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 September 30, 2017

OR

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

For the transition period from to

Commission file number 001-35714

_____________________________________________ 

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) 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, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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 407,066,320 common units and 8,307,473 general partner units outstanding at October 27, 2017.

MPLX LP

Form 10-Q

Quarter Ended September 30, 2017

INDEX

	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	43
Item 3.   Quantitative and Qualitative Disclosures about Market Risk	65
Item 4.   Controls and Procedures	66
PART II – OTHER INFORMATION
Item 1.    Legal Proceedings	67
Item 1A. Risk Factors	67
Item 2.    Unregistered Sales of Equity Securities	68
Item 5. Other Information	68
Item 6.    Exhibits	70
Signatures	72

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, L.L.C. (“MarkWest Hydrocarbon”), MarkWest Pioneer, L.L.C. (“MarkWest Pioneer”), MPLX Pipe Line Holdings LLC (“Pipe Line Holdings”), 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 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”), 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”), Guilford County Terminal Company, LLC (“Guilford Terminal”), LOOP LLC (“LOOP”), LOCAP LLC (“LOCAP”), Illinois Extension Pipeline Company, L.L.C. (“Illinois Extension”) and Explorer Pipeline Company (“Explorer”). References to “MPC” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other than the Partnership. 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 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.

1

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
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
FASB	Financial Accounting Standards Board
GAAP	Accounting principles generally accepted in the United States of America
Gal	Gallon
Gal/d	Gallons per day
IDR	Incentive distribution right
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/d	One million cubic feet of natural gas per day
Net operating margin (a non-GAAP financial measure)	Segment revenues, less segment purchased product costs, less realized derivative gains (losses) related to purchased product costs
NGL	Natural gas liquids, such as ethane, propane, butanes and natural gasoline
NYSE	New York Stock Exchange
OTC	Over-the-Counter
Partnership Agreement	Third Amended and Restated Agreement of Limited Partnership of MPLX LP, dated as of October 31, 2016, as amended
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	United States 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

2

Part I—Financial Information

Item 1. Financial Statements

MPLX LP

Consolidated Statements of Income (Unaudited)

	Three Months Ended   September 30,				Nine Months Ended   September 30,
(In millions, except per unit data)	2017		2016(1)		2017		2016(1)
Revenues and other income:
Service revenue	$	299	$	250	$	845	$	712
Service revenue - related parties	276		253		801		676
Rental income	69		77		208		218
Rental income - related parties	70		68		207		172
Product sales	217		157		611		394
Product sales - related parties	2		2		6		8
Gain on sale of assets	—		1		1		1
Income (loss) from equity method investments	23		6		29		(72		)
Other income	2		2		5		5
Other income - related parties	22		22		69		67
Total revenues and other income	980		838		2,782		2,181
Costs and expenses:
Cost of revenues (excludes items below)	129		122		381		329
Purchased product costs	170		117		441		310
Rental cost of sales	19		13		44		42
Rental cost of sales - related parties	—		—		1		1
Purchases - related parties	114		109		330		286
Depreciation and amortization	164		151		515		438
Impairment expense	—		—		—		130
General and administrative expenses	59		56		174		172
Other taxes	14		12		40		37
Total costs and expenses	669		580		1,926		1,745
Income from operations	311		258		856		436
Related party interest and other financial costs	1		—		1		1
Interest expense (net of amounts capitalized of $6 million, $7 million, $24 million and $21 million, respectively)	77		51		217		158
Other financial costs	15		13		40		37
Income before income taxes	218		194		598		240
Provision (benefit) for income taxes	1		—		3		(12		)
Net income	217		194		595		252
Less: Net income attributable to noncontrolling interests	1		2		3		3
Less: Net income attributable to Predecessor	—		51		36		149
Net income attributable to MPLX LP	216		141		556		100
Less: Preferred unit distributions	16		16		49		25
Less: General partner’s interest in net income attributable to MPLX LP	86		51		222		136
Limited partners’ interest in net income (loss) attributable to MPLX LP	$	114	$	74	$	285	$	(61	)
Per Unit Data (See Note 6)
Net income (loss) attributable to MPLX LP per limited partner unit:
Common - basic	$	0.29	$	0.22	$	0.75	$	(0.19	)
Common - diluted	0.29		0.21		0.75		(0.19		)
Weighted average limited partner units outstanding:
Common - basic	394		341		378		324
Common - diluted	395		346		381		324
Cash distributions declared per limited partner common unit	$	0.5875	$	0.5150	$	1.6900	$	1.5300

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

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

3

MPLX LP

Consolidated Balance Sheets (Unaudited)

(In millions)	September 30, 2017			December 31, 2016
Assets
Current assets:
Cash and cash equivalents	$	3		$	234
Receivables, net	320			299
Receivables - related parties	152			247
Inventories	64			55
Other current assets	32			33
Total current assets	571			868
Equity method investments	3,997			2,471
Property, plant and equipment, net	11,922			11,408
Intangibles, net	463			492
Goodwill	2,245			2,245
Long-term receivables - related parties	18			11
Other noncurrent assets	22			14
Total assets	$	19,238		$	17,509
Liabilities
Current liabilities:
Accounts payable	$	152		$	140
Accrued liabilities	202			232
Payables - related parties	317			87
Deferred revenue	3			2
Deferred revenue - related parties	42			38
Accrued property, plant and equipment	183			146
Accrued taxes	44			38
Accrued interest payable	64			53
Other current liabilities	41			27
Total current liabilities	1,048			763
Long-term deferred revenue	34			12
Long-term deferred revenue - related parties	40			19
Long-term debt	6,848			4,422
Deferred income taxes	7			6
Deferred credits and other liabilities	175			177
Total liabilities	8,152			5,399
Commitments and contingencies (see Note 17)
Redeemable preferred units	1,000			1,000
Equity
Common unitholders - public (289 million and 271 million units issued and outstanding)	8,457			8,086
Class B unitholders (0 million and 4 million units issued and outstanding)	—			133
Common unitholder - MPC (95 million and 86 million units issued and outstanding)	1,302			1,069
Common unitholder - GP (23 million and 0 units issued and outstanding)	822			—
General partner - MPC (8 million and 7 million units issued and outstanding)	(626		)	1,013
Equity of Predecessor	—			791
Accumulated other comprehensive loss	(14		)	—
Total MPLX LP partners’ capital	9,941			11,092
Noncontrolling interests	145			18
Total equity	10,086			11,110
Total liabilities, preferred units and equity	$	19,238		$	17,509

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

4

MPLX LP

Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended   September 30,
(In millions)	2017			2016(1)
(Decrease) increase in cash and cash equivalents
Operating activities:
Net income	$	595		$	252
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred financing costs	38			34
Depreciation and amortization	515			438
Impairment expense	—			130
Deferred income taxes	2			(16		)
Asset retirement expenditures	(2		)	(4		)
Gain on disposal of assets	(1		)	(1		)
(Income) loss from equity method investments	(29		)	72
Distributions from unconsolidated affiliates	136			111
Changes in:
Current receivables	(20		)	(43		)
Inventories	(3		)	(4		)
Fair value of derivatives	(3		)	28
Current accounts payable and accrued liabilities	6			64
Receivables from / liabilities to related parties	61			(104		)
All other, net	43			18
Net cash provided by operating activities	1,338			975
Investing activities:
Additions to property, plant and equipment	(1,004		)	(943		)
Acquisitions, net of cash acquired	(249		)	—
Disposal of assets	4			—
Investments - net related party loans	80			103
Investments in unconsolidated affiliates	(690		)	(56		)
Distributions from unconsolidated affiliates - return of capital	24			—
All other, net	(2		)	4
Net cash used in investing activities	(1,837		)	(892		)
Financing activities:
Long-term debt - borrowings	2,661			434
- repayments	(251		)	(1,312		)
Related party debt - borrowings	829			2,215
- repayments	(627		)	(2,223		)
Debt issuance costs	(25		)	—
Net proceeds from equity offerings	483			510
Issuance of redeemable preferred units	—			984
Distribution to MPC for acquisition	(1,931		)	—
Distributions to preferred unitholders	(49		)	(9		)
Distributions to unitholders and general partner	(800		)	(612		)
Distributions to noncontrolling interests	(4		)	(3		)
Contributions from noncontrolling interests	128			4
Consideration payment to Class B unitholders	(25		)	(25		)
All other, net	(8		)	(2		)
Contribution from MPC	—			225
Distributions to MPC from Predecessor	(113		)	(104		)
Net cash provided by financing activities	268			82
Net (decrease) increase in cash and cash equivalents	(231		)	165
Cash and cash equivalents at beginning of period	234			43
Cash and cash equivalents at end of period	$	3		$	208

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

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

5

MPLX LP

Consolidated Statements of Equity (Unaudited)

	Partnership
(In millions)	Common Unit-holders Public			Class B Unit-holders Public			Common Unit-holder MPC			Common Unit-holder GP			General  Partner MPC			Accumulated Other Comprehensive Loss			Non-controlling Interests			Equity of Predecessor(1)			Total
Balance at December 31, 2015	$	7,691		$	266		$	465		$	—		$	819		$	—		$	13		$	692		$	9,946
Distributions to MPC from Predecessor	—			—			—			—			—			—			—			(104		)	(104		)
Contribution from MPC	—			—			84			—			141			—			—			—			225
Contribution of MarkWest Hydrocarbon from MPC	—			—			—			—			(188		)	—			—			—			(188		)
Distribution of MarkWest Hydrocarbon to MPC	—			—			—			—			565			—			—			—			565
Issuance of units under ATM Program	499			—			—			—			11			—			—			—			510
Net (loss) income	(51		)	—			(10		)	—			136			—			3			149			227
Allocation of MPC's net investment at acquisition	—			—			669			—			(337		)	—			—			(332		)	—
Distributions to unitholders and general partner	(378		)	—			(98		)	—			(136		)	—			—			—			(612		)
Distributions to noncontrolling interests	—			—			—			—			—			—			(3		)	—			(3		)
Contributions from noncontrolling interests	—			—			—			—			—			—			4			—			4
Class B unit conversion	133			(133		)	—			—			—			—			—			—			—
Non-cash contribution from MPC	—			—			—			—			—			—			—			334			334
Equity-based compensation	6			—			—			—			—			—			—			—			6
Deferred income tax impact from changes in equity	(2		)	—			(13		)	—			(2		)	—			—			—			(17		)
Balance at September 30, 2016	$	7,898		$	133		$	1,097		$	—		$	1,009		$	—		$	17		$	739		$	10,893
Balance at December 31, 2016	$	8,086		$	133		$	1,069		$	—		$	1,013		$	—		$	18		$	791		$	11,110
Distributions to MPC from Predecessor	—			—			—			—			—			—			—			(113		)	(113		)
Distributions of cash received from Joint-Interest Acquisition entities to MPC	—			—			—			—			(13		)	—			—			—			(13		)
Issuance of units under ATM Program	473			—			—			—			10			—			—			—			483
Net income	212			—			68			5			222			—			3			36			546
Contribution from MPC	—			—			—			—			—			(14		)	—			689			675
Allocation of MPC's net investment at acquisition	—			—			845			824			(266		)	—			—			(1,403		)	—
Distribution to MPC for acquisitions	—			—			(537		)	—			(1,394		)	—			—			—			(1,931		)
Distributions to unitholders and general partner	(452		)	—			(143		)	(7		)	(198		)	—			—			—			(800		)
Distributions to noncontrolling interests	—			—			—			—			—			—			(4		)	—			(4		)
Contributions from noncontrolling interests	—			—			—			—			—			—			128			—			128
Class B unit conversion	133			(133		)	—			—			—			—			—			—			—
Equity-based compensation	5			—			—			—			—			—			—			—			5
Balance at September 30, 2017	$	8,457		$	—		$	1,302		$	822		$	(626	)	$	(14	)	$	145		$	—		$	10,086

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

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

6

Notes to Consolidated Financial Statements (Unaudited)

1. Description of the Business and Basis of Presentation

Description of the Business – MPLX LP is a diversified, growth-oriented master limited partnership formed by Marathon Petroleum Corporation. MPLX LP and its subsidiaries (collectively, the “Partnership”) are engaged in the gathering, processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of NGLs; and the transportation, storage and distribution of crude oil and refined petroleum products, principally for our sponsor. References to “MPC” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other than the Partnership.

The Partnership’s business consists of two segments based on the nature of services it offers: Logistics and Storage (“L&S”) which is focused on crude oil and refined petroleum products and Gathering and Processing (“G&P”) which is 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 have been recorded as Noncontrolling 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.

Effective March 1, 2017, the Partnership acquired pipeline, storage and terminal businesses that are operated through Hardin Street Transportation LLC (“HST”), Woodhaven Cavern LLC (“WHC”) and MPLX Terminals LLC (“MPLXT”) (collectively with Hardin Street Marine LLC (“HSM”), “Predecessor”) from MPC. The acquisition from MPC was considered a transfer between entities under common control. Accordingly, the Partnership recorded the 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 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 businesses acquired from MPC prior to the effective dates of the acquisition. See Note 3 for additional information regarding the 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 Predecessor on a historical basis. The financial statements of 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 Predecessor had been operated as an unaffiliated entity.

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 until declared. However, when distributions related to the IDRs 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 nine months ended September 30, 2017 are not necessarily indicative of the results to be expected for the full year.

7

2. Accounting Standards

Recently Adopted

In October 2016, the FASB issued an accounting standards update to amend the consolidation guidance issued in February 2015 to require that a decision maker consider, in the determination of the primary beneficiary, its indirect interest in a VIE held by a related party that is under common control on a proportionate basis only. The change was effective for the financial statements for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. The Partnership was required to apply the standard retrospectively to January 1, 2016, the date on which the Partnership adopted the consolidation guidance issued in February 2015. The Partnership adopted this accounting standards 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 standards 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 standards update in the first quarter of 2017 and it did not have a material impact on the consolidated financial statements.

Not Yet Adopted

In August 2017, the FASB issued an accounting standards update to amend the hedge accounting rules to simplify the application of hedge accounting guidance and better portray the economic results of risk management activities in the financial statements. The guidance expands the ability to hedge nonfinancial and financial risk components, reduces complexity in fair value hedges of interest rate risk, eliminates the requirement to separately measure and report hedge ineffectiveness, as well as eases certain hedge effectiveness assessment requirements. The guidance is effective beginning in 2019 with early adoption permitted. The Partnership is in the process of determining the impact of this guidance, including transition elections and required disclosures, on the consolidated financial statements and the timing of adoption.

In May 2017, the FASB issued an accounting standards 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 Partnership will adopt the new standard on a prospective basis beginning on January 1, 2018. The application of this new accounting standard is not expected to have a material impact on the consolidated financial statements.

