, a taxable entity under certain state jurisdictions. MarkWest Hydrocarbon is a tax paying entity for both federal and state purposes. In addition to paying tax on its own earnings, MarkWest Hydrocarbon recognizes a tax expense or a tax benefit on its proportionate share of Partnership income or loss resulting from MarkWest Hydrocarbon’s ownership of Class A units of the Partnership, even though for financial reporting purposes such income or loss is eliminated in consolidation. The Class A units represent limited partner interests with the same rights as common units except that the Class A units do not have voting rights, except as required by law. Class A units are not treated as outstanding common units in the Consolidated Balance Sheets as they are eliminated in the consolidation of MarkWest Hydrocarbon. The deferred income tax component relates to the change in the temporary book to tax basis difference in the carrying amount of the investment in the Partnership which results primarily from its timing differences in MarkWest Hydrocarbon’s proportionate share of the book income or loss as compared with the MarkWest Hydrocarbon’s proportionate share of the taxable income or loss of the Partnership. The Partnership and MarkWest Hydrocarbon account for income taxes under the asset and liability method. Deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis, capital loss carryforwards and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates applied to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on d

Accounting Standards

Accounting Standards	12 Months Ended
	Dec. 31, 2015
Accounting Standards [Abstract]
New Accounting Pronouncements and Changes in Accounting Principles [Text Block]	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 adoption of this standard in the fourth quarter of 2015 did not have a material impact on the 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. The Partnership’s early adoption of this standard in the second quarter of 2015 did not have a material impact on the 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 which would be amortized over the term of the line-of-credit arrangements. This clarification did not have any impact on the 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 the 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. The Partnership is in the process of determining the impact of the new standard on the consolidated financial statements. In September 2015, the FASB issued an accounting standards 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 the consolidated results of operations, financial position or cash flows. In April 2015, the FASB issued an accounting standards update requiring that the earnings of transferred net assets prior to the dropdown date of the net assets to a master limited partnership be allocated entirely to the general partner when calculating earnings per unit under the two class method. Under this guidance, previously reported earnings per unit of the limited partners will not change as a result of a dropdown transaction. 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. Adoption of this standard is not expected to have a material impact on the 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 the 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 variable interest entity 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. Adoption of this standard is not expected to have a material impact on the consolidated 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. This 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 initial accounting standards update for revenue recognition, which has had subsequent updates. The new standard 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. The Partnership is in the process of determining the impact of the new standard on the consolidated financial statements.

Acquisition

Acquisition	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Acquisition	Acquisitions Purchase of MarkWest Energy Partners, L.P. On December 4, 2015 , a wholly-owned subsidiary of the Partnership merged with MarkWest Energy Partners, L.P. 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. MPC contributed approximately $1.3 billion of cash to the Partnership to pay the aggregate cash consideration to MarkWest unitholders, without receiving any new equity in exchange. At closing, MPC made a payment of $1.2 billion to MarkWest common unitholders and the remaining $50 million will be paid in equal amounts in July 2016 and 2017 in connection with the conversion of the Class B units to common units. The Partnership’s financial results and operating statistics reflect the results of MarkWest from the date of the acquisition forward. The components of the fair value of consideration transferred are as follows: (In millions) Fair value of units issued $ 7,326 Cash 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, the Partnership is still completing its 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 8,474 Intangibles 468 Other noncurrent assets 5 Total assets acquired 11,657 Accounts payable 322 Accrued liabilities 13 Accrued taxes 21 Other current liabilities 44 Long-term debt 4,567 Deferred income taxes 374 Deferred credits and other liabilities 151 Noncontrolling interest 13 Total liabilities and noncontrolling interest assumed 5,505 Net assets acquired excluding goodwill 6,152 Goodwill 2,454 Net assets acquired $ 8,606 The purchase price allocation resulted in the recognition of $2.5 billion in goodwill by the Partnership’s G&P 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 multiple segments of the hydrocarbon value chain. The Partnership recognized $36 million of acquisition-related costs associated with the MarkWest Merger. These costs were expensed, with $30 million included in General and administrative expenses and $6 million included in Other financial costs . The fair value of the common units issued was determined on the basis of the closing market price of the Partnership’s units as of the effective time of the transaction, and is considered a Level 1 measurement. The fair value of the Class B units issued was determined based on reference to the value of the common units, adjusted for a lack of distributions prior to their stated conversion dates, and is considered a Level 2 measurement. The fair values of the long-term debt and SMR liabilities were determined as of the acquisition date using the methods discussed in Note 14 . The fair value of the equity method investments was determined based on applying the discounted cash flow method, which is an income approach, to the Partnership’s equity method investments on an individual basis. Key assumptions include discount rates of 9.4 percent to 11.1 percent and terminal values based on the Gordon growth method to capitalize the cash flows, using a 2.5 percent long term growth rate. Intangibles represent customer contracts and related relationships. The fair value of the intangibles was determined based on applying the multi-period excess earnings method, which is an income approach. Key assumptions include attrition rates by reporting unit ranging from 5.0 percent to 10.0 percent and discount rates by reporting unit ranging from 11.0 percent to 13.0 percent . The fair value of property, plant and equipment was determined primarily based on the cost approach. Key assumptions include inputs to the valuation methodology such as recent purchases of similar items and published data for similar items. Components were adjusted for economic and functional obsolescence, location, normal useful lives, and capacity (if applicable). The fair value measurements for equity method investments, intangibles, and property, plant and equipment are based on significant inputs that are not observable in the market and, therefore, represent Level 3 measurements. The amounts of revenue and income from operations associated with MarkWest in the Consolidated Statements of Income for 2015 are as follows: (In millions) 2015 Revenues and other income $ 126 Income from operations 32 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 pro forma financial information does not give effect to potential synergies that could result from the acquisition and is not necessarily indicative of the results of future operations. (In millions, except per unit data) 2015 2014 Revenues and other income $ 2,424 $ 2,707 Net income attributable to MPLX LP 154 248 Net income attributable to MPLX LP per unit - basic 0.20 1.02 Net income attributable to MPLX LP per unit - diluted 0.19 0.96 The unaudited pro forma information includes adjustments primarily to align accounting policies, to adjust depreciation expense to reflect the fair value of property, plant and equipment, increase amortization expense related to identifiable intangible assets, adjust interest expense related to the fair value of MarkWest’s long-term debt and remove approximately $90 million of transaction related costs, as well as the related income tax effects. 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. The financing structure for MarkWest Utica EMG at its inception resulted in a de-facto agent relationship under which MarkWest was deemed to be the primary beneficiary of MarkWest Utica EMG. Therefore, MarkWest consolidated MarkWest Utica EMG in its historical financial statements. In the fourth quarter of 2015, based on economic conditions and other pertinent factors, the accounting for its investment in MarkWest Utica EMG was re-assessed. As of December 4, 2015 , the entity has been deconsolidated. For purposes of this pro forma financial information, MarkWest Utica EMG has been consolidated for the period prior to the acquisition consistent with its treatment in the historical periods presented. A summary of the amounts included in the historical financial statements of MarkWest for the year ended December 31, 2014 and the period from January 1, 2015 through December 3, 2015 related to MarkWest Utica EMG are as follows: (in millions) 2015 2014 Revenue and other income 152 85 Cost of revenue excluding depreciation and amortization 27 48 Depreciation and amortization 61 50 Net income attributable to noncontrolling interest 64 31 Net income (5 ) (46 ) EMG Utica, LLC (“EMG Utica”), a joint venture partner, received a special non-cash allocation of income of approximately $41 million and $37 million for the period from January 1, 2015 through December 3, 2015 and the year ended December 31, 2014, respectively. See Note 5 for a description of the transaction and its impact on the financial statements. Net income of MarkWest would not have changed had MarkWest Utica EMG been deconsolidated for the year ended December 31, 2014 and the period from January 1, 2015 through December 3, 2015. Purchases of Pipe Line Holdings Effective December 4, 2015 , the Partnership purchased the remaining 0.5 percent interest in Pipe Line Holdings from subsidiaries of MPC for consideration of $12 million . This resulted in Pipe Line Holdings becoming a wholly-owned subsidiary of the Partnership. The Partnership recorded the 0.5 percent interest at its historical carrying value of $6 million and the excess cash paid and equity contributed over historical carrying value of $6 million as a decrease to general partner equity. Prior to this transaction, the 0.5 percent interest was held by MPC and was reflected as the noncontrolling interest retained by MPC in the consolidated financial statements. Effective December 1, 2014 , the Partnership purchased a 22.875 percent interest in Pipe Line Holdings from subsidiaries of MPC for consideration of $600 million , which was financed through borrowings under our bank revolving credit facility, as discussed in Note 16 . In addition, the Partnership accepted a contribution of 7.625 percent of outstanding partnership interests of Pipe Line Holdings from subsidiaries of MPC in exchange for the issuance of equity valued at $200 million , as discussed in Note 8 . The Partnership recorded the combined 30.5 percent interest at its historical carrying value of $335 million and the excess cash paid and equity contributed over historical carrying value of $465 million as a decrease to general partner equity. Prior to this transaction, the 30.5 percent interest was held by MPC and was reflected as part of the noncontrolling interest retained by MPC in the consolidated financial statements. Beginning December 1, 2014, the consolidated financial statements reflect the 99.5 percent general partner interest in Pipe Line Holdings owned by MPLX LP, while the 0.5 percent limited partner interest held by MPC is reflected as a noncontrolling interest. On March 1, 2014 , the Partnership acquired a 13 percent interest in Pipe Line Holdings from MPC for consideration of $310 million , which was funded with $40 million of cash on hand and $270 million of borrowings on the bank revolving credit facility. The Partnership recorded the 13 percent interest in Pipe Line Holdings at its historical carrying value of $138 million and the excess cash paid over historical carrying value of $172 million as a decrease to general partner equity. In addition, on May 1, 2013 , the Partnership acquired a five percent interest in Pipe Line Holdings from MPC for consideration of $100 million , which was funded with cash on hand. The Partnership recorded the five percent interest in Pipe Line Holdings at its historical carrying value of $54 million and the excess cash paid over historical carrying value of $46 million as a decrease to general partner equity. These acquisitions were accounted for on a prospective basis and the terms of the acquisitions were approved by the conflicts committee of the board of directors of the general partner, which is comprised entirely of independent directors. Changes in MPLX LP’s equity resulting from changes in its ownership interest in Pipe Line Holdings were as follows: (In millions) 2015 2014 2013 Net income attributable to MPLX LP $ 156 $ 121 $ 78 Transfer to noncontrolling interest: Decrease in general partner-MPC equity for purchases of additional interest in Pipe Line Holdings (6 ) (638 ) (46 ) Change from net income attributable to MPLX LP and transfer to noncontrolling interest $ 150 $ (517 ) $ 32

Equity Method Investments Equit

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 MarkWest Utica EMG Effective January 1, 2012, MarkWest Utica Operating Company, LLC (“Utica Operating”), a wholly-owned and consolidated subsidiary of MarkWest, and EMG Utica (together the “Members”), executed agreements to form a joint venture, MarkWest Utica EMG, to develop significant natural gas gathering, processing and NGL fractionation, transportation and marketing infrastructure in eastern Ohio. The related LLC agreement has been amended from time to time (the LLC agreement as currently in effect is referred to as the “Amended LLC Agreement”). The aggregate funding commitment of EMG Utica was $950 million (the “Minimum EMG Investment”). Thereafter, Utica Operating was required to fund, as needed, 100 percent of future capital for MarkWest Utica EMG until such time as the aggregate capital that had been contributed by the Members reached $2 billion , which occurred prior to the MarkWest Merger. Until such time as the investment balances of Utica Operating and EMG Utica are in the ratio of 70 percent and 30 percent , respectively (such time being referred to as the “Second Equalization Date”), EMG Utica will have the right, but not the obligation, to fund up to 10 percent of each capital call for MarkWest Utica EMG, and Utica Operating will be required to fund all remaining capital not elected to be funded by EMG Utica. After the Second Equalization Date, Utica Operating and EMG Utica will have the right, but not the obligation, to fund their pro rata portion (based on their respective investment balances) of any additional required capital and may also fund additional capital that the other party elects not to fund. As of December 31, 2015, EMG Utica has contributed $996 million and Utica Operating has contributed approximately $ 1.5 billion to MarkWest Utica EMG. Under the Amended LLC Agreement, after EMG Utica has contributed more than $500 million to MarkWest Utica EMG and prior to December 31, 2016, EMG Utica’s investment balance will also be increased by a quarterly special non-cash allocation of income (“Preference Amount”) that is based upon the amount of capital contributed by EMG Utica in excess of $500 million . No Preference Amount will accrue to EMG Utica’s investment balance after December 31, 2016. EMG Utica received a special non-cash allocation of income of approximately $4 million for the 28 days ended December 31, 2015. Under the Amended LLC Agreement, Utica Operating will continue to receive 60 percent of cash generated by MarkWest Utica EMG that is available for distribution until the earlier of December 31, 2016 and the date on which Utica Operating’s investment balance equals 60 percent of the aggregate investment balances of the Members. After the earlier of those dates, cash generated by MarkWest Utica EMG that is available for distribution will be allocated to the Members in proportion to their respective investment balances. As of December 31, 2015, Utica Operating’s investment balance in MarkWest Utica EMG was approximately 56 percent. MarkWest Utica EMG is deemed to be a VIE. As of the date of the MarkWest Merger, Utica Operating is not deemed to be the primary beneficiary due to EMG Utica’s voting rights on significant matters. The Partnership’s portion of MarkWest Utica EMG’s net assets, which was $2.2 billion at December 31, 2015 , is reported under the caption Equity method investments on the Consolidated Balance Sheets. The Partnership’s maximum exposure to loss as a result of its involvement with MarkWest Utica EMG includes its equity investment, any additional capital contribution commitments and any operating expenses incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. The Partnership did not provide any financial support to MarkWest Utica EMG that it was not contractually obligated to provide during the 28 days ended December 31, 2015. The Partnership receives engineering and construction and administrative management fee revenue and other direct personnel costs (“Operational Service” revenue) for operating MarkWest Utica EMG. The amount of Operational Service revenue related to MarkWest Utica EMG for the 28 days ended December 31, 2015 was less than $1 million and is reported as Other income - related parties in the Consolidated Statements of Income. Ohio Gathering 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 this entity is a subsidiary of MarkWest Utica EMG, which is accounted for as an equity method investment, the Partnership reports its portion of Ohio Gathering’s net assets as a component of its investment in MarkWest Utica EMG. The Partnership receives Operational Service revenue for operating Ohio Gathering. The amount of operational service revenue related to Ohio Gathering for the 28 days ended December 31, 2015 was approximately $2 million and is reported as Other income - related parties in the Consolidated Statements of Income. Ohio Condensate In December 2013, MarkWest formed Utica Condensate for the purpose of engaging in wellhead condensate gathering, stabilization, terminalling, storage and marketing in the state of Ohio. As of December 31, 2015 the Partnership owned 100 percent of Utica Condensate. Utica Condensate’s business is conducted solely through its subsidiary, Ohio Condensate Company L.L.C. (“Ohio Condensate”), which is a joint venture between Utica Condensate and Summit. As of December 31, 2015 , Utica Condensate owned 60 percent of Ohio Condensate. The Partnership accounts for Ohio Condensate, which is a VIE, as an equity method investment as MPLX exercises significant influence, but does not control Ohio Condensate and is not its primary beneficiary due to Summit’s voting rights on significant matters. The Partnership’s portion of Ohio Condensate’s net assets are reported under the caption Equity method investments on the Consolidated Balance Sheets. The Partnership receives Operational Service revenue for operating Ohio Condensate. The amount of Operational Service revenue related to Ohio Condensate for the 28 days ended December 31, 2015 was less than $1 million and is reported as Other income - related parties in the Consolidated Statements of Income. Summarized financial information from the date of the MarkWest Merger and as of December 31, 2015 for equity method investments is as follows: (In millions) MarkWest Utica EMG (1) Other VIEs Non-VIEs Total Income statement data: Revenue 18 2 9 29 Income from operations 9 — 1 10 Net income 10 — 1 11 Balance sheet data: Current assets 113 7 30 150 Noncurrent assets 2,207 169 243 2,619 Current liabilities 77 7 18 102 Noncurrent liabilities 1 12 — 13 (1) MarkWest Utica EMG’s noncurrent assets includes its investment in its subsidiary Ohio Gathering, which does not appear elsewhere in this table. The investment was $781 million as of December 31, 2015. As of December 31, 2015, the carrying value of our equity method investments was $ 961 million higher than the underlying net assets of investees. This basis difference is being amortized or accreted into net income over the remaining estimated useful lives of the underlying net assets, except for $ 371 million of excess related to goodwill.

Related Party Agreements and Tr

Related Party Agreements and Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Agreements and Transactions	Related Party Agreements and Transactions The Partnership’s material related parties included: • MPC, which refines, markets and transports crude oil and petroleum products, primarily in the Midwest, Gulf Coast and Southeast regions of the United States. • Centennial Pipeline LLC (“Centennial”), in which MPC has a 50 percent interest. Centennial owns a products pipeline and storage facility. • Muskegon Pipeline LLC (“Muskegon”), in which MPC has a 60 percent interest. Muskegon owns a common carrier products pipeline. • MarkWest Utica EMG, in which MPLX has a 60 percent interest. MarkWest Utica EMG is engaged in significant natural gas processing and NGL fractionation, transportation and marketing in eastern Ohio. • Ohio Gathering, in which MPLX has a 36 percent indirect interest. Ohio Gathering is a subsidiary of MarkWest Utica EMG providing natural gas gathering service in the Utica Shale region of Ohio. • Jefferson Dry Gas, in which MPLX has a 67 percent interest. Jefferson Dry Gas is engaged in dry natural gas gathering in the county of Jefferson, Ohio. • Ohio Condensate, in which MPLX has a 60 percent interest. Ohio Condensate is engaged in wellhead condensate gathering, stabilization, terminalling, transportation and storage within certain defined areas of Ohio. Commercial Agreements The Partnership has various long-term, fee-based transportation services and storage services agreements with MPC. Under these agreements, the Partnership provides transportation and storage services to MPC, and MPC has committed to provide the Partnership with minimum quarterly throughput volumes on crude oil and products systems and minimum storage volumes of crude oil, products and butane. The Partnership believes the terms and conditions under these agreements, as well as the initial agreements with MPC described below, are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services. These commercial agreements with MPC include: • three separate 10 -year transportation services agreements and one five -year transportation services agreement under which MPC pays the Partnership fees for transporting crude oil on various of our crude oil pipeline systems; • four separate 10 -year transportation services agreements under which MPC pays the Partnership fees for transporting products on each of our refined product pipeline systems; • a five -year transportation services agreement under which MPC pays the Partnership fees for handling crude oil and products at our Wood River, Illinois barge dock; • a 10 -year storage services agreement under which MPC pays the Partnership fees for providing storage services at our Neal, West Virginia butane cavern; and • four separate three -year storage services agreements under which MPC pays the Partnership fees for providing storage services at our tank farms. All of the transportation services agreements with MPC for the Partnership’s crude oil and product pipeline systems (other than the Wood River, Illinois to Patoka, Illinois crude system) automatically renew for up to two additional five -year terms unless terminated by either party. The transportation services agreements with MPC for the Wood River to Patoka crude system and the barge dock automatically renew for up to four additional two -year terms unless terminated by either party. The Partnership’s butane cavern storage services agreement with MPC does not automatically renew. The storage services agreements with MPC for the Partnership’s tank farms automatically renew for additional one -year terms unless terminated by either party. Under the transportation services agreements, if MPC fails to transport its minimum throughput volumes during any quarter, then MPC will pay the Partnership a deficiency payment equal to the volume of the deficiency multiplied by the tariff rate then in effect. If the minimum capacity of the pipeline falls below the level of MPC’s commitment at any time or if capacity on the pipeline is required to be allocated among shippers because volume nominations exceed available capacity, depending on the cause of the reduction in capacity, MPC’s commitment may be reduced or MPC will receive a credit for its minimum volume commitment for that period. In addition to MPC’s minimum volume commitment, MPC is also responsible for any loading, handling, transfer and other charges with respect to volumes we transport for MPC. If the Partnership agrees to make any capital expenditures at MPC’s request, MPC will reimburse it for, or we will have the right in certain circumstances, to file for an increased tariff rate to recover the actual cost of such capital expenditures. The transportation services agreements include provisions that permit MPC to suspend, reduce or terminate its obligations under the applicable agreement if certain events occur. These events include MPC deciding to permanently or indefinitely suspend refining operations at one or more of its refineries for at least twelve consecutive months and certain force majeure events that would prevent the Partnership or MPC from performing required services under the applicable agreement. Effective June 11, 2015, MPL entered into a transportation services agreement with MPC pursuant to which MPL will charge fees to MPC, at applicable FERC tariff rates, for transporting products on the Cornerstone pipeline system and related Utica build-out projects. MPC will be obligated to transport certain minimum quarterly volumes of products on the associated pipeline systems. If MPC fails to transport its minimum volume during any quarter, then MPC will pay MPL a quarterly deficiency payment. The amount of any quarterly deficiency payment paid by MPC may be applied as a credit for any volumes transported on the applicable pipeline system in excess of MPC’s minimum volume commitment during any of the succeeding four quarters, after which time any unused credits will expire. Upon the expiration or termination of this agreement, MPC will have the opportunity to apply any remaining credit amounts until the completion of the succeeding four quarter period, without regard to the minimum volume commitment under the agreement. This agreement has an initial term of 15 years after the project’s in-service date and automatically renews for up to two renewal terms of five years each unless either party provides the other party with written notice of its intent to terminate at least six months prior to the end of the primary term or any renewal term, as applicable. Under the storage services agreements, the Partnership is obligated to make available to MPC on a firm basis the available storage capacity at our tank farms and butane cavern, and MPC pays the Partnership a per-barrel fee for such storage capacity, regardless of whether MPC fully utilizes the available capacity. The Partnership may adjust the per-barrel fee by a percentage equal to an increase in the PPI in early 2015. On September 17, 2015, MPL entered into an amendment (the “First Amendment”) to its existing Patoka, Illinois tank farm Storage Services Agreement with MPC dated September 24, 2012 (the “Storage Services Agreement”). Under the Storage Services Agreement, MPC pays a monthly fee to store crude oil at MPL’s Patoka, Illinois tank farm. MPC’s fees under the Storage Services Agreement are for the use of the available shell capacity of MPL’s Patoka, Illinois tank farm, regardless of whether MPC fully utilizes all of its contractual capacity. The First Amendment provides for an increase in available shell capacity at the Patoka, Illinois tank farm from 1,386,000 barrels to 2,626,000 barrels due to the addition of four newly constructed tanks at the facility. Operating Agreements The Partnership operates various pipeline systems owned by MPC under operating services agreements. Under these operating services agreements, the Partnership receives an operating fee for operating the assets and is reimbursed for all direct and indirect costs associated with operating the assets. Most of these agreements are indexed for inflation. These agreements range from one to five years in length and automatically renew unless terminated by either party. On January 1, 2015, MPC and MPL amended the Amended and Restated Operating Agreement to reflect the transfer of certain assets from MPC to Hardin Street Transportation LLC (“HST”), an indirect, wholly-owned subsidiary of MPC. This amended agreement, with an annual operating fee of $1 million , now covers only the assets not transferred to HST. Also on January 1, 2015, MPL entered into a new agreement with HST (the “HST Operating Agreement”) for operation of the transferred assets with an annual fee of $12 million . The HST Operating Agreement has an initial term of one year and automatically renews for additional one -year terms, unless either party provides the other party with written notice of its intent to terminate the agreement at least six months prior to the end of the initial term or any renewal term. In combination, the amended and new agreement did not change the fees received by MPL or the services provided under the agreements. Management Services Agreements The Partnership has two management services agreements with MPC under which it provides certain management services to MPC with respect to certain of MPC’s retained pipeline assets. The Partnership received $1 million in fees under these agreements in 2015 . The Partnership may adjust annually for inflation and based on changes in the scope of management services provided. The Partnership also receives engineering and construction and administrative management fee revenue and other direct personnel costs for operating some joint venture entities. Omnibus Agreement The Partnership has an omnibus agreement with MPC that addresses its payment of a fixed annual fee to MPC for the provision of executive management services by certain executive officers of the general partner and the Partnership’s reimbursement of MPC for the provision of certain general and administrative services to it, as well as MPC’s indemnification of the Partnership for certain matters, including environmental, title and tax matters. Employee Services Agreements The Partnership has two employee services agreements with MPC under which it reimburses MPC for the provision of certain operational and management services to the Partnership in support of its pipelines, barge dock, butane cavern and tank farms within the L&S segment. Effective December 28, 2015, the Partnership entered into an additional employee services agreement under which it reimburses MPC for the same type of services in support of its midstream assets utilized in the natural gas and NGLs businesses within the G&P segment as well as certain other services in support of the Partnership. Loan Agreements On December 4, 2015 , the Partnership entered into a loan agreement with MPC Investment LLC (“MPC Investment”), a wholly-owned subsidiary of MPC. Under the terms of the agreement, MPC Investment will make a loan or loans to the Partnership on a revolving basis as requested by the Partnership and as agreed to by MPC Investment, in an amount or amounts that do not result in the aggregate principal amount of all loans outstanding exceeding $500 million at any one time. The entire unpaid principal amount of the loan, together with all accrued and unpaid interest and other amounts (if any), shall become due and payable on December 4, 2020 . MPC Investment may demand payment of all or any portion of the outstanding principal amount of the loan, together with all accrued and unpaid interest and other amounts (if any), at any time prior to December 4, 2020 . Borrowings under the loan will bear interest at LIBOR plus 1.50 percent . During 2015 , the Partnership borrowed $301 million and repaid $293 million , for an outstanding balance at December 31, 2015 of $8 million , which is included in Payables to related parties on the Consolidated Balance Sheets. Borrowings were at an average interest rate of 1.744 percent , per annum. In connection with this loan agreement, the Partnership terminated the previous revolving credit agreement of $50 million with MPC, effective December 31, 2015 . Related Party Transactions The Partnership believes that transactions with related parties were conducted on terms comparable to those with unrelated parties. Related party sales to MPC consisted of crude oil and refined products pipeline transportation services based on regulated tariff rates and storage services based on contracted rates. Related party sales to MPC also consist of revenue related to volume deficiency credits. Revenue received from related parties related to service and product sales were as follows: (In millions) 2015 2014 2013 Service revenue MPC $ 481 $ 451 $ 384 Product sales MPC $ 1 $ — $ — The revenue received for operating pipelines for related parties included in Other income - related parties on the Consolidated Statements of Income were as follows: (In millions) 2015 2014 2013 MPC $ 24 $ 22 $ 18 Centennial 1 1 1 Ohio Gathering 2 — — Total $ 27 $ 23 $ 19 MPC provides executive management services and certain general and administrative services to the Partnership under the terms of the omnibus agreement. Expenses incurred under these agreements are shown in the table below by the income statement line where they were recorded. Charges for services included in Purchases from related parties primarily relate to services that support the Partnership’s operations and maintenance activities, as well as compensation expenses. Charges for services included in General and administrative expenses primarily relate to services that support the Partnership’s executive management, accounting and human resources activities. These charges were as follows: (In millions) 2015 2014 2013 Purchases from related parties $ 25 $ 25 $ 18 General and administrative expenses 34 31 31 Total $ 59 $ 56 $ 49 Also under terms of the omnibus agreement, some service costs related to engineering services are associated with assets under construction. These costs added to Property, plant and equipment were as follows: (In millions) 2015 2014 2013 MPC $ 13 $ 8 $ 8 MPLX LP obtains employee services from MPC under employee services agreements. Expenses incurred under these agreements are shown in the table below by the income statement line where they were recorded. The costs of personnel directly involved in or supporting operations and maintenance activities are classified as Purchases from related parties . The costs of personnel involved in executive management, accounting and human resources activities are classified as General and administrative expenses. Employee services expenses from related parties were as follows: (In millions) 2015 2014 2013 Purchases from related parties $ 77 $ 73 $ 77 General and administrative expenses 20 24 16 Total $ 97 $ 97 $ 93 Receivables from related parties were as follows: December 31, (In millions) 2015 2014 MPC $ 76 $ 41 Centennial 1 — Jefferson Dry Gas 2 — MarkWest Utica EMG 4 — Ohio Gathering 5 — Total $ 88 $ 41 Long-term receivables related to reimbursements from the MarkWest Merger to be provided by MPC for the conversion of Class B units were as follows: December 31, (In millions) 2015 2014 MPC $ 25 $ — Payables to related parties were as follows: December 31, (In millions) 2015 2014 MPC $ 26 $ 20 MarkWest Utica EMG 21 — Total $ 47 $ 20 Under the Partnership’s transportation services agreements, if MPC fails to transport its minimum throughput volumes during any quarter, then MPC will pay the Partnership a deficiency payment equal to the volume of the deficiency multiplied by the tariff rate then in effect. The deficiency amounts are recorded as deferred revenue-related parties. MPC may then apply the amount of any such deficiency payments as a credit for volumes transported on the applicable pipeline system in excess of its minimum volume commitment during the following four or eight quarters under the terms of the applicable transportation services agreement. The Partnership recognizes revenues for the deficiency payments at the earlier of when credits are used for volumes transported in excess of minimum quarterly volume commitments, when it becomes impossible to physically transport volumes necessary to utilize the credits or upon the expiration of the applicable four or eight quarter period. The use or expiration of the credits is a decrease in deferred revenue-related parties. During 2015 and 2014 , MPC did not transport its minimum committed volumes on certain pipeline systems. In addition, capital projects we are undertaking at the request of MPC are reimbursed in cash and recognized in income over the remaining term of the applicable transportation services agreements. The deferred revenue-related parties associated with the minimum volume deficiencies and project reimbursements were as follows: December 31, (In millions) 2015 2014 Minimum volume deficiencies - MPC $ 36 $ 30 Project reimbursements - MPC 5 5 Total $ 41 $ 35 Certain asset transfers between the Partnership and MPC, including additions to property, plant and equipment related to capitalized interest incurred by MPC on the Partnership’s behalf, and certain expenses, such as stock-based compensation, incurred by MPC on the Partnership’s behalf have been recorded as non-cash capital contributions or distributions. The non-cash contributions from MPC were less than $1 million in 2015 , 2014 and 2013 .

