MPLX - 10-Q quarterly report FY2017 Q2

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________________________________________

FORM 10-Q

_____________________________________________

(Mark One)



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

For the Quarterly Period Ended June 30, 2017



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

For the transition period from to

Commission file number 001-35714

_____________________________________________

MPLX LP

(Exact name of registrant as specified in its charter)

_____________________________________________



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

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

(419) 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 388,521,088 common units and 7,929,000 general partner units outstanding at July 27, 2017.

MPLX LP

Form 10-Q

Quarter Ended June 30, 2017

INDEX

Unless the context otherwise requires, references in this report to “MPLX LP,” “the Partnership,” “we,” “our,” “us,” or like terms refer to MPLX LP and its subsidiaries, including MPLX Operations LLC (“MPLX Operations”), MPLX Terminal and Storage LLC (“MPLX Terminal and Storage”), MarkWest Energy Partners, L.P. (“MarkWest”), MarkWest Hydrocarbon, L.L.C. (“MarkWest Hydrocarbon”), 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 Pioneer, L.L.C. (“MarkWest Pioneer”), MarkWest Utica EMG, L.L.C. (“MarkWest Utica EMG”) and its subsidiary Ohio Gathering Company, L.L.C. (“Ohio Gathering”), Ohio Condensate Company, L.L.C. (“Ohio Condensate”), Wirth Gathering Partnership (“Wirth”), MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. (“Jefferson Dry Gas”), Sherwood Midstream LLC (“Sherwood Midstream”), Sherwood Midstream Holdings LLC (“Sherwood Midstream Holdings”), MarEn Bakken Company, LLC (“MarEn Bakken”), Johnston County Terminal, LLC (“Johnston Terminal”) and Guilford County Terminal Company, LLC (“Guilford Terminal”). References to “MPC” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other than the Partnership. 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.

Glossary of Terms

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



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

Part I—Financial Information

Item 1. Financial Statements

MPLX LP

Consolidated Statements of Income (Unaudited)



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


(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.

MPLX LP

Consolidated Balance Sheets (Unaudited)



(In millions)	June 30, 2017			December 31, 2016
Assets
Current assets:
Cash and cash equivalents	$	293		$	234
Receivables, net	284			299
Receivables - related parties	173			247
Inventories	62			55
Other current assets	31			33
Total current assets	843			868
Equity method investments	3,368			2,471
Property, plant and equipment, net	11,638			11,408
Intangibles, net	473			492
Goodwill	2,245			2,245
Long-term receivables - related parties	16			11
Other noncurrent assets	18			14
Total assets	$	18,601		$	17,509
Liabilities
Current liabilities:
Accounts payable	$	144		$	140
Accrued liabilities	178			232
Payables - related parties	93			87
Deferred revenue	3			2
Deferred revenue - related parties	39			38
Accrued property, plant and equipment	171			146
Accrued taxes	39			38
Accrued interest payable	94			53
Other current liabilities	29			27
Total current liabilities	790			763
Long-term deferred revenue	26			12
Long-term deferred revenue - related parties	33			19
Long-term debt	6,666			4,422
Deferred income taxes	7			6
Deferred credits and other liabilities	170			177
Total liabilities	7,692			5,399
Commitments and contingencies (see Note 17)
Redeemable preferred units	1,000			1,000
Equity
Common unitholders - public (284 million and 271 million units issued and outstanding)	8,360			8,086
Class B unitholders (4 million and 4 million units issued and outstanding)	133			133
Common unitholder - MPC (90 million and 86 million units issued and outstanding)	1,161			1,069
Common unitholder - GP (9 million and 0 units issued and outstanding)	351			—
General partner - MPC (8 million and 7 million units issued and outstanding)	(242		)	1,013
Equity of Predecessor	—			791
Total MPLX LP partners’ capital	9,763			11,092
Noncontrolling interests	146			18
Total equity	9,909			11,110
Total liabilities, preferred units and equity	$	18,601		$	17,509

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

MPLX LP

Consolidated Statements of Cash Flows (Unaudited)



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


(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.

MPLX LP

Consolidated Statements of Equity (Unaudited)



	Partnership
(In millions)	Common Unitholders Public			Class B Unitholders Public		Common Unitholder MPC			Common Unitholder GP			General Partner MPC			Non-controlling Interests			Equity of Predecessor⁽¹⁾			Total
Balance at December 31, 2015	$	7,691		$	266	$	465		$	—		$	819		$	13		$	692		$	9,946
Distributions to MPC from Predecessor	—			—		—			—			—			—			(104		)	(104		)
Issuance of units under ATM Program	315			—		—			—			6			—			—			321
Net (loss) income	(107		)	—		(28		)	—			85			1			98			49
Allocation of MPC's net investment at acquisition	—			—		669			—			(337		)	—			(332		)	—
Distributions to unitholders and general partner	(248		)	—		(57		)	—			(86		)	—			—			(391		)
Distributions to noncontrolling interests	—			—		—			—			—			(1		)	—			(1		)
Contributions from noncontrolling interests	—			—		—			—			—			2			—			2
Non-cash contribution from MPC	—			—		—			—			—			—			334			334
Equity-based compensation	5			—		—			—			—			—			—			5
Deferred income tax impact from changes in equity	2			—		—			—			(2		)	—			—			—
Balance at June 30, 2016	$	7,658		$	266	$	1,049		$	—		$	485		$	15		$	688		$	10,161

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


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

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

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.

The Partnership’s business consists of two segments based on the nature of services it offers: Logistics and Storage (“L&S”) focused on crude oil and refined petroleum products and Gathering and Processing (“G&P”) focused on natural gas and NGLs. See Note 9 for additional information regarding operations.

Basis of Presentation – The Partnership’s consolidated financial statements include all majority-owned and controlled subsidiaries. For non-wholly-owned consolidated subsidiaries, the interests owned by third parties 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 HST, WHC and MPLXT (collectively with 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 at historical cost. 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 for until declared. However, when distributions related to the incentive distribution rights are made, earnings equal to the amount of those distributions are first allocated to the general partner before the remaining earnings are allocated to the limited partner unitholders based on their respective ownership percentages. The allocation of net income attributable to MPLX LP for purposes of calculating net income per limited partner unit is described in Note 6.

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

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

2. Accounting Standards

Recently Adopted

In October 2016, the FASB issued an accounting standard 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 standard update in the first quarter of 2017 and it did not have an impact on the consolidated financial statements.

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

Not Yet Adopted

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

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

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

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

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

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

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

In February 2016, the FASB issued an accounting standard update requiring lessees to record virtually all leases on their balance sheets. The accounting standard update also requires expanded disclosures to help financial statement users better understand the amount, timing and uncertainty of cash flows arising from leases. For lessors, this amended guidance modifies the classification criteria and the accounting for sales-type and direct financing leases. The change will be effective on a 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 generate a right of use asset and lease obligation.