In February 2017, the FASB issued an accounting standards 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 of the revenue recognition accounting standards update, which the Partnership will implement January 1, 2018. The Partnership plans to adopt the new standard using the modified retrospective method and does not expect the application of this accounting standards update to have a material impact on the consolidated financial statements.

In January 2017, the FASB issued an accounting standards 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, which could be different from the amount calculated under the current method using the implied fair value of the goodwill; 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 standards update on the consolidated financial statements.

In January 2017, the FASB issued an accounting standards 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

8

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 evaluating this accounting standards update and determining whether it will early adopt.

In November 2016, the FASB issued an accounting standards 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 standards update will not have a material impact on the Consolidated Statements of Cash Flows.

In August 2016, the FASB issued an accounting standards update related to the classification of certain cash flows. The accounting standards update provides specific guidance on eight cash flow classification issues, including debt prepayment or debt extinguishment costs and distributions received from equity method investees, to reduce diversity in practice. 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 Partnership does not expect application of this accounting standards update to have a material impact on the Consolidated Statements of Cash Flows.

In June 2016, the FASB issued an accounting standards 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 standards update to have a material impact on the consolidated financial statements.

In February 2016, the FASB issued an accounting standards update requiring lessees to record virtually all leases on their balance sheets. The accounting standards 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 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 currently evaluating the impact of this standard on the Partnership’s financial statements and disclosures, internal controls and accounting 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 be recognized as a right of use asset and lease obligation. Based on results of the evaluation process to date, the Partnership also believes the impact on existing processes, controls and information systems may be material.

In January 2016, the FASB issued an accounting standards update requiring unconsolidated equity investments, not accounted for under the equity method, to be measured at fair value with changes in fair value recognized in net income. The update also requires the use of the exit price notion when measuring the fair value of financial instruments for disclosure purposes and the separate presentation of financial assets and liabilities by measurement category and form on the balance sheet and accompanying notes. The update eliminates the requirement to disclose the methods and assumptions used in estimating the fair value of financial instruments measured at amortized cost. Lastly, the accounting standards 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. Early adoption is permitted only for guidance regarding presentation of the liability’s credit risk. The Partnership does not expect application of this accounting standards update to have a material impact on the consolidated financial statements.

9

In May 2014, the FASB issued Accounting Standards Update 2014-09 which created Accounting Standards Codification Topic 606, “Revenue from Contracts with Customers” (“ASC 606”). The guidance in 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 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 fiscal years, with early adoption permitted no earlier than January 1, 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 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.

The Partnership is currently evaluating the impact of the revenue recognition standard on its consolidated financial statements and disclosures, internal controls and accounting 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 was completed as of September 30, 2017.

Based on the results of the first phase assessment, the Partnership has reached conclusions for all material contract types. Revenue recognition patterns will not change for fee-based or percent-of-proceeds contracts. The Partnership does expect certain amounts to be grossed up in revenue and cost of revenues as a result of implementation, specifically related to third-party reimbursements from customers and commodities received as consideration in service agreements, such as keep-whole arrangements. In the third quarter of 2017, the Partnership finalized a conclusion on the valuation of non-cash consideration received in the form of a commodity product, with the valuation being performed on the date the service performance obligation is completed.

The Partnership is in the process of finalizing the second phase of implementation, which includes the calculation of the impact of the new standard on results and the development of new policies, procedures and disclosures related to the application upon adoption. The Partnership believes third-party reimbursements included in the transaction price would have resulted in a gross up in 2016 and 2017 service revenue and cost of revenues between $300 million and $350 million annually, with no impact to net income. The Partnership will provide a summary of the total ASC 606 impact in the Annual Report on Form 10-K for the year ended December 31, 2017.

10

3. Acquisitions

Joint-Interest Acquisition

On September 1, 2017, the Partnership entered into a Membership Interests and Shares Contributions Agreement (the “September 2017 Contributions Agreement”) 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, whereby the Partnership agreed to acquire certain ownership interests in joint venture entities indirectly held by MPC. Pursuant to the September 2017 Contributions Agreement, MPC Investment agreed to contribute: all of the membership interests of Lincoln Pipeline LLC, which holds a 35 percent interest in Illinois Extension Pipeline Company, L.L.C. (“Illinois Extension”); all of the membership interests of MPL Louisiana Holdings LLC, which holds a 40.7 percent interest in LOOP LLC (“LOOP”); a 58.52 percent interest in LOCAP LLC (“LOCAP”); and a 24.51 percent interest in Explorer Pipeline Company (“Explorer”), through a series of intercompany contributions to the Partnership for an agreed upon purchase price of approximately $420 million in cash and equity consideration valued at approximately $630 million for total consideration of $1.05 billion (collectively, the “Joint-Interest Acquisition”). The number of common units representing the equity consideration was then determined by dividing the contribution amount by the simple average of the ten day trading volume weighted average NYSE price of a common unit for the ten trading days ending at market close on August 31, 2017. The fair value of the common and general partner units issued was approximately $653 million based on the closing common unit price as of September 1, 2017, as recorded on the Consolidated Statements of Equity, for a total purchase price of $1.07 billion. The equity issued consisted of: (i) 13,719,017 common units to MPLX GP, (ii) 3,350,893 common units to MPLX Logistics and (iii) 1,441,224 common units to MPLX Holdings. The Partnership also issued 377,778 general partner units to MPLX GP in order to maintain its two percent general partner interest (“GP Interest”) in the Partnership.

Illinois Extension operates the 168-mile, 24-inch diameter Southern Access Extension (“SAX”) crude oil pipeline from Flanagan, Illinois to Patoka, Illinois, as well as additional tankage and two pump stations. LOOP owns and operates midstream crude oil infrastructure, including a deep water oil port offshore of Louisiana, pipelines and onshore storage facilities. LOOP also manages the operations of LOCAP, an affiliate pipeline system. LOCAP owns and operates a crude oil pipeline and tank facility in St. James, Louisiana, that distributes oil received from LOOP’s storage facilities and other connecting pipelines to nearby refineries and into the mid-continent region of the United States. Explorer owns and operates an approximate 1,830-mile common carrier pipeline that primarily transports gasoline, diesel, diluent and jet fuel from the Gulf Coast refining complex to the Midwest United States. The Partnership accounts for the Joint-Interest Acquisition entities as equity method investments within its L&S segment.

As a transfer between entities under common control, the Partnership recorded the Joint-Interest Acquisition on its Consolidated Balance Sheets at MPC’s historical basis, which included accumulated other comprehensive loss. The Partnership recognizes an accumulated other comprehensive loss on its Consolidated Balance Sheets relating to pension and other post-retirement benefits provided by the LOOP and Explorer joint-interests to their employees. MPLX LP is not a sponsor of these benefit plans. There were no changes to Accumulated other comprehensive loss during the period September 1, 2017 through September 30, 2017.

Distributions of cash received from the entities and interests acquired in the Joint-Interest Acquisition related to periods prior to the acquisition will be prorated on a daily basis with MPLX LP retaining the portion of distributions beginning on the closing date. All amounts distributed to MPLX LP related to periods before the acquisition will be paid to MPC. Additionally, MPLX LP has agreed to pay MPC for any distributions of cash from LOOP related to the sale of LOOP’s excess crude oil inventory. Because the future distributions or payments cannot be reasonably quantified, a liability was not recorded in connection with the acquisition. MPLX LP subsequently received distributions related to the third quarter 2017 and recorded a liability to MPC and a corresponding decrease to the general partner’s equity for $13 million, as shown on the Consolidated Statements of Equity. 

There is no income associated with the Joint-Interest Acquisition included in the Consolidated Statements of Income since the September 1, 2017 acquisition date, as the Partnership accounts for these investments in arrears using the most recently available information. The Partnership’s investment balance at September 30, 2017 related to the acquired interests is approximately $645 million and reported under the caption Equity method investments on the Consolidated Balance Sheets. MPC agreed to waive approximately two-thirds of the third quarter 2017 distributions on the common units issued in connection with the Joint-Interest Acquisition. As a result of this waiver, MPC did not receive approximately two-thirds of the distributions or IDRs that would have otherwise accrued on such common units with respect to the third quarter 2017 distributions. The value of these waived distributions was $10 million.

11

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 entered into on March 1, 2017 by the Partnership with MPLX GP, MPLX Logistics, MPLX Holdings and 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 NYSE 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 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 GP Interest in the Partnership. MPC agreed to waive two-thirds of the first quarter 2017 distributions on the 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 IDRs that would have otherwise accrued on such 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 NGL 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.

12

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

	Three Months Ended September 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	$	250	$	—	$	—	$	—		$	250
Service revenue - related parties	153		28		72		—			253
Rental income	77		—		—		—			77
Rental income - related parties	29		13		26		—			68
Product sales	157		—		—		—			157
Product sales - related parties	2		—		—		—			2
Income from equity method investments	6		—		—		—			6
Gain on sale of assets	1		—		—		—			1
Other income	2		—		—		—			2
Other income - related parties	26		—		—		(4		)	22
Total revenues and other income	703		41		98		(4		)	838
Costs and expenses:
Cost of revenues (excludes items below)	90		10		22		—			122
Purchased product costs	117		—		—		—			117
Rental cost of sales	11		2		—		—			13
Rental cost of sales - related parties	—		1		—		(1		)	—
Purchases - related parties	84		4		24		(3		)	109
Depreciation and amortization	138		4		9		—			151
General and administrative expenses	46		2		8		—			56
Other taxes	10		—		2		—			12
Total costs and expenses	496		23		65		(4		)	580
Income from operations	207		18		33		—			258
Interest expense (net of amounts capitalized)	51		—		—		—			51
Other financial costs	13		—		—		—			13
Income before income taxes	143		18		33		—			194
Net income	143		18		33		—			194
Less: Net income attributable to noncontrolling interests	2		—		—		—			2
Less: Net income attributable to Predecessor	—		18		33		—			51
Net income attributable to MPLX LP	141		—		—		—			141
Less: Preferred unit distributions	16		—		—		—			16
Less: General partner’s interest in net income attributable to MPLX LP	51		—		—		—			51
Limited partners’ interest in net income attributable to MPLX LP	$	74	$	—	$	—	$	—		$	74

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

13

	Nine Months Ended September 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	$	712		$	—	$	—	$	—		$	712
Service revenue - related parties	448			82		146		—			676
Rental income	218			—		—		—			218
Rental income - related parties	84			36		52		—			172
Product sales	394			—		—		—			394
Product sales - related parties	8			—		—		—			8
Loss from equity method investments	(72		)	—		—		—			(72		)
Gain on sale of assets	1			—		—		—			1
Other income	5			—		—		—			5
Other income - related parties	78			—		—		(11		)	67
Total revenues and other income	1,876			118		198		(11		)	2,181
Costs and expenses:
Cost of revenues (excludes items below)	263			24		42		—			329
Purchased product costs	310			—		—		—			310
Rental cost of sales	39			3		—		—			42
Rental cost of sales - related parties	—			2		—		(1		)	1
Purchases - related parties	238			13		45		(10		)	286
Depreciation and amortization	407			12		19		—			438
Impairment expense	130			—		—		—			130
General and administrative expenses	147			5		20		—			172
Other taxes	32			2		3		—			37
Total costs and expenses	1,566			61		129		(11		)	1,745
Income from operations	310			57		69		—			436
Related party interest and other financial income	1			—		—		—			1
Interest expense (net of amounts capitalized)	158			—		—		—			158
Other financial costs	37			—		—		—			37
Income before income taxes	114			57		69		—			240
Benefit for income taxes	(12		)	—		—		—			(12		)
Net income	126			57		69		—			252
Less: Net income attributable to noncontrolling interests	3			—		—		—			3
Less: Net income attributable to Predecessor	23			57		69		—			149
Net income attributable to MPLX LP	100			—		—		—			100
Less: Preferred unit distributions	25			—		—		—			25
Less: General partner’s interest in net income attributable to MPLX LP	136			—		—		—			136
Limited partners’ interest in net loss attributable to MPLX LP	$	(61	)	$	—	$	—	$	—		$	(61	)

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

14

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:

	Nine Months Ended September 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 income	$	126		$	57		$	69		$	252
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Amortization of deferred financing costs	34			—			—			34
Depreciation and amortization	407			12			19			438
Impairment expense	130			—			—			130
Deferred income taxes	(16		)	—			—			(16		)
Asset retirement expenditures	(3		)	(1		)	—			(4		)
Gain on disposal of assets	(1		)	—			—			(1		)
Loss from equity method investments	72			—			—			72
Distributions from unconsolidated affiliates	111			—			—			111
Changes in:
Current receivables	(44		)	1			—			(43		)
Inventories	(4		)	—			—			(4		)
Fair value of derivatives	28			—			—			28
Current accounts payable and accrued liabilities	59			(1		)	6			64
Receivables from / liabilities to related parties	15			3			(122		)	(104		)
All other, net	18			2			(2		)	18
Net cash provided by (used in) operating activities	932			73			(30		)	975
Investing activities:
Additions to property, plant and equipment	(874		)	(36		)	(33		)	(943		)
Investments - net related party loans	77			(37		)	63			103
Investments in unconsolidated affiliates	(56		)	—			—			(56		)
All other, net	4			—			—			4
Net cash (used in) provided by investing activities	(849		)	(73		)	30			(892		)
Financing activities:
Long-term debt - borrowings	434			—			—			434
- repayments	(1,312		)	—			—			(1,312		)
Related party debt - borrowings	2,215			—			—			2,215
- repayments	(2,223		)	—			—			(2,223		)
Net proceeds from equity offerings	510			—			—			510
Issuance of redeemable preferred units	984			—			—			984
Distributions to preferred unitholders	(9		)	—			—			(9		)
Distributions to unitholders and general partner	(612		)	—			—			(612		)
Distributions to noncontrolling interests	(3		)	—			—			(3		)
Contributions from noncontrolling interests	4			—			—			4
Consideration payment to Class B unitholders	(25		)	—			—			(25		)
All other, net	(2		)	—			—			(2		)
Contribution from MPC	225			—			—			225
Distributions to MPC from Predecessor	(104		)	—			—			(104		)
Net cash provided by financing activities	82			—			—			82
Net increase in cash and cash equivalents	165			—			—			165
Cash and cash equivalents at beginning of period	43			—			—			43
Cash and cash equivalents at end of period	$	208		$	—		$	—		$	208

15

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 final 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 September 30, 2017		Seven Months Ended September 30, 2017
Revenues and other income	$	19	$	45
Income from operations	6		17

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.