Net Income Per Limited Partner

Net Income Per Limited Partner Unit	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Net Income Per Limited Partner Unit	Net Income Per Limited Partner Unit Net income per unit applicable to common limited partner units and to subordinated limited partner units is computed by dividing the respective limited partners’ interest in net income attributable to MPLX LP by the weighted average number of common units and subordinated units outstanding. Because the Partnership has more than one class of participating securities, it uses the two-class method when calculating the net income per unit applicable to limited partners. The classes of participating securities include common units, subordinated units, general partner units, certain equity-based compensation awards and incentive distribution rights. As discussed further in Note 8 , the subordinated units, all of which were owned by MPC, were converted into common units during the third quarter of 2015. For purposes of calculating net income per unit, the subordinated units were treated as if they converted to common units on July 1, 2015. In 2015, the Partnership had dilutive potential common units consisting of certain equity-based compensation awards and Class B units. Diluted net income per limited partner unit for 2014 and 2013 reporting periods is the same as basic net income per limited partner unit as there were no potentially dilutive common or subordinated units outstanding as of December 31, 2014 or 2013 . (In millions) 2015 2014 2013 Net income attributable to MPLX LP $ 156 $ 121 $ 78 Less: General partner’s distributions declared (including IDRs) (1) 60 6 2 Limited partners’ distributions declared on common units (1) 224 54 43 Limited partner’s distributions declared on subordinated units (1) 31 52 43 Undistributed net (loss) income attributable to MPLX LP $ (159 ) $ 9 $ (10 ) (1) See Note 8 for information regarding the distribution. 2015 (In millions, except per-unit data) General Partner Limited Partners’ Common Units Limited Partner’s Subordinated Units Total Basic and diluted net income attributable to MPLX LP per unit: Net income attributable to MPLX LP: Distributions declared (including IDRs) $ 60 $ 224 $ 31 $ 315 Undistributed net loss attributable to MPLX LP (3 ) (127 ) (29 ) (159 ) Net income attributable to MPLX LP $ 57 $ 97 $ 2 $ 156 Weighted average units outstanding: Basic 2 79 18 99 Diluted 2 80 18 100 Net income attributable to MPLX LP per limited partner unit: Basic $ 1.23 $ 0.11 Diluted $ 1.22 $ 0.11 2014 (In millions, except per-unit data) General Partner Limited Partners’ Common Units Limited Partner’s Subordinated Units Total Basic and diluted net income attributable to MPLX LP per unit: Net income attributable to MPLX LP: Distribution declared $ 6 $ 54 $ 52 $ 112 Undistributed net income attributable to MPLX LP 2 4 3 9 Net income attributable to MPLX LP $ 8 $ 58 $ 55 $ 121 Weighted average units outstanding: Basic 2 37 37 76 Diluted 2 37 37 76 Net income attributable to MPLX LP: Basic $ 1.55 $ 1.50 Diluted $ 1.55 $ 1.50 2013 (In millions, except per-unit data) General Partner Limited Partners’ Common Units Limited Partner’s Subordinated Units Total Basic and diluted net income attributable to MPLX LP per unit: Net income attributable to MPLX LP: Distribution declared $ 2 $ 43 $ 43 $ 88 Undistributed net loss attributable to MPLX LP — (4 ) (6 ) (10 ) Net income attributable to MPLX LP $ 2 $ 39 $ 37 $ 78 Weighted average units outstanding: Basic 1 37 37 75 Diluted 1 37 37 75 Net income attributable to MPLX LP per limited partner unit: Basic $ 1.05 $ 1.01 Diluted $ 1.05 $ 1.01

Equity

Equity	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Equity	Equity Units Outstanding - The Partnership had 296,687,176 common units outstanding as of December 31, 2015 . Of that number, 56,932,134 were owned by MPC. The two percent general partner interest, represented by 6,800,475 general partner units, was owned by MPC. See below for discussion of units issued in connection with the MarkWest Merger. Following payment of the cash distribution for the second quarter of 2015, the requirements for the conversion of all subordinated units were satisfied under the partnership agreement. As a result, effective August 17, 2015 , the 36,951,515 subordinated units owned by MPC were converted into common units on a one-for-one basis and thereafter participate on terms equal with all other common units in distributions of available cash. The conversion did not impact the amount of the cash distributions paid by the Partnership or the total units outstanding. MarkWest Merger - On December 4, 2015, the Partnership completed the MarkWest Merger. As defined in the merger agreement, each common unit of MarkWest issued and outstanding at the effective time of the MarkWest Merger was converted into the right to receive 1.09 common units of MPLX LP. This resulted in the issuance of 216,350,465 common units. The Class A units of MarkWest outstanding immediately prior to the MarkWest Merger were converted into 28,554,313 Class A units of MPLX LP having substantially similar rights and obligations that the Class A units of MarkWest had immediately prior to the combination. Each Class B unit of MarkWest outstanding had immediately prior to the merger converted into the right to receive one Class B unit of MPLX LP having substantially similar rights, including conversion and registration rights, and obligations that the Class B units of MarkWest had immediately prior to the merger. This resulted in the issuance of 7,981,756 MPLX LP Class B units. On July 1, 2016 and July 1, 2017 (unless earlier converted upon certain fundamental changes regarding MPLX LP), each Class B unit of MPLX LP will automatically convert into 1.09 MPLX LP common units and the right to receive $6.20 in cash. ATM Program - On May 18, 2015 , the Partnership filed a prospectus supplement to its shelf registration statement filed with the SEC on March 27, 2015, authorizing the continuous issuance of up to an aggregate of $500 million of common units, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings (such continuous offering program, or at-the-market program is referred to as our “ATM Program”). The Partnership expects the net proceeds from sales under the ATM Program will be used for general partnership purposes. During the year ended December 31, 2015 , the Partnership issued an aggregate of 25,166 common units under our ATM Program, generating net proceeds of approximately $1 million . The table below summarizes the changes in the number of units outstanding through December 31, 2015 : (In units) Common Class B Subordinated General Partner Total Balance at December 31, 2012 36,951,515 — 36,951,515 1,508,225 75,411,255 Balance at December 31, 2013 36,951,515 — 36,951,515 1,508,225 75,411,255 Unit-based compensation awards 15,479 — — 316 15,795 Contribution of interest in Pipe Line Holdings 2,924,104 — — 59,676 2,983,780 December 2014 equity offering 3,450,000 — — 70,408 3,520,408 Balance at December 31, 2014 43,341,098 — 36,951,515 1,638,625 81,931,238 Unit-based compensation awards 18,932 — — 386 19,318 Issuance of units under the ATM program 25,166 — — 514 25,680 Subordinated unit conversion 36,951,515 — (36,951,515 ) — — MarkWest Merger 216,350,465 7,981,756 5,160,950 229,493,171 Balance at December 31, 2015 296,687,176 7,981,756 — 6,800,475 311,469,407 2014 Activity Effective December 1, 2014 , as discussed in Note 4 , the Partnership accepted a contribution of 7.625 percent of outstanding partnership interests of Pipe Line Holdings from subsidiaries of MPC in exchange for the issuance of equity valued at $200 million . The equity consideration consisted of 2,924,104 MPLX common units and was calculated by dividing $200 million by the average closing price for MPLX common units for the ten trading days preceding December 1, 2014, which was $68.397 . On December 8, 2014, the Partnership closed an equity offering of 3,450,000 common units at a public offering price of $66.68 per unit. The Partnership used the net proceeds of $221 million to repay borrowings under its revolving credit facility and for general partnership purposes. As a result of the contribution mentioned above and the December 2014 equity offering, MPLX GP contributed $9 million in exchange for 130,084 general partner units to maintain its general partnership interest. 2015 Activity As a result of common units issued under the ATM Program during 2015 , MPLX GP contributed less than $1 million in exchange for 514 general partner units to maintain its general partner interest. In connection with the MarkWest Merger discussed in Note 4 , MPLX GP contributed $169 million in exchange for 5,160,950 general partner units to maintain its general partner interest. Issuance of Additional Securities - The partnership agreement authorizes the Partnership to issue an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by the general partner without the approval of the unitholders. Incentive Distribution Rights - The following table illustrates the percentage allocations of available cash from operating surplus between the common and subordinated unitholders and the general partner based on the specified target distribution levels. The amounts set forth under “Marginal percentage interest in distributions” are the percentage interests of the general partner and common and subordinated unitholders in any available cash from operating surplus the Partnership distributes up to and including the corresponding amount in the column “Total quarterly distribution per unit target amount.” The percentage interests shown for its common and subordinated unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for the general partner include its two percent general partner interest and assume that the general partner has contributed any additional capital necessary to maintain its two percent general partner interest, the general partner has not transferred its incentive distribution rights and that there are no arrearages on common units. Marginal percentage interest in distributions Total quarterly distribution per unit target amount Unitholders General Partner Minimum quarterly distribution $ 0.2625 98.0 % 2.0 % First target distribution above $0.2625 up to $0.301875 98.0 % 2.0 % Second target distribution above $0.301875 up to $0.328125 85.0 % 15.0 % Third target distribution above $0.328125 up to $0.393750 75.0 % 25.0 % Thereafter above $0.393750 50.0 % 50.0 % Net Income Allocation - In preparing the Consolidated Statements of Equity, net income attributable to MPLX LP is allocated to the unitholders in accordance with their respective ownership percentages. However, when distributions related to the incentive distribution rights are made, earnings equal to the amount of those distributions are first allocated to the general partner before the remaining earnings are allocated to the unitholders based on their respective ownership percentages. The following table presents the allocation of the general partner’s interest in net income attributable to MPLX LP: (In millions) 2015 2014 2013 Net income attributable to MPLX LP $ 156 $ 121 $ 78 Less: General partner's incentive distribution rights and other 55 4 — Net income attributable to MPLX LP available to general and limited partners $ 101 $ 117 $ 78 General partner’s interest in net income attributable to MPLX LP $ 2 $ 2 $ 2 General partner's incentive distribution rights and other 55 4 — General partner's interest in net income attributable to MPLX LP $ 57 $ 6 $ 2 Cash distributions - The partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders and general partner will receive. In accordance with the partnership agreement, on January 25, 2016 , the Partnership declared a quarterly cash distribution, based on the results of the fourth quarter of 2015 , totaling $189 million , or $0.50 per unit. This distribution was paid on February 12, 2016 to unitholders of record on February 4, 2016 . See the table below for the IDR impact for 2015. The allocation of total quarterly cash distributions to general and limited partners is as follows for the year ended December 31, 2015 , 2014 and 2013 . The distributions are declared subsequent to quarter end; therefore, the following table represents total cash distributions applicable to the period in which the distributions were earned. (In millions) 2015 2014 2013 General partner's distributions: General partner's distributions $ 6 $ 2 $ 2 General partner's incentive distribution rights distributions 54 4 — Total general partner's distributions $ 60 $ 6 $ 2 Limited partners' distributions: Common unitholders $ 224 $ 54 $ 43 Subordinated unitholders 31 52 43 Total limited partners' distributions 255 106 86 Total cash distributions declared $ 315 $ 112 $ 88

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2015
Segment Information [Abstract]
Segment Information	Segment Information The Partnership’s chief operating decision maker is the chief executive officer (“CEO”) of its general partner. The CEO reviews the Partnership’s discrete financial information, makes operating decisions, assesses financial performance and allocates resources on a type of service basis. The Partnership has two reportable segments: L&S and G&P . Each of these segments is organized and managed based upon the nature of the products and services it offers. • L&S - transports and stores crude oil, refined products and other hydrocarbon-based products. • G&P - gathers, processes and transports natural gas; gathers, transports, fractionates, stores and markets NGLs. This segment is the result of the MarkWest Merger on December 4, 2015 discussed in more detail in Note 4 . Segment information for periods prior to the MarkWest Merger does not include amounts for these operations. The Partnership has investments in entities that are accounted for using the equity method of accounting (see Note 5 ). However, the CEO views financial information as if those investments were consolidated. Segment operating income represents income from operations attributable to the reportable segments. Corporate general and administrative expenses, unrealized derivative gains (losses) and depreciation and amortization are not allocated to the reportable segments. Management does not consider these items allocable to or controllable by any individual segment and, therefore, excludes these items when evaluating segment performance. Segment results are also adjusted to exclude the portion of income from operations attributable to the noncontrolling interests related to partially owned entities that are either consolidated or accounted for as equity method investments. The tables below present information about income from operations and capital expenditures for the reported segments: 2015 (In millions) L&S G&P Total Revenues and other income: Segment revenues $ 547 $ 150 $ 697 Segment other income 30 — 30 Total segment revenues and other income 577 150 727 Costs and expenses: Segment cost of revenues 254 62 316 Segment operating income before portion attributable to noncontrolling interest 323 88 411 Segment portion attributable to noncontrolling interest 1 12 13 Segment operating income attributable to MPLX LP $ 322 $ 76 $ 398 2014 (In millions) L&S Revenues and other income: Segment revenues $ 520 Segment other income 28 Total segment revenues and other income 548 Costs and expenses: Segment cost of revenues 250 Segment operating income before portion attributable to noncontrolling interest 298 Segment portion attributable to noncontrolling interest 85 Segment operating income attributable to MPLX LP $ 213 2013 (In millions) L&S Revenues and other income: Segment revenues $ 463 Segment other income 23 Total segment revenues and other income 486 Costs and expenses: Segment cost of revenues 237 Segment operating income before portion attributable to noncontrolling interest 249 Segment portion attributable to noncontrolling interest 106 Segment operating income attributable to MPLX LP $ 143 (in millions) 2015 2014 2013 Reconciliation to Income from operations: Segment operating income attributable to MPLX $ 398 $ 213 $ 143 Segment portion attributable to unconsolidated affiliates (21 ) — — Segment portion attributable to noncontrolling interest 13 85 106 Income from equity method investments 3 — — Other income - related parties 2 — — Unrealized derivative gains 4 — — Depreciation and amortization (89 ) (50 ) (49 ) General and administrative expenses (104 ) (65 ) (53 ) Income from operations $ 206 $ 183 $ 147 (in millions) 2015 2014 2013 Reconciliation to Total revenues and other income: Total segment revenues and other income $ 727 $ 548 $ 486 Revenue adjustment from unconsolidated affiliates (28 ) — — Income from equity method investments 3 — — Other income - related parties 2 — — Unrealized derivative loss (1 ) — — Total revenues and other income $ 703 $ 548 $ 486 (in millions) 2015 2014 2013 Reconciliation to Net income attributable to noncontrolling interests Segment portion attributable to noncontrolling interest $ 13 $ 85 $ 106 Portion of noncontrolling interests related to items below segment income from operations (7 ) (28 ) (38 ) Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates (5 ) — — Net income attributable to noncontrolling interests $ 1 $ 57 $ 68 The following reconciles segment capital expenditures to total capital expenditures: (In millions) 2015 2014 2013 L&S segment capital expenditures $ 188 $ 79 $ 107 G&P segment capital expenditures (1) 100 — — Total segment capital expenditures 288 79 107 Less: Capital expenditures for Partnership operated, non-wholly owned subsidiaries (24 ) — — Total capital expenditures $ 264 $ 79 $ 107 (1) The G&P segment includes $24 million of capital expenditures related to Partnership operated, non-wholly owned subsidiaries. Total assets by reportable segment were: December 31, (In millions) 2015 2014 L&S $ 1,431 $ 1,214 G&P 14,246 — Total assets $ 15,677 $ 1,214

Major Customer and Concentratio

Major Customer and Concentration of Credit Risk	12 Months Ended
	Dec. 31, 2015
Risks and Uncertainties [Abstract]
Major Customer and Concentration of Credit Risk	Major Customer and Concentration of Credit Risk MPC accounted for 72 percent, 86 percent and 83 percent of the Partnership’s total revenues and other income for 2015 , 2014 and 2013 , excluding revenues attributable to volumes shipped by MPC under joint tariffs with third parties, which are treated as third-party revenue for accounting purposes. The Partnership provides crude oil and product pipeline transportation and storage services to MPC and operate pipelines on behalf of MPC. The Partnership has a concentration of trade receivables due from customers in the same industry, MPC, integrated oil companies, independent refining companies and other pipeline companies. These concentrations of customers may impact the Partnership’s overall exposure to credit risk as they may be similarly affected by changes in economic, regulatory and other factors. The Partnership manages its exposure to credit risk through credit analysis, credit limit approvals and monitoring procedures, and for certain transactions, it may request letters of credit, prepayments or guarantees.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Income Tax The Partnership is not a taxable entity for United States federal income tax purposes or for the majority of states that impose an income tax. Taxes on the Partnership’s net income generally are borne by its partners through the allocation of taxable income. The Partnership’s income tax provision results from partnership activity in the states of Texas and Tennessee. MarkWest Hydrocarbon is a tax paying entity for both federal and state tax purposes. The Partnership and MarkWest Hydrocarbon’s income tax expense was $2 million for the year ended December 31, 2015, and a benefit of less than $1 million for 2014 and 2013 , respectively. Our effective tax rate was one percent for 2015 and less than one percent for 2014 and 2013 . The components of the provision for income tax expense (benefit) are as follows: (In millions) 2015 Deferred income tax expense (benefit): Federal $ 3 State (1 ) Total deferred 2 Provision for income tax $ 2 A reconciliation of the provision for income tax and the amount computed by applying the federal statutory rate of 35 percent to the income before income taxes for the year ended December 31, 2015 is as follows: (In millions) MarkWest Hydrocarbon Partnership Eliminations Consolidated Income before provision for income tax $ 9 $ 149 $ 1 $ 159 Federal statutory rate 35 % — % — % Federal income tax at statutory rate (1) 3 — — 3 State income taxes net of federal benefit - MarkWest Hydrocarbon — (1 ) — (1 ) Provision on income from Class A units (1) 1 — — 1 Other (1 ) — — (1 ) Provision for income tax $ 3 $ (1 ) $ — $ 2 (1) MarkWest Hydrocarbon pays tax on its share of the Partnership’s income or loss as a result of its ownership of Class A units. Deferred tax assets and liabilities consist of the following: December 31, (In millions) 2015 2014 Deferred tax assets: Derivatives $ 9 $ — Net operating loss carryforwards 62 — Total deferred tax assets 71 — Deferred tax liabilities Property, plant and equipment 6 — Investments in subsidiaries and affiliates 442 — Total deferred tax liabilities 448 — Net deferred tax liabilities (1) $ 377 $ — (1) See Note 3 for discussion regarding a recently adopted accounting standard related to deferred tax assets and liabilities. At December 31, 2015 , MarkWest Hydrocarbon had tax-effected federal operating loss carryforwards of $58 million , which expire in 2033 through 2035 and tax-effected state operating loss carryforwards of $4 million , which expire in 2017 through 2035 . Significant judgment is required in evaluating tax positions and determining the Partnership and MarkWest Hydrocarbon’s provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. However, the Partnership and MarkWest Hydrocarbon did not have any material uncertain tax positions for the years ended December 31, 2015 , 2014 or 2013 . Any interest and penalties related to income taxes were recorded as a part of the provision for income taxes. Such interest and penalties were a net expense of less than $1 million in 2015 , and a net benefit of less than $1 million in 2014 and 2013 . As of December 31, 2015 and 2014 , less than $1 million of interest and penalties were accrued related to income taxes. In addition, the Partnership and MarkWest Hydrocarbon have federal and state tax years 2011 through 2014 open to examination.

Inventories

Inventories	12 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Inventories [Text Block]	Inventories Inventories consist of the following: December 31, (In millions) 2015 2014 NGLs $ 3 $ — Line fill 5 — Spare parts, materials and supplies 41 12 Total inventories $ 49 $ 12

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 Property, plant and equipment consist of the following: Estimated Useful Lives December 31, (In millions) 2015 2014 Natural gas gathering and NGL transportation pipelines and facilities 15 - 30 years $ 4,307 $ — Processing, fractionation and storage facilities 24 - 37 years 3,185 166 Pipelines and related assets 19 - 42 years 1,128 1,081 Land, building, office equipment and other 5 - 25 years 559 29 Construction in progress 939 85 Total 10,118 1,361 Less accumulated depreciation 435 353 Property, plant and equipment, net $ 9,683 $ 1,008 Property, plant and equipment includes gross assets acquired under capital leases of approximately $25 million at December 31, 2015 and 2014 , with related amounts in accumulated depreciation of approximately $7 million at December 31, 2015 and 2014 .

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 Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions as discussed in Note 15 . As part of the MarkWest Merger, the MarkWest opening balance sheet was valued at fair value (see Note 4 ). Money market funds are measured at fair value and are included in Level 1 measurements of the valuation hierarchy. The derivative contracts are measured at fair value on a recurring basis and classified within Level 2 and Level 3 of the valuation hierarchy. The Level 2 and Level 3 measurements are obtained using a market approach. LIBOR rates are an observable input for the measurement of all derivative contracts. The measurements for all 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. Level 2 instruments include crude oil and natural gas swap contracts. MPLX settled natural gas swaps during the year ended December 31, 2015; however, no such instruments were outstanding as of December 31, 2015. The valuations are based on the appropriate commodity prices and contain no significant unobservable inputs. Level 3 instruments include all NGL transactions and embedded derivatives in commodity contracts. The significant unobservable inputs for NGL transactions and embedded derivatives in commodity contracts include NGL prices interpolated and extrapolated due to inactive markets, electricity price curves, and probability of renewal. The following table presents the financial instruments carried at fair value as of December 31, 2015 classified by the valuation hierarchy. (In millions) Assets Liabilities Significant other observable inputs (Level 2) Commodity contracts $ 2 $ — Significant unobservable inputs (Level 3) Commodity contracts 7 — Embedded derivatives in commodity contracts — (32 ) Total carrying value in Consolidated Balance Sheets $ 9 $ (32 ) The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments as of December 31, 2015 . The market approach is used for valuation of all instruments. Level 3 Instrument Balance Sheet Classification Unobservable Inputs Value Range Time Period Commodity contracts Assets Forward ethane prices (per gallon) $0.16 - $0.19 Jan. 2016 - Dec. 2016 Forward propane prices (per gallon) $0.39 - $0.44 Jan. 2016 - Dec. 2016 Forward isobutane prices (per gallon) $0.54 - $0.57 Jan. 2016 - Mar. 2016 Forward normal butane prices (per gallon) $0.51 - $0.57 Jan. 2016 - Mar. 2016 Forward natural gasoline prices (per gallon) $0.89 - $0.93 Jan. 2016 - Dec. 2016 Embedded derivatives in commodity contracts Liabilities Forward propane prices (per gallon) (1) $0.39 - $0.49 Jan. 2016 - Dec. 2022 Forward isobutane prices (per gallon) (1) $0.53 - $0.64 Jan. 2016 - Dec. 2022 Forward normal butane prices (per gallon) (1) $0.48 - $0.60 Jan. 2016 - Dec. 2022 Forward natural gasoline prices (per gallon) (1) $0.89 - $1.04 Jan. 2016 - Dec. 2022 Forward natural gas prices (per MMBtu) (2) $2.18 - $3.39 Jan. 2016 - Dec. 2022 ERCOT Pricing (per MegaWatt Hour) $23.08 - $44.58 Jan. 2016 - Dec. 2016 Probability of renewal (3) 50.0% (1) NGL prices used in the valuation are generally at the lower end of the range in the early years and increase over time. (2) Natural gas prices used in the valuations are generally at the lower end of the range in the early years and increase over time. (3) The producer counterparty to the embedded derivative has the option to renew the gas purchase agreement and the related keep-whole processing agreement for two successive five -year terms after 2022. The embedded gas purchase agreement cannot be renewed without the renewal of the related keep-whole processing agreement. Due to the significant number of years until the renewal options are exercisable and the high level of uncertainty regarding the counterparty’s future business strategy, the future commodity price environment, and the future competitive environment for midstream services in the Southern Appalachian region, management determined that a 50 percent probability of renewal for the first five-year term and 75 percent for the second five-year term are appropriate assumptions. Included in this assumption is a further extension of management’s estimates of future frac spreads through 2032. Fair Value Sensitivity Related to Unobservable Inputs Commodity contracts (assets and liabilities) - For the Partnership’s commodity 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. Embedded derivative in commodity contracts - The Natural Gas Embedded Derivative liability is a single embedded derivative comprised of both the purchase of natural gas at prices impacted by the frac spread and the probability of contract renewal as discussed further in Note 15. Increases (decreases) in forward NGL prices result in an increase (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. Level 3 Valuation Process The Partnership’s Risk Management Department (the “Risk Department”) is responsible for the valuation of the Partnership’s commodity derivative contracts and embedded derivatives in commodity contracts, except for the Natural Gas Embedded Derivative. The Risk Department reports to the Chief Financial Officer and is responsible for the oversight of the Partnership’s commodity risk management program. The members of the Risk Department have the requisite experience, knowledge and day-to-day involvement in the energy commodity markets to ensure appropriate valuations and understand the changes in the valuations from period to period. The valuations of the Level 3 commodity derivative contracts are performed by a third-party pricing service and reviewed and validated on a quarterly basis by the Risk Department by comparing the pricing and option volatilities to actual market data and/or data provided by at least one other independent third-party pricing service. Management is responsible for the valuation of the Natural Gas Embedded Derivative discussed in Note 15. Included in the valuation of the Natural Gas Embedded Derivative are assumptions about the forward price curves for NGLs and natural gas for periods in which price curves and not available from third-party pricing services due to insufficient market data. The Risk Department must develop forward price curves for NGLs and natural gas through the initial contract term (January 2016 through December 2022) for management’s use in determining the fair value of the Natural Gas Embedded Derivative. In developing the pricing curves for these periods, the Risk Department maximizes its use of the latest known market data and trends as well as its understanding of the historical relationships between forward NGL and natural gas prices and the forward market data that is available for the required period, such as crude oil pricing and natural gas pricing from other markets. However, there is very limited actual market data available to validate the Risk Department’s estimated price curves. Management also assesses the probability of the producer customer’s renewal of the contracts, which includes consideration of: • The estimated favorability of the contracts to the producer customer as compared to other options that would be available to them at the time and in the relative geographic area of their producing assets • Extrapolated pricing curves, using a weighted average probability method that is based on historical frac spreads, which impact the calculation of favorability • The producer customer’s potential business strategy decision points that may exist at the time the counterparty would elect whether to renew the contracts Changes in Level 3 Fair Value Measurements The tables below include a roll forward of the balance sheet amounts for the years ended December 31, 2015 (including the change in fair value) for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy. 2015 (In millions) Commodity Derivative Contracts (net) Embedded Derivatives in Commodity Contracts (net) Fair value at beginning of period $ — $ — Net positions assumed in conjunction with the MarkWest Merger 7 (38 ) Total gain (realized and unrealized) included in earnings (1) 3 5 Settlements (3 ) 1 Fair value at end of period $ 7 $ (32 ) The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at end of period $ 2 $ 5 (1) Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in Product sales in the accompanying Consolidated Statements of Income. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in Costs of revenue and Purchased product costs . Fair Values – Reported The Partnership’s primary financial instruments are cash and cash equivalents, receivables, receivables from related parties, accounts payable, payables to related parties, and long-term debt. The Partnership’s fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) MPC’s investment-grade credit rating and (3) its historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk. The Partnership believes the carrying values of its current assets and liabilities approximate fair value. The recorded value of the amounts outstanding under the Credit Facility, if any, approximate fair value due to the variable interest rate that approximates current market rates. Derivative instruments are recorded at fair value, based on available market information (see Note 15 ). The SMR liability and $4.1 billion aggregate principal of the Partnership’s long-term debt were recorded at fair value in connection with the MarkWest Merger as of December 4, 2015, which established a new cost basis for each of those liabilities. The fair value of the long-term debt is estimated based on recent market non-binding indicative quotes. The fair value of the SMR liability is estimated using a discounted cash flow approach based on the contractual cash flows and the Partnership’s unsecured borrowing rate. The long-term debt fair values are considered Level 3 measurements and SMR liability fair values are considered Level 2 measurements. The following table summarizes the fair value and carrying value of the Partnership’s long-term debt, excluding capital leases, and SMR liability. December 31, 2015 2014 (In millions) Fair Value Carrying Value Fair Value Carrying Value Long-term debt $ 5,212 $ 5,255 $ 636 $ 635 SMR liability $ 99 $ 100 $ — $ —

