MPLX - 10-Q quarterly report FY2016 Q3

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________________________________________

FORM 10-Q

_____________________________________________

(Mark One)



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

For the Quarterly Period Ended September 30, 2016



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

For the transition period from to

Commission file number 001-35714

_____________________________________________

MPLX LP

(Exact name of registrant as specified in its charter)

_____________________________________________



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

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

(419) 672-6500

(Registrant’s telephone number, including area code)

_____________________________________________

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

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

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



Large accelerated filer	x	Accelerated filer	¨

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

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 348,489,049 common units, 3,990,878 Class B units and 7,193,467 general partner units outstanding at October 27, 2016.

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MPLX LP

Form 10-Q

Quarter Ended September 30, 2016

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”) and Hardin Street Marine LLC (“HSM”). We have partial ownership interests in a number of joint venture legal entities, including MarkWest Pioneer, L.L.C. (“MarkWest Pioneer”), MarkWest Utica EMG, L.L.C. (“MarkWest Utica EMG”) and its subsidiary Ohio Gathering Company, L.L.C. (“Ohio Gathering”), Ohio Condensate Company, L.L.C. (“Ohio Condensate”), Wirth Gathering Partnership (“Wirth”) and MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. (“Jefferson Dry Gas”). References to “MPC” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other than the Partnership. References to “Predecessor” refer collectively to HSM’s related assets, liabilities and results of operations.

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Glossary of Terms

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



Bbl	Barrels
Btu	One British thermal unit, an energy measurement
Condensate	A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions
DCF (a non-GAAP financial measure)	Distributable Cash Flow
Dth/d	Dekatherms per day
EBITDA (a non-GAAP financial measure)	Earnings Before Interest, Taxes, Depreciation and Amortization
EPA	United States Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas
FASB	Financial Accounting Standards Board
GAAP	Accounting principles generally accepted in the United States of America
Gal	Gallon
Gal/d	Gallons per day
Initial Offering	Initial public offering on October 31, 2012
LIBOR	London Interbank Offered Rate
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 gain (loss)
NGL	Natural gas liquids, such as ethane, propane, butanes and natural gasoline
OTC	Over-the-Counter
SEC	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
VIE	Variable interest entity
WTI	West Texas Intermediate

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Part I—Financial Information

Item 1. Financial Statements

MPLX LP

Consolidated Statements of Income (Unaudited)



	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions, except per unit data)	2016		2015⁽¹⁾		2016			2015⁽¹⁾
Revenues and other income:
Service revenue	$	250	$	18	$	712		$	50
Service revenue - related parties	153		152		448			446
Rental income	77		—		218			—
Rental income - related parties	29		25		84			75
Product sales	157		—		394			—
Product sales - related parties	2		—		8			—
Gain on sale of assets	1		—		1			—
Income (loss) from equity method investments	6		—		(72		)	—
Other income	2		1		5			4
Other income - related parties	26		18		78			53
Total revenues and other income	703		214		1,876			628
Costs and expenses:
Cost of revenues (excludes items below)	90		59		263			147
Purchased product costs	117		—		310			—
Rental cost of sales	11		—		39			—
Purchases - related parties	84		43		238			123
Depreciation and amortization	138		19		407			58
Impairment expense	—		—		130			—
General and administrative expenses	46		25		147			68
Other taxes	10		—		32			8
Total costs and expenses	496		146		1,566			404
Income from operations	207		68		310			224
Related party interest and other financial costs	—		—		1			—
Interest expense (net of amounts capitalized of $7 million, $1 million, $21 million and $3 million, respectively)	51		4		158			15
Other financial costs	13		1		37			2
Income before income taxes	143		63		114			207
Benefit for income taxes	—		—		(12		)	—
Net income	143		63		126			207
Less: Net income attributable to noncontrolling interests	2		—		3			1
Less: Net income attributable to Predecessor	—		22		23			68
Net income attributable to MPLX LP	141		41		100			138
Less: Preferred unit distributions	16		—		25			—
Less: General partner’s interest in net income attributable to MPLX LP	51		8		136			19
Limited partners’ interest in net income (loss) attributable to MPLX LP	$	74	$	33	$	(61	)	$	119
Per Unit Data (See Note 6)
Net income (loss) attributable to MPLX LP per limited partner unit:
Common - basic	$	0.22	$	0.41	$	(0.19	)	$	1.42
Common - diluted	0.21		0.41		(0.19		)	1.42
Subordinated - basic and diluted	—		—		—			1.36
Weighted average limited partner units outstanding:
Common - basic	341		80		324			56
Common - diluted	346		80		324			56
Subordinated - basic and diluted	—		—		—			25
Cash distributions declared per limited partner common unit	$	0.5150	$	0.4700	$	1.5300		$	1.3200


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

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

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MPLX LP

Consolidated Balance Sheets (Unaudited)



(In millions)	September 30, 2016		December 31, 2015
Assets
Current assets:
Cash and cash equivalents	$	208	$	43
Receivables, net	289		245
Receivables - related parties	106		187
Inventories	50		51
Other current assets	33		50
Total current assets	686		576
Equity method investments	2,475		2,458
Property, plant and equipment, net	10,537		9,997
Intangibles, net	501		466
Goodwill	2,199		2,570
Long-term receivables - related parties	3		25
Other noncurrent assets	14		12
Total assets	$	16,415	$	16,104
Liabilities
Current liabilities:
Accounts payable	$	107	$	91
Accrued liabilities	193		187
Payables - related parties	68		54
Deferred revenue - related parties	35		32
Accrued property, plant and equipment	157		168
Accrued taxes	37		27
Accrued interest payable	55		54
Other current liabilities	18		12
Total current liabilities	670		625
Long-term deferred revenue	12		4
Long-term deferred revenue - related parties	12		9
Long-term debt	4,411		5,255
Deferred income taxes	5		378
Deferred credits and other liabilities	151		166
Total liabilities	5,261		6,437
Commitments and contingencies (see Note 19)
Redeemable preferred units	1,000		—
Equity
Common unitholders - public (262 million and 240 million units issued and outstanding)	7,898		7,691
Class B unitholders (4 million and 8 million units issued and outstanding)	133		266
Common unitholder - MPC (87 million and 57 million units issued and outstanding)	1,097		465
General partner - MPC (7 million units issued and outstanding)	1,009		819
Equity of Predecessor	—		413
Total MPLX LP partners’ capital	10,137		9,654
Noncontrolling interest	17		13
Total equity	10,154		9,667
Total liabilities, preferred units and equity	$	16,415	$	16,104

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

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MPLX LP

Consolidated Statements of Cash Flows (Unaudited)



	Nine Months Ended September 30,
(In millions)	2016			2015⁽¹⁾
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	126		$	207
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred financing costs	34			1
Depreciation and amortization	407			58
Impairment expense	130			—
Deferred income taxes	(16		)	(1		)
Asset retirement expenditures	(3		)	(1		)
Net gain on disposal of assets	(1		)	—
Loss from equity method investments	72			—
Distributions from unconsolidated affiliates	111			—
Changes in:
Current receivables	(44		)	(2		)
Inventories	(4		)	—
Change in fair value of derivatives	28			—
Current accounts payable and accrued liabilities	59			12
Receivables from / liabilities to related parties	15			(18		)
All other, net	18			2
Net cash provided by operating activities	932			258
Investing activities:
Additions to property, plant and equipment	(874		)	(129		)
Investments - loans from (to) related parties	77			(64		)
Investments in unconsolidated affiliates	(56		)	—
All other, net	4			2
Net cash used in investing activities	(849		)	(191		)
Financing activities:
Long-term debt - borrowings	434			528
- repayments	(1,312		)	(416		)
Related party debt - borrowings	2,215			—
- repayments	(2,223		)	—
Debt issuance costs	—			(4		)
Net proceeds from equity offerings	510			1
Issuance of redeemable preferred units	984			—
Distributions to preferred unitholders	(9		)	—
Distributions to unitholders and general partner	(612		)	(111		)
Distributions to noncontrolling interests	(3		)	(1		)
Contributions from noncontrolling interests	4			—
Consideration payment to Class B unitholders	(25		)	—
All other, net	(2		)	—
Contribution from MPC	225			—
Distributions to MPC from Predecessor	(104		)	(1		)
Net cash provided by (used in) financing activities	82			(4		)
Net increase in cash and cash equivalents	165			63
Cash and cash equivalents at beginning of period	43			27
Cash and cash equivalents at end of period	$	208		$	90


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

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

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MPLX LP

Consolidated Statements of Equity (Unaudited)



	Partnership
(In millions)	Common Unitholders Public			Class B Unitholders Public			Common Unitholder MPC			Subordinated Unitholder MPC			General Partner MPC			Noncontrolling Interests			Equity of Predecessor⁽¹⁾			Total
Balance at December 31, 2014	$	639		$	—		$	261		$	217		$	(660	)	$	6		$	321		$	784
Issuance of units under ATM program	1			—			—			—			—			—			—			1
Net income	35			—			36			48			19			1			68			207
Distributions to unitholders and general partner	(29		)	—			(25		)	(45		)	(12		)	—			—			(111		)
Distributions to noncontrolling interests	—			—			—			—			—			(1		)	—			(1		)
Subordinated unit conversion	—						220			(220		)	—			—						—
Distributions to MPC from Predecessor	—			—			—			—			—			—			(1		)	(1		)
Equity-based compensation	1			—			—			—			—			—			—			1
Balance at September 30, 2015	$	647		$	—		$	492		$	—		$	(653	)	$	6		$	388		$	880

Balance at December 31, 2015	$	7,691		$	266		$	465		$	—		$	819		$	13		$	413		$	9,667
Distributions to MPC from Predecessor	—			—			—			—			—			—			(104		)	(104		)
Issuance of units under ATM Program	499			—			—			—			11			—			—			510
Net (loss) income	(51		)	—			(10		)	—			136			3			23			101
Contribution from MPC	—			—			84			—			141			—			—			225
Distribution of MarkWest Hydrocarbon to MPC	—			—			—			—			565			—			—			565
Contribution of MarkWest Hydrocarbon from MPC	—			—			—			—			(188		)	—			—			(188		)
Allocation of MPC's net investment at acquisition	—			—			669			—			(337		)	—			(332		)	—
Distributions to unitholders and general partner	(378		)	—			(98		)	—			(136		)	—			—			(612		)
Distributions to noncontrolling interest	—			—			—			—			—			(3		)	—			(3		)
Contributions from noncontrolling interest	—			—			—			—			—			4			—			4
Class B unit conversion	133			(133		)	—			—			—			—			—			—
Equity-based compensation	6			—			—			—			—			—			—			6
Deferred income tax impact from changes in equity	(2		)	—			(13		)	—			(2		)	—			—			(17		)
Balance at September 30, 2016	$	7,898		$	133		$	1,097		$	—		$	1,009		$	17		$	—		$	10,154


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

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

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Notes to Consolidated Financial Statements (Unaudited)

1. Description of the Business and Basis of Presentation

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

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

Basis of Presentation – The Partnership’s consolidated financial statements include all majority-owned and controlled subsidiaries. For non-wholly-owned consolidated subsidiaries, the interests owned by third parties, including MPC, have been recorded as Noncontrolling interest in the accompanying Consolidated Balance Sheets. Intercompany investments, accounts and transactions have been eliminated. The Partnership’s investments in which the Partnership exercises significant influence but does not control and does not have a controlling financial interest are accounted for using the equity method. The Partnership’s investments in a VIE in which the Partnership exercises significant influence but does not control and is not the primary beneficiary are also accounted for using the equity method. The accompanying consolidated financial statements of the Partnership have been prepared in accordance with GAAP. Reclassifications have been made in connection with the MarkWest Merger and HSM acquisition to conform to current classifications. These reclassifications had no effect on previously reported results of operations or retained earnings.

