UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________________________________________

FORM 10-Q

_____________________________________________

(Mark One)



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

For the Quarterly Period Ended June 30, ~~2016~~2017



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

For the transition period from to

Commission file number 001-35714

_____________________________________________

MPLX LP

(Exact name of registrant as specified in its charter)

_____________________________________________



Delaware		27-0005456
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

200 E. Hardin Street, Findlay, Ohio		45840
(Address of principal executive offices)		(Zip code)

(419) ~~672-6500~~421-2414

(Registrant’s telephone number, including area code)

_____________________________________________

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

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

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



Large accelerated filer	x	Accelerated filer	¨

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

		Emerging growth company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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

MPLX LP had ~~335,635,872~~388,521,088 common units ~~3,990,878 Class B units~~ and ~~7,513,899~~7,929,000 general partner units outstanding at July 27, ~~2016.~~2017.

MPLX LP

Form 10-Q

Quarter Ended June 30, ~~2016~~2017

INDEX

Unless the context otherwise requires, references in this report to “MPLX LP,” “the Partnership,” “we,” “our,” “us,” 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”), MarkWest Hydrocarbon, ~~Inc.~~L.L.C. (“MarkWest Hydrocarbon”), MPLX Pipe Line Holdings LLC (“Pipe Line Holdings”) ~~and~~, Marathon Pipe Line LLC (“MPL”), Ohio River Pipe Line LLC (“ORPL”), Hardin Street Marine LLC (“HSM”), Hardin Street Transportation LLC (“HST”), Woodhaven Cavern LLC (“WHC”) and MPLX Terminals LLC (“MPLXT”). We have partial ownership interests in a number of joint venture legal entities, including MarkWest Pioneer, L.L.C. (“MarkWest Pioneer”), MarkWest Utica EMG, L.L.C. (“MarkWest Utica EMG”) and its subsidiary Ohio Gathering Company, L.L.C. (“Ohio Gathering”), Ohio Condensate Company, L.L.C. (“Ohio Condensate”), Wirth Gathering Partnership (“Wirth”) ~~and~~, MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. (“Jefferson Dry Gas”), Sherwood Midstream LLC (“Sherwood Midstream”), Sherwood Midstream Holdings LLC (“Sherwood Midstream Holdings”), MarEn Bakken Company, LLC (“MarEn Bakken”), Johnston County Terminal, LLC (“Johnston Terminal”) and Guilford County Terminal Company, LLC (“Guilford Terminal”). References to “MPC” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other than the Partnership. ~~References~~Unless otherwise specified, references to “Predecessor” refer collectively to HSM’s, HST’s, WHC’s and MPLXT’s related assets, liabilities and results of ~~operations.~~

operations prior to the dates of their respective acquisitions effective January 1, 2014 for HSM, January 1, 2015 for HST and WHC and April 1, 2016 for MPLXT.

~~Table of Contents~~

Glossary of Terms

The abbreviations, acronyms and industry technology used in this report are defined as follows.



ATM Program	A continuous offering, or at-the-market program, by which the Partnership may offer common units in amounts, at prices and on terms to be determined by market conditions and other factors at the time of any offerings, as defined by the prospectus supplement filed with the SEC on August 4, 2016
Bbl	Barrels
Bcf/d	One billion cubic feet of natural gas per day
Btu	One British thermal unit, an energy measurement
Condensate	A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions
DCF (a non-GAAP financial measure)	Distributable Cash Flow
Dth/d	Dekatherms per day
EBITDA (a non-GAAP financial measure)	Earnings Before Interest, Taxes, Depreciation and Amortization
EPA	United States Environmental Protection Agency
~~ERCOT~~	~~Electric Reliability Council of Texas~~
FASB	Financial Accounting Standards Board
GAAP	Accounting principles generally accepted in the United States of America
Gal	Gallon
Gal/d	Gallons per day
Initial Offering	Initial public offering on October 31, 2012
LIBOR	London Interbank Offered Rate
MarkWest Merger	On December 4, 2015, a wholly-owned subsidiary of the Partnership merged with MarkWest Energy Partners, L.P.
mbpd	Thousand barrels per day
MMBtu	One million British thermal units, an energy measurement
~~mmcf/~~MMcf/d	One million cubic feet of natural gas per day
Net operating margin (a non-GAAP financial measure)	Segment revenue, less segment purchased product costs, less realized derivative ~~gain (loss)~~gains (losses) related to purchased product costs
NGL	Natural gas liquids, such as ethane, propane, butanes and natural gasoline
OTC	Over-the-Counter
Predecessor	Collectively: - HSM’s related assets, liabilities and results of operations prior to the date of its acquisition, March 31, 2016, effective January 1, 2015. - HST’s, WHC’s and MPLXT’s related assets, liabilities and results of operations prior to the date of the acquisition, March 1, 2017, effective January 1, 2015 for HST and WHC and April 1, 2016 for MPLXT.
Realized derivative gain/loss	The gain or loss recognized when a derivative matures or is settled
SEC	U.S. Securities and Exchange Commission
SMR	Steam methane reformer, operated by a third party and located at the Javelina gas processing and fractionation complex in Corpus Christi, Texas
Unrealized derivative gain/loss	The gain or loss recognized on a derivative due to changes in fair value prior to the instrument maturing or settling
VIE	Variable interest entity
WTI	West Texas Intermediate

~~Table of Contents~~

Part I—Financial Information

Item 1. Financial Statements

MPLX LP

Consolidated Statements of Income (Unaudited)


	Three Months Ended June 30,						Six Months Ended June 30,					Three Months Ended June 30,					Six Months Ended June 30,
(In millions, except per unit data)	2016				2015⁽¹⁾		2016			2015⁽¹⁾		2017		2016⁽¹⁾			2017		2016⁽¹⁾
Revenues and other income:
Service revenue	$	233			$	16	$	462		$	32	$	286	$	233		$	546	$	462
Service revenue - related parties	145				152		295			294		270		246			525		423
Rental income	71				—		141			—		70		71			139		141
Rental income - related parties	29				25		55			50		70		66			137		104
Product sales	137				—		237			—		191		137			394		237
Product sales - related parties	3				—		6			—		2		3			4		6
Loss from equity method investments	(83		)		—		(78		)	—
Gain on sale of assets												—		—			1		—
Income (loss) from equity method investments												1		(83		)	6		(78		)
Other income	1				2		3			3		1		1			3		3
Other income - related parties	28				18		52			35		25		24			47		45
Total revenues and other income	564				213		1,173			414		916		698			1,802		1,343
Costs and expenses:
Cost of revenues (excludes items below)	84				46		173			88		139		113			252		207
Purchased product costs	114				—		193			—		140		114			271		193
Rental cost of sales	14				—		28			—		13		15			25		29
Rental cost of sales - related parties												1		1			1		1
Purchases - related parties	78				40		154			80		109		99			216		177
Depreciation and amortization	137				20		269			39		164		151			351		287
Impairment expense	1				—		130			—		—		1			—		130
General and administrative expenses	49			��	21		101			43		57		63			115		116
Other taxes	11				4		22			8		13		13			26		25
Total costs and expenses	488				131		1,070			258		636		570			1,257		1,165
Income from operations	76				82		103			156		280		128			545		178
Related party interest and other financial costs	—				—		1			—		—		—			—		1
Interest expense (net of amounts capitalized of $7 million, $1 million, $14 million and $1 million, respectively)	52				6		107			11
Interest expense (net of amounts capitalized of $11 million, $7 million, $18 million and $14 million, respectively)												74		52			140		107
Other financial costs	12				—		24			1		13		12			25		24
Income (loss) before income taxes	12				76		(29		)	144
Benefit for income taxes	(8		)		—		(12		)	—
Net income (loss)	20				76		(17		)	144
Income before income taxes												193		64			380		46
Provision (benefit) for income taxes												2		(8		)	2		(12		)
Net income												191		72			378		58
Less: Net income attributable to noncontrolling interests	1				1		1			1		1		1			2		1
Less: Net income attributable to Predecessor	—				24		23			46		—		52			36		98
Net income (loss) attributable to MPLX LP	19				51		(41		)	97		190		19			340		(41		)
Less: Preferred unit distributions	9				—		9			—		17		9			33		9
Less: General partner’s interest in net income attributable to MPLX LP	46				7		85			11		74		46			136		85
Limited partners’ interest in net (loss) income attributable to MPLX LP	$	(36	)		$	44	$	(135	)	$	86
Limited partners’ interest in net income (loss) attributable to MPLX LP												$	99	$	(36	)	$	171	$	(135	)
Per Unit Data (See Note 6)
Net (loss) income attributable to MPLX LP per limited partner unit:
Net income (loss) attributable to MPLX LP per limited partner unit:
Common - basic	$	(0.11	)		$	0.50	$	(0.43	)	$	0.96	$	0.26	$	(0.11	)	$	0.46	$	(0.43	)
Common - diluted	(0.11		)		0.50		(0.43		)	0.96		0.26		(0.11		)	0.46		(0.43		)
Subordinated - basic and diluted	—				0.50		—			0.96
Weighted average limited partner units outstanding:
Common - basic	331				43		316			43		377		331			370		316
Common - diluted	331				43		316			43		382		331			374		316
Subordinated - basic and diluted	—				37		—			37
Cash distributions declared per limited partner common unit	$	0.5100			$	0.4400	$	1.0150		$	0.8500	$	0.5625	$	0.5100		$	1.1025	$	1.0150


(1)	Financial information has been retrospectively adjusted for the acquisition of ~~Hardin Street Marine LLC~~HST, WHC and MPLXT from MPC. See Notes 1 and 3.

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

~~Table of Contents~~

MPLX LP

Consolidated Balance Sheets (Unaudited)


(In millions)	June 30, 2016		December 31, 2015		June 30, 2017			December 31, 2016
Assets
Current assets:
Cash and cash equivalents	$	35	$	43	$	293		$	234
Receivables, net	265		245		284			299
Receivables - related parties	113		187		173			247
Inventories	49		51		62			55
Other current assets	24		50		31			33
Total current assets	486		576		843			868
Equity method investments	2,485		2,458		3,368			2,471
Property, plant and equipment, net	10,360		9,997		11,638			11,408
Intangibles, net	511		466		473			492
Goodwill	2,199		2,570		2,245			2,245
Long-term receivables - related parties	26		25		16			11
Other noncurrent assets	12		12		18			14
Total assets	$	16,079	$	16,104	$	18,601		$	17,509
Liabilities
Current liabilities:
Accounts payable	$	102	$	91	$	144		$	140
Accrued liabilities	180		187		178			232
Payables - related parties	65		54		93			87
Deferred revenue					3			2
Deferred revenue - related parties	38		32		39			38
Accrued property, plant and equipment	163		168		171			146
Accrued taxes	32		27		39			38
Accrued interest payable	53		54		94			53
Other current liabilities	17		12		29			27
Total current liabilities	650		625		790			763
Long-term deferred revenue	9		4		26			12
Long-term deferred revenue - related parties	10		9		33			19
Long-term debt	4,400		5,255		6,666			4,422
Deferred income taxes	368		378		7			6
Deferred credits and other liabilities	176		166		170			177
Total liabilities	5,613		6,437		7,692			5,399
Commitments and contingencies (see Note 19)
Commitments and contingencies (see Note 17)
Redeemable preferred units	993		—		1,000			1,000
Equity
Common unitholders - public (252 million and 240 million units issued and outstanding)	7,658		7,691
Class B unitholders (8 million units issued and outstanding)	266		266
Common unitholder - MPC (79 million and 57 million units issued and outstanding)	1,049		465
Common unitholders - public (284 million and 271 million units issued and outstanding)					8,360			8,086
Class B unitholders (4 million and 4 million units issued and outstanding)					133			133
Common unitholder - MPC (90 million and 86 million units issued and outstanding)					1,161			1,069
Common unitholder - GP (9 million and 0 units issued and outstanding)					351			—
General partner - MPC (8 million and 7 million units issued and outstanding)	485		819		(242		)	1,013
Equity of Predecessor	—		413		—			791
Total MPLX LP partners’ capital	9,458		9,654		9,763			11,092
Noncontrolling interest	15		13
Noncontrolling interests					146			18
Total equity	9,473		9,667		9,909			11,110
Total liabilities, preferred units and equity	$	16,079	$	16,104	$	18,601		$	17,509

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

~~Table of Contents~~

MPLX LP

Consolidated Statements of Cash Flows (Unaudited)


	Six Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015⁽¹⁾			2017			2016⁽¹⁾
Increase (decrease) in cash and cash equivalents
Operating activities:
Net (loss) income	$	(17	)	$	144
Net income							$	378		$	58
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred financing costs	23			1			25			23
Depreciation and amortization	269			39			351			287
Impairment expense	130			—			—			130
Deferred income taxes	(13		)	(1		)	1			(13		)
Asset retirement expenditures	(2		)	—			(1		)	(2		)
Loss from equity method investments	78			—
Gain on disposal of assets							(1		)	—
(Income) loss from equity method investments							(6		)	78
Distributions from unconsolidated affiliates	78			—			66			78
Changes in:
Current receivables	(20		)	(2		)	17			(20		)
Inventories	(3		)	—			(2		)	(3		)
Change in fair value of derivatives	25			—
Fair value of derivatives							(22		)	25
Current accounts payable and accrued liabilities	18			12			(16		)	19
Receivables from / liabilities to related parties	6			(19		)	22			(12		)
All other, net	21			(1		)	32			22
Net cash provided by operating activities	593			173			844			670
Investing activities:
Additions to property, plant and equipment	(569		)	(70		)	(652		)	(606		)
Investments - loans from (to) related parties	77			(38		)
Acquisitions, net of cash acquired							(220		)	—
Disposal of assets							3			—
Investments - net related party loans							80			37
Investments in unconsolidated affiliates	(39		)	—			(640		)	(39		)
Distributions from unconsolidated affiliates - return of capital							24			—
All other, net	5			(1		)	1			5
Net cash used in investing activities	(526		)	(109		)	(1,404		)	(603		)
Financing activities:
Long-term debt - borrowings	434			528			2,241			434
- repayments	(1,311		)	(415		)	(1		)	(1,311		)
Related party debt - borrowings	1,853			—			12			1,853
- repayments	(1,861		)	—			(12		)	(1,861		)
Debt issuance costs	—			(4		)	(21		)	—
Net proceeds from equity offerings	321			1			443			321
Issuance of redeemable preferred units	984			—			—			984
Distribution to MPC for acquisition							(1,511		)	—
Distributions to preferred unitholders							(33		)	—
Distributions to unitholders and general partner	(391		)	(70		)	(505		)	(391		)
Distributions to noncontrolling interests	(1		)	(1		)	(2		)	(1		)
Contributions from noncontrolling interests	2			—			128			2
All other, net	(1		)	—			(7		)	(1		)
Distributions to MPC from Predecessor	(104		)	—			(113		)	(104		)
Net cash (used in) provided by financing activities	(75		)	39
Net (decrease) increase in cash and cash equivalents	(8		)	103
Net cash provided by (used in) financing activities							619			(75		)
Net increase (decrease) in cash and cash equivalents							59			(8		)
Cash and cash equivalents at beginning of period	43			27			234			43
Cash and cash equivalents at end of period	$	35		$	130		$	293		$	35


(1)	Financial information has been retrospectively adjusted for the acquisition of ~~Hardin Street Marine LLC~~HST, WHC and MPLXT from MPC. See Notes 1 and 3.

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

~~Table of Contents~~

MPLX LP

Consolidated Statements of Equity (Unaudited)


	Partnership																							Partnership
(In millions)	Common Unitholders Public			Class B Unitholders Public		Common Unitholder MPC			Subordinated Unitholder MPC			General Partner MPC			Noncontrolling Interests			Equity of Predecessor⁽¹⁾			Total			Common Unitholders Public			Class B Unitholders Public		Common Unitholder MPC			Common Unitholder GP			General Partner MPC			Non-controlling Interests			Equity of Predecessor⁽¹⁾			Total
Balance at December 31, 2014	$	639		$	—	$	261		$	217		$	(660	)	$	6		$	321		$	784
Issuance of units under ATM program	1			—		—			—			—			—			—			1
Net income	25			—		21			40			11			1			46			144
Distributions to unitholders and general partner	(19		)	—		(16		)	(29		)	(6		)	—			—			(70		)
Distributions to noncontrolling interests	—			—		—			—			—			(1		)	—			(1		)
Equity-based compensation	1			—		—			—			—			—			—			1
Balance at June 30, 2015	$	647		$	—	$	266		$	228		$	(655	)	$	6		$	367		$	859

Balance at December 31, 2015	$	7,691		$	266	$	465		$	—		$	819		$	13		$	413		$	9,667		$	7,691		$	266	$	465		$	—		$	819		$	13		$	692		$	9,946
Distributions to MPC from Predecessor	—			—		—			—			—			—			(104		)	(104		)	—			—		—			—			—			—			(104		)	(104		)
Issuance of units under ATM Program	315			—		—			—			6			—			—			321			315			—		—			—			6			—			—			321
Net (loss) income	(107		)	—		(28		)	—			85			1			23			(26		)	(107		)	—		(28		)	—			85			1			98			49
Contribution from MPC	—			—		12			—			3			—			—			15
Distribution to MPC	—			—		(12		)	—			(3		)	—			—			(15		)
Allocation of MPC's net investment at acquisition	—			—		669			—			(337		)	—			(332		)	—			—			—		669			—			(337		)	—			(332		)	—
Distributions to unitholders and general partner	(248		)	—		(57		)	—			(86		)	—			—			(391		)	(248		)	—		(57		)	—			(86		)	—			—			(391		)
Distributions to noncontrolling interest	—			—		—			—			—			(1		)	—			(1		)
Contributions from noncontrolling interest	—			—		—			—			—			2			—			2
Distributions to noncontrolling interests																								—			—		—			—			—			(1		)	—			(1		)
Contributions from noncontrolling interests																								—			—		—			—			—			2			—			2
Non-cash contribution from MPC																								—			—		—			—			—			—			334			334
Equity-based compensation	5			—		—			—			—			—			—			5			5			—		—			—			—			—			—			5
Deferred income tax impact from changes in equity	2			—		—			—			(2		)	—			—			—			2			—		—			—			(2		)	—			—			—
Balance at June 30, 2016	$	7,658		$	266	$	1,049		$	—		$	485		$	15		$	—		$	9,473		$	7,658		$	266	$	1,049		$	—		$	485		$	15		$	688		$	10,161

Balance at December 31, 2016																								$	8,086		$	133	$	1,069		$	—		$	1,013		$	18		$	791		$	11,110
Distributions to MPC from Predecessor																								—			—		—			—			—			—			(113		)	(113		)
Issuance of units under ATM Program																								434			—		—			—			9			—			—			443
Net income																								127			—		41			3			136			2			36			345
Contribution from MPC																								—			—		—			—			—			—			12			12
Allocation of MPC's net investment at acquisition																								—			—		573			350			(197		)	—			(726		)	—
Distribution to MPC for acquisition																								—			—		(430		)	—			(1,081		)	—			—			(1,511		)
Distributions to unitholders and general partner																								(289		)	—		(92		)	(2		)	(122		)	—			—			(505		)
Distributions to noncontrolling interests																								—			—		—			—			—			(2		)	—			(2		)
Contributions from noncontrolling interests																								—			—		—			—			—			128			—			128
Equity-based compensation																								2			—		—			—			—			—			—			2
Balance at June 30, 2017																								$	8,360		$	133	$	1,161		$	351		$	(242	)	$	146		$	—		$	9,909


(1)	Financial information has been retrospectively adjusted for the acquisition of ~~Hardin Street Marine LLC~~HST, WHC and MPLXT from MPC. See Notes 1 and 3.

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

~~Table of Contents~~

Notes to Consolidated Financial Statements (Unaudited)

1. Description of the Business and Basis of Presentation

Description of the Business – MPLX LP is a diversified, growth-oriented master limited partnership formed by ~~MPC.~~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 transportation, storage and ~~storage~~distribution of crude oil and refined petroleum ~~products. On December 4, 2015, the Partnership completed a merger with MarkWest (the “MarkWest Merger”). See Note 3~~products principally for ~~additional information.~~our sponsor.

The Partnership’s business consists of two segments based on the nature of services it offers: Logistics and Storage (“L&S”) focused on crude oil and refined petroleum products and Gathering and Processing (“G&P”) focused on natural gas and NGLs. 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~~interests 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 also 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 and HSM acquisition to conform to current classifications. These reclassifications had no effect on previously reported results of operations or retained earnings.

Effective March ~~31, 2016,~~1, 2017, the Partnership acquired ~~MPC’s inland marine business. This business is~~pipeline, storage and terminal businesses that are operated through ~~HSM. HSM’s related assets, liabilities~~HST, WHC and ~~results of operations are collectively referred to as the “Predecessor.”~~MPLXT (collectively with HSM, “Predecessor”) from MPC. The acquisition from MPC was considered a transfer between entities under common control. ~~As an entity under common control with MPC,~~Accordingly, the Partnership recorded the ~~assets acquired~~acquisition from MPC on its Consolidated Balance Sheets at MPC’s historical basis instead of fair value. Transfers of businesses between entities under common control require prior periods to be retrospectively adjusted to furnish comparative ~~information. Accordingly,~~information since inception of common control. Therefore, the accompanying consolidated financial statements and related notes of MPLX LP have been retrospectively adjusted to include the historical results of the ~~assets~~businesses acquired from MPC prior to the effective ~~date~~dates of the acquisition. See Note 3 for additional information regarding the ~~HSM~~HST, WHC and MPLXT acquisition. The accompanying financial statements and related notes present the combined financial position, results of operations, cash flows and equity of ~~the~~ Predecessor at historical cost. The financial statements of ~~the~~ Predecessor have been prepared from the separate records maintained by MPC and may not necessarily be indicative of the conditions or the results of operations that would have existed if ~~the~~ Predecessor had been operated as an unaffiliated entity.

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 customer 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. 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. Revenues and costs related to the portion of the revenue earned under these contracts considered to be implicit leases are recorded as ~~Rental income~~ ~~and~~ ~~Rental cost of sales~~, respectively, on the Consolidated Statements of Income. Similarly, the Partnership is considered to be the lessor under implicit operating lease arrangements with MPC in accordance with GAAP. The Partnership’s primary implicit lease operations with MPC relate to the transportation services agreement between HSM and MPC. Revenue related to this agreement is recorded as ~~Rental income - related parties~~ on the Consolidated Statements of Income. The rental cost of sales related to the HSM implicit lease is depreciation of the HSM assets. All other services are provided to MPC on an as-needed basis and recorded as ~~Service revenue-related parties~~ ~~on the Consolidated Statements of Income.~~

These interim consolidated financial statements are unaudited; however, in the opinion of the Partnership’s management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported. All such adjustments are of a normal, recurring nature unless otherwise disclosed. These interim consolidated financial statements, including the notes, have been prepared in accordance with the rules and regulations of the SEC applicable to interim period financial statements and do not include all of the information and disclosures required by GAAP for complete financial statements.

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These interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Annual Report on Form 10-K for the year ended December 31, 2015, as updated by our Current Report on Form 8-K/A filed on May 20, 2016. The results of operations for the three and six months ended ~~June 30, 2016~~ ~~are not necessarily indicative of the results to be expected for the full year.~~

In preparing the Consolidated Statements of Equity, net income attributable to MPLX LP is allocated to preferred unitholders based on a fixed distribution schedule, as discussed in Note 8, and subsequently allocated to the general partner and limited partner unitholders. Distributions, although earned, are not accrued for until declared. 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 limited partner unitholders based on their respective ownership percentages. The allocation of net income attributable to MPLX LP for purposes of calculating net income per limited partner unit is described in Note 6.

The accompanying interim consolidated financial statements are unaudited; however, in the opinion of the Partnership’s management, these statements reflect all adjustments necessary for a fair statement of the results for the periods reported. All such adjustments are of a normal, recurring nature unless otherwise disclosed. These interim consolidated financial statements, including the notes, have been prepared in accordance with the rules and regulations of the SEC applicable to interim period financial statements and do not include all of the information and disclosures required by GAAP for complete financial statements.

These interim consolidated financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto included in the Annual Report on Form 10-K for the year ended December 31, 2016, as updated by our Current Report on Form 8-K filed on May 1, 2017. The results of operations for the three and six months ended June 30, 2017 are not necessarily indicative of the results to be expected for the full year.

2. Accounting Standards

Recently Adopted

In ~~September 2015,~~October 2016, the FASB issued an accounting standard update to amend the consolidation guidance issued in February 2015 to require that eliminates the requirement to restate prior period financial statements for measurement period adjustments related to business combinations. This accounting standard update requires that the cumulative impact of a ~~measurement period adjustment be recognized~~decision maker consider, in the ~~reporting period~~determination of the primary beneficiary, its indirect interest in ~~which the adjustment~~a VIE held by a related party that is ~~identified.~~under common control on a proportionate basis only. The change was effective for ~~interim and annual periods~~the financial statements for fiscal years beginning after December 15, ~~2015. The Partnership recognized measurement period adjustments during the first and second quarters of~~ 2016, on a cumulative prospective basis as additional analysis was completed on the preliminary purchase price allocation for the acquisition of MarkWest. See Notes 3 and 16 for further discussion and detail related to these measurement period adjustments.

In April 2015, the FASB issued an accounting standard 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 was effective for fiscal years and interim periods within those fiscal ~~years beginning after December 15, 2015. Retrospective application is required.~~years. The Partnership ~~adopted this accounting~~was required to apply the standard ~~update in~~retrospectively to January 1, 2016, the ~~first quarter of 2016 and it did not have a material impact~~date on which the ~~consolidated results of operations, financial position or cash flows.~~

In April 2015, the FASB issued an accounting standard 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 was effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2015. Retrospective or prospective application is allowed. The Partnership adopted ~~this accounting standard update prospectively~~the consolidation guidance issued in ~~the first quarter of 2016 and it did not have a material impact on the consolidated results of operations, financial position or cash flows.~~

In February 2015, the FASB issued an accounting standard update making targeted changes to the current consolidation guidance. The accounting standard update changes the considerations related to substantive rights, related parties, and decision making fees when applying the VIE consolidation model and eliminates certain guidance for limited partnerships and similar entities under the voting interest consolidation model. The change was effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2015. The Partnership adopted this accounting standard update in the first quarter of 2017 and it did not have an impact on the consolidated financial statements.

In March 2016, the FASB issued an accounting standard update on the accounting for employee share-based payments. This update requires the recognition of income tax effects of awards through the income statement when awards vest or are settled. It also increases the amount an employer can withhold for tax purposes without triggering liability accounting. Lastly, it allows employers to make a policy election to account for forfeitures as they occur. The changes were effective for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. Under the new guidance, the Partnership will continue estimating forfeiture rates to calculate compensation cost. The Partnership adopted this accounting standard update in the first quarter of 2017 and it did not have a material impact on the consolidated ~~results of operations,~~ financial ~~position or cash flows.~~statements.

Not Yet Adopted

In May 2017, the FASB issued an accounting standard update to provide guidance about when changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting. An entity should account for the effects of a modification unless the fair value, vesting conditions and balance sheet classification of the modified award is the same as the original award immediately before the original award is modified. The update is effective for annual periods beginning after December 15, 2017, and interim periods within that annual period. Early adoption is permitted. This update should be applied prospectively to an award modified on or after the adoption date. The Partnership is in the process of determining the impact of the accounting standard update on the consolidated financial statements.

In February 2017, the FASB issued an accounting standard update addressing the derecognition of nonfinancial assets. The guidance defines in-substance nonfinancial assets, and states that the derecognition of business activities should be evaluated under the consolidation guidance, with limited exceptions related to conveyances of oil and gas mineral rights or contracts with customers. The standard eliminates the previous exclusion for businesses that are in-substance real estate, and eliminates some differences based on whether a transferred set is that of assets or a business and whether the transfer is to a joint venture. The standard must be implemented in conjunction with the implementation date of the revenue recognition accounting standard update, which the Partnership will implement January 1, 2018. The Partnership plans to adopt the new standard using the modified retrospective method and is in the process of determining the impact of the accounting standard update on the consolidated financial statements together with its evaluation of the new revenue recognition standard, as described further below.

In January 2017, the FASB issued an accounting standard update which simplifies the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test. Under the new guidance, the recognition of an impairment charge is calculated based on the amount by which the carrying amount exceeds the reporting unit’s fair value; however, the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. The guidance should be applied on a prospective basis, and is effective for annual or interim goodwill impairment tests in fiscal years beginning after December 15, 2019. Early adoption is permitted for interim or annual goodwill impairment tests performed on testing dates after January 1, 2017. The Partnership is in the process of determining the impact of the accounting standard update on the consolidated financial statements.

In January 2017, the FASB issued an accounting standard update to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The standard is intended to narrow the definition of a business by specifying the minimum inputs and processes and by narrowing the definition of outputs. The change is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years. The guidance will be applied prospectively and early adoption is permitted for certain transactions. The Partnership is in the process of determining the impact of the accounting standard update on the consolidated financial statements.

In November 2016, the FASB issued an accounting standard update requiring that the statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. The change is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. Retrospective application is required. The application of this accounting standard update will not have a material impact on the Consolidated Statements of Cash Flows.

In August 2016, the FASB issued an accounting standard update related to the classification of certain cash flows. The accounting standard update provides specific guidance on eight cash flow classification issues, including debt prepayment or debt extinguishment costs and distributions received from equity method investees. The change is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. The Partnership does not expect application of this accounting standard update to have a material impact on the Consolidated Statements of Cash Flows.

In June 2016, the FASB issued an accounting standard update related to the accounting for credit losses on certain financial instruments. The guidance requires that for most financial assets, losses are based on an expected loss approach which includes estimates of losses over the life of exposure that considers historical, current and forecasted information. Expanded disclosures related to the methods used to estimate the losses as well as a specific disaggregation of balances for financial assets are also required. The change is effective for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years, with early adoption permitted for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. The Partnership does not expect application of this accounting standard update to have a material impact on the consolidated financial statements.

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In March 2016, the FASB issued an accounting standard update on the accounting for employee share-based payments. This accounting standard update requires the recognition of income tax effects of awards through the income statement when awards vest or are settled. It will also increase the amount an employer can withhold for tax purposes without triggering liability accounting. Lastly, it allows employers to make a policy election to account for forfeitures as they occur. The changes are effective for fiscal years beginning after December 15, 2016 and early adoption is permitted. The Partnership is in the process of determining the impact of the new standard on the consolidated financial statements.

In February 2016, the FASB issued an accounting standard update ~~on lease accounting. This accounting standard update requires~~requiring lessees to record virtually all leases on their balance sheets. The accounting standard update also requires expanded disclosures to help financial statement users better understand the amount, timing and uncertainty of cash flows arising from leases. For lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. The change will be effective on a ~~retrospective or~~ modified retrospective basis for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years, with early adoption permitted. The Partnership is ~~in the process of determining~~currently evaluating the impact of this standard on the Partnership’s financial statements and disclosures, internal controls, and accounting ~~standard update~~policies. This evaluation process includes reviewing all forms of leases, performing a completeness assessment over the lease population and analyzing the practical expedients in order to determine the best path to implementation. The Partnership does not plan to early adopt the standard. The Partnership believes the impact will be material on the consolidated financial statements as all operating leases will generate a right of use asset and ~~expects such impact to be material.~~lease obligation.

In January 2016, the FASB issued an accounting standard 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 ~~accounting standard~~ 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 ~~accounting standard~~ 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 accounting standard 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 guidance regarding presentation of the liability’s credit risk. The ~~Partnership is in the process of determining the impact of the accounting standard update on the consolidated financial statements.~~

In August 2014, the FASB issued an accounting standard 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 is required to assess if there is substantial doubt about an entity’s ability to continue as a going concern within one year after the issuance of the financial statements. Disclosures will be required if conditions give rise to substantial doubt and the type of disclosure will be determined based on whether management’s plans will be able to alleviate the substantial doubt. The change will be effective for the first fiscal period ending after December 15, 2016, and for fiscal periods and interim periods thereafter with early application ~~permitted. The adoption~~ of this accounting standard update iswill not ~~expected to~~ have a material impact on the Partnership’s consolidated financial ~~reporting.~~statements.

In May 2014, the FASB issued ~~an initial accounting standard update for revenue recognition for contracts~~ASU 2014-09 which created Accounting Standards Codification (“ASC”) Topic 606, “Revenue from Contracts with ~~customers.~~Customers” (“ASC 606”). The guidance in the ~~accounting standard update~~ASC 606 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 change will be effective on a retrospective or modified retrospective basis for fiscal years 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~~currently evaluating the impact of the revenue recognition standard on its consolidated financial statements and disclosures, internal controls and accounting ~~standard update~~policies. This evaluation process includes a phased approach, the first phase of which includes reviewing a sample of contracts and transaction types across segments. This phase is substantially complete; however, the Partnership continues to evaluate our accounting for certain items such as principal versus agent treatment in relation to commodity sales.

Based on the ~~consolidated~~results of the first phase assessment to date, the Partnership has reached tentative conclusions for most contract types and does not believe revenue recognition patterns for fee-based or percent-of-proceeds contracts will change materially. The Partnership does expect certain amounts to be grossed up in revenue as a result of implementation, specifically related to third-party reimbursements from customers and commodities received as consideration in service agreements. In the second quarter of 2017, the Partnership reached a tentative conclusion on the valuation of noncash consideration received in the form of a commodity product. The Partnership has started the second phase of implementation, which includes the calculation of the impact of the new standard on results and the development of new policies and procedures related to the application upon adoption. The Partnership will provide updates as qualitative and quantitative conclusions are reached throughout 2017.