Derivative Financial Instrument

Derivative Financial Instruments	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging Activities Disclosure [Text Block]	Derivative Financial Instruments Commodity Derivatives NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond the Partnership’s control. The Partnership’s profitability is directly affected by prevailing commodity prices primarily as a result of processing or conditioning at its own or third-party processing plants, purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and the cost of third-party transportation and fractionation services. To the extent that commodity prices influence the level of natural gas drilling by the Partnership’s producer customers, such prices also affect profitability. To protect itself financially against adverse price movements and to maintain more stable and predictable cash flows so that the Partnership can meet its cash distribution objectives, debt service and capital plans, the Partnership executes a strategy governed by its risk management policy. The Partnership has a committee comprised of senior management that oversees risk management activities, continually monitors the risk management program and adjusts its strategy as conditions warrant. The Partnership enters into certain derivative contracts to reduce the risks associated with unfavorable changes in the prices of natural gas, NGLs and crude oil. Derivative contracts utilized are swaps and options traded on the OTC market and fixed price forward contracts. The risk management policy does not allow the Partnership to take speculative positions with its derivative contracts. To mitigate its cash flow exposure to fluctuations in the price of NGLs, the Partnership has entered into derivative financial instruments relating to the future price of NGLs and crude oil. The Partnership currently manages the majority of its NGL price risk using direct product NGL derivative contracts. The Partnership enters into NGL derivative contracts when adequate market liquidity exists and future prices are satisfactory. A portion of the Partnership’s NGL price exposure is managed by using crude oil contracts. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, the crude oil contracts create increased risk and additional gains or losses. The Partnership may settle its crude oil contracts prior to the contractual settlement date in order to take advantage of favorable terms and reduce the future exposure resulting from the less effective crude oil contracts. Based on its current volume forecasts, the majority of its derivative positions used to manage the future commodity price exposure are expected to be direct product NGL derivative contracts. To mitigate its cash flow exposure to fluctuations in the price of natural gas, the Partnership primarily utilizes derivative financial instruments relating to the future price of natural gas and takes into account the partial offset of its long and short gas positions resulting from normal operating activities. The Partnership has no such positions outstanding as of December 31, 2015 . As a result of its current derivative positions, the Partnership has mitigated a portion of its expected commodity price risk through the fourth quarter of 2016. The Partnership would be exposed to additional commodity risk in certain situations such as if producers under deliver or over deliver product or when processing facilities are operated in different recovery modes. In the event the Partnership has derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated. Management conducts a standard credit review on counterparties to derivative contracts, and has provided the counterparties with a guaranty as credit support for its obligations. A separate agreement with certain counterparties allows MarkWest Liberty Midstream to enter into derivative positions without posting cash collateral. The Partnership uses standardized agreements that allow for offset of certain positive and negative exposures (“master netting arrangements”) in the event of default or other terminating events, including bankruptcy. The Partnership records derivative contracts at fair value in the Consolidated Balance Sheets and has not elected hedge accounting or the normal purchases and normal sales designation (except for electricity contracts, for which the normal purchases and normal sales designation has been elected). The Partnership’s accounting may cause volatility in the Consolidated Statements of Income as the Partnership recognizes in current earnings all unrealized gains and losses from the changes in fair value of derivatives. Volume of Commodity Derivative Activity As of December 31, 2015 , the Partnership had the following outstanding commodity contracts that were executed to manage the cash flow risk associated with future sales of NGLs: Derivative contracts not designated as hedging instruments Financial Position Notional Quantity (net) Crude Oil (bbl) Short 109,800 NGLs (gal) Short 43,837,756 Embedded Derivatives in Commodity Contracts The Partnership has a commodity contract with a producer customer in the Southern Appalachian region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. For accounting purposes, these contracts have been aggregated into a single contract and are evaluated together. In February 2011, the Partnership executed agreements with the producer customer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022, with the producer customer’s option to extend the agreement for two successive five year terms through December 31, 2032. The purchase of gas at prices based on the frac spread and the option to extend the agreements have been identified as a single embedded derivative, which is recorded at fair value. The probability of renewal is determined based on extrapolated pricing curves, a review of the overall expected favorability of the contracts based on such pricing curves, and assumptions about the counterparty’s potential business strategy decision points that may exist at the time the counterparty would elect whether to renew the contract. The changes in fair value of this embedded derivative are based on the difference between the contractual and index pricing, the probability of the producer customer exercising its option to extend and the estimated favorability of these contracts compared to current market conditions. The changes in fair value are recorded in earnings through Purchased product costs in the Consolidated Statements of Income. As of December 31, 2015, the estimated fair value of this contract was a liability of $31 million . The Partnership has a commodity contract that gives it an option to fix a component of the utilities cost to an index price on electricity at its plant location in the Southwest operations through the fourth quarter of 2017. The contract is currently fixed through the fourth quarter of 2016 with the ability to fix the commodity contract for its remaining year. Changes in the fair value of the derivative component of this contract were recognized as Cost of revenues in the Consolidated Statements of Income. As of December 31, 2015 , the estimated fair value of this contract was a liability of $1 million . Financial Statement Impact of Derivative Contracts Certain derivative positions are subject to master netting agreements, therefore the Partnership has elected to offset derivative assets and liabilities that are legally permissible to be offset. As of December 31, 2015 , there were no derivative assets or liabilities that were offset in the Consolidated Balance Sheets. The impact of the Partnership’s derivative instruments on its Consolidated Balance Sheets is summarized below: (In millions) December 31, 2015 Derivative contracts not designated as hedging instruments and their balance sheet location Asset Liability Commodity contracts (1) Other current assets / other current liabilities $ 9 $ (5 ) Other noncurrent assets / deferred credits and other liabilities — (27 ) Total $ 9 $ (32 ) (1) Includes embedded derivatives in commodity contracts as discussed above. In the table above, the Partnership does not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although the Partnership’s master netting arrangements would allow current and non-current positions to be offset in the event of default. Additionally, in the event of a default, the Partnership’s master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions and other forms of non-cash collateral (such as letters of credit). The impact of the Partnership’s derivative contracts not designated as hedging instruments and the location of gain or (loss) recognized in the Consolidated Statements of Income is summarized below: December 31, (In millions) 2015 Product sales Realized gain 4 Unrealized loss (1 ) Total revenue: derivative gain from product sales 3 Purchased product costs Unrealized gain 5 Total gain 8

Debt

Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt	Debt The Partnership’s outstanding borrowings at December 31, 2015 and 2014 consisted of the following: December 31, (In millions) 2015 2014 MPLX LP: Bank revolving credit facility due 2020 $ 877 $ 385 Term loan facility due 2019 250 250 5.500% senior notes due 2023 710 — 4.500% senior notes due 2023 989 — 4.875% senior notes due 2024 1,149 — 4.000% senior notes due 2025 500 — 4.875% senior notes due 2025 1,189 — Consolidated subsidiaries: MarkWest - 5.500% senior notes due 2023 40 — MarkWest - 4.500% senior notes due 2023 11 — MarkWest - 4.875% senior notes due 2024 1 — MarkWest - 4.875% senior notes due 2025 11 — MPL - capital lease obligations due 2020 9 10 Total 5,736 645 Unamortized debt issuance costs (1) (8 ) — Unamortized discount (2) (472 ) — Amounts due within one year (1 ) (1 ) Total long-term debt due after one year $ 5,255 $ 644 (1) The Partnership adopted the updated FASB debt issuance cost standard as of June 30, 2015. This has been applied retrospectively and there was no effect to the prior period presented. (2) 2015 includes $465 million discount related to the difference between the fair value and the principal amount of the assumed MarkWest debt. The following table shows five years of scheduled debt payments. (In millions) 2016 $ 1 2017 1 2018 1 2019 1 2020 1,132 Credit Agreements On November 20, 2014 , MPLX entered into a credit agreement with a syndicate of lenders (“MPLX Credit Agreement”) which provides for a five -year, $1 billion bank revolving credit facility and a $250 million term loan facility. In connection with the closing of the MarkWest Merger, we entered into an amendment to our MPLX Credit Agreement to, among other things, increase the aggregate amount of revolving credit capacity under the credit agreement by $1 billion for total aggregate commitments of $2 billion and to extend the maturity for the bank revolving credit facility to December 4, 2020 . The term loan facility was not amended and matures on November 20, 2019 . Also in connection with the closing of the MarkWest Merger, MarkWest’s bank revolving 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 of cash. The bank revolving credit facility includes a letter of credit issuing capacity of up to $250 million and swingline capacity of up to $100 million . The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional $500 million , subject to certain conditions, including the consent of lenders whose commitments would increase. In addition, the maturity date may be extended from time-to-time during its term to a date that is one year after the then-effective maturity subject to the approval of lenders holding the majority of the commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the then-effective maturity date. The term loan facility was drawn in full on November 20, 2014. The maturity date for the term loan facility may be extended for up to two additional one -year periods subject to the consent of the lenders holding a majority of the outstanding term loan borrowings, provided that the portion of the term loan borrowings held by any non-consenting lenders will continue to be due and payable on the then-effective maturity date. The borrowings under this facility during 2015 were at an average interest rate of 1.670 percent . Borrowings under the MPLX Credit Agreement bear interest at either the Adjusted LIBOR or the Alternate Base Rate (as defined in the MPLX Credit Agreement), at our election, plus a specified margin . The Partnership is charged various fees and expenses in connection with the agreement, including administrative agent fees, commitment fees on the unused portion of the bank revolving credit facility and fees with respect to issued and outstanding letters of credit. The applicable margins to the benchmark interest rates and certain fees fluctuate based on the credit ratings in effect from time to time on the Partnership’s long-term debt. The MPLX Credit Agreement includes certain representations and warranties, affirmative and restrictive covenants and events of default that the Partnership considers to be usual and customary for an agreement of this type. This agreement includes a financial covenant that requires the Partnership to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA (both as defined in the MPLX Credit Agreement) for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 for up to two fiscal quarters following certain acquisitions.) Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period. Other covenants restrict the Partnership and certain of its subsidiaries from incurring debt, creating liens on its assets and entering into transactions with affiliates. As of December 31, 2015 , the Partnership was in compliance with the covenants contained in the MPLX Credit Agreement. In connection with entering into the above mentioned MPLX Credit Agreement in 2014, the Partnership terminated its previously existing $500 million five -year MPLX Operations bank revolving credit agreement, dated as of September 14, 2012 . During 2014, we borrowed $280 million under this agreement, at an average interest rate of 1.535 percent , per annum, and repaid all of these borrowings. During 2015 , the Partnership borrowed $992 million under the new bank revolving credit facility, at an average interest rate of 1.617 percent , per annum, and repaid $500 million of these borrowings. At December 31, 2015 , the Partnership had $877 million of borrowings and $8 million letters of credit outstanding under this facility, resulting in total unused loan availability of $1.12 billion , or 55.8 percent of the borrowing capacity. Senior Notes In connection with the MarkWest Merger, MPLX LP 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 in an exchange offer and consent solicitation undertaken by MPLX and MarkWest, leaving approximately $63 million aggregate principal of outstanding senior notes held by MarkWest. The new MPLX senior notes consist of (i) approximately $710 million aggregate principal amount of 5.500 percent senior notes due February 15, 2023 , (ii) approximately $989 million aggregate principal amount of 4.500 percent senior notes due July 15, 2023 , (iii) approximately $1.15 billion aggregate principal amount of 4.875 percent senior notes due December 1, 2024 and (iv) approximately $1.19 billion aggregate principal amount of 4.875 percent senior notes due June 1, 2025 . Interest on each series of MPLX senior notes is payable semi-annually in arrears according to the table below. Senior Notes Interest payable semi-annually in arrears 5.500% senior notes due 2023 February 15 th and August 15 th 4.500% senior notes due 2023 January 15 th and July 15 th 4.875% senior notes due 2024 June 1 st and December 1 st 4.000% senior notes due 2025 February 15 th and August 15 th 4.875% senior notes due 2025 June 1 st and December 1 st After giving effect to the exchange offer and consent solicitation referred to above, as of December 31, 2015, MarkWest had outstanding (i) approximately $40 million aggregate principal amount of 5.500 percent senior notes due February 15, 2023 , (ii) approximately $11 million aggregate principal amount of 4.500 percent senior notes due July 15, 2023 , (iii) approximately $1 million aggregate principal amount of 4.875 percent senior notes due December 1, 2024 and (iv) approximately $11 million aggregate principal amount of 4.875 percent senior notes due June 1, 2025 . Interest on each series of the MarkWest senior notes is payable semi-annually in arrears consistent with the table above. On February 12, 2015, the Partnership completed a public offering of $500 million aggregate principal amount of four percent unsecured senior notes due February 15, 2025 (the “Feb 2025 Notes”). The net proceeds from the offering of the Feb 2025 Notes were approximately $495 million , after deducting underwriting discounts. The net proceeds were used to repay the amounts outstanding under its bank revolving credit facility, as well as for general partnership purposes. Interest is payable semi-annually in arrears commencing on August 15, 2015. SMR Transaction On September 1, 2009, MarkWest completed the SMR Transaction. At that time, MarkWest had begun constructing the SMR at its Javelina gas processing and fractionation complex in Corpus Christi, Texas. Under the terms of the agreement, MarkWest received proceeds of $73 million and the purchaser completed the construction of the SMR. MarkWest and the purchaser also executed a related product supply agreement under which the Partnership will receive the entire product produced by the SMR through 2030 in exchange for processing fees and the reimbursement of certain other expenses. The processing fee payments began when the SMR commenced operations in March 2010. MarkWest was deemed to have continuing involvement with the SMR as a result of certain provisions in the related agreements. Therefore, the transaction is treated as a financing arrangement under GAAP. The Partnership imputes interest on the SMR liability at 6.39 percent annually, its incremental borrowing rate at the time of the purchase accounting valuation. Each processing fee payment has multiple elements: reduction of principal of the SMR liability, interest expense associated with the SMR liability and facility expense related to the operation of the SMR. As part of purchase accounting, the SMR transaction has been recorded at fair value. As of December 31, 2015, the following amounts related to the SMR are included in the accompanying Consolidated Balance Sheets: (In millions) December 31, 2015 Assets Property, plant and equipment, net of accumulated depreciation $ 69 Liabilities Accrued liabilities 4 Deferred credits and other liabilities 96

Goodwill and Intangibles

Goodwill and Intangibles	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets Disclosure [Text Block]	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 has been reduced below carrying value. The Partnership has performed its annual impairment tests, and no impairment in the carrying value of goodwill has been identified during the periods presented. In February of 2016, the Partnership’s units were trading at a price per unit 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 the G&P segment. The significant assumptions that were used to develop the estimates of the fair values recorded in acquisition accounting and the resulting goodwill assigned to the reporting units are discussed in Note 4. If negative events related to those assumptions occur or if the market price of the units continues to trade at a low level in 2016, the Partnership 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 the goodwill was assigned in connection with the MarkWest Merger is less than their carrying value and, if so, evaluate goodwill for impairment. There were no changes in the carrying amount of goodwill for 2014. The changes in carrying amount of goodwill for 2015 were as follows: (In millions) L&S G&P Total Beginning balance $ 105 $ — $ 105 Acquisitions (1) — 2,454 2,454 Ending balance $ 105 $ 2,454 $ 2,559 (1) On December 4, 2015 , the Partnership completed the MarkWest Merger, see Note 4 for more information. Intangible Assets There were no intangible assets as of December 31, 2014. The Partnership’s intangible assets as of December 31, 2015 are comprised of customer contracts and relationships, as follows: (In millions) Gross Accumulated Amortization Net Useful Life L&S $ — $ — $ — N/A G&P 468 (2 ) 466 11-25 years $ 468 $ (2 ) $ 466 Estimated future amortization expense related to the intangible assets at December 31, 2015 is as follows: (In millions) 2016 32 2017 32 2018 32 2019 32 2020 32 Thereafter 306 Total $ 466

Supplemental Cash Flow Informat

Supplemental Cash Flow Information	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [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) $ 13 $ 3 $ — Non-cash investing and financing activities: Net transfers of property, plant and equipment to inventories $ 5 $ 1 $ 4 Contribution - common units issued — 200 — Acquisition: Fair value of MPLX units issued (1) 7,326 — — Payable to seller 50 — — (1) See Note 4 . The Consolidated Statements of Cash Flows exclude changes to the Consolidated Balance Sheets that did not affect cash. The following is the change of additions to property, plant and equipment related to capital accruals: (In millions) 2015 2014 2013 Increase (decrease) in capital accruals $ 25 $ 12 $ (5 )

Equity-Based Compensation Plan

Equity-Based Compensation Plan	12 Months Ended
	Dec. 31, 2015
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Equity-Based Compensation Plan	Compensation Plan Description of the Plan The MPLX LP 2012 Incentive Compensation Plan (“MPLX 2012 Plan”) authorizes the MPLX GP board of directors (the “Board”) to grant unit options, unit appreciation rights, restricted units and phantom units, distribution equivalent rights, unit awards, profits interest units, performance units and other unit-based awards to the Partnership’s or any of its affiliates’ employees, officers and directors, including directors and officers of MPC. No more than 2.75 million MPLX LP common limited partner units may be delivered under the MPLX 2012 Plan. Units delivered pursuant to an award granted under the MPLX 2012 Plan may be funded through acquisition on the open market, from the partnership or from an affiliate of the partnership, as determined by the Board. Unit-based awards under the Plan The Partnership expenses all unit-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. Phantom Units – The Partnership grants phantom units under the MPLX 2012 Plan to non-employee directors of MPLX LP’s general partner and of MPC. Awards to non-employee directors are accounted for as non-employee awards. Phantom units granted to non-employee directors vest immediately at the time of the grant, as they are non-forfeitable, but are not issued until the director’s departure from the board of directors. Prior to issuance, non-employee directors do not have the right to vote such units and cash distribution equivalents accrue in the form of additional phantom units and will be issued when the director departs from the board of directors. The Partnership grants phantom units under the MPLX 2012 Plan to certain officers and non-officers of MPLX LP, MPLX LP’s general partner and MPC who make significant contributions to our business. These grants are accounted for as employee awards. In general, these phantom units will vest over a requisite service period of up to three years . Prior to vesting, these phantom unit recipients will not have the right to vote such units and cash distributions declared will be accrued and paid upon vesting. The accrued distributions at December 31, 2015 were less than $1 million . The fair values of phantom units are based on the fair value of MPLX LP common limited partner units on the grant date. Performance Units - The Partnership grants performance units under the MPLX 2012 Plan to certain officers of MPLX LP’s general partner and certain eligible MPC officers who make significant contributions to its business. These awards are intended to have a per unit payout determined by the total unitholder return of MPLX LP common units as compared to the total unitholder return of a selected group of peer partnerships. The final per-unit payout will be the average of the results of four measurement periods during the 36 month requisite service period. These performance units will pay out 75 percent in cash and 25 percent in MPLX LP common units. 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 paying out in units are accounted for as equity awards and have a weighted average grant date fair value of $1.03 per unit for 2015 and $1.16 per unit for 2014 , as calculated using a Monte Carlo valuation model. Outstanding Phantom Unit Awards The following is a summary of phantom unit award activity of MPLX LP common limited partner units in 2015 : Phantom Units Number of Units Weighted Average Fair Value Aggregate Intrinsic Value (In millions) Outstanding at December 31, 2014 100,769 $ 41.66 Granted 962,764 35.00 Settled (32,314 ) 40.18 Forfeited — Outstanding at December 31, 2015 1,031,219 35.49 Vested and expected to vest at December 31, 2015 1,001,324 35.52 $ 39.40 Convertible at December 31, 2015 472,665 34.26 $ 18.60 The 472,665 convertible units are held by our non-employee directors and certain officers. These units are non-forfeitable and issuable upon the director’s departure from our board of directors or the officer’s end of employment. The following is a summary of the values related to phantom units held by officers and non-employee directors: Phantom Units Intrinsic Value of Units Issued During the Period (in millions) Weighted Average Grant Date Fair Value of Units Granted During the Period 2015 $ 3 $ 35.00 2014 1 49.56 2013 — — As of December 31, 2015 , unrecognized compensation cost related to phantom unit awards was $19 million , which is expected to be recognized over a weighted average period of 2.8 years . Outstanding Performance Unit Awards The following is a summary of activity of performance unit awards paying out in MPLX LP common limited partner units in 2015 : Performance Units Number of Units Weighted Outstanding at December 31, 2014 924,143 $ 0.98 Granted 597,249 1.03 Forfeited — — Outstanding at December 31, 2015 1,521,392 1.00 As of December 31, 2015 , unrecognized compensation cost related to equity-classified performance unit awards was $1 million , which is expected to be recognized over a weighted average period of 1.7 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 the weighted average inputs used for 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 30.12 % 17.17 % 16.75 % Grant date fair value of performance units granted $ 1.03 $ 1.16 $ 0.77 The assumption for expected volatility of our unit price reflects the historical volatility of MPLX common units. The look-back period reflects the remaining performance period at the grant date. 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. Total Unit-Based Compensation Expense Total unit-based compensation expense for awards settling in MPLX LP common units was $4 million in 2015 , $3 million in 2014 and $1 million in 2013 . Approximately $15 million was charged to the MarkWest purchase price in 2015 for MPLX unit-based compensation awards granted in connection with the MarkWest Merger. MPC’s Stock-based Compensation Stock-based compensation expenses charged to MPLX under our employee services agreement with MPC were $1 million for 2015 , 2014 and 2013 .

Lease Operations

Lease Operations	12 Months Ended
	Dec. 31, 2015
Leases [Abstract]
Leases	Lease Operations Based on the terms of certain natural gas gathering, transportation and processing agreements, the Partnership is considered to be the lessor under several implicit operating lease arrangements in accordance with GAAP. The Partnership’s primary implicit lease operations relate to a natural gas gathering agreement in the Marcellus shale 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 2023 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 shale and a natural gas processing agreement in the Southern Appalachia region for which the Partnership earns 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 2030 and 2023. The Partnership’s revenue from its implicit lease arrangements, excluding executory costs, totaled approximately $16 million in 2015 . There was no revenue from these implicit lease arrangements in 2014 and 2013 . The Partnership’s implicit lease arrangements related to the processing facilities contain contingent rental provisions whereby the Partnership receives additional fees if the producer customer exceeds the monthly minimum processed volumes. During the year ended December 31, 2015 , the Partnership received less than $1 million in contingent lease payments. No contingent lease payments were received for the year ended December 31, 2014 . The following is a schedule of minimum future rentals on the non-cancellable operating leases as of December 31, 2015 : (In millions) 2016 $ 174 2017 184 2018 185 2019 186 2020 185 2021 and thereafter 588 Total minimum future rentals $ 1,502 The following schedule summarizes the Partnership’s 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 As of December 31, 2014 , we had no investment in assets held for operating lease.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation Disclosure [Text Block]	Asset Retirement Obligations The Partnership’s assets subject to AROs are primarily certain gas-gathering pipelines and processing facilities, a crude oil pipeline and other related pipeline assets. The Partnership also has land leases that require the Partnership to return the land to its original condition upon termination of the lease. The Partnership reviews current laws and regulations governing obligations for asset retirements and leases, as well as the Partnership’s leases and other agreements. The following is a reconciliation of the changes in the ARO from January 1, 2015 to December 31, 2015 : December 31, (In millions) 2015 Beginning ARO $ — Liabilities assumed in conjunction with the MarkWest Merger 15 Liabilities incurred 2 Ending ARO $ 17 At December 31, 2015 , there were no assets legally restricted for purposes of settling AROs. The AROs have been recorded as part of Deferred credits and other liabilities in the accompanying Consolidated Balance Sheets. In addition to recorded AROs, the Partnership has other AROs related to certain gathering, processing and other assets as a result of environmental and other legal requirements. The Partnership is not required to perform such work until it permanently ceases operations of the respective assets. Because the Partnership considers the operational life of these assets to be indeterminable, an associated ARO cannot be calculated and is not recorded.