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

Based on the terms of certain natural gas gathering, transportation and processing agreements, the Partnership is considered to be the lessor under several implicit operating lease arrangements in accordance with GAAP. The Partnership’s primary implicit lease operations relate to a natural gas gathering agreement in the Marcellus shale for which it earns a fixed-fee for providing gathering services to a single producer customer using a dedicated gathering system. As the gathering system is expanded, the fixed-fee charged to the producer is adjusted to include the additional gathering assets in the lease. Other significant implicit leases relate to a natural gas processing agreement in the Marcellus shale and a natural gas processing agreement in the Southern Appalachia region for which the Partnership earns minimum monthly fees for providing processing services to a single producer using a dedicated processing plant. Revenues and costs related to the portion of the revenue earned under these contracts considered to be implicit leases are recorded as Rental income and Rental cost of sales, respectively, on the Consolidated Statements of Income. Similarly, the Partnership is considered to be the lessor under implicit operating lease arrangements with MPC in accordance with GAAP. The Partnership’s primary implicit lease operations with MPC relate to the transportation services agreement between HSM and MPC. Revenue related to this agreement is recorded as Rental income-related parties on the Consolidated Statements of Income. The rental cost of sales related to the HSM implicit lease is depreciation of the HSM assets. All other services are provided to MPC on an as-needed basis and recorded as Service revenue-related parties on the Consolidated Statements of Income.

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

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

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

2. Accounting Standards

Recently Adopted

In September 2015, the FASB issued an accounting standard update that eliminates the requirement to restate prior period financial statements for measurement period adjustments related to business combinations. This accounting standard update requires that the cumulative impact of a measurement period adjustment be recognized in the reporting period in which the adjustment is identified. The change was effective for interim and annual periods beginning after December 15, 2015. The Partnership recognized measurement period adjustments during the first and second quarters of 2016 on a cumulative prospective basis as additional analysis was completed on the preliminary purchase price allocation for the acquisition of MarkWest. See Notes 3 and 16 for further discussion and detail related to these measurement period adjustments.

In April 2015, the FASB issued an accounting standard update requiring that the earnings of transferred net assets prior to the dropdown date of the net assets to a master limited partnership be allocated entirely to the general partner when calculating earnings per unit under the two class method. Under this guidance, previously reported earnings per unit of the limited partners will not change as a result of a dropdown transaction. The change was effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2015. Retrospective application is required. The Partnership adopted this accounting standard update in the first quarter of 2016 and it did not have a material impact on the consolidated results of operations, financial position or cash flows.

In April 2015, the FASB issued an accounting standard update clarifying whether a customer should account for a cloud computing arrangement as an acquisition of a software license or as a service arrangement by providing characteristics that a cloud computing arrangement must have in order to be accounted for as a software license acquisition. The change was effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2015. Retrospective or prospective application is allowed. The Partnership adopted this accounting standard update prospectively in the first quarter of 2016 and it did not have a material impact on the consolidated results of operations, financial position or cash flows.

In February 2015, the FASB issued an accounting standard update making targeted changes to the current consolidation guidance. The accounting standard update changes the considerations related to substantive rights, related parties, and decision making fees when applying the VIE consolidation model and eliminates certain guidance for limited partnerships and similar entities under the voting interest consolidation model. The change was effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2015. The Partnership adopted this accounting standard update in the first quarter of 2016 and it did not have a material impact on the consolidated results of operations, financial position or cash flows.

Not Yet Adopted

In August 2016, the FASB issued an accounting standard update related to the classification of certain cash flows. This accounting standard update provides classification solutions for eight different cash flow items including: debt prepayment/extinguishment costs, settlement of zero-coupon bonds, contingent consideration payments made after a business combination, proceeds from settlement of insurance claims, proceeds from settlement of corporate-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. 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.

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

In January 2016, the FASB issued an accounting standard update requiring unconsolidated equity investments, not accounted for under the equity method, to be measured at fair value with changes in fair value recognized in net income. The accounting standard update also requires the use of the exit price notion when measuring the fair value of financial instruments for disclosure purposes and the separate presentation of financial assets and liabilities by measurement category and form on the balance sheet and accompanying notes. The accounting standard update eliminates the requirement to disclose the methods and assumptions used in estimating the fair value of financial instruments measured at amortized cost. Lastly, the accounting standard update requires separate presentation in other comprehensive income of the portion of the total change in the fair value of a liability resulting from a change in the instrument-specific credit risk when electing to measure the liability at fair value in accordance with the fair value option for financial instruments. The changes are effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2017. Early adoption is permitted only for guidance regarding presentation of the liability’s credit risk. The Partnership is in the process of determining the impact of the accounting standard update on the consolidated financial statements.

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

In May 2014, the FASB issued an initial accounting standard update for revenue recognition for contracts with customers. The guidance in the accounting standard update states that revenue is recognized when a customer obtains control of a good or service. Recognition of the revenue will involve a multiple step approach including identifying the contract, identifying the separate performance obligations, determining the transaction price, allocating the price to the performance obligations and then recognizing the revenue as the obligations are satisfied. Additional disclosures will be required to provide adequate information to understand the nature, amount, timing and uncertainty of reported revenues and revenues expected to be recognized. The change will be effective on a retrospective or modified retrospective basis for fiscal years beginning after December 15, 2017, and interim periods within those years, with early adoption permitted no earlier than January 1, 2017. The Partnership is in the process of determining the impact of the accounting standard update on the consolidated financial statements.

3. Acquisitions

Acquisition of Hardin Street Marine LLC

On March 14, 2016, the Partnership entered into a Membership Interests Contribution Agreement (the “Contribution Agreement”) with MPLX GP LLC (“MPLX GP”), MPLX Logistics Holdings LLC and MPC Investment LLC (“MPC Investment”), each a wholly-owned subsidiary of MPC, related to the acquisition of HSM, MPC’s inland marine business, from MPC. Pursuant to the Contribution Agreement, the transaction was valued at $600 million consisting of a fixed number of common units and general partner units of 22,534,002 and 459,878, respectively. The general partner units maintain MPC’s two percent general partner interest 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. 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 distributions. The value of these waived distributions was $15 million.

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

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



	Three Months Ended September 30, 2015
(In millions)	MPLX LP (Previously Reported)		HSM		MPLX LP (Currently Reported)
Revenues and other income:
Service revenue	$	18	$	—	$	18
Service revenue - related parties	119		33		152
Rental income - related parties	4		21		25
Other income	1		—		1
Other income - related parties	7		11		18
Total revenues and other income	149		65		214
Costs and expenses:
Cost of revenues (excludes items below)	42		17		59
Purchases - related parties	27		16		43
Depreciation and amortization	13		6		19
General and administrative expenses	21		4		25
Other taxes	—		—		—
Total costs and expenses	103		43		146
Income from operations	46		22		68
Interest expense (net of amounts capitalized of $1 million)	4		—		4
Other financial costs	1		—		1
Income before income taxes	41		22		63
Net income	41		22		63
Less: Net income attributable to noncontrolling interests	—		—		—
Less: Net income attributable to Predecessor	—		22		22
Net income attributable to MPLX LP	41		—		41
Less: General partner’s interest in net income attributable to MPLX LP	8		—		8
Limited partners’ interest in net income attributable to MPLX LP	$	33	$	—	$	33



	Nine Months Ended September 30, 2015
(In millions)	MPLX LP (Previously Reported)		HSM		MPLX LP (Currently Reported)
Revenues and other income:
Service revenue	$	50	$	—	$	50
Service revenue - related parties	349		97		446
Rental income - related parties	12		63		75
Other income	4		—		4
Other income - related parties	19		34		53
Total revenues and other income	434		194		628
Costs and expenses:
Cost of revenues (excludes items below)	101		46		147
Purchases - related parties	75		48		123
Depreciation and amortization	38		20		58
General and administrative expenses	58		10		68
Other taxes	6		2		8
Total costs and expenses	278		126		404
Income from operations	156		68		224
Interest expense (net of amounts capitalized of $3 million)	15		—		15
Other financial costs	2		—		2
Income before income taxes	139		68		207
Net income	139		68		207
Less: Net income attributable to noncontrolling interests	1		—		1
Less: Net income attributable to Predecessor	—		68		68
Net income attributable to MPLX LP	138		—		138
Less: General partner’s interest in net income attributable to MPLX LP	19		—		19
Limited partners’ interest in net income attributable to MPLX LP	$	119	$	—	$	119

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



	Nine Months Ended September 30, 2015
(In millions)	MPLX LP (Previously Reported)			HSM			MPLX LP (Currently Reported)
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	139		$	68		$	207
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred financing costs	1			—			1
Depreciation and amortization	38			20			58
Deferred income taxes	—			(1		)	(1		)
Asset retirement expenditures	(1		)	—			(1		)
Changes in:
Current receivables	(2		)	—			(2		)
Current accounts payable and accrued liabilities	13			(1		)	12
Receivables from / liabilities to related parties	(4		)	(14		)	(18		)
All other, net	1			1			2
Net cash provided by operating activities	185			73			258
Investing activities:
Additions to property, plant and equipment	(121		)	(8		)	(129		)
Investments - loans to related parties	—			(64		)	(64		)
All other, net	2			—			2
Net cash used in investing activities	(119		)	(72		)	(191		)
Financing activities:
Long-term debt - borrowings	528			—			528
- repayments	(416		)	—			(416		)
Debt issuance costs	(4		)	—			(4		)
Net proceeds from equity offerings	1			—			1
Distributions to unitholders and general partner	(111		)	—			(111		)
Distributions to MPC from Predecessor	—			(1		)	(1		)
Distributions to noncontrolling interests	(1		)	—			(1		)
Net cash used in financing activities	(3		)	(1		)	(4		)
Net increase in cash and cash equivalents	63			—			63
Cash and cash equivalents at beginning of period	27			—			27
Cash and cash equivalents at end of period	$	90		$	—		$	90

Purchase of MarkWest Energy Partners, L.P.