The Partnership will adopt the revenue recognition standard during the first quarter of 2018. The Partnership plans to adopt the new standard using the modified retrospective method which will result in a cumulative effect adjustment as of the date of adoption. By selecting this adoption method, the Partnership will disclose the amount by which each financial ~~statements.~~statement line item is affected by the standard in the current reporting period after adoption as compared with the guidance that was in effect before adoption.

3. Acquisitions

Acquisition of Hardin Street Transportation LLC, Woodhaven Cavern LLC and MPLX Terminals LLC

MPC contributed the assets of HST, WHC and MPLXT to newly created and wholly-owned subsidiaries and entered into commercial agreements related to services provided by these new entities to MPC on January 1, 2015 for HST and WHC and April 1, 2016 for MPLXT. Pursuant to a Membership Interests Contributions Agreement (the “Contributions Agreement”) entered into on March 1, 2017 by the Partnership with MPLX GP LLC (“MPLX GP”), MPLX Logistics Holdings LLC (“MPLX Logistics”), MPLX Holdings Inc. (“MPLX Holdings”) and MPC Investment LLC (“MPC Investment”), each a wholly-owned subsidiary of MPC, MPC Investment agreed to contribute the outstanding membership interests in HST, WHC and MPLXT through a series of intercompany contributions to the Partnership for approximately $1.5 billion in cash and equity consideration valued at approximately $504 million (the “Transaction”). The number of common units representing the equity consideration was determined by dividing the contribution amount by the simple average of the ten day trailing volume weighted average New York Stock Exchange price of a common unit for the ten trading days ending at market close on February 28, 2017. The fair value of the common and general partner units issued was approximately $503 million, as recorded on the Consolidated Statements of Equity, and consisted of (i) 9,197,900 common units representing limited partner interests in the Partnership to MPLX GP, (ii) 2,630,427 common units to MPLX Logistics and (iii) 1,132,049 common units to MPLX Holdings. The Partnership also issued 264,497 general partner units to MPLX GP in order to maintain its two percent general partner interest (“GP Interest”) in the Partnership. MPC agreed to waive two-thirds of the first quarter 2017 distributions on the MPLX LP common units issued in connection with the Transaction. As a result of this waiver, MPC did not receive two-thirds of the general partner distributions or incentive distribution rights that would have otherwise accrued on such MPLX LP common units with respect to the first quarter 2017 distributions. The value of these waived distributions was $6 million.

HST owns and operates various private crude oil and refined product pipeline systems and associated storage tanks. As of the acquisition date, these pipeline systems consisted of 174 miles of crude oil pipelines and 430 miles of refined products pipelines. WHC owns and operates nine butane and propane storage caverns located in Michigan with approximately 1.8 million barrels of natural gas liquids storage capacity. As of the acquisition date, MPLXT owned and operated 59 terminals for the receipt, storage, blending, additization, handling and redelivery of refined petroleum products. Additionally, MPLXT operated one leased terminal and had partial ownership interest in two terminals. Collectively, these 62 terminals have a combined shell capacity of approximately 23.6 million barrels. The terminal facilities are located primarily in the Midwest, Gulf Coast and Southeast regions of the United States. The Partnership accounts for these businesses within its L&S segment.

The Partnership retrospectively adjusted the historical financial results for all periods to give effect to the acquisition of HST and WHC effective January 1, 2015 and the acquisition of MPLXT effective April 1, 2016, as required for transactions between entities under common control. Prior to these dates, these entities were not considered businesses and, therefore, there are no financial results from which to recast.

The following tables present the Partnership’s previously reported unaudited Consolidated Statements of Income for the three and six months ended June 30, 2016, retrospectively adjusted for the acquisition of HST, WHC and MPLXT:



	Three Months Ended June 30, 2016
(In millions, except per unit data)	MPLX LP (Previously Reported)			HST/WHC		MPLXT		Eliminations⁽¹⁾			MPLX LP (Currently Reported)
Revenues and other income:
Service revenue	$	233		$	—	$	—	$	—		$	233
Service revenue - related parties	145			27		74		—			246
Rental income	71			—		—		—			71
Rental income - related parties	29			11		26		—			66
Product sales	137			—		—		—			137
Product sales - related parties	3			—		—		—			3
Loss from equity method investments	(83		)	—		—		—			(83		)
Other income	1			—		—		—			1
Other income - related parties	28			—		—		(4		)	24
Total revenues and other income	564			38		100		(4		)	698
Costs and expenses:
Cost of revenues (excludes items below)	84			9		20		—			113
Purchased product costs	114			—		—		—			114
Rental cost of sales	14			1		—		—			15
Rental cost of sales - related parties	—			1		—		—			1
Purchases - related parties	78			4		21		(4		)	99
Depreciation and amortization	137			4		10		—			151
Impairment expense	1			—		—		—			1
General and administrative expenses	49			2		12		—			63
Other taxes	11			1		1		—			13
Total costs and expenses	488			22		64		(4		)	570
Income from operations	76			16		36		—			128
Interest expense (net of amounts capitalized)	52			—		—		—			52
Other financial costs	12			—		—		—			12
Income before income taxes	12			16		36		—			64
Benefit for income taxes	(8		)	—		—		—			(8		)
Net income	20			16		36		—			72
Less: Net income attributable to noncontrolling interests	1			—		—		—			1
Less: Net income attributable to Predecessor	—			16		36		—			52
Net income attributable to MPLX LP	19			—		—		—			19
Less: Preferred unit distributions	9			—		—		—			9
Less: General partner’s interest in net income attributable to MPLX LP	46			—		—		—			46
Limited partners’ interest in net loss attributable to MPLX LP	$	(36	)	$	—	$	—	$	—		$	(36	)


(1)	Represents intercompany transactions eliminated during the consolidation process, in accordance with GAAP.



	Six Months Ended June 30, 2016
(In millions, except per unit data)	MPLX LP (Previously Reported)			HST/WHC		MPLXT		Eliminations⁽¹⁾			MPLX LP (Currently Reported)
Revenues and other income:
Service revenue	$	462		$	—	$	—	$	—		$	462
Service revenue - related parties	295			54		74		—			423
Rental income	141			—		—		—			141
Rental income - related parties	55			23		26		—			104
Product sales	237			—		—		—			237
Product sales - related parties	6			—		—		—			6
Loss from equity method investments	(78		)	—		—		—			(78		)
Other income	3			—		—		—			3
Other income - related parties	52			—		—		(7		)	45
Total revenues and other income	1,173			77		100		(7		)	1,343
Costs and expenses:
Cost of revenues (excludes items below)	173			14		20		—			207
Purchased product costs	193			—		—		—			193
Rental cost of sales	28			1		—		—			29
Rental cost of sales - related parties	—			1		—		—			1
Purchases - related parties	154			9		21		(7		)	177
Depreciation and amortization	269			8		10		—			287
Impairment expense	130			—		—		—			130
General and administrative expenses	101			3		12		—			116
Other taxes	22			2		1		—			25
Total costs and expenses	1,070			38		64		(7		)	1,165
Income from operations	103			39		36		—			178
Related party interest and other financial income	1			—		—		—			1
Interest expense (net of amounts capitalized)	107			—		—		—			107
Other financial costs	24			—		—		—			24
(Loss) income before income taxes	(29		)	39		36		—			46
Benefit for income taxes	(12		)	—		—		—			(12		)
Net (loss) income	(17		)	39		36		—			58
Less: Net income attributable to noncontrolling interests	1			—		—		—			1
Less: Net income attributable to Predecessor	23			39		36		—			98
Net loss attributable to MPLX LP	(41		)	—		—		—			(41		)
Less: Preferred unit distributions	9			—		—		—			9
Less: General partner’s interest in net income attributable to MPLX LP	85			—		—		—			85
Limited partners’ interest in net loss attributable to MPLX LP	$	(135	)	$	—	$	—	$	—		$	(135	)


(1)	Represents intercompany transactions eliminated during the consolidation process, in accordance with GAAP.

The following table presents the Partnership’s previously reported unaudited Consolidated Statements of Cash Flows, retrospectively adjusted for the acquisition of HST, WHC and MPLXT:



	Six Months Ended June 30, 2016
(In millions)	MPLX LP (Previously Reported)			HST/WHC			MPLXT			MPLX LP (Currently Reported)
Increase (decrease) in cash and cash equivalents
Operating activities:
Net (loss) income	$	(17	)	$	39		$	36		$	58
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Amortization of deferred financing costs	23			—			—			23
Depreciation and amortization	269			8			10			287
Impairment expense	130			—			—			130
Deferred income taxes	(13		)	—			—			(13		)
Asset retirement expenditures	(2		)	—			—			(2		)
Loss from equity method investments	78			—			—			78
Distributions from unconsolidated affiliates	78			—			—			78
Changes in:
Current receivables	(20		)	—			—			(20		)
Inventories	(3		)	—			—			(3		)
Fair value of derivatives	25			—			—			25
Current accounts payable and accrued liabilities	18			(1		)	2			19
Receivables from / liabilities to related parties	6			—			(18		)	(12		)
All other, net	21			3			(2		)	22
Net cash provided by operating activities	593			49			28			670
Investing activities:
Additions to property, plant and equipment	(569		)	(23		)	(14		)	(606		)
Investments - net related party loans	77			(26		)	(14		)	37
Investments in unconsolidated affiliates	(39		)	—			—			(39		)
All other, net	5			—			—			5
Net cash used in investing activities	(526		)	(49		)	(28		)	(603		)
Financing activities:
Long-term debt - borrowings	434			—			—			434
- repayments	(1,311		)	—			—			(1,311		)
Related party debt - borrowings	1,853			—			—			1,853
- repayments	(1,861		)	—			—			(1,861		)
Net proceeds from equity offerings	321			—			—			321
Issuance of redeemable preferred units	984			—			—			984
Distributions to unitholders and general partner	(391		)	—			—			(391		)
Distributions to noncontrolling interests	(1		)	—			—			(1		)
Contributions from noncontrolling interests	2			—			—			2
All other, net	(1		)	—			—			(1		)
Distributions to MPC from Predecessor	(104		)	—			—			(104		)
Net cash used in financing activities	(75		)	—			—			(75		)
Net decrease in cash and cash equivalents	(8		)	—			—			(8		)
Cash and cash equivalents at beginning of period	43			—			—			43
Cash and cash equivalents at end of period	$	35		$	—		$	—		$	35

Acquisition of Ozark Pipeline

On March 1, 2017, the Partnership acquired the Ozark pipeline from Enbridge Pipelines (Ozark) LLC for approximately $219 million, including purchase price adjustments made in the second quarter of 2017. Based on the preliminary fair value estimates of assets acquired and liabilities assumed at the acquisition date, the purchase price was primarily allocated to property, plant and equipment. The Ozark pipeline is a 433-mile, 22-inch crude oil pipeline originating in Cushing, Oklahoma, and terminating in Wood River, Illinois, capable of transporting approximately 230 mbpd. The Partnership accounts for the Ozark pipeline within its L&S segment.

The amounts of revenue and income from operations associated with the acquisition included in the Consolidated Statements of Income, since the March 1, 2017 acquisition date, are as follows:



(In millions)	Three Months Ended June 30, 2017		Four Months Ended June 30, 2017
Revenues and other income	$	19	$	26
Income from operations	9		11

Assuming the acquisition of the Ozark pipeline had occurred on January 1, 2016, the consolidated pro forma results would not have been materially different from reported results.

Acquisition of Hardin Street Marine LLC

On March 14, 2016, the Partnership entered into a Membership Interests Contribution Agreement (the “Contribution Agreement”) with MPLX GP, ~~LLC (“MPLX GP”),~~ MPLX Logistics ~~Holdings LLC~~ and MPC Investment, ~~LLC (“MPC Investment”),~~ each a wholly-owned subsidiary of MPC, related to the acquisition of HSM, MPC’s inland marine business, from MPC. Pursuant to the Contribution Agreement, the transaction was valued at $600 million consisting of a fixed number of common units and general partner units of 22,534,002 and 459,878, respectively. The general partner units maintain MPC’s two percent ~~general partner interest~~GP Interest in the Partnership. The acquisition closed on March 31, 2016 and the fair value of the common

units and general partner units issued was $669 million and $14 million, respectively, as recorded on the Consolidated Statements of Equity. MPC agreed to waive distributions in the first quarter of 2016 on MPLX LP common units issued in connection with this transaction. As a result of this waiver, MPC did not receive general partner distributions or incentive distribution rights that would have otherwise accrued on such MPLX LP common units with respect to the first quarter 2016 distributions. The value of these waived distributions was $15 million.

The inland marine business, comprised of 18 tow boats and ~~205~~219 owned and leased barges as of the acquisition date, which transport light products, heavy oils, crude oil, renewable fuels, chemicals and feedstocks in the Midwest and U.S. Gulf Coast regions, accounted for nearly 60 percent of the total volumes MPC shipped by inland marine vessels as of March 31, 2016. The Partnership accounts for HSM ~~as a reporting unit of the~~within its L&S segment.

~~The Partnership retrospectively adjusted the historical~~

4. Investments and Noncontrolling Interests

Summarized financial ~~results for all periods to include HSM as required for transactions between entities under common control. For the previously reported Consolidated Balance Sheets retrospectively adjusted~~information for the ~~acquisition of HSM, see the Annual Report on Form 10-K for the year ended December 31, 2015, as updated by our Current Report on Form 8-K/A filed on May 20, 2016. The following table presents the~~ Partnership’s ~~previously reported Consolidated Statement of Income, retrospectively adjusted for the acquisition of HSM:~~

Three Months Ended June 30, 2015
(In millions) MPLX LP (Previously Reported) HSM MPLX LP (Currently Reported)
Revenues and other income:
Service revenue $ 16
$ —
$ 16
Service revenue - related parties 119
33
152
Rental income - related parties 4
21
25
Other income 2
—
2
Other income - related parties 6
12
18
Total revenues and other income 147
66
213
Costs and expenses:
Cost of revenues (excludes items below) 31
15
46
Purchases - related parties 24
16
40
Depreciation and amortization 13
7
20
General and administrative expenses 18
3
21
Other taxes 3
1
4
Total costs and expenses 89
42
131
Income from operations 58
24
82
Interest expense (net of amounts capitalized of $1 million) 6
—
6
Other financial costs —
—
—
Income before income taxes 52
24
76
Net income 52
24
76
Less: Net income attributable to noncontrolling interests 1
—
1
Less: Net income attributable to Predecessor —
24
24
Net income attributable to MPLX LP 51
—
51
Less: General partner’s interest in net income attributable to MPLX LP 7
—
7
Limited partners’ interest in net income attributable to MPLX LP $ 44
$ —
$ 44

Six Months Ended June 30, 2015
(In millions) MPLX LP (Previously Reported) HSM MPLX LP (Currently Reported)
Revenues and other income:
Service revenue $ 32
$ —
$ 32
Service revenue - related parties 230
64
294
Rental income - related parties 8
42
50
Other income 3
—
3
Other income - related parties 12
23
35
Total revenues and other income 285
129
414
Costs and expenses:
Cost of revenues (excludes items below) 59
29
88
Purchases - related parties 48
32
80
Depreciation and amortization 25
14
39
General and administrative expenses 37
6
43
Other taxes 6
2
8
Total costs and expenses 175
83
258
Income from operations 110
46
156
Interest expense (net of amounts capitalized of $1 million) 11
—
11
Other financial costs 1
—
1
Income before income taxes 98
46
144
Net income 98
46
144
Less: Net income attributable to noncontrolling interests 1
—
1
Less: Net income attributable to Predecessor —
46
46
Net income attributable to MPLX LP 97
—
97
Less: General partner’s interest in net income attributable to MPLX LP 11
—
11
Limited partners’ interest in net income attributable to MPLX LP $ 86
$ —
$ 86

~~The following table presents the Partnership’s previously reported Consolidated Statement of Cash Flows, retrospectively adjusted for the acquisition of HSM:~~

Six Months Ended June 30, 2015
(In millions) MPLX LP (Previously Reported) HSM MPLX LP (Currently Reported)
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income $ 98
$ 46
$ 144
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred financing costs 1
—
1
Depreciation and amortization 25
14
39
Deferred income taxes —
(1 ) (1 )
Changes in:
Current receivables (2 ) —
(2 )
Current accounts payable and accrued liabilities 14
(2 ) 12
Receivables from / liabilities to related parties (8 ) (11 ) (19 )
All other, net —
(1 ) (1 )
Net cash provided by operating activities 128
45
173
Investing activities:
Additions to property, plant and equipment (64 ) (6 ) (70 )
Investments - loans to related parties —
(38 ) (38 )
All other, net —
(1 ) (1 )
Net cash used in investing activities (64 ) (45 ) (109 )
Financing activities:
Long-term debt - borrowings 528
—
528
- repayments (415 ) —
(415 )
Debt issuance costs (4 ) —
(4 )
Net proceeds from equity offerings 1
—
1
Distributions to unitholders and general partner (70 ) —
(70 )
Distributions to MPC from Predecessor (1 ) —
(1 )
Net cash provided by financing activities 39
—
39
Net increase in cash and cash equivalents 103
—
103
Cash and cash equivalents at beginning of period 27
—
27
Cash and cash equivalents at end of period $ 130
$ —
$ 130

~~Purchase of MarkWest Energy Partners, L.P.~~

On December 4, 2015, a wholly-owned subsidiary of the Partnership merged with MarkWest. 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 representing limited partner interests in MPLX LP, plus a one-time cash payment of $6.20 per unit. Each Class B unit of MarkWest issued and outstanding immediately prior to the effective time of the MarkWest Merger was converted into the right to receive one Class B unit of MPLX LP. Each Class B unit of MPLX LP will convert into 1.09 common units of MPLX LP and the right to receive $6.20 in cash, and the conversion of the Class B units will occur in equal installments, the first of which occurred on July 1, 2016 and the second of which will occur on July 1, 2017. 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 is payable in equal amounts, the first of which was paid in July 2016 and the second of which will be paid in July 2017, in connection with the conversion of the Class B units to common units of MPLX LP. The Partnership’s financial results reflect the results of MarkWest from the date of the acquisition.

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

(In millions)
Fair value of units issued $ 7,326
Cash 1,230
Paid/payable to MarkWest Class B unitholders 50
Total fair value of consideration transferred $ 8,606

The following table summarizes the final purchase price allocation. Subsequent to December 31, 2015, additional analysis was completed and adjustments were made to the preliminary purchase price allocation as noted in the table below. The fair value of assets acquired and liabilities and noncontrolling interests assumed at the acquisition date as of June 30, 2016, are as follows:

(In millions) As Originally Reported Adjustments As Adjusted
Cash and cash equivalents $ 12
$ —
$ 12
Receivables 164
—
164
Inventories 33
(1 ) 32
Other current assets 44
—
44
Equity method investments 2,457
143
2,600
Property, plant and equipment 8,474
43
8,517
Intangibles 468
65
533
Other noncurrent assets 5
—
5
Total assets acquired 11,657
250
11,907
Accounts payable 322
—
322
Accrued liabilities 13
6
19
Accrued taxes 21
—
21
Other current liabilities 44
—
44
Long-term debt 4,567
—
4,567
Deferred income taxes 374
3
377
Deferred credits and other liabilities 151
—
151
Noncontrolling interest 13
—
13
Total liabilities and noncontrolling interest assumed 5,505
9
5,514
Net assets acquired excluding goodwill 6,152
241
6,393
Goodwill 2,454
(241 ) 2,213
Net assets acquired $ 8,606
$ —
$ 8,606

Adjustments to the preliminary purchase price stem mainly from additional information obtained by management in the first and second quarters of 2016 about facts and circumstances that existed at the acquisition date, including updates to forecasted employee benefit costs, maintenance capital expenditures and completion of certain valuations to determine the underlying fair value of certain acquired assets. The adjustment to intangibles mainly relates to a misstatement in the original preliminary purchase price allocation. The correction of the error resulted in a $68 million reduction to the carrying value of goodwill and an offsetting increase of $64 million in intangibles and $2 million in each of equity method investments and property, plant and equipment. Management concluded that the correction of the error is immaterial to the consolidated financial statements of all periods presented. As further discussed in Note 16, in the first quarter of 2016 the Partnership recorded a goodwill impairment charge based on the implied fair value of goodwill as of the interim impairment analysis date. During the second quarter of 2016, the Partnership finalized its analysis of the final purchase price allocation. The completion of the purchase price allocation resulted in a refinement of the impairment expense recorded, as more fully discussed in Note 16.

~~The increase to the fair value of intangibles and property, plant and equipment noted above resulted in additional amortization and depreciation expense of approximately $1 million recognized~~ for the six months ended June 30, 2017 and 2016 in ~~Depreciation and amortization~~ ~~in the~~ ~~Consolidated Statements of Income, that would have been recorded for the year ended December 31, 2015,~~

~~had the fair value adjustments been recorded~~is as of December 4, 2015. The increase in the fair value of equity investments above would not have had a material effect on the income from equity method investments had the fair value adjustment been recorded as of December 4, 2015.

The purchase price allocation resulted in the recognition of $2.2 billion of goodwill in three reporting units within the Partnership’s G&P segment, substantially all of which is not deductible for tax purposes. Goodwill represents the complementary aspects of the highly diverse asset base of MarkWest and MPLX LP that will provide significant additional opportunities across multiple segments of the hydrocarbon value chain.

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 13.

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 11.5 percent to 12.8 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 are not included in the Consolidated Statement of Income for the period ended June 30, 2015.~~

~~Unaudited Pro Forma Financial Information~~

~~The following unaudited pro forma financial information presents consolidated results assuming the MarkWest Merger occurred on January 1, 2014.~~follows:

(In millions, except per unit data) Three Months Ended June 30, 2015 Six Months Ended June 30, 2015
Revenues and other income $ 668
$ 1,332
Net (loss) income attributable to MPLX LP (11 ) 53
Net income attributable to MPLX LP per unit - basic (0.19 ) (0.10 )
Net income attributable to MPLX LP per unit - diluted (0.19 ) (0.10 )



	Six Months Ended June 30, 2017
(In millions)	MarkWest Utica EMG		Other VIEs			Non-VIEs		Total
Revenues and other income	$	88	$	21		$	91	$	200
Costs and expenses	48		17			73		138
Income from operations	40		4			18		62
Net income	40		4			17		61
Income (loss) from equity method investments⁽¹⁾	2		(1		)	5		6

The unaudited pro forma financial information includes adjustments primarily to align accounting policies, adjust depreciation expense to reflect the fair value of property, plant and equipment, increase amortization expense related to identifiable intangible assets and adjust interest expense related to the fair value of MarkWest’s long-term debt, as well as the related income tax effects. 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.

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.



	Six Months Ended June 30, 2016
(In millions)	MarkWest Utica EMG		Other VIEs⁽²⁾			Non-VIEs		Total
Revenues and other income	$	113	$	10		$	70	$	193
Costs and expenses	45		104			52		201
Income (loss) from operations	68		(94		)	18		(8		)
Net income (loss)	68		(94		)	18		(8		)
Income (loss) from equity method investments⁽¹⁾	7		(88		)	3		(78		)


(1)	Income (loss) from equity method investments includes the impact of any basis differential amortization or accretion.


(2)	Includes an impairment charge of $89 million for the six months ended June 30, 2016 related to the Partnership’s investment in Ohio Condensate, which does not appear separately in this table.

~~A summary~~Summarized balance sheet information for the Partnership’s equity method investments as of ~~the amounts included in the historical financial statements of MarkWest related to MarkWest Utica EMG are~~June 30, 2017 and December 31, 2016 is as follows:

(In millions) Three Months Ended June 30, 2015 Six Months Ended June 30, 2015
Revenues and other income $ 34
$ 67
Cost of revenue excluding depreciation and amortization 7
14
Depreciation and amortization 16
32
Net income attributable to noncontrolling interest 15
29
Net loss (5 ) (9 )



	June 30, 2017
(In millions)	MarkWest Utica EMG⁽¹⁾		Other VIEs		Non-VIEs		Total
Current assets	$	72	$	49	$	33	$	154
Noncurrent assets	2,103		881		2,421		5,405
Current liabilities	26		69		18		113
Noncurrent liabilities	2		13		—		15

~~EMG Utica, LLC (“EMG Utica”), a joint venture partner in MarkWest Utica EMG, received a special non-cash allocation~~



	December 31, 2016
(In millions)	MarkWest Utica EMG⁽¹⁾		Other VIEs		Non-VIEs		Total
Current assets	$	45	$	2	$	40	$	87
Noncurrent assets	2,173		132		390		2,695
Current liabilities	30		4		26		60
Noncurrent liabilities	2		13		—		15


(1)	MarkWest Utica EMG’s noncurrent assets include its investment in its subsidiary Ohio Gathering, which does not appear elsewhere in this table. The investment was $794 million as of June 30, 2017 and December 31, 2016.

As of ~~income of approximately $11 million and $21 million for the three and six months ended~~ June 30, ~~2015. See Note 4 for a description~~2017 and December 31, 2016, the carrying value of the ~~transaction and~~Partnership’s equity method investments exceeded the underlying net assets of its ~~impact on~~investees by $1.1 billion. This basis difference is being amortized or accreted into net income over the ~~financial statements. Net income~~remaining estimated useful lives of ~~MarkWest would not have changed had MarkWest Utica EMG been deconsolidated~~the underlying net assets, except for ~~the period ended June 30, 2015.~~

~~4. Equity Method Investments~~$459 million of excess related to goodwill.

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 limited liability company agreement has been amended from time to time (the limited liability company 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$2.0 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 June 30, ~~2016,~~2017, EMG Utica has

contributed approximately ~~$998 million~~$1.2 billion 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~~was increased by a quarterly special non-cash allocation of income (“Preference Amount”) ~~that is~~, calculated based upon the amount of capital contributed by EMG Utica in excess of $500 million. NoAfter December 31, 2016, no Preference Amount will accrue to EMG Utica’s investment ~~balance after December 31, 2016.~~balance. EMG Utica received a ~~special non-cash allocation of income of~~Preference Amount totaling approximately $4 million and ~~approximately~~ $8 million for the three and six months ended June 30, 2016, respectively.

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~~after 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 June 30, ~~2016,~~2017, 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~~investment in MarkWest Utica EMG’s, ~~net assets,~~ which was ~~$2.3~~$2.2 billion at June 30, 2017 and December 31, 2016, is reported under the caption Equity method investments on the Consolidated Balance ~~Sheets (see basis differential discussion below).~~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 ~~period~~three and six months ended June 30, ~~2016.~~2017 and 2016, respectively. The Partnership receives management fee revenue for engineering and construction and administrative services for operating MarkWest Utica EMG, and is also reimbursed for personnel services (“Operational Service revenue”) ~~for operating~~. Operational Service revenue is reported as Other income-related parties in the Consolidated Statements of Income. The amount of Operational Service revenue related to MarkWest Utica ~~EMG.~~EMG for the three and six months ended June 30, 2017, totaled approximately $4 million and $8 million, respectively. The amount of Operational Service revenue related to MarkWest Utica EMG for the three and six months ended June 30, 2016, ~~was~~totaled $5 million and $7 million, ~~respectively, and is reported as~~ ~~Other income-related parties~~ ~~in the Consolidated Statements of Income.~~respectively.

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, ~~LLC (“Summit”).~~LLC. As of June 30, 2017, the Partnership has an approximate 34 percent indirect ownership interest in Ohio Gathering. As Ohio Gathering 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.~~Gathering which is reported as Other income-related parties in the Consolidated Statements of Income. The amount of Operational Service revenue related to Ohio Gathering for the three and six months ended June 30, 2017, was approximately $4 million and $8 million, respectively. The amount of Operational Service revenue related to Ohio Gathering for the three and six months ended June 30, 2016, totaled $3 million and $7 million, respectively.

Sherwood Midstream

Effective January 1, 2017, MarkWest Liberty Midstream & Resources, L.L.C. (“MarkWest Liberty Midstream”), a wholly-owned and consolidated subsidiary of MarkWest, and Antero Midstream Partners, LP (“Antero Midstream”) formed a joint venture, Sherwood Midstream, to support Antero Resources Corporation’s development in the Marcellus Shale. MarkWest Liberty Midstream has a 50 percent ownership interest in Sherwood Midstream. Pursuant to the terms of the related limited liability company agreement (the “LLC Agreement”), MarkWest Liberty Midstream contributed assets then under construction with a fair value of approximately $134 million and cash of approximately $20 million. Antero Midstream made an initial capital contribution of approximately $154 million.

Also effective January 1, 2017, MarkWest Liberty Midstream converted all of its ownership interests in MarkWest Ohio Fractionation Company, L.L.C. (“Ohio Fractionation”), a previously wholly-owned subsidiary, to Class A Interests and amended its LLC Agreement to create Class B-3 Interests, which were sold to Sherwood Midstream for $126 million in cash. The Class B-3 Interests provide Sherwood Midstream with the right to fractionation revenue and the obligation to pay expenses related to 20 mbpd of capacity in the Hopedale 3 fractionator. Sherwood Midstream accounts for its investment in Ohio Fractionation, which is a VIE, as an equity method investment as Sherwood Midstream does not control Ohio Fractionation. MarkWest Liberty Midstream has been deemed to be the primary beneficiary of Ohio Fractionation because it has control over the decisions that could significantly impact its financial performance, and as a result, consolidates Ohio Fractionation. The

carrying amounts of assets and liabilities included in the Partnership’s Consolidated Balance Sheets pertaining to Ohio Fractionation at June 30, 2017, were current assets of $13 million, non-current assets of $389 million and current liabilities of $377 million. The creditors of Ohio Fractionation do not have recourse to MPLX LP’s general credit through guarantees or other financial arrangements. The assets of Ohio Fractionation are the property of Ohio Fractionation and cannot be used to satisfy the obligations of MPLX LP. Sherwood Midstream’s interests are reflected in Net income attributable to noncontrolling interests in the Consolidated Statements of Income and Noncontrolling interests in the Consolidated Balance Sheets.

Under the LLC Agreement, cash generated by Sherwood Midstream that is available for distribution (the “Distribution”) will be allocated to the members in proportion to their respective investment balances. For the three and six months ended June 30, 2017, there was no cash available for the Distribution.

Sherwood Midstream is deemed to be a VIE. MarkWest Liberty Midstream is not deemed to be the primary beneficiary, due to Antero Midstream’s voting rights on significant matters. The Partnership’s investment in Sherwood Midstream, which was approximately $192 million at June 30, 2017, 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 Sherwood Midstream 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 Sherwood Midstream that it was not contractually obligated to provide during the six months ended June 30, 2017. The Partnership receives Operational Service revenue for operating Sherwood Midstream. The amount of Operational Service revenue related to Sherwood Midstream for the three and six months ended June 30, 2017 totaled approximately $3 million and $7$4 million, respectively, and is reported as Other income-related parties in the Consolidated Statements of Income.

~~Ohio Condensate~~Sherwood Midstream Holdings

~~In December 2013,~~Effective January 1, 2017, MarkWest Liberty Midstream and Sherwood Midstream formed ~~MarkWest Utica EMG Condensate L.L.C. (“Utica Condensate”)~~a joint venture, Sherwood Midstream Holdings, for the purpose of ~~engaging~~owning, operating and maintaining all of the shared assets that support the operations of the gas plants and other assets owned by Sherwood Midstream and the gas plants and deethanization facilities owned by MarkWest Liberty Midstream. MarkWest Liberty Midstream initially contributed certain real property, equipment and facilities with a fair value of approximately $209 million to Sherwood Midstream Holdings in ~~wellhead condensate gathering, stabilization, terminalling, storage and marketing~~exchange for a 79 percent initial ownership interest. Sherwood Midstream contributed cash of approximately $44 million to Sherwood Midstream Holdings in ~~Ohio. As of~~exchange for a 21 percent ownership interest. During the three months ended June 30, ~~2016,~~2017, true-ups to the initial contributions were made. MarkWest Liberty Midstream contributed certain additional real property, equipment and facilities with a fair value of approximately $10 million to Sherwood Midstream Holdings and Sherwood Midstream contributed cash of approximately $4 million to Sherwood Midstream Holdings. Collectively, the real property, equipment, facilities and cash initially contributed, or that may be subsequently constructed by or contributed, to Sherwood Midstream Holdings are referred to as the “Shared Assets.” The net book value of the contributed assets was approximately $203 million. The contribution was determined to be an in-substance sale of real estate. As such, the Partnership ~~owned 100 percent~~only recognized a gain for the portion attributable to Antero Midstream’s indirect interest of ~~Utica Condensate. Utica Condensate’s business~~approximately $2 million, included in Gain on sale of assets in the Consolidated Statements of Income. MarkWest Liberty Midstream’s portion of the gain attributable to its direct and indirect interests of approximately $14 million is ~~conducted solely through~~included in its ~~subsidiary, Ohio Condensate, which~~investment in Sherwood Midstream Holdings and is reported under the caption Equity method investments on the Consolidated Balance Sheets. In connection with the initial contributions, MarkWest Liberty Midstream received a ~~joint venture between Utica Condensate~~special distribution of approximately $45 million.