Commitments and Contingencies

Commitments and Contingencies	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingencies	Commitments and Contingencies The Partnership is 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 the Partnership has not recorded an accrued liability, the Partnership is unable to estimate a range of possible losses for the reasons discussed in more detail below. However, the ultimate resolution of some of these contingencies could, individually or in the aggregate, be material. Environmental Matters – The Partnership is subject to federal, state and local 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. Penalties may be imposed for non-compliance. At December 31, 2015 and 2014 , accrued liabilities for remediation totaled $1 million . However, 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. There were $1 million in receivables from MPC for indemnification of environmental costs related to incidents occurring prior to the Initial Offering at December 31, 2015 . There were no receivables from MPC for indemnification at December 31, 2014 . On July 6, 2015, officials from the EPA and the United States Department of Justice entered a MarkWest Liberty Midstream pipeline launcher/receiver site utilized for pipeline maintenance operations in Washington County, Pennsylvania 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, and any permit related 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 MarkWest Liberty Midstream’s operations have been conducted in a manner fully protective of its employees and the public, and that other than potentially having to obtain minor source Clean Air Act permits at a relatively small number of individual sites, MarkWest Liberty has operated 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 results of operations, financial position or cash flows. The amount of any potential assessments, penalties, fines, restrictions, requirements, modifications, costs or expenses that may be incurred in connection with any potential enforcement action cannot be reasonably estimated at this time. We are involved in a number of other 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 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 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. Other Lawsuits – In 2003, the State of Illinois brought an action against the Premcor Refining Group, Inc. (“Premcor”) and Apex Refining Company (“Apex”) asserting claims for environmental cleanup related to the refinery owned by these entities in the Hartford/Wood River, Illinois area. In 2006, Premcor and Apex filed third-party complaints against numerous owners and operators of petroleum products facilities in the Hartford/Wood River, Illinois area, including MPL. These complaints, which have been amended since filing, assert claims of common law nuisance and contribution under the Illinois Contribution Act and other laws for environmental cleanup costs that may be imposed on Premcor and Apex by the State of Illinois. There are several third-party defendants in the litigation and MPL has asserted cross-claims in contribution against the various third-party defendants. This litigation is currently pending in the Third Judicial Circuit Court, Madison County, Illinois. While the ultimate outcome of these litigated matters remains uncertain, neither the likelihood of an unfavorable outcome nor the ultimate liability, if any, with respect to this matter can be determined at this time and the Partnership is unable to estimate a reasonably possible loss (or range of loss) for this litigation. Under the omnibus agreement, MPC will indemnify the Partnership for the full cost of any losses should MPL be deemed responsible for any damages in this lawsuit. The Partnership is 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, the Partnership believes the resolution of these other lawsuits and proceedings will not have a material adverse effect on its consolidated financial position, results of operations or cash flows. Guarantees – Over the years, the Partnership has sold various assets in the normal course of its 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 the Partnership to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling assets. The Partnership is 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 the Partnership’s contractual commitments to acquire property, plant and equipment totaled $144 million . Our contractual commitments at December 31, 2015 were primarily related to plant expansion projects for the Marcellus and Southwest operations and the Cornerstone Pipeline project. Certain natural gas processing and gathering arrangements require the Partnership 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 the Partnership 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. Lease and Other Contractual Obligations – The Partnership executed transportation and terminalling agreements that obligate us to minimum volume, throughput or payment commitments over the terms of the agreements, which range from three to ten years. After the minimum volume commitments are met in the transportation and terminalling agreements, the Partnership pays additional amounts based on throughput. There are escalation clauses in the transportation and terminalling agreements, which are based on CPI adjustments. The minimum future payments under these agreements as of December 31, 2015 are as follows: (In millions) 2016 $ 68 2017 74 2018 60 2019 59 2020 59 2021 and thereafter 299 Total $ 619 The Partnership has various non-cancellable operating lease agreements and a long-term propane storage agreement expiring at various times through fiscal year 2040. Most of these leases include renewal options. The Partnership also leases certain pipelines under a capital lease that has a fixed price purchase option in 2020. Future minimum commitments as of December 31, 2015 , for capital lease obligations and for operating lease obligations having initial or remaining non-cancellable lease terms in excess of one year are as follows: (In millions) Capital Obligations Operating Obligations 2016 $ 1 $ 49 2017 1 49 2018 2 40 2019 2 35 2020 5 30 Later years — 100 Total minimum lease payments 11 $ 303 Less imputed interest costs 2 Present value of net minimum lease payments $ 9 Operating lease rental expense was: (In millions) 2015 2014 2013 Minimum rental expense $ 14 $ 10 $ 10 SMR Transaction – On September 1, 2009, MarkWest entered into a product supply agreement creating a long-term contractual obligation for the payment of processing fees in exchange for the entire product processed by the SMR. The product received under this agreement is sold to a refinery customer pursuant to a corresponding long-term agreement. The minimum amounts payable annually under the product supply agreement, excluding the potential impact of inflation adjustments per the agreement, are as follows: (In millions) 2016 $ 17 2017 17 2018 17 2019 17 2020 17 2021 and thereafter 162 Total minimum payments 247 Less: Services element 95 Less: Interest 52 Total SMR liability 100 Less: Current portion of SMR liability 4 Long-term portion of SMR liability $ 96

Subsequent Event

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

Select Quarterly Financial Data

Select Quarterly Financial Data	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Select Quarterly Financial Data	Select Quarterly Financial Data (Unaudited) 2015 2014 (In millions, except per unit data) 1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr. (1) 1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr. Revenues $ 130 $ 140 $ 141 $ 257 $ 131 $ 126 $ 131 $ 132 Income from operations 51 58 47 50 56 44 44 39 Net income 46 51 42 18 56 42 43 37 Net income attributable to MPLX LP 46 50 42 18 34 28 30 29 Net income attributable to MPLX LP per limited partner unit: Common - basic $ 0.46 $ 0.50 $ 0.41 $ (0.14 ) $ 0.41 $ 0.37 $ 0.37 $ 0.38 Common - diluted 0.46 0.50 0.41 (0.14 ) 0.41 0.37 0.37 0.38 Subordinated - basic and diluted 0.46 0.50 — — 0.41 0.37 0.37 0.33 Distributions declared per limited partner common unit $ 0.4100 $ 0.4400 $ 0.4700 $ 0.5000 $ 0.3275 $ 0.3425 $ 0.3575 $ 0.3825 Distributions declared: Limited partner units - Public $ 10 $ 10 $ 11 $ 120 $ 7 $ 6 $ 7 $ 9 Limited partner units - MPC 23 25 27 29 18 19 19 21 General partner units - MPC 1 1 1 3 — — 1 1 Incentive distribution rights - MPC 3 6 8 37 — 1 1 2 Total distributions declared $ 37 $ 42 $ 47 $ 189 $ 25 $ 26 $ 28 $ 33 (1) These amounts include results from the MarkWest Merger which closed on December 4, 2015. See Note 4 for more information on the MarkWest Merger.

Summary of Principal Accounti32

Summary of Principal Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Consolidation	Basis of Presentation – The Partnership’s consolidated financial statements include all majority-owned and controlled subsidiaries. For non-wholly-owned consolidated subsidiaries, the interests owned by third parties, including MPC, have been recorded as Noncontrolling interest in the accompanying Consolidated Balance Sheets. Intercompany investments, accounts and transactions have been eliminated. The Partnership’s investments in which the Partnership exercises significant influence but does not control and does not have a controlling financial interest, are accounted for using the equity method. The Partnership’s investments in a VIE in which the Partnership exercises significant influence but does not control and is not the primary beneficiary are accounted for using the equity method. The accompanying consolidated financial statements of the Partnership have been prepared in accordance with GAAP.
Use of estimates	Use of Estimates – The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates affect, among other items, valuing identified intangible assets; determining the fair value of derivative instruments; valuing inventory; evaluating impairments of long-lived assets, goodwill and equity investments; establishing estimated useful lives for long-lived assets; acquisition accounting; recognizing share-based compensation expense; estimating revenues, expense accruals and capital expenditures; valuing AROs; and determining liabilities, if any, for environmental and legal contingencies.
Revenue recognition	Revenue Recognition – The Partnership’s assessment of each of the revenue recognition criteria as they relate to its revenue producing activities are as follows: persuasive evidence of an arrangement exists, delivery, the fee is fixed or determinable and collectability is reasonably assured. It is upon delivery or title transfer to the customer that the Partnership meets all four revenue recognition criteria and it is at such time that the Partnership recognizes Product sales . It is upon completion of services provided that the Partnership meets all four criteria and it is at such time that the Partnership recognizes Service revenue . L&S Segment Revenues are recognized in the L&S segment for crude oil and product pipeline transportation based on the delivery of actual volumes transported at regulated tariff rates. When MPC ships volumes on our pipeline systems under a joint tariff with a third party, those revenues are recorded as sales and other operating revenues, and not as sales to related parties, because we receive payment from the third party. Revenues are recognized for crude oil and refined product storage as performed based on contractual rates. Operating fees received for operating pipeline systems are recognized as a component of other income in the period the service is performed. All such amounts are reported as Service revenue on the Consolidated Statements of Income. Under our MPC transportation services agreements, if MPC fails to transport its minimum throughput volumes during any quarter, then MPC will pay us a deficiency payment equal to the volume of the deficiency multiplied by the tariff rate then in effect. MPC may then apply the amount of any such deficiency payments as a credit for volumes transported on the applicable pipeline system in excess of its minimum volume commitment during the following four or eight quarters under the terms of the applicable transportation services agreement. The deficiency payments are initially recorded as Deferred revenue - related parties in the Consolidated Balance Sheets. The Partnership recognizes revenues for the deficiency payments at the earlier of when credits are used for volumes transported in excess of minimum volume commitments, when it becomes impossible to physically transport volumes necessary to utilize the credits or upon the expiration of the applicable four or eight quarter period. The use or expiration of the credits is a decrease in Deferred revenue - related parties . In addition, capital projects the Partnership undertakes at the request of MPC are reimbursed in cash and recognized in income over the remaining term of the applicable transportation services agreements. G&P Segment The Partnership generates the majority of its G&P segment revenues from natural gas gathering, transportation and processing; NGL gathering, transportation, fractionation, marketing and storage; and crude oil gathering and transportation. The Partnership disaggregates revenue as Product sales and Service revenue on the Consolidated Statements of Income. Revenue is reported as follows: • Product sales – Product sales represent the sale of NGLs, condensate and natural gas. The product is primarily obtained as consideration for or related to providing midstream services. • Service revenue – Service revenue represents all other revenue generated as the result of performing the services listed above. The Partnership enters into a variety of contract types in order to generate Product sales and Service revenue . The Partnership provides services under the following different types of arrangements: • Fee-based arrangements – Under fee-based arrangements, the Partnership receives a fee or fees for one or more of the following services: gathering, processing and transportation of natural gas; gathering, transportation, fractionation, exchange and storage of NGLs; and gathering and transportation of crude oil. The revenue the Partnership earns from these arrangements is generally directly related to the volume of natural gas, NGLs or crude oil that flows through the Partnership’s systems and facilities and is not normally directly dependent on commodity prices. In certain cases, the Partnership’s arrangements provide for minimum annual payments or fixed demand charges. ◦ Fee-based arrangements are reported as Service revenue on the Consolidated Statements of Income. In certain instances when specifically stated in the contract terms, the Partnership purchases product after fee-based services have been provided. Revenue from the sale of products purchased after services are provided is reported as Product sales and recognized on a gross basis as the Partnership is the principal in the transaction. • Percent-of-proceeds arrangements – Under percent-of-proceeds arrangements, the Partnership gathers and processes natural gas on behalf of producers, sells the resulting residue gas, condensate and NGLs at market prices and remits to producers an agreed-upon percentage of the proceeds. In other cases, instead of remitting cash payments to the producer, the Partnership delivers an agreed-upon percentage of the residue gas and NGLs to the producer (take-in-kind arrangements) and sells the volumes the Partnership retains to third parties. Revenue from these arrangements is reported on a gross basis where the Partnership acts as the principal, as the Partnership has physical inventory risk and does not earn a fixed dollar amount. The agreed-upon percentage paid to the producer is reported as Purchased product costs on the Consolidated Statements of Income. Revenue is recognized on a net basis when the Partnership acts as an agent and earns a fixed dollar amount of physical product and does not have risk of loss of the gross amount of gas and/or NGLs. Percent-of-proceeds revenue is reported as Product sales on the Consolidated Statements of Income. • Keep-whole arrangements – Under keep-whole arrangements, the Partnership gathers natural gas from the producer, processes the natural gas and sells the resulting condensate and NGLs to third parties at market prices. Because the extraction of the condensate and NGLs from the natural gas during processing reduces the Btu content of the natural gas, the Partnership must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the energy content of this natural gas. Certain keep-whole arrangements also have provisions that require the Partnership to share a percentage of the keep-whole profits with the producers based on the oil to gas ratio or the NGL to gas ratio. Sales of NGLs under these arrangements are reported as Product sales on the Consolidated Statements of Income and are reported on a gross basis as the Partnership is the principal in the arrangement. Natural gas purchased to return to the producer and shared NGL profits are recorded as Purchased product costs in the Consolidated Statements of Income. • Percent-of-index arrangements – Under percent-of-index arrangements, the Partnership purchases natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount. The Partnership then gathers and delivers the natural gas to pipelines where the Partnership resells the natural gas at the index price or at a different percentage discount to the index price. Revenue generated from percent-of-index arrangements are reported as Product sales on the Consolidated Statements of Income and are recognized on a gross basis as the Partnership purchases and takes title to the product prior to sale and is the principal in the transaction. In many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements described above. When fees are charged (in addition to product received) under keep-whole arrangements, percent-of-proceeds arrangements or percent-of-index arrangements, the Partnership records such fees as Service revenue on the Consolidated Statements of Income. The terms of the Partnership’s contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. Amounts billed to customers for shipping and handling, including fuel costs, are included in Product sales on the Consolidated Statements of Income, except under contracts where we are acting as an agent. Shipping and handling costs associated with product sales are included in Purchased product costs on the Consolidated Statements of Income. Taxes collected from customers and remitted to the appropriate taxing authority are excluded from revenue. Facility expenses and depreciation represent those expenses related to operating our various facilities and are necessary to provide both Product sales and Service revenue .
Revenue and Expense Accruals	Revenue and Expense Accruals – The Partnership routinely makes accruals based on estimates for both revenues and expenses due to the timing of compiling billing information, receiving certain third party information and reconciling the Partnership’s records with those of third parties. The delayed information from third parties includes, among other things, actual volumes purchased, transported or sold, adjustments to inventory and invoices for purchases, actual natural gas and NGL deliveries and other operating expenses. The Partnership makes accruals to reflect estimates for these items based on its internal records and information from third parties. Estimated accruals are adjusted when actual information is received from third parties and the Partnership’s internal records have been reconciled.
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 initial 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 in the Consolidated Balance Sheets was $9 million and $4 million , respectively.
Receivables	Receivables – Receivables primarily consist of customer accounts receivable, which are recorded at the invoiced amount and generally do not bear interest. Management reviews the allowance quarterly. Past-due balances over 90 days and other higher risk amounts are reviewed individually for collectability. Balances that remain outstanding after reasonable collection efforts have been unsuccessful are written off through a charge to the valuation allowance and a credit to accounts receivable.
Inventory	Inventories – Inventories consist primarily of natural gas, propane, other NGLs and materials and supplies to be used in operations. Natural gas, propane, and other NGLs are valued at the lower of weighted-average cost or net realizable value. Materials and supplies are stated at the lower of cost or net realizable value. Cost for materials and supplies is determined primarily using the weighted-average cost method. Processed natural gas and NGL inventories include material, labor and overhead. Shipping and handling costs related to purchases of natural gas and NGLs are included in inventory.
Imbalances	Imbalances – Within our pipelines and storage assets we experience volume gains and losses due to pressure and temperature changes, evaporation and variances in meter readings and other measurement methods. Until settled, positive imbalances are recorded as other current assets and negative imbalances are recorded as accounts payable. Positive and negative product imbalances are settled in cash, settled by physical delivery of gas from a different source, or tracked and settled in the future.
Property, plant and equipment	Property, Plant and Equipment – Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of assets are capitalized. Repairs, maintenance and renewals that do not extend the useful lives of the assets are expensed as incurred. Interest costs for the construction or development of long-lived assets are capitalized and amortized over the related asset’s estimated useful life. Leasehold improvements are amortized over the shorter of the useful life or lease term. When items of property, plant and equipment are sold or otherwise disposed of, any gains or losses are reported in the Consolidated Statements of Income. Gains on the disposal of property, plant and equipment are recognized when they occur, 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. The Partnership evaluates transactions involving the sale of property, plant and equipment to determine if they are, in-substance, the sale of real estate. Tangible assets may be considered real estate if the costs to relocate them for use in a different location exceed 10 percent of the asset’s fair value. Financial assets, primarily in the form of ownership interests in an entity, may be in-substance real estate based on the significance of the real estate in the entity. Sales of real estate are not considered consummated if the Partnership maintains an interest in the asset after it is sold or has certain other forms of continuing involvement. Significant judgment is required to determine if a transaction is a sale of real estate and if a transaction has been consummated. If a sale of real estate is not considered consummated, the Partnership cannot record the transaction as a sale and must account for the transaction under an alternative method of accounting such as a financing or leasing arrangement. The Partnership’s policy is to evaluate whether there has been an impairment in the value of long-lived assets when certain events indicate that the remaining balance may not be recoverable. The Partnership evaluates the carrying value of its property, plant and equipment on at least a segment level and at lower levels where the cash flows for specific assets can be identified, which generally is the business unit level for our G&P segment and the pipeline system level for our L&S segment, and are largely independent from other asset groups. A long-lived asset group is considered impaired when the estimated undiscounted cash flows from such asset group are less than the asset group’s carrying value. In that event, a loss is recognized to the extent that the carrying value exceeds the fair value of the long-lived asset group. Fair value is determined primarily using estimated discounted cash flows. Management considers the volume of producer customers’ reserves behind the asset and future NGL product and natural gas prices to estimate cash flows. The amount of additional producer customers’ reserves developed by future drilling activity depends, in part, on expected natural gas prices. Projections of producer customers’ reserves, drilling activity and future commodity prices are inherently subjective and contingent upon a number of variable factors, many of which are difficult to forecast. Any significant variance in any of these assumptions or factors could materially affect future cash flows, which could result in the impairment of an asset group. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value, less the cost to sell, to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is redetermined when related events or circumstances change.
Intangibles	Intangibles – The Partnership’s intangibles are mainly comprised of customer contracts and related relationships acquired in business combinations and recorded under the acquisition method of accounting at their estimated fair values at the date of acquisition. Using relevant information and assumptions, management determines the fair value of acquired identifiable intangible assets. Fair value was calculated using the multi-period excess earnings method under the income approach for each reporting unit. This valuation method is based on first forecasting gross profit for the existing customer base and then applying expected attrition rates. The operating cash flows are calculated by determining the costs required to generate gross profit from the existing customer base. The key assumptions include overall gross profit growth, attrition rate of existing customers over time and the discount rate. Amortization of intangibles with definite lives is calculated using the straight-line method which is reflective of benefit pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible asset. The estimated economic life is determined by assessing the life of the assets related to the contracts and relationships, likelihood of renewals, the projected reserves, competitive factors, regulatory or legal provisions and maintenance and renewal costs. Intangibles with indefinite lives 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.
Goodwill	Goodwill – Goodwill is the cost of an acquisition less the fair value of the net identifiable assets and noncontrolling interest, if any, of the acquired business. The Partnership evaluates goodwill for impairment annually as of November 30, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The Partnership may first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Partnership may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step process goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit to which goodwill has been allocated, with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss. There were no impairments as a result of the Partnership’s 2015 and 2014 goodwill impairment analyses.
Other taxes	Other Taxes – Other taxes primarily include real estate taxes.
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. The Partnership recognizes 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. A receivable is recorded for environmental costs indemnified by MPC.
Asset retirement obligations	Asset Retirement Obligations – An ARO is a legal obligation associated with the retirement of tangible long-lived assets that generally result from the acquisition, construction, development or normal operation of the asset. AROs are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a risk free interest rate and increases due to the passage of time based on the time value of money until the obligation is settled. The Partnership recognizes a liability of a conditional ARO as soon as the fair value of the liability can be reasonably estimated. A conditional ARO is defined as an unconditional legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. AROs have not been recognized for certain 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.
Investment in Unconsolidated Affiliates	Investment in Unconsolidated Affiliates – Equity investments in which the Partnership exercises significant influence, but does not control and is not the primary beneficiary, are accounted for using the equity method and are reported in Equity method investments in the accompanying Consolidated Balance Sheets. 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. The Partnership believes the equity method is an appropriate means for it to recognize increases or decreases measured by GAAP in the economic resources underlying the investments. Regular evaluation of these investments is appropriate to evaluate any potential need for impairment. The Partnership uses evidence of a loss in value to identify if an investment has an other than a temporary decline.
Deferred financing costs	Deferred Financing Costs – Deferred financing costs are an asset for credit facility costs and netted in debt for senior notes. These costs are amortized over the contractual term of the related obligations using the effective interest method or, in certain circumstances, accelerated if the obligation is refinanced.
Derivative instruments	Derivative Instruments – Derivative instruments (including derivative instruments embedded in other contracts) are recorded at fair value and are reflected in the Consolidated Balance Sheets on a net basis, as either an asset or liability, as they are governed by the master netting agreements. The Partnership discloses the fair value of all of its derivative instruments under the captions Other noncurrent assets , Other current liabilities and Deferred credits and other liabilities in the Consolidated Balance Sheets, inclusive of option premiums, if any. Changes in the fair value of derivative instruments are reported in the Consolidated Statements of Income in accounts related to the item whose value or cash flows are being managed. All derivative instruments were marked to market through Product sales , Purchased product costs , or Cost of revenues . Revenue gains and losses relate to contracts utilized to manage the cash flow for the sale of a product. Purchased product costs gains and losses relate to contracts utilized to manage the cost of natural gas purchases, typically related to keep‑whole arrangements. Cost of revenues gains and losses relate to a contract utilized to manage electricity costs. Changes in risk management for unrealized activities are reported as an adjustment to net income in computing cash flow from operating activities on the accompanying Consolidated Statements of Cash Flows. During the years ended December 31, 2015 , 2014 and 2013 , the Partnership did not designate any hedges or designate any contracts as normal purchases and normal sales (except for electricity contracts, for which the normal purchases and normal sales designation has been elected during the year ended December 31, 2015).
Fair value of financial instruments	Fair Value of Financial Instruments – Management believes the carrying amount of financial instruments, including cash and cash equivalents, receivables, receivables from related parties, other current assets, accounts payable, accounts payable to related parties and accrued liabilities approximate fair value because of the short-term maturity of these instruments. The recorded value of the amounts outstanding under the bank revolving credit facility, if any, approximate fair value due to the variable interest rate that approximates current market rates (see Note 14 ). Derivative instruments are recorded at fair value, based on available market information (see Note 15 ).
Fair value measurement	Fair Value Measurement – Financial assets and liabilities recorded at fair value in the Consolidated Balance Sheets are categorized based upon a fair value hierarchy established by GAAP, which classifies the inputs used to measure fair value into the following levels: • Level 1-inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2-inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument. • Level 3-inputs to the valuation methodology are unobservable and significant to the fair value measurement. A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The determination to classify a financial instrument within Level 3 of the valuation hierarchy is based upon the significance of the unobservable inputs to the overall fair value measurement. However, Level 3 financial instruments typically include, in addition to the unobservable or Level 3 inputs, observable inputs (that is, inputs that are actively quoted and can be validated to external sources); accordingly, the gains and losses for Level 3 financial instruments include changes in fair value due in part to observable inputs that are part of the valuation methodology. Level 3 financial instruments include crude oil options, all NGL derivatives and the embedded derivatives in commodity contracts discussed in Note 14 as they have significant unobservable inputs. The methods and assumptions described above may produce a fair value that may not be realized in future periods upon settlement. Furthermore, while the Partnership believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. For further discussion see Note 14 .
Employee benefit plans	Employee Benefit Plans – Neither we nor our subsidiaries have any employees as of January 1, 2016. The Partnership entered into an employee services agreement, effective December 28, 2015, with a subsidiary of MPC for the services provided by the employees from the MarkWest Merger. The Partnership also has two other employee services agreements with MPC.
Equity-based compensation arrangements	Equity-Based Compensation Arrangements – The Partnership issues phantom units under its share-based compensation plan as described further in Note 19 . A phantom unit entitles the grantee a right to receive a common unit upon the issuance of the phantom unit. The fair value of phantom unit awards granted to employees and non-employee directors is based on the fair market value of MPLX LP common units on the date of grant. The fair value of the units awarded is amortized into earnings using a straight-line amortization schedule over the period of service corresponding with the vesting period. For phantom units that vest immediately and are not forfeitable, equity-based compensation expense is recognized at the time of grant. 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 paying out in units are accounted for as equity awards and use a Monte Carlo valuation model to calculate a grant date fair value. To satisfy common unit awards, the Partnership may issue new common units, acquire common units in the open market or use common units already owned by the general partner.
Tax Effect of Share based Compensation	Tax Effects of Share-Based Compensation – The Partnership elected to adopt the simplified method to establish the beginning balance of the additional paid-in capital pool (“APIC Pool”) related to the tax effects of employee share-based compensation and to determine the subsequent impact on the APIC Pool and Consolidated Statements of Cash Flows of the tax effects of share-based compensation awards that were outstanding upon adoption. Additional paid-in capital is reported as Common unitholders - public in the accompanying Consolidated Balance Sheets.
Income taxes	Income Taxes – The Partnership is not a taxable entity for federal income tax purposes. As a result of the MarkWest Merger, discussed further in Note 4 , MarkWest was the surviving entity for tax purposes. MarkWest is not a taxable entity for federal income tax purposes. As such, the Partnership does not directly pay federal income tax. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the Consolidated Statements of Income, is includable in the federal income tax returns of each partner. The Partnership is, however, a taxable entity under certain state jurisdictions. MarkWest Hydrocarbon is a tax paying entity for both federal and state purposes. In addition to paying tax on its own earnings, MarkWest Hydrocarbon recognizes a tax expense or a tax benefit on its proportionate share of Partnership income or loss resulting from MarkWest Hydrocarbon’s ownership of Class A units of the Partnership, even though for financial reporting purposes such income or loss is eliminated in consolidation. The Class A units represent limited partner interests with the same rights as common units except that the Class A units do not have voting rights, except as required by law. Class A units are not treated as outstanding common units in the Consolidated Balance Sheets as they are eliminated in the consolidation of MarkWest Hydrocarbon. The deferred income tax component relates to the change in the temporary book to tax basis difference in the carrying amount of the investment in the Partnership which results primarily from its timing differences in MarkWest Hydrocarbon’s proportionate share of the book income or loss as compared with the MarkWest Hydrocarbon’s proportionate share of the taxable income or loss of the Partnership. The Partnership and MarkWest Hydrocarbon account for income taxes under the asset and liability method. Deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis, capital loss carryforwards and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates applied to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized as tax expense (benefit) from continuing operations in the period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to reflect the deferred tax assets at net realizable value as determined by management. All deferred tax balances are classified as long-term in the accompanying Consolidated Balance Sheets. All changes in the tax bases of assets and liabilities are allocated among operations and items charged or credited directly to equity.
Net income per limited partner unit	Net Income Per Limited Partner Unit – The Partnership uses the two-class method when calculating the net income per unit applicable to limited partners, because there is more than one participating security. The classes of participating securities include common units, subordinated units, general partner units, certain equity-based compensation awards and incentive distribution rights. Class B units are considered to be a separate class of common units that do not participate in distributions. Net income attributable to MPLX LP is allocated to the unitholders differently for preparation of the Consolidated Statements of Equity and the calculation of net income per limited partner unit. In preparing the Consolidated Statements of Equity, net income attributable to MPLX LP is allocated to unitholders in accordance with their respective ownership percentages. However, when distributions related to the incentive distribution rights are made, earnings equal to the amount of those distributions are first allocated to the general partner before the remaining earnings are allocated to the unitholders based on their respective ownership percentages. During periods in which a net loss attributable to the Partnership is reported or periods in which the total distributions exceed the reported net income attributable to the Partnership’s unitholders, the amount allocable to certain equity-based compensation awards and Class B units is based on actual distributions to the equity-based compensation awards and Class B unitholders. Diluted earnings per unit is calculated by dividing net income attributable to the Partnership’s unitholders, after deducting amounts allocable to the outstanding equity-based compensation awards and Class B units, by the weighted average number of potential common units outstanding during the period. Potential common units are excluded from the calculation of diluted earnings per unit during periods in which net income attributable to the Partnership’s unitholders, after deducting amounts that are allocable to the outstanding equity-based compensation awards and Class B units, is a loss as the impact would be anti-dilutive.
Business Combinations	Business Combinations – The Partnership recognizes and measures 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, the Partnership 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 volumes, NGL prices, 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. See Note 4 for more information about the MarkWest Merger.
Accounting for Changes in Ownership Interests in Subsidiaries	Accounting for Changes in Ownership Interests in Subsidiaries – The Partnership’s ownership interest in a consolidated subsidiary may change if it sells a portion of its interest or acquires additional interest or if the subsidiary issues or repurchases its own shares. If the transaction does not result in a change in control over the subsidiary, the transaction is accounted for as an equity transaction. If a sale results in a loss of control, it would result in the deconsolidation of a subsidiary with a gain or loss recognized in the Consolidated Statements of Income unless the subsidiary meets the definition of in-substance real estate. Deconsolidation of in-substance real estate is recorded at cost with no gain or loss recognized. If the purchase of additional interest occurs which changes the acquirer’s ownership interest from noncontrolling to controlling, the acquirer’s preexisting interest in the acquiree is remeasured to its fair value, with a resulting gain or loss recorded in earnings upon consummation of the business combination. Once an entity has control of a subsidiary, its acquisitions of some or all of the noncontrolling interests in that subsidiary are accounted for as equity transactions and are not considered to be a business combination.