On December 4, 2015, a wholly-owned subsidiary of the Partnership merged with MarkWest. Each common unit of MarkWest issued and outstanding immediately prior to the effective time of the MarkWest Merger was converted into a right to receive 1.09 common units representing limited partner interests in MPLX LP, plus a one-time cash payment of $6.20 per unit. Each Class B unit of MarkWest issued and outstanding immediately prior to the effective time of the MarkWest Merger was converted into the right to receive one Class B unit of MPLX LP. Each Class B unit of MPLX LP will convert into 1.09 common units of MPLX LP and the right to receive $6.20 in cash, and the conversion of the Class B units will occur in equal installments, the first of which occurred on July 1, 2016 and the second of which will occur on July 1, 2017. MPC contributed approximately $1.3 billion of cash to the Partnership to pay the aggregate cash consideration to MarkWest unitholders, without receiving any new equity in exchange. At closing, MPC made a payment of $1.2 billion to MarkWest common unitholders and the remaining $50 million is payable in equal amounts, the first of which was paid in July 2016 and the second of which will be

paid in July 2017, in connection with the conversion of the remaining outstanding Class B units to MPLX LP common units. The Partnership’s financial results reflect the results of MarkWest from the date of the acquisition.

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



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

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



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

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

The increase to the fair value of intangibles and property, plant and equipment noted above resulted in additional amortization and depreciation expense of approximately $1 million recognized for the nine months ended September 30, 2016, in Depreciation and amortization in the Consolidated Statements of Income, that would have been recorded for the year ended December 31, 2015, had the fair value adjustments been recorded as of December 4, 2015. The increase in the fair value of equity investments above would not have had a material effect on the income from equity method investments had the fair value adjustment been recorded as of December 4, 2015.

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

The fair value of the common units issued was determined on the basis of the closing market price of the Partnership’s units as of the effective time of the transaction and is considered a Level 1 measurement. The fair value of the Class B units issued was determined based on reference to the value of the common units, adjusted for a lack of distributions prior to their stated conversion dates, and is considered a Level 2 measurement. The fair values of the long-term debt and SMR liabilities were determined as of the acquisition date using the methods discussed in Note 13.

The fair value of the equity method investments was determined based on applying the discounted cash flow method, which is an income approach, to the Partnership’s equity method investments on an individual basis. Key assumptions include discount rates of 9.4 percent to 11.1 percent and terminal values based on the Gordon growth method to capitalize the cash flows, using a 2.5 percent long-term growth rate. Intangibles represent customer contracts and related relationships. The fair value of the intangibles was determined based on applying the multi-period excess earnings method, which is an income approach. Key assumptions include attrition rates by reporting unit ranging from 5.0 percent to 10.0 percent and discount rates by reporting unit ranging from 11.5 percent to 12.8 percent. The fair value of property, plant and equipment was determined primarily based on the cost approach. Key assumptions include inputs to the valuation methodology such as recent purchases of similar items and published data for similar items. Components were adjusted for economic and functional obsolescence, location, normal useful lives and capacity (if applicable). The fair value measurements for equity method investments, intangibles, and property, plant and equipment are based on significant inputs that are not observable in the market and, therefore, represent Level 3 measurements.

The amounts of revenue and income from operations associated with MarkWest are not included in the Consolidated Statement of Income for the period ended September 30, 2015.

Unaudited Pro Forma Financial Information

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



(In millions, except per unit data)	Three Months Ended September 30, 2015		Nine Months Ended September 30, 2015
Revenues and other income	$	689	$	2,021
Net income attributable to MPLX LP	107		160
Net income attributable to MPLX LP per unit - basic	0.17		0.08
Net income attributable to MPLX LP per unit - diluted	0.17		0.08

The unaudited pro forma financial information includes adjustments primarily to align accounting policies, adjust depreciation expense to reflect the fair value of property, plant and equipment, increase amortization expense related to identifiable intangible assets and adjust interest expense related to the fair value of MarkWest’s long-term debt, as well as the related income tax effects. The pro forma financial information does not give effect to potential synergies that could result from the acquisition and is not necessarily indicative of the results of future operations.

MarkWest has a 60 percent legal ownership interest in MarkWest Utica EMG. MarkWest Utica EMG’s inability to fund its planned activities without subordinated financial support qualify it as a VIE. The financing structure for MarkWest Utica EMG at its inception resulted in a de-facto agent relationship under which MarkWest was deemed to be the primary beneficiary of MarkWest Utica EMG. Therefore, MarkWest consolidated MarkWest Utica EMG in its historical financial statements. In the fourth quarter of 2015, based on economic conditions and other pertinent factors, the accounting for its investment in

MarkWest Utica EMG was re-assessed. As of December 4, 2015, the entity has been deconsolidated. For purposes of this pro forma financial information, MarkWest Utica EMG has been consolidated for the period prior to the acquisition consistent with its treatment in the historical periods presented.

A summary of the amounts included in the historical financial statements of MarkWest related to MarkWest Utica EMG are as follows:



(In millions)	Three Months Ended September 30, 2015		Nine Months Ended September 30, 2015
Revenues and other income	$	47	$	114
Cost of revenue excluding depreciation and amortization	8		22
Depreciation and amortization	17		49
Net income attributable to noncontrolling interest	20		49
Net income (loss)	1		(8		)

EMG Utica, LLC (“EMG Utica”), a joint venture partner in MarkWest Utica EMG, received a special non-cash allocation of income of approximately $11 million and $32 million for the three and nine months ended September 30, 2015. See Note 4 for a description of the transaction and its impact on the financial statements. Net income of MarkWest would not have changed had MarkWest Utica EMG been deconsolidated for the period ended September 30, 2015.

Investment in Pipeline Company

The Partnership currently expects to participate in a joint venture with Enbridge Energy Partners L.P. (“Enbridge Energy Partners”) to acquire a 9.1875 percent indirect ownership 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”) for $500 million. Furthermore, MPC expects to become a committed shipper on the Bakken Pipeline system under terms of an on-going open season. The acquisition remains subject to certain closing conditions and is expected to close in the fourth quarter of 2016.

The Bakken Pipeline system is currently expected to deliver in excess of 470,000 barrels per day 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.

ETP and SXL collectively own a 75 percent interest in each of the two joint ventures that are developing the Bakken Pipeline system. MPLX LP and Enbridge Energy Partners will participate in a new joint venture to acquire 49 percent of ETP and SXL’s 75 percent indirect interest in the Bakken Pipeline system. MPLX LP will own 25 percent of this new joint venture with Enbridge, which results in a 9.1875 percent indirect ownership interest in the Bakken pipeline system. The Partnership expects to account for the investment as part of the L&S segment using the equity method of accounting.

4. Equity Method Investments

MarkWest Utica EMG

Effective January 1, 2012, MarkWest Utica Operating Company, LLC (“Utica Operating”), a wholly-owned and consolidated subsidiary of MarkWest, and EMG Utica (together the “Members”) executed agreements to form a joint venture, MarkWest Utica EMG, to develop significant natural gas gathering, processing and NGL fractionation, transportation and marketing infrastructure in eastern Ohio. The related limited liability company agreement has been amended from time to time (the limited liability company agreement as currently in effect is referred to as the “Amended LLC Agreement”). The aggregate funding commitment of EMG Utica was $950 million (the “Minimum EMG Investment”). Thereafter, Utica Operating was required to fund, as needed, 100 percent of future capital for MarkWest Utica EMG until such time as the aggregate capital that had been contributed by the Members reached $2 billion, which occurred prior to the MarkWest Merger. Until such time as the investment balances of Utica Operating and EMG Utica are in the ratio of 70 percent and 30 percent, respectively (such time being referred to as the “Second Equalization Date”), EMG Utica will have the right, but not the obligation, to fund up to 10 percent of each capital call for MarkWest Utica EMG, and Utica Operating will be required to fund all remaining capital not elected to be funded by EMG Utica. After the Second Equalization Date, Utica Operating and EMG Utica will have the right, but not the obligation, to fund their pro rata portion (based on their respective investment balances) of any additional required capital and may also fund additional capital that the other party elects not to fund. As of September 30, 2016, EMG Utica has

contributed approximately $999 million and Utica Operating has contributed approximately $1.5 billion to MarkWest Utica EMG.

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

Under the Amended LLC Agreement, Utica Operating will continue to receive 60 percent of cash generated by MarkWest Utica EMG that is available for distribution until the earlier of December 31, 2016 and the date on which Utica Operating’s investment balance equals 60 percent of the aggregate investment balances of the Members. After the earlier of those dates, cash generated by MarkWest Utica EMG that is available for distribution will be allocated to the Members in proportion to their respective investment balances. As of September 30, 2016, Utica Operating’s investment balance in MarkWest Utica EMG was approximately 56 percent.

MarkWest Utica EMG is deemed to be a VIE. As of the date of the MarkWest Merger, Utica Operating is not deemed to be the primary beneficiary due to EMG Utica’s voting rights on significant matters. The Partnership’s portion of MarkWest Utica EMG’s net assets, which was $2.2 billion at September 30, 2016, is reported under the caption Equity method investments on the Consolidated Balance Sheets (see basis differential discussion below). The Partnership’s maximum exposure to loss as a result of its involvement with MarkWest Utica EMG includes its equity investment, any additional capital contribution commitments and any operating expenses incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. The Partnership did not provide any financial support to MarkWest Utica EMG that it was not contractually obligated to provide during the period ended September 30, 2016. The Partnership receives management fee revenue for engineering and construction, administrative and personnel services (“Operational Service revenue”) for operating MarkWest Utica EMG. The amount of Operational Service revenue related to MarkWest Utica EMG for the three and nine months ended September 30, 2016 was $5 million and $12 million, respectively, and is reported as Other income-related parties in the Consolidated Statements of Income.

Ohio Gathering

Ohio Gathering is a subsidiary of MarkWest Utica EMG and is engaged in providing natural gas gathering services in the Utica Shale in eastern Ohio. Ohio Gathering is a joint venture between MarkWest Utica EMG and Summit Midstream Partners, LLC (“Summit”). 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. The amount of Operational Service revenue related to Ohio Gathering for the three and nine months ended September 30, 2016 was approximately $5 million and $12 million, respectively, and is reported as Other income-related parties in the Consolidated Statements of Income.

Ohio Condensate

In December 2013, MarkWest formed MarkWest Utica EMG Condensate L.L.C. (“Utica Condensate”) for the purpose of engaging in wellhead condensate gathering, stabilization, terminalling, storage and marketing in Ohio. As of September 30, 2016, the Partnership owned 100 percent of Utica Condensate. Utica Condensate’s business is conducted solely through its subsidiary, Ohio Condensate, which is a joint venture between Utica Condensate and Summit. As of September 30, 2016, Utica Condensate owned 60 percent of Ohio Condensate. The Partnership accounts for Ohio Condensate, which is a VIE, as an equity method investment as MPLX LP exercises significant influence, but does not control Ohio Condensate and is not its primary beneficiary due to Summit’s voting rights on significant matters. The Partnership’s portion of Ohio Condensate’s net assets are reported under the caption Equity method investments on the Consolidated Balance Sheets. The Partnership receives Operational Service revenue for operating Ohio Condensate. The amount of Operational Service revenue related to Ohio Condensate for the three and nine months ended September 30, 2016 was $1 million and $3 million, respectively, and is reported as Other income-related parties in the Consolidated Statements of Income.