In January 2016, the FASB issued an accounting standard update requiring unconsolidated equity investments, not accounted for under the equity method, to be measured at fair value with changes in fair value recognized in net income. The 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 standard update requires separate presentation in other comprehensive income of the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when electing to measure the liability at fair value in accordance with the fair value option for financial instruments. The changes are effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. Early adoption is permitted only for guidance regarding presentation of the liability’s credit risk. The application of this accounting standard update will not have a material impact on the Partnership’s consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09 which created Accounting Standards Codification (“ASC”) Topic 606, “Revenue from Contracts with Customers” (“ASC 606”). The guidance in the 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 years, with early adoption permitted no earlier than January 1, 2017.

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 is substantially complete; however, the Partnership continues to evaluate our accounting for certain items such as principal versus agent treatment in relation to commodity sales.

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

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

3. Acquisitions

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

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

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

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

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



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


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



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


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

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



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

Acquisition of Ozark Pipeline

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

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



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

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

Acquisition of Hardin Street Marine LLC

On March 14, 2016, the Partnership entered into a Membership Interests Contribution Agreement (the “Contribution Agreement”) with MPLX GP, 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 MPLX LP common units issued in connection with this transaction. As a result of this waiver, MPC did not receive general partner distributions or incentive distribution rights that would have otherwise accrued on such MPLX LP common units with respect to the first quarter 2016 distributions. The value of these waived distributions was $15 million.

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

4. Investments and Noncontrolling Interests

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



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



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


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


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

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



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



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


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

As of June 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.

MarkWest Utica EMG

Effective January 1, 2012, MarkWest Utica Operating Company, LLC (“Utica Operating”), a wholly-owned and consolidated subsidiary of MarkWest, and EMG Utica (together the “Members”) executed agreements to form a joint venture, MarkWest Utica EMG, to develop significant natural gas gathering, processing and NGL fractionation, transportation and marketing infrastructure in eastern Ohio. The related limited liability company agreement has been amended from time to time (the limited liability company agreement currently in effect is referred to as the “Amended LLC Agreement”). The aggregate funding commitment of EMG Utica was $950 million (the “Minimum EMG Investment”). Thereafter, Utica Operating was required to fund, as needed, 100 percent of future capital for MarkWest Utica EMG until 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 June 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 $8 million for the three and six months ended June 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 June 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 June 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 six months ended June 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 six months ended June 30, 2017, totaled approximately $4 million and $8 million, respectively. The amount of Operational Service revenue related to MarkWest Utica EMG for the three and six months ended June 30, 2016, totaled $5 million and $7 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 June 30, 2017, the Partnership has an approximate 34 percent indirect ownership interest in Ohio Gathering. As Ohio Gathering is a subsidiary of MarkWest Utica EMG, which is accounted for as an equity method investment, the Partnership reports its portion of Ohio Gathering’s net assets as a component of its investment in MarkWest Utica EMG. The Partnership receives Operational Service revenue for operating Ohio Gathering which is reported as Other income-related parties in the Consolidated Statements of Income. The amount of Operational Service revenue related to Ohio Gathering for the three and six months ended June 30, 2017, was approximately $4 million and $8 million, respectively. The amount of Operational Service revenue related to Ohio Gathering for the three and six months ended June 30, 2016, totaled $3 million and $7 million, respectively.

Sherwood Midstream

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

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

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

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

Sherwood Midstream is deemed to be a VIE. MarkWest Liberty Midstream is not deemed to be the primary beneficiary, due to Antero Midstream’s voting rights on significant matters. The Partnership’s investment in Sherwood Midstream, which was approximately $192 million at June 30, 2017, is reported under the caption Equity method investments on the Consolidated Balance Sheets. The Partnership’s maximum exposure to loss as a result of its involvement with Sherwood Midstream includes its equity investment, any additional capital contribution commitments and any operating expenses incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. The Partnership did not provide any financial support to Sherwood Midstream that it was not contractually obligated to provide during the six months ended June 30, 2017. The Partnership receives Operational Service revenue for operating Sherwood Midstream. The amount of Operational Service revenue related to Sherwood Midstream for the three and six months ended June 30, 2017 totaled approximately $3 million and $4 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, 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 three months ended June 30, 2017, true-ups to the initial contributions were made. MarkWest Liberty Midstream contributed certain additional real property, equipment and facilities with a fair value of approximately $10 million to Sherwood Midstream Holdings and Sherwood Midstream contributed cash of approximately $4 million to Sherwood Midstream Holdings. Collectively, the real property, equipment, facilities and cash initially contributed, or that may be subsequently constructed by or contributed, to Sherwood Midstream Holdings are referred to as the “Shared Assets.” The net book value of the contributed assets was approximately $203 million. The contribution was determined to be an in-substance sale of real estate. As such, the Partnership 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 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 Asset, 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 $165 million at June 30, 2017, is reported under the caption Equity method investments on the Consolidated Balance Sheets. The Partnership’s maximum exposure to loss as a result of its involvement with Sherwood Midstream 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 six months ended June 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 June 30, 2017, the Partnership has a 13.9 percent indirect ownership interest in Sherwood Midstream Holdings through Sherwood Midstream.

MarEn Bakken

On February 15, 2017, the Partnership closed on a joint venture, MarEn Bakken, with Enbridge Energy Partners L.P. (“Enbridge Energy Partners”) in which MPLX LP acquired a partial, indirect interest in the Dakota Access Pipeline (“DAPL”) and Energy Transfer Crude Oil Company Pipeline (“ETCOP”) projects, collectively referred to as the Bakken Pipeline system, from Energy Transfer Partners, L.P. (“ETP”) and Sunoco Logistics Partners, L.P. (“SXL”). The Partnership contributed $500 million of the $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 based on the most recent available information. The Partnership’s investment balance at June 30, 2017 is approximately $519 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, which was prorated to $0.8 million from the acquisition date.

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 June 30, 2017. Centennial owns a products pipeline and storage facility.


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


•	MarkWest Utica EMG, in which MPLX LP has a 56 percent interest as of June 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 June 30, 2017. Ohio Gathering is a subsidiary of MarkWest Utica EMG providing natural gas gathering service in the Utica Shale region of eastern Ohio.


•	Sherwood Midstream, in which MPLX LP has a 50 percent interest as of June 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 at June 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.

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 six months ended June 30, 2017, the Partnership borrowed $12 million and repaid $12 million, resulting in no outstanding balance at June 30, 2017. Borrowings were at an average interest rate of 2.270 percent, per annum, for the six months ended June 30, 2017. During the year ended December 31, 2016, the Partnership borrowed $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.

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 June 30,				Six Months Ended June 30,
(In millions)	2017		2016		2017		2016
Service revenues
MPC	$	270	$	246	$	525	$	423
Rental income
MPC	$	70	$	66	$	137	$	104
Product sales⁽¹⁾
MPC	$	2	$	3	$	4	$	6

(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 six months ended June 30, 2017, these sales totaled $53 million and $110 million, respectively. For the three and six months ended June 30, 2016, these sales totaled $7 million and $12 million, respectively.