MarkWest Liberty Midstream’s and ~~Summit.~~Sherwood Midstream’s ownership interests in Sherwood Midstream Holdings will fluctuate over time. As new Shared Assets are constructed, the members will make additional capital contributions to Sherwood Midstream Holdings. The amount that each member must contribute will be based on the expected utilization of ~~June 30, 2016, Utica Condensate owned 60 percent~~the Shared Asset, as defined in the LLC Agreement. Pursuant to the terms of ~~Ohio Condensate.~~ the LLC Agreement, MarkWest Liberty Midstream will serve as the operator for Sherwood Midstream Holdings.

The Partnership accounts for ~~Ohio Condensate,~~Sherwood Midstream Holdings, which is a VIE, as an equity method investment as ~~MPLX LP exercises significant influence, but does not control Ohio Condensate~~Sherwood Midstream is considered to be the general partner and ~~is not its primary beneficiary due to Summit’s voting rights on significant matters.~~controls all decisions. The Partnership’s ~~portion of Ohio Condensate’s net assets are~~investment in Sherwood Midstream Holdings, which was approximately $165 million at June 30, 2017, is reported under the caption Equity method investments on the Consolidated Balance Sheets. The ~~Partnership receives Operational Service revenue for~~Partnership’s maximum exposure to loss as a result of its involvement with Sherwood Midstream Holdings includes its equity investment, any additional capital contribution commitments and any operating ~~Ohio Condensate. The amount~~expenses incurred by the subsidiary operator in excess of ~~Operational Service revenue related to Ohio Condensate~~its compensation received for the ~~three and six months ended June 30, 2016~~performance of the operating services. The Partnership did not provide any financial support to Sherwood Midstream Holdings that it was ~~$1 million and $2 million, respectively, and is reported as~~ ~~Other income-related parties~~ ~~in the Consolidated Statements of Income.~~

~~Summarized financial information for~~not contractually obligated to provide during the six months ended June 30, ~~2016 for equity method investments is as follows:~~

Six Months Ended June 30, 2016
(In millions)
MarkWest Utica EMG ⁽¹⁾
Ohio Condensate Other VIEs Non-VIEs Total
Revenue $ 113
$ 10
$ —
$ 68
$ 191
Gross margin 113
10
—
32
155
Income (loss) from operations 68
(94 ) —
18
(8 )
Net income (loss) 68
(94 ) —
18
(8 )
Income (loss) from equity method investments⁽²⁾
7
(88 ) —
3
(78 )
2017.

~~Summarized balance sheet information as of June 30, 2016 and December 31, 2015 for equity method investments is as follows:~~

June 30, 2016
(In millions)
MarkWest Utica EMG ⁽¹⁾
Ohio Condensate Other VIEs Non-VIEs Total
Current assets $ 138
$ 7
$ —
$ 38
$ 183
Noncurrent assets 2,193
31
55
385
2,664
Current liabilities 108
6
—
26
140
Noncurrent liabilities 2
14
—
—
16

1617

December 31, 2015
(In millions)
MarkWest Utica EMG ⁽¹⁾
Ohio Condensate Other VIEs Non-VIEs Total
Current assets $ 113
$ 7
$ —
$ 30
$ 150
Noncurrent assets 2,207
127
42
243
2,619
Current liabilities 77
6
1
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 $788 million and $781 million as of June 30, 2016 and December 31, 2015, respectively.


~~(2)~~	~~Income (loss) from equity method investments includes the impact of any basis differential amortization or accretion.~~

Sherwood Midstream has been deemed the primary beneficiary of Sherwood Midstream Holdings due to its controlling financial interest through its authority to manage the joint venture. As a result, Sherwood Midstream consolidates Sherwood Midstream Holdings. Therefore, the Partnership also reports its portion of Sherwood Midstream Holdings’ net assets as a component of its investment in Sherwood Midstream. As of June 30, ~~2016,~~2017, the ~~carrying value~~Partnership has a 13.9 percent indirect ownership interest in Sherwood Midstream Holdings through Sherwood Midstream.

MarEn Bakken

On February 15, 2017, the Partnership closed on a joint venture, MarEn Bakken, with Enbridge Energy Partners L.P. (“Enbridge Energy Partners”) in which MPLX LP acquired a partial, indirect interest in the Dakota Access Pipeline (“DAPL”) and Energy Transfer Crude Oil Company Pipeline (“ETCOP”) projects, collectively referred to as the Bakken Pipeline system, from Energy Transfer Partners, L.P. (“ETP”) and Sunoco Logistics Partners, L.P. (“SXL”). The Partnership contributed $500 million of the ~~Partnership’s equity method investments was $1.1~~$2.0 billion higher than the underlying net assets of the 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 $459 million of excess related to goodwill. During the second quarter of 2016, the Partnership completed its purchase price ~~allocation related~~paid by MarEn Bakken to acquire a 36.75 percent indirect interest in the ~~MarkWest Merger. As~~Bakken Pipeline system. The Partnership holds, through a ~~result,~~subsidiary, a ~~portion of~~25 percent interest in MarEn Bakken, which equates to a 9.1875 percent indirect interest in the ~~basis differential related to goodwill for Utica EMG was reclassified to fixed assets and will be amortized prospectively.~~Bakken Pipeline system.

~~During~~The Partnership accounts for its investment in MarEn Bakken as an equity method investment and bases the ~~second quarter of 2016, forecasts~~equity method accounting for ~~Ohio Condensate were reduced to align with updated forecasts for customer requirements. As~~this joint venture in arrears based on the ~~operator of that entity responsible for maintaining its financial records, the Partnership completed a fixed asset impairment analysis as of~~most recent available information. The Partnership’s investment balance at June 30, ~~2016, in accordance with ASC Topic 360, to determine~~2017 is approximately $519 million and reported under the potential fixed asset impairment charge. The resulting fixed asset impairment charge recorded within Ohio Condensate’s financial statements was $96 million. Based on the Partnership’s 60 percent ownership of Ohio Condensate, approximately $58 million was recorded in the second quarter of 2016 incaption ~~Loss from equity~~Equity method investments on the ~~accompanying~~ Consolidated ~~Statements of Income.~~

~~The Partnership’s investment in Ohio Condensate, which was established at fair value in~~Balance Sheets. In connection with the ~~MarkWest Merger, exceeded~~Partnership’s acquisition of a partial, indirect equity interest in the Bakken Pipeline system, MPC agreed to waive its ~~proportionate share~~right to receive incentive distributions of $1.6 million per quarter for twelve consecutive quarters, beginning with distributions declared in the ~~underlying net assets. Therefore, in conjunction with the ASC Topic 360 impairment analysis, the Partnership completed an equity method impairment analysis in accordance with ASC Topic 323~~first quarter of 2017 and paid to determine the potential additional equity method impairment charge to be recorded on the Partnership’s consolidated financial statements resulting from an other-than-temporary impairment. As a result, an additional impairment charge of approximately $31 million was recordedMPC in the second quarter, ~~of 2016 in~~ ~~Loss~~which was prorated to $0.8 million from ~~equity method investments~~ on the ~~accompanying Consolidated Statements of Income, which eliminated the basis differential established in connection with the MarkWest Merger.~~acquisition date.

The fair value of Ohio Condensate and its underlying fixed assets was determined based upon applying the discounted cash flow method, which is an income approach, and the guideline public company method, which is a market approach. The discounted cash flow fair value estimate is based on known or knowable information at the interim measurement date. The significant assumptions that were used to develop the estimate of the fair value under the discounted cash flow method include management’s best estimates of the expected future results using a probability weighted average set of cash flow forecasts and a discount rate of 11.2 percent. An increase to the discount rate of 50 basis points would have resulted in an additional charge of $1 million on the Consolidated Statements of Income. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As such, the fair value of the Ohio Condensate equity method investment and its underlying fixed assets represents a Level 3 measurement. As a result, there can be no assurance that the estimates and assumptions made for purposes of the interim impairment test will prove to be an accurate prediction of the future.

5. Related Party Agreements and Transactions

The Partnership’s material related parties include:

MPC, which refines, markets and transports crude oil and petroleum products, primarily in the Midwest, Gulf Coast, East Coast and Southeast regions of the United States.

Centennial Pipeline LLC (“Centennial”), in which MPC has a 50 percent ~~interest.~~interest as of June 30, 2017. Centennial owns a products pipeline and storage facility.

~~Table of Contents~~

Muskegon Pipeline LLC (“Muskegon”), in which MPC has a 60 percent ~~interest.~~interest as of June 30, 2017. Muskegon owns a common carrier products pipeline.

MarkWest Utica EMG, in which MPLX LP has a 6056 percent ~~interest.~~interest as of June 30, 2017. MarkWest Utica EMG is engaged in ~~significant~~ natural gas processing and NGL fractionation, transportation and marketing in ~~eastern~~ Ohio.

Ohio Gathering, in which MPLX LP has a 3634 percent indirect ~~interest.~~interest as of June 30, 2017. Ohio Gathering is a subsidiary of MarkWest Utica EMG providing natural gas gathering service in the Utica Shale region of eastern Ohio.

~~Jefferson Dry Gas,~~Sherwood Midstream, in which MPLX LP has a 6750 percent ~~interest. Jefferson Dry Gas is engaged~~interest as of June 30, 2017. Sherwood Midstream supports the development of Antero Resources Corporation’s Marcellus Shale acreage in ~~dry natural gas gathering in Jefferson County, Ohio.~~the rich-gas corridor of West Virginia.

~~Ohio Condensate,~~Sherwood Midstream Holdings, in which MPLX LP has ~~a 60~~an 86 percent ~~interest. Ohio Condensate~~total direct and indirect interest at June 30, 2017. Sherwood Midstream Holdings owns certain infrastructure at the Sherwood Complex that is ~~engaged in wellhead condensate gathering, stabilization, terminalling, transportation~~shared by and ~~storage within certain defined areas~~supports the operation of ~~Ohio.~~both the Sherwood Midstream and MarkWest gas processing plants and deethanization facilities.

Related Party Agreements

The Partnership has various long-term, fee-based commercial agreements with MPC. Under these agreements, the Partnership provides ~~pipeline~~ transportation, terminal and storage services to MPC, and MPC has committed to provide the Partnership with minimum quarterly throughput volumes on crude oil and refined products systems and minimum storage volumes of crude oil, ~~and~~ refined products and ~~minimum storage volumes of~~ butane.

In addition, the Partnership is party to a loan agreement with 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 the six months ended June 30, 2017, the Partnership borrowed $12 million and repaid $12 million, resulting in no outstanding balance at June 30, 2017. Borrowings were at an average interest rate of 2.270 percent, per annum, for the six months ended June 30, 2017. During the year ended December 31, 2016, the Partnership borrowed ~~$1.9~~$2.5 billion and repaid ~~$1.9~~$2.5 billion, resulting in no outstanding balance at ~~June 30,~~December 31, 2016. Borrowings were at an average interest rate of ~~1.93~~1.939 percent, per ~~annum.~~annum, for the year ended December 31, 2016. For additional information regarding the Partnership’s commercial and other agreements with MPC, see Item 1. Business in ~~our~~the Annual Report on Form 10-K for the year ended December 31, ~~2015.~~2016.

The Partnership believes the terms and conditions under its agreements with MPC are generally comparable to those with unrelated parties.

~~HSM~~HST, WHC and MPLXT Agreements

As discussed in Note 3, the Partnership acquired ~~HSM~~HST, WHC and MPLXT on March ~~31, 2016. HSM has~~1, 2017. HST, WHC and MPLXT have various operating, ~~management~~transportation services, terminal services, storage services and employee services agreements with MPC, which ~~are discussed below.~~were assumed by the Partnership with the closing of the Transaction.

HST is a party to a transportation services agreement with MPC dated January 1, 2015. Under this agreement, HST provides pipeline transportation of crude oil and refined products, as well as related services, for MPC. MPC pays HST for such services based on contractual rates related to MPC crude oil and refined product deliveries as well as any viscosity surcharges, loading, handling, transfers or other related charges. This agreement is set to expire on December 31, 2026 and automatically renews for two additional renewal terms of four years each unless terminated by either party.

On January 1, 2015, ~~HSM~~HST entered into various three-year term storage services agreements with MPC. Under the storage services agreements, HST receives a monthly fee from MPC based on a contractual rate per barrel multiplied by the total commitment volume respective to each storage tank. The contractual rate per barrel is subject to an annual review and adjustment for inflation. HST is not obligated to measure volume gains and losses per the terms of these agreements.

On January 1, 2015, WHC entered into a long-term, fee-based ~~transportation~~storage and services agreement with MPC related to storage at its butane and propane caverns with an initial term of ~~six years~~10 years. Under this storage and services agreement, WHC receives a monthly fee from MPC based on a contractual rate per barrel multiplied by the total commitment volume respective to each storage cavern. The contractual rate per barrel includes utilization of the caverns and related services. The agreement is subject to an annual review and adjustment for inflation.

Under the storage services agreements with both HST and WHC, the Partnership is obligated to make available to MPC, on a firm basis, the available storage capacity at the tank farms and butane and propane caverns and MPC pays the Partnership a per-barrel fee for such storage capacity regardless of whether MPC fully utilizes the available capacity.

MPLXT is a party to a terminal services agreement with MPC, dated March 1, 2017. Under this agreement, MPLXT provides terminal storage for refined petroleum products, as well as related services, for MPC. MPC pays MPLXT monthly for such services based on contractual fees relating to MPC product deliveries as well as any viscosity surcharges, loading, handling, transfers or other related charges. This agreement is set to expire on March 31, 2026 and automatically renews for two additional renewal terms of five years each unless terminated by either party provides the other party with written notice of its intent to terminate at least 12 months prior to the end of the then-current term. Under the agreement, HSM provides marine transportation of crude oil, feedstocks and refined petroleum products, as well as related services. Under the agreement MPC pays HSM monthly for the following: the specified day rate for equipment and charges for services related to transportation, tankerman services and cleaning and repair charges. Fleeting services are billed monthly.party.

~~HSM entered into a management~~The Partnership is party to various employee services ~~agreement~~agreements with MPC ~~on January 1, 2015 with an initial term of six years and automatically renews for two additional renewal terms of five years each unless either party provides~~under which the ~~other party with written notice of its intent to terminate at least 12 months prior to the end of the then-current term. Under this agreement, HSM provides management services to assist~~Partnership reimburses MPC in the oversight and management of the MPC marine business. HSM receives a fixed annual fee in monthly installments for providing the required management services. This fee is adjusted annually on the anniversary of the contract for inflation and any changes in the scope of the management services provided.

On January 1, 2015, HSM employees were transferred to Marathon Petroleum Logistics Services LLC ("MPLS"), a wholly-owned subsidiary of MPC, and HSM and MPLS entered into an employee services agreement. Under the agreement, HSM reimburses MPLS for employee benefit expenses, along with ~~certain~~the provision of operational and management services, ~~provided~~including those in support of ~~HSM’s areas of operation. The employee services agreement has an initial term of six years~~HST, WHC and automatically renews for two additional renewal terms of five years each unless either party provides the other party with written notice of its intent to terminate at least 12 months prior to the end of the then-current term.MPLXT.

1819

~~Table of Contents~~

Related Party Transactions

Sales to related parties were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2016		2015		2016		2015		2017		2016		2017		2016
Service revenues
MPC	$	145	$	152	$	295	$	294	$	270	$	246	$	525	$	423
Rental income
MPC	$	29	$	25	$	55	$	50	$	70	$	66	$	137	$	104
Product sales⁽¹⁾
MPC	$	3	$	—	$	6	$	—	$	2	$	3	$	4	$	6

(1)

~~For the three and six months ended June 30, 2016, there~~There were ~~$7 million and $12 million, respectively, of~~ additional product sales to MPC that net to zero within ~~our~~the consolidated financial statements as the transactions are recorded net due to the terms of the agreements under which such product was sold. For the three and six months ended June 30, 2017, these sales totaled $53 million and $110 million, respectively. For the three and six months ended June 30, 2016, these sales totaled $7 million and $12 million, respectively.

Related party sales to MPC consist of crude oil and refined products pipeline transportation services based on regulated tariff rates, storage services based on contracted rates and transportation services provided by HSM. Under the Partnership’s pipeline 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 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 credits. The use or expiration of the credits is a decrease in Deferred revenue-related parties.

The revenue received from related parties, included in Other income-related parties on the Consolidated Statements of Income, was as follows:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2016		2015		2016		2015		2017		2016		2017		2016
MPC	$	16	$	18	$	33	$	34	$	10	$	12	$	21	$	26
MarkWest Utica EMG	5		—		7		—		4		5		8		7
Ohio Gathering	3		—		7		—		4		3		8		7
Ohio Condensate	1		—		2		—
Other	3		—		3		1		7		4		10		5
Total	$	28	$	18	$	52	$	35	$	25	$	24	$	47	$	45

MPC provides executive management services and certain general and administrative services to the Partnership under the terms of an omnibus agreement. Expenses incurred under this agreement are shown in the table below by the income statement line where they were recorded. Charges for services included in Purchases-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:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2016		2015		2016		2015		2017		2016		2017		2016
Purchases - related parties	$	5	$	7	$	11	$	14	$	18	$	11	$	33	$	18
General and administrative expenses	7		11		15		22		11		12		19		22
Total	$	12	$	18	$	26	$	36	$	29	$	23	$	52	$	40

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~~Table of Contents~~

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:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2016		2015		2016		2015		2017		2016		2017		2016
MPC	$	9	$	4	$	18	$	6	$	12	$	12	$	22	$	22

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-related parties. The costs of personnel involved in executive management, accounting and human resources activities are classified as General and administrative ~~expenses.~~expenses in the Consolidated Statements of Income.

Employee services expenses from related parties were as follows:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2016		2015		2016		2015		2017		2016		2017		2016
Purchases - related parties	$	73	$	33	$	143	$	66	$	91	$	88	$	183	$	159
General and administrative expenses	19		8		40		15		24		27		49		48
Total	$	92	$	41	$	183	$	81	$	115	$	115	$	232	$	207

Receivables from ~~related parties were as follows:~~

(In millions) June 30, 2016 December 31, 2015
MPC $ 104
$ 175
MarkWest Utica EMG 5
4
Ohio Gathering 3
5
Other 1
3
Total $ 113
$ 187

~~Long-term receivables with~~ related parties, which include reimbursements from the MarkWest Merger to be provided by MPC for the conversion of Class B units, ~~and~~were as follows:



(In millions)	June 30, 2017		December 31, 2016
MPC	$	167	$	242
MarkWest Utica EMG	1		2
Ohio Gathering	2		2
Other	3		1
Total	$	173	$	247

Long-term receivables with related parties, which includes straight-line rental income, were as follows:


(In millions)	June 30, 2016		December 31, 2015		June 30, 2017		December 31, 2016
MPC	$	26	$	25	$	16	$	11

Payables to related parties were as follows:


(In millions)	June 30, 2016		December 31, 2015		June 30, 2017		December 31, 2016
MPC	$	51	$	33	$	74	$	63
MarkWest Utica EMG	14		21		15		24
Other					4		—
Total	$	65	$	54	$	93	$	87

During the six months ended June 30, ~~2016~~2017 and the year ended December 31, ~~2015,~~2016, MPC did not ship its minimum committed volumes on certain pipeline systems. In addition, capital projects the Partnership is 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 balance associated with the minimum volume deficiencies and project reimbursements were as follows:


(In millions)	June 30, 2016		December 31, 2015		June 30, 2017		December 31, 2016
Minimum volume deficiencies - MPC	$	43	$	36	$	51	$	48
Project reimbursements - MPC	5		5		21		9
Total	$	48	$	41	$	72	$	57

2021

~~Table of Contents~~

6. Net Income (Loss) Per Limited Partner Unit

Net income (loss) 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 (loss) 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 (loss) per unit applicable to limited partners. The classes of participating securities include common units, ~~subordinated units,~~ general partner units, ~~preferred~~Preferred units, certain equity-based compensation awards and incentive distribution rights (“IDRs”).

As discussed in Note 1, the ~~HSM~~HST, WHC and MPLXT acquisition was a transfer between entities under common control. As ~~an entity~~entities under common control with MPC, prior periods were retrospectively adjusted to furnish comparative information. Accordingly, the prior period earnings have been allocated to the general partner and do not affect the net income (loss) per unit calculation. The earnings for ~~HSM~~the entities acquired under common control will be included in the net income (loss) per unit calculation prospectively as described above.

As discussed further in Note 7, 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 (loss) per unit, the subordinated units were treated as if they converted to common units on July 1, 2015.

For the three and six months ended June 30, 2017 and 2016, the Partnership had dilutive potential common units consisting of certain equity-based compensation awards and Class B units. Diluted net income (loss) per limited partner unit for the three and six months ended June 30, 2016 is the same as basic net income (loss) per limited partner unit since the inclusion of any potential common units would have been anti-dilutive. Potential common units omitted from the diluted earnings per unit calculation ~~was~~for the three and six months ended June 30, 2017 were less than one million and for three and six months ended June 30, 2016 were approximately 10 million.

Three Months Ended June 30, Six Months Ended June 30,
(In millions) 2016 2015 2016 2015
Net (loss) income attributable to MPLX LP $ 19
$ 51
$ (41 ) $ 97
Less: Limited partners’ distributions declared
on preferred units ⁽¹⁾
9
—
9
—
General partner’s distributions declared (including IDRs)⁽¹⁾
50
6
94
10
Limited partners’ distributions declared on common units ⁽¹⁾
172
19
328
37
Limited partner’s distributions declared
on subordinated units ⁽¹⁾
—
17
—
32
Undistributed net (loss) income attributable to MPLX LP $ (212 )
$ 9
$ (472 ) $ 18



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2017			2016			2017			2016
Net income (loss) attributable to MPLX LP	$	190		$	19		$	340		$	(41	)
Less: Limited partners’ distributions declared on Preferred units⁽¹⁾	17			9			33			9
General partner’s distributions declared (including IDRs)⁽¹⁾	76			50			141			94
Limited partners’ distributions declared on common units⁽¹⁾	218			172			416			328
Undistributed net loss attributable to MPLX LP	$	(121	)	$	(212	)	$	(250	)	$	(472	)


(1)	See Note 7 for distribution information.

~~Table of Contents~~

Three Months Ended June 30, 2016
(In millions, except per unit data)
General
Partner

Limited
Partners’
Common
Units
Preferred Units Total
Basic and diluted net income (loss) attributable to MPLX LP per unit:
Net income (loss) attributable to MPLX LP:
Distributions declared (including IDRs) $ 50
$ 172
$ 9
$ 231
Undistributed net loss attributable to MPLX LP (5 ) (207 ) —
(212 )
Net income (loss) attributable to MPLX LP ⁽¹⁾
$ 45
$ (35 ) $ 9
$ 19
Weighted average units outstanding:
Basic 7
331
17
355
Diluted 7
331
17
355
Net loss attributable to MPLX LP per limited partner unit:
Basic $ (0.11 )
Diluted $ (0.11 )


	Three Months Ended June 30, 2015								Three Months Ended June 30, 2017
(In millions, except per unit data)	General Partner		Limited Partners’ Common Units		Limited Partner’s Subordinated Units		Total		General Partner			Limited Partners’ Common Units			Redeemable Preferred Units		Total
Basic and diluted net income attributable to MPLX LP per unit:
Net income attributable to MPLX LP:
Distributions declared (including IDRs)	$	6	$	19	$	17	$	42	$	76		$	218		$	17	$	311
Undistributed net income attributable to MPLX LP	5		2		2		9
Undistributed net loss attributable to MPLX LP									(2		)	(119		)	—		(121		)
Net income attributable to MPLX LP ⁽¹⁾	$	11	$	21	$	19	$	51	$	74		$	99		$	17	$	190
Weighted average units outstanding:
Basic	2		43		37		82		8			377			31		416
Diluted	2		43		37		82		8			382			31		421
Net income attributable to MPLX LP per limited partner unit:
Basic			$	0.50	$	0.50						$	0.26
Diluted			$	0.50	$	0.50						$	0.26

~~Table of Contents~~

Six Months Ended June 30, 2016
(In millions, except per unit data)
General
Partner

Limited
Partners’
Common
Units
Preferred Units Total
Basic and diluted net income (loss) attributable to MPLX LP per unit:
Net income (loss) attributable to MPLX LP:
Distributions declared (including IDRs) $ 94
$ 328
$ 9
$ 431
Undistributed net loss attributable to MPLX LP (9 ) (463 ) —
(472 )
Net income (loss) attributable to MPLX LP ⁽¹⁾
$ 85
$ (135 ) $ 9
$ (41 )
Weighted average units outstanding:
Basic 7
316
8
331
Diluted 7
316
8
331
Net loss attributable to MPLX LP per limited partner unit:
Basic $ (0.43 )
Diluted $ (0.43 )


	Six Months Ended June 30, 2015								Three Months Ended June 30, 2016
(In millions, except per unit data)	General Partner		Limited Partners’ Common Units		Limited Partner’s Subordinated Units		Total		General Partner			Limited Partners’ Common Units			Redeemable Preferred Units		Total
Basic and diluted net income attributable to MPLX LP per unit:
Net income attributable to MPLX LP:
Basic and diluted net income (loss) attributable to MPLX LP per unit:
Net income (loss) attributable to MPLX LP:
Distributions declared (including IDRs)	$	10	$	37	$	32	$	79	$	50		$	172		$	9	$	231
Undistributed net income attributable to MPLX LP	9		5		4		18
Net income attributable to MPLX LP ⁽¹⁾	$	19	$	42	$	36	$	97
Undistributed net loss attributable to MPLX LP									(5		)	(207		)	—		(212		)
Net income (loss) attributable to MPLX LP⁽¹⁾									$	45		$	(35	)	$	9	$	19
Weighted average units outstanding:
Basic	2		43		37		82		7			331			17		355
Diluted	2		43		37		82		7			331			17		355
Net income attributable to MPLX LP per limited partner unit:
Net loss attributable to MPLX LP per limited partner unit:
Basic			$	0.96	$	0.96						$	(0.11	)
Diluted			$	0.96	$	0.96						$	(0.11	)



	Six Months Ended June 30, 2017
(In millions, except per unit data)	General Partner			Limited Partners’ Common Units			Redeemable Preferred Units		Total
Basic and diluted net income attributable to MPLX LP per unit:
Net income attributable to MPLX LP:
Distributions declared (including IDRs)	$	141		$	416		$	33	$	590
Undistributed net loss attributable to MPLX LP	(5		)	(245		)	—		(250		)
Net income attributable to MPLX LP⁽¹⁾	$	136		$	171		$	33	$	340
Weighted average units outstanding:
Basic	8			370			31		$	409
Diluted	8			374			31		413
Net income attributable to MPLX LP per limited partner unit:
Basic				$	0.46
Diluted				$	0.46



	Six Months Ended June 30, 2016
(In millions, except per unit data)	General Partner			Limited Partners’ Common Units			Redeemable Preferred Units		Total
Basic and diluted net income (loss) attributable to MPLX LP per unit:
Net income (loss) attributable to MPLX LP:
Distributions declared (including IDRs)	$	94		$	328		$	9	$	431
Undistributed net loss attributable to MPLX LP	(9		)	(463		)	—		(472		)
Net income (loss) attributable to MPLX LP⁽¹⁾	$	85		$	(135	)	$	9	$	(41	)
Weighted average units outstanding:
Basic	7			316			8		331
Diluted	7			316			8		331
Net loss attributable to MPLX LP per limited partner unit:
Basic				$	(0.43	)
Diluted				$	(0.43	)


(1)	Allocation of net income (loss) attributable to MPLX LP assumes all earnings for the period had been distributed based on the current period distribution priorities.

7. Equity

~~Units Outstanding~~– The Partnership had 331,283,429 common units outstanding as of June 30, 2016. Of that number, 79,466,136 were owned by MPC, which also owned the two percent general partner interest, represented by 7,506,520 general partner units.

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.

~~ATM Program~~ – On March 4, 2016, the Partnership entered into an amended and restated distribution agreement providing for the continuous issuance of up to an aggregate of $500 million of common units, in amounts, at prices and on terms to be

~~Table of Contents~~

determined by market conditions and other factors at the time of any offerings (such continuous offering program, or at-the-market program, referred to as the “ATM Program”). The Partnership expects the net proceeds from sales under the ATM Program will be used for general partnership purposes. During the six months ended June 30, 2016, the sale of common units under the ATM Program generated net proceeds of approximately $315 million.

The changes in the number of units outstanding ~~from December 31, 2015 through~~during the six months ended June 30, ~~2016~~2017 are summarized below:


(In units)	Common	Class B⁽¹⁾	General Partner	Total	Common	Class B⁽¹⁾	General Partner	Total
Balance at December 31, 2015	296,687,176	7,981,756	6,800,475	311,469,407
Balance at December 31, 2016					357,193,288	3,990,878	7,371,105	368,555,271
Unit-based compensation awards⁽²⁾	37,251	—	761	38,012	168,622	—	3,441	172,063
Issuance of units under the ATM Program⁽³⁾	12,025,000	—	245,406	12,270,406	12,662,663	—	258,422	12,921,085
Contribution of HSM⁽⁴⁾	22,534,002	—	459,878	22,993,880
Balance at June 30, 2016	331,283,429	7,981,756	7,506,520	346,771,705
Contribution of HST/WHC/MPLXT⁽⁴⁾					12,960,376	—	264,497	13,224,873
Balance at June 30, 2017					382,984,949	3,990,878	7,897,465	394,873,292


(1)	On July 1, ~~2016,~~2017, 3,990,878 Class B units converted to 4,350,057 common units and will be eligible to receive the second quarter 2017 distribution.


(2)	As a result of the unit-based compensation awards issued during the period, MPLX GP contributed less than $1 million in exchange for ~~761~~3,441 general partner units to maintain its two percent ~~general partner interest.~~GP Interest.


(3)	As a result of common units issued under the ATM Program during the period, MPLX GP contributed $6$9 million in exchange for ~~245,406~~258,422 general partner units to maintain its two percent ~~general partner interest.~~GP Interest.


(4)	See Note 3 for information regarding the ~~HSM~~HST, WHC and MPLXT acquisition.

~~Issuance of Additional Securities~~–The partnership agreement authorizes the issuance of 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.

Net ~~(Loss)~~ Income Allocation – In preparing the Consolidated Statements of Equity, net income (loss) ~~income~~ attributable to MPLX LP is allocated to ~~preferred~~Preferred unitholders based on a fixed distribution schedule, as discussed in Note 8, and subsequently allocated to ~~remaining unitholders in accordance with their respective ownership percentages.~~the general partner and limited partner unitholders. 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~~GP Interest in net income attributable to MPLX LP:

Three Months Ended June 30, Six Months Ended June 30,
(In millions) 2016 2015 2016 2015
Net (loss) income attributable to MPLX LP $ 19
$ 51
$ (41 ) $ 97
Less: Preferred unit distributions 9
—
9
—
General partner's incentive distribution
rights and other
47
6
88
9
Net (loss) income attributable to MPLX LP available to general and limited partners $ (37 ) $ 45
$ (138 ) $ 88

General partner's two percent interest in net (loss) income attributable to MPLX LP $ (1 ) $ 1
$ (3 ) $ 2
General partner's incentive distribution rights and other 47
6
88
9
General partner's interest in net income attributable to MPLX LP $ 46
$ 7
$ 85
$ 11



	Three Months Ended June 30,					Six Months Ended June 30,
(In millions)	2017		2016			2017		2016
Net income (loss) attributable to MPLX LP	$	190	$	19		$	340	$	(41	)
Less: Preferred unit distributions	17		9			33		9
General partner's incentive distribution rights and other	72		47			133		88
Net income (loss) attributable to MPLX LP available to general and limited partners	$	101	$	(37	)	$	174	$	(138	)

General partner's two percent GP Interest in net income (loss) attributable to MPLX LP	$	2	$	(1	)	$	3	$	(3	)
General partner's incentive distribution rights and other	72		47			133		88
General partner's GP Interest in net income attributable to MPLX LP	$	74	$	46		$	136	$	85

Cash distributions – The partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common ~~and subordinated~~unitholders, Preferred unitholders and general partner will receive. In accordance with the partnership agreement, on July ~~22, 2016,~~26, 2017, the Partnership declared a quarterly cash distribution, based on the results of ~~$0.5100~~the second quarter of 2017, totaling $294 million, or $0.5625 per ~~unit, resulting in total distributions of $222 million.~~common unit. These distributions will be paid on August ~~12, 2016~~14, 2017 to common unitholders of record on August ~~2, 2016.~~7, 2017.

~~Table of Contents~~

The allocation of total quarterly cash distributions to ~~preferred,~~ general, limited and ~~limited partners~~Preferred unitholders is as follows for the three and six months ended June 30, ~~2016~~2017 and ~~2015.~~2016. The Partnership’s 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.