Summarized financial information for the nine months ended September 30, 2016 for equity method investments is as follows:



	Nine Months Ended September 30, 2016
(In millions)	MarkWest Utica EMG ⁽¹⁾		Ohio Condensate			Other VIEs		Non-VIEs		Total
Revenue and other income	$	165	$	13		$	—	$	106	$	284
Gross margin	165		13			—		52		230
Income (loss) from operations	95		(94		)	—		28		29
Net income (loss)	94		(94		)	—		28		28
Income (loss) from equity method investments⁽²⁾	10		(88		)	—		6		(72		)

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



	September 30, 2016
(In millions)	MarkWest Utica EMG ⁽¹⁾		Ohio Condensate		Other VIEs		Non-VIEs		Total
Current assets	$	50	$	3	$	1	$	34	$	88
Noncurrent assets	2,183		32		70		383		2,668
Current liabilities	22		4		—		21		47
Noncurrent liabilities	2		14		—		—		16



	December 31, 2015
(In millions)	MarkWest Utica EMG ⁽¹⁾		Ohio Condensate		Other VIEs		Non-VIEs		Total
Current assets	$	113	$	7	$	—	$	30	$	150
Noncurrent assets	2,207		127		42		243		2,619
Current liabilities	77		6		1		18		102
Noncurrent liabilities	1		12		—		—		13


(1)	MarkWest Utica EMG’s noncurrent assets includes its investment in its subsidiary Ohio Gathering, which does not appear elsewhere in this table. The investment was $788 million and $781 million as of September 30, 2016 and December 31, 2015, respectively.


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

As of September 30, 2016, the carrying value of the Partnership’s equity method investments was $1.1 billion higher than the underlying net assets of the investees. This basis difference is being amortized or accreted into net income over the remaining estimated useful lives of the underlying net assets, except for $459 million of excess related to goodwill. During the second quarter of 2016, the Partnership completed its purchase price allocation related to the MarkWest Merger. As a result, a portion of the basis differential related to goodwill for Utica EMG was reclassified to fixed assets and will be amortized prospectively.

During the second quarter of 2016, forecasts for Ohio Condensate were reduced to align with updated forecasts for customer requirements. As the operator of that entity responsible for maintaining its financial records, the Partnership completed a fixed asset impairment analysis as of June 30, 2016, in accordance with ASC Topic 360, to determine the potential fixed asset impairment charge. The resulting fixed asset impairment charge recorded within Ohio Condensate’s financial statements was $96 million. Based on the Partnership’s 60 percent ownership of Ohio Condensate, approximately $58 million was recorded in the second quarter of 2016 in Income (loss) from equity method investments on the accompanying Consolidated Statements of Income.

The Partnership’s investment in Ohio Condensate, which was established at fair value in connection with the MarkWest Merger, exceeded its proportionate share of the underlying net assets. Therefore, in conjunction with the ASC Topic 360 impairment analysis, the Partnership completed an equity method impairment analysis in accordance with ASC Topic 323 to determine the potential additional equity method impairment charge to be recorded on the Partnership’s consolidated financial statements resulting from an other-than-temporary impairment. As a result, an additional impairment charge of approximately $31 million was recorded in the second quarter of 2016 in Income (loss) from equity method investments on the accompanying

Consolidated Statements of Income, which eliminated the basis differential established in connection with the MarkWest Merger.

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

5. Related Party Agreements and Transactions

The Partnership’s material related parties include:


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


•	Centennial Pipeline LLC (“Centennial”), in which MPC has a 50 percent interest. Centennial owns a products pipeline and storage facility.


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


•	MarkWest Utica EMG, in which MPLX LP has a 60 percent interest. MarkWest Utica EMG is engaged in significant natural gas processing and NGL fractionation, transportation and marketing in eastern Ohio.


•	Ohio Gathering, in which MPLX LP has a 36 percent indirect interest. Ohio Gathering is a subsidiary of MarkWest Utica EMG providing natural gas gathering service in the Utica Shale region of eastern Ohio.


•	Jefferson Dry Gas, in which MPLX LP has a 67 percent interest. Jefferson Dry Gas is engaged in dry natural gas gathering in Jefferson County, Ohio.


•	Ohio Condensate, in which MPLX LP has a 60 percent interest. Ohio Condensate is engaged in wellhead condensate gathering, stabilization, terminalling, transportation and storage within certain defined areas of Ohio.

Related Party Agreements

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

In addition, the Partnership is party to a loan agreement with MPC Investment, a wholly-owned subsidiary of MPC. Under the terms of the agreement, MPC Investment will make a loan or loans to the Partnership on a revolving basis as requested by the Partnership and as agreed to by MPC Investment, in an amount or amounts that do not result in the aggregate principal amount of all loans outstanding exceeding $500 million at any one time. The entire unpaid principal amount of the loan, together with all accrued and unpaid interest and other amounts (if any), shall become due and payable on December 4, 2020. MPC Investment may demand payment of all or any portion of the outstanding principal amount of the loan, together with all accrued and unpaid interest and other amounts (if any), at any time prior to December 4, 2020. Borrowings under the loan will bear interest at LIBOR plus 1.50 percent. During the nine months ended September 30, 2016, the Partnership borrowed $2.2 billion and repaid $2.2 billion, resulting in no outstanding balance at September 30, 2016. Borrowings were at an average interest rate of 1.94 percent, per annum. 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, 2015.

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

HSM Agreements

As discussed in Note 3, the Partnership acquired HSM on March 31, 2016. HSM has various operating, management services and employee services agreements with MPC, which are discussed below.

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On January 1, 2015, HSM entered into a long-term, fee-based transportation services agreement with MPC with an initial term of six years and automatically renews for two additional renewal terms of five years each unless either party provides the other party with written notice of its intent to terminate at least 12 months prior to the end of the then-current term. Under the agreement, HSM provides marine transportation of crude oil, feedstocks and refined petroleum products, as well as related services. Under the agreement MPC pays HSM monthly for the following: the specified day rate for equipment and charges for services related to transportation, tankerman services and cleaning and repair charges. Fleeting services are billed monthly.

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

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

Related Party Transactions

Sales to related parties were as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2016		2015		2016		2015
Service revenues
MPC	$	153	$	152	$	448	$	446
Rental income
MPC	$	29	$	25	$	84	$	75
Product sales⁽¹⁾
MPC	$	2	$	—	$	8	$	—


(1)	For the three and nine months ended September 30, 2016, there were $13 million and $25 million respectively, of 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.

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.

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



	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2016		2015		2016		2015
MPC	$	14	$	18	$	47	$	52
MarkWest Utica EMG	5		—		12		—
Ohio Gathering	5		—		12		—
Ohio Condensate	1		—		3		—
Other	1		—		4		1
Total	$	26	$	18	$	78	$	53

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



	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2016		2015		2016		2015
Purchases - related parties	$	4	$	9	$	15	$	23
General and administrative expenses	7		12		22		34
Total	$	11	$	21	$	37	$	57

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



	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2016		2015		2016		2015
MPC	$	11	$	3	$	29	$	9

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.

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Employee services expenses from related parties were as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2016		2015		2016		2015
Purchases - related parties	$	80	$	34	$	223	$	100
General and administrative expenses	21		6		61		21
Total	$	101	$	40	$	284	$	121

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)	September 30, 2016		December 31, 2015
MPC	$	100	$	175
MarkWest Utica EMG	2		4
Ohio Gathering	2		5
Other	2		3
Total	$	106	$	187

Long-term receivables with related parties, including straight line rental income for both periods presented, as well as reimbursements from the MarkWest Merger to be provided by MPC for the conversion of Class B units for the period ended December 31, 2015, were as follows:



(In millions)	September 30, 2016		December 31, 2015
MPC	$	3	$	25

Payables to related parties were as follows:



(In millions)	September 30, 2016		December 31, 2015
MPC	$	52	$	33
MarkWest Utica EMG	16		21
Total	$	68	$	54

During the nine months ended September 30, 2016 and the year ended December 31, 2015, MPC did not ship its minimum committed volumes on certain pipeline systems. In addition, capital projects the Partnership is undertaking at the request of MPC are reimbursed in cash and recognized in income over the remaining term of the applicable transportation services agreements. The Deferred revenue-related parties balance associated with the minimum volume deficiencies and project reimbursements were as follows:



(In millions)	September 30, 2016		December 31, 2015
Minimum volume deficiencies - MPC	$	42	$	36
Project reimbursements - MPC	5		5
Total	$	47	$	41

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6. Net Income (Loss) Per Limited Partner Unit

Net income (loss) per unit applicable to common limited partner units and to subordinated limited partner units is computed by dividing the respective limited partners’ interest in net income (loss) attributable to MPLX LP by the weighted average number of common units and subordinated units outstanding. Because the Partnership has more than one class of participating securities, it uses the two-class method when calculating the net income (loss) per unit applicable to limited partners. The classes of participating securities include common units, subordinated units, general partner units, preferred units, certain equity-based compensation awards and incentive distribution rights (“IDRs”).

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

As discussed further in Note 7, the subordinated units, all of which were owned by MPC, were converted into common units during the third quarter of 2015. For purposes of calculating net income (loss) per unit, the subordinated units were treated as if they converted to common units on July 1, 2015.

For the three and nine months ended September 30, 2016, the Partnership had dilutive potential common units consisting of certain equity-based compensation awards and Class B units. Diluted net income (loss) per limited partner unit for the nine months ended September 30, 2016 is the same as basic net income (loss) per limited partner unit since the inclusion of any potential common units would have been anti-dilutive. Potential common units omitted from the diluted earnings per unit calculation for the nine months ended September 30, 2016 was approximately 8 million.



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2016			2015			2016			2015
Net income attributable to MPLX LP	$	141		$	41		$	100		$	138
Less: Limited partners’ distributions declared on preferred units ⁽¹⁾	16			—			25			—
General partner’s distributions declared (including IDRs)⁽¹⁾	54			9			148			20
Limited partners’ distributions declared on common units ⁽¹⁾	179			38			507			75
Limited partner’s distributions declared on subordinated units ⁽¹⁾	—			—			—			31
Undistributed net (loss) income attributable to MPLX LP	$	(108	)	$	(6	)	$	(580	)	$	12


(1)	See Note 7 for distribution information.