Related party sales to MPC consist of crude oil and refined products pipeline transportation services based on regulated tariff rates, storage services based on contracted rates and transportation services provided by HSM. Under the Partnership’s pipeline transportation services agreements, if MPC fails to transport its minimum throughput volumes during any quarter, then MPC will pay the Partnership a deficiency payment equal to the volume of the deficiency multiplied by the tariff rate then in effect. The deficiency amounts are recorded as Deferred revenue-related parties. MPC may then apply the amount of any such deficiency payments as a credit for volumes transported on the applicable pipeline system in excess of its minimum volume commitment during the following four or eight quarters under the terms of the applicable transportation services agreement. The Partnership recognizes revenues for the deficiency payments when credits are used for volumes transported in excess of minimum quarterly volume commitments, when it becomes impossible to physically transport volumes necessary to utilize the credits or upon the expiration of the credits. The use or expiration of the credits is a decrease in Deferred revenue-related parties.

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



	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2017		2016		2017		2016
MPC	$	10	$	12	$	21	$	26
MarkWest Utica EMG	4		5		8		7
Ohio Gathering	4		3		8		7
Other	7		4		10		5
Total	$	25	$	24	$	47	$	45

MPC provides executive management services and certain general and administrative services to the Partnership under the terms of an omnibus agreement. Expenses incurred under this agreement are shown in the table below by the income statement line where they were recorded. Charges for services included in Purchases-related parties primarily relate to services that support the Partnership’s operations and maintenance activities, as well as compensation expenses. Charges for services included in General and administrative expenses primarily relate to services that support the Partnership’s executive management, accounting and human resources activities. These charges were as follows:



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

Also under terms of the omnibus agreement, some service costs related to engineering services are associated with assets under construction. These costs added to Property, plant and equipment were as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2017		2016		2017		2016
MPC	$	12	$	12	$	22	$	22

MPLX LP obtains employee services from MPC under employee services agreements. Expenses incurred under these agreements are shown in the table below by the income statement line where they were recorded. The costs of personnel directly involved in or supporting operations and maintenance activities are classified as Purchases-related parties. The costs of personnel involved in executive management, accounting and human resources activities are classified as General and administrative expenses in the Consolidated Statements of Income.

Employee services expenses from related parties were as follows:



	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2017		2016		2017		2016
Purchases - related parties	$	91	$	88	$	183	$	159
General and administrative expenses	24		27		49		48
Total	$	115	$	115	$	232	$	207

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



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

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



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

Payables to related parties were as follows:



(In millions)	June 30, 2017		December 31, 2016
MPC	$	74	$	63
MarkWest Utica EMG	15		24
Other	4		—
Total	$	93	$	87

During the six months ended June 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)	June 30, 2017		December 31, 2016
Minimum volume deficiencies - MPC	$	51	$	48
Project reimbursements - MPC	21		9
Total	$	72	$	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 incentive distribution rights (“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 and six months ended June 30, 2017 and 2016, the Partnership had dilutive potential common units consisting of certain equity-based compensation awards and Class B units. Potential common units omitted from the diluted earnings per unit calculation for the three and six months ended June 30, 2017 were less than one million and for three and six months ended June 30, 2016 were approximately 10 million.



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


(1)	See Note 7 for distribution information.



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



	Three Months Ended June 30, 2016
(In millions, except per unit data)	General Partner			Limited Partners’ Common Units			Redeemable Preferred Units		Total
Basic and diluted net income (loss) attributable to MPLX LP per unit:
Net income (loss) attributable to MPLX LP:
Distributions declared (including IDRs)	$	50		$	172		$	9	$	231
Undistributed net loss attributable to MPLX LP	(5		)	(207		)	—		(212		)
Net income (loss) attributable to MPLX LP⁽¹⁾	$	45		$	(35	)	$	9	$	19
Weighted average units outstanding:
Basic	7			331			17		355
Diluted	7			331			17		355
Net loss attributable to MPLX LP per limited partner unit:
Basic				$	(0.11	)
Diluted				$	(0.11	)



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



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


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

7. Equity

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



(In units)	Common	Class B⁽¹⁾	General Partner	Total
Balance at December 31, 2016	357,193,288	3,990,878	7,371,105	368,555,271
Unit-based compensation awards⁽²⁾	168,622	—	3,441	172,063
Issuance of units under the ATM Program⁽³⁾	12,662,663	—	258,422	12,921,085
Contribution of HST/WHC/MPLXT⁽⁴⁾	12,960,376	—	264,497	13,224,873
Balance at June 30, 2017	382,984,949	3,990,878	7,897,465	394,873,292


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


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


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


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

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 incentive distribution rights are made, earnings equal to the amount of those distributions are first allocated to the general partner before the remaining earnings are allocated to the unitholders, based on their respective ownership percentages. The following table presents the allocation of the general partner’s GP Interest in net income attributable to MPLX LP:



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

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

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

The allocation of total quarterly cash distributions to general, limited and Preferred unitholders is as follows for the three and six months ended June 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 June 30,				Six Months Ended June 30,
(In millions)	2017		2016		2017		2016
General partner's distributions:
General partner's distributions on general partner units	$	6	$	4	$	11	$	8
General partner's distributions on incentive distribution rights	70		46		130		86
Total distribution on general partner units and incentive distribution rights	$	76	$	50	$	141	$	94
Common and preferred unit distributions:
Common unitholders, includes common units of general partner	$	218	$	172	$	416	$	328
Preferred unit distributions	17		9		33		9
Total cash distributions declared	$	311	$	231	$	590	$	431

8. Redeemable Preferred Units

Private Placement of Preferred Units – On May 13, 2016, MPLX LP completed the private placement of approximately 30.8 million 6.5 percent Series A Convertible Preferred units (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 common units.

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



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

The purchasers may convert their Preferred units 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 in 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.

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 HST, WHC and MPLXT as they are entities under common control. Segment information for periods prior to the Ozark pipeline acquisition does not include amounts for these operations. See Note 3 for more detail of these acquisitions.