Three Months Ended June 30, Six Months Ended June 30,
(In millions) 2016 2015 2016 2015
General partner's distributions:
General partner's distributions $ 4
$ 1
$ 8
$ 2
General partner's incentive distribution rights distributions 46
6
86
9
Total general partner's distributions $ 50
$ 7
$ 94
$ 11
Limited partners' distributions:
Common unitholders $ 172
$ 19
$ 328
$ 37
Subordinated unitholders —
16
—
31
Total limited partners' distributions 172
35
328
68
Preferred unit distributions 9
—
9
—
Total cash distributions declared $ 231
$ 42
$ 431
$ 79



	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2017		2016		2017		2016
General partner's distributions:
General partner's distributions on general partner units	$	6	$	4	$	11	$	8
General partner's distributions on incentive distribution rights	70		46		130		86
Total distribution on general partner units and incentive distribution rights	$	76	$	50	$	141	$	94
Common and preferred unit distributions:
Common unitholders, includes common units of general partner	$	218	$	172	$	416	$	328
Preferred unit distributions	17		9		33		9
Total cash distributions declared	$	311	$	231	$	590	$	431

8. Redeemable Preferred Units

Private Placement of Preferred Units – On May 13, 2016, MPLX LP completed the private placement of approximately 30.8 million 6.5 percent Series A Convertible Preferred ~~Units~~units (the "Preferred ~~Units"~~units") for a cash purchase price of $32.50 per unit. The aggregate net proceeds of approximately $984 million from the sale of the Preferred ~~Units was~~units were used for capital expenditures, repayment of debt and general partnership purposes.

The Preferred ~~Units~~units rank senior to all common units with respect to distributions and rights upon liquidation. The holders of the Preferred ~~Units~~units are entitled to receive cumulative quarterly distributions equal to $0.528125 per ~~unit commencing for the quarter ended June 30, 2016, with a prorated amount from the date of issuance.~~unit. Following the second anniversary of the issuance of the Preferred ~~Units,~~units, the holders of the Preferred ~~Units~~units will receive as a distribution the greater of $0.528125 per unit or the amount of per unit distributions paid to common units. Since the Preferred Unit distribution was declared subsequent to the end of the second quarter of 2016, the distribution was not accrued to the Preferred Unit holders’ capital account. For the quarter ended June 30, 2016, the Preferred Units will receive an earned aggregate cash distribution of $9 million, based on the quarterly per unit distribution prorated for the 49-day period the Preferred Units were outstanding during the second quarter of 2016.

The changes in the redeemable preferred balance ~~for~~from December 31, 2016 ~~were as follows:~~through June 30, 2017 are summarized below:

(In millions) Redeemable Preferred Units
Issuance of MPLX LP redeemable preferred units on May 13, 2016 $ 984
Net income allocated for May 13, 2016 through June 30, 2016 9
Balance at June 30, 2016 $ 993



(In millions)	Redeemable Preferred Units
Balance at December 31, 2016	$	1,000
Net income	33
Distributions received by Preferred unitholders	(33		)
Balance at June 30, 2017	$	1,000

The purchasers may convert their Preferred ~~Units~~units into common units at any time after the third anniversary of the issuance date or prior to liquidation, dissolution or winding up of the Partnership, in full or in part, subject to minimum conversion amounts and conditions. After the fourth anniversary of the issuance date, the Partnership may convert the Preferred ~~Units~~units into common units at any time, in whole or in part, subject to certain minimum conversion amounts and conditions, if the closing price of MPLX LP common units is greater than $48.75 for the 20 day trading period immediately preceding the conversion notice date. The conversion rate for the Preferred ~~Units~~units shall be the quotient of (a) the sum of (i) $32.50, plus (ii) any unpaid cash distributions on the applicable Preferred ~~Unit,~~unit, divided by (b) $32.50. The holders of the Preferred ~~Units~~units are entitled to vote on an as-converted basis with the common unitholders and will have certain other class voting rights with respect to any amendment to the partnership agreement that would adversely affect any rights, preferences or privileges of the Preferred ~~Units.~~units. In addition, upon certain events involving a change in control the holders of Preferred ~~Units~~units may elect, among other potential elections, to convert their Preferred ~~Units~~units to common units at the ~~then change~~then-change of control conversion rate.

~~Table of Contents~~

The Preferred ~~Units~~units are considered redeemable securities under GAAP due to the existence of redemption provisions upon a deemed liquidation event which is outside the Partnership’s control. Therefore, they are presented as temporary equity in the mezzanine section of the Consolidated Balance Sheets. The Preferred ~~Units~~units have been recorded at their issuance date fair value, net of issuance costs. Income allocations increase the carrying value, and declared distributions decreased the carrying value of the Preferred ~~Units. Because~~units. As the Preferred ~~Units~~units are not currently redeemable and not probable of becoming redeemable, adjustment to the initial carrying amount is not necessary and would only be required if it becomes probable that the Preferred ~~Units~~units would become redeemable.

9. 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 isare organized and managed based upon the nature of the products and services it offers.

L&S -– transports, stores and ~~stores~~distributes crude oil and refined petroleum products. Segment information for prior periods includes ~~HSM~~HST, WHC and MPLXT as ~~it is an entity~~they are entities under common control. Segment information for periods prior to the Ozark pipeline acquisition does not include amounts for these operations. See Note 3 for more detail of these acquisitions.

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 3. 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 4). However, the CEO views the ~~Partnership operated~~Partnership-operated equity method investments’ 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), ~~property, plant and equipment~~goodwill impairment, ~~goodwill impairment~~certain management fees 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~~partially-owned entities that are either consolidated or accounted for as equity method investments. Segment operating income attributable to MPLX LP excludes the operating income related to Predecessors of the HSM, HST, WHC and MPLXT businesses prior to the dates they were acquired by MPLX LP.

The tables below present information about income from operations and capital expenditures for the reported segments:

Three Months Ended June 30, 2016
(In millions) L&S G&P Total
Revenues and other income:
Segment revenues $ 193
$ 530
$ 723
Segment other income 18
—
18
Total segment revenues and other income 211
530
741
Costs and expenses:
Segment cost of revenues 88
223
311
Segment operating income before portion attributable to noncontrolling interest 123
307
430
Segment portion attributable to noncontrolling interest and Predecessor —
36
36
Segment operating income attributable to MPLX LP $ 123
$ 271
$ 394

~~Table of Contents~~

Three Months Ended June 30, 2015
(In millions) L&S
Revenues and other income:
Segment revenues $ 193
Segment other income 20
Total segment revenues and other income 213
Costs and expenses:
Segment cost of revenues 90
Segment operating income before portion attributable to noncontrolling interest and Predecessor 123
Segment portion attributable to noncontrolling interest and Predecessor 35
Segment operating income attributable to MPLX LP $ 88

Six Months Ended June 30, 2016
(In millions) L&S G&P Total
Revenues and other income:
Segment revenues $ 385
$ 1,028
$ 1,413
Segment other income 37
—
37
Total segment revenues and other income 422
1,028
1,450
Costs and expenses:
Segment cost of revenues 177
423
600
Segment operating income before portion attributable to noncontrolling interest 245
605
850
Segment portion attributable to noncontrolling interest and Predecessor 34
77
111
Segment operating income attributable to MPLX LP $ 211
$ 528
$ 739


	Six Months Ended June 30, 2015		Three Months Ended June 30, 2017
(In millions)	L&S		L&S		G&P		Total
Revenues and other income:
Segment revenues	$	376	$	372	$	603	$	975
Segment other income	38		12		—		12
Total segment revenues and other income	414		384		603		987
Costs and expenses:
Segment cost of revenues	176		176		252		428
Segment operating income before portion attributable to noncontrolling interest and Predecessor	238
Segment portion attributable to noncontrolling interest and Predecessor	68
Segment operating income before portion attributable to noncontrolling interests and Predecessor			208		351		559
Segment portion attributable to noncontrolling interests and Predecessor			—		38		38
Segment operating income attributable to MPLX LP	$	170	$	208	$	313	$	521

~~Table of Contents~~



	Three Months Ended June 30, 2016
(In millions)	L&S		G&P		Total
Revenues and other income:
Segment revenues	$	331	$	530	$	861
Segment other income	14		—		14
Total segment revenues and other income	345		530		875
Costs and expenses:
Segment cost of revenues	142		223		365
Segment operating income before portion attributable to noncontrolling interests and Predecessor	203		307		510
Segment portion attributable to noncontrolling interests and Predecessor	80		36		116
Segment operating income attributable to MPLX LP	$	123	$	271	$	394



	Six Months Ended June 30, 2017
(In millions)	L&S		G&P		Total
Revenues and other income:
Segment revenues	$	717	$	1,200	$	1,917
Segment other income	24		1		25
Total segment revenues and other income	741		1,201		1,942
Costs and expenses:
Segment cost of revenues	324		505		829
Segment operating income before portion attributable to noncontrolling interests and Predecessor	417		696		1,113
Segment portion attributable to noncontrolling interests and Predecessor	53		74		127
Segment operating income attributable to MPLX LP	$	364	$	622	$	986



	Six Months Ended June 30, 2016
(In millions)	L&S		G&P		Total
Revenues and other income:
Segment revenues	$	562	$	1,028	$	1,590
Segment other income	30		—		30
Total segment revenues and other income	592		1,028		1,620
Costs and expenses:
Segment cost of revenues	239		423		662
Segment operating income before portion attributable to noncontrolling interests and Predecessor	353		605		958
Segment portion attributable to noncontrolling interests and Predecessor	142		77		219
Segment operating income attributable to MPLX LP	$	211	$	528	$	739


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015			2017			2016			2017			2016
Reconciliation to Income from operations:
L&S segment operating income attributable to MPLX LP													$	208		$	123		$	364		$	211
G&P segment operating income attributable to MPLX LP													313			271			622			528
Segment operating income attributable to MPLX LP	$	394		$	88		$	739		$	170		521			394			986			739
Segment portion attributable to unconsolidated affiliates	(83		)	—			(166		)	—			(38		)	(47		)	(78		)	(89		)
Segment portion attributable to noncontrolling interest and Predecessor	36			35			111			68
Loss from equity method investments	(83		)	—			(78		)	—
Segment portion attributable to Predecessor													—			80			53			142
Income (loss) from equity method investments													1			(83		)	6			(78		)
Other income - related parties	11			—			18			—			14			11			25			18
Unrealized derivative losses	(12		)	—			(21		)	—
Unrealized derivative gains (losses)⁽¹⁾													3			(12		)	19			(21		)
Depreciation and amortization													(164		)	(151		)	(351		)	(287		)
Impairment expense	(1		)	—			(130		)	—			—			(1		)	—			(130		)
Depreciation and amortization	(137		)	(20		)	(269		)	(39		)
General and administrative expenses	(49		)	(21		)	(101		)	(43		)	(57		)	(63		)	(115		)	(116		)
Income from operations	$	76		$	82		$	103		$	156		$	280		$	128		$	545		$	178


	Three Months Ended June 30,					Six Months Ended June 30,					Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015		2016			2015		2017			2016			2017			2016
Reconciliation to Total revenues and other income:
Total segment revenues and other income	$	741		$	213	$	1,450		$	414	$	987		$	875		$	1,942		$	1,620
Revenue adjustment from unconsolidated affiliates	(99		)	—		(203		)	—		(88		)	(99		)	(180		)	(203		)
Loss from equity method investments	(83		)	—		(78		)	—
Income (loss) from equity method investments											1			(83		)	6			(78		)
Other income - related parties	11			—		18			—		14			11			25			18
Unrealized derivative loss	(6		)	—		(14		)	—
Unrealized derivative gains (losses) related to product sales⁽¹⁾											2			(6		)	9			(14		)
Total revenues and other income	$	564		$	213	$	1,173		$	414	$	916		$	698		$	1,802		$	1,343

(1)

The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded.


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015			2017			2016			2017			2016
Reconciliation to Net income attributable to noncontrolling interests and Predecessor
Segment portion attributable to noncontrolling interest and Predecessor	$	36		$	35		$	111		$	68
Reconciliation to Net income attributable to noncontrolling interests and Predecessor:
Segment portion attributable to noncontrolling interests and Predecessor													$	38		$	116		$	127		$	219
Portion of noncontrolling interests and Predecessor related to items below segment income from operations	(56		)	(10		)	(85		)	(21		)	(27		)	(84		)	(63		)	(118		)
Portion of operating income attributable to noncontrolling interest of unconsolidated affiliates	21			—			(2		)	—
Portion of operating (income) loss attributable to noncontrolling interests of unconsolidated affiliates													(10		)	21			(26		)	(2		)
Net income attributable to noncontrolling interests and Predecessor	$	1		$	25		$	24		$	47		$	1		$	53		$	38		$	99

The following table reconciles segment capital expenditures to total capital expenditures:


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2016		2015		2016		2015		2017		2016		2017		2016
L&S segment capital expenditures	$	82	$	35	$	144	$	70	$	136	$	106	$	233	$	181
G&P segment capital expenditures⁽¹⁾	212		—		485		—		317		212		624		485
Total segment capital expenditures	294		35		629		70		453		318		857		666
Less: Capital expenditures for Partnership operated, non-wholly-owned subsidiaries	16		—		60		—
Less: Capital expenditures for Partnership-operated, non-wholly-owned subsidiaries in G&P segment									81		16		205		60
Total capital expenditures	$	278	$	35	$	569	$	70	$	372	$	302	$	652	$	606

~~Table of Contents~~


~~(1)~~	~~The G&P segment includes $16 million and $60 million of capital expenditures related to Partnership operated, non-wholly-owned subsidiaries for the three and six months ended June 30, 2016.~~

Total assets by reportable segment were:


(In millions)	June 30, 2016		December 31, 2015		June 30, 2017		December 31, 2016
Cash and cash equivalents					$	293	$	234
L&S	$	1,952	$	1,858	3,819		2,978
G&P	14,127		14,246		14,489		14,297
Total assets	$	16,079	$	16,104	$	18,601	$	17,509

10. ~~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 (benefit) 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’s income tax activity was less than $1 million for the three and six months ended June 30, 2015.

A reconciliation of the benefit for income tax and the amount computed by applying the federal statutory rate of 35 percent to the income before income taxes for the six months ended June 30, 2016 is as follows:

(In millions) MarkWest Hydrocarbon Partnership Eliminations
Consolidated⁽¹⁾
Income before (benefit) provision for income tax $ (35 ) $ 4
$ 2
$ (29 )
Federal statutory rate 35 % — % — %
Federal income tax at statutory rate⁽²⁾
(12 ) —
—
(12 )
Change in state statutory rate (1 ) —
—
(1 )
State income taxes net of federal benefit - MarkWest Hydrocarbon (1 ) —
—
(1 )
Provision on income from Class A units⁽²⁾
—
—
—
—
Other 1
1
—
2
(Benefit) provision for income tax $ (13 ) $ 1
$ —
$ (12 )


~~(1)~~	~~Financial information has been retrospectively adjusted for the acquisition of HSM from MPC. See Notes 1 and 3. Prior to this acquisition, MPC paid all income taxes related to HSM.~~


~~(2)~~	~~MarkWest Hydrocarbon pays tax on its share of the Partnership’s income or loss as a result of its ownership of Class A units.~~

~~11.~~ Inventories

Inventories consist of the following:


(In millions)	June 30, 2016		December 31, 2015		June 30, 2017		December 31, 2016
NGLs	$	2	$	3	$	3	$	2
Line fill	6		5		7		9
Spare parts, materials and supplies	41		43		52		44
Total inventories	$	49	$	51	$	62	$	55

~~12.~~11. Property, Plant and Equipment

Property, plant and equipment with associated accumulated depreciation ~~was:~~is shown below:


(In millions)	June 30, 2016		December 31, 2015		June 30, 2017		December 31, 2016
Natural gas gathering and NGL transportation pipelines and facilities	$	4,573	$	4,307	$	4,919	$	4,748
Processing, fractionation and storage facilities(1)	3,456		3,185		3,736		3,547
Pipelines and related assets	1,186		1,128		2,156		1,799
Barges and towing vessels	478		475		484		479
Terminals and related assets⁽¹⁾					784		759
Land, building, office equipment and other	662		606		723		757
Construction in progress	898		946
Construction-in-progress					816		1,013
Total	11,253		10,647		13,618		13,102
Less accumulated depreciation	893		650		1,980		1,694
Property, plant and equipment, net	$	10,360	$	9,997	$	11,638	$	11,408


(1)	Certain prior period amounts have been updated to conform to current period presentation.

~~13.~~

12. Fair Value Measurements

Fair Values – Recurring

Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions as discussed in Note ~~14.~~13. Money market funds, which are included in Cash and cash equivalents on the Consolidated Balance Sheets, are measured at fair value and are included in Level 1 measurements of the valuation hierarchy. Level 2 instruments include crude oil and natural gas swap contracts. Level 3 instruments include all NGL transactions and embedded derivatives in commodity contracts. The following table presents the financial instruments carried at fair value classified by the valuation hierarchy:

(In millions) June 30, 2016 December 31, 2015
Assets Liabilities Assets Liabilities
Significant other observable inputs (Level 2)
Commodity contracts $ —
$ —
$ 2
$ —
Significant unobservable inputs (Level 3)
Commodity contracts —
(4 ) 7
—
Embedded derivatives in commodity contracts 1
(41 ) —
(32 )
Total carrying value in Consolidated Balance Sheets $ 1
$ (45 ) $ 9
$ (32 )

~~Table of Contents~~



	June 30, 2017					December 31, 2016
(In millions)	Assets		Liabilities			Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	—	$	—		$	—	$	—
Significant unobservable inputs (Level 3)
Commodity contracts	2		—			—		(6		)
Embedded derivatives in commodity contracts	—		(43		)	—		(54		)
Total carrying value in Consolidated Balance Sheets	$	2	$	(43	)	$	—	$	(60	)

The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments as of June 30, ~~2016.~~2017. The market approach is used for valuation of all instruments.



Level 3 Instrument	Balance Sheet Classification	Unobservable Inputs	Value Range	Time Period
Commodity contracts	~~Liabilities~~Assets	Forward ethane prices (per gallon)⁽¹⁾	$~~0.24~~0.25 - ~~$0.28~~$0.26	July ~~2016~~17 - Dec. ~~2016~~17
		Forward propane prices (per gallon)⁽¹⁾	$~~0.52~~0.53 - ~~$0.57~~$0.63	July ~~2016~~17 - Dec. ~~2016~~18
		Forward isobutane prices (per gallon)⁽¹⁾	$~~0.69~~0.66 - ~~$0.72~~$0.76	July ~~2016~~17 - Dec. ~~2016~~18
		Forward normal butane prices (per gallon)⁽¹⁾	$~~0.63~~0.59 - ~~$0.69~~$0.74	July ~~2016~~17 - Dec. ~~2016~~18
		Forward natural gasoline prices (per gallon)⁽¹⁾	$~~0.99~~1.03 - ~~$1.03~~$1.06	July ~~2016~~17 - Dec. ~~2016~~18

Embedded derivatives in commodity contracts	Assets	ERCOT Pricing (per MegaWatt Hour)	$~~26.47~~24.62 - ~~$57.95~~$45.42	July ~~2016~~17 - Dec. ~~2016~~17
	Liabilities	Forward propane prices (per gallon)⁽¹⁾	$0.52 - ~~$0.58~~$0.63	July ~~2016~~17 - Dec. ~~2022~~22
		Forward isobutane prices (per gallon)⁽¹⁾	$~~0.67~~0.64 - ~~$0.73~~$0.76	July ~~2016~~17 - Dec. ~~2022~~22
		Forward normal butane prices (per gallon)⁽¹⁾	$~~0.62~~0.59 - ~~$0.71~~$0.74	July ~~2016~~17 - Dec. ~~2022~~22
		Forward natural gasoline prices (per gallon)⁽¹⁾	$~~0.99~~1.03 - $1.10	July ~~2016~~17 - Dec. ~~2022~~22
		Forward natural gas prices (per ~~mmbtu)~~MMBtu)⁽²⁾	$~~2.61~~2.26 - ~~$3.35~~$3.14	July ~~2016~~17 - Dec. ~~2022~~22
		Probability of renewal⁽³⁾	50.0%
		Probability of renewal for second 5-yr term⁽³⁾	75.0%


(1)	NGL prices used in the ~~valuation are generally at the lower end of the range~~valuations decrease 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~~decrease 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.

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 derivatives in commodity contracts – The Partnership has two embedded derivatives in commodity contracts, as follows:

A single embedded derivative liability comprised of both the purchase of natural gas at prices impacted by the frac spread and the probability of contract renewal (the “Natural Gas Embedded Derivative”), as discussed further in Note ~~14.~~13. Increases (decreases) in the frac spread result in an increase (decrease) in the fair value of the embedded derivative liability. An increase in the probability of renewal would result in an increase in the fair value of the related embedded derivative liability.

~~Table of Contents~~

An embedded derivative related to utilities costs discussed further in Note ~~14.~~13. Increases in the forward ERCOT prices result in ~~an increase~~a decrease in the fair value of the embedded derivative ~~asset.~~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 are 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 ~~14.~~13. 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 are 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 (July ~~2016~~2017 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; and

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 rollforward of the balance sheet amounts for the three and six months ended June 30, 2017 and 2016, respectively (including the change in fair value), for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy, except for the changes in goodwill. See Note 4 for detail of the Ohio Condensate equity method impairment charge, which included a Level 3 valuation adjustment during the three and six months ended June 30, 2016. See Note 16 for a rollforward of goodwill, which included a Level 3 valuation adjustment during the three and six months ended June 30, 2016.hierarchy.


	Three Months Ended June 30, 2016						Six Months Ended June 30, 2016						Three Months Ended June 30, 2017					Six Months Ended June 30, 2017
(In millions)	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)			Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)			Commodity Derivative Contracts (net)		Embedded Derivatives in Commodity Contracts (net)			Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	—		$	(34	)	$	7		$	(32	)	$	—	$	(44	)	$	(6	)	$	(54	)
Total loss (realized and unrealized) included in earnings⁽¹⁾	(6		)	(7		)	(7		)	(11		)
Total gains (realized and unrealized) included in earnings⁽¹⁾													2		—			7			8
Settlements	1			1			(5		)	3			—		1			1			3
Netting adjustment ⁽²⁾	1			—			1			—
Fair value at end of period	$	(4	)	$	(40	)	$	(4	)	$	(40	)	$	2	$	(43	)	$	2		$	(43	)
The amount of total loss for the period included in earnings attributable to the change in unrealized loss relating to assets still held at end of period	$	(5	)	$	(8	)	$	(6	)	$	(11	)
The amount of total gains (losses) for the period included in earnings attributable to the change in unrealized losses relating to liabilities still held at end of period													$	2	$	(1	)	$	5		$	7



	Three Months Ended June 30, 2016						Six Months Ended June 30, 2016
(In millions)	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)			Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	—		$	(34	)	$	7		$	(32	)
Total (losses) (realized and unrealized) included in earnings⁽¹⁾	(6		)	(7		)	(7		)	(11		)
Settlements	1			1			(5		)	3
Netting adjustment⁽²⁾	1			—			1			—
Fair value at end of period	$	(4	)	$	(40	)	$	(4	)	$	(40	)
The amount of total losses for the period included in earnings attributable to the change in unrealized losses relating to liabilities still held at end of period	$	(5	)	$	(8	)	$	(6	)	$	(11	)


(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 and Cost of Revenues.

(2)

Certain derivative positions are subject to master netting agreements; therefore, the Partnership has elected to offset derivative assets and liabilities where legally permissible. The Partnership may hold positions with certain counterparties, which for GAAP purposes are classified within different levels of the fair value hierarchy and may be legally permissible to offset. This adjustment represents the total impact of offsetting Level 2 positions with Level 3 positions as of June 30, 2016.

~~Table of Contents~~

which for GAAP purposes are classified within different levels of the fair value hierarchy and may be legally permissible to offset. This adjustment represents the total impact of offsetting Level 2 positions with Level 3 positions as of June 30, 2016.

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) the 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 bank revolving credit facility, if any, approximates 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 ~~14)~~13).

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 Partnership’s 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 and SMR liability fair values are considered Level 3 measurements.

The following table summarizes the fair value and carrying value of the ~~Partnership’s~~ long-term debt, excluding capital leases, and SMR ~~liability.~~liability:


	June 30, 2016				December 31, 2015				June 30, 2017				December 31, 2016
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value		Fair Value		Carrying Value
Long-term debt	$	4,748	$	4,400	$	5,212	$	5,255	$	7,362	$	6,687	$	4,953	$	4,422
SMR liability	$	105	$	98	$	99	$	100	106		93		108		96

~~14.~~13. 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~~A portion of 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.~~NGLs. 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.

~~Table of Contents~~

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.

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.~~2018. The Partnership would be exposed to additional commodity risk in certain situations such as if producers ~~under deliver~~under-deliver or ~~over deliver~~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 ~~& Resources L.L.C. (“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 and certain other qualifying 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 in current earnings. The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, changes in the fair value of the derivative are recorded as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded.

Volume of Commodity Derivative Activity

As of June 30, ~~2016,~~2017, the Partnership had the following outstanding commodity contracts that were executed to manage the cash flow risk associated with future sales of ~~NGLs:~~NGLs and purchases of natural gas:



Derivative contracts not designated as hedging instruments	Financial Position	Notional Quantity (net)
Crude Oil (bbl)	Short	~~184,000~~36,800
Natural Gas (MMBtu)	Long	~~1,088,484~~1,264,924
NGLs (gal)	Short	~~64,810,176~~58,214,105

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 June 30, 2017 and December 31, 2016, the estimated fair value of this contract was a liability of ~~$41 million.~~$43 million and $54 million, respectively.

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 a plant location in the Southwest ~~operations~~ through the fourth quarter of ~~2017.~~2018. The ~~contract~~contract’s pricing is currently fixed through the fourth quarter of ~~2016~~2017 with the ability to fix the ~~commodity contract~~pricing for its remaining year. Changes in the fair value as of the derivative component of this contract were recognized as Cost of ~~revenues~~Revenues in the Consolidated Statements of Income. As of June 30, ~~2016,~~2017, the estimated fair value of this contract was ~~an asset~~a liability of less than $1 million.

~~Table of Contents~~

Financial Statement Impact of Derivative Contracts

There were no material changes to the Partnership’s policy regarding the accounting for these instruments as previously disclosed in the Partnership’s Annual Report on Form 10-K for the year ended December 31, ~~2015,~~2016, as updated by our Current Report on Form ~~8-K/A~~8-K filed on May ~~20, 2016.~~1, 2017. The impact of the Partnership’s derivative instruments on its Consolidated Balance Sheets is summarized below:


(In millions)	June 30, 2016					December 31, 2015					June 30, 2017					December 31, 2016
Derivative contracts not designated as hedging instruments and their balance sheet location	Asset		Liability			Asset		Liability			Asset		Liability			Asset		Liability
Commodity contracts⁽¹⁾
Other current assets / other current liabilities	$	1	$	(9	)	$	9	$	(5	)	$	2	$	(6	)	$	—	$	(13	)
Other noncurrent assets / deferred credits and other liabilities	—		(36		)	—		(27		)	—		(37		)	—		(47		)
Total	$	1	$	(45	)	$	9	$	(32	)	$	2	$	(43	)	$	—	$	(60	)


(1)	Includes embedded derivatives in commodity contracts as discussed above.

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. The net amounts in the table below equal the balances presented in the Consolidated Balance Sheets:


	June 30, 2016															June 30, 2017
	Assets							Liabilities								Assets							Liabilities
(In millions)	Gross Amount		Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount of Assets in the Consolidated Balance Sheets		Gross Amount			Gross Amounts Offset in the Consolidated Balance Sheets		Net Amount of Liabilities in the Consolidated Balance Sheets			Gross Amount		Gross Amounts Offset in the Consolidated Balance Sheets			Net Amount of Assets in the Consolidated Balance Sheets		Gross Amount			Gross Amounts Offset in the Consolidated Balance Sheets		Net Amount of Liabilities in the Consolidated Balance Sheets
Current
Commodity contracts	$	2	$	(2	)	$	—	$	(6	)	$	2	$	(4	)	$	3	$	(1	)	$	2	$	(1	)	$	1	$	—
Embedded derivatives in commodity contracts	1		—			1		(5		)	—		(5		)	—		—			—		(6		)	—		(6		)
Total current derivative instruments	3		(2		)	1		(11		)	2		(9		)	3		(1		)	2		(7		)	1		(6		)

Non-current
Commodity contracts	—		—			—		—			—		—			—		—			—		—			—		—
Embedded derivatives in commodity contracts	—		—			—		(36		)	—		(36		)	—		—			—		(37		)	—		(37		)
Total non-current derivative instruments	—		—			—		(36		)	—		(36		)	—		—			—		(37		)	—		(37		)

Total derivative instruments	$	3	$	(2	)	$	1	$	(47	)	$	2	$	(45	)	$	3	$	(1	)	$	2	$	(44	)	$	1	$	(43	)

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

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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:


							Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	Three Months Ended June 30, 2016			Six Months Ended June 30, 2016			2017			2016			2017			2016
Product sales
Realized (loss) gain	$	(1	)	$	6		$	—		$	(1	)	$	(1	)	$	6
Unrealized loss	(6		)	(14		)
Total revenue: derivative loss from product sales	(7		)	(8		)
Unrealized gain (loss)							2			(6		)	9			(14		)
Total derivative gain (loss) related to product sales							2			(7		)	8			(8		)
Purchased product costs
Unrealized loss	(8		)	(9		)
Realized loss⁽¹⁾							(2		)	(2		)	(4		)	(3		)
Unrealized gain (loss)							1			(8		)	10			(9		)
Total derivative (loss) gain related to purchased product costs							(1		)	(10		)	6			(12		)
Cost of Revenues
Realized loss⁽¹⁾							—			(1		)	—			(2		)
Unrealized gain	2			2			—			2			—			2
Total loss	$	(13	)	$	(15	)
Total derivative gain related to cost of revenues							—			1			—			—
Total derivative gains (losses)							$	1		$	(16	)	$	14		$	(20	)


(1)	Certain prior period amounts have been updated to conform to current period presentation.

~~15.~~

14. Debt

The Partnership’s outstanding borrowings at ~~June 30, 2016~~ ~~and December 31, 2015~~ consisted of the following:


(In millions)	June 30, 2016			December 31, 2015			June 30, 2017			December 31, 2016
MPLX LP:
Bank revolving credit facility due 2020	$	—		$	877		$	—		$	—
Term loan facility due 2019	250			250			250			250
5.500% senior notes due 2023	710			710
4.500% senior notes due 2023	989			989
4.875% senior notes due 2024	1,149			1,149
4.000% senior notes due 2025	500			500
4.875% senior notes due 2025	1,189			1,189
5.500% senior notes due February 2023							710			710
4.500% senior notes due July 2023							989			989
4.875% senior notes due December 2024							1,149			1,149
4.000% senior notes due February 2025							500			500
4.875% senior notes due June 2025							1,189			1,189
4.125% senior notes due March 2027							1,250			—
5.200% senior notes due March 2047							1,000			—
Consolidated subsidiaries:
MarkWest - 4.500% - 5.500% senior notes, due 2023 - 2025	63			63
MarkWest - 4.500% - 5.500% senior notes, due 2023-2025							63			63
MPL - capital lease obligations due 2020	9			9			8			8
Total	4,859			5,736			7,108			4,858
Unamortized debt issuance costs	(8		)	(8		)	(28		)	(7		)
Unamortized discount⁽¹⁾	(450		)	(472		)
Unamortized discount							(413		)	(428		)
Amounts due within one year	(1		)	(1		)	(1		)	(1		)
Total long-term debt due after one year	$	4,400		$	5,255		$	6,666		$	4,422


~~(1)~~	Includes $442 million and $465 million discount as of June 30, 2016 and December 31, 2015, respectively, related to the difference between the fair value and the principal amount of the assumed MarkWest debt.

Credit Agreements

During the six months ended June 30, ~~2016,~~2017, the Partnership ~~borrowed $434 million under the bank revolving credit facility, at an average interest rate of 1.899 percent, per annum, and repaid $1.3 billion~~had no borrowings under the bank revolving credit facility. At June 30, ~~2016,~~2017, the Partnership had no outstanding borrowings and $8$3 million letters of credit outstanding under this facility, resulting in total availability of ~~$1.99~~$2.0 billion, or ~~99.6~~99.9 percent of the borrowing capacity.

The $250 million term loan facility was drawn in full on November 20, 2014. The borrowings under this facility during the six months ended June 30, ~~2016~~2017 were at an average interest rate of ~~1.931~~2.377 percent.

Senior Notes

~~16. Goodwill~~

The Partnership annually evaluates goodwill for impairment as of November 30, as well as whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit with goodwill is less than its carrying amount.

During the first quarter of 2016, the Partnership determined that an interim impairment analysis of the goodwill recorded in connection with the MarkWest Merger was necessary based on consideration of a number of first quarter events and circumstances, including i) continued deterioration of near term commodity prices as well as longer term pricing trends, ii) recent guidance on reductions to forecasted capital spending, the slowing of drilling activity and the resulting reduced production growth forecasts released or communicated by the Partnership’s producer customers and iii) increases in cost of capital. The combination of these factors was considered to be a triggering event requiring an interim impairment test. Based on the first step of the interim goodwill impairment analysis, the fair value for the three reporting units to which goodwill was assigned in connection with the MarkWest Merger was less than the respective carrying value. In step two of the impairment analysis, the implied fair values of the goodwill were compared to the carrying values within those reporting units. Based on this assessment, it was determined that goodwill was impaired in two of the three reporting units. Accordingly, the Partnership recorded an impairment charge of approximately $129 million in the first quarter of 2016. In the second quarter of 2016,On February 10, 2017, the Partnership completed ~~its purchase price allocation, which resulted~~a public offering of $2.25 billion aggregate principal amount of unsecured senior notes, consisting of (i) $1.25 billion aggregate principal amount of 4.125 percent senior notes due in ~~an additional $1 million~~March 2027 and (ii) $1.0 billion aggregate principal amount of ~~impairment expense that would have been recorded~~5.200 percent senior notes due in March 2047 (collectively, the ~~first quarter of 2016 had~~“New Senior Notes”). The net proceeds from the ~~purchase price allocation been completed as of that date. This adjustment to the impairment expense was the result of completing an evaluation~~New Senior Notes totaled approximately $2.22 billion, after deducting underwriting discounts, and were used for general partnership purposes and capital expenditures. Interest on each series of the ~~deferred tax liabilities associated with the MarkWest Merger~~notes is payable semi-annually in arrears on March 1 and ~~their impact~~September 1, commencing on ~~the resulting goodwill that was recognized.~~September 1, 2017.