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	Three Months Ended September 30, 2016
(In millions, except per unit data)	General Partner			Limited Partners’ Common Units			Redeemable Preferred Units		Total
Basic and diluted net income attributable to MPLX LP per unit:
Net income attributable to MPLX LP:
Distributions declared (including IDRs)	$	54		$	179		$	16	$	249
Undistributed net loss attributable to MPLX LP	(3		)	(105		)	—		(108		)
Net income attributable to MPLX LP ⁽¹⁾	$	51		$	74		$	16	$	141
Weighted average units outstanding:
Basic	7			341			31		379
Diluted	7			346			31		384
Net income attributable to MPLX LP per limited partner unit:
Basic				$	0.22
Diluted				$	0.21



	Three Months Ended September 30, 2015
(In millions, except per unit data)	General Partner			Limited Partners’ Common Units			Limited Partner’s Subordinated Units		Total
Basic and diluted net income attributable to MPLX LP per unit:
Net income attributable to MPLX LP:
Distributions declared (including IDRs)	$	9		$	38		$	—	$	47
Undistributed net loss attributable to MPLX LP	(1		)	(5		)	—		(6		)
Net income attributable to MPLX LP ⁽¹⁾	$	8		$	33		$	—	$	41
Weighted average units outstanding:
Basic	2			80			—		82
Diluted	2			80			—		82
Net income attributable to MPLX LP per limited partner unit:
Basic				$	0.41		$	—
Diluted				$	0.41		$	—

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



	Nine Months Ended September 30, 2015
(In millions, except per unit data)	General Partner		Limited Partners’ Common Units		Limited Partner’s Subordinated Units		Total
Basic and diluted net income attributable to MPLX LP per unit:
Net income attributable to MPLX LP:
Distributions declared (including IDRs)	$	20	$	75	$	31	$	126
Undistributed net income attributable to MPLX LP	6		4		2		12
Net income attributable to MPLX LP ⁽¹⁾	$	26	$	79	$	33	$	138
Weighted average units outstanding:
Basic	2		56		25		83
Diluted	2		56		25		83
Net income attributable to MPLX LP per limited partner unit:
Basic			$	1.42	$	1.36
Diluted			$	1.42	$	1.36


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

7. Equity

Units Outstanding – The Partnership had 348,489,049 common units outstanding as of September 30, 2016. Of that number, 86,619,313 were owned by MPC, which also owned the two percent general partner interest, represented by 7,193,467 general partner units.

Following payment of the cash distribution for the second quarter of 2015, the requirements for the conversion of all subordinated units were satisfied under the partnership agreement. As a result, effective August 17, 2015, the 36,951,515 subordinated units owned by MPC were converted into common units on a one-for-one basis and thereafter participate on terms equal with all other common units in distributions of available cash. The conversion did not impact the amount of the cash distributions paid by the Partnership or the total units outstanding.

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

ATM Program – On August 4, 2016, the Partnership entered into a second amended and restated distribution agreement providing for the continuous issuance of up to an aggregate of $1.2 billion of common units, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of any offerings (such continuous offering program, or at-the-market program, referred to as the “ATM Program”). The Partnership expects the net proceeds from sales under the ATM Program will be used for general partnership purposes including repayment of debt and funding for acquisitions, working capital requirements and capital expenditures. During the nine months ended September 30, 2016, the sale of common units under the ATM Program generated net proceeds of approximately $499 million.

The changes in the number of units outstanding from December 31, 2015 through September 30, 2016 are summarized below:



(In units)	Common	Class B⁽¹⁾		General Partner		Total
Balance at December 31, 2015	296,687,176	7,981,756		6,800,475		311,469,407
Unit-based compensation awards⁽²⁾	39,637	—		810		40,447
Issuance of units under the ATM Program⁽³⁾	17,725,000	—		361,732		18,086,732
Contribution of HSM⁽⁴⁾	22,534,002	—		459,878		22,993,880
Class B conversion ⁽⁵⁾	4,350,057	(3,990,878	)	7,330		366,509
Class A Reorganization⁽⁶⁾	7,153,177	—		(436,758	)	6,716,419
Balance at September 30, 2016	348,489,049	3,990,878		7,193,467		359,673,394


(1)	On July 1, 2016, 3,990,878 Class B units converted to 4,350,057 common units and were eligible to receive the second quarter 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 810 general partner units to maintain its two percent general partner interest.


(3)	As a result of common units issued under the ATM Program during the period, MPLX GP contributed $11 million in exchange for 361,732 general partner units to maintain its two percent general partner interest.


(4)	See Note 3 for information regarding the HSM acquisition.


(5)	As a result of the Class B units converted to common units during the period, MPLX GP contributed less than $1 million in exchange for 7,330 general partner units to maintain its two percent general partner interest.

(6)

As a result of the Class A Reorganization, 7 million common units were acquired by MPC that represents the common units received by MPC on the exchange of the MPLX LP Class A units less the units redeemed in the distribution of MPLX Holdings Inc., including the MPLX LP Class A units. Additionally, MPLX LP transferred common units representing a two percent ownership interest of MPLX Holdings Inc. to MPLX GP in exchange for 436,758 MPLX general partner units held by MPLX GP, as discussed above.

Issuance of Additional Securities – The partnership agreement authorizes the issuance of an unlimited number of additional partnership securities for the consideration and on the terms and conditions determined by the general partner without the approval of the unitholders.

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Net Income Allocation – In preparing the Consolidated Statements of Equity, net (loss) 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 remaining unitholders in accordance with their respective ownership percentages. However, when distributions related to the incentive distribution rights are made, earnings equal to the amount of those distributions are first allocated to the general partner before the remaining earnings are allocated to the unitholders based on their respective ownership percentages. The following table presents the allocation of the general partner’s interest in net income attributable to MPLX LP:



	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2016		2015		2016			2015
Net income attributable to MPLX LP	$	141	$	41	$	100		$	138
Less: Preferred unit distributions	16		—		25			—
General partner's incentive distribution rights and other	49		8		137			17
Net income (loss) attributable to MPLX LP available to general and limited partners	$	76	$	33	$	(62	)	$	121

General partner's two percent interest in net income (loss) attributable to MPLX LP	$	2	$	—	$	(1	)	$	2
General partner's incentive distribution rights and other	49		8		137			17
General partner's interest in net income attributable to MPLX LP	$	51	$	8	$	136		$	19

Cash distributions – The partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common and subordinated unitholders and general partner will receive. In accordance with the partnership agreement, on October 25, 2016, the Partnership declared a quarterly cash distribution of $0.5150 per unit, resulting in total distributions of $233 million. These distributions will be paid on November 14, 2016 to unitholders of record on November 4, 2016.

The allocation of total quarterly cash distributions to preferred, general and limited partners is as follows for the three and nine months ended September 30, 2016 and 2015. The Partnership’s distributions are declared subsequent to quarter end; therefore, the following table represents total cash distributions applicable to the period in which the distributions were earned.



	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2016		2015		2016		2015
General partner's distributions:
General partner's distributions	$	5	$	1	$	13	$	3
General partner's incentive distribution rights distributions	49		8		135		17
Total general partner's distributions	$	54	$	9	$	148	$	20
Limited partners' distributions:
Common unitholders	$	179	$	38	$	507	$	75
Subordinated unitholders	—		—		—		31
Total limited partners' distributions	179		38		507		106
Preferred unit distributions	16		—		25		—
Total cash distributions declared	$	249	$	47	$	680	$	126

8. Redeemable Preferred Units

Private Placement of Preferred Units – On May 13, 2016, MPLX 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 was used for capital expenditures, repayment of debt and general partnership purposes.

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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 commencing for the quarter ended June 30, 2016, with a prorated amount from the date of issuance. 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. Since the Preferred Unit distribution was declared subsequent to the end of the second quarter of 2016, the distribution was not accrued to the Preferred Unit holders’ capital account. For the quarter ended June 30, 2016, the Preferred Units received an earned aggregate cash distribution of $9 million, based on the quarterly per unit distribution prorated for the 49-day period the Preferred Units were outstanding during the second quarter of 2016.

The changes in the redeemable preferred balance for 2016 were as follows:



(In millions)	Redeemable Preferred Units
Issuance of MPLX LP redeemable preferred units on May 13, 2016	$	984
Net income allocated for May 13, 2016 through September 30, 2016	25
Distributions received by preferred unitholders	(9		)
Balance at September 30, 2016	$	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. Because 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 is organized and managed based upon the nature of the products and services it offers.


•	L&S - transports and stores crude oil and refined petroleum products. Segment information for prior periods includes HSM as it is an entity under common control.


•	G&P - gathers, processes and transports natural gas; gathers, transports, fractionates, stores and markets NGLs. This segment is the result of the MarkWest Merger on December 4, 2015 discussed in more detail in Note 3. Segment information for periods prior to the MarkWest Merger does not include amounts for these operations.

The Partnership has investments in entities that are accounted for using the equity method of accounting (see Note 4). However, the CEO views the Partnership operated equity method investments’ financial information as if those investments were consolidated.

Segment operating income represents income from operations attributable to the reportable segments. Corporate general and administrative expenses, unrealized derivative gains (losses), property, plant and equipment impairment, goodwill impairment

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and depreciation and amortization are not allocated to the reportable segments. Management does not consider these items allocable to or controllable by any individual segment and, therefore, excludes these items when evaluating segment performance. Segment results are also adjusted to exclude the portion of income from operations attributable to the noncontrolling interests related to partially owned entities that are either consolidated or accounted for as equity method investments.

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



	Three Months Ended September 30, 2016
(In millions)	L&S		G&P		Total
Revenues and other income:
Segment revenues	$	200	$	567	$	767
Segment other income	16		1		17
Total segment revenues and other income	216		568		784
Costs and expenses:
Segment cost of revenues	92		239		331
Segment operating income before portion attributable to noncontrolling interest	124		329		453
Segment portion attributable to noncontrolling interest	—		36		36
Segment operating income attributable to MPLX LP	$	124	$	293	$	417



	Three Months Ended September 30, 2015
(In millions)	L&S
Revenues and other income:
Segment revenues	$	195
Segment other income	19
Total segment revenues and other income	214
Costs and expenses:
Segment cost of revenues	102
Segment operating income before portion attributable to noncontrolling interest and Predecessor	112
Segment portion attributable to noncontrolling interest and Predecessor	31
Segment operating income attributable to MPLX LP	$	81



	Nine Months Ended September 30, 2016
(In millions)	L&S		G&P		Total
Revenues and other income:
Segment revenues	$	585	$	1,595	$	2,180
Segment other income	53		1		54
Total segment revenues and other income	638		1,596		2,234
Costs and expenses:
Segment cost of revenues	269		662		931
Segment operating income before portion attributable to noncontrolling interest and Predecessor	369		934		1,303
Segment portion attributable to noncontrolling interest and Predecessor	34		113		147
Segment operating income attributable to MPLX LP	$	335	$	821	$	1,156

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	Nine Months Ended September 30, 2015
(In millions)	L&S
Revenues and other income:
Segment revenues	$	571
Segment other income	57
Total segment revenues and other income	628
Costs and expenses:
Segment cost of revenues	278
Segment operating income before portion attributable to noncontrolling interest and Predecessor	350
Segment portion attributable to noncontrolling interest and Predecessor	99
Segment operating income attributable to MPLX LP	$	251



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2016			2015			2016			2015
Reconciliation to Income from operations:
Segment operating income attributable to MPLX LP	$	417		$	81		$	1,156		$	251
Segment portion attributable to unconsolidated affiliates	(77		)	—			(243		)	—
Segment portion attributable to noncontrolling interest and Predecessor	36			31			147			99
Income (loss) from equity method investments	6			—			(72		)	—
Other income - related parties	11			—			29			—
Unrealized derivative losses	(2		)	—			(23		)	—
Impairment expense	—			—			(130		)	—
Depreciation and amortization	(138		)	(19		)	(407		)	(58		)
General and administrative expenses	(46		)	(25		)	(147		)	(68		)
Income from operations	$	207		$	68		$	310		$	224