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

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



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



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



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



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



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

(1)

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



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

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



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

Total assets by reportable segment were:



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

10. Inventories

Inventories consist of the following:



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

11. Property, Plant and Equipment

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



(In millions)	June 30, 2017		December 31, 2016
Natural gas gathering and NGL transportation pipelines and facilities	$	4,919	$	4,748
Processing, fractionation and storage facilities⁽¹⁾	3,736		3,547
Pipelines and related assets	2,156		1,799
Barges and towing vessels	484		479
Terminals and related assets⁽¹⁾	784		759
Land, building, office equipment and other	723		757
Construction-in-progress	816		1,013
Total	13,618		13,102
Less accumulated depreciation	1,980		1,694
Property, plant and equipment, net	$	11,638	$	11,408


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

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:



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

The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments as of June 30, 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	Assets	Forward ethane prices (per gallon)⁽¹⁾	$0.25 - $0.26	July 17 - Dec. 17
		Forward propane prices (per gallon)⁽¹⁾	$0.53 - $0.63	July 17 - Dec. 18
		Forward isobutane prices (per gallon)⁽¹⁾	$0.66 - $0.76	July 17 - Dec. 18
		Forward normal butane prices (per gallon)⁽¹⁾	$0.59 - $0.74	July 17 - Dec. 18
		Forward natural gasoline prices (per gallon)⁽¹⁾	$1.03 - $1.06	July 17 - Dec. 18

Embedded derivatives in commodity contracts	Assets	ERCOT Pricing (per MegaWatt Hour)	$24.62 - $45.42	July 17 - Dec. 17
	Liabilities	Forward propane prices (per gallon)⁽¹⁾	$0.52 - $0.63	July 17 - Dec. 22
		Forward isobutane prices (per gallon)⁽¹⁾	$0.64 - $0.76	July 17 - Dec. 22
		Forward normal butane prices (per gallon)⁽¹⁾	$0.59 - $0.74	July 17 - Dec. 22
		Forward natural gasoline prices (per gallon)⁽¹⁾	$1.03 - $1.10	July 17 - Dec. 22
		Forward natural gas prices (per MMBtu)⁽²⁾	$2.26 - $3.14	July 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 in the early years and increase over time.


(2)	Natural gas prices used in the valuations decrease in the early years and increase over time.

(3)

The producer counterparty to the embedded derivative has the option to renew the gas purchase agreement and the related keep-whole processing agreement for two successive five-year terms after 2022. The embedded gas purchase agreement cannot be renewed without the renewal of the related keep-whole processing agreement. Due to the significant number of years until the renewal options are exercisable and the high level of uncertainty regarding the counterparty’s future

business strategy, the future commodity price environment, and the future competitive environment for midstream services in the Southern Appalachian region, management determined that a 50 percent probability of renewal for the first five-year term and 75 percent for the second five-year term are appropriate assumptions. Included in this assumption is a further extension of management’s estimates of future frac spreads through 2032.

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 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 (July 2017 through December 2022) for management’s use in determining the fair value of the Natural Gas Embedded Derivative. In developing the pricing curves for these periods, the Risk Department maximizes its use of the latest known market data and trends as well as its understanding of the historical relationships between forward NGL and natural gas prices and the forward market data that is available for the required period, such as crude oil pricing and natural gas pricing from other markets. However, there is very limited actual market data available to validate the Risk Department’s estimated price curves. Management also assesses the probability of the producer customer’s renewal of the contracts, which includes consideration of:


•	The estimated favorability of the contracts to the producer customer as compared to other options that would be available to them at the time and in the relative geographic area of their producing assets;


•	Extrapolated pricing curves, using a weighted average probability method that is based on historical frac spreads, which impact the calculation of favorability; and


•	The producer customer’s potential business strategy decision points that may exist at the time the counterparty would elect whether to renew the contracts.

Changes in Level 3 Fair Value Measurements

The tables below include a rollforward of the balance sheet amounts for the three and six months ended June 30, 2017 and 2016, respectively (including the change in fair value), for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy.



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



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


(1)	Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in Product sales in the accompanying Consolidated Statements of Income. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in Purchased product costs and Cost of Revenues.

(2)

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

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).

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:



	June 30, 2017				December 31, 2016
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Long-term debt	$	7,362	$	6,687	$	4,953	$	4,422
SMR liability	106		93		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, 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 June 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	36,800
Natural Gas (MMBtu)	Long	1,264,924
NGLs (gal)	Short	58,214,105

Embedded Derivatives in Commodity Contracts

The Partnership has a commodity contract with a producer customer in the Southern Appalachian region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. For accounting purposes, these contracts have been aggregated into a single contract and are evaluated together. In February 2011, the Partnership executed agreements with the producer customer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022, with the producer customer’s option to extend the agreement for two successive five-year terms through December 31, 2032. The purchase of gas at prices based on the frac spread and the option to extend the agreements have been identified as a single embedded derivative, which is recorded at fair value. The probability of renewal is determined based on extrapolated pricing curves, a review of the overall expected favorability of the contracts based on such pricing curves and assumptions about the counterparty’s potential business strategy decision points that may exist at the time the counterparty would elect whether to renew the contract. The changes in fair value of this embedded derivative are based on the difference between the contractual and index pricing, the probability of the producer customer exercising its option to extend and the estimated favorability of these contracts compared to current market conditions. The changes in fair value are recorded in earnings through Purchased product costs in the Consolidated Statements of Income. As of June 30, 2017 and December 31, 2016, the estimated fair value of this contract was a liability of $43 million and $54 million, respectively.

The Partnership has a commodity contract that gives it an option to fix a component of the utilities cost to an index price on electricity at a plant location in the Southwest 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 June 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)	June 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	$	2	$	(6	)	$	—	$	(13	)
Other noncurrent assets / deferred credits and other liabilities	—		(37		)	—		(47		)
Total	$	2	$	(43	)	$	—	$	(60	)


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

Certain derivative positions are subject to master netting agreements, therefore the Partnership has elected to offset derivative assets and liabilities that are legally permissible to be offset. The net amounts in the table below equal the balances presented in the Consolidated Balance Sheets:



	June 30, 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	$	3	$	(1	)	$	2	$	(1	)	$	1	$	—
Embedded derivatives in commodity contracts	—		—			—		(6		)	—		(6		)
Total current derivative instruments	3		(1		)	2		(7		)	1		(6		)
Non-current
Commodity contracts	—		—			—		—			—		—
Embedded derivatives in commodity contracts	—		—			—		(37		)	—		(37		)
Total non-current derivative instruments	—		—			—		(37		)	—		(37		)
Total derivative instruments	$	3	$	(1	)	$	2	$	(44	)	$	1	$	(43	)

In the table above, the Partnership does not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although the Partnership’s master netting arrangements would allow current and non-current positions to be offset in the event of default. Additionally, in the event of a default, the Partnership’s master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions and other forms of non-cash collateral (such as letters of credit).

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



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


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

14. Debt

The Partnership’s outstanding borrowings consisted of the following:



(In millions)	June 30, 2017			December 31, 2016
MPLX LP:
Bank revolving credit facility due 2020	$	—		$	—
Term loan facility due 2019	250			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	8			8
Total	7,108			4,858
Unamortized debt issuance costs	(28		)	(7		)
Unamortized discount	(413		)	(428		)
Amounts due within one year	(1		)	(1		)
Total long-term debt due after one year	$	6,666		$	4,422

Credit Agreements

During the six months ended June 30, 2017, the Partnership had no borrowings under the bank revolving credit facility. At June 30, 2017, the Partnership had no outstanding borrowings and $3 million letters of credit outstanding under this facility, resulting in total availability of $2.0 billion, or 99.9 percent of the borrowing capacity.

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

Table of Contents

15. Supplemental Cash Flow Information



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


(1)	Contribution of assets to Sherwood Midstream and Sherwood Midstream Holdings. See Note 4.