MarEn Bakken

On February 15, 2017, the Partnership closed on a joint venture, MarEn Bakken Company, LLC (“MarEn Bakken”), with Enbridge Energy Partners L.P. in which MPLX LP acquired a partial, indirect interest in the Dakota Access Pipeline and Energy Transfer Crude Oil Company Pipeline projects, collectively referred to as the Bakken Pipeline system, from Energy Transfer Partners, L.P. and Sunoco Logistics Partners, L.P. The Partnership contributed $500 million of the $2.0 billion purchase price paid by MarEn Bakken to acquire a 36.75 percent indirect interest in the Bakken Pipeline system. The Partnership holds, through a subsidiary, a 25 percent interest in MarEn Bakken, which equates to a 9.1875 percent indirect interest in the Bakken Pipeline system.

The Partnership accounts for its investment in MarEn Bakken as an equity method investment and bases the equity method accounting for this joint venture in arrears using the most recently available information. The Partnership’s investment balance at September 30, 2017 is approximately $520 million and reported under the caption Equity method investments on the Consolidated Balance Sheets. In connection with the Partnership’s acquisition of a partial, indirect equity interest in the Bakken Pipeline system, MPC agreed to waive its right to receive incentive distributions of $1.6 million per quarter for twelve consecutive quarters, beginning with distributions declared in the first quarter of 2017 and paid to MPC in the second quarter of 2017, which was prorated to $0.8 million from the acquisition date.

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, MPLX Logistics and 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 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 common units issued in connection with this transaction. As a result of this waiver, MPC did not receive general partner distributions or IDRs that would have otherwise accrued on such 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 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 Gulf Coast regions of the United States, 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 within its L&S segment.

16

4. Investments and Noncontrolling Interests

Summarized financial information for the Partnership’s equity method investments for the nine months ended September 30, 2017 and 2016 is as follows:

	Nine Months Ended September 30, 2017
(In millions)	MarkWest Utica EMG		Other VIEs		Non-VIEs		Total
Revenues and other income	$	137	$	49	$	178	$	364
Costs and expenses	72		29		115		216
Income from operations	65		20		63		148
Net income	65		19		28		112
Income from equity method investments(1)	6		7		16		29

	Nine Months Ended September 30, 2016
(In millions)	MarkWest Utica EMG		Other VIEs(2)			Non-VIEs		Total
Revenues and other income	$	165	$	13		$	108	$	286
Costs and expenses	70		107			80		257
Income (loss) from operations	95		(94		)	28		29
Net income (loss)	94		(94		)	28		28
Income (loss) from equity method investments(1)	10		(88		)	6		(72		)

(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 nine months ended September 30, 2016 related to the Partnership’s investment in Ohio Condensate Company, L.L.C., which does not appear separately in this table.

Summarized balance sheet information for the Partnership’s equity method investments as of September 30, 2017 and December 31, 2016 is as follows:

	September 30, 2017
(In millions)	MarkWest Utica EMG(1)		Other VIEs		Non-VIEs		Total
Current assets	$	72	$	47	$	379	$	498
Noncurrent assets	2,092		878		4,614		7,584
Current liabilities	37		55		492		584
Noncurrent liabilities	2		12		562		576

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

As of September 30, 2017 and December 31, 2016, the carrying value of the Partnership’s equity method investments exceeded the underlying net assets of its investees by $1.1 billion. 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.

17

MarkWest Utica EMG

Effective January 1, 2012, MarkWest Utica Operating Company, LLC (“Utica Operating”), a wholly-owned and consolidated subsidiary of MarkWest Energy Partners, L.P. (“MarkWest”), and EMG Utica, LLC (“EMG Utica” and together with Utica Operating, 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 currently in effect is referred to as the “Amended LLC Agreement”). The aggregate funding commitment of EMG Utica was $950 million. Thereafter, Utica Operating was required to fund, as needed, 100 percent of future capital for MarkWest Utica EMG until the aggregate capital that had been contributed by the Members reached $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 September 30, 2017, EMG Utica has contributed approximately $1.2 billion and Utica Operating has contributed approximately $1.5 billion to MarkWest Utica EMG.

Under the Amended LLC Agreement, prior to December 31, 2016, EMG Utica’s investment balance was increased by a quarterly special non-cash allocation of income (“Preference Amount”), calculated based upon the amount of capital contributed by EMG Utica in excess of $500 million. After December 31, 2016, no Preference Amount will accrue to EMG Utica’s investment balance. EMG Utica received a Preference Amount totaling approximately $4 million and $12 million for the three and nine months ended September 30, 2016, respectively.

Under the Amended LLC Agreement, after December 31, 2016, 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 September 30, 2017, Utica Operating’s investment balance in MarkWest Utica EMG was approximately 56 percent.

MarkWest Utica EMG is deemed to be a VIE. Utica Operating is not deemed to be the primary beneficiary, due to EMG Utica’s voting rights on significant matters. The Partnership’s investment in MarkWest Utica EMG’s, which was $2.2 billion at September 30, 2017 and December 31, 2016, is reported under the caption Equity method investments on the Consolidated Balance Sheets. The Partnership’s maximum exposure to loss as a result of its involvement with MarkWest Utica EMG includes its equity investment, any additional capital contribution commitments and any operating expenses incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. The Partnership did not provide any financial support to MarkWest Utica EMG that it was not contractually obligated to provide during the three and nine months ended September 30, 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”). 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 for the three and nine months ended September 30, 2017, totaled $5 million and $13 million, respectively. The amount of Operational Service revenue related to MarkWest Utica EMG for the three and nine months ended September 30, 2016, totaled approximately $5 million and $12 million, 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. As of September 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 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 nine months ended September 30, 2017, totaled $4 million and $12 million, respectively. The amount of Operational Service revenue related to Ohio Gathering for the three and nine months ended September 30, 2016, totaled approximately $5 million and $12 million, respectively.

18

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 LLC (“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 September 30, 2017, were current assets of $51 million, non-current assets of $406 million and current liabilities of $26 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 will be allocated to the members in proportion to their respective investment balances.

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 $220 million at September 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 nine months ended September 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 nine months ended September 30, 2017, totaled approximately $2 million and $6 million, respectively, and is reported as Other income-related parties in the Consolidated Statements of Income.

Sherwood Midstream Holdings

Effective January 1, 2017, MarkWest Liberty Midstream and Sherwood Midstream formed a joint venture, Sherwood Midstream Holdings LLC (“Sherwood Midstream Holdings”), for the purpose of 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 exchange for a 79 percent initial ownership interest. Sherwood Midstream contributed cash of approximately $44 million to Sherwood Midstream Holdings in exchange for a 21 percent ownership interest. During the second quarter ended June 30, 2017, true-ups to the initial contributions were finalized. 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 only recognized a gain for the portion attributable to Antero Midstream’s indirect interest of 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 included in its investment in Sherwood

19

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 special distribution of approximately $45 million.

MarkWest Liberty Midstream’s and 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 the Shared Assets, as defined in the LLC Agreement. Pursuant to the terms of the LLC Agreement, MarkWest Liberty Midstream will serve as the operator for Sherwood Midstream Holdings.

The Partnership accounts for Sherwood Midstream Holdings, which is a VIE, as an equity method investment as Sherwood Midstream is considered to be the general partner and controls all decisions. The Partnership’s investment in Sherwood Midstream Holdings, which was approximately $163 million at September 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 Holdings 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 Holdings that it was not contractually obligated to provide during the nine months ended September 30, 2017.

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 September 30, 2017, the Partnership has a 14.7 percent indirect ownership interest in Sherwood Midstream Holdings through Sherwood Midstream.

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 as of September 30, 2017. Centennial owns a products pipeline and storage facility.

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

• MarkWest Utica EMG, in which MPLX LP has a 56 percent interest as of September 30, 2017. MarkWest Utica EMG is engaged in natural gas processing and NGL fractionation, transportation and marketing in Ohio.

• Ohio Gathering, in which MPLX LP has a 34 percent indirect interest as of September 30, 2017. Ohio Gathering is a subsidiary of MarkWest Utica EMG providing natural gas gathering service in the Utica Shale region of eastern Ohio.

• Sherwood Midstream, in which MPLX LP has a 50 percent interest as of September 30, 2017. Sherwood Midstream supports the development of Antero Resources Corporation’s Marcellus Shale acreage in the rich-gas corridor of West Virginia.

• Sherwood Midstream Holdings, in which MPLX LP has an 86 percent total direct and indirect interest as of September 30, 2017. Sherwood Midstream Holdings owns certain infrastructure at the Sherwood Complex that is shared by and supports the operation of both the Sherwood Midstream and MarkWest gas processing plants and deethanization facilities.

• Illinois Extension, in which MPLX LP has a 35 percent interest as of September 30, 2017. Illinois Extension operates the SAX crude oil pipeline from Flanagan, Illinois to Patoka, Illinois, as well as additional tankage and two pump stations.

• LOOP, in which MPLX LP has a 40.7 percent interest as of September 30, 2017. LOOP owns and operates midstream crude oil infrastructure, including a deep water oil port offshore of Louisiana, pipelines, and onshore storage facilities, and manages operations of LOCAP, an affiliate pipeline system.

20

• LOCAP, in which MPLX LP has a 58.52 percent interest as of September 30, 2017. LOCAP owns and operates a crude oil pipeline and tank facility in St. James, Louisiana, that distributes oil received from LOOP’s storage facilities and other connecting pipelines to nearby refineries and into the midcontinent region of the United States.

• Explorer, in which MPLX LP has a 24.51 percent interest as of September 30, 2017. Explorer owns and operates a common carrier pipeline that primarily transports gasoline, diesel, diluent and jet fuel from the Gulf Coast refining complex to the Midwestern United States.

Related Party Agreements

The Partnership has various long-term, fee-based commercial agreements with MPC. Under these agreements, the Partnership provides 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, refined products and 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 nine months ended September 30, 2017, the Partnership borrowed $829 million and repaid $627 million, resulting in $202 million outstanding balance at September 30, 2017, which is included in Payables-related parties on the Consolidated Balance Sheets. Borrowings were at an average interest rate of 2.721 percent, per annum, for the nine months ended September 30, 2017. During the year ended December 31, 2016, the Partnership borrowed $2.5 billion and repaid $2.5 billion, resulting in no outstanding balance at December 31, 2016. Borrowings were at an average interest rate of 1.939 percent, per 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 the Annual Report on Form 10-K for the year ended December 31, 2016.

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

HST, WHC and MPLXT Agreements

As discussed in Note 3, the Partnership acquired HST, WHC and MPLXT on March 1, 2017. HST, WHC and MPLXT have various operating, transportation services, terminal services, storage services and employee services agreements with MPC, which 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, 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 storage and services agreement with MPC related to storage at its butane and propane caverns with an initial term of 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.

21

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.

The Partnership is party to various employee services agreements with MPC under which the Partnership reimburses MPC for employee benefit expenses, along with the provision of operational and management services, including those in support of HST, WHC and MPLXT.

Related Party Transactions

Sales to related parties were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2017		2016		2017		2016
Service revenues
MPC	$	276	$	253	$	801	$	676
Rental income
MPC	$	70	$	68	$	207	$	172
Product sales(1)
MPC	$	2	$	2	$	6	$	8

(1) There were additional product sales to MPC that net to zero within 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 nine months ended September 30, 2017, these sales totaled $63 million and $173 million, respectively. For the three and nine months ended September 30, 2016, these sales totaled $13 million and $25 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 September 30,				Nine Months Ended September 30,
(In millions)	2017		2016		2017		2016
MPC	$	9	$	10	$	30	$	36
MarkWest Utica EMG	5		5		13		12
Ohio Gathering	4		5		12		12
Other	4		2		14		7
Total	$	22	$	22	$	69	$	67

22

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 September 30,				Nine Months Ended September 30,
(In millions)	2017		2016		2017		2016
Purchases - related parties	$	17	$	11	$	50	$	29
General and administrative expenses	9		11		28		33
Total	$	26	$	22	$	78	$	62

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 September 30,				Nine Months Ended September 30,
(In millions)	2017		2016		2017		2016
MPC	$	11	$	14	$	33	$	36

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 in the Consolidated Statements of Income.

Employee services expenses from related parties were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2017		2016		2017		2016
Purchases - related parties	$	97	$	98	$	280	$	257
General and administrative expenses	25		27		74		75
Total	$	122	$	125	$	354	$	332

Receivables from related parties, which for December 31, 2016 included reimbursements from the MarkWest Merger to be provided by MPC for the conversion of Class B units, were as follows:

(In millions)	September 30, 2017		December 31, 2016
MPC	$	144	$	242
MarkWest Utica EMG	2		2
Ohio Gathering	2		2
Other	4		1
Total	$	152	$	247

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

(In millions)	September 30, 2017		December 31, 2016
MPC	$	18	$	11

23

Payables to related parties were as follows:

(In millions)	September 30, 2017		December 31, 2016
MPC(1)	$	277	$	63
MarkWest Utica EMG	30		24
Other	10		—
Total	$	317	$	87

(1) Balance includes approximately $202 million related to the loan with MPC Investment as discussed above.

During the nine months ended September 30, 2017 and the year ended December 31, 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 agreements. The Deferred revenue-related parties balance associated with the minimum volume deficiencies and project reimbursements were as follows:

(In millions)	September 30, 2017		December 31, 2016
Minimum volume deficiencies - MPC	$	55	$	48
Project reimbursements - MPC	27		9
Total	$	82	$	57

6. Net Income (Loss) Per Limited Partner Unit

Net income (loss) per unit applicable to common 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 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, general partner units, Preferred units, certain equity-based compensation awards and IDRs.

As discussed in Note 1, the HST, WHC and MPLXT acquisition was a transfer between entities under common control. As 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 the entities acquired under common control will be included in the net income (loss) per unit calculation prospectively as described above.

For the three months endedSeptember 30, 2017, the Partnership had dilutive potential common units consisting of certain equity-based compensation awards. For the three months endedSeptember 30, 2016 and the nine months ended September 30, 2017 and 2016, the Partnership had dilutive potential common units consisting of certain equity-based compensation awards and Class B units. Potential common units omitted from the diluted earnings per unit calculation for the three and nine months ended September 30, 2017 were less than one million and for the three and nine months ended September 30, 2016 were less than one million and approximately eight million, respectively.

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2017			2016			2017			2016
Net income attributable to MPLX LP	$	216		$	141		$	556		$	100
Less: Limited partners’ distributions declared on Preferred units(1)	16			16			49			25
General partner’s distributions declared (including IDRs)(1)	88			54			229			148
Limited partners’ distributions declared on common units(1)	232			179			648			507
Undistributed net loss attributable to MPLX LP	$	(120	)	$	(108	)	$	(370	)	$	(580	)

(1) See Note 7 for distribution information.