	Three Months Ended September 30,					Nine Months Ended September 30,
(In millions)	2016			2015		2016			2015
Reconciliation to Total revenues and other income:
Total segment revenues and other income	$	784		$	214	$	2,234		$	628
Revenue adjustment from unconsolidated affiliates	(100		)	—		(303		)	—
Income (loss) from equity method investments	6			—		(72		)	—
Other income - related parties	11			—		29			—
Unrealized derivative gain (loss)	2			—		(12		)	—
Total revenues and other income	$	703		$	214	$	1,876		$	628

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	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2016			2015			2016			2015
Reconciliation to Net income attributable to noncontrolling interests and Predecessor:
Segment portion attributable to noncontrolling interest and Predecessor	$	36		$	31		$	147		$	99
Portion of noncontrolling interests and Predecessor related to items below segment income from operations	(16		)	(9		)	(101		)	(30		)
Portion of operating income attributable to noncontrolling interest of unconsolidated affiliates	(18		)	—			(20		)	—
Net income attributable to noncontrolling interests and Predecessor	$	2		$	22		$	26		$	69

The following reconciles segment capital expenditures to total capital expenditures:



	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2016		2015		2016		2015
L&S segment capital expenditures	$	156	$	59	$	300	$	129
G&P segment capital expenditures⁽¹⁾	183		—		668		—
Total segment capital expenditures	339		59		968		129
Less: Capital expenditures for Partnership operated, non-wholly-owned subsidiaries	34		—		94		—
Total capital expenditures	$	305	$	59	$	874	$	129


(1)	The G&P segment includes $34 million and $94 million of capital expenditures related to Partnership operated, non-wholly-owned subsidiaries for the three and nine months ended September 30, 2016.

Total assets by reportable segment were:



(In millions)	September 30, 2016		December 31, 2015
Cash and cash equivalents	$	208	$	43
L&S	2,022		1,842
G&P	14,185		14,219
Total assets	$	16,415	$	16,104

10. Income Tax

The Partnership is not a taxable entity for United States federal income tax purposes or for the majority of states that impose an income tax. Taxes on the Partnership’s net income generally are borne by its partners through the allocation of taxable income. The Partnership’s income tax (benefit) provision results from partnership activity in the states of Texas, Ohio and Tennessee.

As a result of the Class A Reorganization discussed in Note 7, MarkWest Hydrocarbon (MarkWest Hydrocarbon, Inc. prior to the Class A Reorganization) is no longer a tax paying entity for federal income tax purposes or for the majority of states that impose an income tax effective September 1, 2016. After MarkWest Hydrocarbon files its 2016 income tax returns in 2017, the Partnership anticipates a residual tax provision to be recorded. In connection with the Class A Reorganization, MPC assumed $377 million of MPLX’s deferred tax liabilities.

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The Partnership’s income tax activity was less than $1 million for the three and nine months ended September 30, 2015. A reconciliation of the benefit for income tax and the amount computed by applying the federal statutory rate of 35 percent to the income before income taxes for the nine months ended September 30, 2016 is as follows:



(In millions)	MarkWest Hydrocarbon			Partnership			Eliminations			Consolidated⁽¹⁾
Income before (benefit) provision for income tax	$	(41	)	$	153		$	2		$	114
Federal statutory rate	35		%	—		%	—		%
Federal income tax at statutory rate⁽²⁾	(14		)	—			—			(14		)
Change in state statutory rate	(1		)	—			—			(1		)
State income taxes net of federal benefit - MarkWest Hydrocarbon	(2		)	—			—			(2		)
Provision on income from MPLX LP Class A units⁽²⁾	3			—			—			3
Other	1			1			—			2
(Benefit) provision for income tax	$	(13	)	$	1		$	—		$	(12	)


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


(2)	MarkWest Hydrocarbon paid tax on its share of the Partnership’s income or loss as a result of its ownership of MPLX LP Class A units through September 1, 2016.

11. Inventories

Inventories consist of the following:



(In millions)	September 30, 2016		December 31, 2015
NGLs	$	2	$	3
Line fill	6		5
Spare parts, materials and supplies	42		43
Total inventories	$	50	$	51

12. Property, Plant and Equipment

Property, plant and equipment with associated accumulated depreciation was:



(In millions)	September 30, 2016		December 31, 2015
Natural gas gathering and NGL transportation pipelines and facilities	$	4,670	$	4,307
Processing, fractionation and storage facilities	3,481		3,185
Pipelines and related assets	1,372		1,128
Barges and towing vessels	479		475
Land, building, office equipment and other	673		606
Construction in progress	876		946
Total	11,551		10,647
Less accumulated depreciation	1,014		650
Property, plant and equipment, net	$	10,537	$	9,997

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13. Fair Value Measurements

Fair Values – Recurring

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



(In millions)	September 30, 2016					December 31, 2015
	Assets		Liabilities			Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	—	$	—		$	2	$	—
Significant unobservable inputs (Level 3)
Commodity contracts	—		(3		)	7		—
Embedded derivatives in commodity contracts	—		(44		)	—		(32		)
Total carrying value in Consolidated Balance Sheets	$	—	$	(47	)	$	9	$	(32	)

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



Level 3 Instrument	Balance Sheet Classification	Unobservable Inputs	Value Range	Time Period
Commodity contracts	Liabilities	Forward ethane prices (per gallon)⁽¹⁾	$0.22 - $0.29	Oct. 16 - Dec. 17
		Forward propane prices (per gallon)⁽¹⁾	$0.53 - $0.57	Oct. 16 - Dec. 17
		Forward isobutane prices (per gallon)⁽¹⁾	$0.69 - $0.74	Oct. 16 - Dec. 17
		Forward normal butane prices (per gallon)⁽¹⁾	$0.64 - $0.72	Oct. 16 - Dec. 17
		Forward natural gasoline prices (per gallon)⁽¹⁾	$1.08 - $1.12	Oct. 16 - Dec. 17

Embedded derivatives in commodity contracts	Liabilities	Forward propane prices (per gallon)⁽¹⁾	$0.53 - $0.59	Oct. 16 - Dec. 22
		Forward isobutane prices (per gallon)⁽¹⁾	$0.68 - $0.75	Oct. 16 - Dec. 22
		Forward normal butane prices (per gallon)⁽¹⁾	$0.64 - $0.72	Oct. 16 - Dec. 22
		Forward natural gasoline prices (per gallon)⁽¹⁾	$1.08 - $1.19	Oct. 16 - Dec. 22
		Forward natural gas prices (per mmbtu)⁽²⁾	$2.37 - $3.13	Oct. 16 - Dec. 22
		ERCOT Pricing (per MegaWatt Hour)	$24.66 - $27.11	Oct. 16 - Dec. 16
		Probability of renewal⁽³⁾	50.0%
		Probability of renewal for second 5-yr term⁽³⁾	75.0%


(1)	NGL prices used in the valuation are generally at the lower end of the range in the early years and increase over time.


(2)	Natural gas prices used in the valuations are generally at the lower end of the range in the early years and increase over time.


(3)	The producer counterparty to the embedded derivative has the option to renew the gas purchase agreement and the related keep-whole processing agreement for two successive five-year terms after 2022. The embedded gas purchase agreement cannot be renewed without the renewal of the related keep-whole processing agreement. Due to the significant number of

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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 14. 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 14. 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 reviewed and validated on a quarterly basis by the Risk Department by comparing the pricing and option volatilities to actual market data and/or data provided by at least one other independent third-party pricing service.

Management is responsible for the valuation of the Natural Gas Embedded Derivative discussed in Note 14. 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 (September 2016 through December 2022) for management’s use in determining the fair value of the Natural Gas Embedded Derivative. In developing the pricing curves for these periods, the Risk Department maximizes its use of the latest known market data and trends as well as its understanding of the historical relationships between forward NGL and natural gas prices and the forward market data that is available for the required period, such as crude oil pricing and natural gas pricing from other markets. However, there is very limited actual market data available to validate the Risk Department’s estimated price curves. Management also assesses the probability of the producer customer’s renewal of the contracts, which includes consideration of:


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


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


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

Changes in Level 3 Fair Value Measurements

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

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	Three Months Ended September 30, 2016						Nine Months Ended September 30, 2016
(In millions)	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)			Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(4	)	$	(40	)	$	7		$	(32	)
Total gain (loss) (realized and unrealized) included in earnings⁽¹⁾	2			(6		)	(5		)	(17		)
Settlements	(1		)	2			(6		)	5
Netting adjustment ⁽²⁾	—			—			1			—
Fair value at end of period	$	(3	)	$	(44	)	$	(3	)	$	(44	)
The amount of total losses for the period included in earnings attributable to the change in unrealized losses relating to liabilities still held at end of period	$	—		$	(4	)	$	(4	)	$	(15	)


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

(2)

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

Fair Values – Reported

The Partnership’s primary financial instruments are cash and cash equivalents, receivables, receivables from related parties, accounts payable, payables to related parties and long-term debt. The Partnership’s fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) MPC’s investment-grade credit rating and (3) the historical incurrence of and expected future insignificance of bad debt expense, which includes an evaluation of counterparty credit risk. The Partnership believes the carrying values of its current assets and liabilities approximate fair value. The recorded value of the amounts outstanding under the bank revolving credit facility, if any, approximates fair value due to the variable interest rate that approximates current market rates. Derivative instruments are recorded at fair value, based on available market information (see Note 14).

The SMR liability and $4.1 billion aggregate principal of the Partnership’s long-term debt were recorded at fair value in connection with the MarkWest Merger as of December 4, 2015, which established a new cost basis for each of those liabilities. The fair value of the long-term debt is estimated based on recent market non-binding indicative quotes. The fair value of the SMR liability is estimated using a discounted cash flow approach based on the contractual cash flows and the Partnership’s unsecured borrowing rate. The long-term debt and SMR liability fair values are considered Level 3 measurements.

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



	September 30, 2016				December 31, 2015
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Long-term debt	$	4,987	$	4,411	$	5,212	$	5,255
SMR liability	$	109	$	97	$	99	$	100

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14. Derivative Financial Instruments

Commodity Derivatives

NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond the Partnership’s control. The Partnership’s profitability is directly affected by prevailing commodity prices primarily as a result of processing or conditioning at its own or third-party processing plants, purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and the cost of third-party transportation and fractionation services. To the extent that commodity prices influence the level of natural gas drilling by the Partnership’s producer customers, such prices also affect profitability. To protect itself financially against adverse price movements and to maintain more stable and predictable cash flows so that the Partnership can meet its cash distribution objectives, debt service and capital plans, the Partnership executes a strategy governed by its risk management policy. The Partnership has a committee comprised of senior management that oversees risk management activities, continually monitors the risk management program and adjusts its strategy as conditions warrant. The Partnership enters into certain derivative contracts to reduce the risks associated with unfavorable changes in the prices of natural gas and NGLs. Derivative contracts utilized are swaps and options traded on the OTC market and fixed price forward contracts. The risk management policy does not allow the Partnership to take speculative positions with its derivative contracts.