The fair value of the reporting units for the interim goodwill impairment analysis was determined based on applying the discounted cash flow method, which is an income approach, and the guideline public company method, which is a market approach. The discounted cash flow fair value estimate is based on known or knowable information at the interim measurement date. The significant assumptions that were used to develop the estimates of the fair values under the discounted cash flow method include management’s best estimates of the expected future results and discount rates, which range from 10.5 percent to 11.5 percent. 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 11.5 percent to 12.8 percent. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the interim goodwill impairment test will prove to be an accurate prediction of the future. The fair value measurements for the individual reporting units’ overall fair values, and the fair values of the goodwill assigned thereto, represent Level 3 measurements.

~~The changes in carrying amount of goodwill for 2016 were as follows:~~

(In millions) L&S G&P Total
Gross goodwill as of December 31, 2015 $ 116
$ 2,454
$ 2,570
Accumulated impairment losses —
—
—
Balance as of December 31, 2015 116
2,454
2,570
Purchase price allocation adjustments⁽¹⁾
—
(241 ) (241 )
Impairment losses —
(130 ) (130 )
Balance as of June 30, 2016 $ 116
$ 2,083
$ 2,199

Gross goodwill as of June 30, 2016 $ 116
$ 2,213
$ 2,329
Accumulated impairment losses —
(130 ) (130 )
Balance as of June 30, 2016 $ 116
$ 2,083
$ 2,199


~~(1)~~	~~See Note 3 for further discussion on purchase price allocation adjustments.~~

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~~17.~~15. Supplemental Cash Flow Information


	Six Months Ended June 30,					Six Months Ended June 30,
(In millions)	2016			2015		2017		2016
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	109		$	2	$	99	$	109
Non-cash investing and financing activities:
Net transfers of property, plant and equipment from materials and supplies inventories	$	(5	)	$	—	$	5	$	(4	)
Contribution of fixed assets to joint venture⁽¹⁾						337		—


(1)	Contribution of assets to Sherwood Midstream and Sherwood Midstream Holdings. 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:

Six Months Ended June 30,
(In millions) 2016 2015
(Decrease) increase in capital accruals $ (6 ) $ 13

In connection with the acquisition of HSM described in Note 3, MPC agreed to waive first quarter 2016 distributions on the MPLX common units issued in connection with the transaction. MPC did not receive general partner distributions or incentive distribution rights that would have otherwise accrued on such MPLX common units with respect to the first quarter distributions. The value of these waived distributions was $15 million.



	Six Months Ended June 30,
(In millions)	2017		2016
Increase (decrease) in capital accruals	$	33	$	(7	)

~~18.~~16. Equity-Based Compensation

Phantom Units – The following is a summary of phantom unit award activity of MPLX LP common ~~limited partner~~ units for the six months ended June 30, ~~2016~~2017:


	Number of Units		Weighted Average Fair Value		Number of Units		Weighted Average Fair Value
Outstanding at December 31, 2015	1,031,219		$	35.49
Outstanding at December 31, 2016					1,173,411		$	33.09
Granted	445,555		29.31		529,434		36.86
Settled	(43,660	)	51.21		(268,154	)	33.47
Forfeited	(19,490	)	31.36		(62,852	)	34.66
Outstanding at June 30, 2016	1,413,624		33.11
Outstanding at June 30, 2017					1,371,839		34.40

Performance Units – The Partnership grants performance units under the MPLX LP 2012 Incentive Compensation Plan to certain officers of ~~our~~the general partner and certain eligible MPC officers who make significant contributions to its business. These performance units pay out 75 percent in cash and 25 percent in MPLX LP common units. The performance units paying out in units are accounted for as equity awards. The performance units granted in 2017 are hybrid awards having a three-year performance period of January 1, 2017 through December 31, 2019. The payout of the award is dependent on two independent conditions, each constituting 50 percent of the overall target units granted. The awards have a performance condition based on MPLX LP’s distributable cash flow during the last twelve months of the performance period, and ~~had~~ a ~~weighted-average grant date fair value per unit of $0.63 for 2016, as calculated~~market condition based on MPLX LP’s total unitholder return over the entire three-year performance period. The market condition was valued using a Monte Carlo valuation, ~~model.~~with the result being combined with the expected payout of the performance condition as of the grant date, resulting in a grant date fair value of $0.90 for the 2017 equity-classified performance units.

The following is a summary of the equity-classified performance unit award activity for the six months ended June 30, ~~2016~~2017:



	Number of Units
Outstanding at December 31, ~~2015~~2016	~~1,521,392~~1,799,249
Granted	~~789,375~~1,407,062
Settled	(~~458,011~~464,500	)
Forfeited	(~~53,507~~15,312	)
Outstanding at June 30, ~~2016~~2017	~~1,799,249~~2,726,499

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~~19.~~17. 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 June 30, ~~2016~~2017 and December 31, ~~2015,~~2016, accrued liabilities for remediation totaled $7$5 million and $1$3 million, respectively. However, it is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties, if any, which may be imposed. At ~~June 30,~~December 31, 2016, there was less than $1 million in receivables from MPC for indemnification of environmental costs related to incidents occurring prior to the Initial Offering. There were ~~$1 million in~~no such receivables ~~from MPC for indemnification~~ at ~~December 31, 2015.~~June 30, 2017.

In July 2015, representatives from the EPA and the United States Department of Justice ~~entered~~conducted a raid on a MarkWest Liberty Midstream pipeline launcher/receiver site utilized for pipeline maintenance operations in Washington County, Pennsylvania pursuant to a search warrant issued by a magistrate of the United States District Court for the Western District of Pennsylvania. As part of this initiative, the U.S. Attorney’s Office for the Western District of Pennsylvania, proceeded with an investigation of MarkWest Liberty ~~Midstream has provided information in~~Midstream’s launcher/receiver, pipeline and compressor station operations. In response to ~~subpoenas presented~~the investigation, MarkWest initiated independent studies which demonstrated that there was no risk to worker safety and no threat of public harm associated with MarkWest Liberty Midstream’s launcher/receiver operations. These findings were supported by a subsequent inspection and review by the ~~government~~Occupational Safety and ~~similar requests for information from the EPA, state~~Health Administration. After providing these studies, and other ~~agencies~~substantial documentation related to ~~MarkWest's~~MarkWest Liberty Midstream's pipeline and compressor stations, ~~located~~and arranging site visits and conducting several meetings with the government’s representatives, on September 13, 2016, the U.S. Attorney’s Office for the Western District of Pennsylvania rendered a declination decision, dropping its criminal investigation and declining to pursue charges in ~~Pennsylvania. The Partnership is engaged in ongoing discussions~~this matter.

MarkWest Liberty Midstream continues to discuss with the EPA and the ~~U.S. Attorney’s office regarding alleged omissions~~State of Pennsylvania civil enforcement allegations associated with ~~permits~~permitting or other related regulatory obligations for its launcher/receiver and compressor station facilities in the region. In connection with these discussions, MarkWest Liberty ~~Midstream’s internal review has determined that its operations have been conducted consistent with industry practices and in a manner protective of its employees and~~Midstream received an initial proposal from the ~~public. It is possible however, that in connection with any potential or asserted~~EPA to settle all civil ~~or criminal enforcement action~~claims associated with this matter for the combination of a proposed cash penalty of approximately $2.4 million and proposed supplemental environmental projects with an estimated cost of approximately $3.6 million. MarkWest Liberty Midstream has submitted a response asserting that this action involves novel issues surrounding primarily minor source emissions from facilities that the agencies themselves considered de minimis and were not the subject of regulation and consequently that the settlement proposal is excessive. MarkWest Liberty Midstream will ~~incur material assessments, penalties or fines, incur material defense costs~~continue to negotiate with EPA regarding the amount and expenses, be required to modify 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 allscope 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 or determined at this time.the proposed settlement.

The Partnership is involved in a number of other environmental enforcement matters arising in the ordinary course of business. While the outcome and impact on MPLX LP cannot be predicted with certainty, management believes the resolution of these environmental matters will not, individually or collectively, have a material adverse effect on its 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 purported 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, 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, LLC (the “MarkWest GP Board”), MPLX LP, MPLX GP, MPC and Sapphire Holdco LLC, a wholly-owned subsidiary of MPLX LP, 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 LP and (ii) MPC, MPLX LP, 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 the Court retained jurisdiction to adjudicate an application for a mootness fee by plaintiffs' counsel for an award of attorneys’ fees and reimbursement of expenses. On March 28, 2016, the plaintiffs filed an application for reimbursement of approximately $2 million of fees and expenses. On May 17, 2016, the plaintiffs withdrew the fee application and the case is now dismissed.

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

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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. On September 6, 2016, the trial court approved a settlement between Apex and the State of Illinois whereby Apex agreed to settle all claims against it for a $10 million payment. Premcor has objected to this ruling and is seeking an appeal. 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)~~losses) 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 the Partnership 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 June 30, ~~2016,~~2017, the Partnership’s contractual commitments to acquire property, plant and equipment totaled ~~$190~~$415 million. These commitments at June 30, 2017 were primarily related to plant expansion projects for the Marcellus and Southwest Operations and the Cornerstone Pipeline project. In addition, from time to time and in the ordinary course of business, the Partnership and its affiliates provide guarantees of the Partnership’s subsidiaries payment and performance obligations in the G&P segment. ~~These commitments at June 30, 2016 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 June 30, ~~2016,~~2017, 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.

18. Subsequent Events

On July 21, 2017, the Partnership entered into a credit agreement to replace its previous $2.0 billion five-year bank revolving credit facility with a $2.25 billion five-year bank revolving credit facility that expires in July 2022. The financial covenants and the interest rate terms contained in the new credit agreement are substantially the same as those contained in the previous bank revolving credit facility. Additionally, on July 19, 2017, MPLX LP prepaid the entire outstanding principal amount of its $250 million term loan with cash on hand.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the unaudited financial statements and accompanying footnotes included under Item 1. Financial Statements and in conjunction with our Annual Report on Form 10-K for the year ended December 31, ~~2015,~~2016, as updated by our Current Report on Form ~~8-K/A~~8-K filed on May ~~20, 2016.~~1, 2017.

Management’s Discussion and Analysis of Financial Condition and Results of Operations includes various forward-looking statements concerning trends or events potentially affecting our business. You can identify our forward-looking statements by words such as “anticipate,” “believe,” “estimate,” “objective,” “expect,” “forecast,” “goal,” “intend,” “plan,” “predict,” “project,” “potential,” “seek,” “target,” “could,” “may,” “should,” “would,” “will” or other similar expressions that convey the uncertainty of future events or outcomes. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, which could cause future outcomes to differ materially from those set forth in forward-looking statements. For additional risk factors affecting our business, see Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015, as updated by our Current Report on Form 8-K/A filed on May 20, 2016, Item 1A. Risk Factors in our Quarterly Report on Form 10-Q for the period ended March 31, 2016 and Item 1A. Risk Factors of Part II below.2016.

PARTNERSHIP OVERVIEW

We are a diversified, growth-oriented master limited partnership formed by MPC to own, operate, develop and acquire midstream energy infrastructure assets. We are engaged in the gathering, processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of NGLs; and the ~~gathering,~~ transportation, storage and ~~storage~~distribution of crude oil and refined petroleum products.

SIGNIFICANT FINANCIAL AND OTHER HIGHLIGHTS

Significant financial and other highlights for the three months ended June 30, ~~2016~~2017 are listed below. Refer to Results of Operations and Liquidity and Capital Resources for further details.

L&S segment operating income attributable to MPLX LP increased approximately ~~$35~~$85 million, or 69 percent, for the three months ended June 30, ~~2016~~2017 compared to the same period of ~~2015~~2016 due to $80 million from the inclusion of ~~HSM~~HST, WHC and MPLXT results after our acquisition as of March ~~31, 2016.~~1, 2017 and approximately $11 million from the acquisition of the Ozark pipeline.

G&P segment operating income attributable to MPLX LP increased approximately ~~$271~~$42 million, or 15 percent, for the three months ended June 30, ~~2016~~2017 compared to the same period of ~~2015~~2016. The G&P segment realized volume and product price increases during the second quarter of 2017 primarily due to expansions in the ~~MarkWest Merger.~~

~~During~~Southwest as well as growth at the Sherwood, Majorsville and Bluestone (previously referred to as Keystone) plants. Compared to the second quarter of 2016, ~~we completed the private placement of~~processing volumes were up approximately ~~30.8 million 6.5~~14 percent, ~~Series A Convertible Preferred Units for a cash purchase price of $32.50 per unit. The aggregate net proceeds of~~fractionated volumes were up approximately ~~$984 million from the sale of the Preferred Units was used for capital expenditures~~20 percent and ~~repayment of debt.~~gathering volumes were up approximately one percent. Additionally, there were lower transportation costs and other operating expenses.

During the second quarter of 2016, forecasts for Ohio Condensate were reduced to align with updated forecasts for customer requirements. This resulted in a fixed assets impairment charge of $96 million within Ohio Condensate, of which MPLX recorded its proportionate share of $58 million in ~~Loss from equity method investments~~Additional highlights for the three and six months ended June 30, ~~2016. Additionally,~~2017, including a look ahead to anticipated growth, are listed below.

Acquisition and Growth Activities

MPLX LP anticipates completing the second of several acquisitions in the third quarter with the offer of joint-interest ownership in certain pipelines and storage facilities from MPC. These assets are projected to generate approximately $135 million of EBITDA. MPC has indicated work remains on schedule to prepare the remaining assets contributing annual EBITDA of approximately $1.0 billion for dropdown no later than the end of the first quarter of 2018.

On March 1, 2017, we acquired certain pipeline, storage and terminal assets from MPC for $1.5 billion in cash and the issuance of $503 million in MPLX LP equity. As of the acquisition date, the assets consisted of 174 miles of crude oil pipelines and 430 miles of refined products pipelines, nine butane and propane storage caverns located in Michigan with approximately 1.8 million barrels of natural gas liquids storage capacity, 59 terminals for the receipt, storage, blending, additization, handling and redelivery of refined petroleum products, along with one leased terminal and partial ownership interest in two terminals. Collectively, the 62 terminals have a combined total shell capacity of approximately 23.6 million barrels. The terminal facilities are located primarily

in the Midwest, Gulf Coast and Southeast regions of the United States. The stable, fee-based earnings from these assets add both scale and diversification to the Partnership’s portfolio of high-quality midstream assets.

On March 1, 2017, we purchased the 433-mile, 22-inch Ozark crude oil pipeline for $219 million. The pipeline is capable of transporting approximately 230 mbpd and expands the footprint of our logistics and storage segment by connecting Cushing, Oklahoma-sourced volumes to our extensive Midwest pipeline network. An expansion project to increase the line's capacity to approximately 345 mbpd is expected to be completed in the second quarter of 2018.

On February 15, 2017, we acquired a 9.1875 percent indirect equity interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Company Pipeline projects, collectively referred to as the Bakken Pipeline system, for $500 million. The Bakken Pipeline system is currently expected to deliver in excess of 520 mbpd of crude oil from the Bakken/Three Forks production area in North Dakota to the Midwest through Patoka, Illinois and ultimately to the Gulf Coast.

On February 6, 2017, we formed a strategic joint venture with Antero Midstream to process natural gas at the Sherwood Complex and fractionate natural gas liquids at the Hopedale Complex. This unique transaction strengthens our long-term relationship with the largest producer in the Appalachian Basin and provides the Partnership ~~recorded an impairment charge~~with substantial future growth opportunities. As part of ~~$31~~this agreement, Antero Midstream released to the joint venture the dedication of approximately 195,000 gross operated acres located in Tyler, Wetzel and Ritchie counties of West Virginia. We contributed cash of $20 million, along with $353 million of assets, comprised of real property, equipment and facilities, including three 200 MMcf/d gas processing plants then under construction at the Sherwood Complex. Antero Midstream contributed cash of $154 million. The joint venture commenced operations of the first new facility during the first quarter of 2017, the second new facility during the third quarter of 2017 and expects to commence operations of the third new facility during the first quarter of 2018. Construction of a fourth new facility was announced during the first quarter of 2017 and is expected to commence operations in ~~Loss from equity method investments~~ ~~for~~late 2018. In addition to the ~~three~~four new processing facilities, the joint venture contemplates the development of up to another seven processing facilities to support Antero Resources Corporation, which would be located at both the Sherwood Complex and a new location in West Virginia. At the Hopedale Complex, the largest fractionation facility in the Marcellus and Utica shales, the joint venture will also support the growth of Antero Resources Corporation’s NGL production by investing in 20 mbpd of existing fractionation capacity, with options to invest in future fractionation expansions.

Financing Activities

On February 10, 2017, we completed a public offering of $2.25 billion aggregate principal amount senior notes.

During the six months ended June 30, ~~2016 to eliminate~~2017, we issued an aggregate of 12,662,663 commons units under our ATM Program, generating net proceeds of approximately $434 million. As of June 30, 2017, $280 million of common units remain available for issuance through the ~~basis differential related to our investment in Ohio Condensate that was established in connection with~~ATM Program under the ~~MarkWest Merger. See Note 4 of the Notes to Consolidated Financial Statements for more information.~~

Distribution Agreement.

NON-GAAP FINANCIAL INFORMATION

Our management uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include the non-GAAP financial measures of Adjusted EBITDA and DCF. The amount of Adjusted EBITDA and DCF generated is considered by the ~~Board~~board of ~~Directors~~directors of our general partner in approving the Partnership’s cash ~~distribution.~~distributions.

We define Adjusted EBITDA as net income adjusted for (i) depreciation and amortization; (ii) ~~benefit~~provision (benefit) for income taxes; (iii)amortization of deferred financing costs; (iv) non-cash equity-based compensation; (v) impairment expense; (vi) net interest and other financial costs; ~~(vi) income~~(vii) loss (income) from equity investments; ~~(vii)~~(viii) distributions from unconsolidated subsidiaries; ~~(viii) impairment expense~~ (ix) unrealized ~~gain/loss on commodity hedges;~~derivative losses (gains); and (x) acquisition costs. We also use DCF, which we define as Adjusted EBITDA

~~Table of Contents~~

~~plus~~ adjusted for (i) ~~the current period cash received/~~deferred revenue ~~for committed volume deficiencies less~~impacts; (ii) net interest and other financial costs; (iii) ~~equity investment capital expenditures paid out; (iv) cash contributions to unconsolidated affiliates; (v)~~ maintenance capital ~~expenditures paid; (vi) volume deficiency credits recognized;~~expenditures; and ~~(vii)~~(iv) other non-cash items. The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, changes in the fair value of the derivative are

recorded as an unrealized gain or loss. When a derivative contract matures or is settled, the previously recorded unrealized gain or loss is reversed and the realized gain or loss of the contract is recorded.

We believe that the presentation of Adjusted EBITDA and DCF provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and DCF are net income and net cash provided by operating activities. Adjusted EBITDA and DCF should not be considered as alternatives to GAAP net income or net cash provided by operating activities. Adjusted EBITDA and DCF have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and DCF should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and DCF may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA and DCF may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For a reconciliation of Adjusted EBITDA and DCF to their most directly comparable measures calculated and presented in accordance with GAAP, see Results of Operations.

Management evaluates contract performance on the basis of net operating margin, (aa non-GAAP financial ~~measure),~~measure, which is defined as segment revenue less segment purchased product costs less ~~any~~realized derivative ~~gain (loss).~~gains (losses) related to purchased product costs. These charges have been excluded for the purpose of enhancing the understanding by both management and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting. Net operating margin does not have any standardized definition and, therefore, is unlikely to be comparable to similar measures presented by other reporting companies. Net operating margin results should not be evaluated in isolation of, or as a substitute for, our financial results prepared in accordance with GAAP. Our use of net operating margin and the underlying methodology in excluding certain charges is not necessarily an indication of the results of operations expected in the future, or that we will not, in fact, incur such charges in future periods.

In evaluating our financial performance, management utilizes the segment performance measures, segment revenues and segment operating income, including total segment operating income. These financial measures are presented in Item 1. Financial Statements - Note 9 and are considered non-GAAP financial measures when presented outside of the Notes to Consolidated Financial Statements. The use of these measures allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. See Note 9 of the Notes to Consolidated Financial Statements for the reconciliations of these segment measures, including total segment operating income, to their respective most directly comparable GAAP measures.

COMPARABILITY OF OUR FINANCIAL RESULTS

Our acquisitions have impacted comparability of our financial results (see Note 3 of the Notes to Consolidated Financial Statements).

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RESULTS OF OPERATIONS

The following table and discussion is a summary of our results of operations for the three and six months ended June 30, ~~2016~~2017 and ~~2015,~~2016, including a reconciliation of Adjusted EBITDA and DCF from net income and net cash provided by operating activities, the most directly comparable GAAP financial measures. Prior period financial information has been retrospectively adjusted for the acquisition of ~~HSM.~~HST, WHC and MPLXT.


	Three Months Ended June 30,								Six Months Ended June 30,								Three Months Ended June 30,								Six Months Ended June 30,
(In millions)	2016			2015		Variance			2016			2015		Variance			2017		2016			Variance			2017		2016			Variance
Total revenues and other income	$	564		$	213	$	351		$	1,173		$	414	$	759		$	916	$	698		$	218		$	1,802	$	1,343		$	459
Costs and expenses:
Cost of revenues (excludes items below)	84			46		38			173			88		85			139		113			26			252		207			45
Purchased product costs	114			—		114			193			—		193			140		114			26			271		193			78
Rental cost of sales	14			—		14			28			—		28			13		15			(2		)	25		29			(4		)
Rental cost of sales - related parties																	1		1			—			1		1			—
Purchases - related parties	78			40		38			154			80		74			109		99			10			216		177			39
Depreciation and amortization	137			20		117			269			39		230			164		151			13			351		287			64
Impairment expense	1			—		1			130			—		130			—		1			(1		)	—		130			(130		)
General and administrative expenses	49			21		28			101			43		58			57		63			(6		)	115		116			(1		)
Other taxes	11			4		7			22			8		14			13		13			—			26		25			1
Total costs and expenses	488			131		357			1,070			258		812			636		570			66			1,257		1,165			92
Income from operations	76			82		(6		)	103			156		(53		)	280		128			152			545		178			367
Related party interest and other financial costs	—			—		—			1			—		1			—		—			—			—		1			(1		)
Interest expense, net of amounts capitalized	52			6		46			107			11		96			74		52			22			140		107			33
Other financial costs	12			—		12			24			1		23			13		12			1			25		24			1
Income (loss) before income taxes	12			76		(64		)	(29		)	144		(173		)
Benefit for income taxes	(8		)	—		(8		)	(12		)	—		(12		)
Net income (loss)	20			76		(56		)	(17		)	144		(161		)
Income before income taxes																	193		64			129			380		46			334
Provision (benefit) for income taxes																	2		(8		)	10			2		(12		)	14
Net income																	191		72			119			378		58			320
Less: Net income attributable to noncontrolling interests	1			1		—			1			1		—			1		1			—			2		1			1
Less: Net income attributable to Predecessor	—			24		(24		)	23			46		(23		)	—		52			(52		)	36		98			(62		)
Net income (loss) attributable to MPLX LP	$	19		$	51	$	(32	)	$	(41	)	$	97	$	(138	)	$	190	$	19		$	171		$	340	$	(41	)	$	381

Adjusted EBITDA attributable to MPLX LP ⁽¹⁾	$	351		$	70	$	281		$	653		$	134	$	519		$	474	$	351		$	123		$	897	$	653		$	244
DCF⁽¹⁾	$	285		$	62	$	223		$	521		$	118	$	403		387		285			102			741		521			220
DCF attributable to GP and LP unitholders⁽¹⁾	$	276		$	62	$	214		$	512		$	118	$	394		370		276			94			708		512			196


(1)	Non-GAAP financial measure. See the following tables for reconciliations to the most directly comparable GAAP measures.

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Three Months Ended June 30, Six Months Ended June 30,
(In millions) 2016 2015 Variance 2016 2015 Variance
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net Income (Loss):
Net income (loss) $ 20
$ 76
$ (56 ) $ (17 ) $ 144
$ (161 )
Plus: Depreciation and amortization 137
20
117
269
39
230
Benefit for income taxes (8 ) —
(8 ) (12 ) —
(12 )
Amortization of deferred financing costs 12
—
12
23
—
23
Non-cash equity-based compensation 4
—
4
6
1
5
Impairment expense 1
—
1
130
—
130
Net interest and other financial costs 52
6
46
109
12
97
Loss from equity investments 83
—
83
78
—
78
Distributions from unconsolidated subsidiaries 40
—
40
78
—
78
Unrealized loss on commodity hedges 12
—
12
21
—
21
Acquisition costs (2 ) —
(2 ) (1 ) —
(1 )
Adjusted EBITDA 351
102
249
684
196
488
Less: Adjusted EBITDA attributable to noncontrolling interests —
1
(1 ) 1
1
—
Adjusted EBITDA attributable to Predecessor —
31
(31 ) 30
61
(31 )
Adjusted EBITDA attributable to MPLX LP 351
70
281
653
134
519
Plus: Current period cash received/deferred revenue for committed volume deficiencies 11
10
1
21
22
(1 )
Less: Net interest and other financial costs 52
6
46
109
12
97
Equity investment capital expenditures paid (10 ) —
(10 ) (38 ) —
(38 )
Investment in unconsolidated affiliates 10
—
10
39
—
39
Maintenance capital expenditures paid 16
4
12
28
8
20
Volume deficiency credits recognized 9
9
—
16
19
(3 )
Adjustments attributable to Predecessor —
(1 ) 1
(1 ) (1 ) —
DCF 285
62
223
521
118
403
Less: Preferred unit distributions 9
—
9
9
—
9
DCF attributable to GP and LP unitholders $ 276
$ 62
$ 214
$ 512
$ 118
$ 394



	Three Months Ended June 30,									Six Months Ended June 30,
(In millions)	2017			2016			Variance			2017			2016			Variance
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net income:
Net income	$	191		$	72		$	119		$	378		$	58		$	320
Depreciation and amortization	164			151			13			351			287			64
Provision (benefit) for income taxes	2			(8		)	10			2			(12		)	14
Amortization of deferred financing costs	13			12			1			25			23			2
Non-cash equity-based compensation	3			4			(1		)	6			6			—
Impairment expense	—			1			(1		)	—			130			(130		)
Net interest and other financial costs	74			52			22			140			109			31
(Income) loss from equity method investments	(1		)	83			(84		)	(6		)	78			(84		)
Distributions from unconsolidated subsidiaries	33			40			(7		)	66			78			(12		)
Unrealized derivative (gains) losses⁽¹⁾	(3		)	12			(15		)	(19		)	21			(40		)
Acquisition costs	—			(2		)	2			4			(1		)	5
Adjusted EBITDA	476			417			59			947			777			170
Adjusted EBITDA attributable to noncontrolling interests	(2		)	—			(2		)	(3		)	(1		)	(2		)
Adjusted EBITDA attributable to Predecessor⁽²⁾	—			(66		)	66			(47		)	(123		)	76
Adjusted EBITDA attributable to MPLX LP	474			351			123			897			653			244
Deferred revenue impacts	9			4			5			17			7			10
Net interest and other financial costs	(74		)	(52		)	(22		)	(140		)	(109		)	(31		)
Maintenance capital expenditures	(23		)	(20		)	(3		)	(35		)	(33		)	(2		)
Other	1			—			1			—			—			—
Portion of DCF adjustments attributable to Predecessor⁽²⁾	—			2			(2		)	2			3			(1		)
DCF	387			285			102			741			521			220
Preferred unit distributions	(17		)	(9		)	(8		)	(33		)	(9		)	(24		)
DCF attributable to GP and LP unitholders	$	370		$	276		$	94		$	708		$	512		$	196

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Six Months Ended June 30,
(In millions) 2016 2015 Variance
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net Cash Provided by Operating Activities:
Net cash provided by operating activities $ 593
$ 173
$ 420
Less: Changes in working capital items 26
(9 ) 35
All other, net 21
(1 ) 22
Plus: Non-cash equity-based compensation 6
1
5
Net interest and other financial costs 109
12
97
Current portion income taxes 1
—
1
Asset retirement expenditures 2
—
2
Unrealized loss on commodity hedges 21
—
21
Acquisition costs (1 ) —
(1 )
Adjusted EBITDA 684
196
488
Less: Adjusted EBITDA attributable to noncontrolling interests 1
1
—
Adjusted EBITDA attributable to Predecessor 30
61
(31 )
Adjusted EBITDA attributable to MPLX LP 653
134
519
Plus: Current period cash received/deferred revenue for committed volume deficiencies 21
22
(1 )
Less: Net interest and other financial costs 109
12
97
Equity investment capital expenditures paid (38 ) —
(38 )
Investment in unconsolidated affiliates 39
—
39
Maintenance capital expenditures paid 28
8
20
Volume deficiency credits recognized 16
19
(3 )
Adjustments attributable to Predecessor (1 ) (1 ) —
DCF 521
118
403
Less: Preferred unit distributions 9
—
9
DCF attributable to GP and LP unitholders $ 512
$ 118
$ 394



	Six Months Ended June 30,
(In millions)	2017			2016			Variance
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net cash provided by operating activities:
Net cash provided by operating activities	$	844		$	670		$	174
Changes in working capital items	1			(9		)	10
All other, net	(32		)	(22		)	(10		)
Non-cash equity-based compensation	6			6			—
Net gain on disposal of assets	1			—			1
Net interest and other financial costs	140			109			31
Current income taxes	1			1			—
Asset retirement expenditures	1			2			(1		)
Unrealized derivative (gains) losses⁽¹⁾	(19		)	21			(40		)
Acquisition costs	4			(1		)	5
Adjusted EBITDA	947			777			170
Adjusted EBITDA attributable to noncontrolling interests	(3		)	(1		)	(2		)
Adjusted EBITDA attributable to Predecessor⁽²⁾	(47		)	(123		)	76
Adjusted EBITDA attributable to MPLX LP	897			653			244
Deferred revenue impacts	17			7			10
Net interest and other financial costs	(140		)	(109		)	(31		)
Maintenance capital expenditures	(35		)	(33		)	(2		)
Portion of DCF adjustments attributable to Predecessor⁽²⁾	2			3			(1		)
DCF	741			521			220
Preferred unit distributions	(33		)	(9		)	(24		)
DCF attributable to GP and LP unitholders	$	708		$	512		$	196

(1)


(2)	The Adjusted EBITDA and DCF adjustments related to Predecessor are excluded from Adjusted EBITDA attributable to MPLX LP and DCF prior to the acquisition dates.

Three months ended June 30, ~~2016~~2017 compared to three months ended June 30, ~~2015~~2016

Total revenues and other income increased ~~$351~~$218 million in the second quarter of ~~2016~~2017 compared to the same period of ~~2015.~~2016. This variance was ~~primarily related~~due mainly to ~~$353~~increased pricing on product sales of approximately $48 million ~~due to~~as well as higher revenues from volume growth of $36 million in the ~~MarkWest Merger offset by~~Marcellus and the Southwest areas, higher crude and product transportation volumes of $12 million, $19 million from the acquisition of the Ozark pipeline and a ~~decline in product and crude oil volumes shipped.~~$4 million increase from additional barges. The three months ended June 30, 2016 also ~~includes~~included an impairment expense of $89 million related to our investment in Ohio ~~Condensate. See Note 4 of~~Condensate as referenced in our Annual Report on Form 10-K for the ~~Notes to Consolidated Financial Statements for more information.~~year ended December 31, 2016, as updated by our Current Report on Form 8-K filed on May 1, 2017.

Cost of revenues increased ~~$38~~$26 million in the second quarter of ~~2016~~2017 compared to the same period of ~~2015.~~2016. This variance was primarily due to approximately $8 million from the ~~MarkWest Merger, offset by a reduction in contract services.~~acquisition of the Ozark pipeline and expenses related to the timing of projects.

Purchased product costs increased ~~$114~~$26 million in the second quarter of ~~2016~~2017 compared to the same period of ~~2015.~~2016. This variance was primarily due to higher NGL and gas prices, primarily in the ~~MarkWest Merger.~~Southwest area.

~~Rental cost of sales~~Purchases-related parties increased ~~$14~~$10 million in the second quarter of ~~2016~~2017 compared to the same period of ~~2015. This variance was primarily due to the MarkWest Merger.~~

~~Purchases-related parties increased $38 million in the second quarter of 2016 compared to the same period of 2015.~~2016. The increase was primarily due to ~~higher~~salaries, compensation ~~expenses provided under the omnibus~~ and ~~employee services agreements with MPC due to the MarkWest Merger, partially offset by increased capitalization of employee costs associated with capital projects.~~other miscellaneous expenses.