24

	Three Months Ended September 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)	$	88		$	232		$	16	$	336
Undistributed net loss attributable to MPLX LP	(2		)	(118		)	—		(120		)
Net income attributable to MPLX LP(1)	$	86		$	114		$	16	$	216
Weighted average units outstanding:
Basic	8			394			31		433
Diluted	8			395			31		434
Net income attributable to MPLX LP per limited partner unit:
Basic				$	0.29
Diluted				$	0.29

	Three Months Ended September 30, 2016
(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)	$	54		$	179		$	16	$	249
Undistributed net loss attributable to MPLX LP	(3		)	(105		)	—		(108		)
Net income attributable to MPLX LP(1)	$	51		$	74		$	16	$	141
Weighted average units outstanding:
Basic	7			341			31		379
Diluted	7			346			31		384
Net income attributable to MPLX LP per limited partner unit:
Basic				$	0.22
Diluted				$	0.21

25

	Nine Months Ended September 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)	$	229		$	648		$	49	$	926
Undistributed net loss attributable to MPLX LP	(7		)	(363		)	—		(370		)
Net income attributable to MPLX LP(1)	$	222		$	285		$	49	$	556
Weighted average units outstanding:
Basic	8			378			31		417
Diluted	8			381			31		420
Net income attributable to MPLX LP per limited partner unit:
Basic				$	0.75
Diluted				$	0.75

	Nine Months Ended September 30, 2016
(In millions, except per unit data)	General Partner			Limited Partners’ Common Units			Redeemable Preferred Units		Total
Basic and diluted net loss attributable to MPLX LP per unit:
Net income (loss) attributable to MPLX LP:
Distributions declared (including IDRs)	$	148		$	507		$	25	$	680
Undistributed net loss attributable to MPLX LP	(12		)	(568		)	—		(580		)
Net income (loss) attributable to MPLX LP(1)	$	136		$	(61	)	$	25	$	100
Weighted average units outstanding:
Basic	7			324			16		347
Diluted	7			324			16		347
Net loss attributable to MPLX LP per limited partner unit:
Basic				$	(0.19	)
Diluted				$	(0.19	)

(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.

26

7. Equity

The changes in the number of units outstanding during the nine months ended September 30, 2017 are summarized below:

(In units)	Common	Class B		General Partner	Total
Balance at December 31, 2016	357,193,288	3,990,878		7,371,105	368,555,271
Unit-based compensation awards(1)	183,509	—		3,745	187,254
Issuance of units under the ATM Program(2)	13,846,998	—		282,591	14,129,589
Contribution of HST/WHC/MPLXT(3)	12,960,376	—		264,497	13,224,873
Contribution of the Joint-Interest Acquisition(3)	18,511,134	—		377,778	18,888,912
Class B conversion(4)	4,350,057	(3,990,878	)	7,330	366,509
Balance at September 30, 2017	407,045,362	—		8,307,046	415,352,408

(1) As a result of the unit-based compensation awards issued during the period, MPLX GP contributed less than $1 million in exchange for 3,745 general partner units to maintain its two percent GP Interest.

(2) As a result of common units issued under the ATM Program during the period, MPLX GP contributed $10 million in exchange for 282,591 general partner units to maintain its two percent GP Interest.

(3) See Note 3 for information regarding this acquisition.

(4) On July 1, 2017, 3,990,878 Class B units converted to 4,350,057 common units and were eligible to receive the second quarter 2017 distribution. As a result of the Class B conversion, MPLX GP contributed less than $1 million in exchange for 7,330 general partner units to maintain its two percent GP Interest.

Reorganization Transactions – On September 1, 2016, the Partnership and various affiliates initiated a series of reorganization transactions in order to simplify the Partnership’s ownership structure and its financial and tax reporting requirements. In connection with these transactions, the issued and outstanding MPLX LP Class A units, all of which were held by MarkWest Hydrocarbon, were either distributed to or purchased by MPC in exchange for $84 million in cash, 21,401,137 MPLX LP common units and 436,758 MPLX LP general partner units. Following these initial transactions, all of the MPLX LP Class A units were exchanged on a one-for-one basis for newly issued common units representing limited partner interests in MPLX LP. MPC also contributed $141 million to facilitate the repayment of intercompany debt between MarkWest Hydrocarbon and MarkWest. As a result of these transactions, the MPLX LP Class A units were eliminated, are no longer outstanding and no longer participate in distributions of cash from the Partnership. Cash that is derived from or attributable to MarkWest Hydrocarbon’s operations is now treated in the same manner as cash derived from or attributable to other operations of the Partnership and its subsidiaries.

Net Income Allocation–In preparing the Consolidated Statements of Equity, net income (loss) 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. However, when distributions related to the IDRs 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 GP Interest in net income attributable to MPLX LP:

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2017		2016		2017		2016
Net income attributable to MPLX LP	$	216	$	141	$	556	$	100
Less: Preferred unit distributions	16		16		49		25
General partner's IDRs and other	83		49		216		137
Net income (loss) attributable to MPLX LP available to general and limited partners	$	117	$	76	$	291	$	(62	)
General partner's two percent GP Interest in net income (loss) attributable to MPLX LP	$	3	$	2	$	6	$	(1	)
General partner's IDRs and other	83		49		216		137
General partner's GP Interest in net income attributable to MPLX LP	$	86	$	51	$	222	$	136

27

Cash distributions–The Partnership Agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders, Preferred unitholders and general partner will receive. In accordance with the Partnership Agreement, on October 25, 2017, the Partnership declared a quarterly cash distribution, based on the results of the third quarter of 2017, totaling $320 million, or $0.5875 per common unit. These distributions will be paid on November 14, 2017 to common unitholders of record on November 6, 2017.

The allocation of total quarterly cash distributions to general, limited and Preferred unitholders is as follows for the three and nine months ended September 30, 2017 and 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 September 30,				Nine Months Ended September 30,
(In millions)	2017		2016		2017		2016
General partner's distributions:
General partner's distributions on general partner units	$	7	$	5	$	18	$	13
General partner's distributions on IDRs	81		49		211		135
Total distribution on general partner units and IDRs	$	88	$	54	$	229	$	148
Common and preferred unit distributions:
Common unitholders, includes common units of general partner	$	232	$	179	$	648	$	507
Preferred unit distributions	16		16		49		25
Total cash distributions declared	$	336	$	249	$	926	$	680

8. Redeemable Preferred Units

Private Placement of Preferred Units –On May 13, 2016, MPLX LP completed the private placement of approximately 30.8 million6.5 percent Series A Convertible Preferred units (the "Preferred 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 were used for capital expenditures, repayment of debt and general partnership purposes.

The Preferred units rank senior to all common units with respect to distributions and rights upon liquidation. The holders of the Preferred units are entitled to receive cumulative quarterly distributions equal to $0.528125 per unit. Following the second anniversary of the issuance of the Preferred units, the holders of the Preferred units will receive as a distribution the greater of $0.528125 per unit or the amount of per unit distributions paid to holders of MPLX LP common units.

The changes in the redeemable preferred balance from December 31, 2016 through September 30, 2017 are summarized below:

(In millions)	Redeemable Preferred Units
Balance at December 31, 2016	$	1,000
Net income	49
Distributions received by Preferred unitholders	(49		)
Balance at September 30, 2017	$	1,000

The holders may convert their Preferred 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 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 shall be the quotient of (a) the sum of (i) $32.50, plus (ii) any unpaid cash distributions on the applicable Preferred unit, divided by (b) $32.50. The holders of the Preferred 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. In addition, upon certain events involving a change of control the holders of Preferred units may elect, among other potential elections, to convert their Preferred units to common units at the then-change of control conversion rate.

28

The Preferred 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 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. As the Preferred 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 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 are organized and managed based upon the nature of the products and services it offers.

• L&S – transports, stores and distributes crude oil and refined petroleum products. Segment information for prior periods includes retrospective adjustments in connection with the acquisition of HST, WHC and MPLXT. Segment information is not included for periods prior to the Joint-Interest Acquisition and the Ozark pipeline acquisition. See Note 3 for more detail of these acquisitions.

• G&P – gathers, processes and transports natural gas; gathers, transports, fractionates, stores and markets NGLs.

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 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), 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 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 September 30, 2017
(In millions)	L&S		G&P		Total
Revenues and other income:
Segment revenues	$	378	$	669	$	1,047
Segment other income	11		1		12
Total segment revenues and other income	389		670		1,059
Costs and expenses:
Segment cost of revenues	176		276		452
Segment operating income before portion attributable to noncontrolling interests and Predecessor	213		394		607
Segment portion attributable to noncontrolling interests and Predecessor	—		45		45
Segment operating income attributable to MPLX LP	$	213	$	349	$	562

29

	Three Months Ended September 30, 2016
(In millions)	L&S		G&P		Total
Revenues and other income:
Segment revenues	$	339	$	567	$	906
Segment other income	12		1		13
Total segment revenues and other income	351		568		919
Costs and expenses:
Segment cost of revenues	153		239		392
Segment operating income before portion attributable to noncontrolling interests and Predecessor	198		329		527
Segment portion attributable to noncontrolling interests and Predecessor	74		36		110
Segment operating income attributable to MPLX LP	$	124	$	293	$	417

	Nine Months Ended September 30, 2017
(In millions)	L&S		G&P		Total
Revenues and other income:
Segment revenues	$	1,095	$	1,869	$	2,964
Segment other income	35		2		37
Total segment revenues and other income	1,130		1,871		3,001
Costs and expenses:
Segment cost of revenues	500		781		1,281
Segment operating income before portion attributable to noncontrolling interests and Predecessor	630		1,090		1,720
Segment portion attributable to noncontrolling interests and Predecessor	53		119		172
Segment operating income attributable to MPLX LP	$	577	$	971	$	1,548

	Nine Months Ended September 30, 2016
(In millions)	L&S		G&P		Total
Revenues and other income:
Segment revenues	$	901	$	1,595	$	2,496
Segment other income	42		1		43
Total segment revenues and other income	943		1,596		2,539
Costs and expenses:
Segment cost of revenues	392		662		1,054
Segment operating income before portion attributable to noncontrolling interests and Predecessor	551		934		1,485
Segment portion attributable to noncontrolling interests and Predecessor	216		113		329
Segment operating income attributable to MPLX LP	$	335	$	821	$	1,156

30

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2017			2016			2017			2016
Reconciliation to Income from operations:
L&S segment operating income attributable to MPLX LP	$	213		$	124		$	577		$	335
G&P segment operating income attributable to MPLX LP	349			293			971			821
Segment operating income attributable to MPLX LP	562			417			1,548			1,156
Segment portion attributable to unconsolidated affiliates	(47		)	(41		)	(125		)	(130		)
Segment portion attributable to Predecessor	—			74			53			216
Income (loss) from equity method investments	23			6			29			(72		)
Other income - related parties	13			11			38			29
Unrealized derivative (losses) gains(1)	(17		)	(2		)	2			(23		)
Depreciation and amortization	(164		)	(151		)	(515		)	(438		)
Impairment expense	—			—			—			(130		)
General and administrative expenses	(59		)	(56		)	(174		)	(172		)
Income from operations	$	311		$	258		$	856		$	436

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2017			2016			2017			2016
Reconciliation to Total revenues and other income:
Total segment revenues and other income	$	1,059		$	919		$	3,001		$	2,539
Revenue adjustment from unconsolidated affiliates	(107		)	(100		)	(287		)	(303		)
Income (loss) from equity method investments	23			6			29			(72		)
Other income - related parties	13			11			38			29
Unrealized derivative (losses) gains related to product sales(1)	(8		)	2			1			(12		)
Total revenues and other income	$	980		$	838		$	2,782		$	2,181

(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 September 30,						Nine Months Ended September 30,
(In millions)	2017			2016			2017			2016
Reconciliation to Net income attributable to noncontrolling interests and Predecessor:
Segment portion attributable to noncontrolling interests and Predecessor	$	45		$	110		$	172		$	329
Portion of noncontrolling interests and Predecessor related to items below segment income from operations	(21		)	(39		)	(84		)	(157		)
Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates	(23		)	(18		)	(49		)	(20		)
Net income attributable to noncontrolling interests and Predecessor	$	1		$	53		$	39		$	152

31

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

	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2017		2016		2017		2016
L&S segment capital expenditures	$	120	$	188	$	353	$	369
G&P segment capital expenditures	333		183		957		668
Total segment capital expenditures	453		371		1,310		1,037
Less: Capital expenditures for Partnership-operated, non-wholly-owned subsidiaries in G&P segment	101		34		306		94
Total capital expenditures	$	352	$	337	$	1,004	$	943

Total assets by reportable segment were:

(In millions)	September 30, 2017		December 31, 2016
Cash and cash equivalents	$	3	$	234
L&S	4,520		2,978
G&P	14,715		14,297
Total assets	$	19,238	$	17,509

10. Inventories

Inventories consist of the following:

(In millions)	September 30, 2017		December 31, 2016
NGLs	$	3	$	2
Line fill	9		9
Spare parts, materials and supplies	52		44
Total inventories	$	64	$	55

11. Property, Plant and Equipment

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

(In millions)	September 30, 2017		December 31, 2016
Natural gas gathering and NGL transportation pipelines and facilities	$	5,101	$	4,748
Processing, fractionation and storage facilities(1)	3,753		3,547
Pipelines and related assets	2,181		1,799
Barges and towing vessels	484		479
Terminals and related assets(1)	794		759
Land, building, office equipment and other	755		757
Construction-in-progress	986		1,013
Total	14,054		13,102
Less accumulated depreciation	2,132		1,694
Property, plant and equipment, net	$	11,922	$	11,408

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

32

12. Fair Value Measurements

Fair Values – Recurring

Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions as discussed in Note 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:

	September 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	—		(5		)	—		(6		)
Embedded derivatives in commodity contracts	—		(52		)	—		(54		)
Total carrying value in Consolidated Balance Sheets	$	—	$	(57	)	$	—	$	(60	)

The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments as of September 30, 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	Forward ethane prices (per Gal)(1)	$0.27 - $0.28	Oct. 17 - Dec. 17
		Forward propane prices (per Gal)(1)	$0.68 - $0.91	Oct. 17 - Dec. 18
		Forward isobutane prices (per Gal)(1)	$0.82 - $1.06	Oct. 17 - Dec. 18
		Forward normal butane prices (per Gal)(1)	$0.76 - $1.03	Oct. 17 - Dec. 18
		Forward natural gasoline prices (per Gal)(1)	$1.18 - $1.22	Oct. 17 - Dec. 18
Embedded derivatives in commodity contracts	Assets	ERCOT Pricing (per MegaWatt Hour)	$24.19 - $26.05	Oct. 17 - Dec. 17
	Liabilities	Forward propane prices (per Gal)(1)	$0.61 - $0.91	Oct. 17 - Dec. 22
		Forward isobutane prices (per Gal)(1)	$0.75 - $1.06	Oct. 17 - Dec. 22
		Forward normal butane prices (per Gal)(1)	$0.69 - $1.03	Oct. 17 - Dec. 22
		Forward natural gasoline prices (per Gal)(1)	$1.15 - $1.22	Oct. 17 - Dec. 22
		Forward natural gas prices (per MMBtu)(2)	$2.30 - $3.11	Oct. 17 - Dec. 22
		Probability of renewal(3)	50.0%
		Probability of renewal for second 5-yr term(3)	75.0%

(1) NGL prices used in the valuations decrease over time.