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

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 2017. 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 & Resources L.L.C. (“MarkWest Liberty Midstream”) to enter into derivative positions without posting cash collateral. The Partnership uses standardized agreements that allow for offset of certain positive and negative exposures (“master netting arrangements”) in the event of default or other terminating events, including bankruptcy.

The Partnership records derivative contracts at fair value in the Consolidated Balance Sheets and has not elected hedge accounting or the normal purchases and normal sales designation (except for electricity and certain other qualifying contracts, for which the normal purchases and normal sales designation has been elected). The Partnership’s accounting may cause volatility in the Consolidated Statements of Income as the Partnership recognizes in current earnings all unrealized gains and losses from the changes in fair value of derivatives.

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Volume of Commodity Derivative Activity

As of September 30, 2016, the Partnership had the following outstanding commodity contracts that were executed to manage the cash flow risk associated with future sales of NGLs:



Derivative contracts not designated as hedging instruments	Financial Position	Notional Quantity (net)
Crude Oil (bbl)	Short	92,000
Natural Gas (MMBtu)	Long	841,931
NGLs (gal)	Short	56,107,839

Embedded Derivatives in Commodity Contracts

The Partnership has a commodity contract with a producer customer in the Southern Appalachian region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. For accounting purposes, these contracts have been aggregated into a single contract and are evaluated together. In February 2011, the Partnership executed agreements with the producer customer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022, with the producer customer’s option to extend the agreement for two successive five-year terms through December 31, 2032. The purchase of gas at prices based on the frac spread and the option to extend the agreements have been identified as a single embedded derivative, which is recorded at fair value. The probability of renewal is determined based on extrapolated pricing curves, a review of the overall expected favorability of the contracts based on such pricing curves, and assumptions about the counterparty’s potential business strategy decision points that may exist at the time the counterparty would elect whether to renew the contract. The changes in fair value of this embedded derivative are based on the difference between the contractual and index pricing, the probability of the producer customer exercising its option to extend and the estimated favorability of these contracts compared to current market conditions. The changes in fair value are recorded in earnings through Purchased product costs in the Consolidated Statements of Income. As of September 30, 2016, the estimated fair value of this contract was a liability of $44 million.

The Partnership has a commodity contract that gives it an option to fix a component of the utilities cost to an index price on electricity at a plant location in the Southwest operations through the fourth quarter of 2017. The contract is currently fixed through the fourth quarter of 2016 with the ability to fix the commodity contract for its remaining year. Changes in the fair value of the derivative component of this contract were recognized as Cost of revenues in the Consolidated Statements of Income. As of September 30, 2016, the estimated fair value of this contract was a liability 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, 2015, as updated by the Current Report on Form 8-K/A filed on May 20, 2016. The impact of the Partnership’s derivative instruments on its Consolidated Balance Sheets is summarized below:



(In millions)	September 30, 2016					December 31, 2015
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	$	—	$	(9	)	$	9	$	(5	)
Other noncurrent assets / deferred credits and other liabilities	—		(38		)	—		(27		)
Total	$	—	$	(47	)	$	9	$	(32	)


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

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



	September 30, 2016
	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	$	1	$	(1	)	$	—	$	(4	)	$	1	$	(3	)
Embedded derivatives in commodity contracts	—		—			—		(6		)	—		(6		)
Total current derivative instruments	1		(1		)	—		(10		)	1		(9		)

Non-current
Commodity contracts	—		—			—		—			—		—
Embedded derivatives in commodity contracts	—		—			—		(38		)	—		(38		)
Total non-current derivative instruments	—		—			—		(38		)	—		(38		)

Total derivative instruments	$	1	$	(1	)	$	—	$	(48	)	$	1	$	(47	)

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).

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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:



(In millions)	Three Months Ended September 30, 2016			Nine Months Ended September 30, 2016
Product sales
Realized gain	$	—		$	6
Unrealized gain (loss)	2			(12		)
Total revenue: derivative gain (loss) from product sales	2			(6		)
Purchased product costs
Unrealized loss	(3		)	(12		)
Cost of Revenues
Unrealized (loss) gain	(1		)	1
Total loss	$	(2	)	$	(17	)

15. Debt

The Partnership’s outstanding borrowings consisted of the following:



(In millions)	September 30, 2016			December 31, 2015
MPLX LP:
Bank revolving credit facility due 2020	$	—		$	877
Term loan facility due 2019	250			250
5.500% senior notes due 2023	710			710
4.500% senior notes due 2023	989			989
4.875% senior notes due 2024	1,149			1,149
4.000% senior notes due 2025	500			500
4.875% senior notes due 2025	1,189			1,189
Consolidated subsidiaries:
MarkWest - 4.500% - 5.500% senior notes, due 2023 - 2025	63			63
MPL - capital lease obligations due 2020	8			9
Total	4,858			5,736
Unamortized debt issuance costs	(7		)	(8		)
Unamortized discount⁽¹⁾	(439		)	(472		)
Amounts due within one year	(1		)	(1		)
Total long-term debt due after one year	$	4,411		$	5,255


(1)	Includes $431 million and $465 million discount as of September 30, 2016 and December 31, 2015, respectively, related to the difference between the fair value and the principal amount of the assumed MarkWest debt.

Credit Agreements

During the nine months ended September 30, 2016, the Partnership borrowed $434 million under the bank revolving credit facility, at an average interest rate of 1.899 percent, per annum, and repaid $1.3 billion under the bank revolving credit facility. At September 30, 2016, the Partnership had no outstanding borrowings and $3 million letters of credit outstanding under this facility, resulting in total availability of $2 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 nine months ended September 30, 2016 were at an average interest rate of 1.936 percent.

16. Goodwill

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

During the first quarter of 2016, the Partnership determined that an interim impairment analysis of the goodwill recorded in connection with the MarkWest Merger was necessary based on consideration of a number of first quarter events and circumstances, including i) continued deterioration of near term commodity prices as well as longer term pricing trends, ii) recent guidance on reductions to forecasted capital spending, the slowing of drilling activity and the resulting reduced production growth forecasts released or communicated by the Partnership’s producer customers and iii) increases in cost of capital. The combination of these factors was considered to be a triggering event requiring an interim impairment test. Based on the first step of the interim goodwill impairment analysis, the fair value for the three reporting units to which goodwill was assigned in connection with the MarkWest Merger was less than the respective carrying value. In step two of the impairment analysis, the implied fair values of the goodwill were compared to the carrying values within those reporting units. Based on this assessment, it was determined that goodwill was impaired in two of the three reporting units. Accordingly, the Partnership recorded an impairment charge of approximately $129 million in the first quarter of 2016. In the second quarter of 2016, the Partnership completed its purchase price allocation, which resulted in an additional $1 million of impairment expense that would have been recorded in the first quarter of 2016 had the purchase price allocation been completed as of that date. This adjustment to the impairment expense was the result of completing an evaluation of the deferred tax liabilities associated with the MarkWest Merger and their impact on the resulting goodwill that was recognized.

The fair value of the reporting units for the interim goodwill impairment analysis was determined based on applying the discounted cash flow method, which is an income approach, and the guideline public company method, which is a market approach. The discounted cash flow fair value estimate is based on known or knowable information at the interim measurement date. The significant assumptions that were used to develop the estimates of the fair values under the discounted cash flow method included management’s best estimates of the expected future results and discount rates, which range from 10.5 percent to 11.5 percent. The fair value of the intangibles was determined based on applying the multi-period excess earnings method, which is an income approach. Key assumptions included attrition rates by reporting unit ranging from 5.0 percent to 10.0 percent and discount rates by reporting unit ranging from 11.5 percent to 12.8 percent. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the interim goodwill impairment test will prove to be an accurate prediction of the future. The fair value measurements for the individual reporting units’ overall fair values, and the fair values of the goodwill assigned thereto, represent Level 3 measurements.

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



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

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


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

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17. Supplemental Cash Flow Information



	Nine Months Ended September 30,
(In millions)	2016			2015
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	158		$	12
Non-cash investing and financing activities:
Net transfers of property, plant and equipment from materials and supplies inventories	$	(5	)	$	—

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



	Nine Months Ended September 30,
(In millions)	2016			2015
(Decrease) increase in capital accruals	$	(5	)	$	18

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

18. Equity-Based Compensation

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



	Number of Units		Weighted Average Fair Value
Outstanding at December 31, 2015	1,031,219		$	35.49
Granted	451,231		29.36
Settled	(46,048	)	50.88
Forfeited	(35,348	)	31.47
Outstanding at September 30, 2016	1,401,054		33.11

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 and had a weighted-average grant date fair value per unit of $0.63 for 2016, as calculated using a Monte Carlo valuation model.

The following is a summary of the equity-classified performance unit award activity for the nine months ended September 30, 2016:



	Number of Units
Outstanding at December 31, 2015	1,521,392
Granted	789,375
Settled	(458,011	)
Forfeited	(53,507	)
Outstanding at September 30, 2016	1,799,249

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19. Commitments and Contingencies

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

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

At September 30, 2016 and December 31, 2015, accrued liabilities for remediation totaled $7 million and $1 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 September 30, 2016, there was less than $1 million in receivables from MPC for indemnification of environmental costs related to incidents occurring prior to the Initial Offering. There were $1 million in receivables from MPC for indemnification at December 31, 2015.

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, with the assistance of EPA’s Criminal Investigation Division proceeded with an investigation of MarkWest’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’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'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 alleged omissions associated with permits or related regulatory obligations for its launcher/receiver and compressor station facilities in the region. It is possible that in connection with any potential or asserted enforcement action associated with this matter, MarkWest Liberty Midstream will incur material assessments, penalties or fines, incur material defense costs and expenses, be required to modify operations or construction activities which could increase operating costs and capital expenditures, or be subject to other obligations or restrictions that could restrict or prohibit our activities, any or all of which could adversely affect our results of operations, financial position or cash flows. The amount of any potential assessments, penalties, fines, restrictions, requirements, modifications, costs or expenses that may be incurred in connection with any potential enforcement action cannot be reasonably estimated or determined at this time.

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 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

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range of loss) for this litigation. Under the omnibus agreement, MPC will indemnify the Partnership for the full cost of any losses should MPL be deemed responsible for any damages in this lawsuit.

The Partnership is also a party to a number of other lawsuits and other proceedings arising in the ordinary course of business. While the ultimate outcome and impact to the Partnership cannot be predicted with certainty, the Partnership believes the resolution of these other lawsuits and proceedings will not have a material adverse effect on its consolidated financial position, results of operations or cash flows.

Guarantees – Over the years, the Partnership has sold various assets in the normal course of its business. Certain of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require the Partnership to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling assets. The Partnership is typically not able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the underlying triggering event has little or no past experience upon which a reasonable prediction of the outcome can be based.