The Consolidated Statements of Cash Flows exclude changes to the Consolidated Balance Sheets that did not affect cash. The following is the change of additions to property, plant and equipment related to capital accruals:



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

16. Equity-Based Compensation

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



	Number of Units		Weighted Average Fair Value
Outstanding at December 31, 2016	1,173,411		$	33.09
Granted	529,434		36.86
Settled	(268,154	)	33.47
Forfeited	(62,852	)	34.66
Outstanding at June 30, 2017	1,371,839		34.40

Performance Units – The Partnership grants performance units under the MPLX LP 2012 Incentive Compensation Plan to certain officers of the general partner and certain eligible MPC officers who make significant contributions to its business. These performance units pay out 75 percent in cash and 25 percent in MPLX LP common units. The performance units paying out in units are accounted for as equity awards. The performance units granted in 2017 are hybrid awards having a three-year performance period of January 1, 2017 through December 31, 2019. The payout of the award is dependent on two independent conditions, each constituting 50 percent of the overall target units granted. The awards have a performance condition based on MPLX LP’s distributable cash flow during the last twelve months of the performance period, and 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 six months ended June 30, 2017:



	Number of Units
Outstanding at December 31, 2016	1,799,249
Granted	1,407,062
Settled	(464,500	)
Forfeited	(15,312	)
Outstanding at June 30, 2017	2,726,499

17. Commitments and Contingencies

The Partnership is the subject of, or a party to, a number of pending or threatened legal actions, contingencies and commitments involving a variety of matters, including laws and regulations relating to the environment. Some of these matters are discussed below. For matters for which the Partnership has not recorded an accrued liability, the Partnership is unable to estimate a range of possible losses for the reasons discussed in more detail below. However, the ultimate resolution of some of these contingencies could, individually or in the aggregate, be material.

Environmental Matters – The Partnership is subject to federal, state and local laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for non-compliance.

At June 30, 2017 and December 31, 2016, accrued liabilities for remediation totaled $5 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 June 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. 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 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, 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 June 30, 2017, the Partnership’s contractual commitments to acquire property, plant and equipment totaled $415 million. These commitments at June 30, 2017 were primarily related to plant expansion projects for the Marcellus and Southwest Operations and the Cornerstone Pipeline project. In addition, from time to time and in the ordinary course of business, the Partnership and its affiliates provide guarantees of the Partnership’s subsidiaries payment and performance obligations in the G&P segment. Certain natural gas processing and gathering arrangements require the Partnership to construct new natural gas processing plants, natural gas gathering pipelines and NGL pipelines and contain certain fees and charges if specified construction milestones are not achieved for reasons other than force majeure. In certain cases, certain producers may have the right to cancel the processing arrangements if there are significant delays that are not due to force majeure. As of June 30, 2017, management does not believe there are any indications that the Partnership will not be able to meet the construction milestones, that force majeure does not apply, or that such fees and charges will otherwise be triggered.

18. Subsequent Events

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

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 June 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 $85 million, or 69 percent, for the three months ended June 30, 2017 compared to the same period of 2016 due to $80 million from the inclusion of HST, WHC and MPLXT results after our acquisition as of March 1, 2017 and approximately $11 million from the acquisition of the Ozark pipeline.

•

G&P segment operating income attributable to MPLX LP increased approximately $42 million, or 15 percent, for the three months ended June 30, 2017 compared to the same period of 2016. The G&P segment realized volume and product price increases during the second 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 second quarter of 2016, processing volumes were up approximately 14 percent, fractionated volumes were up approximately 20 percent and gathering volumes were up approximately one percent. Additionally, there were lower transportation costs and other operating expenses.

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

Acquisition and Growth Activities

•

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

•

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

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

•

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

•

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

•

On February 6, 2017, we formed a strategic joint venture with Antero Midstream to process natural gas at the Sherwood Complex and fractionate natural gas liquids at the Hopedale Complex. This unique transaction strengthens our long-term relationship with the largest producer in the Appalachian Basin and provides the Partnership 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 February 10, 2017, we completed a public offering of $2.25 billion aggregate principal amount senior notes.


•	During the six months ended June 30, 2017, we issued an aggregate of 12,662,663 commons units under our ATM Program, generating net proceeds of approximately $434 million. As of June 30, 2017, $280 million of common units remain available for issuance through the ATM Program under the Distribution Agreement.

NON-GAAP FINANCIAL INFORMATION

Our management uses a variety of financial and operating metrics to analyze our performance. These metrics are significant factors in assessing our operating results and profitability and include the non-GAAP financial measures of Adjusted EBITDA and DCF. The amount of Adjusted EBITDA and DCF generated is considered by the board 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) loss (income) from equity investments; (viii) distributions from unconsolidated subsidiaries; (ix) unrealized derivative losses (gains); and (x) 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).

RESULTS OF OPERATIONS

The following table and discussion is a summary of our results of operations for the three and six months ended June 30, 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 June 30,								Six Months Ended June 30,
(In millions)	2017		2016			Variance			2017		2016			Variance
Total revenues and other income	$	916	$	698		$	218		$	1,802	$	1,343		$	459
Costs and expenses:
Cost of revenues (excludes items below)	139		113			26			252		207			45
Purchased product costs	140		114			26			271		193			78
Rental cost of sales	13		15			(2		)	25		29			(4		)
Rental cost of sales - related parties	1		1			—			1		1			—
Purchases - related parties	109		99			10			216		177			39
Depreciation and amortization	164		151			13			351		287			64
Impairment expense	—		1			(1		)	—		130			(130		)
General and administrative expenses	57		63			(6		)	115		116			(1		)
Other taxes	13		13			—			26		25			1
Total costs and expenses	636		570			66			1,257		1,165			92
Income from operations	280		128			152			545		178			367
Related party interest and other financial costs	—		—			—			—		1			(1		)
Interest expense, net of amounts capitalized	74		52			22			140		107			33
Other financial costs	13		12			1			25		24			1
Income before income taxes	193		64			129			380		46			334
Provision (benefit) for income taxes	2		(8		)	10			2		(12		)	14
Net income	191		72			119			378		58			320
Less: Net income attributable to noncontrolling interests	1		1			—			2		1			1
Less: Net income attributable to Predecessor	—		52			(52		)	36		98			(62		)
Net income (loss) attributable to MPLX LP	$	190	$	19		$	171		$	340	$	(41	)	$	381

Adjusted EBITDA attributable to MPLX LP⁽¹⁾	$	474	$	351		$	123		$	897	$	653		$	244
DCF⁽¹⁾	387		285			102			741		521			220
DCF attributable to GP and LP unitholders⁽¹⁾	370		276			94			708		512			196


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



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



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

(1)


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

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

Total revenues and other income increased $218 million in the second quarter of 2017 compared to the same period of 2016. This variance was due mainly to increased pricing on product sales of approximately $48 million as well as higher revenues from volume growth of $36 million in the Marcellus and the Southwest areas, higher crude and product transportation volumes of $12 million, $19 million from the acquisition of the Ozark pipeline and a $4 million increase from additional barges. The three months ended June 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 $26 million in the second quarter of 2017 compared to the same period of 2016. This variance was primarily due to approximately $8 million from the acquisition of the Ozark pipeline and expenses related to the timing of projects.