Acquisition (Tables)

Acquisition (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 pro forma financial information does not give effect to potential synergies that could result from the acquisition and is not necessarily indicative of the results of future operations. (In millions, except per unit data) 2015 2014 Revenues and other income $ 2,424 $ 2,707 Net income attributable to MPLX LP 154 248 Net income attributable to MPLX LP per unit - basic 0.20 1.02 Net income attributable to MPLX LP per unit - diluted 0.19 0.96
Effects of Changes From Changes in Ownership Interest [Table Text Block]	Changes in MPLX LP’s equity resulting from changes in its ownership interest in Pipe Line Holdings were as follows: (In millions) 2015 2014 2013 Net income attributable to MPLX LP $ 156 $ 121 $ 78 Transfer to noncontrolling interest: Decrease in general partner-MPC equity for purchases of additional interest in Pipe Line Holdings (6 ) (638 ) (46 ) Change from net income attributable to MPLX LP and transfer to noncontrolling interest $ 150 $ (517 ) $ 32
MarkWest [Member]
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 units issued $ 7,326 Cash 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 following table summarizes the preliminary purchase price allocation. Due to the proximity of the MarkWest Merger to December 31, 2015, the Partnership is still completing its 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 8,474 Intangibles 468 Other noncurrent assets 5 Total assets acquired 11,657 Accounts payable 322 Accrued liabilities 13 Accrued taxes 21 Other current liabilities 44 Long-term debt 4,567 Deferred income taxes 374 Deferred credits and other liabilities 151 Noncontrolling interest 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 MarkWest in the Consolidated Statements of Income for 2015 are as follows: (In millions) 2015 Revenues and other income $ 126 Income from operations 32
MarkWest Utica EMG [Member]
Business Acquisition [Line Items]
Historical Information for Deconsolidated Entity [Table Text Block]	A summary of the amounts included in the historical financial statements of MarkWest for the year ended December 31, 2014 and the period from January 1, 2015 through December 3, 2015 related to MarkWest Utica EMG are as follows: (in millions) 2015 2014 Revenue and other income 152 85 Cost of revenue excluding depreciation and amortization 27 48 Depreciation and amortization 61 50 Net income attributable to noncontrolling interest 64 31 Net income (5 ) (46 )

Equity Method Investments Equ34

Equity Method Investments Equity Method Investments (Tables)	12 Months Ended
	Dec. 31, 2015
Equity Method Investments and Joint Ventures [Abstract]
Summarized Financial Information For Equity Method Investees Table [Text Block]	Summarized financial information from the date of the MarkWest Merger and as of December 31, 2015 for equity method investments is as follows: (In millions) MarkWest Utica EMG (1) Other VIEs Non-VIEs Total Income statement data: Revenue 18 2 9 29 Income from operations 9 — 1 10 Net income 10 — 1 11 Balance sheet data: Current assets 113 7 30 150 Noncurrent assets 2,207 169 243 2,619 Current liabilities 77 7 18 102 Noncurrent liabilities 1 12 — 13

Related Party Agreements and 35

Related Party Agreements and Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Revenue from Related Parties	Revenue received from related parties related to service and product sales were as follows: (In millions) 2015 2014 2013 Service revenue MPC $ 481 $ 451 $ 384 Product sales MPC $ 1 $ — $ —
Summary of Fees Received for Operating Pipelines for Related Parties Included in Other Income - Related Parties	The revenue received for operating pipelines for related parties included in Other income - related parties on the Consolidated Statements of Income were as follows: (In millions) 2015 2014 2013 MPC $ 24 $ 22 $ 18 Centennial 1 1 1 Ohio Gathering 2 — — Total $ 27 $ 23 $ 19
Schedule of Entity Wide Information Allocated Related Party Omnibus Agreement Costs by Income Stmt Line	MPC provides executive management services and certain general and administrative services to the Partnership under the terms of the omnibus agreement. Expenses incurred under these agreements are shown in the table below by the income statement line where they were recorded. Charges for services included in Purchases from related parties primarily relate to services that support the Partnership’s operations and maintenance activities, as well as compensation expenses. Charges for services included in General and administrative expenses primarily relate to services that support the Partnership’s executive management, accounting and human resources activities. These charges were as follows: (In millions) 2015 2014 2013 Purchases from related parties $ 25 $ 25 $ 18 General and administrative expenses 34 31 31 Total $ 59 $ 56 $ 49
Summary of Related Party Costs Added to Property, Plant and Equipment	, some service costs related to engineering services are associated with assets under construction. These costs added to Property, plant and equipment were as follows: (In millions) 2015 2014 2013 MPC $ 13 $ 8 $ 8
Summary of Allocated Related Party Employee Benefit Costs by Income Statement Line Item	(In millions) 2015 2014 2013 Purchases from related parties $ 77 $ 73 $ 77 General and administrative expenses 20 24 16 Total $ 97 $ 97 $ 93
Receivables from Related Parties	Receivables from related parties were as follows: December 31, (In millions) 2015 2014 MPC $ 76 $ 41 Centennial 1 — Jefferson Dry Gas 2 — MarkWest Utica EMG 4 — Ohio Gathering 5 — Total $ 88 $ 41
Schedule of Long Term Receivables with Related Parties	Long-term receivables related to reimbursements from the MarkWest Merger to be provided by MPC for the conversion of Class B units were as follows: December 31, (In millions) 2015 2014 MPC $ 25 $ —
Payables to Related Parties	Payables to related parties were as follows: December 31, (In millions) 2015 2014 MPC $ 26 $ 20 MarkWest Utica EMG 21 — Total $ 47 $ 20
Schedule Of Related Party Deferred Revenue Table	The deferred revenue-related parties associated with the minimum volume deficiencies and project reimbursements were as follows: December 31, (In millions) 2015 2014 Minimum volume deficiencies - MPC $ 36 $ 30 Project reimbursements - MPC 5 5 Total $ 41 $ 35

Net Income Per Limited Partne36

Net Income Per Limited Partner Unit (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of Net Income Per Limited Partner Unit	Diluted net income per limited partner unit for 2014 and 2013 reporting periods is the same as basic net income per limited partner unit as there were no potentially dilutive common or subordinated units outstanding as of December 31, 2014 or 2013 . (In millions) 2015 2014 2013 Net income attributable to MPLX LP $ 156 $ 121 $ 78 Less: General partner’s distributions declared (including IDRs) (1) 60 6 2 Limited partners’ distributions declared on common units (1) 224 54 43 Limited partner’s distributions declared on subordinated units (1) 31 52 43 Undistributed net (loss) income attributable to MPLX LP $ (159 ) $ 9 $ (10 ) (1) See Note 8 for information regarding the distribution.
Schedule of Basic and Diluted Earnings Per Unit	2015 (In millions, except per-unit data) General Partner Limited Partners’ Common Units Limited Partner’s Subordinated Units Total Basic and diluted net income attributable to MPLX LP per unit: Net income attributable to MPLX LP: Distributions declared (including IDRs) $ 60 $ 224 $ 31 $ 315 Undistributed net loss attributable to MPLX LP (3 ) (127 ) (29 ) (159 ) Net income attributable to MPLX LP $ 57 $ 97 $ 2 $ 156 Weighted average units outstanding: Basic 2 79 18 99 Diluted 2 80 18 100 Net income attributable to MPLX LP per limited partner unit: Basic $ 1.23 $ 0.11 Diluted $ 1.22 $ 0.11 2014 (In millions, except per-unit data) General Partner Limited Partners’ Common Units Limited Partner’s Subordinated Units Total Basic and diluted net income attributable to MPLX LP per unit: Net income attributable to MPLX LP: Distribution declared $ 6 $ 54 $ 52 $ 112 Undistributed net income attributable to MPLX LP 2 4 3 9 Net income attributable to MPLX LP $ 8 $ 58 $ 55 $ 121 Weighted average units outstanding: Basic 2 37 37 76 Diluted 2 37 37 76 Net income attributable to MPLX LP: Basic $ 1.55 $ 1.50 Diluted $ 1.55 $ 1.50 2013 (In millions, except per-unit data) General Partner Limited Partners’ Common Units Limited Partner’s Subordinated Units Total Basic and diluted net income attributable to MPLX LP per unit: Net income attributable to MPLX LP: Distribution declared $ 2 $ 43 $ 43 $ 88 Undistributed net loss attributable to MPLX LP — (4 ) (6 ) (10 ) Net income attributable to MPLX LP $ 2 $ 39 $ 37 $ 78 Weighted average units outstanding: Basic 1 37 37 75 Diluted 1 37 37 75 Net income attributable to MPLX LP per limited partner unit: Basic $ 1.05 $ 1.01 Diluted $ 1.05 $ 1.01

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Schedule of Stockholders Equity	The table below summarizes the changes in the number of units outstanding through December 31, 2015 : (In units) Common Class B Subordinated General Partner Total Balance at December 31, 2012 36,951,515 — 36,951,515 1,508,225 75,411,255 Balance at December 31, 2013 36,951,515 — 36,951,515 1,508,225 75,411,255 Unit-based compensation awards 15,479 — — 316 15,795 Contribution of interest in Pipe Line Holdings 2,924,104 — — 59,676 2,983,780 December 2014 equity offering 3,450,000 — — 70,408 3,520,408 Balance at December 31, 2014 43,341,098 — 36,951,515 1,638,625 81,931,238 Unit-based compensation awards 18,932 — — 386 19,318 Issuance of units under the ATM program 25,166 — — 514 25,680 Subordinated unit conversion 36,951,515 — (36,951,515 ) — — MarkWest Merger 216,350,465 7,981,756 5,160,950 229,493,171 Balance at December 31, 2015 296,687,176 7,981,756 — 6,800,475 311,469,407
Schedule of Incentive Distributions Made to Managing Members or General Partners by Distribution	Marginal percentage interest in distributions Total quarterly distribution per unit target amount Unitholders General Partner Minimum quarterly distribution $ 0.2625 98.0 % 2.0 % First target distribution above $0.2625 up to $0.301875 98.0 % 2.0 % Second target distribution above $0.301875 up to $0.328125 85.0 % 15.0 % Third target distribution above $0.328125 up to $0.393750 75.0 % 25.0 % Thereafter above $0.393750 50.0 % 50.0 %
Schedule Of Calculation Of Net Income Applicable to Partners	Net Income Allocation - In preparing the Consolidated Statements of Equity, net income attributable to MPLX LP is allocated to the unitholders in accordance with their respective ownership percentages. However, when distributions related to the incentive distribution rights are made, earnings equal to the amount of those distributions are first allocated to the general partner before the remaining earnings are allocated to the unitholders based on their respective ownership percentages. The following table presents the allocation of the general partner’s interest in net income attributable to MPLX LP: (In millions) 2015 2014 2013 Net income attributable to MPLX LP $ 156 $ 121 $ 78 Less: General partner's incentive distribution rights and other 55 4 — Net income attributable to MPLX LP available to general and limited partners $ 101 $ 117 $ 78 General partner’s interest in net income attributable to MPLX LP $ 2 $ 2 $ 2 General partner's incentive distribution rights and other 55 4 — General partner's interest in net income attributable to MPLX LP $ 57 $ 6 $ 2
Distributions Made to Limited Partner, by Distribution	The allocation of total quarterly cash distributions to general and limited partners is as follows for the year ended December 31, 2015 , 2014 and 2013 . The distributions are declared subsequent to quarter end; therefore, the following table represents total cash distributions applicable to the period in which the distributions were earned. (In millions) 2015 2014 2013 General partner's distributions: General partner's distributions $ 6 $ 2 $ 2 General partner's incentive distribution rights distributions 54 4 — Total general partner's distributions $ 60 $ 6 $ 2 Limited partners' distributions: Common unitholders $ 224 $ 54 $ 43 Subordinated unitholders 31 52 43 Total limited partners' distributions 255 106 86 Total cash distributions declared $ 315 $ 112 $ 88

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Information [Abstract]
Income from operations and capital expenditures by segment [Table Text Block]	2015 (In millions) L&S G&P Total Revenues and other income: Segment revenues $ 547 $ 150 $ 697 Segment other income 30 — 30 Total segment revenues and other income 577 150 727 Costs and expenses: Segment cost of revenues 254 62 316 Segment operating income before portion attributable to noncontrolling interest 323 88 411 Segment portion attributable to noncontrolling interest 1 12 13 Segment operating income attributable to MPLX LP $ 322 $ 76 $ 398 2014 (In millions) L&S Revenues and other income: Segment revenues $ 520 Segment other income 28 Total segment revenues and other income 548 Costs and expenses: Segment cost of revenues 250 Segment operating income before portion attributable to noncontrolling interest 298 Segment portion attributable to noncontrolling interest 85 Segment operating income attributable to MPLX LP $ 213 2013 (In millions) L&S Revenues and other income: Segment revenues $ 463 Segment other income 23 Total segment revenues and other income 486 Costs and expenses: Segment cost of revenues 237 Segment operating income before portion attributable to noncontrolling interest 249 Segment portion attributable to noncontrolling interest 106 Segment operating income attributable to MPLX LP $ 143
Reconciliation to Income from Operations [Table Text Block]	(in millions) 2015 2014 2013 Reconciliation to Income from operations: Segment operating income attributable to MPLX $ 398 $ 213 $ 143 Segment portion attributable to unconsolidated affiliates (21 ) — — Segment portion attributable to noncontrolling interest 13 85 106 Income from equity method investments 3 — — Other income - related parties 2 — — Unrealized derivative gains 4 — — Depreciation and amortization (89 ) (50 ) (49 ) General and administrative expenses (104 ) (65 ) (53 ) Income from operations $ 206 $ 183 $ 147
Reconciliation to Total Revenues and other income [Table Text Block]	(in millions) 2015 2014 2013 Reconciliation to Total revenues and other income: Total segment revenues and other income $ 727 $ 548 $ 486 Revenue adjustment from unconsolidated affiliates (28 ) — — Income from equity method investments 3 — — Other income - related parties 2 — — Unrealized derivative loss (1 ) — — Total revenues and other income $ 703 $ 548 $ 486
Reconciliation of Net Income Attributable to Noncontrolling Interests [Table Text Block]	(in millions) 2015 2014 2013 Reconciliation to Net income attributable to noncontrolling interests Segment portion attributable to noncontrolling interest $ 13 $ 85 $ 106 Portion of noncontrolling interests related to items below segment income from operations (7 ) (28 ) (38 ) Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates (5 ) — — Net income attributable to noncontrolling interests $ 1 $ 57 $ 68
Reconciliation of Other Significant Reconciling Items from Segments to Consolidated [Table Text Block]	The following reconciles segment capital expenditures to total capital expenditures: (In millions) 2015 2014 2013 L&S segment capital expenditures $ 188 $ 79 $ 107 G&P segment capital expenditures (1) 100 — — Total segment capital expenditures 288 79 107 Less: Capital expenditures for Partnership operated, non-wholly owned subsidiaries (24 ) — — Total capital expenditures $ 264 $ 79 $ 107 (1) The G&P segment includes $24 million of capital expenditures related to Partnership operated, non-wholly owned subsidiaries.
Reconciliation of Assets from Segment to Consolidated [Table Text Block]	Total assets by reportable segment were: December 31, (In millions) 2015 2014 L&S $ 1,431 $ 1,214 G&P 14,246 — Total assets $ 15,677 $ 1,214

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	The components of the provision for income tax expense (benefit) are as follows: (In millions) 2015 Deferred income tax expense (benefit): Federal $ 3 State (1 ) Total deferred 2 Provision for income tax $ 2
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	A reconciliation of the provision for income tax and the amount computed by applying the federal statutory rate of 35 percent to the income before income taxes for the year ended December 31, 2015 is as follows: (In millions) MarkWest Hydrocarbon Partnership Eliminations Consolidated Income before provision for income tax $ 9 $ 149 $ 1 $ 159 Federal statutory rate 35 % — % — % Federal income tax at statutory rate (1) 3 — — 3 State income taxes net of federal benefit - MarkWest Hydrocarbon — (1 ) — (1 ) Provision on income from Class A units (1) 1 — — 1 Other (1 ) — — (1 ) Provision for income tax $ 3 $ (1 ) $ — $ 2 (1) MarkWest Hydrocarbon pays tax on its share of the Partnership’s income or loss as a result of its ownership of Class A units.
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	Deferred tax assets and liabilities consist of the following: December 31, (In millions) 2015 2014 Deferred tax assets: Derivatives $ 9 $ — Net operating loss carryforwards 62 — Total deferred tax assets 71 — Deferred tax liabilities Property, plant and equipment 6 — Investments in subsidiaries and affiliates 442 — Total deferred tax liabilities 448 — Net deferred tax liabilities (1) $ 377 $ — (1) See Note 3 for discussion regarding a recently adopted accounting standard related to deferred tax assets and liabilities.

Inventories (Tables)

Inventories (Tables)	12 Months Ended
	Dec. 31, 2015
Inventory Disclosure [Abstract]
Schedule of Components of Inventory [Table Text Block]	Inventories consist of the following: December 31, (In millions) 2015 2014 NGLs $ 3 $ — Line fill 5 — Spare parts, materials and supplies 41 12 Total inventories $ 49 $ 12

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	Property, plant and equipment consist of the following: Estimated Useful Lives December 31, (In millions) 2015 2014 Natural gas gathering and NGL transportation pipelines and facilities 15 - 30 years $ 4,307 $ — Processing, fractionation and storage facilities 24 - 37 years 3,185 166 Pipelines and related assets 19 - 42 years 1,128 1,081 Land, building, office equipment and other 5 - 25 years 559 29 Construction in progress 939 85 Total 10,118 1,361 Less accumulated depreciation 435 353 Property, plant and equipment, net $ 9,683 $ 1,008

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	The following table presents the financial instruments carried at fair value as of December 31, 2015 classified by the valuation hierarchy. (In millions) Assets Liabilities Significant other observable inputs (Level 2) Commodity contracts $ 2 $ — Significant unobservable inputs (Level 3) Commodity contracts 7 — Embedded derivatives in commodity contracts — (32 ) Total carrying value in Consolidated Balance Sheets $ 9 $ (32 )
Fair Value Inputs Assets and Liabilities Quantitative Information [Table Text Block]	The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments as of December 31, 2015 . The market approach is used for valuation of all instruments. Level 3 Instrument Balance Sheet Classification Unobservable Inputs Value Range Time Period Commodity contracts Assets Forward ethane prices (per gallon) $0.16 - $0.19 Jan. 2016 - Dec. 2016 Forward propane prices (per gallon) $0.39 - $0.44 Jan. 2016 - Dec. 2016 Forward isobutane prices (per gallon) $0.54 - $0.57 Jan. 2016 - Mar. 2016 Forward normal butane prices (per gallon) $0.51 - $0.57 Jan. 2016 - Mar. 2016 Forward natural gasoline prices (per gallon) $0.89 - $0.93 Jan. 2016 - Dec. 2016 Embedded derivatives in commodity contracts Liabilities Forward propane prices (per gallon) (1) $0.39 - $0.49 Jan. 2016 - Dec. 2022 Forward isobutane prices (per gallon) (1) $0.53 - $0.64 Jan. 2016 - Dec. 2022 Forward normal butane prices (per gallon) (1) $0.48 - $0.60 Jan. 2016 - Dec. 2022 Forward natural gasoline prices (per gallon) (1) $0.89 - $1.04 Jan. 2016 - Dec. 2022 Forward natural gas prices (per MMBtu) (2) $2.18 - $3.39 Jan. 2016 - Dec. 2022 ERCOT Pricing (per MegaWatt Hour) $23.08 - $44.58 Jan. 2016 - Dec. 2016 Probability of renewal (3) 50.0% (1) NGL prices used in the valuation are generally at the lower end of the range in the early years and increase over time. (2) Natural gas prices used in the valuations are generally at the lower end of the range in the early years and increase over time. (3)
Schedule of changes in Level 3 fair value measurements [Table Text Block]	The tables below include a roll forward of the balance sheet amounts for the years ended December 31, 2015 (including the change in fair value) for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy. 2015 (In millions) Commodity Derivative Contracts (net) Embedded Derivatives in Commodity Contracts (net) Fair value at beginning of period $ — $ — Net positions assumed in conjunction with the MarkWest Merger 7 (38 ) Total gain (realized and unrealized) included in earnings (1) 3 5 Settlements (3 ) 1 Fair value at end of period $ 7 $ (32 ) The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at end of period $ 2 $ 5 (1) Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in Product sales in the accompanying Consolidated Statements of Income. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in Costs of revenue and Purchased product costs .
Fair Value, by Balance Sheet Grouping [Table Text Block]	The following table summarizes the fair value and carrying value of the Partnership’s long-term debt, excluding capital leases, and SMR liability. December 31, 2015 2014 (In millions) Fair Value Carrying Value Fair Value Carrying Value Long-term debt $ 5,212 $ 5,255 $ 636 $ 635 SMR liability $ 99 $ 100 $ — $ —

Derivative Financial Instrume43

Derivative Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]	Volume of Commodity Derivative Activity As of December 31, 2015 , the Partnership had the following outstanding commodity contracts that were executed to manage the cash flow risk associated with future sales of NGLs: Derivative contracts not designated as hedging instruments Financial Position Notional Quantity (net) Crude Oil (bbl) Short 109,800 NGLs (gal) Short 43,837,756
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	The impact of the Partnership’s derivative instruments on its Consolidated Balance Sheets is summarized below: (In millions) December 31, 2015 Derivative contracts not designated as hedging instruments and their balance sheet location Asset Liability Commodity contracts (1) Other current assets / other current liabilities $ 9 $ (5 ) Other noncurrent assets / deferred credits and other liabilities — (27 ) Total $ 9 $ (32 ) (1) Includes embedded derivatives in commodity contracts as discussed above.
Derivative Instruments, Gain (Loss) [Table Text Block]	The impact of the Partnership’s derivative contracts not designated as hedging instruments and the location of gain or (loss) recognized in the Consolidated Statements of Income is summarized below: December 31, (In millions) 2015 Product sales Realized gain 4 Unrealized loss (1 ) Total revenue: derivative gain from product sales 3 Purchased product costs Unrealized gain 5 Total gain 8

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Summary of Outstanding Borrowings	outstanding borrowings at December 31, 2015 and 2014 consisted of the following: December 31, (In millions) 2015 2014 MPLX LP: Bank revolving credit facility due 2020 $ 877 $ 385 Term loan facility due 2019 250 250 5.500% senior notes due 2023 710 — 4.500% senior notes due 2023 989 — 4.875% senior notes due 2024 1,149 — 4.000% senior notes due 2025 500 — 4.875% senior notes due 2025 1,189 — Consolidated subsidiaries: MarkWest - 5.500% senior notes due 2023 40 — MarkWest - 4.500% senior notes due 2023 11 — MarkWest - 4.875% senior notes due 2024 1 — MarkWest - 4.875% senior notes due 2025 11 — MPL - capital lease obligations due 2020 9 10 Total 5,736 645 Unamortized debt issuance costs (1) (8 ) — Unamortized discount (2) (472 ) — Amounts due within one year (1 ) (1 ) Total long-term debt due after one year $ 5,255 $ 644 (1) The Partnership adopted the updated FASB debt issuance cost standard as of June 30, 2015. This has been applied retrospectively and there was no effect to the prior period presented. (2) 2015 includes $465 million discount related to the difference between the fair value and the principal amount of the assumed MarkWest debt.
Schedule of Debt Payments	The following table shows five years of scheduled debt payments. (In millions) 2016 $ 1 2017 1 2018 1 2019 1 2020 1,132
Schedule of interest payable dates	Interest on each series of MPLX senior notes is payable semi-annually in arrears according to the table below. Senior Notes Interest payable semi-annually in arrears 5.500% senior notes due 2023 February 15 th and August 15 th 4.500% senior notes due 2023 January 15 th and July 15 th 4.875% senior notes due 2024 June 1 st and December 1 st 4.000% senior notes due 2025 February 15 th and August 15 th 4.875% senior notes due 2025 June 1 st and December 1 st
Schedule of amounts related to the SMR included in the Balance Sheet	As of December 31, 2015, the following amounts related to the SMR are included in the accompanying Consolidated Balance Sheets: (In millions) December 31, 2015 Assets Property, plant and equipment, net of accumulated depreciation $ 69 Liabilities Accrued liabilities 4 Deferred credits and other liabilities 96

Goodwill and Intangibles (Table

Goodwill and Intangibles (Tables)	12 Months Ended
	Dec. 31, 2015
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill	There were no changes in the carrying amount of goodwill for 2014. The changes in carrying amount of goodwill for 2015 were as follows: (In millions) L&S G&P Total Beginning balance $ 105 $ — $ 105 Acquisitions (1) — 2,454 2,454 Ending balance $ 105 $ 2,454 $ 2,559 (1) On December 4, 2015 , the Partnership completed the MarkWest Merger, see Note 4 for more information.
Schedule of Acquired Finite-Lived Intangible Assets by Major Class	There were no intangible assets as of December 31, 2014. The Partnership’s intangible assets as of December 31, 2015 are comprised of customer contracts and relationships, as follows: (In millions) Gross Accumulated Amortization Net Useful Life L&S $ — $ — $ — N/A G&P 468 (2 ) 466 11-25 years $ 468 $ (2 ) $ 466
Schedule of Finite-Lived Intangible Assets, Future Amortization Expense	Estimated future amortization expense related to the intangible assets at December 31, 2015 is as follows: (In millions) 2016 32 2017 32 2018 32 2019 32 2020 32 Thereafter 306 Total $ 466

Supplemental Cash Flow Inform46

Supplemental Cash Flow Information (Tables)	12 Months Ended
	Dec. 31, 2015
Supplemental Cash Flow Elements [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) $ 13 $ 3 $ — Non-cash investing and financing activities: Net transfers of property, plant and equipment to inventories $ 5 $ 1 $ 4 Contribution - common units issued — 200 — Acquisition: Fair value of MPLX units issued (1) 7,326 — — Payable to seller 50 — — (1) See Note 4 .
Summary of Changes in Capital Accruals	The Consolidated Statements of Cash Flows exclude changes to the Consolidated Balance Sheets that did not affect cash. The following is the change of additions to property, plant and equipment related to capital accruals: (In millions) 2015 2014 2013 Increase (decrease) in capital accruals $ 25 $ 12 $ (5 )

Equity-Based Compensation Plan

Equity-Based Compensation Plan (Tables)	12 Months Ended
	Dec. 31, 2015
Phantom Units [Member]
Equity Transactions And Share Based Compensation [Line Items]
Summary of Unit Award Activity	The following is a summary of phantom unit award activity of MPLX LP common limited partner units in 2015 : Phantom Units Number of Units Weighted Average Fair Value Aggregate Intrinsic Value (In millions) Outstanding at December 31, 2014 100,769 $ 41.66 Granted 962,764 35.00 Settled (32,314 ) 40.18 Forfeited — Outstanding at December 31, 2015 1,031,219 35.49 Vested and expected to vest at December 31, 2015 1,001,324 35.52 $ 39.40 Convertible at December 31, 2015 472,665 34.26 $ 18.60
Schedule of Share-based Compensation Arrangement by Share-based Payment Award, Restricted Stock Units, Vested and Expected to Vest	The following is a summary of the values related to phantom units held by officers and non-employee directors: Phantom Units Intrinsic Value of Units Issued During the Period (in millions) Weighted Average Grant Date Fair Value of Units Granted During the Period 2015 $ 3 $ 35.00 2014 1 49.56 2013 — —
Performance Shares [Member]
Equity Transactions And Share Based Compensation [Line Items]
Summary of Unit Award Activity	The following is a summary of activity of performance unit awards paying out in MPLX LP common limited partner units in 2015 : Performance Units Number of Units Weighted Outstanding at December 31, 2014 924,143 $ 0.98 Granted 597,249 1.03 Forfeited — — Outstanding at December 31, 2015 1,521,392 1.00
Schedule of Share-based Compensation, Performance Unit Awards, Valuation 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 30.12 % 17.17 % 16.75 % Grant date fair value of performance units granted $ 1.03 $ 1.16 $ 0.77

Lease Operations (Tables)

Lease Operations (Tables)	12 Months Ended
	Dec. 31, 2015
Leases [Abstract]
Schedule of Future Minimum Rental Payments Receivable for Operating Leases [Table Text Block]	The following is a schedule of minimum future rentals on the non-cancellable operating leases as of December 31, 2015 : (In millions) 2016 $ 174 2017 184 2018 185 2019 186 2020 185 2021 and thereafter 588 Total minimum future rentals $ 1,502
Schedule of Property Subject to or Available for Operating Lease [Table Text Block]	The following schedule summarizes the Partnership’s 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

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Change in Asset Retirement Obligation [Table Text Block]	The following is a reconciliation of the changes in the ARO from January 1, 2015 to December 31, 2015 : December 31, (In millions) 2015 Beginning ARO $ — Liabilities assumed in conjunction with the MarkWest Merger 15 Liabilities incurred 2 Ending ARO $ 17

Commitments and Contingencies C

Commitments and Contingencies Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments and Contingencies (Minimum Future Payments) [Abstract]
Contractual Obligation, Fiscal Year Maturity Schedule	The Partnership executed transportation and terminalling agreements that obligate us to minimum volume, throughput or payment commitments over the terms of the agreements, which range from three to ten years. After the minimum volume commitments are met in the transportation and terminalling agreements, the Partnership pays additional amounts based on throughput. There are escalation clauses in the transportation and terminalling agreements, which are based on CPI adjustments. The minimum future payments under these agreements as of December 31, 2015 are as follows: (In millions) 2016 $ 68 2017 74 2018 60 2019 59 2020 59 2021 and thereafter 299 Total $ 619
Schedule Of Future Minimum Lease Payments For Operating And Capital Leases Table	The Partnership has various non-cancellable operating lease agreements and a long-term propane storage agreement expiring at various times through fiscal year 2040. Most of these leases include renewal options. The Partnership also leases certain pipelines under a capital lease that has a fixed price purchase option in 2020. Future minimum commitments as of December 31, 2015 , for capital lease obligations and for operating lease obligations having initial or remaining non-cancellable lease terms in excess of one year are as follows: (In millions) Capital Obligations Operating Obligations 2016 $ 1 $ 49 2017 1 49 2018 2 40 2019 2 35 2020 5 30 Later years — 100 Total minimum lease payments 11 $ 303 Less imputed interest costs 2 Present value of net minimum lease payments $ 9
Schedule of Rent Expense	Operating lease rental expense was: (In millions) 2015 2014 2013 Minimum rental expense $ 14 $ 10 $ 10
Schedule of minimum amounts payable annually under the product supply agreement	SMR Transaction – On September 1, 2009, MarkWest entered into a product supply agreement creating a long-term contractual obligation for the payment of processing fees in exchange for the entire product processed by the SMR. The product received under this agreement is sold to a refinery customer pursuant to a corresponding long-term agreement. The minimum amounts payable annually under the product supply agreement, excluding the potential impact of inflation adjustments per the agreement, are as follows: (In millions) 2016 $ 17 2017 17 2018 17 2019 17 2020 17 2021 and thereafter 162 Total minimum payments 247 Less: Services element 95 Less: Interest 52 Total SMR liability 100 Less: Current portion of SMR liability 4 Long-term portion of SMR liability $ 96

Select Quarterly Financial Da51

Select Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Summary of Quarterly Financial Data	2015 2014 (In millions, except per unit data) 1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr. (1) 1st Qtr. 2nd Qtr. 3rd Qtr. 4th Qtr. Revenues $ 130 $ 140 $ 141 $ 257 $ 131 $ 126 $ 131 $ 132 Income from operations 51 58 47 50 56 44 44 39 Net income 46 51 42 18 56 42 43 37 Net income attributable to MPLX LP 46 50 42 18 34 28 30 29 Net income attributable to MPLX LP per limited partner unit: Common - basic $ 0.46 $ 0.50 $ 0.41 $ (0.14 ) $ 0.41 $ 0.37 $ 0.37 $ 0.38 Common - diluted 0.46 0.50 0.41 (0.14 ) 0.41 0.37 0.37 0.38 Subordinated - basic and diluted 0.46 0.50 — — 0.41 0.37 0.37 0.33 Distributions declared per limited partner common unit $ 0.4100 $ 0.4400 $ 0.4700 $ 0.5000 $ 0.3275 $ 0.3425 $ 0.3575 $ 0.3825 Distributions declared: Limited partner units - Public $ 10 $ 10 $ 11 $ 120 $ 7 $ 6 $ 7 $ 9 Limited partner units - MPC 23 25 27 29 18 19 19 21 General partner units - MPC 1 1 1 3 — — 1 1 Incentive distribution rights - MPC 3 6 8 37 — 1 1 2 Total distributions declared $ 37 $ 42 $ 47 $ 189 $ 25 $ 26 $ 28 $ 33 (1) These amounts include results from the MarkWest Merger which closed on December 4, 2015. See Note 4 for more information on the MarkWest Merger.