(2) Natural gas prices used in the valuations decrease 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

33

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 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.

• An embedded derivative related to utilities costs discussed further in Note 13. Increases in the forward Electric Reliability Council of Texas (“ERCOT”) prices result in a decrease in the fair value of the embedded derivative liability.

Level 3 Valuation Process

The Partnership’s Risk Management Department (the “Risk Department”) is responsible for the valuation of the Partnership’s commodity derivative contracts and embedded derivatives in commodity contracts, except for the Natural Gas Embedded Derivative. The Risk Department reports to the Chief Financial Officer and is responsible for the oversight of the Partnership’s commodity risk management program. The members of the Risk Department have the requisite experience, knowledge and day-to-day involvement in the energy commodity markets to ensure appropriate valuations and understand the changes in the valuations from period to period. The valuations of the Level 3 commodity derivative contracts are performed by a third-party pricing service and 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 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 (October 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.

34

Changes in Level 3 Fair Value Measurements

The tables below include a rollforward of the balance sheet amounts for the three and nine months ended September 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.

	Three Months Ended September 30, 2017						Nine Months Ended September 30, 2017
(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	$	2		$	(43	)	$	(6	)	$	(54	)
Total losses (realized and unrealized) included in earnings(1)	(10		)	(12		)	(3		)	(4		)
Settlements	3			3			4			6
Fair value at end of period	$	(5	)	$	(52	)	$	(5	)	$	(52	)
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	$	(7	)	$	(10	)	$	(4	)	$	(4	)

	Three Months Ended September 30, 2016						Nine Months Ended September 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	$	(4	)	$	(40	)	$	7		$	(32	)
Total gains (losses) (realized and unrealized) included in earnings(1)	2			(6		)	(5		)	(17		)
Settlements	(1		)	2			(6		)	5
Netting adjustment(2)	—			—			1			—
Fair value at end of period	$	(3	)	$	(44	)	$	(3	)	$	(44	)
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	$	—		$	(4	)	$	(4	)	$	(15	)

(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 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 September 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 13).

35

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 long-term debt, excluding capital leases, and SMR liability:

	September 30, 2017				December 31, 2016
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Long-term debt	$	7,619	$	6,869	$	4,953	$	4,422
SMR liability	106		92		108		96

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. 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 and NGLs. Derivative contracts utilized are swaps traded on the OTC market and fixed price forward contracts. The risk management policy does not allow the Partnership to take speculative positions with its derivative contracts.

To mitigate its cash flow exposure to fluctuations in the price of NGLs, the Partnership has entered into derivative financial instruments relating to the future price of NGLs and crude oil. The Partnership currently manages the majority of its NGL price risk using direct product NGL derivative contracts. The Partnership enters into NGL derivative contracts when adequate market liquidity exists and future prices are satisfactory. A portion of the Partnership’s NGL price exposure is managed by using crude oil contracts. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, the crude oil contracts create increased risk and additional gains or losses. The Partnership may settle its crude oil contracts prior to the contractual settlement date in order to take advantage of favorable terms and reduce the future exposure resulting from the less effective crude oil contracts. Based on its current volume forecasts, the majority of its derivative positions used to manage the future commodity price exposure are expected to be direct product NGL derivative contracts.

To mitigate its cash flow exposure to fluctuations in the price of natural gas, the Partnership primarily utilizes derivative financial instruments relating to the future price of natural gas and takes into account the partial offset of its long and short gas positions resulting from normal operating activities.

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 2018. The Partnership would be exposed to additional commodity risk in certain situations such as if producers under-deliver or over-deliver product or when processing facilities are operated in different recovery modes. In the event the Partnership has derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated.

Management conducts a standard credit review on counterparties to derivative contracts and has provided the counterparties with a guaranty as credit support for its obligations. A separate agreement with certain counterparties allows MarkWest Liberty Midstream to enter into derivative positions without posting cash collateral. The Partnership uses standardized agreements that allow for offset of certain positive and negative exposures (“master netting arrangements”) in the event of default or other terminating events, including bankruptcy.

The Partnership records derivative contracts at fair value in the Consolidated Balance Sheets and has not elected hedge accounting or the normal purchases and normal sales designation (except for electricity and certain other qualifying contracts,

36

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

Derivative contracts not designated as hedging instruments	Financial Position	Notional Quantity (net)
Crude Oil (bbl)	Short	18,400
Natural Gas (MMBtu)	Long	1,096,539
NGLs (gal)	Short	33,387,904

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 September 30, 2017 and December 31, 2016, the estimated fair value of this contract was a liability of $52 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 through the fourth quarter of 2018. The contract’s pricing is currently fixed through the fourth quarter of 2017 with the ability to fix the pricing for its remaining year. Changes in the fair value as of the derivative component of this contract were recognized as Cost of Revenues in the Consolidated Statements of Income. As of September 30, 2017, the estimated fair value of this contract was a liability of less than $1 million.

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, 2016, as updated by our Current Report on Form 8-K filed on May 1, 2017. The impact of the Partnership’s derivative instruments on its Consolidated Balance Sheets is summarized below:

(In millions)	September 30, 2017					December 31, 2016
Derivative contracts not designated as hedging instruments and their balance sheet location	Asset		Liability			Asset		Liability
Commodity contracts(1)
Other current assets / other current liabilities	$	—	$	(15	)	$	—	$	(13	)
Other noncurrent assets / deferred credits and other liabilities	—		(42		)	—		(47		)
Total	$	—	$	(57	)	$	—	$	(60	)

37

(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:

	September 30, 2017
	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
Current
Commodity contracts	$	—	$	—	$	—	$	(5	)	$	—	$	(5	)
Embedded derivatives in commodity contracts	—		—		—		(10		)	—		(10		)
Total current derivative instruments	—		—		—		(15		)	—		(15		)
Non-current
Commodity contracts	—		—		—		—			—		—
Embedded derivatives in commodity contracts	—		—		—		(42		)	—		(42		)
Total non-current derivative instruments	—		—		—		(42		)	—		(42		)
Total derivative instruments	$	—	$	—	$	—	$	(57	)	$	—	$	(57	)

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 default, the Partnership’s master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions and other forms of non-cash collateral (such as letters of credit).

The impact of the Partnership’s derivative contracts not designated as hedging instruments and the location of gain or (loss) recognized in the Consolidated Statements of Income is summarized below:

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2017			2016			2017			2016
Product sales
Realized (loss) gain	$	(2	)	$	—		$	(3	)	$	6
Unrealized (loss) gain	(8		)	2			1			(12		)
Total derivative (loss) gain related to product sales	(10		)	2			(2		)	(6		)
Purchased product costs
Realized loss(1)	(2		)	(1		)	(6		)	(4		)
Unrealized (loss) gain	(9		)	(3		)	1			(12		)
Total derivative loss related to purchased product costs	(11		)	(4		)	(5		)	(16		)
Cost of revenues
Realized loss(1)	—			—			—			(2		)
Unrealized (loss) gain	—			(1		)	—			1
Total derivative loss related to cost of revenues	—			(1		)	—			(1		)
Total derivative losses	$	(21	)	$	(3	)	$	(7	)	$	(23	)

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

38

14. Debt

The Partnership’s outstanding borrowings consisted of the following:

(In millions)	September 30, 2017			December 31, 2016
MPLX LP:
Bank revolving credit facility due 2022	$	420		$	—
Term loan facility due 2019	—			250
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
MPL - capital lease obligations due 2020	7			8
Total	7,277			4,858
Unamortized debt issuance costs	(27		)	(7		)
Unamortized discount	(401		)	(428		)
Amounts due within one year	(1		)	(1		)
Total long-term debt due after one year	$	6,848		$	4,422

Credit Agreements

On July 21, 2017, the Partnership entered into a syndicated credit agreement to replace its previously outstanding $2.0 billionfive-year bank revolving credit facility with a $2.25 billionfive-year bank revolving credit facility that expires in July 2022 (the “MPLX Credit Agreement 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. During the nine months ended September 30, 2017, the Partnership had no borrowings under the previous bank revolving credit facility. During the nine months ended September 30, 2017, the Partnership borrowed$420 million under the MPLX Credit Agreement 2022, at an average interest rate of 2.702 percent. At September 30, 2017, the Partnership had $420 million outstanding borrowings and $3 million letters of credit outstanding under the new facility, resulting in total availability of $1.827 billion, or 81.2 percent of the borrowing capacity.

The $250 million term loan facility was drawn in full on November 20, 2014. On July 19, 2017, MPLX LP prepaid the entire outstanding principal of this loan facility with cash on hand. The borrowings under this facility between January 1, 2017 and July 19, 2017 were at an average interest rate of 2.407 percent.

Senior Notes

On February 10, 2017, the Partnership completed 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 March 2027 and (ii) $1.0 billion aggregate principal amount of 5.200 percent senior notes due in March 2047 (collectively, the “New Senior Notes”). The net proceeds from the 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 notes is payable semi-annually in arrears on March 1 and September 1, commencing on September 1, 2017.

39

15. Supplemental Cash Flow Information

	Nine Months Ended September 30,
(In millions)	2017		2016
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	207	$	158
Non-cash investing and financing activities:
Net transfers of property, plant and equipment from materials and supplies inventories	$	6	$	(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:

	Nine Months Ended September 30,
(In millions)	2017		2016
Increase in capital accruals	$	55	$	—

16. Equity-Based Compensation

Phantom Units – The following is a summary of phantom unit award activity of MPLX LP common units for the nine months ended September 30, 2017:

	Number of Units		Weighted Average Fair Value
Outstanding at December 31, 2016	1,173,411		$	33.09
Granted	653,721		36.36
Settled	(288,584	)	33.50
Forfeited	(113,107	)	34.59
Outstanding at September 30, 2017	1,425,441		34.39

Performance Units – The Partnership grants performance units under the MPLX LP 2012 Incentive Compensation Plan to certain officers of 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 DCF during the last twelve months of the performance period, and a 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, 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 nine months ended September 30, 2017:

	Number of Units
Outstanding at December 31, 2016	1,799,249
Granted	1,407,062
Settled	(464,500	)
Forfeited	(35,217	)
Outstanding at September 30, 2017	2,706,594

40

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 September 30, 2017 and December 31, 2016, accrued liabilities for remediation totaled $14 million and $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 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 no such receivables at September 30, 2017.

In July 2015, representatives from the EPA and the United States Department of Justice 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’s launcher/receiver, pipeline and compressor station operations. In response to 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 Occupational Safety and Health Administration. After providing these studies, and other substantial documentation related to MarkWest Liberty Midstream's pipeline and compressor stations, 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 this matter.

MarkWest Liberty Midstream continues to discuss with the EPA and the State of Pennsylvania civil enforcement allegations associated with 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 received an initial proposal from the EPA to settle all civil 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. In connection with these negotiations, MarkWest Liberty Midstream has received a revised settlement proposal from the EPA which proposes to lower the proposed cash penalty to approximately $1.24 million and the estimated cost of proposed supplemental environmental projects to an estimated cost of approximately $1.6 million. MarkWest Liberty Midstream will continue to negotiate with EPA regarding the amount and scope of 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.

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 Marathon Pipe Line LLC (“MPL”). These complaints, which have been amended since filing, assert claims of common law nuisance and contribution under the Illinois Contribution Act and other laws for environmental cleanup costs that may be imposed on Premcor and Apex by the State of Illinois. 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,

41

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 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 September 30, 2017, the Partnership’s contractual commitments to acquire property, plant and equipment totaled $520 million. These commitments at September 30, 2017 were primarily related to plant expansion projects for the Marcellus and Southwest Operations. 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. 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 September 30, 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.

42

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, 2016, as updated by our Current Report on Form 8-K filed on May 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, 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 transportation, storage and distribution of crude oil and refined petroleum products.

SIGNIFICANT FINANCIAL AND OTHER HIGHLIGHTS

Significant financial and other highlights for the three months ended September 30, 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 $89 million, or 72 percent, for the three months ended September 30, 2017 compared to the same period of 2016 due to $74 million from the inclusion of HST, WHC and MPLXT results after our acquisition as of March 1, 2017and$7 million from the acquisition of the Ozark pipeline.

• G&P segment operating income attributable to MPLX LP increased approximately $56 million, or 19 percent, for the three months ended September 30, 2017 compared to the same period of 2016. The G&P segment realized product price increases and volume increases during the third quarter of 2017 primarily due to expansions in the Southwest as well as growth at the Sherwood, Majorsville and Bluestone (previously referred to as Keystone) plants. Compared to the third quarter of 2016, processing volumes were up approximately 11 percent, fractionated volumes were up approximately 14 percent and gathering volumes were up approximately 13 percent.

Additional highlights for the three and nine months ended September 30, 2017, including a look ahead to anticipated growth, are listed below.

Acquisition and Growth Activities

• On September 27, 2017, MPC authorized an offer of MPLX Fuels Distributions LLC and MPLX Refining Logistics LLC to MPLX LP in exchange for cash and limited and general partnership units. MPLX Fuels Distribution LLC is structured to provide a broad range of scheduling and marketing services as MPC’s sole and exclusive agent. MPLX Refining Logistics LLC contains the integrated tank farm assets that support MPC’s refining operations. These essential logistics assets include: approximately 56 million barrels storage capacity (crude, finished products and intermediates), 619 tanks, 32 rail and truck racks, and 18 docks and gasoline blenders. This offer, which is projected to contribute approximately $1.0 billion of annual EBITDA, is currently under review by the conflicts committee of the board of directors of our general partner. The transaction is expected to close no later than the end of the first quarter of 2018. If approved, this acquisition will complete a series of planned acquisitions of assets from MPC that began in early 2017. The combined sum of the three transactions totals an estimated $1.4 billion of annual EBITDA. The stable, fee-based earnings from these acquired assets add both scale and diversification to our portfolio of high-quality midstream assets.