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

Purchases-related parties increased $10 million in the second quarter of 2017 compared to the same period of 2016. The increase was primarily due to salaries, compensation and other miscellaneous expenses.

Depreciation and amortization expense increased $13 million in the second 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 $5 million of accelerated depreciation related to adjustments of certain assets’ useful life.

General and administrative expense decreased $6 million in the second quarter of 2017 compared to the same period of 2016. This decrease was mainly due to savings on insurance programs and other costs.

Net interest expense and other financial costs increased $23 million in the second quarter of 2017 compared to the same period of 2016. The increase is mainly due to the New Senior Notes issued in February 2017 partially offset by decreased borrowings on the bank revolving credit facility.

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

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

This variance was due mainly to the inclusion of $106 million of revenue generated by MPLXT and its subsidiaries since it was not formed as a business until April 1, 2016, increased pricing on product sales of approximately $139 million as well as higher revenues from volume growth of $66 million in the Marcellus and the Southwest areas, higher crude and product transportation volumes of $14 million, $26 million from the acquisition of the Ozark pipeline, $5 million due to an increase in recognition of revenues related to volume deficiency payments and a $6 million increase from additional barges. The six months ended June 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 $45 million in the first six months of 2017 compared to the same period of 2016. This variance was primarily due to $26 million from the inclusion of MPLXT during the six months of 2017, as well as $11 million from the acquisition of the Ozark pipeline and expenses related to the timing of projects.

Purchased product costs increased $78 million in the first six 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 $19 million unrealized gain on our Natural Gas Embedded Derivative.

Purchases-related parties increased $39 million in the first six months of 2017 compared to the same period of 2016. The increase was primarily due to the inclusion of approximately $26 million related party purchases of MPLXT as well as general increases in employee benefit costs.

Depreciation and amortization expense increased $64 million in the first six months of 2017 compared to the same period of 2016. This variance was primarily due to accelerated depreciation expense of approximately $33 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 throughout 2016 and the first half of 2017.

Impairment expense decreased $130 million in the first six 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 second quarter of 2016.

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

SEGMENT RESULTS

We classify our business in the following reportable segments: L&S and G&P. Segment operating income represents income from operations attributable to the reportable segments. We have investments in entities that we operate that are accounted for using equity method investment accounting standards. However, we view financial information as if those investments were consolidated. Corporate general and administrative expenses, unrealized derivative gains (losses), property, plant and equipment impairment, goodwill impairment and depreciation and amortization are not allocated to the reportable segments. Management does not consider these items allocable to or controllable by any individual segment and, therefore, excludes these items when evaluating segment performance. Segment results are also adjusted to exclude the portion of income from operations attributable to the noncontrolling interests related to partially owned entities that are either consolidated or accounted for as equity method investments. Segment operating income attributable to MPLX LP excludes the operating income related to the HSM Predecessor prior to the March 31, 2016 acquisition and the HST, WHC and MPLXT Predecessor prior to the March 1, 2017 acquisition.

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

L&S Segment



	Three Months Ended June 30,							Six Months Ended June 30,
(In millions)	2017		2016		Variance			2017		2016		Variance
Revenues and other income:
Segment revenues	$	372	$	331	$	41		$	717	$	562	$	155
Segment other income	12		14		(2		)	24		30		(6		)
Total segment revenues and other income	384		345		39			741		592		149
Costs and expenses:
Segment cost of revenues	176		142		34			324		239		85
Segment operating income before portion attributable to noncontrolling interests and Predecessor	208		203		5			417		353		64
Segment portion attributable to noncontrolling interests and Predecessor	—		80		(80		)	53		142		(89		)
Segment operating income attributable to MPLX LP	$	208	$	123	$	85		$	364	$	211	$	153

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

In the second quarter of 2017 compared to the same period of 2016, segment revenue increased primarily due to a $12 million increase from higher crude and product transportation volumes, a $19 million increase from the acquisition of the Ozark pipeline, a $3 million increase in the recognition of revenue related to volume deficiency payments, a $3 million increase from the annual increase in fees and a $4 million increase from additional barges.

In the second quarter of 2017 compared to the same period of 2016, segment cost of revenues increased primarily due to expenses related to the timing of projects, the acquisition of the Ozark pipeline, and salaries, compensation and other miscellaneous expenses.

In the second 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.

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

In the first six months of 2017 compared to the same period of 2016, segment revenue increased primarily due to the inclusion of $106 million of revenue generated by MPLXT and its subsidiaries, a $14 million increase from higher crude and product transportation volumes, a $26 million increase from the acquisition of the Ozark pipeline, a $5 million increase due to the recognition of revenues related to volume deficiency payments, a $3 million increase from the annual increase in fees and a $6 million increase from additional barges.

In the first six 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, and increases in expenses related to the timing of projects.

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



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

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

G&P Segment

Our assets include approximately 5.6 bcf/d of gathering capacity, 7.8 bcf/d of natural gas processing capacity and 570 mbpd of fractionation capacity.



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

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

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

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

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

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

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

Segment Reconciliations

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



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

(1)



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

OUR G&P CONTRACTS WITH THIRD PARTIES

We generate the majority of our revenues in the G&P segment from natural gas gathering, transportation and processing; NGL gathering, transportation, fractionation, exchange, marketing and storage; and crude oil gathering and transportation. We enter into a variety of 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 June 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⁾	88	%	10	%	2	%
Total	93	%	6	%	1	%

For the six months ended June 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 June 30,						Six Months Ended June 30,
(In millions)	2017			2016			2017			2016
Reconciliation of net operating margin to income from operations:
Segment revenues	$	975		$	861		$	1,917		$	1,590
Segment purchased product costs	(141		)	(108		)	(281		)	(186		)
Realized derivative loss related to purchased product costs⁽¹⁾	2			2			4			3
Net operating margin	836			755			1,640			1,407
Revenue adjustment from unconsolidated affiliates⁽²⁾	(88		)	(99		)	(180		)	(203		)
Realized derivative loss related to purchased product costs⁽¹⁾	(2		)	(2		)	(4		)	(3		)
Unrealized derivative gains (losses)⁽¹⁾	3			(12		)	19			(21		)
Income (loss) from equity method investments	1			(83		)	6			(78		)
Other income	1			1			3			3
Other income - related parties	25			24			47			45
Cost of revenues (excludes items below)	(139		)	(113		)	(252		)	(207		)
Rental cost of sales	(13		)	(15		)	(25		)	(29		)
Rental cost of sales - related parties	(1		)	(1		)	(1		)	(1		)
Purchases - related parties	(109		)	(99		)	(216		)	(177		)
Depreciation and amortization	(164		)	(151		)	(351		)	(287		)
Impairment expense	—			(1		)	—			(130		)
General and administrative expenses	(57		)	(63		)	(115		)	(116		)
Other taxes	(13		)	(13		)	(26		)	(25		)
Income from operations	$	280		$	128		$	545		$	178

(1)


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

SEASONALITY

The volume of crude oil and refined products transported on our pipeline systems, at our barge dock and stored at our storage assets is directly affected by the level of supply and demand for crude oil and refined products in the markets served directly or indirectly by our assets. Many effects of seasonality on the L&S segment’s revenues will be mitigated through the use of our fee-based transportation and storage services agreements with MPC that include minimum volume commitments.