Description of the Business a52

Description of the Business and Basis of Presentation (Detail)	Dec. 04, 2015	Oct. 31, 2012	Mar. 27, 2012	Dec. 31, 2015
Description Of Business And Basis Of Presentation [Line Items]
Date of partnership formation			Mar. 27, 2012
Date for initial public offering completed		Oct. 31, 2012
Number of reportable segments				2
MarkWest [Member]
Description Of Business And Basis Of Presentation [Line Items]
Effective date of acquisition	Dec. 4, 2015

Summary of Principal Accounti53

Summary of Principal Accounting Policies (Detail)	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Summary of Principal Accounting Policies [Line Items]
Restricted cash	$ 9,000,000	$ 4,000,000
Threshold Relocation Cost of Assets as Percentage of Fair Value to be Classified as Real Estate	10.00%
Goodwill, Impairment Loss	$ 0	$ 0
MPC [Member] | Employee Services Agreements [Member]
Summary of Principal Accounting Policies [Line Items]
Number of agreements	2

Acquisitions (Purchase of MarkW

Acquisitions (Purchase of MarkWest Energy Partners L.P.) (Details) $ / shares in Units, $ in Millions	Dec. 04, 2015USD ($)$ / shares	Mar. 01, 2014USD ($)	May. 02, 2013USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Business Acquisition [Line Items]
Payments to acquire businesses		$ 310	$ 100		$ 12	$ 910	$ 100
Payable to MarkWest Class B unitholders					50	0	$ 0
Goodwill				$ 2,559	2,559	$ 105
MarkWest [Member]
Business Acquisition [Line Items]
Effective date of acquisition	Dec. 4, 2015
Common Units Conversion Ratio	1.09
Cash consideration to unitholders | $ / shares	$ 6.20
Payments to acquire businesses	$ 1,230
Payable to MarkWest Class B unitholders	50
Goodwill	2,454
Business Acquisition, Transaction Costs				36	36
MPC [Member] | MarkWest [Member]
Business Acquisition [Line Items]
Payments to acquire businesses	1,200			1,300
Payable to MarkWest Class B unitholders	$ 50
Selling, General and Administrative Expenses [Member] | MarkWest [Member]
Business Acquisition [Line Items]
Business Acquisition, Transaction Costs				30	30
Nonoperating Income (Expense) [Member] | MarkWest [Member]
Business Acquisition [Line Items]
Business Acquisition, Transaction Costs				$ 6	$ 6
Equity Method Investments [Member] | Income Approach Valuation Technique [Member]
Business Acquisition [Line Items]
Fair Value Inputs, Long-term Revenue Growth Rate	2.50%
Equity Method Investments [Member] | Minimum [Member] | Income Approach Valuation Technique [Member]
Business Acquisition [Line Items]
Fair Value Inputs, Discount Rate	9.40%
Equity Method Investments [Member] | Maximum [Member] | Income Approach Valuation Technique [Member]
Business Acquisition [Line Items]
Fair Value Inputs, Discount Rate	11.10%
Finite-Lived Intangible Assets [Member] | Minimum [Member] | Income Approach Valuation Technique [Member]
Business Acquisition [Line Items]
Fair Value Inputs, Discount Rate	11.00%
Fair Value Inputs, Attrition Rate	5.00%
Finite-Lived Intangible Assets [Member] | Maximum [Member] | Income Approach Valuation Technique [Member]
Business Acquisition [Line Items]
Fair Value Inputs, Discount Rate	13.00%
Fair Value Inputs, Attrition Rate	10.00%

Acquisitions (Fair Value of Con

Acquisitions (Fair Value of Consideration Transferred - MarkWest) (Details) - USD ($) $ in Millions	Dec. 04, 2015	Mar. 01, 2014	May. 02, 2013	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Fair value of units issued				$ 7,326	$ 0	$ 0
Cash		$ 310	$ 100	12	910	100
Payable to MarkWest Class B unitholders				$ 50	$ 0	$ 0
MarkWest [Member]
Business Acquisition [Line Items]
Fair value of units issued	$ 7,326
Cash	1,230
Payable to MarkWest Class B unitholders	50
Total fair value of consideration transferred	$ 8,606

Acquisitions (Schedule of Asset

Acquisitions (Schedule of Assets Acquired and Liabilities Assumed) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 04, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Goodwill	$ 2,559		$ 105
MarkWest [Member]
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		8,474
Intangibles		468
Other noncurrent assets		5
Total assets acquired		11,657
Accounts payable		322
Accrued liabilities		13
Accrued taxes		21
Other current liabilities		44
Long-term debt		4,567
Deferred income taxes		374
Deferred credits and other liabilities		151
Noncontrolling interest		13
Total liabilities and noncontrolling interest assumed		5,505
Net assets acquired excluding goodwill		6,152
Goodwill		2,454
Net assets acquired		$ 8,606

Acquisition Acquisition (Revenu

Acquisition Acquisition (Revenues and Earnings from MarkWest Included in Consolidated Statements of Income) (Details) - MarkWest [Member] $ in Millions	12 Months Ended
	Dec. 31, 2014USD ($)
Business Acquisition [Line Items]
Revenues and other income	$ 126
Income from operations	$ 32

Acquisitions (Pro Forma Financi

Acquisitions (Pro Forma Financial Information) (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Acquisitions [Abstract]
Revenues and other income	$ 2,424	$ 2,707
Net income attributable to MPLX LP	$ 154	$ 248
Net income attributable to MPLX LP per unit - basic	$ 0.20	$ 1.02
Net income attributable to MPLX LP per unit - diluted	$ 0.19	$ 0.96

Acquisitions (Pro Forma Narrati

Acquisitions (Pro Forma Narrative) (Details) - USD ($) $ in Millions	Dec. 04, 2015	Dec. 03, 2015	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Business Acquisition, Pro Forma Information, Description			The unaudited pro forma information includes adjustments primarily to align accounting policies, to adjust depreciation expense to reflect the fair value of property, plant and equipment, increase amortization expense related to identifiable intangible assets, adjust interest expense related to the fair value of MarkWest’s long-term debt and remove approximately $90 million of transaction related costs, as well as the related income tax effects.
MarkWest Utica EMG [Member]
Business Acquisition [Line Items]
Equity Method Investment, Ownership Percentage			60.00%
Deconsolidation, Date	Dec. 4, 2015
EMG Utica [Member]
Business Acquisition [Line Items]
Noncontrolling Owners Accrual of Preference Amount		$ 41		$ 37

Acquisitions (Pro Forma Informa

Acquisitions (Pro Forma Information - Historical MarkWest Utica EMG Information) (Details) - USD ($) $ in Millions	3 Months Ended									11 Months Ended	12 Months Ended
	Dec. 31, 2015	[1]	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 03, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Revenues	$ 257		$ 141	$ 140	$ 130	$ 132	$ 131	$ 126	$ 131		$ 703	$ 548	$ 486
Less: Net income attributable to noncontrolling interests											1	57	68
Net income attributable to MPLX LP	$ 18		$ 42	$ 50	$ 46	$ 29	$ 30	$ 28	$ 34		$ 156	121	$ 78
MarkWest Utica EMG [Member]
Business Acquisition [Line Items]
Revenues										$ 152		85
Cost of revenue excluding depreciation and amortization										27		48
Depreciation and Amortization										61		50
Less: Net income attributable to noncontrolling interests										64		31
Net income attributable to MPLX LP										$ (5)		$ (46)
[1]	(1) These amounts include results from the MarkWest Merger which closed on December 4, 2015. See Note 4 for more information on the MarkWest Merger.

Acquisition (Purchases of Pipe

Acquisition (Purchases of Pipe Line Holdings) (Details) - USD ($) $ in Millions	Dec. 04, 2015	Dec. 01, 2014	Mar. 01, 2014	May. 02, 2013	Dec. 03, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Business Acquisition [Line Items]
Payments to acquire businesses			$ 310	$ 100		$ 12	$ 910	$ 100
Purchase of additional interest in Pipe Line Holdings						(12)	(910)	(100)
Noncontrolling Interest [Member]
Business Acquisition [Line Items]
Purchase of additional interest in Pipe Line Holdings	$ 6	$ 335	138
General Partner [Member]
Business Acquisition [Line Items]
Decrease in general partner equity	$ 6	$ 465	$ 172			6	638	46
MPC [Member] | Noncontrolling Interest [Member]
Business Acquisition [Line Items]
Purchase of additional interest in Pipe Line Holdings						$ (6)	$ (472)	$ (54)
Ownership percentage		0.50%			0.50%
MPLX Pipe Line Holdings LP [Member]
Business Acquisition [Line Items]
Ownership percentage		99.50%
Pipe Line Holding [Member]
Business Acquisition [Line Items]
Effective date of acquisition	Dec. 4, 2015	Dec. 1, 2014	Mar. 1, 2014	May 1, 2013
Payments to acquire businesses	$ 12	$ 600
Percentage of partners interest acquired	0.50%	22.875%	13.00%	5.00%
Percentage Of Partners Interest Contributed		7.625%
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned		$ 200
Percentage of Partners Interest Purchased and Contributed		30.50%
Pipe Line Holding [Member] | Noncontrolling Interest [Member]
Business Acquisition [Line Items]
Purchase of additional interest in Pipe Line Holdings				$ 54
Pipe Line Holding [Member] | General Partner [Member]
Business Acquisition [Line Items]
Decrease in general partner equity				$ 46
Cash [Member] | Pipe Line Holding [Member]
Business Acquisition [Line Items]
Payments to acquire businesses			$ 40
Revolving Credit Facility [Member] | Pipe Line Holding [Member]
Business Acquisition [Line Items]
Payments to acquire businesses			$ 270

Acquisition (Summary of Changes

Acquisition (Summary of Changes in MPLX LP's Ownership Interest in Pipe Line Holdings) (Details) - USD ($) $ in Millions	Dec. 04, 2015	Dec. 01, 2014	Mar. 01, 2014	Dec. 31, 2015	[1]	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
Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net [Line Items]
Net income attributable to MPLX LP				$ 18		$ 42	$ 50	$ 46	$ 29	$ 30	$ 28	$ 34	$ 156	$ 121	$ 78
Transfer to noncontrolling interest:
Change from net income attributable to MPLX LP and transfer to noncontrolling interest													150	(517)	32
General Partner [Member]
Transfer to noncontrolling interest:
Decrease in general partner-MPC equity for purchases of additional interest in Pipe Line Holdings	$ (6)	$ (465)	$ (172)										$ (6)	$ (638)	$ (46)
[1]	(1) These amounts include results from the MarkWest Merger which closed on December 4, 2015. See Note 4 for more information on the MarkWest Merger.

Equity Method Investments Equ63

Equity Method Investments Equity Method Investments (Narrative) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Feb. 28, 2013
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 2,458	$ 2,458	$ 0
Other income - related parties		27	$ 23	$ 19
Equity Method Investment, Difference Between Carrying Amount and Underlying Equity	$ 961	$ 961
Markwest Utica EMG
Schedule of Equity Method Investments [Line Items]
NCI owners total funding commitment					$ 950
Percentage of capital required by reporting entity after NCI minimum contribution					100.00%
Aggregate Contributions to VIE Threshold					$ 2,000
Maximum percentage ownership interest in joint ventures	70.00%	70.00%
Threshold percentage for noncontrolling owners to make pro rata contributions	30.00%	30.00%
Maximum noncontrolling percentage of capital contributions until pro rata ownership threshhold is reached		10.00%
Noncontrolling interest owners actual contribution	$ 996	$ 996
Contribution by the Partnership	1,500	$ 1,500
Noncontrolling interest owners capital contribution preference threshold					$ 500
Noncontrolling Owners Accrual of Preference Amount	$ 4
Percentage of available cash to be received by the Partnership	60.00%	60.00%
Percentage of aggregate investment balance for proportionate distribution of cash	60.00%	60.00%
Percentage of aggregate investment balance	56.00%	56.00%
Equity method investments	$ 2,200	$ 2,200
Other income - related parties	1
Equity Method Investment Difference Between Carrying Amount And Underlying Equity Portion Related To Goodwill Not Amortized	371	$ 371
Ohio Gathering
Schedule of Equity Method Investments [Line Items]
Other income - related parties	$ 2
Equity Method Investment, Ownership Percentage	36.00%	36.00%
Ohio Condensate Company, LLC [Member]
Schedule of Equity Method Investments [Line Items]
Other income - related parties	$ 1
Equity Method Investment, Ownership Percentage	60.00%	60.00%
Utica Condensate
Schedule of Equity Method Investments [Line Items]
Subsidiary of Limited Liability Company or Limited Partnership, Ownership Interest		100.00%
Investment in subsidiary	$ 781	$ 781

Equity Method Investments Equ64

Equity Method Investments Equity Method Investments (Summary of Equity Method Investment Financial Information) (Details) $ in Millions	1 Months Ended
	Dec. 31, 2015USD ($)
Schedule of Equity Method Investments [Line Items]
Revenue	$ 29
Income from operations	10
Net income	11
Current assets	150
Noncurrent assets	2,619
Current liabilities	102
Noncurrent liabilities	13
Markwest Utica EMG
Schedule of Equity Method Investments [Line Items]
Revenue	18	[1]
Income from operations	9	[1]
Net income	10	[1]
Current assets	113	[1]
Noncurrent assets	2,207	[1]
Current liabilities	77	[1]
Noncurrent liabilities	1	[1]
Other VIEs
Schedule of Equity Method Investments [Line Items]
Revenue	2
Income from operations	0
Net income	0
Current assets	7
Noncurrent assets	169
Current liabilities	7
Noncurrent liabilities	12
Non-VIEs
Schedule of Equity Method Investments [Line Items]
Revenue	9
Income from operations	1
Net income	1
Current assets	30
Noncurrent assets	243
Current liabilities	18
Noncurrent liabilities	$ 0
[1]	(1) MarkWest Utica EMG’s noncurrent assets includes its investment in its subsidiary Ohio Gathering, which does not appear elsewhere in this table. The investment was $781 million as of December 31, 2015.

Related Party Agreements and 65

Related Party Agreements and Transactions (Narrative) (Detail) $ in Millions	1 Months Ended	3 Months Ended	9 Months Ended	12 Months Ended
	Dec. 31, 2015USD ($)Agreement	Dec. 31, 2015USD ($)Agreementbbl	Sep. 16, 2015bbl	Dec. 31, 2015USD ($)Agreement
Five Year Transportation Services Agreement [Member] | Commercial Agreements [Member] | Handling Crude Oil And Products [Member]
Commercial Agreements
Number of agreements	1	1		1
Ten Year Storage Services Agreement [Member] | Commercial Agreements [Member] | Storage Services Butane Cavern [Member]
Commercial Agreements
Number of agreements	1	1		1
MPC [Member]
Loan Agreement [Abstract]
Other Significant Noncash Transaction Value Of Consideration Given Or Received				$ 1
MPC [Member] | Commercial Agreements [Member] | Storage services tank farms [Member]
Commercial Agreements
Storage Capacity | bbl		2,626,000	1,386,000
Number of Tanks		4
MPC [Member] | Operating Agreements [Member]
Operating Agreements
Sales to related parties				$ 1
MPC [Member] | Operating Agreements [Member] | Minimum [Member]
Commercial Agreements
Duration of agreements (in years)				1 year
MPC [Member] | Operating Agreements [Member] | Maximum [Member]
Commercial Agreements
Duration of agreements (in years)				5 years
MPC [Member] | Management Services Agreements [Member]
Commercial Agreements
Number of agreements | Agreement	2	2		2
Management Services Agreements
Fees received for providing management services				$ 1
MPC [Member] | Employee Services Agreements [Member]
Commercial Agreements
Number of agreements | Agreement	2	2		2
MPC [Member] | Ten Year Transportation Services Agreement [Member] | Commercial Agreements [Member] | Crude oil [Member]
Commercial Agreements
Number of agreements | Agreement	3	3		3
Duration of agreements (in years)				10 years
MPC [Member] | Ten Year Transportation Services Agreement [Member] | Commercial Agreements [Member] | Pipelines products [Member]
Commercial Agreements
Number of agreements | Agreement	4	4		4
Duration of agreements (in years)				10 years
MPC [Member] | Five Year Transportation Services Agreement [Member] | Commercial Agreements [Member] | Crude oil [Member]
Commercial Agreements
Number of agreements | Agreement	1	1		1
Duration of agreements (in years)				5 years
MPC [Member] | Five Year Transportation Services Agreement [Member] | Commercial Agreements [Member] | Handling Crude Oil And Products [Member]
Commercial Agreements
Duration of agreements (in years)				5 years
MPC [Member] | Ten Year Storage Services Agreement [Member] | Commercial Agreements [Member] | Storage Services Butane Cavern [Member]
Commercial Agreements
Duration of agreements (in years)				10 years
MPC [Member] | Three Year Storage Services Agreement [Member] | Commercial Agreements [Member] | Storage services tank farms [Member]
Commercial Agreements
Number of agreements | Agreement	4	4		4
Duration of agreements (in years)				3 years
MPC [Member] | Transportation Services Agreements [Member] | Commercial Agreements [Member] | Cornerstone pipeline system and Utica build out projects [Member]
Commercial Agreements
Duration of agreements (in years)				15 years
Number of renewals	2	2		2
Renewal term agreement				5 years
MPC [Member] | Transportation Services Agreements [Member] | Commercial Agreements [Member] | Crude oil and product pipeline [Member]
Commercial Agreements
Number of renewals	2	2		2
Renewal term agreement				5 years
MPC [Member] | Transportation Services Agreements [Member] | Commercial Agreements [Member] | Wood River To Patoka System And Barge Dock [Member]
Commercial Agreements
Number of renewals	4	4		4
Renewal term agreement				2 years
MPC [Member] | Storage Services Agreements [Member] | Commercial Agreements [Member] | Storage services tank farms [Member]
Commercial Agreements
Renewal term agreement				1 year
Hardin Street Transportation LLC [Member] | Operating Agreements [Member]
Commercial Agreements
Duration of agreements (in years)				1 year
Renewal term agreement				1 year
Operating Agreements
Sales to related parties				$ 12
Centennial Pipeline Llc [Member] | MPC [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage	50.00%	50.00%		50.00%
Muskegon [Member] | MPC [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage	60.00%	60.00%		60.00%
MarkWest Utica EMG [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage	60.00%	60.00%		60.00%
Ohio Gathering
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage	36.00%	36.00%		36.00%
MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage	67.00%	67.00%		67.00%
Ohio Condensate Company, LLC [Member]
Related Party Transaction [Line Items]
Equity Method Investment, Ownership Percentage	60.00%	60.00%		60.00%
Related Party Revolving Credit Agreement [Member] | MPC Investment [Member]
Loan Agreement [Abstract]
Line of Credit Facility, Initiation Date	Dec. 4, 2015
Line of Credit Facility, Current Borrowing Capacity	$ 500	$ 500		$ 500
Expiration date	Dec. 4, 2020
Description of variable rate basis	LIBOR plus 1.50 percent
Proceeds from Long-term Lines of Credit	$ 301
Repayments of Long-term Lines of Credit	293
Long-term Debt, Gross	$ 8	$ 8		$ 8
Debt Instrument, Interest Rate, Effective Percentage	1.744%	1.744%		1.744%
Related Party Revolving Credit Agreement [Member] | MPL Investment LLC [Member]
Loan Agreement [Abstract]
Line of Credit Facility, Current Borrowing Capacity	$ 50	$ 50		$ 50
Expiration date				Dec. 31, 2015

Related Party Agreements and 66

Related Party Agreements and Transactions (Revenue from Related Parties) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Service revenue to related parties	$ 481	$ 451	$ 384
Product sales to related parties	1	0	0
MPC [Member]
Related Party Transaction [Line Items]
Service revenue to related parties	481	451	384
Product sales to related parties	$ 1	$ 0	$ 0

Related Party Agreements and 67

Related Party Agreements and Transactions (Summary of Fees Received for Operating Pipelines for Related Parties Included in Other Income - Related Parties) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Other income - related parties	$ 27	$ 23	$ 19
MPC [Member]
Related Party Transaction [Line Items]
Other income - related parties	24	22	18
Centennial Pipeline Llc [Member]
Related Party Transaction [Line Items]
Other income - related parties	1	1	1
Ohio Gathering
Related Party Transaction [Line Items]
Other income - related parties	$ 2	$ 0	$ 0

Related Party Agreements and 68

Related Party Agreements and Transactions Related Party Agreements and Transactions (Charges related to Omnibus Agreement) (Details) - MPC [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 59	$ 56	$ 49
Purchases From Related Parties [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	25	25	18
General and administrative expenses [Member]
Related Party Transaction [Line Items]
Related Party Transaction, Expenses from Transactions with Related Party	$ 34	$ 31	$ 31

Related Party Agreements and 69

Related Party Agreements and Transactions (Summary of Related Party Costs Added to Property, Plant and Equipment) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
MPC [Member] | Asset under construction [Member]
Property, Plant and Equipment [Line Items]
Costs added to property, plant and equipment	$ 13	$ 8	$ 8

Related Party Agreements and 70

Related Party Agreements and Transactions (Summary of Allocated Related Party Employee Benefit Costs by Income Statement Line Item) (Detail) - MPC [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Expenses incurred under employee services agreements	$ 97	$ 97	$ 93
Purchases From Related Parties [Member]
Related Party Transaction [Line Items]
Expenses incurred under employee services agreements	77	73	77
General and administrative expenses [Member]
Related Party Transaction [Line Items]
Expenses incurred under employee services agreements	$ 20	$ 24	$ 16

Related Party Agreements and 71

Related Party Agreements and Transactions (Receivables from Related Parties) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Receivables from related parties	$ 88	$ 41
MPC [Member]
Related Party Transaction [Line Items]
Receivables from related parties	76	41
Centennial Pipeline Llc [Member]
Related Party Transaction [Line Items]
Receivables from related parties	1	0
MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. [Member]
Related Party Transaction [Line Items]
Receivables from related parties	2	0
MarkWest Utica EMG [Member]
Related Party Transaction [Line Items]
Receivables from related parties	4	0
Ohio Gathering
Related Party Transaction [Line Items]
Receivables from related parties	$ 5	$ 0

Related Party Agreements and 72

Related Party Agreements and Transactions Related Party Agreements and Transactions (Long Term Receivables from Related Parties) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Long-term receivables from related parties	$ 25	$ 0
MPC [Member]
Related Party Transaction [Line Items]
Long-term receivables from related parties	$ 25	$ 0

Related Party Agreements and 73

Related Party Agreements and Transactions (Payables to Related Parties) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Payables to related parties	$ 47	$ 20
MPC [Member]
Related Party Transaction [Line Items]
Payables to related parties	26	20
MarkWest Utica EMG [Member]
Related Party Transaction [Line Items]
Payables to related parties	$ 21	$ 0

Related Party Agreements and 74

Related Party Agreements and Transactions (Deferred Revenue from Related Parties) (Details) - MPC [Member] - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Deferred Revenue Related Parties	$ 41	$ 35
Minimum Committed Volume Contracts [Member]
Related Party Transaction [Line Items]
Deferred Revenue Related Parties	36	30
Reimbursable Projects [Member]
Related Party Transaction [Line Items]
Deferred Revenue Related Parties	$ 5	$ 5

Net Income Per Limited Partne75

Net Income Per Limited Partner Unit (Schedule of Distributions by Partner Class) (Detail) - USD ($) $ in Millions		3 Months Ended									12 Months Ended
		Dec. 31, 2015	[1]	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
Net Income Per Share [Line Items]
Potentially dilutive securities											0	0
Net income attributable to MPLX LP		$ 18		$ 42	$ 50	$ 46	$ 29	$ 30	$ 28	$ 34	$ 156	$ 121	$ 78
Less: distribution declared											(315)	(112)	(88)
Undistributed net (loss) income attributable to MPLX LP											(159)	9	(10)
Limited Partners Common Units [Member]
Net Income Per Share [Line Items]
Net income attributable to MPLX LP											97	58	39
Less: distribution declared	[2]										(224)	(54)	(43)
MPC [Member]
Net Income Per Share [Line Items]
Less: distribution declared		$ (29)		$ (27)	$ (25)	$ (23)	$ (21)	$ (19)	$ (19)	$ (18)
MPC [Member] | General Partner [Member]
Net Income Per Share [Line Items]
Net income attributable to MPLX LP											57	8	2
Less: distribution declared	[2]										(60)	(6)	(2)
MPC [Member] | Limited Partners Subordinated Units [Member]
Net Income Per Share [Line Items]
Net income attributable to MPLX LP											2	55	37
Less: distribution declared	[2]										$ (31)	$ (52)	$ (43)
[1]	(1) These amounts include results from the MarkWest Merger which closed on December 4, 2015. See Note 4 for more information on the MarkWest Merger.
[2]	(1) See Note 8 for information regarding the distribution.