43

• On September 1, 2017, we acquired joint-interest ownerships in certain pipelines and storage facilities from MPC for $420 million in cash and the issuance of $653 million in MPLX LP equity. The acquired ownership interests include a 35 percent ownership interest in Illinois Extension, a 40.7 percent ownership interest in LOOP, a 58.52 percent ownership interest in LOCAP, and a 24.51 percent ownership interest in Explorer. The assets held by these entities include a 1,830-mile refined products pipeline, storage facilities, pump stations, and an offshore deep water oil port located along the Gulf Coast. The infrastructure serves primarily the Midwest and Gulf Coast regions of the United States. There is no income associated with the Joint-Interest Acquisition included in the Consolidated Statements of Income since the September 1, 2017 acquisition date, as we account for these equity method investments in arrears using the most recently available information.

• 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 NGL 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 had 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.

• 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. During the third quarter 2017, MPLX LP benefited from the first full quarter of earnings from its indirect interest in the Bakken Pipeline system. Initial cash distributions related to this investment were also received during the third quarter 2017.

• 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 with substantial future growth opportunities. As part of 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 late 2018. In addition to the 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 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.

• On February 10, 2017, we completed a public offering of $2.25 billion aggregate principal amount of senior notes (the “New Senior Notes”).

44

• During the nine months ended September 30, 2017, we issued an aggregate of 13,846,998 commons units under our ATM Program, generating net proceeds of approximately $473 million. As of September 30, 2017, $1.7 billion of common units remain available for issuance through the ATM Program.

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 of directors of our general partner in approving the Partnership’s cash distributions.

We define Adjusted EBITDA as net income adjusted for (i) depreciation and amortization; (ii) 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; (vii) (income) loss from equity investments; (viii) distributions from unconsolidated subsidiaries considering principal payments of debt and certain capital expenditures; (ix) distributions of cash received from Joint-Interest Acquisition entities to MPC; (x) unrealized derivative losses (gains); and (xi) acquisition costs. We also use DCF, which we define as Adjusted EBITDA adjusted for (i) deferred revenue impacts; (ii) net interest and other financial costs; (iii) maintenance capital expenditures; and (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 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, a non-GAAP financial measure, which is defined as segment revenue less segment purchased product costs less realized derivative 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. 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).

45

RESULTS OF OPERATIONS

The following table and discussion is a summary of our results of operations for the three and nine months ended September 30, 2017 and 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 HST, WHC and MPLXT.

	Three Months Ended September 30,							Nine Months Ended September 30,
(In millions)	2017		2016		Variance			2017		2016			Variance
Total revenues and other income	$	980	$	838	$	142		$	2,782	$	2,181		$	601
Costs and expenses:
Cost of revenues (excludes items below)	129		122		7			381		329			52
Purchased product costs	170		117		53			441		310			131
Rental cost of sales	19		13		6			44		42			2
Rental cost of sales - related parties	—		—		—			1		1			—
Purchases - related parties	114		109		5			330		286			44
Depreciation and amortization	164		151		13			515		438			77
Impairment expense	—		—		—			—		130			(130		)
General and administrative expenses	59		56		3			174		172			2
Other taxes	14		12		2			40		37			3
Total costs and expenses	669		580		89			1,926		1,745			181
Income from operations	311		258		53			856		436			420
Related party interest and other financial costs	1		—		1			1		1			—
Interest expense, net of amounts capitalized	77		51		26			217		158			59
Other financial costs	15		13		2			40		37			3
Income before income taxes	218		194		24			598		240			358
Provision (benefit) for income taxes	1		—		1			3		(12		)	15
Net income	217		194		23			595		252			343
Less: Net income attributable to noncontrolling interests	1		2		(1		)	3		3			—
Less: Net income attributable to Predecessor	—		51		(51		)	36		149			(113		)
Net income attributable to MPLX LP	$	216	$	141	$	75		$	556	$	100		$	456
Adjusted EBITDA attributable to MPLX LP(1)	$	538	$	375	$	163		$	1,435	$	1,028		$	407
DCF(1)	442		301		141			1,183		822			361
DCF attributable to GP and LP unitholders(1)	426		285		141			1,134		797			337

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

46

	Three Months Ended September 30,									Nine Months Ended September 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	$	217		$	194		$	23		$	595		$	252		$	343
Depreciation and amortization	164			151			13			515			438			77
Provision (benefit) for income taxes	1			—			1			3			(12		)	15
Amortization of deferred financing costs	13			11			2			38			34			4
Non-cash equity-based compensation	4			3			1			10			9			1
Impairment expense	—			—			—			—			130			(130		)
Net interest and other financial costs	80			53			27			220			162			58
(Income) loss from equity method investments	(23		)	(6		)	(17		)	(29		)	72			(101		)
Distributions from unconsolidated subsidiaries	70			33			37			136			111			25
Distributions of cash received from Joint-Interest Acquisition entities to MPC	(13		)	—			(13		)	(13		)	—			(13		)
Other adjustments to equity method investment distributions	8			—			8			8			—			8
Unrealized derivative losses (gains)(1)	17			2			15			(2		)	23			(25		)
Acquisition costs	2			—			2			6			(1		)	7
Adjusted EBITDA	540			441			99			1,487			1,218			269
Adjusted EBITDA attributable to noncontrolling interests	(2		)	(2		)	—			(5		)	(3		)	(2		)
Adjusted EBITDA attributable to Predecessor(2)	—			(64		)	64			(47		)	(187		)	140
Adjusted EBITDA attributable to MPLX LP	538			375			163			1,435			1,028			407
Deferred revenue impacts	8			1			7			25			8			17
Net interest and other financial costs	(80		)	(53		)	(27		)	(220		)	(162		)	(58		)
Maintenance capital expenditures	(24		)	(25		)	1			(59		)	(58		)	(1		)
Other	—			(2		)	2			—			(2		)	2
Portion of DCF adjustments attributable to Predecessor(2)	—			5			(5		)	2			8			(6		)
DCF	442			301			141			1,183			822			361
Preferred unit distributions	(16		)	(16		)	—			(49		)	(25		)	(24		)
DCF attributable to GP and LP unitholders	$	426		$	285		$	141		$	1,134		$	797		$	337

47

	Nine Months Ended September 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	$	1,338		$	975		$	363
Changes in working capital items	(41		)	59			(100		)
All other, net	(43		)	(18		)	(25		)
Non-cash equity-based compensation	10			9			1
Net gain on disposal of assets	1			1			—
Net interest and other financial costs	220			162			58
Current income taxes	1			4			(3		)
Asset retirement expenditures	2			4			(2		)
Unrealized derivative (gains) losses(1)	(2		)	23			(25		)
Acquisition costs	6			(1		)	7
Distributions of cash received from Joint-Interest Acquisition entities to MPC	(13		)	—			(13		)
Other adjustments to equity method investment distributions	8			—			8
Adjusted EBITDA	1,487			1,218			269
Adjusted EBITDA attributable to noncontrolling interests	(5		)	(3		)	(2		)
Adjusted EBITDA attributable to Predecessor(2)	(47		)	(187		)	140
Adjusted EBITDA attributable to MPLX LP	1,435			1,028			407
Deferred revenue impacts	25			8			17
Net interest and other financial costs	(220		)	(162		)	(58		)
Maintenance capital expenditures	(59		)	(58		)	(1		)
Other	—			(2		)	2
Portion of DCF adjustments attributable to Predecessor(2)	2			8			(6		)
DCF	1,183			822			361
Preferred unit distributions	(49		)	(25		)	(24		)
DCF attributable to GP and LP unitholders	$	1,134		$	797		$	337

(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.

(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 September 30, 2017 compared to three months ended September 30, 2016

Total revenues and other income increased$142 million in the third quarter of 2017 compared to the same period of 2016. This variance was due mainly to increased pricing on product sales of approximately $54 million, offset by an increased unrealized derivative loss of $10 million, higher revenues from volume growth of $49 million in the Marcellus and the Southwest areas,higher crude and product transportation volumes of $14 million, a $19 million increase from the acquisition of the Ozark pipeline, a $17 million increase from our equity method investments, mainly due to the acquisition of an equity interest in the Bakken Pipeline system, the addition of the Sherwood Midstream joint venture during 2017 and increased dry gas gathering volumes for certain of our equity method investments.

Cost of revenues increased$7 million in the third quarter of 2017 compared to the same period of 2016. This variance was primarily due to the acquisition of the Ozark pipeline.

48

Purchased product costs increased$53 million in the third quarter of 2017 compared to the same period of 2016. This variance was primarily due to higher NGL and gas prices of $36 million and increased volumes of $10 million, primarily in the Southwest area, as well as an increase in the unrealized loss of $6 million, of which a majority is related to our Natural Gas Embedded Derivative.

Depreciation and amortization expense increased$13 million in the third quarter of 2017 compared to the same period of 2016. This variance was primarily due to additions to in-service property, plant and equipment as well as approximately $2 million of accelerated depreciation related to adjustments of certain assets’ useful life.

Net interest expense and other financial costs increased$28 million in the third quarter of 2017 compared to the same period of 2016. The increase is mainly due to the New Senior Notes issued in February 2017.

Nine months endedSeptember 30, 2017 compared to nine months ended September 30, 2016

Total revenues and other income increased$601 million in the first nine months of 2017 compared to the same period of 2016. This variance was due mainly to the inclusion of $103 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 $177 million as well as higher revenues from volume growth of $146 million in the Marcellus and the Southwest areas, higher crude and product transportation volumes of $28 million, $45 million from the acquisition of the Ozark pipelineand a $12 million increase from our equity method investments. The nine months ended September 30, 2016 also included an impairment expense of $89 million related to our investment in Ohio Condensate as referenced in our 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.

Cost of revenues increased$52 million in the first nine months of 2017 compared to the same period of 2016. This variance was primarily due to $20 million from the inclusion of MPLXT, as well as $20 million from the acquisition of the Ozark pipeline and an increase in expenses related to the timing of projects.

Purchased product costs increased$131 million in the first nine months of 2017 compared to the same period of 2016. This variance was primarily due to higher NGL and gas prices and purchase volumes in the Southwest area, offset by a $13 million unrealized gain on our Natural Gas Embedded Derivative.

Purchases-related parties increased$44 million in the first nine months of 2017 compared to the same period of 2016. The increase was primarily due to the inclusion of approximately $23 million related party purchases of MPLXT as well as general increases in employee costs due to headcount.

Depreciation and amortization expense increased$77 million in the first nine months of 2017 compared to the same period of 2016. This variance was primarily due to accelerated depreciation expense of approximately $35 million incurred on the 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 during the fourth quarter of 2016 and the first nine months of 2017.

Impairment expense decreased$130 million in the first nine months of 2017 compared to the same period of 2016. This variance was due to a non-cash impairment to goodwill in two reporting units in the G&P segment during the first six months of 2016.

Net interest expense and other financial costs increased$62 million in the first nine months of 2017 compared to the same period of 2016. The increase is primarily due to the New Senior Notes issued in February 2017.

49

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 (losses) gains, 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. 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 September 30,							Nine Months Ended September 30,
(In millions)	2017		2016		Variance			2017		2016		Variance
Revenues and other income:
Segment revenues	$	378	$	339	$	39		$	1,095	$	901	$	194
Segment other income	11		12		(1		)	35		42		(7		)
Total segment revenues and other income	389		351		38			1,130		943		187
Costs and expenses:
Segment cost of revenues	176		153		23			500		392		108
Segment operating income before portion attributable to noncontrolling interests and Predecessor	213		198		15			630		551		79
Segment portion attributable to noncontrolling interests and Predecessor	—		74		(74		)	53		216		(163		)
Segment operating income attributable to MPLX LP	$	213	$	124	$	89		$	577	$	335	$	242

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

In the third quarter of 2017 compared to the same period of 2016, segment revenue increased primarily due to a $14 million increase from higher crude and product transportation volumes, a $19 million increase from the acquisition of the Ozark pipeline,a $4 million increase from the annual increase in fees and a $4 million increase from additional barges, partially offset by a $2 million decrease in the recognition of revenue related to volume deficiency payments.

In the third quarter of 2017 compared to the same period of 2016, segment cost of revenues increasedprimarily due to a $12 million increase from the acquisition of the Ozark pipeline, as well as from salaries and compensation due to headcount and other miscellaneous expenses.

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

Nine months endedSeptember 30, 2017 compared to nine months ended September 30, 2016

In the first nine months of 2017 compared to the same period of 2016, segment revenue increased primarily due to the inclusion of $103 million of revenue generated by MPLXT and its subsidiaries, a $28 million increase from higher crude and product transportation volumes,a $45 million increase from the acquisition of the Ozark pipeline, a $3 million increase due to the recognition of revenues related to volume deficiency payments,and a $10 million increase from additional barges.

50

In the first nine months of 2017 compared to the same period of 2016, segment cost of revenues increased primarily due to the acquisitions of MPLXT and the Ozark pipeline, increased expenses related to the timing of projects, salaries and compensation due to headcount, and other miscellaneous expenses.

In the first nine months of 2017 compared to the same period of 2016, the segment portion attributable to noncontrolling interests and Predecessor decreased due to the inclusion of HSM for the first three months of 2016 and the acquisition of HST, WHC and MPLXT as of March 1, 2017.

During both the third quarter and first nine months of 2017, MPC did not ship its minimum committed volumes on certain of our pipeline systems. As a result, for the first nine months, MPC was obligated to make a $37 million deficiency payment, of which $11 million was paid in the third quarter of 2017. We record deficiency payments as Deferred revenue-related parties on our Consolidated Balance Sheets. In the third quarter and first nine months of 2017, we recognized revenue of $7 million and $29 million, respectively, related to volume deficiency credits. At September 30, 2017, the cumulative balance of Deferred revenue-related parties on our Consolidated Balance Sheets related to volume deficiencies was $55 million. The following table presents the future expiration dates of the associated deferred revenue credits as of September 30, 2017:

(In millions)
December 31, 2017	$	8
March 31, 2018	11
June 30, 2018	11
September 30, 2018	10
December 31, 2018	4
March 31, 2019	3
June 30, 2019	4
September 30, 2019	4
Total	$	55

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 5.9 bcf/d of gathering capacity, 7.8 bcf/d of natural gas processing capacity and 570 mbpd of fractionation capacity.

	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2017		2016		Variance		2017		2016		Variance
Revenues and other income:
Segment revenues	$	669	$	567	$	102	$	1,869	$	1,595	$	274
Segment other income	1		1		—		2		1		1
Total segment revenues and other income	670		568		102		1,871		1,596		275
Costs and expenses:
Segment cost of revenues	276		239		37		781		662		119
Segment operating income before portion attributable to noncontrolling interests	394		329		65		1,090		934		156
Segment portion attributable to noncontrolling interests	45		36		9		119		113		6
Segment operating income attributable to MPLX LP	$	349	$	293	$	56	$	971	$	821	$	150

51

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

In the third quarter of 2017 compared to the same period of 2016, segment revenue increased due to increased pricing on product sales of approximately $46 million and increased volumes of $15 million, combined with increased fees of approximately $41 million on higher volumes due to new gathering and processing facilities in the Marcellus, Southwest, and Utica areas, as well as additional fractionation capacity in the Marcellus and Utica areas.