Depreciation and amortization expense increased ~~$117~~$13 million in the second quarter of ~~2016~~2017 compared to the same period of ~~2015.~~2016. This variance was primarily due to ~~the MarkWest Merger.~~

~~Table~~additions to in-service property, plant and equipment as well as approximately $5 million of ~~Contents~~

accelerated depreciation related to adjustments of certain assets’ useful life.

General and administrative ~~expenses increased $28~~expense decreased $6 million in the second quarter of ~~2016~~2017 compared to the same period of ~~2015. The increases were primarily~~2016. This decrease was mainly due to ~~the MarkWest Merger.~~savings on insurance programs and other costs.

~~Interest~~Net interest expense and other financial costs increased ~~$58~~$23 million in the second quarter of ~~2016~~2017 compared to the same period of ~~2015.~~2016. The ~~increases are primarily~~increase is mainly due to the ~~senior notes assumed as part of~~New Senior Notes issued in February 2017 partially offset by decreased borrowings on the ~~MarkWest Merger.~~bank revolving credit facility.

Six months ended June 30, ~~2016~~2017 compared to six months ended June 30, ~~2015~~2016

Total revenues and other income increased ~~$759~~$459 million in the first six months of ~~2016~~2017 compared to the same period of ~~2015.~~ 2016.

This variance was ~~primarily related~~due mainly to ~~$751~~the inclusion of $106 million of revenue generated by MPLXT and its subsidiaries since it was not formed as a business until April 1, 2016, increased pricing on product sales of approximately $139 million as well as higher revenues from volume growth of $66 million in the Marcellus and the Southwest areas, higher crude and product transportation volumes of $14 million, $26 million from the acquisition of the Ozark pipeline, $5 million due to ~~the MarkWest Merger and~~ an increase ~~due~~in recognition of revenues related to ~~higher average tariffs received on the volumes of crude oil~~volume deficiency payments and ~~products shipped.~~a $6 million increase from additional barges. The six months ended June 30, 2016 also ~~includes~~included an impairment expense of $89 million related to our investment in Ohio ~~Condensate. See Note 4 of~~Condensate as referenced in our Annual Report on Form 10-K for the ~~Notes to Consolidated Financial Statements for more information.~~year ended December 31, 2016, as updated by our Current Report on Form 8-K filed on May 1, 2017.

Cost of revenues increased ~~$85~~$45 million in the first six months of ~~2016~~2017 compared to the same period of ~~2015.~~2016. This variance was primarily due to $26 million from the ~~MarkWest Merger, offset by a reduction in contract services.~~inclusion of MPLXT during the six months of 2017, as well as $11 million from the acquisition of the Ozark pipeline and expenses related to the timing of projects.

Purchased product costs increased ~~$193~~$78 million in the first six months of ~~2016~~2017 compared to the same period of ~~2015.~~2016. This variance was primarily due to higher NGL and gas prices and purchase volumes in the ~~MarkWest Merger.~~Southwest area, offset by a $19 million unrealized gain on our Natural Gas Embedded Derivative.

~~Rental cost of sales~~Purchases-related parties increased ~~$28~~$39 million in the first six months of ~~2016~~2017 compared to the same period of ~~2015. This variance~~2016. The increase was primarily due to the ~~MarkWest Merger.~~inclusion of approximately $26 million related party purchases of MPLXT as well as general increases in employee benefit costs.

~~Purchases-related parties~~Depreciation and amortization expense increased ~~$74~~$64 million in the first six months of ~~2016~~2017 compared to the same period of 2015. The increases were primarily due to higher compensation expenses provided under the omnibus and employee services agreements with MPC due to the MarkWest Merger, partially offset by increased capitalization of employee costs associated with capital projects.

~~Depreciation and amortization expense increased $230 million in the first six months of 2016 compared to the same period of 2015.~~2016. This variance was primarily due to accelerated depreciation expense of approximately $33 million incurred on the ~~MarkWest Merger.~~decommissioning of the Houston 1 facility in the Marcellus area and other various assets, approximately $10 million of additional depreciation due to the inclusion of MPLXT, as well additions to in-service property, plant and equipment throughout 2016 and the first half of 2017.

Impairment expense ~~increased~~decreased $130 million in the first six months of ~~2016~~2017 compared to the same period of ~~2015.~~2016. This variance was due to a non-cash impairment to goodwill in two reporting units in the G&P ~~segment. See Note 16~~segment during the second quarter of ~~the Notes to Consolidated Financial Statements for more information.~~

General and administrative expenses increased $58 million in the first six months of 2016 compared to the same period of 2015. The increases were primarily due to the MarkWest Merger with additional increases related to services provided under the omnibus and employee services agreements with MPC.2016.

Interest expense and other financial costs increased ~~$120~~$34 million in the first six months of ~~2016~~2017 compared to the same period of ~~2015.~~2016. The increases are primarily due to the ~~senior notes assumed as part of~~New Senior Notes issued in February 2017 partially offset by decreased borrowings on the ~~MarkWest Merger.~~bank revolving credit facility.

SEGMENT RESULTS

We classify our business in the following reportable segments: L&S and G&P. Segment operating income represents income from operations attributable to the reportable segments. We have investments in entities that we operate that are accounted for using equity method investment accounting standards. However, we view financial information as if those investments were consolidated. Corporate general and administrative expenses, unrealized derivative gains (losses), property, plant and equipment impairment, goodwill impairment 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.

~~Table of Contents~~

Segment operating income attributable to MPLX LP excludes the operating income related to the HSM Predecessor prior to the March 31, 2016 acquisition and the HST, WHC and MPLXT Predecessor prior to the March 1, 2017 acquisition.

The tables below present information about segment operating income for the reported segments.

L&S Segment


	Three Months Ended June 30,							Six Months Ended June 30,							Three Months Ended June 30,							Six Months Ended June 30,
(In millions)	2016		2015		Variance			2016		2015		Variance			2017		2016		Variance			2017		2016		Variance
Revenues and other income:
Segment revenue	$	193	$	193	$	—		$	385	$	376	$	9
Segment revenues															$	372	$	331	$	41		$	717	$	562	$	155
Segment other income	18		20		(2		)	37		38		(1		)	12		14		(2		)	24		30		(6		)
Total segment revenues and other income	211		213		(2		)	422		414		8			384		345		39			741		592		149
Costs and expenses:
Segment cost of revenues	88		90		(2		)	177		176		1			176		142		34			324		239		85
Segment operating income before portion attributable to noncontrolling interest and Predecessor	123		123		—			245		238		7
Segment portion attributable to noncontrolling interest and Predecessor	—		35		(35		)	34		68		(34		)
Segment operating income before portion attributable to noncontrolling interests and Predecessor															208		203		5			417		353		64
Segment portion attributable to noncontrolling interests and Predecessor															—		80		(80		)	53		142		(89		)
Segment operating income attributable to MPLX LP	$	123	$	88	$	35		$	211	$	170	$	41		$	208	$	123	$	85		$	364	$	211	$	153

Three months ended June 30, ~~2016~~2017 compared to three months ended June 30, ~~2015~~2016

In the second quarter of ~~2016~~2017 compared to the same period of ~~2015,~~2016, segment revenue ~~remained stable~~increased primarily due to a $7$12 million increase from higher crude and product transportation volumes, a $19 million increase from the acquisition of the Ozark pipeline, a $3 million increase in ~~higher average tariffs received on~~ the ~~volumes~~recognition of ~~crude oil and products shipped offset by a $6 million decrease~~revenue related to volume deficiency payments, a ~~94 mbpd decline~~$3 million increase from the annual increase in ~~product~~fees and ~~crude oil volumes shipped.~~a $4 million increase from additional barges.

In the second quarter of ~~2016~~2017 compared to the same period of ~~2015,~~2016, segment cost of revenues ~~decreased~~increased primarily due to ~~$6 million in fees previously paid by HSM that are now being paid directly by MPC, offset by a $2 million increase in fees~~expenses related to the timing of projects, ~~a $1 million increase in fuel expense~~the acquisition of the Ozark pipeline, and ~~a $1 million increase in general expense.~~salaries, compensation and other miscellaneous expenses.

In the second quarter of ~~2016~~2017 compared to the same period of ~~2015,~~2016, the segment portion attributable to noncontrolling ~~interest~~interests and Predecessor decreased due to the acquisition of ~~HSM~~HST, WHC and MPLXT as of March ~~31, 2016.~~1, 2017.

Six months ended June 30, ~~2016~~2017 compared to six months ended June 30, ~~2015~~2016

In the first six months of ~~2016~~2017 compared to the same period of ~~2015,~~2016, segment revenue increased primarily due to the inclusion of $106 million of revenue generated by MPLXT and its subsidiaries, a ~~$12~~$14 million increase infrom higher ~~average tariffs received on~~crude and product transportation volumes, a $26 million increase from the ~~volumes~~acquisition of ~~crude oil and products shipped and~~the Ozark pipeline, a $5 million increase due to the recognition of revenues related to volume deficiency payments, a $3 million increase from the annual increase in ~~storage service income, offset by a $2 million decrease related to a 26 mbpd decline in product and crude oil volumes shipped~~fees and a $6 million ~~decrease in revenue related to volume deficiency credits recognized.~~increase from additional barges.

In the first six months of ~~2016~~2017 compared to the same period of ~~2015,~~2016, segment cost of revenues increased primarily due to ~~a decrease~~the acquisitions of MPLXT and the Ozark pipeline, and increases in ~~fees previously paid by HSM that are now being paid directly by MPC, partially offset by an increase in fees~~expenses related to the timing of projects.

In the first six months of ~~2016~~2017 compared to the same period of ~~2015,~~2016, the segment portion attributable to noncontrolling ~~interest~~interests and Predecessor decreased due to the inclusion of HSM for the first three months of 2016 and the acquisition of ~~HSM~~HST, WHC and MPLXT as of March ~~31, 2016.~~

~~Table of Contents~~

1, 2017.

During both the second quarter and ~~the~~ first six months of ~~2016,~~2017, MPC did not ship its minimum committed volumes on certain of our pipeline systems. As a result, for the first six months, MPC was obligated to make a ~~$22~~$26 million deficiency payment of which ~~$13~~$12 million was paid in the second quarter of ~~2016.~~2017. We record deficiency payments as Deferred revenue-related parties on our Consolidated Balance Sheets. In the second quarter and ~~the~~ first six months of ~~2016,~~2017, we recognized revenue of $8$11 million and ~~$15~~$22 million ~~respectively,~~ related to volume deficiency credits. At June 30, ~~2016,~~2017, the cumulative balance of ~~deferred~~Deferred revenue-related parties on our ~~consolidated balance sheet~~Consolidated Balance Sheets related to volume deficiencies was ~~$43~~$51 million. The following table presents the future expiration dates of the associated deferred revenue credits as of June 30, ~~2016:~~2017:


(In millions)
September 30, 2016	$	7
December 31, 2016	10
March 31, 2017	10
June 30, 2017	10
September 30, 2017	1		$	7
December 31, 2017	1		10
March 31, 2018	2		10
June 30, 2018	2		10
September 30, 2018			3
December 31, 2018			4
March 31, 2019			3
June 30, 2019			4
Total	$	43	$	51

We will recognize revenue for the deficiency payments in future periods at the earlier of when volumes are transported in excess of the minimum quarterly volume commitments, when it becomes impossible to physically transport volumes necessary to utilize the accumulated credits or upon expiration of the make-up period. Deficiency payments are included in the determination of DCF in the period in which a deficiency occurs.

G&P Segment

Our assets include approximately ~~5,500 MMcf/~~5.6 bcf/d of gathering capacity, ~~7,500 MMcf/~~7.8 bcf/d of natural gas processing capacity and ~~500~~570 mbpd of fractionation capacity. We also own more than 5,000 miles of gas gathering and NGL pipelines and have ownership interests in 54 gas processing plants, 13 NGL fractionation facilities and two condensate stabilization facilities.

Three Months Ended June 30, Six Months Ended June 30,
(In millions) 2016 2015 Variance 2016 2015 Variance
Revenues and other income:
Segment revenue $ 530
$ —
$ 530
$ 1,028
$ —
$ 1,028
Segment other income —
—
—
—
—
—
Total segment revenues and other income 530
—
530
1,028
—
1,028
Costs and expenses:
Segment cost of revenues 223
—
223
423
—
423
Segment operating income before portion attributable to noncontrolling interest 307
—
307
605
—
605
Segment portion attributable to noncontrolling interest 36
—
36
77
—
77
Segment operating income attributable to MPLX LP $ 271
$ —
$ 271
$ 528
$ —
$ 528

~~The G&P segment increased overall due to the MarkWest Merger. There was no G&P segment prior to the MarkWest Merger. See Supplemental MD&A - G&P Pro Forma for more information.~~



	Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2017		2016		Variance		2017		2016		Variance
Revenues and other income:
Segment revenues	$	603	$	530	$	73	$	1,200	$	1,028	$	172
Segment other income	—		—		—		1		—		1
Total segment revenues and other income	603		530		73		1,201		1,028		173
Costs and expenses:
Segment cost of revenues	252		223		29		505		423		82
Segment operating income before portion attributable to noncontrolling interests	351		307		44		696		605		91
Segment portion attributable to noncontrolling interests	38		36		2		74		77		(3		)
Segment operating income attributable to MPLX LP	$	313	$	271	$	42	$	622	$	528	$	94

4849

~~Table of Contents~~

Three months ended June 30, 2017 compared to three months ended June 30, 2016

In the second quarter of 2017 compared to the same period of 2016, segment revenue increased due to increased pricing on product sales of approximately $40 million and increased volumes of $6 million, combined with increased fees of approximately $26 million on higher volumes due to new processing plants in the Marcellus and Southwest areas and additional fractionation capacity in the Marcellus and Utica areas.

In the second quarter of 2017 compared to the same period of 2016, segment cost of revenues increased primarily due to increased product costs resulting from higher NGL and gas prices of $32 million primarily in the Southwest area.

Six months ended June 30, 2017 compared to six months ended June 30, 2016

In the first six months of 2017 compared to the same period of 2016, segment revenue increased due to increased pricing on product sales of approximately $116 million and increased volumes of $17 million, combined with increased fees of approximately $38 million on higher volumes due to new processing plants in the Marcellus and Southwest areas and additional fractionation capacity in the Marcellus and Utica areas.

In the first six months of 2017 compared to the same period of 2016, segment cost of revenues increased due primarily to increased product costs resulting from higher prices of approximately $85 million and higher volumes of $11 million primarily in the Southwest area offset by lower facility costs due to lower transportation costs and other operating efficiencies.

Segment Reconciliations

The following tables provide reconciliations of segment operating income to our consolidated income from operations, segment revenue to our consolidated total revenues and other income, and segment portion attributable to noncontrolling ~~interest~~interests to our consolidated net income attributable to noncontrolling interests for the three and six months ended June 30, ~~2016~~2017 and ~~2015.~~2016. Adjustments related to unconsolidated affiliates relate to our ~~Partnership operated~~Partnership-operated non-wholly-owned entities that we consolidate for segment purposes.

Three Months Ended June 30, Six Months Ended June 30,
(In millions) 2016 2015 Variance 2016 2015 Variance
Reconciliation to Income from operations:
L&S segment operating income attributable to MPLX LP $ 123
$ 88
$ 35
$ 211
$ 170
$ 41
G&P segment operating income attributable to MPLX LP 271
—
271
528
—
528
Segment operating income attributable to MPLX LP 394
88
306
739
170
569
Segment portion attributable to unconsolidated affiliates (83 ) —
(83 ) (166 ) —
(166 )
Segment portion attributable to noncontrolling interest and Predecessor 36
35
1
111
68
43
Loss from equity method investments (83 ) —
(83 ) (78 ) —
(78 )
Other income - related parties 11
—
11
18
—
18
Unrealized derivative losses (12 ) —
(12 ) (21 ) —
(21 )
Depreciation and amortization (137 ) (20 ) (117 ) (269 ) (39 ) (230 )
Impairment expense (1 ) —
(1 ) (130 ) —
(130 )
General and administrative expenses (49 ) (21 ) (28 ) (101 ) (43 ) (58 )
Income from operations $ 76
$ 82
$ (6 ) $ 103
$ 156
$ (53 )

Three Months Ended June 30, Six Months Ended June 30,
(In millions) 2016 2015 Variance 2016 2015 Variance
Reconciliation to Total revenues and other income:
Total segment revenues and other income $ 741
$ 213
$ 528
$ 1,450
$ 414
$ 1,036
Revenue adjustment from unconsolidated affiliates (99 ) —
(99 ) (203 ) —
(203 )
Loss from equity method investments (83 ) —
(83 ) (78 ) —
(78 )
Other income - related parties 11
—
11
18
—
18
Unrealized derivative loss (6 ) —
(6 ) (14 ) —
(14 )
Total revenues and other income $ 564
$ 213
$ 351
$ 1,173
$ 414
$ 759

Three Months Ended June 30, Six Months Ended June 30,
(In millions) 2016 2015 Variance 2016 2015 Variance
Reconciliation to Net income attributable to noncontrolling interests and Predecessor
Segment portion attributable to noncontrolling interest and Predecessor $ 36
$ 35
$ 1
$ 111
$ 68
$ 43
Portion of noncontrolling interests and Predecessor related to items below segment income from operations (56 ) (10 ) (46 ) (85 ) (21 ) (64 )
Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates 21
—
21
(2 ) —
(2 )
Net income attributable to noncontrolling interests and Predecessor $ 1
$ 25
$ (24 ) $ 24
$ 47
$ (23 )

~~Loss~~ Income (loss) from equity method investmentsrelates to our portion of income (loss) from our unconsolidated joint ventures of which ~~Partnership operated~~Partnership-operated joint ventures are consolidated for segment purposes. The three and six months ended June 30, 2016 includes an impairment expense of $89 million related to Ohio Condensate. See Note 4 of the Notes to Consolidated Financial Statements for more information.

~~Table of Contents~~

Other income-related parties consists of operational service fee revenues from our operated unconsolidated affiliates.

~~Unrealized loss from the change in fair value of our~~ ~~Product sales~~ ~~derivative instruments for the three and six months ended June 30, 2016 was $6 million and $14 million, respectively. Unrealized loss from the change in fair value of our~~ ~~Purchased product costs~~ ~~derivative instruments for the three and six months ended June 30, 2016 was $8 million and $9 million, respectively. Unrealized gain from the change in fair value of our~~ ~~Cost of revenues~~ ~~derivative instruments was $2 million for the three and six months ended June 30, 2016.~~ Unrealized derivative activity is not allocated to segments.



	Three Months Ended June 30,									Six Months Ended June 30,
(In millions)	2017			2016			Variance			2017			2016			Variance
Reconciliation to Income from operations:
L&S segment operating income attributable to MPLX LP	$	208		$	123		$	85		$	364		$	211		$	153
G&P segment operating income attributable to MPLX LP	313			271			42			622			528			94
Segment operating income attributable to MPLX LP	521			394			127			986			739			247
Segment portion attributable to unconsolidated affiliates	(38		)	(47		)	9			(78		)	(89		)	11
Segment portion attributable to Predecessor	—			80			(80		)	53			142			(89		)
Income (loss) from equity method investments	1			(83		)	84			6			(78		)	84
Other income - related parties	14			11			3			25			18			7
Unrealized derivative gains (losses)⁽¹⁾	3			(12		)	15			19			(21		)	40
Depreciation and amortization	(164		)	(151		)	(13		)	(351		)	(287		)	(64		)
Impairment expense	—			(1		)	1			—			(130		)	130
General and administrative expenses	(57		)	(63		)	6			(115		)	(116		)	1
Income from operations	$	280		$	128		$	152		$	545		$	178		$	367



	Three Months Ended June 30,								Six Months Ended June 30,
(In millions)	2017			2016			Variance		2017			2016			Variance
Reconciliation to Total revenues and other income:
Total segment revenues and other income	$	987		$	875		$	112	$	1,942		$	1,620		$	322
Revenue adjustment from unconsolidated affiliates	(88		)	(99		)	11		(180		)	(203		)	23
Income (loss) from equity method investments	1			(83		)	84		6			(78		)	84
Other income - related parties	14			11			3		25			18			7
Unrealized derivative gains (losses) related to product sales⁽¹⁾	2			(6		)	8		9			(14		)	23
Total revenues and other income	$	916		$	698		$	218	$	1,802		$	1,343		$	459

(1)



	Three Months Ended June 30,									Six Months Ended June 30,
(In millions)	2017			2016			Variance			2017			2016			Variance
Reconciliation to Net income attributable to noncontrolling interests and Predecessor:
Segment portion attributable to noncontrolling interests and Predecessor	$	38		$	116		$	(78	)	$	127		$	219		$	(92	)
Portion of noncontrolling interests and Predecessor related to items below segment income from operations	(27		)	(84		)	57			(63		)	(118		)	55
Portion of operating (income) loss attributable to noncontrolling interests of unconsolidated affiliates	(10		)	21			(31		)	(26		)	(2		)	(24		)
Net income attributable to noncontrolling interests and Predecessor	$	1		$	53		$	(52	)	$	38		$	99		$	(61	)

OUR G&P CONTRACTS WITH THIRD PARTIES

We generate the majority of our revenues in the G&P segment from natural gas gathering, transportation and processing; NGL gathering, transportation, fractionation, exchange, marketing and storage; and crude oil gathering and transportation. We enter into a variety of ~~contract types.~~contracts to provide services under the following types of arrangements: fee-based, percent-of-proceeds, percent-of-index and keep-whole. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described below. ~~We provide services under the following types of arrangements: fee-based, percent-of-proceeds, percent-of-index and keep-whole.~~ See Item 1. ~~Business-Our~~Business – Our G&P Contracts With Third Parties in our Annual Report on Form 10-K for the year ended December 31, ~~2015, as updated by our Current Report on Form 8-K/A filed on May 20,~~ 2016 for further discussion of each of these types of arrangements.

The following table does not give effect to our active commodity risk management program. For further discussion of how we manage commodity price volatility for the portion of our net operating margin that is not fee-based, see Note 13 of the Notes to Consolidated Financial Statements. We manage our business by taking into account the partial offset of short natural gas positions primarily in the Southwest region of our G&P segment. The calculated percentages for net operating margin for percent-of-proceeds, percent-of-index and keep-whole contracts reflect the partial offset of our natural gas positions. The calculated percentages are less than one percent for percent-of-index due to the offset of our natural gas positions and, therefore, not meaningful to the table below.

For the three months ended June 30, ~~2016,~~2017, we calculated the following approximate percentages of our net operating margin from the following types of contracts:


	Fee-Based		Percent-of-Proceeds⁽¹⁾		Keep-Whole⁽²⁾		Fee-Based		Percent-of-Proceeds⁽¹⁾		Keep-Whole⁽²⁾
L&S	100	%	—	%	—	%	100	%	—	%	—	%
G&P⁽³⁾	90	%	9	%	1	%	88	%	10	%	2	%
Total	93	%	6	%	1	%	93	%	6	%	1	%

For the six months ended June 30, ~~2016,~~2017, we calculated the following approximate percentages of our net operating margin from the following types of contracts:


	Fee-Based		Percent-of-Proceeds⁽¹⁾		Keep-Whole⁽²⁾		Fee-Based		Percent-of-Proceeds⁽¹⁾		Keep-Whole⁽²⁾
L&S	100	%	—	%	—	%	100	%	—	%	—	%
G&P⁽³⁾	92	%	7	%	1	%	87	%	11	%	2	%
Total	94	%	5	%	1	%	93	%	6	%	1	%


(1)	Includes condensate sales and other types of arrangements tied to NGL prices.


(2)	Includes condensate sales and other types of arrangements tied to both NGL and natural gas prices.


(3)	Includes unconsolidated affiliates (See Note 4 of the Notes to Consolidated Financial Statements).

~~Table of Contents~~

The following table presents a reconciliation of net operating margin to income from operations, the most directly comparable GAAP financial measure.


	Three Months Ended June 30,						Six Months Ended June 30,						Three Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2016			2015			2017			2016			2017			2016
Reconciliation of net operating margin to income from operations:
Segment revenue	$	723		$	193		$	1,413		$	376
Less: Segment purchased product costs	108			—			186			—
Realized derivative (loss) gain related to revenues and purchased product costs	(1		)	—			6			—
Segment revenues													$	975		$	861		$	1,917		$	1,590
Segment purchased product costs													(141		)	(108		)	(281		)	(186		)
Realized derivative loss related to purchased product costs⁽¹⁾													2			2			4			3
Net operating margin	616			193			1,221			376			836			755			1,640			1,407
Revenue adjustment from unconsolidated affiliates⁽¹⁾⁽²⁾	(99		)	—			(203		)	—			(88		)	(99		)	(180		)	(203		)
Realized derivative (loss) gain related to revenues and purchased product costs	(1		)	—			6			—
Unrealized derivative losses	(12		)	—			(21		)	—
Loss from equity method investments	(83		)	—			(78		)	—
Realized derivative loss related to purchased product costs⁽¹⁾													(2		)	(2		)	(4		)	(3		)
Unrealized derivative gains (losses)⁽¹⁾													3			(12		)	19			(21		)
Income (loss) from equity method investments													1			(83		)	6			(78		)
Other income	1			2			3			3			1			1			3			3
Other income - related parties	28			18			52			35			25			24			47			45
Cost of revenues (excludes items below)	(84		)	(46		)	(173		)	(88		)	(139		)	(113		)	(252		)	(207		)
Rental cost of sales	(14		)	—			(28		)	—			(13		)	(15		)	(25		)	(29		)
Rental cost of sales - related parties													(1		)	(1		)	(1		)	(1		)
Purchases - related parties	(78		)	(40		)	(154		)	(80		)	(109		)	(99		)	(216		)	(177		)
Depreciation and amortization	(137		)	(20		)	(269		)	(39		)	(164		)	(151		)	(351		)	(287		)
Impairment expense	(1		)	—			(130		)	—			—			(1		)	—			(130		)
General and administrative expenses	(49		)	(21		)	(101		)	(43		)	(57		)	(63		)	(115		)	(116		)
Other taxes	(11		)	(4		)	(22		)	(8		)	(13		)	(13		)	(26		)	(25		)
Income from operations	$	76		$	82		$	103		$	156		$	280		$	128		$	545		$	178

(1)


(2)	These amounts relate to Partnership operated unconsolidated affiliates. The chief operating decision maker and management include these to evaluate the segment performance as we continue to operate and manage the operations. Therefore, the impact of the revenue is included for segment reporting purposes, but removed for GAAP purposes.

SEASONALITY

The volume of crude oil and refined products transported on our pipeline systems, at our barge dock and stored at our storage assets is directly affected by the level of supply and demand for crude oil and refined products in the markets served directly or indirectly by our assets. Many effects of seasonality on the L&S segment’s revenues will be mitigated through the use of our fee-based transportation and storage services agreements with MPC that include minimum volume commitments. Historically, the L&S segment has spent approximately two-thirds of both our budgeted maintenance capital expenditures and budgeted pipeline integrity, repair and maintenance expenses during the third and fourth quarter of each calendar year due to our budgeting cycle, operating conditions, weather and safety concerns.

Our G&P segment can be affected by seasonal fluctuations in the demand for natural gas and NGLs and the related fluctuations in commodity prices caused by various factors such as changes in transportation and travel patterns and variations in weather patterns from year to year. However, we manage the seasonality impact through the execution of our marketing strategy. We have access to up to 50 million gallons of propane storage capacity in the Southern Appalachia region provided by an arrangement with a ~~third-party~~third party which provides us with flexibility to manage the seasonality impact. Overall, our exposure to the seasonal fluctuations in the commodity markets is declining due to our growth in fee-based business.

5153

~~Table of Contents~~

OPERATING DATA

Three Months Ended June 30, Six Months Ended June 30,
2016 2015 2016 2015
L&S
Pipeline throughput (mbpd):
Crude oil pipelines 1,066
1,123
1,045
1,068
Product pipelines 904
941
910
913
Total pipelines 1,970
2,064
1,955
1,981

Average tariff rates ($ per barrel)⁽¹⁾:

Crude oil pipelines $ 0.69
$ 0.66
$ 0.69
$ 0.67
Product pipelines 0.68
0.64
0.67
0.63
Total pipelines 0.68
0.65
0.68
0.65

Marine Assets (number in operation)⁽²⁾

Barges 205
202
205
202
Towboats 18
18
18
18

G&P⁽³⁾

Gathering Throughput (mmcf/d)
Marcellus operations 918
910

Utica operations⁽⁴⁾
902
946

Southwest operations⁽⁵⁾
1,468
1,460

Total gathering throughput 3,288
3,316

Natural Gas Processed (mmcf/d)
Marcellus operations 3,072
3,112

Utica operations⁽⁴⁾
1,034
1,077

Southwest operations 1,175
1,142

Southern Appalachian operations 248
251

Total natural gas processed 5,529
5,582

C2 + NGLs Fractionated (mbpd)
Marcellus operations⁽⁶⁾
252
244

Utica operations⁽⁴⁾⁽⁶⁾
40
44

Southwest operations 14
16

Southern Appalachian operations⁽⁷⁾
16
17

Total C2 + NGLs fractionated⁽⁸⁾
322
321

Pricing Information
Natural Gas NYMEX HH ($ per MMBtu) $ 2.24
$ 2.12

C2 + NGL Pricing ($ per gallon)⁽⁹⁾
$ 0.47
$ 0.42



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
L&S
Pipeline throughput (mbpd)⁽¹⁾
Crude oil pipelines	2,027		1,643		1,827		1,609
Product pipelines	1,067		987		1,010		988
Total pipelines	3,094		2,630		2,837		2,597

Average tariff rates ($ per barrel)⁽¹⁾⁽²⁾
Crude oil pipelines	$	0.58	$	0.57	$	0.58	$	0.58
Product pipelines	0.70		0.67		0.73		0.66
Total pipelines	0.62		0.61		0.63		0.61

Terminal throughput (mbpd)	1,489		1,503		1,456		1,503

Marine Assets (number in operation)⁽³⁾
Barges	232		219		232		219
Towboats	18		18		18		18

G&P
Gathering Throughput (MMcf/d)
Marcellus Operations	964		918		944		910
Utica Operations⁽⁴⁾	951		902		933		946
Southwest Operations⁽⁵⁾	1,411		1,468		1,378		1,460
Total gathering throughput	3,326		3,288		3,255		3,316

Natural Gas Processed (MMcf/d)
Marcellus Operations	3,811		3,072		3,672		3,112
Utica Operations⁽⁴⁾	879		1,034		973		1,077
Southwest Operations	1,333		1,175		1,300		1,142
Southern Appalachian Operations	269		248		267		251
Total natural gas processed	6,292		5,529		6,212		5,582

C2 + NGLs Fractionated (mbpd)
Marcellus Operations⁽⁶⁾	313		252		302		244
Utica Operations⁽⁴⁾⁽⁶⁾	38		40		40		44
Southwest Operations	21		14		20		16
Southern Appalachian Operations⁽⁷⁾	15		16		15		17
Total C2 + NGLs fractionated⁽⁸⁾	387		322		377		321

Pricing Information
Natural Gas NYMEX HH ($ per MMBtu)	$	3.14	$	2.24	$	3.10	$	2.12
C2 + NGL Pricing ($ per gallon)⁽⁹⁾	$	0.57	$	0.47	$	0.60	$	0.42


(1)	Pipeline throughput and tariff rates as of June 30, 2016 have been retrospectively adjusted to reflect the acquisition of HST.


(2)	Average tariff rates calculated using pipeline transportation revenues divided by pipeline throughput barrels.


~~(2)~~(3)	Represents total at end of period.


~~(3)~~	~~See Supplemental MD&A - G&P Pro Forma comparable prior year pro-forma information.~~


(4)	~~Utica is an~~Includes unconsolidated equity method ~~investment and is~~investments that are shown consolidated for segment purposes only.

(5)

Includes approximately ~~291 mmcf/~~363 MMcf/d and ~~294 mmcf/~~347 MMcf/d related to unconsolidated equity method investments, Wirth and MarkWest Pioneer, for the three and six months ended June 30, 2017, respectively. Includes approximately 291 MMcf/d and 294 MMcf/d related to unconsolidated equity method investments, Wirth and MarkWest Pioneer, for the three and six months ended June 30, 2016, respectively.

~~Table of Contents~~

~~MarkWest Pioneer, for the three and six months ended June 30, 2016, respectively.~~

(6)

Hopedale is jointly owned by Ohio Fractionation and MarkWest Utica EMG. Ohio Fractionation is a subsidiary of MarkWest Liberty Midstream. MarkWest Liberty Midstream and MarkWest Utica EMG are entities that operate in the Marcellus and Utica regions, respectively. The Marcellus Operations includes its portion utilized of the jointly owned Hopedale Fractionation Complex. The Utica Operations includes Utica’s portion utilized of the jointly owned Hopedale Fractionation Complex. Additionally, Sherwood Midstream has the right to fractionation revenue and the obligation to pay expenses related to 20 mbpd of capacity in the Hopedale 3 fractionator.


(7)	Includes NGLs fractionated for the Marcellus Operations and Utica ~~operations.~~Operations.