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.

OPERATING DATA



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

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

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

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

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

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

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

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


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


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


(3)	Represents total at end of period.


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


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

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


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

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Our cash and cash equivalents balance was $293 million at June 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:



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

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

Net cash used in investing activities increased $801 million in the first six months of 2017 compared to the first six months of 2016, primarily due to the acquisition of an equity interest in the Bakken Pipeline system for $513 million, $220 million for the acquisition of the Ozark pipeline, investments in unconsolidated entities of approximately $127 million, as well as an increase in cash used for additions to property, plant and equipment related to various capital projects. 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 and a $43 million increase in investment loans with MPC.

Financing activities were a $619 million source of cash in the first six months of 2017 compared to a $75 million use of cash in the first six months of 2016. The source of cash in the first six months of 2017 was primarily due to $2.2 billion of net proceeds from the New Senior Notes, $128 million in contributions from noncontrolling interests, and $443 million of net proceeds from sales of units under the ATM Program. These items were partially offset by distributions to MPC of $1.5 billion for the acquisition of HST, WHC and MPLXT, distributions of $33 million to Preferred unitholders, and increased distributions of $114 million to unitholders and our general partner due mainly to the increase in units outstanding as well as a four percent increase in the distribution per common unit.

Debt and Liquidity Overview

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



(In millions)	June 30, 2017			December 31, 2016
MPLX LP:
Bank revolving credit facility due 2020	$	—		$	—
Term loan facility due 2019	250			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	8			8
Total	7,108			4,858
Unamortized debt issuance costs	(28		)	(7		)
Unamortized discount	(413		)	(428		)
Amounts due within one year	(1		)	(1		)
Total long-term debt due after one year	$	6,666		$	4,422

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

Our bank revolving credit facility and term loan facility (“MPLX Credit Agreement”) include certain representations and warranties, affirmative and negative covenants and events of default that we consider usual and customary for an agreement of that type, and that could, among other things, limit our ability to pay distributions to our unitholders. The financial covenant requires us to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA (both as defined in the MPLX Credit Agreement) for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 for up to two fiscal quarters following certain acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period. As of June 30, 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.

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

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



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


(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 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 June 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	168,622	—	3,441	172,063
Issuance of units under the ATM Program	12,662,663	—	258,422	12,921,085
Contribution of HST/WHC/MPLXT	12,960,376	—	264,497	13,224,873
Balance at June 30, 2017	382,984,949	3,990,878	7,897,465	394,873,292

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

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 six months ended June 30, 2017, the sale of common units under the ATM Program generated net proceeds of approximately $434 million. As of June 30, 2017, $280 million 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 MPLX LP 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 incentive distribution rights that would have otherwise accrued on such MPLX LP common units with respect to the first quarter 2017 distributions. The value of these waived distributions was $6 million. Additionally, in connection with our acquisition of a partial, indirect equity interest in Bakken Pipeline system on February 15, 2017, MPC agreed to waive its right to receive incentive distributions of $1.6 million per quarter for twelve consecutive quarters beginning with the distributions declared in the first quarter of 2017 and paid to MPC in the second quarter, which was prorated from the acquisition date.

We intend to pay at least the minimum quarterly distribution of $0.2625 per unit per quarter, which equates to $103 million per quarter, or $410 million per year, based on the number of common and general partner units outstanding at June 30, 2017. On July 26, 2017, we announced the board of directors of our general partner had declared a distribution of $0.5625 per unit that will be paid on August 14, 2017 to unitholders of record on August 7, 2017. This represents an increase of $0.0225 per unit, or four percent, above the first quarter 2017 distribution of $0.5400 per unit and an increase of ten percent over the second 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 six months ended June 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 June 30,				Six Months Ended June 30,
(In millions)	2017		2016		2017		2016
Distribution declared:
Limited partner units - public	$	162	$	131	$	311	$	258
Limited partner units - MPC	51		41		98		70
Limited partner units - GP	5		—		7		—
General partner units - MPC	6		4		11		8
Incentive distribution rights - MPC	70		46		130		86
Total GP & LP distribution declared	294		222		557		422
Redeemable preferred units	17		9		33		9
Total distribution declared	$	311	$	231	$	590	$	431

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

Our intentions regarding the distribution growth profile expressed above include forward-looking statements. Such forward-looking statements are not guarantees of future performance and are subject to risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Factors that could cause actual results to differ materially from those implied in the forward-looking statements include: the adequacy of our capital resources and liquidity, including, but not 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 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 first drop of assets contributing approximately $250 million of annual EBITDA took place in the first quarter of 2017 and was financed through cash and equity, as discussed in Note 3 of the Notes to Consolidated Financial Statements. MPLX LP anticipates completing the second of several strategic acquisitions in the third quarter with the offer of joint-interest ownership in certain pipelines and storage facilities from MPC. These assets are projected to generate approximately $135 million of EBITDA. MPC has indicated work remains on schedule to prepare the remaining assets contributing annual EBITDA of approximately $1.0 billion for dropdown no later than the end of the first quarter of 2018. The Partnership's plans for funding these dropdowns would likely include debt and equity in approximately equal proportions, with the equity financing to be funded through transactions with MPC. In addition to the expected dropdowns,

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

Capital Expenditures

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

Our capital expenditures are shown in the table below:



	Six Months Ended June 30,
(In millions)	2017		2016
Capital expenditures:
Maintenance	$	35	$	35
Expansion	651		566
Total capital expenditures	686		601
Less: Increase (decrease) in capital accruals	33		(7		)
Asset retirement expenditures	1		2
Additions to property, plant and equipment	652		606
Capital expenditures of unconsolidated subsidiaries⁽¹⁾	205		60
Total gross capital expenditures	857		666
Less: Joint venture partner contributions⁽²⁾	93		29
Total capital expenditures, net	764		637
Less: Maintenance capital	36		35
Total growth capital	$	728	$	602


(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 for 2017 is $1.8 billion to $2.0 billion, not including the future dropdowns previously discussed, or their respective subsequent capital spending. This range excludes acquisition costs for the dropdowns of HST, WHC and MPLXT, the acquisition of the Ozark pipeline and the MarEn Bakken investment, as discussed in Note 3 of the Notes to Consolidated Financial Statements. The range also excludes non-affiliated joint venture members’ share of capital expenditures. The G&P segment capital plan includes investments that are expected to support producer customers and complete certain processing plants currently under construction at the Sherwood Complex. The L&S segment capital plan includes the development of various crude oil and refined petroleum products infrastructure projects, including the continued build out of Utica Shale infrastructure in connection with the completed Cornerstone Pipeline, a 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 June 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 six months ended June 30, 2017, our long-term debt obligations increased by $4.2 billion due to the new senior notes issued and contracts to acquire property, plant and equipment increased $213 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 June 30, 2017, we have not entered into any transactions, agreements or other arrangements that would result in off-balance sheet liabilities.