In the third 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 $28 million and increased volumes of $10 million primarily in the Southwest area partially offset by lower maintenance costs and other operating efficiencies.

Nine months ended September 30, 2017 compared to nine months ended September 30, 2016

In the first nine months of 2017 compared to the same period of 2016, segment revenue increased due to increased pricing on product sales of approximately $144 million and increased volumes of $38 million, combined with increased fees of approximately $92 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 nine 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 $102 million and higher volumes of $21 million primarily in the Southwest area partially offset by lower facility costs due to lower maintenance 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 interests to our consolidated net income attributable to noncontrolling interests for the three and nine months ended September 30, 2017 and 2016. Adjustments related to unconsolidated affiliates relate to our Partnership-operated non-wholly-owned entities that we consolidate for segment purposes. Income (loss) from equity method investmentsrelates to our portion of income (loss) from our unconsolidated joint ventures of which Partnership-operated joint ventures are consolidated for segment purposes. Other income-related parties consists of operational service fee revenues from our operated unconsolidated affiliates. Unrealized derivative activity is not allocated to segments.

	Three Months Ended September 30,									Nine Months Ended September 30,
(In millions)	2017			2016			Variance			2017			2016			Variance
Reconciliation to Income from operations:
L&S segment operating income attributable to MPLX LP	$	213		$	124		$	89		$	577		$	335		$	242
G&P segment operating income attributable to MPLX LP	349			293			56			971			821			150
Segment operating income attributable to MPLX LP	562			417			145			1,548			1,156			392
Segment portion attributable to unconsolidated affiliates	(47		)	(41		)	(6		)	(125		)	(130		)	5
Segment portion attributable to Predecessor	—			74			(74		)	53			216			(163		)
Income (loss) from equity method investments	23			6			17			29			(72		)	101
Other income - related parties	13			11			2			38			29			9
Unrealized derivative (losses) gains(1)	(17		)	(2		)	(15		)	2			(23		)	25
Depreciation and amortization	(164		)	(151		)	(13		)	(515		)	(438		)	(77		)
Impairment expense	—			—			—			—			(130		)	130
General and administrative expenses	(59		)	(56		)	(3		)	(174		)	(172		)	(2		)
Income from operations	$	311		$	258		$	53		$	856		$	436		$	420

52

	Three Months Ended September 30,									Nine Months Ended September 30,
(In millions)	2017			2016			Variance			2017			2016			Variance
Reconciliation to Total revenues and other income:
Total segment revenues and other income	$	1,059		$	919		$	140		$	3,001		$	2,539		$	462
Revenue adjustment from unconsolidated affiliates	(107		)	(100		)	(7		)	(287		)	(303		)	16
Income (loss) from equity method investments	23			6			17			29			(72		)	101
Other income - related parties	13			11			2			38			29			9
Unrealized derivative (losses) gains related to product sales(1)	(8		)	2			(10		)	1			(12		)	13
Total revenues and other income	$	980		$	838		$	142		$	2,782		$	2,181		$	601

(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 September 30,									Nine Months Ended September 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	$	45		$	110		$	(65	)	$	172		$	329		$	(157	)
Portion of noncontrolling interests and Predecessor related to items below segment income from operations	(21		)	(39		)	18			(84		)	(157		)	73
Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates	(23		)	(18		)	(5		)	(49		)	(20		)	(29		)
Net income attributable to noncontrolling interests and Predecessor	$	1		$	53		$	(52	)	$	39		$	152		$	(113	)

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 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. See Item 1. Business – Our G&P Contracts With Third Parties in our Annual Report on Form 10-K for the year ended December 31, 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 September 30, 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)
L&S	100	%	—	%	—	%
G&P(3)	86	%	12	%	2	%
Total	92	%	7	%	1	%

53

For the nine months ended September 30, 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)
L&S	100	%	—	%	—	%
G&P(3)	87	%	11	%	2	%
Total	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).

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

	Three Months Ended   September 30,						Nine Months Ended   September 30,
(In millions)	2017			2016			2017			2016
Reconciliation of net operating margin to income from operations:
Segment revenues	$	1,047		$	906		$	2,964		$	2,496
Purchased product costs	(170		)	(117		)	(441		)	(310		)
Total derivative loss related to purchased product costs	11			4			5			16
Other	(1		)	—			(5		)	(5		)
Net operating margin	887			793			2,523			2,197
Revenue adjustment from unconsolidated affiliates(2)	(107		)	(100		)	(287		)	(303		)
Realized derivative loss related to purchased product costs(1)	(2		)	(1		)	(6		)	(4		)
Other	2			1			6			4
Unrealized derivative (losses) gains(1)	(17		)	(2		)	2			(23		)
Income (loss) from equity method investments	23			6			29			(72		)
Other income	2			2			5			5
Other income - related parties	22			22			69			67
Cost of revenues (excludes items below)	(129		)	(122		)	(381		)	(329		)
Rental cost of sales	(19		)	(13		)	(44		)	(42		)
Rental cost of sales - related parties	—			—			(1		)	(1		)
Purchases - related parties	(114		)	(109		)	(330		)	(286		)
Depreciation and amortization	(164		)	(151		)	(515		)	(438		)
Impairment expense	—			—			—			(130		)
General and administrative expenses	(59		)	(56		)	(174		)	(172		)
Other taxes	(14		)	(12		)	(40		)	(37		)
Income from operations	$	311		$	258		$	856		$	436

(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.

(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.

54

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.

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 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.

55

OPERATING DATA

	Three Months Ended   September 30,				Nine Months Ended   September 30,
	2017		2016		2017		2016
L&S
Pipeline throughput (mbpd)(1)
Crude oil pipelines	2,046		1,775		1,901		1,665
Product pipelines	1,131		992		1,051		989
Total pipelines	3,177		2,767		2,952		2,654
Average tariff rates ($ per barrel)(1)(2)
Crude oil pipelines	$	0.54	$	0.55	$	0.57	$	0.57
Product pipelines	0.75		0.69		0.74		0.67
Total pipelines	0.62		0.60		0.63		0.61
Terminal throughput (mbpd)	1,496		1,517		1,470		1,510
Marine Assets (number in operation)(3)
Barges	232		217		232		217
Towboats	18		18		18		18
G&P
Gathering Throughput (MMcf/d)
Marcellus Operations	1,005		946		965		922
Utica Operations(4)	1,324		916		1,065		936
Southwest Operations(5)	1,400		1,444		1,385		1,455
Total gathering throughput	3,729		3,306		3,415		3,313
Natural Gas Processed (MMcf/d)
Marcellus Operations	3,986		3,273		3,778		3,166
Utica Operations(4)	1,000		1,050		982		1,068
Southwest Operations	1,331		1,339		1,310		1,209
Southern Appalachian Operations	264		244		266		248
Total natural gas processed	6,581		5,906		6,336		5,691
C2 + NGLs Fractionated (mbpd)
Marcellus Operations(6)	326		274		310		254
Utica Operations(4)(6)	39		41		40		43
Southwest Operations	18		19		19		17
Southern Appalachian Operations(7)	14		14		15		16
Total C2 + NGLs fractionated(8)	397		348		384		330
Pricing Information
Natural Gas NYMEX HH ($ per MMBtu)	$	2.96	$	2.80	$	3.05	$	2.34
C2 + NGL Pricing ($ per gallon)(9)	$	0.66	$	0.46	$	0.62	$	0.44

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

56

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

(3) Represents total at end of period.

(4) Includes unconsolidated equity method investments that are shown consolidated for segment purposes only.

(5) Includes approximately two MMcf/d related to the unconsolidated equity method investment, Wirth, for the three months endedSeptember 30, 2017, and 230 MMcf/d related to unconsolidated equity method investments, Wirth and MarkWest Pioneer, for the nine months ended September 30, 2017. Includes approximately 307 MMcf/d and 299 MMcf/d related to unconsolidated equity method investments, Wirth and MarkWest Pioneer, for the three and nine months ended September 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.

(8) Purity ethane makes up approximately 164 mbpd and 160 mbpd of total fractionated products for the three and nine months ended September 30, 2017, respectively, and approximately 137 mbpd and 125 mbpd of total fractionated products for the three and nine months ended September 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.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Our cash and cash equivalents balance was $3 million at September 30, 2017 compared to $234 million at December 31, 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:

	Nine Months Ended September 30,
(In millions)	2017			2016
Net cash provided by (used in):
Operating activities	$	1,338		$	975
Investing activities	(1,837		)	(892		)
Financing activities	268			82
Total	$	(231	)	$	165

Net cash provided by operating activities increased$363 million in the first nine months of 2017 compared to the first nine months of 2016, the majority of which is related to an increase in adjusted EBITDA of $269 million. The favorable change in adjusted EBITDA was driven primarily by higher prices and volumes, the inclusion of MPLXT, since it was not formed as a business until April 1, 2016, and the acquisition of the Ozark pipeline. In addition, there was an increase in distributions received from unconsolidated affiliates of $25 million due to the acquisition of an equity interest in the Bakken Pipeline system and the joint-interest acquisitions.

Net cash used in investing activities increased $945 million in the first nine months of 2017 compared to the first nine months of 2016, primarily due to the acquisition of an equity interest in the Bakken Pipeline system for $513 million, investments in other unconsolidated entities of approximately $177 million, $219 million for the acquisition of the Ozark pipeline, $30 million for the buy-out of an equity method investment partner, an increase in cash used for additions to property, plant and equipment related to various capital projects, as well as a net decrease of $23 million in investment loans with MPC. Partially offsetting these items was a return of capital of $24 million from our acquisition of equity interests in Sherwood Midstream and Sherwood Midstream Holdings.

Financing activities were a $268 million source of cash in the first nine months of 2017 compared to a $82 million source of cash in the first nine months of 2016. The source of cash in the first nine months of 2017 was primarily due to $2.2 billion of net proceeds from the New Senior Notes, $420 million of proceeds under the bank revolving credit facility, $128 million in contributions from noncontrolling interests and $483 million of net proceeds from sales of units under the ATM Program. These items were partially offset by distributions to MPC of $1.9 billion for the acquisition of HST, WHC, MPLXT and the Joint-

57

Interest Acquisition, $250 million repayment of the term loan facility, distributions of $49 million to Preferred unitholders, and increased distributions of $188 million to unitholders and our general partner due mainly to the increase in units outstanding as well as a 10 percent increase in the distribution per limited partner unit.

Debt and Liquidity Overview

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

(In millions)	September 30, 2017			December 31, 2016
MPLX LP:
Bank revolving credit facility due 2022	$	420		$	—
Term loan facility due 2019	—			250
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
MPL - capital lease obligations due 2020	7			8
Total	7,277			4,858
Unamortized debt issuance costs	(27		)	(7		)
Unamortized discount	(401		)	(428		)
Amounts due within one year	(1		)	(1		)
Total long-term debt due after one year	$	6,848		$	4,422

The increase in debt as of September 30, 2017 compared to year-end 2016 was due to the public offering of the New Senior Notes in the first quarter of 2017 and from borrowings on the intercompany loan with MPC and the bank revolving credit facility for general partnership purposes including the acquisitions of HST, WHC, MPLXT and the Joint-Interest Acquisition 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 with a $2.25 billion five-year bank revolving credit facility that expires in July 2022 (“MPLX Credit Agreement 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.

The MPLX Credit Agreement 2022 includes 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 2022) 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 September 30, 2017, we were in compliance with this financial covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of 3.4 to 1.0, as well as other covenants contained in the MPLX Credit Agreement 2022. As disclosed in Note 2 of the Notes to Consolidated Financial Statements, we expect the adoption of the lease accounting standards update to result in the recognition of a significant lease obligation. The MPLX Credit Agreement 2022 contains provisions under which the effects of the new accounting standard are not recognized for purposes of financial covenant calculation violations.

58

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

Rating Agency	Rating
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 2022 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 2022 and may limit our flexibility to obtain future financing.

Our liquidity totaled $2.1 billion at September 30, 2017 consisting of:

	September 30, 2017
(In millions)	Total Capacity		Outstanding Borrowings			Available Capacity
MPLX LP - bank revolving credit facility expiring 2022(1)	$	2,250	$	(423	)	$	1,827
MPC Investment - loan agreement	500		(202		)	298
Total liquidity	$	2,750	$	(625	)	$	2,125
Cash and cash equivalents						3
Total liquidity						$	2,128

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

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. From time to time, we may also consider other sources of liquidity, including the formation of joint ventures or sales of non-strategic assets.

Equity and Preferred Units Overview

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

(In units)	Common	Class B		General Partner	Total
Balance at December 31, 2016	357,193,288	3,990,878		7,371,105	368,555,271
Unit-based compensation awards	183,509	—		3,745	187,254
Issuance of units under the ATM Program	13,846,998	—		282,591	14,129,589
Contribution of HST/WHC/MPLXT	12,960,376	—		264,497	13,224,873
Contribution of the Joint-Interest Acquisition	18,511,134	—		377,778	18,888,912
Class B conversion	4,350,057	(3,990,878	)	7,330	366,509
Balance at September 30, 2017	407,045,362	—		8,307,046	415,352,408

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

On July 1, 2017, all of the remaining 3,990,878 Class B units automatically converted into 1.09 MPLX LP common units and the right to receive $6.20 per unit in cash. MPC funded this cash payment, which reduced our liability payable to Class B

59

unitholders by approximately $25 million on July 1, 2017. As a result of the Class B units conversion on July 1, 2017, MPLX GP contributed less than $1 million in exchange for 7,330 general partner units to maintain its two percent general partner interest. As common units outstanding as of the August 7, 2017 record date, the converted Class B units participated in the second quarter distribution.

The Partnership expects the net proceeds from sales under the ATM Program will be used for general partnership purposes including repayment or refinancing of debt and funding for acquisitions, working capital requirements and capital expenditures. During the nine months ended September 30, 2017, the sale of common units under the ATM Program generated net proceeds of approximately $473 million. As of September 30, 2017, $1.7 billion of common units remain available for issuance through the ATM Program under the Distribution Agreement.

MPC agreed to waive two-thirds of the first quarter 2017 distributions on the common units issued in connection with the acquisition of HST, WHC and MPLXT. As a result of this waiver, MPC did not receive general partner distributions or IDRs that would have otherwise accrued on such common units with respect to 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 the Bakken Pipeline system on February 15, 2017, MPC agreed to waive its 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 of 2017, which was prorated from the acquisition date. Lastly, MPC agreed to waive two-thirds of the third quarter 2017 distributions on the common units issued in connection with the Joint-Interest Acquisition. As a result of this waiver, MPC did not receive the distributions or IDRs that would have otherwise accrued on such common units with respect to the third quarter 2017 distributions. The value of these waived distributions was $10 million.