Net Income Per Limited Partne76

Net Income Per Limited Partner Unit (Basic and Diluted Earnings Per Unit) (Detail) - USD ($) $ / shares in Units, shares in Millions, $ in Millions		3 Months Ended									12 Months Ended
		Dec. 31, 2015	[1]	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
Net income attributable to MPLX LP:
Cash distributions declared											$ 315	$ 112	$ 88
Undistributed net income loss attributable to MPLX LP											(159)	9	(10)
Net income attributable to MPLX LP		$ 18		$ 42	$ 50	$ 46	$ 29	$ 30	$ 28	$ 34	$ 156	$ 121	$ 78
Weighted average units outstanding:
Basic (shares)											99	76	75
Diluted (shares)											100	76	75
Limited Partners Common Units [Member]
Net income attributable to MPLX LP:
Cash distributions declared	[2]										$ 224	$ 54	$ 43
Undistributed net income loss attributable to MPLX LP											(127)	4	(4)
Net income attributable to MPLX LP											$ 97	$ 58	$ 39
Weighted average units outstanding:
Basic (shares)											79	37.4	37
Diluted (shares)											80	37.4	37
Net income attributable to MPLX LP subsequent to initial public offering per limited partner unit:
Basic (in USD per unit)		$ (0.14)		$ 0.41	$ 0.50	$ 0.46	$ 0.38	$ 0.37	$ 0.37	$ 0.41	$ 1.23	$ 1.55	$ 1.05
Diluted (in USD per unit)		$ (0.14)		$ 0.41	$ 0.50	$ 0.46	$ 0.38	$ 0.37	$ 0.37	$ 0.41	$ 1.22	$ 1.55	$ 1.05
MPC [Member]
Net income attributable to MPLX LP:
Cash distributions declared		$ 29		$ 27	$ 25	$ 23	$ 21	$ 19	$ 19	$ 18
MPC [Member] | General Partner [Member]
Net income attributable to MPLX LP:
Cash distributions declared	[2]										$ 60	$ 6	$ 2
Undistributed net income loss attributable to MPLX LP											(3)	2	0
Net income attributable to MPLX LP											$ 57	$ 8	$ 2
Weighted average units outstanding:
Basic (shares)											2	2	1
Diluted (shares)											2	2	1
MPC [Member] | Limited Partners Subordinated Units [Member]
Net income attributable to MPLX LP:
Cash distributions declared	[2]										$ 31	$ 52	$ 43
Undistributed net income loss attributable to MPLX LP											(29)	3	(6)
Net income attributable to MPLX LP											$ 2	$ 55	$ 37
Weighted average units outstanding:
Basic (shares)											18	37	37
Diluted (shares)											18	37	37
Net income attributable to MPLX LP subsequent to initial public offering per limited partner unit:
Basic (in USD per unit)											$ 0.11	$ 1.50	$ 1.01
Diluted (in USD per unit)											$ 0.11	$ 1.50	$ 1.01
[1]	(1) These amounts include results from the MarkWest Merger which closed on December 4, 2015. See Note 4 for more information on the MarkWest Merger.
[2]	(1) See Note 8 for information regarding the distribution.

Equity (Units Outstanding) (Det

Equity (Units Outstanding) (Details) - shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Stockholders Equity [Line Items]
Aggregate percentage of general partner interest	2.00%
General partner units outstanding	6,800,475
Unit conversion	19,318	15,795
Limited Partners Common Units [Member]
Stockholders Equity [Line Items]
Common units outstanding	296,687,176
Subordinated Units [Member]
Stockholders Equity [Line Items]
Equity Instruments Conversion Date	Aug. 17, 2015
Unit conversion	36,951,515
MPC [Member] | Limited Partners Common Units [Member]
Stockholders Equity [Line Items]
Common units outstanding	56,932,134

Equity (MarkWest Merger) (Detai

Equity (MarkWest Merger) (Details)	Dec. 04, 2015$ / sharesshares	Dec. 31, 2015shares
Stockholders Equity [Line Items]
Units Acquired		229,493,171
MarkWest [Member]
Stockholders Equity [Line Items]
Common Units Conversion Ratio	1.09
Units Acquired	216,350,465
Class B Units Conversion Ratio	1
Cash consideration to unitholders | $ / shares	$ 6.20
Class A Units [Member] | MarkWest [Member]
Stockholders Equity [Line Items]
Units Acquired		28,554,313
Class B Units [Member] | MarkWest [Member]
Stockholders Equity [Line Items]
Units Acquired		7,981,756

Equity (ATM Program) (Details)

Equity (ATM Program) (Details) - USD ($) $ in Millions	May. 18, 2015	Dec. 08, 2014	Dec. 31, 2015	Dec. 31, 2014
Stockholders Equity [Line Items]
Units Offered			25,680	3,520,408
Partners' Capital Account, Public Sale of Units Net of Offering Costs		$ 221
ATM Program [Member]
Stockholders Equity [Line Items]
Equity Instrument Regulatory Filing Date	May 18, 2015
Common Units Aggregate Value	$ 500
Partners' Capital Account, Public Sale of Units Net of Offering Costs			$ 1
Limited Partners Common Units [Member]
Stockholders Equity [Line Items]
Units Offered				3,450,000
Limited Partners Common Units [Member] | ATM Program [Member]
Stockholders Equity [Line Items]
Units Offered			25,166

Equity (Changes in Partners Cap

Equity (Changes in Partners Capital, Unit Rollforward) (Details) - USD ($) $ / shares in Units, $ in Millions	Dec. 04, 2015	Dec. 08, 2014	Dec. 01, 2014	Mar. 01, 2014	May. 02, 2013	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2012
Stockholders Equity [Line Items]
Balance at December 31, 2013							81,931,238	75,411,255
Unit conversion							19,318	15,795
Units Acquired							229,493,171
Units Offered							25,680	3,520,408
Balance at December 31, 2014						81,931,238	81,931,238	75,411,255	75,411,255
Balance at December 31, 2015						81,931,238	311,469,407	81,931,238
2014 Activity [Abstract]
Shares Issued, Price Per Share		$ 66.68
Partners' Capital Account, Public Sale of Units Net of Offering Costs		$ 221
Issuance of units							$ 1	$ 230
Limited Partners Common Units [Member]
Stockholders Equity [Line Items]
Balance at December 31, 2013							43,341,098	36,951,515
Unit conversion							18,932	15,479
Units Offered								3,450,000
Balance at December 31, 2014						43,341,098	43,341,098	36,951,515	36,951,515
Balance at December 31, 2015						43,341,098	296,687,176	43,341,098
Class B Units [Member]
Stockholders Equity [Line Items]
Balance at December 31, 2014							7,981,756
Balance at December 31, 2015							7,981,756
Limited Partners Subordinated Units [Member]
Stockholders Equity [Line Items]
Balance at December 31, 2013							36,951,515	36,951,515
Balance at December 31, 2014						36,951,515	36,951,515	36,951,515	36,951,515
Balance at December 31, 2015						36,951,515	0	36,951,515
General Partner Units [Member]
Stockholders Equity [Line Items]
Balance at December 31, 2013							1,638,625	1,508,225
Unit conversion							386	316
Units Offered						130,084		70,408
Balance at December 31, 2014						1,638,625	1,638,625	1,508,225	1,508,225
Balance at December 31, 2015						1,638,625	6,800,475	1,638,625
2014 Activity [Abstract]
Issuance of units						$ 9
Pipe Line Holding [Member]
Stockholders Equity [Line Items]
Units Acquired								2,983,780
2014 Activity [Abstract]
Effective date of acquisition	Dec. 4, 2015		Dec. 1, 2014	Mar. 1, 2014	May 1, 2013
Percentage Of Partners Interest Contributed			7.625%
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned			$ 200
Pipe Line Holding [Member] | Limited Partners Common Units [Member]
Stockholders Equity [Line Items]
Units Acquired							2,924,104	2,924,104
2014 Activity [Abstract]
Shares Issued, Price Per Share			$ 68.397
Pipe Line Holding [Member] | General Partner Units [Member]
Stockholders Equity [Line Items]
Units Acquired								59,676
MarkWest [Member]
Stockholders Equity [Line Items]
Units Acquired	216,350,465
2014 Activity [Abstract]
Effective date of acquisition	Dec. 4, 2015
MarkWest [Member] | Limited Partners Common Units [Member]
Stockholders Equity [Line Items]
Units Acquired							216,350,465
MarkWest [Member] | Class B Units [Member]
Stockholders Equity [Line Items]
Units Acquired							7,981,756
MarkWest [Member] | General Partner Units [Member]
Stockholders Equity [Line Items]
Units Acquired							5,160,950
Units Offered						5,160,950
2014 Activity [Abstract]
Issuance of units	$ 169
Subordinated Units [Member]
Stockholders Equity [Line Items]
Unit conversion							36,951,515
Subordinated Units [Member] | Limited Partners Common Units [Member]
Stockholders Equity [Line Items]
Unit conversion							36,951,515
Subordinated Units [Member] | Limited Partners Subordinated Units [Member]
Stockholders Equity [Line Items]
Unit conversion							36,951,515
ATM Program [Member]
2014 Activity [Abstract]
Partners' Capital Account, Public Sale of Units Net of Offering Costs							$ 1
ATM Program [Member] | Limited Partners Common Units [Member]
Stockholders Equity [Line Items]
Units Offered							25,166
ATM Program [Member] | General Partner Units [Member]
Stockholders Equity [Line Items]
Units Offered							514
2014 Activity [Abstract]
Issuance of units							$ 1

Equity (Incentive Distribution

Equity (Incentive Distribution Rights) (Details)	12 Months Ended
	Dec. 31, 2015$ / shares
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Aggregate percentage of general partner interest	2.00%
Minimum Quarterly Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total quarterly distribution per unit target amount	$ 0.2625
Minimum Quarterly Distribution [Member] | Limited Partner [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	98.00%
Minimum Quarterly Distribution [Member] | General Partner [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	2.00%
First Target Distribution [Member] | Limited Partner [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	98.00%
First Target Distribution [Member] | General Partner [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	2.00%
Second Target Distribution [Member] | Limited Partner [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	85.00%
Second Target Distribution [Member] | General Partner [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	15.00%
Third Target Distribution [Member] | Limited Partner [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	75.00%
Third Target Distribution [Member] | General Partner [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	25.00%
Thereafter | Limited Partner [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	50.00%
Thereafter | General Partner [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Marginal percentage interest in distributions	50.00%
Minimum [Member] | First Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total quarterly distribution per unit target amount	$ 0.2625
Minimum [Member] | Second Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total quarterly distribution per unit target amount	0.301875
Minimum [Member] | Third Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total quarterly distribution per unit target amount	0.328125
Minimum [Member] | Thereafter
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total quarterly distribution per unit target amount	0.393750
Maximum [Member] | First Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total quarterly distribution per unit target amount	0.301875
Maximum [Member] | Second Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total quarterly distribution per unit target amount	0.328125
Maximum [Member] | Third Target Distribution [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Total quarterly distribution per unit target amount	$ 0.393750

Equity (Net Income Allocation)

Equity (Net Income Allocation) (Details) - USD ($) $ in Millions	3 Months Ended									12 Months Ended
	Dec. 31, 2015	[1]	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
Equity [Abstract]
Net income attributable to MPLX LP	$ 18		$ 42	$ 50	$ 46	$ 29	$ 30	$ 28	$ 34	$ 156	$ 121	$ 78
Incentive Distribution Rights And Other										55	4	0
Net income attributable to MPLX LP available to general and limited partners										101	117	78
General partner’s interest in net income attributable to MPLX LP										2	2	2
General partner’s interest in net income attributable to MPLX LP										$ 57	$ 6	$ 2
[1]	(1) These amounts include results from the MarkWest Merger which closed on December 4, 2015. See Note 4 for more information on the MarkWest Merger.

Equity (Cash Distributions) (De

Equity (Cash Distributions) (Details) - USD ($) $ / shares in Units, $ in Millions	Feb. 12, 2016	Feb. 04, 2016	Jan. 25, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Incentive Distribution Made to Managing Member or General Partner [Line Items]
General partner's distributions				$ 6	$ 2	$ 2
General partner's incentive distribution rights distributions				54	4	0
Total general partner's distributions				60	6	2
Limited partners' distributions				255	106	86
Cash distributions declared				315	112	88
Limited Partners Common Units [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Limited partners' distributions				224	54	43
Subordinated Units [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Limited partners' distributions				$ 31	$ 52	$ 43
Subsequent Event [Member]
Incentive Distribution Made to Managing Member or General Partner [Line Items]
Distribution made to limited partner, declaration date			Jan. 25, 2016
Distributions declared per limited partner common unit			$ 0.50
Distribution Made to Limited Partner, Distribution Date	Feb. 12, 2016
Distribution Made to Limited Partner, Date of Record		Feb. 4, 2016
Cash distributions declared			$ 189

Segment Information (Details)

Segment Information (Details)	Dec. 04, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Number of reportable segments		2
MarkWest [Member]
Segment Reporting Information [Line Items]
Effective date of acquisition	Dec. 4, 2015

Segment Information (Income fro

Segment Information (Income from operations and capital expenditures) (Details) - USD ($) $ in Millions	3 Months Ended									12 Months Ended
	Dec. 31, 2015	[1]	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]
Segment revenues										$ 36	$ 0	$ 0
Segment other income										8	5	4
Total segment revenues and other income	$ 257		$ 141	$ 140	$ 130	$ 132	$ 131	$ 126	$ 131	703	548	486
Operating Segments [Member]
Segment Reporting Information [Line Items]
Segment revenues										697
Segment other income										30
Total segment revenues and other income										727	548	486
Segment cost of revenues										316
Segment operating income before portion attributable to noncontrolling interest										411
Segment portion attributable to noncontrolling interest										13	85	106
Segment operating income attributable to MPLX LP										398	213	143
Operating Segments [Member] | L&S [Member]
Segment Reporting Information [Line Items]
Segment revenues										547	520	463
Segment other income										30	28	23
Total segment revenues and other income										577	548	486
Segment cost of revenues										254	250	237
Segment operating income before portion attributable to noncontrolling interest										323	298	249
Segment portion attributable to noncontrolling interest										1	85	106
Segment operating income attributable to MPLX LP										322	$ 213	$ 143
Operating Segments [Member] | G&P [Member]
Segment Reporting Information [Line Items]
Segment revenues										150
Segment other income										0
Total segment revenues and other income										150
Segment cost of revenues										62
Segment operating income before portion attributable to noncontrolling interest										88
Segment portion attributable to noncontrolling interest										12
Segment operating income attributable to MPLX LP										$ 76
[1]	(1) These amounts include results from the MarkWest Merger which closed on December 4, 2015. See Note 4 for more information on the MarkWest Merger.

Segment Information (Reconcilia

Segment Information (Reconciliation to Income from operations) (Details) - USD ($) $ in Millions	3 Months Ended									12 Months Ended
	Dec. 31, 2015	[1]	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, Revenue Reconciling Item [Line Items]
Income from equity method investments										$ 3	$ 0	$ 0
Other income - related parties										27	23	19
Depreciation and amortization										(89)	(50)	(49)
General and administrative expenses										(104)	(65)	(53)
Income from operations	$ 50		$ 47	$ 58	$ 51	$ 39	$ 44	$ 44	$ 56	206	183	147
Operating Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Segment operating income attributable to MPLX LP										398	213	143
Segment portion attributable to noncontrolling interest										13	85	106
Segment Reconciling Items [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Segment portion attributable to unconsolidated affiliates										(21)	0	0
Income from equity method investments										3	0	0
Other income - related parties										2	0	0
Unrealized derivative gains										$ 4	$ 0	$ 0
[1]	(1) These amounts include results from the MarkWest Merger which closed on December 4, 2015. See Note 4 for more information on the MarkWest Merger.

Segment Information (Reconcil87

Segment Information (Reconciliation to Total revenues and other income) (Details) - USD ($) $ in Millions	3 Months Ended									12 Months Ended
	Dec. 31, 2015	[1]	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, Revenue Reconciling Item [Line Items]
Revenues	$ 257		$ 141	$ 140	$ 130	$ 132	$ 131	$ 126	$ 131	$ 703	$ 548	$ 486
Equity in earnings of subsidiaries										3	0	0
Other income - related parties										27	23	19
Operating Segments [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenues										727	548	486
Segment Reconciling Items [Member]
Segment Reporting, Revenue Reconciling Item [Line Items]
Revenue adjustment for unconsolidated affiliates										(28)	0	0
Equity in earnings of subsidiaries										3	0	0
Other income - related parties										2	0	0
Derivative, Loss on Derivative										$ (1)	$ 0	$ 0
[1]	(1) These amounts include results from the MarkWest Merger which closed on December 4, 2015. See Note 4 for more information on the MarkWest Merger.

Segment Information (Reconcil88

Segment Information (Reconciliation to Net Income Attributable to Noncontrolling Interests (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Reconciliation to Net Income Attributable to Noncontrolling Interests [Line Items]
Net income attributable to noncontrolling interests	$ 1	$ 57	$ 68
Operating Segments [Member]
Reconciliation to Net Income Attributable to Noncontrolling Interests [Line Items]
Segment portion attributable to noncontrolling interest	13	85	106
Segment Reconciling Items [Member]
Reconciliation to Net Income Attributable to Noncontrolling Interests [Line Items]
Portion of noncontrolling interests related to items below segment income from operations	(7)	(28)	(38)
Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates	$ (5)	$ 0	$ 0

Segment Information (Reconcil89

Segment Information (Reconciliation of Segment Capital Expenditures) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting, Other Significant Reconciling Item [Line Items]
Additions to property, plant and equipment		$ (264)	$ (79)	$ (107)
Operating Segments [Member]
Segment Reporting, Other Significant Reconciling Item [Line Items]
Additions to property, plant and equipment		(288)	(79)	(107)
Operating Segments [Member] | L&S [Member]
Segment Reporting, Other Significant Reconciling Item [Line Items]
Additions to property, plant and equipment		(188)	(79)	(107)
Operating Segments [Member] | G&P [Member]
Segment Reporting, Other Significant Reconciling Item [Line Items]
Additions to property, plant and equipment	[1]	(100)	0	0
Segment Reconciling Items [Member]
Segment Reporting, Other Significant Reconciling Item [Line Items]
Additions to property, plant and equipment		$ (24)	$ 0	$ 0
[1]	(1) The G&P segment includes $24 million of capital expenditures related to Partnership operated, non-wholly owned subsidiaries.

Segment Information (Assets by

Segment Information (Assets by Segment) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 15,677	$ 1,214
Operating Segments [Member] | L&S [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	1,431	1,214
Operating Segments [Member] | G&P [Member]
Segment Reporting, Asset Reconciling Item [Line Items]
Assets	$ 14,246	$ 0

Major Customer and Concentrat91

Major Customer and Concentration of Credit Risk (Details)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
MPC [Member] | Revenues And Other Income [Member] | Customer Concentration Risk [Member]
Concentration Risk [Line Items]
Concentration risk, percentage	72.00%	86.00%	83.00%

Income Taxes (Narrative) (Detai

Income Taxes (Narrative) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Taxes [Line Items]
Provision for income tax	$ 2	$ 0	$ 0
Income tax rate	1.00%	(1.00%)
Federal statutory rate	35.00%
Interest and penalties, net expenses (benefits)	$ 1	$ (1)	(1)
Accrual of interest and penalties	$ 1
Minimum [Member]
Income Taxes [Line Items]
Open Tax Year	2,011
Maximum [Member]
Income Taxes [Line Items]
Provision for income tax		(1)	$ (1)
Accrual of interest and penalties		$ 1
Open Tax Year	2,014
MarkWest Hydrocarbon [Member] | Federal [Member]
Income Taxes [Line Items]
Operating Loss Carryforwards	$ 58
MarkWest Hydrocarbon [Member] | Federal [Member] | Minimum [Member]
Income Taxes [Line Items]
Operating Loss Carryforwards, Expiration Period	2,033
MarkWest Hydrocarbon [Member] | Federal [Member] | Maximum [Member]
Income Taxes [Line Items]
Operating Loss Carryforwards, Expiration Period	2,035
MarkWest Hydrocarbon [Member] | State [Member]
Income Taxes [Line Items]
Operating Loss Carryforwards	$ 4
MarkWest Hydrocarbon [Member] | State [Member] | Minimum [Member]
Income Taxes [Line Items]
Operating Loss Carryforwards, Expiration Period	2,017
MarkWest Hydrocarbon [Member] | State [Member] | Maximum [Member]
Income Taxes [Line Items]
Operating Loss Carryforwards, Expiration Period	2,035

Income Taxes (Components of Tax

Income Taxes (Components of Tax Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Federal	$ 3
State	(1)
Total deferred	2	$ 0	$ 0
Provision for income tax	$ 2	$ 0	$ 0

Income Taxes (Reconciliation of

Income Taxes (Reconciliation of Federal Statutory Income Tax Rate) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Entity Information [Line Items]
Income before provision for income tax		$ 159	$ 178	$ 146
Federal statutory rate		35.00%
Federal income tax at statutory rate(1)		$ 3
State income taxes net of federal benefit - MarkWest Hydrocarbon		(1)
Provision on income from Class A units(1)	[1]	1
Other		(1)
Provision for income tax		2	$ 0	$ 0
Reportable Legal Entities [Member] | MarkWest Hydrocarbon [Member]
Entity Information [Line Items]
Income before provision for income tax		$ 9
Federal statutory rate		35.00%
Federal income tax at statutory rate(1)		$ 3
State income taxes net of federal benefit - MarkWest Hydrocarbon		0
Provision on income from Class A units(1)	[1]	1
Other		(1)
Provision for income tax		3
Reportable Legal Entities [Member] | Partnership [Member]
Entity Information [Line Items]
Income before provision for income tax		$ 149
Federal statutory rate		0.00%
Federal income tax at statutory rate(1)		$ 0
State income taxes net of federal benefit - MarkWest Hydrocarbon		(1)
Provision on income from Class A units(1)		0
Other		0
Provision for income tax		(1)
Eliminations [Member]
Entity Information [Line Items]
Income before provision for income tax		$ 1
Federal statutory rate		0.00%
Federal income tax at statutory rate(1)		$ 0
State income taxes net of federal benefit - MarkWest Hydrocarbon		0
Provision on income from Class A units(1)		0
Other		0
Provision for income tax		$ 0
[1]	(1) MarkWest Hydrocarbon pays tax on its share of the Partnership’s income or loss as a result of its ownership of Class A units.

Income Taxes (Components of Def

Income Taxes (Components of Deferred Tax Assets and Liabilities) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Deferred Tax Assets, Net [Abstract]
Derivatives		$ 9	$ 0
Net operating loss carryforwards		62	0
Total deferred tax assets		71
Deferred Tax Liabilities, Net [Abstract]
Property, plant and equipment		6	0
Investments in subsidiaries and affiliates		442	0
Total deferred tax liabilities		448
Deferred Tax Liabilities, Net	[1]	$ 377	$ 0
[1]	(1) See Note 3 for discussion regarding a recently adopted accounting standard related to deferred tax assets and liabilities.

Inventories (Details)

Inventories (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Inventory Disclosure [Abstract]
NGLs	$ 3	$ 0
Line fill	5	0
Spare parts, materials and supplies	41	12
Total inventories	$ 49	$ 12

Property, Plant and Equipment97

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	$ 10,118	$ 1,361
Less accumulated depreciation	435	353
Property, plant and equipment, net	9,683	1,008
Natural gas gathering and NGL transportation pipelines and facilities [Member]
Property, Plant and Equipment [Line Items]
Property plant and equipment, gross	4,307	0
Processing, fractionation and storage facilities [Member]
Property, Plant and Equipment [Line Items]
Property plant and equipment, gross	3,185	166
Pipelines and related assets [Member]
Property, Plant and Equipment [Line Items]
Property plant and equipment, gross	1,128	1,081
Land, building, office equipment and other [Member]
Property, Plant and Equipment [Line Items]
Property plant and equipment, gross	559	29
Asset under construction [Member]
Property, Plant and Equipment [Line Items]
Property plant and equipment, gross	$ 939	$ 85
Minimum [Member] | Natural gas gathering and NGL transportation pipelines and facilities [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	15 years
Minimum [Member] | Processing, fractionation and storage facilities [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	24 years
Minimum [Member] | Pipelines and related assets [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	19 years
Minimum [Member] | Land, building, office equipment and other [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	10 years
Maximum [Member] | Natural gas gathering and NGL transportation pipelines and facilities [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	30 years
Maximum [Member] | Processing, fractionation and storage facilities [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	37 years
Maximum [Member] | Pipelines and related assets [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	42 years
Maximum [Member] | Land, building, office equipment and other [Member]
Property, Plant and Equipment [Line Items]
Estimated Useful Lives	25 years

Property Plant and Equipment (N

Property Plant and Equipment (Narrative) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Interest Cost Capitalized And Depreciation And Amortization Expenses For Property, Plant and Equipment [Line Items]
Accumulated depreciation	$ 435	$ 353
Assets Held under Capital Leases [Member]
Interest Cost Capitalized And Depreciation And Amortization Expenses For Property, Plant and Equipment [Line Items]
Capital leases	25	25
Accumulated depreciation	$ 7	$ 7

Fair Value Measurements - Recur

Fair Value Measurements - Recurring (Financial Instruments by Valuation Hierarchy) (Details) - Fair Value, Measurements, Recurring [Member] $ in Millions	Dec. 31, 2015USD ($)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	$ 9
Liabilities	(32)
Natural gas swap [Member] | Significant other observable inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0
Commodity contracts | Significant other observable inputs (Level 2)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	2
Liabilities	0
Commodity contracts | Significant unobservable inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	7
Liabilities	0
Embedded derivatives in commodity contracts | Significant unobservable inputs (Level 3)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Assets	0
Liabilities	$ (32)

Fair Value Measurements - Re100

Fair Value Measurements - Recurring (Significant Unobservable Inputs in Level 3 Valuation) (Details) - Significant unobservable inputs (Level 3)	12 Months Ended
	Dec. 31, 2015USD ($)
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Number Of Renewal Periods	2
Term of counterparty option to renew gas purchase agreement	5 years
Liability [Member] | Embedded derivatives in commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Probability of Renewal	50.00%	[1]
Minimum [Member] | Assets [Member] | Ethanol prices [Member] | Commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	$ 0.0016
Minimum [Member] | Assets [Member] | Propane Contract [Member] | Commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0039
Minimum [Member] | Assets [Member] | Isobutane Contract [Member] | Commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0054
Minimum [Member] | Assets [Member] | Normal Butane Contract [Member] | Commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0051
Minimum [Member] | Assets [Member] | Natural Gasoline Contract [Member] | Commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0089
Minimum [Member] | Liability [Member] | Propane Contract [Member] | Embedded derivatives in commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0039	[2]
Minimum [Member] | Liability [Member] | Isobutane Contract [Member] | Embedded derivatives in commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0053	[2]
Minimum [Member] | Liability [Member] | Normal Butane Contract [Member] | Embedded derivatives in commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0048	[2]
Minimum [Member] | Liability [Member] | Natural Gasoline Contract [Member] | Embedded derivatives in commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0089	[2]
Minimum [Member] | Liability [Member] | Natural Gas Contract [Member] | Embedded derivatives in commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0218	[3]
Minimum [Member] | Liability [Member] | ERCOT Pricing [Member] | Embedded derivatives in commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Commodity Price	0.2308
Maximum [Member] | Assets [Member] | Ethanol prices [Member] | Commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0019
Maximum [Member] | Assets [Member] | Propane Contract [Member] | Commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0044
Maximum [Member] | Assets [Member] | Isobutane Contract [Member] | Commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0057
Maximum [Member] | Assets [Member] | Normal Butane Contract [Member] | Commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0057
Maximum [Member] | Assets [Member] | Natural Gasoline Contract [Member] | Commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0093
Maximum [Member] | Liability [Member] | Propane Contract [Member] | Embedded derivatives in commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0049	[2]
Maximum [Member] | Liability [Member] | Isobutane Contract [Member] | Embedded derivatives in commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0064	[2]
Maximum [Member] | Liability [Member] | Normal Butane Contract [Member] | Embedded derivatives in commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0060	[2]
Maximum [Member] | Liability [Member] | Natural Gasoline Contract [Member] | Embedded derivatives in commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0104	[2]
Maximum [Member] | Liability [Member] | Natural Gas Contract [Member] | Embedded derivatives in commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Forward Commodity Price	0.0339	[3]
Maximum [Member] | Liability [Member] | ERCOT Pricing [Member] | Embedded derivatives in commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Commodity Price	$ 0.4458
First Five Year Term [Member] | Liability [Member] | Embedded derivatives in commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Probability of Renewal	50.00%
Second Five Year Term [Member] | Liability [Member] | Embedded derivatives in commodity contracts
Fair Value Inputs, Assets and Liabilities, Quantitative Information [Line Items]
Fair Value Inputs Probability of Renewal	75.00%
[1]	(3)
[2]	(1) NGL prices used in the valuation are generally at the lower end of the range in the early years and increase over time.
[3]	(2) Natural gas prices used in the valuations are generally at the lower end of the range in the early years and increase over time.