(8)	Purity ethane makes up approximately 162 mbpd and 158 mbpd of total fractionated products for the three and six months ended June 30, 2017, respectively, and approximately 124 mbpd and 119 mbpd of total fractionated products for the three and six months ended June 30, 2016, respectively.


(9)	C2 + NGL pricing based on Mont Belvieu prices assuming an NGL barrel of approximately 35 percent ethane, 35 percent propane, six percent Iso-Butane, 12 percent normal butane and 12 percent natural gasoline.

~~SUPPLEMENTAL MD&A - G&P PRO FORMA~~

~~Three and Six Months Ended June 30, 2016 Compared to Three and Six Months Ended June 30, 2015~~

The tables below present financial information, as evaluated by management, for the reported segments for the three and six months ended June 30, 2016 and 2015. The 2016 amounts are actual results. This is a supplemental disclosure showing G&P segment results as if it were acquired as of January 1, 2014 and it incorporates pro forma adjustments necessary, to reflect a January 1, 2014 acquisition date (see reconciliations below). The pro forma information was prepared in a manner consistent with Article 11 of Regulation S-X and FASB ASC Topic 805 (see Note 3 of the Notes to Consolidated Financial Statements). We believe this data will provide a more meaningful discussion of trends for the G&P segment as it helps convey the impact of commodity pricing and volume changes to the business. Future results may vary significantly from the results reflected below because of various factors. In addition, all Partnership operated, non-wholly-owned subsidiaries are treated as if they are consolidated for segment reporting purposes (for more information on how management has determined our segments see Note 9 of the Notes to Consolidated Financial Statements).

Three Months Ended June 30, Six Months Ended June 30,
(In millions) 2016 2015 Variance 2016 2015 Variance
Revenues and other income:
Segment revenue and other income $ 530
$ 492
$ 38
$ 1,028
$ 989
$ 39
Total segment revenues and other income 530
492
38
1,028
989
39
Costs and expenses:
Segment cost of revenues 223
223
—
423
453
(30 )
Segment operating income before portion attributable to noncontrolling interest 307
269
38
605
536
69
Segment portion attributable to noncontrolling interest 36
26
10
77
48
29
Segment operating income attributable to MPLX LP $ 271
$ 243
$ 28
$ 528
$ 488
$ 40

~~Three months ended June 30, 2016 compared to three months ended June 30, 2015~~

In the second quarter of 2016 compared to the same period of 2015, segment revenue increased slightly due to an increase in volumes. Total gathering throughput, total natural gas processed and total C2+ NGLs fractionated volumes increased by 14 percent, 11 percent and 24 percent, respectively. These volume increases mainly related to our expansions in Marcellus and Utica operations. This increase was offset by a 18 percent decrease in natural gas prices and a 2 percent decrease in NGL prices over the same period in 2015.

The change in the segment portion of operating income attributable to noncontrolling interests increased for the second quarter of 2016 compared to the same period of 2015 due to ongoing growth in our entities that are not wholly-owned.

~~Six months ended June 30, 2016 compared to six months ended June 30, 2015~~

In the first six months of 2016 compared to the same period of 2015, segment revenue increased slightly due to an increase in volumes. Total gathering throughput, total natural gas processed and total C2+ NGLs fractionated volumes increased by 18 percent, 12 percent and 27 percent, respectively. These volume increases mainly related to our expansions in Marcellus and Utica operations. This increase was offset by a 23 percent decrease in natural gas prices and a 14 percent decrease in NGL prices over the same period in 2015.

~~In the first six months of 2016 compared to the same period of 2015, segment cost of revenues decreased mainly due to~~

~~Table of Contents~~

decreases in natural gas purchased prices and NGL prices. Segment cost of revenues as a percentage of segment revenues and other income decreased 4 percent for the six months ended June 30, 2016 compared to the same period in 2015. This decrease was primarily due to an increase in fee revenue as a percent of total revenue by 3 percent. The decreases were partially offset by increased expenses related to the expansion of Utica and Marcellus operations.

The increase in the segment portion of operating income attributable to noncontrolling interests for the first six months of 2016 compared to the same period of 2015 is due to ongoing growth in our entities that are not wholly-owned.

~~Reconciliation of Segment Operating Income to Consolidated Income Before Benefit for Income Tax~~

The following tables provide reconciliations of G&P segment revenues and other income to total revenues and other income and G&P’s segment operating income attributable to MPLX LP to net income attributable to MPLX LP, for the three and six months ended June 30, 2016 and 2015, respectively. The ensuing items listed below the ~~Other income-related parties~~ ~~lines are not allocated to business segments as management does not consider these items allocable to any individual segment.~~

Three Months Ended June 30, Six Months Ended June 30,
(In millions) 2016 2015 Variance 2016 2015 Variance
Pro forma reconciliation to total revenues and other income:
Total G&P segment revenues and other income $ 530
$ 492
$ 38
$ 1,028
$ 989
$ 39
Revenue adjustment from unconsolidated affiliates (99 ) (31 ) (68 ) (203 ) (59 ) (144 )
Loss from equity method investments (83 ) 1
(84 ) (78 ) (2 ) (76 )
G&P Other income (loss) - related parties 11
(2 ) 13
18
(1 ) 19
Unrealized derivative losses related to revenue (6 ) (5 ) (1 ) (14 ) (9 ) (5 )
Total pro forma G&P revenues and other income 353
455
(102 ) 751
918
(167 )
Total pro forma L&S revenues and other income 211
213
(2 ) 422
414
8
Total pro forma revenues and other income $ 564
$ 668
$ (104 ) $ 1,173
$ 1,332
$ (159 )

~~Table of Contents~~

Three Months Ended June 30, Six Months Ended June 30,
(In millions) 2016 2015 Variance 2016 2015 Variance
Pro Forma reconciliation to pro forma net income attributable to MPLX LP:
Segment operating income attributable to G&P $ 271
$ 243
$ 28
$ 528
$ 488
$ 40
Segment operating income attributable to L&S 123
88
35
211
170
41
Segment portion attributable to unconsolidated affiliates (83 ) (4 ) (79 ) (166 ) (6 ) (160 )
Segment portion attributable to noncontrolling interest and Predecessor 36
47
(11 ) 111
90
21
(Loss) income from equity method investments (83 ) 1
(84 ) (78 ) (2 ) (76 )
Other income (loss) - related parties 11
(2 ) 13
18
—
18
Unrealized derivative losses (12 ) (7 ) (5 ) (21 ) (16 ) (5 )
Depreciation and amortization (137 ) (140 ) 3
(269 ) (279 ) 10
Impairment expense (1 ) —
(1 ) (130 ) (26 ) (104 )
General and administrative expenses (49 ) (53 ) 4
(101 ) (110 ) 9
Pro forma income from operations 76
173
(97 ) 103
309
$ (206 )
Related party interest and other financial costs —
—
—
1
—
1
Debt retirement expense —
118
(118 ) —
118
(118 )
Net interest and other financial costs 64
65
(1 ) 131
126
5
Pro forma income (loss) before income taxes 12
(10 ) 22
(29 ) 65
(94 )
Benefit for income taxes (8 ) (11 ) 3
(12 ) (14 ) 2
Pro forma net income (loss) 20
1
19
(17 ) 79
(96 )
Less: Net income attributable to noncontrolling interests 1
12
(11 ) 24
26
(2 )
Pro forma net income (loss) attributable to MPLX LP $ 19
$ (11 ) $ 30
$ (41 ) $ 53
$ (94 )

~~Table of Contents~~

Three Months Ended June 30, Six Months Ended June 30,
2016 2015 % Change 2016 2015 % Change
Pro Forma Operating Statistics
Gathering Throughput (mmcf/d)
Marcellus operations 918
857
7 % 910
836
9 %
Utica operations⁽¹⁾
902
583
55 % 946
543
74 %
Southwest operations⁽²⁾
1,468
1,445
2 % 1,460
1,421
3 %
Total gathering throughput 3,288
2,885
14 % 3,316
2,800
18 %

Natural Gas Processed (mmcf/d)

Marcellus operations 3,072
2,894
6 % 3,112
2,870
8 %
Utica operations⁽¹⁾
1,034
762
36 % 1,077
759
42 %
Southwest operations 1,175
1,064
10 % 1,142
1,065
7 %
Southern Appalachian operations 248
278
(11 )% 251
272
(8 )%
Total natural gas processed 5,529
4,998
11 % 5,582
4,966
12 %

C2 + NGLs Fractionated (mbpd)
Marcellus operations⁽³⁾
252
193
31 % 244
187
30 %
Utica operations⁽¹⁾⁽³⁾
40
34
18 % 44
34
29 %
Southwest operations 14
17
(18 )% 16
17
(6 )%
Southern Appalachian operations⁽⁴⁾
16
15
7 % 17
15
13 %
Total C2 + NGLs fractionated⁽⁵⁾
322
259
24 % 321
253
27 %

Pricing Information
Natural Gas NYMEX HH ($ per MMBtu) $ 2.24
$ 2.74
(18 )% $ 2.12
$ 2.77
(23 )%
C2 + NGL Pricing ($ per gallon)⁽⁶⁾
$ 0.47
$ 0.48
(2 )% $ 0.42
$ 0.49
(14 )%


~~(1)~~	~~Utica is an unconsolidated equity method investment and is consolidated for segment purposes only.~~

~~(2)~~

Includes approximately 291 mmcf/d and 239 mmcf/d related to unconsolidated equity method investments, Wirth and MarkWest Pioneer, for the three months ended June 30, 2016 and June 30, 2015, respectively. Includes approximately 294 mmcf/d and 226 mmcf/d related to unconsolidated equity method investments, Wirth and MarkWest Pioneer, for the six months ended June 30, 2016 and June 30, 2015, respectively.


~~(3)~~	Hopedale is jointly owned by MarkWest Liberty Midstream and MarkWest Utica EMG, respectively. The Marcellus Operations includes its portion utilized of the jointly owned Hopedale Fractionation Complex. The Utica Operations includes Utica’s portion utilized of the jointly owned Hopedale Fractionation Complex.


~~(4)~~	~~Includes NGLs fractionated for the Marcellus and Utica operations.~~


~~(5)~~	Purity ethane makes up approximately 124 mbpd and 76 mbpd of total fractionated products for the three months ended June 30, 2016 and June 30, 2015, respectively, and approximately 119 mbpd and 72 mbpd of total fractionated products for the six months ended June 30, 2016 and June 30, 2015, respectively.


~~(6)~~	C2 + NGL pricing based on Mont Belvieu prices assuming an NGL barrel of approximately 35 percent ethane, 35 percent propane, 6 percent Iso-Butane, 12 percent normal butane and 12 percent natural gasoline.

~~Table of Contents~~

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Our cash and cash equivalents balance was ~~$35~~$293 million at June 30, ~~2016~~2017 compared to ~~$43~~$234 million at December 31, ~~2015.~~2016. The change in cash and cash equivalents was due to the factors discussed below. Net cash provided by (used in) operating activities, investing activities and financing activities were as follows:


	Six Months Ended June 30,						Six Months Ended June 30,
(In millions)	2016			2015			2017			2016
Net cash provided by (used in):
Operating activities	$	593		$	173		$	844		$	670
Investing activities	(526		)	(109		)	(1,404		)	(603		)
Financing activities	(75		)	39			619			(75		)
Total	$	(8	)	$	103		$	59		$	(8	)

Net cash provided by operating activities increased ~~$420~~$174 million in the first six months of ~~2016~~2017 compared to the first six months of ~~2015,~~2016, the majority of which is related to an increase in adjusted EBITDA of $170 million. The favorable change in adjusted EBITDA was driven primarily by higher prices and volumes, as well as the ~~MarkWest Merger.~~inclusion of MPLXT, since it was not formed as a business until April 1, 2016, and the acquisition of the Ozark pipeline.

Net cash used in investing activities increased ~~$417~~$801 million in the first six months of ~~2016~~2017 compared to the first six months of ~~2015,~~2016, primarily due to ~~a $499~~the acquisition of an equity interest in the Bakken Pipeline system for $513 million, ~~use~~$220 million for the acquisition of the Ozark pipeline, investments in unconsolidated entities of approximately $127 million, as well as an increase in cash used for additions to property, plant and equipment related to various capital ~~projects, mainly due to the~~projects. Partially offsetting these items was a return of capital of $24 million from our acquisition of ~~MarkWest,~~equity interests in Sherwood Midstream and Sherwood Midstream Holdings and a ~~$39~~$43 million ~~use of cash for investments~~increase in ~~unconsolidated affiliates, partially offset by a $115 million source of cash from~~ investment loans ~~between HSM and related parties.~~with MPC.

Financing activities were a $619 million source of cash in the first six months of 2017 compared to a $75 million use of cash in the first six months of 2016 compared to a $39 million source of cash in the first six months of 2015. The use of cash in the first six months of 2016 was primarily due to $877 million in net repayments on the bank revolving credit facility, $8 million of net repayments from the related party debt borrowings, distributions of $391 million and $104 million in distributions to MPC from Predecessor, partially offset by $321 million of net proceeds from sales of common units under the ATM Program and $984 million of net proceeds from the issuance of the Preferred Units.2016. The source of cash in the first six months of ~~2015~~2017 was primarily due to ~~$495~~$2.2 billion of net proceeds from the New Senior Notes, $128 million in contributions from noncontrolling interests, and $443 million of net proceeds from ~~the issuance~~sales of ~~the senior notes due 2025 and borrowings of $30 million~~units under the ~~bank revolving credit facility,~~ATM Program. These items were partially offset by ~~$415 million in long-term debt repayments primarily on~~distributions to MPC of $1.5 billion for the ~~bank revolving credit facility~~acquisition of HST, WHC and MPLXT, distributions of ~~$70 million.~~$33 million to Preferred unitholders, and increased distributions of $114 million to unitholders and our general partner due mainly to the increase in units outstanding as well as a four percent increase in the distribution per common unit.

Debt and Liquidity Overview

Our outstanding borrowings at June 30, ~~2016~~2017 and December 31, ~~2015~~2016 consisted of the following:


(In millions)	June 30, 2016			December 31, 2015			June 30, 2017			December 31, 2016
MPLX LP:
Bank revolving credit facility due 2020	$	—		$	877		$	—		$	—
Term loan facility due 2019	250			250			250			250
5.500% senior notes due 2023	710			710
4.500% senior notes due 2023	989			989
4.875% senior notes due 2024	1,149			1,149
4.000% senior notes due 2025	500			500
4.875% senior notes due 2025	1,189			1,189
5.500% senior notes due February 2023							710			710
4.500% senior notes due July 2023							989			989
4.875% senior notes due December 2024							1,149			1,149
4.000% senior notes due February 2025							500			500
4.875% senior notes due June 2025							1,189			1,189
4.125% senior notes due March 2027							1,250			—
5.200% senior notes due March 2047							1,000			—
Consolidated subsidiaries:
MarkWest - 4.500% - 5.500%, due 2023 - 2025	63			63
MarkWest - 4.500% - 5.500%, due 2023-2025							63			63
MPL - capital lease obligations due 2020	9			9			8			8
Total	4,859			5,736			7,108			4,858
Unamortized debt issuance costs	(8		)	(8		)	(28		)	(7		)
Unamortized discount⁽¹⁾	(450		)	(472		)
Unamortized discount							(413		)	(428		)
Amounts due within one year	(1		)	(1		)	(1		)	(1		)
Total long-term debt due after one year	$	4,400		$	5,255		$	6,666		$	4,422

~~Table of Contents~~


~~(1)~~	Includes $442 million and $465 million discount as of June 30, 2016 and December 31, 2015, respectively, related to the difference between the fair value and the principal amount of the assumed MarkWest debt.

The ~~decrease~~increase in debt as of June 30, ~~2016~~2017 compared to year-end ~~2015~~2016 was ~~primarily related~~due to the ~~repayment~~public offering of the New Senior Notes in the first quarter of 2017 for general partnership purposes including the acquisition of HST, WHC and MPLXT from MPC, the acquisition of our equity interest in MarEn Bakken, the acquisition of the Ozark pipeline and capital expenditures. See Notes 3, 4 and 14 of the Notes to Consolidated Financial Statements for additional information.

On July 21, 2017, the Partnership entered into a credit agreement to replace its previous $2.0 billion five-year bank revolving credit facility ~~using proceeds from~~with a $2.25 billion five-year bank revolving credit facility that expires in July 2022. The financial covenants and the ~~issuance~~interest rate terms contained in the new credit agreement are substantially the same as those contained in the previous bank revolving credit facility. Additionally, on July 19, 2017, MPLX LP prepaid the entire outstanding principal amount of ~~the Preferred Units.~~its $250 million term loan with cash on hand.

Our bank revolving credit facility and term loan facility (“MPLX Credit Agreement”) include certain representations and warranties, affirmative and negative covenants and events of default that we consider usual and customary for an agreement of that type, and that could, among other things, limit our ability to pay distributions to our unitholders. The financial covenant requires us 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. As of June 30, ~~2016,~~2017, we were in compliance with this financial covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of ~~3.6~~3.4 to 1.0, as well as other covenants contained in the MPLX Credit Agreement.

Our intention is to maintain an investment grade credit profile. As of June 30, ~~2016,~~2017, the credit ratings on our senior unsecured debt were at or above investment grade level as ~~follows.~~

follows:



Rating Agency		Rating
~~Fitch~~		~~BBB- (stable outlook)~~
Moody’s		Baa3 (stable outlook)
Standard & Poor’s		BBB- (stable outlook)
Fitch		BBB- (stable outlook)

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

The MPLX Credit Agreement does not contain credit rating triggers that would result in the acceleration of interest, principal or other payments in the event that our credit ratings are downgraded. However, any downgrades in the credit ratings of our senior unsecured debt ratings to below investment grade ratings would increase the applicable interest rates and other fees payable under the MPLX Credit Agreement and may limit our flexibility to obtain future financing.

Our liquidity totaled ~~$2.5~~$2.8 billion at June 30, ~~2016~~2017 consisting of:


	June 30, 2016							June 30, 2017
(In millions)	Total Capacity		Outstanding Borrowings			Available Capacity		Total Capacity		Outstanding Borrowings			Available Capacity
MPLX LP - bank revolving credit facility⁽¹⁾	$	2,000	$	(8	)	$	1,992	$	2,000	$	(3	)	$	1,997
MPC Investment - loan agreement	500		—			500		500		—			500
Total	$	2,500	$	(8	)	$	2,492
Total liquidity								$	2,500	$	(3	)	$	2,497
Cash and cash equivalents⁽²⁾						33							293
Total liquidity						$	2,525						$	2,790


(1)	Outstanding borrowings include $8$3 million in letters of credit outstanding under this facility.


~~(2)~~	~~Approximately $2 million of cash and cash equivalents related to our consolidated joint venture and is not available for general use.~~

We expect our ongoing sources of liquidity to include cash generated from operations, borrowings under our revolving credit agreements and issuances of additional debt and equity securities. We believe that cash generated from these sources will be sufficient to meet our short-term and long-term funding requirements, including working capital requirements, capital expenditure requirements, contractual obligations, repayment of debt maturities and quarterly cash distributions. MPC manages our cash and cash equivalents on our behalf directly with third-party institutions as part of the treasury services that it provides to us under our omnibus agreement.

~~Table~~ From time to time we may also consider other sources of ~~Contents~~

liquidity, including formation of joint ventures or sales of non-strategic assets.

Equity and Preferred ~~Unit~~Units Overview

The table below summarizes the changes in the number of units outstanding through June 30, ~~2016:~~2017:


(In units)	Common	Class B	General Partner	Total	Common	Class B	General Partner	Total
Balance at December 31, 2015	296,687,176	7,981,756	6,800,475	311,469,407
Balance at December 31, 2016					357,193,288	3,990,878	7,371,105	368,555,271
Unit-based compensation awards	37,251	—	761	38,012	168,622	—	3,441	172,063
Issuance of units under the ATM Program	12,025,000	—	245,406	12,270,406	12,662,663	—	258,422	12,921,085
Contribution of HSM	22,534,002	—	459,878	22,993,880
Balance at June 30, 2016	331,283,429	7,981,756	7,506,520	346,771,705
Contribution of HST/WHC/MPLXT					12,960,376	—	264,497	13,224,873
Balance at June 30, 2017					382,984,949	3,990,878	7,897,465	394,873,292

For more details on equity activity, see Notes 7 and 8 of the Notes to Consolidated Financial Statements.

~~On May 13, 2016,~~The Partnership expects the ~~Partnership completed~~net proceeds from sales under the ~~private placement~~ATM Program will be used for general partnership purposes including repayment or refinancing of ~~approximately 30.8 million Preferred Units~~debt and funding for ~~a cash purchase price~~acquisitions, working capital requirements and capital expenditures. During the six months ended June 30, 2017, the sale of ~~$32.50 per unit. The aggregate~~common units under the ATM Program generated net proceeds of approximately ~~$984~~$434 million. As of June 30, 2017, $280 million ~~from~~of common units remain available for issuance through the ~~sale~~ATM Program under the Distribution Agreement.

MPC agreed to waive two-thirds of the ~~Preferred Units will be used for capital expenditures, repayment of debt and general partnership purposes. With~~first quarter 2017 distributions on the ~~completion of its $1.3 billion of financing earlier this year, the Partnership has provided for its forecast funding needs through the remainder of 2016 and into 2017.~~

~~On July 1, 2016, 3,990,878 Class B units automatically converted into 1.09~~ MPLX LP common units issued in connection with the acquisition of HST, WHC and the right to receive $6.20 per unit in cash. They are also eligible to receive the second quarter distribution. MPC funded this cash payment, which reduced our liability payable to Class B unitholders by approximately $25 million on July 1, 2016.MPLXT. As a result of ~~the Class B units conversion on July 1, 2016, MPLX GP contributed less than $1 million in exchange for 7,330~~this waiver, MPC did not receive general partner distributions or incentive distribution rights that would have otherwise accrued on such MPLX LP common units with respect to ~~maintain~~the first quarter 2017 distributions. The value of these waived distributions was $6 million. Additionally, in connection with our acquisition of a partial, indirect equity interest in Bakken Pipeline system on February 15, 2017, MPC agreed to waive its ~~two percent general partner interest.~~right to receive incentive distributions of $1.6 million per quarter for twelve consecutive quarters beginning with the distributions declared in the first quarter of 2017 and paid to MPC in the second quarter, which was prorated from the acquisition date.

We intend to pay at least the minimum quarterly distribution of $0.2625 per unit per quarter, which equates to ~~$89~~$103 million per quarter, or ~~$356~~$410 million per year, based on the number of common and general partner units outstanding at June 30, ~~2016.~~2017. On July ~~22, 2016,~~26, 2017, we announced the board of directors of our general partner had declared a distribution of ~~$0.5100~~$0.5625 per unit that will be paid on August ~~12, 2016~~14, 2017 to unitholders of record on August ~~2, 2016.~~7, 2017. This represents an increase of ~~0.0050~~$0.0225 per unit, or ~~one~~four percent, above the first quarter ~~2016~~2017 distribution of ~~$0.5050~~$0.5400 per unit and an increase of 16ten percent over the second quarter ~~2015~~2016 distribution. This increase in the distribution is consistent with our intent to maintain an attractive distribution growth profile over an extended period of time. Although our partnership agreement requires that we distribute all of our available cash each quarter, we do not otherwise have a legal obligation to distribute any particular amount per unit.

The allocation of total quarterly cash distributions to general and limited partners is as follows for the three and six months ended June 30, ~~2016~~2017 and ~~2015.~~2016. Our 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.


	Three Months Ended June 30,				Six Months Ended June 30,				Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2016		2015		2016		2015		2017		2016		2017		2016
Distribution declared:
Limited partner units - public	$	131	$	10	$	258	$	20	$	162	$	131	$	311	$	258
Limited partner units - MPC	41		25		70		48		51		41		98		70
Limited partner units - GP									5		—		7		—
General partner units - MPC	4		1		8		2		6		4		11		8
Incentive distribution rights - MPC	46		6		86		9		70		46		130		86
Total GP & LP distribution declared	222		42		422		79		294		222		557		422
Redeemable preferred units	9		—		9		—		17		9		33		9
Total distribution declared	$	231	$	42	$	431	$	79	$	311	$	231	$	590	$	431

Cash distributions declared per limited partner common unit	$	0.5100	$	0.4400	$	1.0150	$	0.8500	$	0.5625	$	0.5100	$	1.1025	$	1.0150

Our intentions regarding the distribution growth profile expressed above include forward-looking statements. Such forward-looking statements are not guarantees of future performance and are subject to risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Factors that could cause actual results to differ materially from those implied in the forward-looking statements include: the adequacy of our capital resources and liquidity, including, but not

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limited to, the availability of sufficient cash flow to pay distributions and execute our business plan; negative capital market conditions, including ~~a persistence or~~an increase of the current yield on common ~~units, which is higher than historical yields;~~units; the timing and extent of changes in commodity prices and demand for natural gas, NGLs, crude oil, feedstocks or refined petroleum products; volatility in and/or degradation of market and industry conditions; completion of midstream capacity by our competitors; disruptions due to equipment interruption or failure, including electrical shortages and power grid failures; the suspension, reduction or termination of MPC’s obligations under our commercial agreements; our ability to successfully implement our growth plan, whether through organic growth or acquisitions; modifications to earnings and distribution objectives; state and federal environmental, economic, health and safety, energy and other policies and regulations; changes to our capital budget; financial stability of our producer customers and MPC; other risk factors inherent to our industry; and the factors set forth under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, ~~2015, as updated by our Current Report on Form 8-K/A filed on May 20, 2016, and our Quarterly Report on Form 10-Q for the quarter ended March 31,~~ 2016. In addition, the forward-looking statements included herein could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed here or in our SEC filings could also have material adverse effects on forward-looking statements.

MPC Strategic Actions

On January 3, 2017, MPC announced its plans to offer the Partnership the opportunity to acquire assets contributing an estimated $1.4 billion of annual EBITDA. The first drop of assets contributing approximately $250 million of annual EBITDA took place in the first quarter of 2017 and was financed through cash and equity, as discussed in Note 3 of the Notes to Consolidated Financial Statements. MPLX LP anticipates completing the second of several strategic acquisitions in the third quarter with the offer of joint-interest ownership in certain pipelines and storage facilities from MPC. These assets are projected to generate approximately $135 million of EBITDA. MPC has indicated work remains on schedule to prepare the remaining assets contributing annual EBITDA of approximately $1.0 billion for dropdown no later than the end of the first quarter of 2018. The Partnership's plans for funding these dropdowns would likely include debt and equity in approximately equal proportions, with the equity financing to be funded through transactions with MPC. In addition to the expected dropdowns,

MPC announced its intentions to offer to exchange its IDRs for common units in conjunction with the completion of the dropdowns. Following these transactions, we expect to internally fund a greater portion of our future growth from internal cash flows.

Capital Expenditures

Our operations are capital intensive, requiring investments to expand, upgrade, enhance or maintain existing operations and to meet environmental and operational regulations. Our capital requirements consist of maintenance capital expenditures and growth capital expenditures. Examples of maintenance capital expenditures are those made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. In contrast, growth capital expenditures are those incurred for acquisitions or capital improvements that we expect will increase our operating capacity to increase volumes gathered, processed, transported or fractionated, decrease operating expenses within our facilities or increase operating income over the long term. Examples of growth capital expenditures include the acquisition of equipment or the construction costs associated with new well connections, and the development or acquisition of additional pipeline, processing or storage capacity. In general, growth capital includes costs that are expected to generate additional or new cash flow for us.

Our capital expenditures are shown in the table below:


	Six months ended June 30,					Six Months Ended June 30,
(In millions)	2016			2015		2017		2016
Capital expenditures:
Maintenance	$	31		$	8	$	35	$	35
Expansion	533			75		651		566
Total capital expenditures	564			83		686		601
Less: (Decrease) increase in capital accruals	(7		)	13
Less: Increase (decrease) in capital accruals						33		(7		)
Asset retirement expenditures	2			—		1		2
Additions to property, plant and equipment	569			70		652		606
Capital expenditures of unconsolidated subsidiaries⁽¹⁾	60			—		205		60
Total gross capital expenditures	629			70		857		666
Less: Joint venture partner contributions⁽²⁾	29			—		93		29
Total gross capital expenditures, net	$	600		$	70
Total capital expenditures, net						764		637
Less: Maintenance capital						36		35
Total growth capital						$	728	$	602


(1)	Includes amounts related to unconsolidated, ~~Partnership operated~~Partnership-operated subsidiaries.


(2)	This represents estimated joint venture partners’ share of growth capital.

Our organic growth capital plan range for ~~2016 was narrowed~~2017 is $1.8 billion to $2.0 billion, not including the future dropdowns previously discussed, or their respective subsequent capital spending. This range excludes acquisition costs for the dropdowns of HST, WHC and MPLXT, the acquisition of the Ozark pipeline and the MarEn Bakken investment, as discussed in Note 3 of the Notes to Consolidated Financial Statements. The range also excludes non-affiliated joint venture members’ share of capital expenditures. The G&P segment capital plan includes investments that are expected to support producer customers and complete certain processing plants currently under construction at the Sherwood Complex. The L&S segment capital plan includes the development of various crude oil and refined petroleum products infrastructure projects, including the continued build out of Utica Shale infrastructure in connection with the completed Cornerstone Pipeline, a ~~range~~butane cavern and a tank farm expansion, and an expansion project to increase line capacity on the Ozark pipeline. We also have large organic growth prospects associated with the anticipated growth of ~~$900 million to $1.2 billion.~~MPC’s operations and third-party activity in our areas of operation that we anticipate will provide attractive returns and cash flows. We continuously evaluate our capital plan and make changes as conditions warrant.

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Contractual Cash Obligations

As of June 30, ~~2016,~~2017, our contractual cash obligations included long-term debt, capital and operating lease obligations, purchase obligations for services and to acquire property, plant and equipment, and other liabilities. During the six months ended June 30, ~~2016,~~2017, our ~~bank revolving credit facility committed payments decreased $953 million~~long-term debt obligations increased by $4.2 billion due to the ~~repayment of the bank revolving credit facility~~new senior notes issued and contracts to acquire property, plant and equipment increased ~~$46~~$213 million largely due to ~~the spending associated with various~~new and growing projects. There were no other material changes to these obligations outside the ordinary course of business since December 31, ~~2015.~~2016.

Off-Balance Sheet Arrangements

As of June 30, ~~2016,~~2017, we have not entered into any transactions, agreements or other arrangements that would result in off-balance sheet liabilities.

Forward-looking Statements

Our opinions concerning liquidity and capital resources ~~including~~and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors, including cash provided by operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and future credit ratings by rating agencies. The discussion of liquidity and capital resources above also contains forward-looking statements regarding expected capital spending. The forward-looking statements about our capital budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include negative capital market conditions, including an increase of the current yield on common units, adversely affecting the Partnership’s ability to meet its distribution growth guidance; the time, costs and ability to obtain regulatory or other approvals and consents and otherwise consummate the strategic initiatives discussed herein and other proposed transactions; the satisfaction or waiver of conditions in the agreements governing the strategic initiatives discussed herein and other proposed transactions; our ability to achieve the strategic and other objectives related to the strategic initiatives and transactions discussed herein, including the dropdowns proposed by MPC, the joint venture with Antero Midstream Partners LP, the Ozark pipeline acquisition, and other proposed transactions; adverse changes in laws including with respect to tax and regulatory matters; the inability to agree with respect to the timing of and value attributed to assets identified for dropdown; the adequacy of the Partnership’s capital resources and liquidity, including, but not limited to, availability of sufficient cash flow to pay distributions, and the ability to successfully execute its business plans and growth strategy; continued/further volatility in and/or degradation of market and industry conditions; changes to the expected construction costs and timing of projects; civil protests and resulting legal/regulatory uncertainty regarding environmental and social issues, including pipeline infrastructure, may prevent or delay the construction and operation of such infrastructure and realization of associated revenues; completion of midstream infrastructure by competitors; disruptions due to equipment interruption or failure, including electrical shortages and power grid failures; the suspension, reduction or termination of MPC's obligations under the Partnership’s commercial agreements; modifications to earnings and distribution growth objectives; the level of support from MPC, including dropdowns, alternative financing arrangements, taking equity units, and other methods of sponsor support, as a result of the capital allocation needs of the enterprise as a whole and its ability to provide support on commercially reasonable terms; compliance with federal and state environmental, economic, health and safety, energy and other policies and regulations and/or enforcement actions initiated thereunder; changes to the Partnership’s capital budget; prices of and demand for natural gas, NGLs, crude oil and refined ~~petroleum products, actions of competitors,~~products; delays in obtaining necessary third-party approvals and governmental permits; changes in labor, material and equipment costs and ~~availability,~~availability; planned and unplanned outages, the delay of, cancellation of or failure to implement planned capital ~~projects,~~projects; project overruns, disruptions or interruptions of our operations due to the shortage of skilled ~~labor and~~labor; unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military ~~response,~~response; and other operating and economic considerations. These factors, among others, could cause actual results to differ materially from those set forth in the forward-looking statements. For additional information on forward-looking statements and risks that can affect our business, see “Disclosures Regarding Forward-Looking Statements” and Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2016.

TRANSACTIONS WITH RELATED PARTIES

At June 30, ~~2016,~~2017, MPC held a two percent ~~general partner interest~~GP Interest and a ~~22.9~~25.2 percent limited partner interest (including the Class B units on an as-converted basis) in MPLX LP.