Forward-looking Statements

Our opinions concerning liquidity and capital resources and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors, including cash provided by operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and future credit ratings by rating agencies. The discussion of liquidity and capital resources above also contains forward-looking statements regarding expected capital spending. The forward-looking statements about our capital budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are difficult to predict. Some factors that could cause actual results to differ materially include negative capital market conditions, including an increase of the current yield on common units, adversely affecting the Partnership’s ability to meet its distribution growth guidance; the time, costs and ability to obtain regulatory or other approvals and consents and otherwise consummate the strategic initiatives discussed herein and other proposed transactions; the satisfaction or waiver of conditions in the agreements governing the strategic initiatives discussed herein and other proposed transactions; our ability to achieve the strategic and other objectives related to the strategic initiatives and transactions discussed herein, including the dropdowns proposed by MPC, the joint venture with Antero Midstream Partners LP, the Ozark pipeline acquisition, and other proposed transactions; adverse changes in laws including with respect to tax and regulatory matters; the inability to agree with respect to the timing of and value attributed to assets identified for dropdown; the adequacy of the Partnership’s capital resources and liquidity, including, but not limited to, availability of sufficient cash flow to pay distributions, and the ability to successfully execute its business plans and growth strategy; continued/further volatility in and/or degradation of market and industry conditions; changes to the expected construction costs and timing of projects; civil protests and resulting legal/regulatory uncertainty regarding environmental and social issues, including pipeline infrastructure, may prevent or delay the construction and operation of such infrastructure and realization of associated revenues; completion of midstream infrastructure by competitors; disruptions due to equipment interruption or failure, including electrical shortages and power grid failures; the suspension, reduction or termination of MPC's obligations under the Partnership’s commercial agreements; modifications to earnings and distribution growth objectives; the level of support from MPC, including dropdowns, alternative financing arrangements, taking equity units, and other methods of sponsor support, as a result of the capital allocation needs of the enterprise as a whole and its ability to provide support on commercially reasonable terms; compliance with federal and state environmental, economic, health and safety, energy and other policies and regulations and/or enforcement actions initiated thereunder; changes to the Partnership’s capital budget; prices of and demand for natural gas, NGLs, crude oil and refined 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 June 30, 2017, MPC held a two percent GP Interest and a 25.2 percent limited partner interest (including the Class B units on an as-converted basis) in MPLX LP.

Excluding revenues attributable to volumes shipped by MPC under joint tariffs with third parties that are treated as third-party revenues for accounting purposes, MPC accounted for 38 percent and 47 percent of our total revenues and other income for the second 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 23 percent and 24 percent for the second 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.

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 June 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 June 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.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

The information about commodity price risk for the three and six months ended June 30, 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 June 30, 2017, including the weighted-average prices (“WAVG”):



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



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



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



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



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



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



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

We have a commodity contract with a producer customer in the Southern Appalachian region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. For accounting purposes, these contracts have been aggregated into a single contract and are evaluated together. In February 2011, we executed agreements with the producer customer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022, with the producer customer’s option to extend the agreement for two successive five-year terms through December 31, 2032. The purchase of gas at prices based on the frac spread and the option to extend the agreements have been identified as a single embedded derivative, which is recorded at fair value. The probability of renewal is determined based on extrapolated pricing curves, a review of the overall expected favorability of the contracts based on such pricing curves and assumptions about the counterparty’s potential

business strategy decision points that may exist at the time the counterparty would elect whether to renew the contracts. The changes in fair value of this embedded derivative are based on the difference between the contractual and index pricing, the probability of the producer customer exercising its option to extend and the estimated favorability of these contracts compared to current market conditions. The changes in fair value are recorded in earnings through Purchased product costs in the Consolidated Statements of Income. As of June 30, 2017, the estimated fair value of this contract was a liability of $43 million.

We have a commodity contract that gives us an option to fix a component of the utilities cost to an index price on electricity at a plant location in the Southwest 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 June 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 June 30, 2017⁽¹⁾		Change in Fair Value⁽²⁾		Change in Income Before Income Taxes for the Six Months Ended June 30, 2017⁽³⁾
Long-term debt
Fixed-rate	$	7,112	$	577	N/A
Variable-rate	$	250	N/A		$	1


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


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


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

At June 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 June 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 June 30, 2017, the end of the period covered by this report.

Changes in Internal Control Over Financial Reporting

During the quarter ended June 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.

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.

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.

Item 2. Unregistered Sales of Equity Securities

In connection with the issuance of 69,159 common units upon the vesting of phantom units under the MPLX LP 2012 Incentive Compensation Plan and 8,511,405 common units under the ATM Program, our general partner purchased an aggregate of 175,113 general partner units for a total of $5,928,325.51 in cash during the three months ended June 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.

Item 6. Exhibits

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

Filed

Herewith

Furnished

Herewith

3.1

Certificate of Limited Partnership of MPLX LP

S-1

3.1

7/2/2012

333-182500

3.2

Amendment to the Certificate of Limited Partnership of MPLX LP

S-1/A

3.2

10/9/2012

333-182500

3.3

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

10-Q

3.3

10/31/2016

001-35714

3.4

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

10-K

3.4

2/24/2017

001-35714

10.1

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

31.1

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

31.2

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

32.1

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

32.2

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

101.INS

XBRL Instance Document

101.SCH

XBRL Taxonomy Extension Schema

101.CAL

XBRL Taxonomy Extension Calculation Linkbase

101.DEF

XBRL Taxonomy Extension Definition Linkbase

101.LAB

XBRL Taxonomy Extension Label Linkbase

101.PRE

XBRL Taxonomy Extension Presentation Linkbase

SIGNATURES

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



	MPLX LP

	By:	MPLX GP LLC
		Its general partner

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

MPLX - 10-Q quarterly report FY2017 Q2

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	Page
PART I – FINANCIAL INFORMATION
Item 1. Financial Statements:
Consolidated Statements of Income (Unaudited)	3
Consolidated Balance Sheets (Unaudited)	4
Consolidated Statements of Cash Flows (Unaudited)	5
Consolidated Statements of Equity (Unaudited)	6
Notes to Consolidated Financial Statements (Unaudited)	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	41
Item 3. Quantitative and Qualitative Disclosures about Market Risk	62
Item 4. Controls and Procedures	63

PART II – OTHER INFORMATION
Item 1. Legal Proceedings	64
Item 1A. Risk Factors	64
Item 2. Unregistered Sales of Equity Securities	65
Item 6. Exhibits	66
Signatures	67