Fair Value Measurements Fair Va

Fair Value Measurements Fair Value Measurements - Recurring (Changes in Level 3 Measurements) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Commodity Derivative Contracts (net)
Derivative assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy [Roll Forward]
Fair value at beginning of period	$ 0
Net positions assumed in conjunction with the MarkWest Merger	7
Total gain (realized and unrealized) included in earnings(1)	3	[1]
Settlements	(3)
Fair value at end of period	7
The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at end of period	2
Embedded Derivatives in Commodity Contracts (net)
Derivative assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy [Roll Forward]
Fair value at beginning of period	0
Net positions assumed in conjunction with the MarkWest Merger	(38)
Total gain (realized and unrealized) included in earnings(1)	5	[1]
Settlements	1
Fair value at end of period	(32)
The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at end of period	$ 5
[1]	(1) Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in Product sales in the accompanying Consolidated Statements of Income. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in Costs of revenue and Purchased product costs.

Fair Value Measurements Fair102

Fair Value Measurements Fair Value Measurements - Reported (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 04, 2015	Dec. 31, 2014
Reported Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	$ 5,255		$ 635
SMR liability	100
Estimate of Fair Value Measurement [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term debt	5,212		$ 636
SMR liability	$ 99
MarkWest [Member] | Senior Notes [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt assumed in MarkWest Merger		$ 4,100

Derivative Financial Instrum103

Derivative Financial Instruments Derivative Financial Instruments (Volume of Derivative Activity) (Details) - Commodity contracts - Not Designated as Hedging Instrument [Member] - Short [Member]	Dec. 31, 2015bblgal
Derivative [Line Items]
Crude Oil (bbl) | bbl	109,800
NGLs (gal) | gal	43,837,756

Derivative Financial Instrum104

Derivative Financial Instruments (Embedded Derivatives in Commodity Contracts) (Details) - Embedded derivatives in commodity contracts $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Embedded derivative in natural gas processing and purchase contract [Member]
Derivative [Line Items]
Notional amount for embedded derivative in commodity contract (in Dth per day)	9,000
Number of renewals	2
Embedded Derivative Renewal Term	5 years
Embedded Derivative Fair Value of Embedded Derivative Liability Including Inception Value Allocable to Host Contract	$ (31)
Embedded derivative in electricity purchase contract [Member]
Derivative [Line Items]
Embedded Derivative, Fair Value of Embedded Derivative Liability	$ 1

Derivative Financial Instrum105

Derivative Financial Instruments (Derivatives Balance Sheet Location) (Details) - Commodity contracts $ in Millions	Dec. 31, 2015USD ($)
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	$ 9
Derivative Liability, Fair Value, Gross Liability	(32)
Other Current Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	9
Other Current Liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	(5)
Other Noncurrent Assets [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Gross Asset	0
Deferred credits and other liabilities [Member]
Derivatives, Fair Value [Line Items]
Derivative Liability, Fair Value, Gross Liability	$ (27)

Derivative Financial Instrum106

Derivative Financial Instruments (Derivatives Income Statement Location) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Product Sales [Member]
Product sales [Abstract]
Realized gain	$ 4
Unrealized loss	(1)
Total revenue: derivative gain from product sales	3
Purchased product costs [Abstract]
Unrealized gain	4
Total gain	3
Purchased product costs [Member]
Product sales [Abstract]
Realized gain	5
Total revenue: derivative gain from product sales	8
Purchased product costs [Abstract]
Unrealized gain	5
Total gain	$ 8

Debt (Summary of Outstanding Bo

Debt (Summary of Outstanding Borrowings) (Details) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Debt and Capital Lease Obligations		$ 5,736	$ 645
Unamortized Debt Issuance Expense	[1]	8	0
Debt Instrument, Unamortized Discount	[2]	472	0
Amounts due within one year		1	1
Total long-term debt due after one year		5,255	644
Mplx Lp [Member] | Line of Credit [Member] | MPLX Revolver [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		877	385
Mplx Lp [Member] | Unsecured Debt [Member] | MPLX Term Loan [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		250	250
Mplx Lp [Member] | Senior Notes [Member] | 5.500% senior notes due 2023
Debt Instrument [Line Items]
Long-term Debt, Gross		710	0
Mplx Lp [Member] | Senior Notes [Member] | 4.500% senior notes due 2023
Debt Instrument [Line Items]
Long-term Debt, Gross		989	0
Mplx Lp [Member] | Senior Notes [Member] | 4.875% senior notes due 2024
Debt Instrument [Line Items]
Long-term Debt, Gross		1,149	0
Mplx Lp [Member] | Senior Notes [Member] | 4.000% senior notes due 2025
Debt Instrument [Line Items]
Long-term Debt, Gross		500	0
Mplx Lp [Member] | Senior Notes [Member] | 4.875% senior notes due 2025
Debt Instrument [Line Items]
Long-term Debt, Gross		1,189	0
MarkWest [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross		63
Debt Instrument, Unamortized Discount		465
MarkWest [Member] | Senior Notes [Member] | 5.500% senior notes due 2023
Debt Instrument [Line Items]
Long-term Debt, Gross		40	0
MarkWest [Member] | Senior Notes [Member] | 4.500% senior notes due 2023
Debt Instrument [Line Items]
Long-term Debt, Gross		11	0
MarkWest [Member] | Senior Notes [Member] | 4.875% senior notes due 2024
Debt Instrument [Line Items]
Long-term Debt, Gross		1	0
MarkWest [Member] | Senior Notes [Member] | 4.875% senior notes due 2025
Debt Instrument [Line Items]
Long-term Debt, Gross		11	0
Marathon Pipe Line Llc [Member] | Capital Lease Obligations [Member]
Debt Instrument [Line Items]
MPL - capital lease obligations due 2020		$ 9	$ 10
[1]	(1) The Partnership adopted the updated FASB debt issuance cost standard as of June 30, 2015. This has been applied retrospectively and there was no effect to the prior period presented.
[2]	(2) 2015 includes $465 million discount related to the difference between the fair value and the principal amount of the assumed MarkWest debt.

Debt (Summary of Outstanding108

Debt (Summary of Outstanding Borrowings Interest Rates and Table Due Dates) (Details)	12 Months Ended
	Dec. 31, 2015	Feb. 12, 2015
Mplx Lp [Member] | MPLX Revolver [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date	Dec. 4, 2020
Mplx Lp [Member] | MPLX Term Loan [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date	Nov. 20, 2019
Mplx Lp [Member] | 4.000% senior notes due 2025
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.00%
Mplx Lp [Member] | Line of Credit [Member] | MPLX Revolver [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date	Dec. 4, 2020
Mplx Lp [Member] | Unsecured Debt [Member] | MPLX Term Loan [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date	Nov. 20, 2019
Mplx Lp [Member] | Senior Notes [Member] | 5.500% senior notes due 2023
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt Instrument, Maturity Date	Feb. 15, 2023
Mplx Lp [Member] | Senior Notes [Member] | 4.500% senior notes due 2023
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Debt Instrument, Maturity Date	Jul. 15, 2023
Mplx Lp [Member] | Senior Notes [Member] | 4.875% senior notes due 2024
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.875%
Debt Instrument, Maturity Date	Dec. 1, 2024
Mplx Lp [Member] | Senior Notes [Member] | 4.000% senior notes due 2025
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.00%
Debt Instrument, Maturity Date	Feb. 15, 2025
Mplx Lp [Member] | Senior Notes [Member] | 4.875% senior notes due 2025
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.875%
Debt Instrument, Maturity Date	Jun. 1, 2025
MarkWest [Member] | Senior Notes [Member] | 5.500% senior notes due 2023
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Debt Instrument, Maturity Date	Feb. 15, 2023
MarkWest [Member] | Senior Notes [Member] | 4.500% senior notes due 2023
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Debt Instrument, Maturity Date	Jul. 15, 2023
MarkWest [Member] | Senior Notes [Member] | 4.875% senior notes due 2024
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.875%
Debt Instrument, Maturity Date	Dec. 1, 2024
MarkWest [Member] | Senior Notes [Member] | 4.875% senior notes due 2025
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	4.875%
Debt Instrument, Maturity Date	Jun. 1, 2025
Marathon Pipe Line Llc [Member] | Capital Lease Obligations [Member]
Debt Instrument [Line Items]
Capital Lease Due Date Year	2,020

Debt (Schedule of Debt Payments

Debt (Schedule of Debt Payments) (Detail) $ in Millions	Dec. 31, 2015USD ($)
Debt Disclosure [Abstract]
2,016	$ 1
2,017	1
2,018	1
2,018	1
2,019	$ 1,132

Debt (Credit Agreements) (Detai

Debt (Credit Agreements) (Detail) $ in Millions	Dec. 04, 2015USD ($)	Nov. 21, 2014	Nov. 19, 2014USD ($)	Dec. 31, 2015USD ($)	Dec. 03, 2015USD ($)	Dec. 31, 2014USD ($)	Nov. 20, 2014USD ($)
MPLX Revolver [Member] | Mplx Operations Llc [Member]
Debt Instrument [Line Items]
Term of senior unsecured revolving credit agreement (in years)				5 years
MPLX Revolver [Member] | Mplx Operations Llc [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Effective Percentage						1.535%
Line of Credit Facility, Initiation Date				Sep. 14, 2012
Proceeds from Long-term Lines of Credit			$ 280
MPLX Revolver [Member] | Mplx Operations Llc [Member] | Maximum [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity				$ 500
MPLX Revolver [Member] | Mplx Lp [Member]
Debt Instrument [Line Items]
Debt Instrument, Issuance Date		Nov. 20, 2014
Debt Instrument, Term				5 years
Line of Credit Facility, Expiration Date				Dec. 4, 2020
Debt Instrument, Interest Rate, Effective Percentage				1.617%
Description of variable rate basis				Adjusted LIBOR or the Alternate Base Rate (as defined in the MPLX Credit Agreement), at our election, plus a specified margin
Proceeds from Long-term Lines of Credit				$ 992
Repayments of Long-term Lines of Credit				500
Letters of Credit Outstanding, Amount				8
Line of Credit Facility, Remaining Borrowing Capacity				$ 1,120
Line of Credit Facility, Remaining Borrowing Capacity, Percentage				55.80%
MPLX Revolver [Member] | Mplx Lp [Member] | Maximum [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity				$ 2,000	$ 1,000
Increase in borrowing capacity	$ 1,000
Line Of Credit Facility Additional Borrowing Capacity				$ 500
Covenant of ratio of consolidated net debt to consolidated EBITDA (in ratio)				5
Number of prior quarterly reporting periods used in determining compliance with covenant of ratio of consolidated net debt to consolidated EBITDA				4
Covenant of ratio of consolidated net debt to consolidated EBITDA following certain acquisitions (in ratio)				5.5
MPLX Revolver [Member] | Mplx Lp [Member] | Letter of credit [Member] | Maximum [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity				$ 250
MPLX Revolver [Member] | Mplx Lp [Member] | Swingline Loan [Member] | Maximum [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Current Borrowing Capacity				$ 100
MPLX Term Loan [Member] | Mplx Lp [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity							$ 250
Line of Credit Facility, Expiration Date				Nov. 20, 2019
Number Of Renewal Periods				2
Line Of Credit Facility Duration Of Renewal Period		1 year
Debt Instrument, Interest Rate, Effective Percentage				1.67%
Line of Credit [Member] | MPLX Revolver [Member] | Mplx Lp [Member]
Debt Instrument [Line Items]
Line of Credit Facility, Expiration Date				Dec. 4, 2020
Long-term Debt, Gross				$ 877		$ 385
MarkWest [Member]
Debt Instrument [Line Items]
Repayments of Long-term Lines of Credit	93
MarkWest [Member] | MPLX Revolver [Member]
Debt Instrument [Line Items]
Repayments of Long-term Lines of Credit	$ 850
MarkWest [Member] | Line of Credit [Member]
Debt Instrument [Line Items]
Repayments of Long-term Lines of Credit				$ 943

Debt (Senior Notes) (Details)

Debt (Senior Notes) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 22, 2015	Dec. 04, 2015	Feb. 12, 2015	Dec. 31, 2014
MarkWest [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross			$ 4,100
Debt Instrument, Face Amount		$ 4,040
MarkWest [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 63
MarkWest [Member] | Senior Notes [Member] | 5.500% senior notes due 2023
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 40				$ 0
Debt Instrument, Maturity Date	Feb. 15, 2023
Debt Instrument, Interest Rate, Stated Percentage	5.50%
MarkWest [Member] | Senior Notes [Member] | 4.500% senior notes due 2023
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 11				0
Debt Instrument, Maturity Date	Jul. 15, 2023
Debt Instrument, Interest Rate, Stated Percentage	4.50%
MarkWest [Member] | Senior Notes [Member] | 4.875% senior notes due 2024
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1				0
Debt Instrument, Maturity Date	Dec. 1, 2024
Debt Instrument, Interest Rate, Stated Percentage	4.875%
MarkWest [Member] | Senior Notes [Member] | 4.875% senior notes due 2025
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 11				0
Debt Instrument, Maturity Date	Jun. 1, 2025
Debt Instrument, Interest Rate, Stated Percentage	4.875%
Mplx Lp [Member] | 4.000% senior notes due 2025
Debt Instrument [Line Items]
Debt Instrument, Face Amount				$ 500
Debt Instrument, Interest Rate, Stated Percentage				4.00%
Proceeds from (Repayments of) Debt	$ 495
Mplx Lp [Member] | Senior Notes [Member] | 5.500% senior notes due 2023
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 710				0
Debt Instrument, Maturity Date	Feb. 15, 2023
Debt Instrument, Interest Rate, Stated Percentage	5.50%
Mplx Lp [Member] | Senior Notes [Member] | 4.500% senior notes due 2023
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 989				0
Debt Instrument, Maturity Date	Jul. 15, 2023
Debt Instrument, Interest Rate, Stated Percentage	4.50%
Mplx Lp [Member] | Senior Notes [Member] | 4.875% senior notes due 2024
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,149				0
Debt Instrument, Maturity Date	Dec. 1, 2024
Debt Instrument, Interest Rate, Stated Percentage	4.875%
Mplx Lp [Member] | Senior Notes [Member] | 4.875% senior notes due 2025
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 1,189				0
Debt Instrument, Maturity Date	Jun. 1, 2025
Debt Instrument, Interest Rate, Stated Percentage	4.875%
Mplx Lp [Member] | Senior Notes [Member] | 4.000% senior notes due 2025
Debt Instrument [Line Items]
Long-term Debt, Gross	$ 500				$ 0
Debt Instrument, Maturity Date	Feb. 15, 2025
Debt Instrument, Interest Rate, Stated Percentage				4.00%

Goodwill and Intangibles Goodwi

Goodwill and Intangibles Goodwill and Intangibles (Goodwill) (Details) - USD ($)	Dec. 04, 2015	Dec. 31, 2015	Dec. 31, 2014
Goodwill [Line Items]
Goodwill, Impairment Loss		$ 0	$ 0
Beginning balance		105,000,000
Acquisitions		2,454,000,000
Ending balance		2,559,000,000	105,000,000
L&S [Member]
Goodwill [Line Items]
Beginning balance		105,000,000
Acquisitions		0
Ending balance		105,000,000	105,000,000
G&P [Member]
Goodwill [Line Items]
Beginning balance		0
Acquisitions		2,454,000,000
Ending balance		$ 2,454,000,000	$ 0
MarkWest [Member]
Goodwill [Line Items]
Ending balance	$ 2,454,000,000
Effective date of acquisition	Dec. 4, 2015

Goodwill and Intangibles (Intan

Goodwill and Intangibles (Intangibles) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Accumulated Amortization		$ (2)
Intangibles, net	$ 466	0
Minimum [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life	11 years
Maximum [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Asset, Useful Life	25 years
L&S [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Accumulated Amortization		0
Intangibles, net	$ 0
G&P [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Accumulated Amortization		(2)
Intangibles, net	$ 466
Customer Relationships [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross		468
Customer Relationships [Member] | L&S [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross		0
Customer Relationships [Member] | G&P [Member]
Finite-Lived Intangible Assets [Line Items]
Finite-Lived Intangible Assets, Gross		$ 468

Goodwill and Intangibles (In114

Goodwill and Intangibles (Intangible Amortization) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Goodwill and Intangible Assets Disclosure [Abstract]
2,016	$ 32
2,017	32
2,018	32
2,019	32
2,020	32
Thereafter	306
Intangibles, net	$ 466	$ 0

Supplemental Cash Flow Infor115

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)	$ 13	$ 3	$ 0
Non-cash investing and financing activities:
Net transfers of property, plant and equipment to inventories	5	1	4
Contribution - common units issued	0	200	0
Acquisitions [Abstract]
Fair value of MPLX units issued(1)	7,326	0	0
Payable to seller	$ 50	$ 0	$ 0

Supplemental Cash Flow Infor116

Supplemental Cash Flow Information (Summary of 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 Elements [Abstract]
Increase (decrease) in capital accruals	$ 25	$ 12	$ (5)

Equity-Based Compensation Pl117

Equity-Based Compensation Plan (Narrative) (Detail) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)$ / sharesshares	Dec. 31, 2014USD ($)$ / shares	Dec. 31, 2013USD ($)$ / shares
Phantom Units [Member]
Unit-based awards under the Plan
Grant date fair value of performance units granted | $ / shares	$ 35	$ 49.56	$ 0
Outstanding Phantom Unit Awards
Convertible at December 31, 2015 | shares	472,665
Unrecognized compensation cost	$ 19
Cost not yet recognized, period for recognition	2 years 9 months
Performance Shares [Member]
Unit-based awards under the Plan
Grant date fair value of performance units granted | $ / shares	$ 1.03	$ 1.16	$ 0.77
Outstanding Phantom Unit Awards
Unrecognized compensation cost	$ 1
Cost not yet recognized, period for recognition	1 year 8 months
Mplx 2012 Incentive Compensation Plan [Member]
Compensation Expense
Total compensation expense	$ 4	$ 3	$ 1
Maximum [Member] | Mplx 2012 Incentive Compensation Plan [Member]
Description of the Plan
Common units available for delivery under the plan | shares	2,750,000
Officer [Member] | Mplx 2012 Incentive Compensation Plan [Member] | Phantom Units [Member]
Unit-based awards under the Plan
Award requisite service period	3 years
Accrued distributions	$ 1
Officer [Member] | Mplx 2012 Incentive Compensation Plan [Member] | Performance Shares [Member]
Unit-based awards under the Plan
Award requisite service period	36 months
Measurement period	4
Award percentage paid out in cash	75.00%
Award percentage paid out in stock	25.00%
Grant date fair value of performance units granted | $ / shares	$ 1.03	$ 1.16
General and administrative expenses [Member]
Compensation Expense
Stock-based compensation plans expenses	$ 1	$ 1	$ 1
MarkWest [Member] | Mplx 2012 Incentive Compensation Plan [Member]
Compensation Expense
Total compensation expense	$ 15

Equity-Based Compensation Pl118

Equity-Based Compensation Plan (Summary of Phantom Unit Award Activity) (Detail) - Phantom Units [Member] - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Number of Units
Outstanding at December 31, 2014	100,769
Granted	962,764
Settled	32,314
Forfeited	0
Outstanding at December 31, 2015	1,031,219	100,769
Vested and expected to vest at December 31, 2015	1,001,324
Convertible at December 31, 2015	472,665
Weighted Average Fair Value
Outstanding at December 31, 2014 (usd per share)	$ 41.66
Granted (usd per share)	35	$ 49.56	$ 0
Settled (usd per share)	$ 40.18
Forfeited (usd per share)
Outstanding at December 31, 2015 (usd per share)	$ 35.49	$ 41.66
Vested and expected to vest at December 31, 2014 (usd per share)	35.52
Convertible at December 31, 2014 (usd per share)	$ 34.26
Aggregate Intrinsic Value
Vested and expected to vest at December 31, 2015	$ 39,400
Convertible at December 31, 2015	$ 18,600

Equity-Based Compensation Pl119

Equity-Based Compensation Plan (Summary of Values Related To Vested and Unvested Restricted Stock Awards) (Details) - Phantom Units [Member] - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity-Based Compensation [Line Items]
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Vested In Period Total Intrinsic Value 1	$ 3	$ 1	$ 0
Grant date fair value of performance units granted	$ 35	$ 49.56	$ 0

Equity-Based Compensation Pl120

Equity-Based Compensation Plan (Summary of Performance Unit Award Activity) (Details) - Performance Shares [Member]	12 Months Ended
	Dec. 31, 2015$ / sharesshares
Number of Units
Outstanding at December 31, 2014 | shares	924,143
Granted | shares	597,249
Forfeited | shares	0
Outstanding at December 31, 2015 | shares	1,521,392
Weighted Average Fair Value
Outstanding at December 31, 2014 (usd per share) | $ / shares	$ 0.98
Granted (usd per share) | $ / shares	1.03
Forfeited (usd per share) | $ / shares	0
Outstanding at December 31, 2015 (usd per share) | $ / shares	$ 1

Equity-Based Compensation Pl121

Equity-Based Compensation Plan (Assumptions) (Details) - Performance Shares [Member] - $ / shares	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity-Based Compensation [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	30.12%	17.17%	16.75%
Grant date fair value of performance units granted	$ 1.03	$ 1.16	$ 0.77

Lease Operations Lease Operatio

Lease Operations Lease Operations (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Leases [Abstract]
Revenue from implicit lease arrangements	$ 16	$ 0	$ 0
Operating Leases of Lessor Contingent Rentals Received	$ 1	$ 0

Lease Operations (Schedule of M

Lease Operations (Schedule of Minimum Future Rentals on Non-cancellable Leases) (Details) $ in Millions	Dec. 31, 2015USD ($)
Leases [Abstract]
2,016	$ 174
2,017	184
2,018	185
2,019	186
2,020	185
2021 and thereafter	588
Total minimum future rentals	$ 1,502

Lease Operations (Schedule of I

Lease Operations (Schedule of Investment in Assets Held for Operating Lease) (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property Subject to or Available for Operating Lease [Line Items]
Property, plant and equipment	$ 1,482
Less: accumulated depreciation	(5)
Total property, plant and equipment	1,477	$ 0
Natural gas gathering and NGL transportation pipelines and facilities [Member]
Property Subject to or Available for Operating Lease [Line Items]
Property, plant and equipment	619
Natural gas processing facilities [Member]
Property Subject to or Available for Operating Lease [Line Items]
Property, plant and equipment	753
Construction in Progress [Member]
Property Subject to or Available for Operating Lease [Line Items]
Property, plant and equipment	$ 110

Asset Retirement Obligations (R

Asset Retirement Obligations (Reconciliation of Changes in the ARO) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Asset Retirement Obligations [Line Items]
Beginning ARO	$ 0
Asset Retirement Obligation, Liabilities Incurred	2
Ending ARO	17
MarkWest [Member]
Asset Retirement Obligations [Line Items]
Asset Retirement Obligation, Liabilities Assumed	$ 15

Asset Retirement Obligations As

Asset Retirement Obligations Asset Retirement Obligations (Narrative) (Details)	Dec. 31, 2015USD ($)
Asset Retirement Obligation Disclosure [Abstract]
Assets legally restricted for purposes of settling asset retirement obligations	$ 0

Commitments and Contingencies (

Commitments and Contingencies (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Commitments And Contingencies [Line Items]
Accrued liabilities for remediation	$ 1	$ 1
Contractual commitments to acquire property, plant and equipment	144
Environmental Loss Contingency [Member] | MPC [Member]
Commitments And Contingencies [Line Items]
Receivable from MPC for indemnification of environmental costs	$ 1	$ 0

Commitments and Contingencie128

Commitments and Contingencies (Minimum Future Payments) (Details) - Operating Leases Propane Storage And Transporation And Terminalling Agreements [Member] $ in Millions	Dec. 31, 2015USD ($)
Other Commitments [Line Items]
2,016	$ 68
2,017	74
2,018	60
2,019	59
2,020	59
2021 and thereafter	299
Total	$ 619

Commitments and Contingencie129

Commitments and Contingencies (Future Minimum Commitments) (Details) $ in Millions	Dec. 31, 2015USD ($)
Capital Lease Obligations
2,016	$ 1
2,017	1
2,018	2
2,019	2
2,020	5
Later years	0
Total minimum lease payments	11
Less imputed interest costs	2
Present value of net minimum lease payments	9
Operating Lease Obligations
2,016	49
2,017	49
2,018	40
2,019	35
2,020	30
Later years	100
Total minimum lease payments	$ 303

Commitments and Contingencie130

Commitments and Contingencies (Operating Lease Rental Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Commitments and Contingencies Disclosure [Abstract]
Operating Leases, Rent Expense	$ 14	$ 10	$ 10

Commitments and Contingencie131

Commitments and Contingencies (SMR Liability) (Details) - SMR [Member] - SMR Liability [Member] $ in Millions	Dec. 31, 2015USD ($)
Recorded Unconditional Purchase Obligation [Line Items]
2,016	$ 17
2,017	17
2,018	17
2,019	17
2,020	17
2021 and thereafter	162
Total minimum payments	247
Less: Services element	95
Less: Interest	52
Total SMR liability	100
Less: Current portion of SMR liability	4
Long-term portion of SMR liability	$ 96

Select Quarterly Financial D132

Select Quarterly Financial Data (Detail) - USD ($) $ / shares in Units, $ in Millions		Sep. 01, 2009	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 [Line Items]
Revenues			$ 257	[1]	$ 141	$ 140	$ 130	$ 132	$ 131	$ 126	$ 131	$ 703	$ 548	$ 486
Income from operations			50	[1]	47	58	51	39	44	44	56	206	183	147
Net income			18	[1]	42	51	46	37	43	42	56	157	178	146
Net income attributable to MPLX LP			18	[1]	42	50	46	29	30	28	34	156	121	78
Distributions declared: [Abstract]
Limited partner units												315	112	88
Incentive distribution rights - MPC												54	4	0
Total distributions declared			189	[1]	$ 47	$ 42	$ 37	33	$ 28	$ 26	$ 25
Assets
Property, plant and equipment, net			9,683					1,008				9,683	1,008
Liabilities
Accrued liabilities			186					11				186	11
Deferred credits and other liabilities			$ 166					$ 2				166	2
Limited Partners Common Units [Member]
Quarterly Financial Data [Line Items]
Net income attributable to MPLX LP												$ 97	$ 58	$ 39
Net income attributable to MPLX LP subsequent to initial public offering per limited partner unit:
Common - basic			$ (0.14)	[1]	$ 0.41	$ 0.50	$ 0.46	$ 0.38	$ 0.37	$ 0.37	$ 0.41	$ 1.23	$ 1.55	$ 1.05
Common - diluted			(0.14)	[1]	0.41	0.50	0.46	0.38	0.37	0.37	0.41	1.22	1.55	1.05
Distributions declared per limited partner common unit			0.5000	[1]	0.4700	0.4400	0.4100	0.3825	0.3575	0.3425	0.3275	$ 1.8200	$ 1.4100	$ 1.1675
Distributions declared: [Abstract]
Limited partner units	[2]											$ 224	$ 54	$ 43
Limited Partners Subordinated Units [Member]
Net income attributable to MPLX LP subsequent to initial public offering per limited partner unit:
Subordinated - basic and diluted			$ 0	[1]	$ 0	$ 0.50	$ 0.46	$ 0.33	$ 0.37	$ 0.37	$ 0.41
Public [Member]
Distributions declared: [Abstract]
Limited partner units			$ 120	[1]	$ 11	$ 10	$ 10	$ 9	$ 7	$ 6	$ 7
MPC [Member]
Distributions declared: [Abstract]
Limited partner units			29	[1]	27	25	23	21	19	19	18
General partner units - MPC			3	[1]	1	1	1	1	1	0	0
Incentive distribution rights - MPC			$ 37	[1]	$ 8	$ 6	$ 3	$ 2	$ 1	$ 1	$ 0
MPC [Member] | Limited Partners Subordinated Units [Member]
Quarterly Financial Data [Line Items]
Net income attributable to MPLX LP												$ 2	$ 55	$ 37
Net income attributable to MPLX LP subsequent to initial public offering per limited partner unit:
Common - basic												$ 0.11	$ 1.50	$ 1.01
Common - diluted												0.11	1.50	1.01
Subordinated - basic and diluted												$ 0.11	$ 1.50	$ 1.01
Distributions declared: [Abstract]
Limited partner units	[2]											$ 31	$ 52	$ 43
SMR [Member]
Property, Plant and Equipment [Line Items]
Proceeds from Liability		$ 73
Imputed Interest Rate on Liability			6.39%									6.39%
Assets
Property, plant and equipment, net			$ 69									$ 69
Liabilities
Accrued liabilities			4									4
Deferred credits and other liabilities			$ 96									$ 96
[1]	(1) These amounts include results from the MarkWest Merger which closed on December 4, 2015. See Note 4 for more information on the MarkWest Merger.
[2]	(1) See Note 8 for information regarding the distribution.