We intend to pay at least the minimum quarterly distribution of $0.2625 per unit per quarter, which equates to $109 million per quarter, or $436 million per year, based on the number of common and general partner units outstanding at September 30, 2017. On October 25, 2017, we announced the board of directors of our general partner had declared a distribution of $0.5875 per unit that will be paid on November 14, 2017 to unitholders of record on November 6, 2017. This represents an increase of $0.0250 per unit, or four percent, above the second quarter 2017 distribution of $0.5625 per unit and an increase of 14 percent over the third quarter 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 nine months ended September 30, 2017 and 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 September 30,				Nine Months Ended September 30,
(In millions)	2017		2016		2017		2016
Distribution declared:
Limited partner units - public	$	170	$	135	$	481	$	393
Limited partner units - MPC	54		44		152		114
Limited partner units - GP	8		—		15		—
General partner units - MPC	7		5		18		13
IDRs - MPC	81		49		211		135
Total GP & LP distribution declared	320		233		877		655
Redeemable preferred units	16		16		49		25
Total distribution declared	$	336	$	249	$	926	$	680
Cash distributions declared per limited partner common unit	$	0.5875	$	0.5150	$	1.6900	$	1.5300

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 limited to, the availability of sufficient cash flow to pay distributions and execute our business plan; negative capital market conditions, including an increase of the current yield on common units; the timing and extent of changes in commodity prices

60

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, 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 Partnership's plans for funding the dropdowns include debt and equity in approximately equal proportions, with the equity financing to be funded through transactions with MPC. In conjunction with the completion of the dropdowns, MPC announced its intentions to offer to exchange its IDRs and two percent GP Interest for common units. Following these transactions, we expect to internally fund a greater portion of our future growth from internal cash flows. 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. The second drop of assets contributing approximately $138 million of annual EBITDA took place in the third quarter of 2017 and was financed through cash and equity, as discussed in Note 3 of the Notes to Consolidated Financial Statements. The remaining dropdown, which includes refinery logistics assets and fuels distribution services, with projected annual EBITDA of approximately $1.0 billion has been offered to the Partnership and referred to the conflicts committee of the board of directors of our general partner. The transaction is expected to close no later than the end of the first quarter of 2018.

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.

61

Our capital expenditures are shown in the table below:

	Nine Months Ended September 30,
(In millions)	2017		2016
Capital expenditures:
Maintenance	$	59	$	58
Expansion	1,002		889
Total capital expenditures	1,061		947
Less: Increase in capital accruals	55		—
Asset retirement expenditures	2		4
Additions to property, plant and equipment	1,004		943
Capital expenditures of unconsolidated subsidiaries(1)	306		94
Total gross capital expenditures	1,310		1,037
Less: Joint venture partner contributions(2)	132		45
Total capital expenditures, net	1,178		992
Less: Maintenance capital	60		58
Total growth capital	$	1,118	$	934

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

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

Our organic growth capital plan range has not been revised for the remainder of 2017. We anticipate finishing the year near below the previously reported range. This range excludes acquisition costs for the dropdowns of HST, WHC, MPLXT and the Joint-Interest Acquisition, the acquisition of the Ozark pipeline and the MarEn Bakken investment, as discussed in Notes 3 and 4 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, a 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 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.

Contractual Cash Obligations

As of September 30, 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 nine months ended September 30, 2017, our long-term debt obligations increased by $4.1 billion due to the new senior notes issued and contracts to acquire property, plant and equipment increased $317 million largely due to new and growing projects. There were no other material changes to these obligations outside the ordinary course of business since December 31, 2016.

Off-Balance Sheet Arrangements

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

62

Forward-looking Statements

Our opinions concerning liquidity and capital resources and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors, including cash provided by operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and 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 dropdown from MPC and the proposed exchange of common units for MPC’s economic interests in the general partner, the joint venture with Antero Midstream, 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 and/or the economic interests in the general partner; 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 products; delays in obtaining necessary third-party approvals and governmental permits; changes in labor, material and equipment costs and availability; planned and unplanned outages, the delay of, cancellation of or failure to implement planned capital projects; project overruns, disruptions or interruptions of our operations due to the shortage of skilled labor; unforeseen hazards such as weather conditions, acts of war or terrorist acts and the governmental or military 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 September 30, 2017, MPC held a two percent GP Interest and a 28.4 percent limited partner interest 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 36 percent and 40 percent of our total revenues and other income for the third quarter of 2017 and 2016, 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 22 percent and 25 percent for the third quarter of 2017 and 2016, 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 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, 2016 and Note 5 of the Notes to Consolidated Financial Statements in this report.

63

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.

As of September 30, 2017, there have been no significant changes to our environmental matters and compliance costs since our 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.

CRITICAL ACCOUNTING ESTIMATES

As of September 30, 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, 2016, as updated by our Current Report on Form 8-K filed on May 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.

64

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 nine months ended September 30, 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, 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 September 30, 2017, including the weighted-average prices (“WAVG”):

WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2017 (Oct - Dec)	200	$	54.25	$	42

Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2017 (Oct - Dec)	1,832	$	3.03	$	(30	)
2018	2,542	$	2.78	$	4

Ethane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2017 (Oct - Dec)	54,600	$	0.27	$	(47	)

Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2017 (Oct - Dec)	119,932	$	0.61	$	(3,164	)
2018	16,925	$	0.64	$	(506	)

IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2017 (Oct - Dec)	10,730	$	0.81	$	(236	)
2018	1,655	$	0.80	$	(38	)

Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2017 (Oct - Dec)	31,622	$	0.75	$	(823	)
2018	4,595	$	0.75	$	(120	)

Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2017 (Oct - Dec)	41,827	$	1.13	$	(346	)
2018	3,089	$	1.18	$	(20	)

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

65

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 September 30, 2017, the estimated fair value of this contract was a liability of $52 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 through the fourth quarter of 2018. The contract’s pricing is currently fixed through the fourth quarter of 2017 with the ability to fix the pricing for its remaining year. Changes in the fair value as of the derivative component of this contract were recognized as Cost of Revenues in the Consolidated Statements of Income. As of September 30, 2017, the estimated fair value of this contract was a liability of less than $1 million.

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 September 30, 2017(1)		Change in Fair Value(2)		Change in Income Before Income Taxes for the Nine Months Ended September 30, 2017(3)
Long-term debt
Fixed-rate	$	7,199	$	575	N/A
Variable-rate	$	420	N/A		$	2

(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 September 30, 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 nine months ended September 30, 2017.

At September 30, 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 facilities, but may affect our results of operations and cash flows. As of September 30, 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 September 30, 2017, the end of the period covered by this report.

Changes in Internal Control Over Financial Reporting

During the quarter ended September 30, 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.

66

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.

As previously reported in our Annual Report on Form 10-K for the year ended December 31, 2016, in July 2015, representatives from the EPA and the United States Department of Justice 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’s launcher/receiver, pipeline and compressor station operations. In response to 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 Occupational Safety and Health Administration. After providing these studies, and other substantial documentation related to MarkWest Liberty Midstream's pipeline and compressor stations, 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 this matter.

MarkWest Liberty Midstream continues to discuss with the EPA and the State of Pennsylvania civil enforcement allegations associated with 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 received an initial proposal from the EPA to settle all civil 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. In connection with these negotiations, MarkWest Liberty Midstream has received a revised settlement proposal from the EPA which proposes to lower the proposed cash penalty to approximately $1.24 million and the estimated cost of proposed supplemental environmental projects to an estimated cost of approximately $1.6 million. MarkWest Liberty Midstream will continue to negotiate with EPA regarding the amount and scope of the proposed settlement.

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, 2016.

67

Item 2. Unregistered Sales of Equity Securities

In connection with the issuance of 14,887 common units upon the vesting of phantom units under the MPLX LP 2012 Incentive Compensation Plan, 359,179 common units as a result of the conversion of Class B units to common units and 1,184,335 common units under the ATM Program, our general partner purchased an aggregate of 31,803 general partner units for $1,059,390.81 in cash during the three months ended September 30, 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.

On September 1, 2017, in connection with the Joint-Interest Acquisition, we issued 377,778 general partner units to our general partner. The number of general partner units issued were calculated by dividing $12,600,000 by 33.3529, the simple average of the ten day trading volume weighted average NYSE price of an MPLX LP common unit for the ten trading days ending at market close on August 31, 2017. 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.

Item 5. Other Information

Amended Restricted Stock Award Agreement

On October 26, 2017, C. Corwin Bromley entered into an Amended Restricted Stock Award Agreement with MPC (the “Amended Award Agreement”) to provide for the immediate vesting of a restricted stock award upon Mr. Bromley’s retirement effective January 1, 2018, which was announced by MPLX LP (the “Partnership”) on August 4, 2017. Mr. Bromley was a named executive officer in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2016.

The foregoing description of the Amended Award Agreement is summary in nature and subject to, and qualified in its entirety by, the full text of the Amended Award Agreement, a copy of which is attached as Exhibit 10.2 to this Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017 and is incorporated herein by reference.

MPLX LP Executive Change in Control Severance Benefits Plan

Effective October 26, 2017, the board of directors of Marathon Petroleum Corporation (the “Corporation”) and the board of directors of MPLX GP LLC, the general partner (the “General Partner”) of MPLX LP (“the Partnership”), adopted the MPLX LP Executive Change in Control Severance Benefits Plan (the “MPLX Plan”).

The purpose of the MPLX Plan is to recognize the contributions of the senior executives who provide services to the Corporation or the Partnership and to assure the continued provision of services by these senior executives. The MPLX Plan is intended to operate as a companion plan to the Marathon Petroleum Corporation Amended and Restated Executive Change in Control Severance Benefits Plan (the “MPC Plan”). It is intended that the MPLX Plan shall not result in a duplication of benefits in the event a participant would be eligible to receive benefits under both the MPLX Plan and the MPC Plan. The following is a summary of the MPLX Plan:

• The MPLX Plan applies to certain senior executives who provide services to the Partnership, the Corporation or any of their respective subsidiaries or affiliates.

• A participant is generally entitled to receive benefits under the MPLX Plan if within two years following a Partnership Change in Control (as defined in the MPLX Plan), the participant’s employment is terminated without cause or for good reason, with good reason generally being defined in the MPLX Plan as a reduction in the participant’s roles, responsibilities, pay or benefits or the participant is required to relocate more than 50 miles from his or her current location. However, benefits are not payable if the termination is for cause or due to mandatory retirement, death, disability or resignation (other than for good reason) by the participant.

• In addition to any earned but unpaid salary, a lump sum cash amount equal to the value of the participant’s unused vacation days and any normal post-termination compensation and benefits under the retirement, insurance and other compensation and benefit plans in which the participant participates, upon a Partnership Change in Control and Qualified Termination (as defined in the MPLX Plan), participants are eligible to receive: (i) a cash payment equal to three times the sum of the participant’s base salary and the highest bonus paid in the three years before the Qualified Termination or, if higher, in the three years before the Partnership Change in Control; (ii) life and health insurance benefits for up to 36 months after termination at the active employee cost; (iii) benefits that are equivalent to the retiree medical and life benefit provided under the MPC Plan; and (iv) a cash payment that is equivalent to the supplemental retirement benefit and supplemental savings benefit provided under the MPC Plan.

68

• Participants who incur a Qualified Termination or who separate from service with all of the Partnership, the General Partner and any applicable buyer or successor entity within two years after the Partnership Change in Control under circumstances that would have resulted in a Qualified Termination had such separation occurred at the time of the Partnership Change in Control and participants who remain in service with the Corporation (and its affiliates) following the Partnership Change in Control may become eligible for the following benefits: (i) all Partnership equity awards that vest based solely upon the passage of time will be become vested and exercisable; and (ii) all Partnership equity awards that vest based on the attainment of performance goals will become vested as to the entire award with payment as follows (a) with respect to the period prior to the Partnership Change in Control (“Pre-CiC Period”), the award will be determined using actual performance during the Pre-CiC Period; and (b) with respect to the period after the Partnership Change in Control, the award will be determined assuming performance goals were satisfied at target levels. Participants who incur a Qualified Termination and participants who remain in or commence services with the Partnership, General Partner or any applicable buyer or successor entity (or any of their affiliates) following the Partnership Change in Control are eligible for the following benefits: (i) all Corporation equity awards will become vested and exercisable; (ii) the vesting of any Corporation equity awards that otherwise would vest based on the attainment of performance goals shall remain subject to the attainment of applicable performance goals at the end of the regularly scheduled performance period.

• The Corporation and the General Partner may at any time amend or terminate the MPLX Plan, provided that, for a period of two years following a Partnership Change in Control, the MPLX Plan may not be amended in a manner adverse to a participant with respect to that Partnership Change in Control. Any amendment or termination shall be set out in an instrument in writing and executed by an appropriate officer.

The foregoing description of the MPLX Plan is summary in nature and subject to, and qualified in its entirety by, the full text of the MPLX Plan, a copy of which is attached as Exhibit 10.3 to this Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017 and is incorporated herein by reference.

69

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 and Shares Contributions Agreement, dated September 1, 2017, between MPLX LP, MPLX Logistics Holdings LLC, MPLX Holdings Inc., MPLX GP LLC and MPC Investment LLC	8-K	2.1	9/1/2017	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
3.3	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	Credit Agreement, dated as of July 21, 2017, among MPLX LP, as borrower, Wells Fargo Bank, National Association, as administrative agent, each of Wells Fargo Securities, LLC, JPMorgan Chase Bank, N.A., Barclays Bank PLC, Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Mizuho Bank, Ltd., The Bank of Tokyo-Mitsubishi UFJ, Ltd. and RBC Capital Markets, as joint lead arrangers and joint bookrunners, JPMorgan Chase Bank, N.A., as syndication agent, each of Bank of America, N.A., Barclays Bank PLC, Citigroup Global Markets Inc., Mizuho Bank, Ltd., The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Royal Bank of Canada, as documentation agents, and the other lenders and issuing banks that are parties thereto.	8-K	10.1	7/27/2017	001-35714
10.2	Amended Restricted Stock Award Agreement					X
10.3	MPLX LP Executive Change in Control Severance Benefits Plan					X
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

70

		Incorporated by Reference
Exhibit Number	Exhibit Description	Form	Exhibit	Filing Date	SEC File No.	Filed Herewith	Furnished Herewith
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
101.LAB	XBRL Taxonomy Extension Label Linkbase					X
101.PRE	XBRL Taxonomy Extension Presentation Linkbase					X

71

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: October 30, 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)

72