Excluding revenues attributable to volumes shipped by MPC under joint tariffs with third parties that are treated as third-party revenues for accounting purposes, MPC accounted for 3438 percent and 9247 percent of our total revenues and other income for the second quarter of ~~2016~~2017 and ~~2015, respectively. MPC accounted for 33 percent and 91 percent of our total revenues and other income for the first six months of~~ 2016, ~~and 2015,~~ respectively. We provide to MPC crude oil and product pipeline transportation services based on regulated tariff rates and storage services and inland marine transportation based on contracted rates.

Of our total costs and expenses, MPC accounted for 2123 percent and 4524 percent for the second quarter of ~~2016~~2017 and ~~2015, respectively, and 20 percent and 45 percent for the first six months of~~ 2016, ~~and 2015,~~ respectively. MPC performed certain services for us related to information technology, engineering, legal, accounting, treasury, human resources and other administrative services.

We believe that transactions with related parties ~~have been~~were conducted under terms comparable to those with unrelated parties. For further discussion of agreements and activity with MPC and related parties see Item 1. Business in our Annual Report on Form 10-K for the year ended December 31, ~~2015, as updated by our Current Report on Form 8-K/A filed on May 20,~~ 2016 and Note 5 of the Notes to Consolidated Financial Statements in this report.

~~OPERATIONAL CONSIDERATIONS~~

On June 22, 2016, we determined that a slip had occurred on a section of right of way involving our ethane and NGL pipelines near our Sherwood Processing Facility in Doddridge County, West Virginia. During the second quarter of 2016, we incurred approximately $1 million in operating expenses, and we estimate that we will incur an additional $1 million to resolve this issue.

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On June 24, 2016, our Cobb Processing Facility in Kanawha County, West Virginia experienced flooding due to heavy rains. As of June 30, 2016, we have yet to incur any expense to repair the facility; however, total spend is expected to be approximately $1 million.

ENVIRONMENTAL MATTERS AND COMPLIANCE COSTS

We have incurred and may continue to incur substantial capital, operating and maintenance, and remediation expenditures as a result of environmental laws and regulations. If these expenditures, as with all costs, are not ultimately reflected in the prices of our products and services, our operating results will be adversely affected. We believe that substantially all of our competitors must comply with similar environmental laws and regulations. However, the specific impact on each competitor may vary depending on a number of factors, including, but not limited to, the age and location of its operating facilities.

In February 2016, we identified a release of heat transfer oil at our Mobley gas processing facility in Wetzel County, West Virginia. During the six months ended June 30, 2016, we incurred approximately $6 million in remediation expenses and we estimate that there will be no material incremental charges. There were no expenses incurred during the three months ended June 30, 2016. This incident has been submitted to our insurance carriers.

On April 17, 2016, a release of diesel fuel was discovered near Crawleyville, Indiana from our pipeline that transports products from Robinson, Illinois to Mount Vernon, Indiana. The estimated volume of the release is 1,150 barrels. During the second quarter of 2016, we incurred approximately $2 million in remediation expenses, and we do not anticipate that there will be any material incremental costs incurred in connection with this matter. We have submitted this incident to our insurers.

As of June 30, ~~2016,~~2017, there have been no significant changes ~~(except the incident discussed above)~~ to our environmental matters and compliance costs since our Annual Report on Form 10-K for the year ended December 31, ~~2015,~~2016, as updated by our Current Report on Form ~~8-K/A~~8-K filed on May ~~20, 2016.~~1, 2017.

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CRITICAL ACCOUNTING ESTIMATES

As of June 30, ~~2016,~~2017, there have been no significant changes to our critical accounting estimates since our Annual Report on Form 10-K for the year ended December 31, ~~2015,~~2016, as updated by our Current Report on Form ~~8-K/A~~8-K filed on May 20, 2016, except as noted below. Equity method investments are assessed for impairment whenever factors indicate an other than temporary loss in value. In the second quarter of 2016, MPLX also considered whether there was any indication of impairment of equity method investments recorded in connection with the MarkWest Merger and determined that there were none, other than the impairment recorded related to our investment in Ohio Condensate Company.



~~Description~~	~~Judgments and Uncertainties~~	~~Effect if Actual Results Differ from~~ ~~Estimates and Assumptions~~
~~Impairment of Long-Lived Assets~~
Management evaluates our long-lived assets, including intangibles, for impairment when certain events have taken place that indicate that the carrying value may not be recoverable from the expected undiscounted future cash flows. Qualitative and quantitative information is reviewed in order to determine if a triggering event has occurred or if an impairment indicator exists. If we determine that a triggering event has occurred we would complete a full impairment analysis. If we determine that the carrying value of an asset grouping is not recoverable, a loss is recorded for the difference between the fair value and the carrying value. We evaluate our property, plant and equipment and intangibles on at least a segment level and at lower levels where cash flows for specific assets can be identified, which generally is the plant level for our G&P segment, the pipeline system level for our L&S segment, and the customer relationship for our customer contract intangibles.	Management considers the volume of reserves dedicated to be processed by the asset and future NGL product and natural gas prices to estimate cash flows for each asset group. Management considers the expected net operating margin to be earned by customers for each customer contract intangible. Management uses discount rates commensurate with the risks involved for each asset considered. The amount of additional reserves developed by future drilling activity and expected net operating margin earned by customer depends, in part, on expected commodity prices. Projections of reserves, drilling activity, ability to renew contracts of significant customers, and future commodity prices are inherently subjective and contingent upon a number of variable factors, many of which are difficult to forecast. Management considered the sustained reduction of commodity prices in forecasted cash flows.	As of December 31, 2015, there were no indicators of impairment for any of our long-lived assets. A significant variance in any of the assumptions or factors used to estimate future cash flows could result in the impairment of an asset.

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~~Description~~	~~Judgments and Uncertainties~~	~~Effect if Actual Results Differ from~~ ~~Estimates and Assumptions~~
~~Impairment of Goodwill~~
Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate 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 first step of the evaluation is a qualitative analysis to determine if it is “more likely than not” that the carrying value of a reporting unit with goodwill exceeds its fair value. The additional quantitative steps in the goodwill impairment test may be performed if we determine that it is more likely than not that the carrying value is greater than the fair value.	Management performed a quantitative analysis during the first quarter of 2016, and determined the fair value of our reporting units in both the G&P and L&S segments using the income and market approaches for our first quarter 2016 impairment analysis. Management performed a qualitative analysis during the second quarter of 2016 and concluded that there were no indicators that would cause us to proceed to a quantitative analysis for the second quarter. These types of analyses require us to make assumptions and estimates regarding industry and economic factors such as relevant commodity prices, contract renewals, and production volumes. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations. Management is also required to make certain assumptions when identifying the reporting units and determining the amount of goodwill allocated to each reporting unit. The method of allocating goodwill resulting from the acquisitions involved estimating the fair value of the reporting units and allocating the purchase price for each acquisition to each reporting unit. Goodwill is then calculated for each reporting unit as the excess of the allocated purchase price over the estimated fair value of the net assets.	During the first quarter of 2016, we determined that an interim impairment analysis of the goodwill recorded in connection with the MarkWest Merger was necessary based on consideration of a number of first quarter events and circumstances, including i) continued deterioration of near term commodity prices as well as longer term pricing trends, ii) recent guidance on reductions to forecasted capital spending, the slowing of drilling activity and the resulting reduced production growth forecasts released or communicated by our producer customers and iii) increases in cost of capital. The combination of these factors was considered to be a triggering event requiring an interim impairment test. Based on the first step of the interim goodwill impairment analysis, the fair value for the three reporting units to which goodwill was assigned in connection with the merger was less than the respective carrying value. In step two of the impairment analysis, the implied fair values of the goodwill were compared to the carrying values within those reporting units. Based on this assessment, it was determined that goodwill was impaired in two of the three reporting units. Accordingly, we recorded an impairment charge of approximately $129 million in the first quarter of 2016. The fair value of the reporting units for the interim goodwill impairment analysis was determined based on applying the discounted cash flow method, which is an income approach, and the guideline public company method, which is a market approach. The discounted cash flow fair value estimate is based on known or knowable information at the interim measurement date. The significant assumptions that were used to develop the estimates of the fair values under the discounted cash flow method include management’s best estimates of the expected future results and discount rates, which range from 10.5 percent to 11.5 percent. 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 11.5 percent to 12.8 percent. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the first quarter interim goodwill impairment test will prove to be an accurate prediction of the future. We did not record an impairment charge in the Marcellus reporting unit within the G&P segment, which is the only other reporting unit within the G&P segment that has assigned goodwill. As of March 31, 2016, our allocation of the purchase price was provisional. Based on our assessment as of that date, the Marcellus reporting unit had $1,814 million of goodwill assigned to it (which amount was not adjusted as of June 30, 2016 when we finalized our purchase price allocation). Step 1 of the first quarter 2016 interim impairment analysis resulted in the carrying value of the Marcellus reporting unit exceeding its fair value by 0.62%; therefore, we completed Step 2 of the goodwill impairment analysis. Step 2 of the goodwill impairment analysis requires us to determine the fair value of all assets, liabilities and noncontrolling interests, if any, of the reporting unit, whether or not currently recognized. The implied fair value of goodwill is the residual value of the reporting unit's fair value, less the fair value of the assets, liabilities and noncontrolling interests, if any. The results of our Step 2 first quarter 2016 interim impairment analysis concluded that the fair value of the goodwill of the Marcellus reporting unit exceeded its carrying value of $1,814 million by approximately $20 million, or 1.2%. An increase of 0.50% to the discount rate used to estimate Marcellus' fair value as of the first quarter 2016 interim impairment analysis would have resulted in an additional goodwill impairment charge of more than $400 million for the three months ended March 31, 2016. The other significant assumption used to estimate the Marcellus reporting unit's fair value included estimates of future cash flows. If estimates for future cash flows, which are impacted primarily by commodity prices and producers' production plans, for this reporting unit were to decline, the overall reporting unit's fair value would decrease, resulting in a potential goodwill impairment charge. Additionally, an increase in the cost of capital would result in a decrease in the fair value of the Marcellus reporting unit, causing its value to decline and goodwill to potentially be impaired. During the second quarter of 2016, we determined that an interim impairment analysis of the goodwill recorded in connection with the MarkWest Merger was not necessary. The stabilization or improvement in the second quarter of the circumstances considered during our first quarter impairment analysis, the date of our last full goodwill impairment analysis, lead to our conclusion that it is not more likely than not that the fair value of our reporting units is less than their respective carrying values. In the second quarter of 2016, we completed our purchase price accounting for the MarkWest Merger. The completion of this accounting resulted in additional goodwill attributed to the reporting units for which an impairment charge had been taken in the first quarter of 2016. We therefore recorded an additional $1 million of impairment expense in the second quarter of 2016.

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~~Description~~	~~Judgments and Uncertainties~~	~~Effect if Actual Results Differ from~~ ~~Estimates and Assumptions~~
~~Impairment of Equity Method Investments~~
We evaluate our equity method investments for impairment whenever events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced a decline in value. When evidence of an other-than-temporary loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment should be recorded.	Our impairment assessment requires us to apply judgment in estimating future cash flows received from or attributable to our equity method investments. The primary estimates may include the expected volumes, the terms of related customer agreements and future commodity prices.	Our equity method investments were recorded at fair value in connection with the MarkWest Merger on December 4, 2015. If expected cash flows used to determine the fair value as of December 4, 2015 are not realized our equity method investments may be subject to future impairment charges. Based on a review of cash flow forecasts as of the second quarter of 2016, we have concluded that no indicators of an other than temporary impairment exist except for Ohio Condensate. During the second quarter of 2016, forecasts for Ohio Condensate were reduced to align with updated forecasts for customer requirements. As the operator of that entity responsible for maintaining its financial records, we completed a fixed asset impairment analysis as of June 30, 2016, in accordance with ASC Topic 360, to determine the potential fixed asset impairment charge. The resulting fixed asset impairment charge recorded within Ohio Condensate’s financial statements was $96 million. Based on the Partnership’s 60% ownership of Ohio Condensate, approximately $58 million was recorded in the second quarter of 2016 in ~~Loss from equity method investments~~ on the accompanying Consolidated Statements of Income. The Partnership’s investment in Ohio Condensate, which was established at fair value in connection with the MarkWest Merger, exceeded its proportionate share of the underlying net assets. Therefore, in conjunction with the ASC Topic 360 analysis, we completed an equity method impairment analysis in accordance with ASC Topic 323 to determine the potential additional equity method impairment charge to be recorded on our consolidated financial statements resulting from an other-than-temporary impairment. As a result, an additional impairment charge of approximately $31 million was recorded in the second quarter of 2016 in ~~Loss from equity method investments~~ ~~on the accompanying Consolidated Statements of Income, which eliminated the basis differential established in connection with the MarkWest Merger.~~ The fair value of Ohio Condensate and its underlying fixed assets was determined based upon applying the discounted cash flow method, which is an income approach, and the guideline public company method, which is a market approach. The discounted cash flow fair value estimate is based on known or knowable information at the interim measurement date. The significant assumptions that were used to develop the estimate of the fair value under the discounted cash flow method include management’s best estimates of the expected future results using a probability weighted average set of cash flow forecasts and a discount rate of 11.2%. An increase to the discount rate of 50 basis points would have resulted in an additional charge of $1 million on our Consolidated Statements of Income. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As such, the fair value of the Ohio Condensate equity method investment and its underlying fixed assets represents a Level 3 measurement. As a result, there can be no assurance that the estimates and assumptions made for purposes of the interim impairment test will prove to be an accurate prediction of the future.

1, 2017.

ACCOUNTING STANDARDS NOT YET ADOPTED

As discussed in Note 2 of the Notes to Consolidated Financial Statements, certain new financial accounting pronouncements will be effective for our financial statements in the future.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity price changes and, to a lesser extent, interest rate changes and non-performance by our customers and counterparties.

Commodity Price Risk

The information about commodity price risk for the three and six months ended June 30, ~~2016~~2017 does not differ materially from that discussed in Item 7A. Quantitative and Qualitative Disclosures about Market Risk of our Annual Report on Form 10-K for the year ended December 31, ~~2015, as updated by our Current Report on Form 8-K/A filed on May 20,~~ 2016.

Outstanding Derivative Contracts

The following tables provide information on the volume of our derivative activity for positions related to long liquids price risk at June 30, ~~2016,~~2017, including the weighted-average prices (“WAVG”):


WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)		Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2016 (Jul - Dec)	1,000	$	52.17	$	407
2017 (Jul - Dec)						199	$	54.25	$	275

Ethane Swaps Volumes (Gal/d) WAVG Price (Per Gal) Fair Value (in thousands)
2016 (Jul - Dec) 54,600
$ 0.23
$ (260 )



Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2017 (Jul - Dec)	1,821	$	3.03	$	(47	)
2018	2,536	$	2.78	$	(64	)

Propane Swaps Volumes (Gal/d) WAVG Price (Per Gal) Fair Value (in thousands)
2016 (Jul - Dec) 75,600
$ 0.43
$ (1,639 )



Ethane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2017 (Jul - Dec)	54,305	$	0.27	$	114

IsoButane Swaps Volumes (Gal/d) WAVG Price (Per Gal) Fair Value (in thousands)
2016 (Jul - Dec) 16,658
$ 0.59
$ (353 )



Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2017 (Jul - Dec)	124,888	$	0.62	$	34
2018	16,879	$	0.64	$	483

Normal Butane Swaps Volumes (Gal/d) WAVG Price (Per Gal) Fair Value (in thousands)
2016 (Jul - Dec) 12,600
$ 0.53
$ (396 )



IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2017 (Jul - Dec)	10,658	$	0.81	$	122
2018	1,650	$	0.80	$	68

Natural Gasoline Swaps Volumes (Gal/d) WAVG Price (Per Gal) Fair Value (in thousands)
2016 (Jul - Dec) 4,200
$ 0.98
$ (22 )

The following tables provide information on the volume of our taxable subsidiary’s commodity derivative activity for positions related to keep-whole and long liquids price risk at June 30, 2016, including the WAVG:



Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2017 (Jul - Dec)	31,408	$	0.75	$	140
2018	4,582	$	0.75	$	190

Natural Gas Swaps Volumes (MMBtu/d) WAVG Price (Per MMBtu) Fair Value (in thousands)
2016 (Jul - Dec) 5,916
$ 2.22
$ 718

Propane Swaps Volumes (Gal/d) WAVG Price (Per Gal) Fair Value (in thousands)
2016 (Jul - Dec) 37,835
$ 0.49
$ (434 )

IsoButane Swaps Volumes (Gal/d) WAVG Price (Per Gal) Fair Value (in thousands)
2016 (Jul - Dec) 4,222
$ 0.59
$ (90 )

Normal Butane Swaps Volumes (Gal/d) WAVG Price (Per Gal) Fair Value (in thousands)
2016 (Jul - Dec) 11,842
$ 0.57
$ (207 )



Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2017 (Jul - Dec)	41,593	$	1.13	$	734
2018	3,081	$	1.18	$	144

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Natural Gasoline Swaps Volumes (Gal/d) WAVG Price (Per Gal) Fair Value (in thousands)
2016 (Jul - Dec) 8,671
$ 0.90
$ (170 )

The following tables provides information on the volume of MarkWest Liberty Midstream’s commodity derivative activity positions related to long liquids price risk at June 30, 2016, including the WAVG:

Propane Swaps Volumes (Gal/d) WAVG Price (Per Gal) Fair Value (in thousands)
2016 (Jul - Dec) 50,400
$ 0.47
$ (725 )

IsoButane Swaps Volumes (Gal/d) WAVG Price (Per Gal) Fair Value (in thousands)
2016 (Jul - Dec) 8,400
$ 0.55
$ (237 )

Normal Butane Swaps Volumes (Gal/d) WAVG Price (Per Gal) Fair Value (in thousands)
2016 (Jul - Dec) 21,000
$ 0.57
$ (336 )

Natural Gasoline Swaps Volumes (Gal/d) WAVG Price (Per Gal) Fair Value (in thousands)
2016 (Jul - Dec) 46,200
$ 0.99
$ (184 )

~~The following table provides information on the derivative positions related to long liquids price risk that we have entered into subsequent to June 30, 2016, including the WAVG:~~

IsoButane Swaps Volumes (Gal/d) WAVG Price (Per Gal)
2017 (Jan - Mar) 4,200
$ 0.65

Normal Butane Swaps Volumes (Gal/d) WAVG Price (Per Gal)
2017 (Jan - Mar) 8,400
$ 0.65

We have 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, we 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 contracts. 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 June 30, ~~2016,~~2017, the estimated fair value of this contract was a liability of ~~$41~~$43 million.

We have a commodity contract that gives us an option to fix a component of the utilities cost to an index price on electricity at a plant location in the Southwest ~~operations~~ through the fourth quarter of ~~2017.~~2018. The ~~contract~~contract’s pricing is currently fixed through the fourth quarter of ~~2016~~2017 with the ability to fix the ~~commodity contract~~pricing for its remaining year. Changes in the fair value as of the derivative component of this contract were recognized as Cost of ~~revenues~~Revenues in the Consolidated Statements of Income. As of June 30, ~~2016,~~2017, the estimated fair value of this contract was ~~an asset~~a liability of less than $1 million.

~~Table of Contents~~

Interest Rate Risk

Sensitivity analysis of the effect of a hypothetical 100-basis-point change in interest rates on long-term debt, excluding capital leases, is provided in the following table. Fair value of cash and cash equivalents, receivables, accounts payable and accrued interest approximate carrying value and are relatively insensitive to changes in interest rates due to the short-term maturity of the instruments. Accordingly, these instruments are excluded from the table.


(In millions)	Fair Value as of June 30, 2016⁽¹⁾		Change in Fair Value ⁽²⁾		Change in Income Before Income Taxes for the Six Months Ended June 30, 2016 ⁽³⁾		Fair value as of June 30, 2017⁽¹⁾		Change in Fair Value⁽²⁾		Change in Income Before Income Taxes for the Six Months Ended June 30, 2017⁽³⁾
Long-term debt
Fixed-rate	$	4,498	$	305	n/a		$	7,112	$	577	N/A
Variable-rate	$	250	n/a		$	4	$	250	N/A		$	1


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


(2)	Assumes a 100-basis-point decrease in the weighted average yield-to-maturity at June 30, ~~2016.~~2017.


(3)	Assumes a 100-basis-point change in interest rates. The change to net income was based on the weighted average balance of all outstanding variable-rate debt for the six months ended June 30, ~~2016.~~2017.

At June 30, ~~2016,~~2017, our portfolio of long-term debt consisted of fixed-rate instruments and variable-rate instruments under our term loan facility. The fair value of our fixed-rate debt is relatively sensitive to interest rate fluctuations. Our sensitivity to interest rate declines and corresponding increases in the fair value of our debt portfolio unfavorably affects our results of operations and cash flows only when we elect to repurchase or otherwise retire fixed-rate debt at prices above carrying value. Interest rate fluctuations generally do not impact the fair value of borrowings under our bank revolving credit or term loan ~~facility,~~facilities, but may affect our results of operations and cash flows. As of June 30, ~~2016,~~2017, we did not have any financial derivative instruments to hedge the risks related to interest rate fluctuations; however, we continually monitor the market and our exposure and may enter into these agreements in the future.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

An evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) under the Securities Exchange Act of 1934, as amended) was carried out under the supervision and with the participation of management, including the chief executive officer and chief financial officer of our general partner. Based upon that evaluation, the chief executive officer and chief financial officer of our general partner concluded that the design and operation of these disclosure controls and procedures were effective as of June 30, ~~2016~~2017, the end of the period covered by this report.

Changes in Internal Control Over Financial Reporting

During the quarter ended June 30, ~~2016,~~2017, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

6863

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Part II – Other Information

Item 1. Legal Proceedings

We are the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. ~~Specific matters discussed below are either new proceedings or material developments in proceedings previously reported.~~

~~Litigation~~

We are a party to a number of lawsuits and other proceedings and cannot predict the outcome of every such matter with certainty. While it is possible that an adverse result in one or more of the lawsuits or proceedings in which we are a defendant could be material to us, based upon current information and our experience as a defendant in other matters, we believe that these lawsuits and proceedings, individually or in the aggregate, will not have a material adverse effect on our consolidated results of operations, financial position or cash flows.

As reported in our Annual Report on Form 10-K for the year ended December 31, 2015, as updated by our Current Report on Form 8-K/A filed on May 20, 2016, 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 purported 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, 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 the MarkWest GP Board, MPLX, MPLX GP, MPC and Sapphire Holdco LLC, a wholly-owned subsidiary of MPLX, asserting in connection with the MarkWest Merger and related disclosures that, among other things, (i) the MarkWest GP Board breached its duties in approving the MarkWest Merger with MPLX and (ii) MPC, MPLX, MPLX GP, and Sapphire Holdco LLC aided and abetted such breaches. On February 4, 2016, the Court approved a stipulation and proposed order to dismiss all claims with prejudice as to the named plaintiffs, but the Court retained jurisdiction to adjudicate an application for a mootness fee by the plaintiffs’ counsel for an award of attorneys’ fees and reimbursement of expenses. On March 28, 2016, the plaintiffs filed an application for reimbursement of approximately $2 million of legal fees and expenses. On May 17, 2016, the plaintiffs withdrew the fee application and the case is now dismissed.

~~Environmental Proceedings~~

On May 18, 2016, MarkWest Liberty Midstream received a draft Consent Order (“Consent Order”) from the West Virginia Department of Environmental Protection (“WVDEP”) alleging certain air permitting and emissions violations at our Sherwood Facility, a gas processing facility located in West Virginia, including failure to comply with monitoring, tagging, recordkeeping and repair requirements with respect to certain equipment at the facility as well as the failure to comply with certain permit application requirements. The Consent Order sets forth a proposed civil penalty of $425,000.

The Illinois Environmental Protection Agency (“IEPA”) initiated an enforcement action against Marathon Pipe Line LLC (“MPL”), in connection with an April 17, 2016 pipeline release to the Wabash River near Crawleyville, Indiana. MPL also received a Clean Water Act request for information from the EPA in furtherance of its investigation of possible violations arising from the April 17, 2016 pipeline release. The IEPA and the EPA may each seek penalties in excess of $100,000 in connection with this matter.

As previously reported, in July 2015, representatives 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 a magistrate of the United States District Court for the Western District of Pennsylvania. MarkWest Liberty Midstream has provided information in response to subpoenas presented by the government and similar requests for information from the EPA, state and other agencies related to MarkWest's pipeline and compressor stations located in Pennsylvania. The Partnership is engaged in ongoing discussions with EPA and the U.S. Attorney’s office regarding alleged omissions associated with permits or related regulatory obligations for its launcher/receiver facilities in the region. MarkWest Liberty Midstream’s internal review has determined that its operations have been conducted consistent with industry practices and in a manner protective of its employees and the public. It is possible however, that in connection with any potential or asserted 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 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 or determined at this time.

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

Item 1A. Risk Factors

We are subject to various risks and uncertainties in the course of our business. The discussion of such risks and uncertainties may be found under Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, ~~2015, as updated by our Current Report on Form 8-K/A filed on May 20, 2016, and under Item 1A. Risk Factors in our Quarterly Report on Form 10-Q for the period ended March 31,~~ 2016.

7064

~~Table of Contents~~

Item 2. Unregistered Sales of Equity Securities

In connection with ~~2,913~~the issuance of 69,159 common units ~~issued~~ upon the ~~settlement of performance units and~~ vesting of phantom units under the MPLX LP 2012 Incentive Compensation Plan and ~~22,534,002~~8,511,405 common units ~~issued pursuant to~~under the ~~acquisition of HSM,~~ATM Program, our general partner purchased an aggregate of ~~459,938~~175,113 general partner units for ~~$12 million~~a total of $5,928,325.51 in cash during the three months ended June 30, ~~2016,~~2017, to maintain its two percent general partner interest in us.

The general partner units were issued in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended.

7165

~~Table of Contents~~

Item 6. Exhibits

Incorporated by Reference
Exhibit
Number
Exhibit Description Form Exhibit Filing Date SEC File No.
Filed
Herewith

Furnished
Herewith
2.1 Membership Interests Contribution Agreement, dated March 14, 2016, between MPLX LP, MPLX Logistics Holdings LLC, MPLX GP LLC and MPC Investment LLC 8-K 2.1
3/17/2016 001-35714
3.1 Certificate of Limited Partnership of MPLX LP S-1 3.1
7/2/2012 333-182500
3.2 Amendment to the Certificate of Limited Partnership of MPLX LP S-1/A 3.2
10/9/2012 333-182500
3.4 Second Amended and Restated Agreement of Limited Partnership of MPLX LP, dated as of May 13, 2016 8-K 3.1
5/16/2016 001-35714
4.1 Registration Rights Agreement, dated as of May 13, 2016, by and between MPLX LP and the Purchasers party thereto 8-K 4.1
5/16/2016 001-35714
10.1 First Amendment to Employee Services Agreement, dated May 10, 2016, by and between Marathon Petroleum Logistics Services LLC, MPLX GP LLC and Marathon Pipe Line LLC X
10.2 First Amendment to Amended and Restated Transportation Services Agreement, effective as of April 1, 2016, by and between Marathon Petroleum Company LP and Hardin Street Marine LLC X
10.3 Series A Preferred Unit Purchase Agreement, dated as of April 27, 2016, by and among MPLX LP and the Purchasers party thereto 8-K 10.1
4/29/2016 001-35714
31.1 Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934 X
31.2 Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934 X
32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350 X
32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350 X
101.INS XBRL Instance Document X
101.SCH XBRL Taxonomy Extension Schema X
101.CAL XBRL Taxonomy Extension Calculation Linkbase X
101.DEF XBRL Taxonomy Extension Definition Linkbase X

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

Filed

Herewith

Furnished

Herewith

3.1

Certificate of Limited Partnership of MPLX LP

S-1

3.1

7/2/2012

333-182500

3.2

Amendment to the Certificate of Limited Partnership of MPLX LP

S-1/A

3.2

10/9/2012

333-182500

3.3

Third Amended and Restated Agreement of Limited Partnership of MPLX LP, dated as of October 31, 2016

10-Q

3.3

10/31/2016

001-35714

3.4

First Amendment to Third Amended and Restated Agreement of Limited Partnership of MPLX LP, dated as of February 23, 2017

10-K

3.4

2/24/2017

001-35714

10.1

Form of MPLX LP Phantom Unit Award Agreement - Officer, Cliff Vesting

31.1

Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934

31.2

Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934

32.1

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350

32.2

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema

101.CAL

XBRL Taxonomy Extension Calculation Linkbase

101.DEF

XBRL Taxonomy Extension Definition Linkbase

101.LAB

XBRL Taxonomy Extension Label Linkbase

101.PRE

XBRL Taxonomy Extension Presentation Linkbase

~~Table of Contents~~

~~Incorporated by Reference~~

~~Exhibit~~

~~Number~~

~~Exhibit Description~~

~~Form~~

~~Exhibit~~

~~Filing Date~~

~~SEC File No.~~

~~Filed~~

~~Herewith~~

~~Furnished~~

~~Herewith~~

~~101.LAB~~

~~XBRL Taxonomy Extension Label Linkbase~~

~~101.PRE~~

~~XBRL Taxonomy Extension Presentation Linkbase~~

7366

~~Table of Contents~~

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



	MPLX LP

	By:	MPLX GP LLC
		Its general partner

Date: August ~~2, 2016~~3, 2017	By:	/s/ Paula L. Rosson
		Paula L. Rosson
		Senior Vice President and Chief Accounting Officer of MPLX GP LLC (the general partner of MPLX LP)

7467



	Page
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements:
Consolidated Statements of Income (Unaudited)	3
Consolidated Balance Sheets (Unaudited)	4
Consolidated Statements of Cash Flows (Unaudited)	5
Consolidated Statements of Equity (Unaudited)	6
Notes to Consolidated Financial Statements (Unaudited)	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 3. Quantitative and Qualitative Disclosures about Market Risk	6662
Item 4. Controls and Procedures	6863

PART II – OTHER INFORMATION
Item 1. Legal Proceedings	6964
Item 1A. Risk Factors	7064
Item 2. Unregistered Sales of Equity Securities	7165
Item 6. Exhibits	7266
Signatures	7467



(In millions)
Fair value of units issued	$	7,326
Cash	1,230
Paid/payable to MarkWest Class B unitholders	50
Total fair value of consideration transferred	$	8,606



(In millions)	As Originally Reported		Adjustments			As Adjusted
Cash and cash equivalents	$	12	$	—		$	12
Receivables	164		—			164
Inventories	33		(1		)	32
Other current assets	44		—			44
Equity method investments	2,457		143			2,600
Property, plant and equipment	8,474		43			8,517
Intangibles	468		65			533
Other noncurrent assets	5		—			5
Total assets acquired	11,657		250			11,907
Accounts payable	322		—			322
Accrued liabilities	13		6			19
Accrued taxes	21		—			21
Other current liabilities	44		—			44
Long-term debt	4,567		—			4,567
Deferred income taxes	374		3			377
Deferred credits and other liabilities	151		—			151
Noncontrolling interest	13		—			13
Total liabilities and noncontrolling interest assumed	5,505		9			5,514
Net assets acquired excluding goodwill	6,152		241			6,393
Goodwill	2,454		(241		)	2,213
Net assets acquired	$	8,606	$	—		$	8,606



	Six Months Ended June 30, 2016
(In millions)	MarkWest Utica EMG ⁽¹⁾		Ohio Condensate			Other VIEs		Non-VIEs		Total
Revenue	$	113	$	10		$	—	$	68	$	191
Gross margin	113		10			—		32		155
Income (loss) from operations	68		(94		)	—		18		(8		)
Net income (loss)	68		(94		)	—		18		(8		)
Income (loss) from equity method investments⁽²⁾	7		(88		)	—		3		(78		)



(In millions)	Redeemable Preferred Units
Issuance of MPLX LP redeemable preferred units on May 13, 2016	$	984
Net income allocated for May 13, 2016 through June 30, 2016	9
Balance at June 30, 2016	$	993



(In millions)	MarkWest Hydrocarbon			Partnership			Eliminations			Consolidated⁽¹⁾
Income before (benefit) provision for income tax	$	(35	)	$	4		$	2		$	(29	)
Federal statutory rate	35		%	—		%	—		%
Federal income tax at statutory rate⁽²⁾	(12		)	—			—			(12		)
Change in state statutory rate	(1		)	—			—			(1		)
State income taxes net of federal benefit - MarkWest Hydrocarbon	(1		)	—			—			(1		)
Provision on income from Class A units⁽²⁾	—			—			—			—
Other	1			1			—			2
(Benefit) provision for income tax	$	(13	)	$	1		$	—		$	(12	)



(In millions)	L&S		G&P			Total
Gross goodwill as of December 31, 2015	$	116	$	2,454		$	2,570
Accumulated impairment losses	—		—			—
Balance as of December 31, 2015	116		2,454			2,570
Purchase price allocation adjustments⁽¹⁾	—		(241		)	(241		)
Impairment losses	—		(130		)	(130		)
Balance as of June 30, 2016	$	116	$	2,083		$	2,199

Gross goodwill as of June 30, 2016	$	116	$	2,213		$	2,329
Accumulated impairment losses	—		(130		)	(130		)
Balance as of June 30, 2016	$	116	$	2,083		$	2,199