Contractual Commitments and Contingencies – At September 30, 2016, the Partnership’s contractual commitments to acquire property, plant and equipment totaled $202 million. In addition, from time to time and in the ordinary course of business, the Partnership and its affiliates provide guarantees of the Partnership’s subsidiaries payment and performance obligations in the G&P segment. These commitments at September 30, 2016 were primarily related to plant expansion projects for the Marcellus and Southwest operations and the Cornerstone Pipeline project. Certain natural gas processing and gathering arrangements require the Partnership to construct new natural gas processing plants, natural gas gathering pipelines and NGL pipelines and contain certain fees and charges if specified construction milestones are not achieved for reasons other than force majeure. In certain cases, certain producers may have the right to cancel the processing arrangements if there are significant delays that are not due to force majeure. As of September 30, 2016, 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.

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

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

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

PARTNERSHIP OVERVIEW

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

SIGNIFICANT FINANCIAL AND OTHER HIGHLIGHTS

Significant financial and other highlights for the three months ended September 30, 2016 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 $43 million for the three months ended September 30, 2016 compared to the same period of 2015 due to the inclusion of HSM results after our acquisition as of March 31, 2016 as well as a reduction in contract services and materials and supplies.


•	G&P segment operating income attributable to MPLX LP increased approximately $293 million for the three months ended September 30, 2016 compared to the same period of 2015 due to the MarkWest Merger.


•	During the third quarter 2016, we issued an aggregate of 5,700,000 commons units under our ATM Program, generating net proceeds of approximately $184 million. As a result of common units issued under the ATM Program, MPLX GP contributed $5 million in exchange for 116,326 general partner units to maintain its two percent general partner interest.

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 distribution.

We define Adjusted EBITDA as net income adjusted for (i) depreciation and amortization; (ii) benefit for income taxes; (iii)amortization of deferred financing costs; (iv) non-cash equity-based compensation; (v) impairment expense; (vi) net interest and other financial costs; (vii) income/loss from equity investments; (viii) distributions from unconsolidated subsidiaries; (ix) unrealized gain/loss on commodity hedges; and (x) acquisition costs. We also use DCF, which we define as Adjusted EBITDA plus (i) the current period cash received/deferred revenue for committed volume deficiencies less (ii) net interest and other financial costs; (iii) gain on disposal of assets; (iv) equity investment maintenance capital expenditures; (v) current portion of income taxes; (vi) maintenance capital expenditures paid; (vii) volume deficiency credits recognized; and (viii) other non-cash items.

We believe that the presentation of Adjusted EBITDA and DCF provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and DCF are net income and net cash provided by operating activities. Adjusted EBITDA and DCF should not be considered as alternatives

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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 gain (loss). These charges have been excluded for the purpose of enhancing the understanding by both management and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting. Net operating margin does not have any standardized definition and, therefore, is unlikely to be comparable to similar measures presented by other reporting companies. Net operating margin results should not be evaluated in isolation of, or as a substitute for, our financial results prepared in accordance with GAAP. Our use of net operating margin and the underlying methodology in excluding certain charges is not necessarily an indication of the results of operations expected in the future, or that we will not, in fact, incur such charges in future periods.

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

COMPARABILITY OF OUR FINANCIAL RESULTS

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

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RESULTS OF OPERATIONS

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



	Three Months Ended September 30,							Nine Months Ended September 30,
(In millions)	2016		2015		Variance			2016			2015		Variance
Total revenues and other income	$	703	$	214	$	489		$	1,876		$	628	$	1,248
Costs and expenses:
Cost of revenues (excludes items below)	90		59		31			263			147		116
Purchased product costs	117		—		117			310			—		310
Rental cost of sales	11		—		11			39			—		39
Purchases - related parties	84		43		41			238			123		115
Depreciation and amortization	138		19		119			407			58		349
Impairment expense	—		—		—			130			—		130
General and administrative expenses	46		25		21			147			68		79
Other taxes	10		—		10			32			8		24
Total costs and expenses	496		146		350			1,566			404		1,162
Income from operations	207		68		139			310			224		86
Related party interest and other financial costs	—		—		—			1			—		1
Interest expense, net of amounts capitalized	51		4		47			158			15		143
Other financial costs	13		1		12			37			2		35
Income before income taxes	143		63		80			114			207		(93		)
Benefit for income taxes	—		—		—			(12		)	—		(12		)
Net income	143		63		80			126			207		(81		)
Less: Net income attributable to noncontrolling interests	2		—		2			3			1		2
Less: Net income attributable to Predecessor	—		22		(22		)	23			68		(45		)
Net income attributable to MPLX LP	$	141	$	41	$	100		$	100		$	138	$	(38	)

Adjusted EBITDA attributable to MPLX LP ⁽¹⁾	$	375	$	66	$	309		$	1,028		$	200	$	828
DCF⁽¹⁾	$	301	$	54	$	247		$	822		$	172	$	650
DCF attributable to GP and LP unitholders⁽¹⁾	$	285	$	54	$	231		$	797		$	172	$	625


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

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	Three Months Ended September 30,								Nine Months Ended September 30,
(In millions)	2016			2015		Variance			2016			2015			Variance
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net income:
Net income	$	143		$	63	$	80		$	126		$	207		$	(81	)
Plus: Depreciation and amortization	138			19		119			407			58			349
Benefit for income taxes	—			—		—			(12		)	—			(12		)
Amortization of deferred financing costs	11			—		11			34			—			34
Non-cash equity-based compensation	3			2		1			9			3			6
Impairment expense	—			—		—			130			—			130
Net interest and other financial costs	53			5		48			162			17			145
(Income) loss from equity investments	(6		)	—		(6		)	72			—			72
Distributions from unconsolidated subsidiaries	33			—		33			111			—			111
Unrealized loss on commodity hedges	2			—		2			23			—			23
Acquisition costs	—			4		(4		)	(1		)	4			(5		)
Adjusted EBITDA	377			93		284			1,061			289			772
Less: Adjusted EBITDA attributable to noncontrolling interests	2			—		2			3			1			2
Adjusted EBITDA attributable to Predecessor	—			27		(27		)	30			88			(58		)
Adjusted EBITDA attributable to MPLX LP	375			66		309			1,028			200			828
Plus: Current period cash received/deferred revenue for committed volume deficiencies	10			11		(1		)	31			33			(2		)
Less: Net interest and other financial costs	53			5		48			162			17			145
Gain on disposal of assets	1			—		1			1			—			1
Equity investment maintenance capital expenditures	—			—		—			1			—			1
Current portion of income taxes	4			—		4			4			—			4
Maintenance capital expenditures paid	20			8		12			48			16			32
Volume deficiency credits recognized	9			10		(1		)	25			29			(4		)
Other	(3		)	—		(3		)	(3		)	—			(3		)
Adjustments attributable to Predecessor	—			—		—			(1		)	(1		)	—
DCF	301			54		247			822			172			650
Less: Preferred unit distributions	16			—		16			25			—			25
DCF attributable to GP and LP unitholders	$	285		$	54	$	231		$	797		$	172		$	625

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	Nine Months Ended September 30,
(In millions)	2016			2015			Variance
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net cash provided by operating activities:
Net cash provided by operating activities	$	932		$	258		$	674
Less: Changes in working capital items	54			(8		)	62
All other, net	18			2			16
Plus: Non-cash equity-based compensation	9			3			6
Net gain on disposal of assets	1			—			1
Net interest and other financial costs	162			17			145
Current income taxes	4			—			4
Asset retirement expenditures	3			1			2
Unrealized loss on commodity hedges	23			—			23
Acquisition costs	(1		)	4			(5		)
Adjusted EBITDA	1,061			289			772
Less: Adjusted EBITDA attributable to noncontrolling interests	3			1			2
Adjusted EBITDA attributable to Predecessor	30			88			(58		)
Adjusted EBITDA attributable to MPLX LP	1,028			200			828
Plus: Current period cash received/deferred revenue for committed volume deficiencies	31			33			(2		)
Less: Net interest and other financial costs	162			17			145
Gain on disposal of assets	1			—			1
Equity investment maintenance capital expenditures	1			—			1
Current portion of income taxes	4			—			4
Maintenance capital expenditures paid	48			16			32
Volume deficiency credits recognized	25			29			(4		)
Other	(3		)	—			(3		)
Adjustments attributable to Predecessor	(1		)	(1		)	—
DCF	822			172			650
Less: Preferred unit distributions	25			—			25
DCF attributable to GP and LP unitholders	$	797		$	172		$	625

Three months ended September 30, 2016 compared to three months ended September 30, 2015

Total revenues and other income increased $489 million in the third quarter of 2016 compared to the same period of 2015. This variance was primarily related to a $487 million increase due to the MarkWest Merger, an increase due to higher average tariffs received on the volumes of crude oil and products shipped and an increase in storage fees partially offset by a reduction in fees previously paid by HSM on behalf of MPC that are now being paid directly by MPC.

Cost of revenues increased $31 million in the third quarter of 2016 compared to the same period of 2015. This variance was primarily due to the MarkWest Merger, offset by a reduction in contract services and fees previously paid by HSM on behalf of MPC that are now paid directly by MPC.

Purchased product costs increased $117 million in the third quarter of 2016 compared to the same period of 2015. This variance was primarily due to the MarkWest Merger.

Rental cost of sales increased $11 million in the third quarter of 2016 compared to the same period of 2015. This variance was primarily due to the MarkWest Merger.

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Purchases-related parties increased $41 million in the third quarter of 2016 compared to the same period of 2015. The increase was primarily due to higher compensation expenses provided under the omnibus and employee services agreements with MPC due to the MarkWest Merger, partially offset by increased capitalization of employee costs associated with capital projects.

Depreciation and amortization expense increased $119 million in the third quarter of 2016 compared to the same period of 2015. This variance was primarily due to the MarkWest Merger.

General and administrative expenses increased $21 million in the third quarter of 2016 compared to the same period of 2015. The increases were primarily due to the MarkWest Merger offset by a reduction in expenses due to changes in allocations provided for in the omnibus and employee services agreements with MPC.

Interest expense and other financial costs increased $59 million in the third quarter of 2016 compared to the same period of 2015. The increases are primarily due to the senior notes assumed as part of the MarkWest Merger.

Nine months ended September 30, 2016 compared to nine months ended September 30, 2015

Total revenues and other income increased $1.2 billion in the first nine months of 2016 compared to the same period of 2015. This variance was primarily related to a $1.2 billion increase due to the MarkWest Merger and an increase due to higher average tariffs received on the volumes of crude oil and products shipped. The nine months ended September 30, 2016 also includes an impairment expense of $89 million related to Ohio Condensate. See Note 4 of the Notes to Consolidated Financial Statements for more information.

Cost of revenues increased $116 million in the first nine months of 2016 compared to the same period of 2015. This variance was primarily due to the MarkWest Merger, offset by a reduction in contract services and fees previously paid by HSM on behalf of MPC that are now paid directly by MPC.

Purchased product costs increased $310 million in the first nine months of 2016 compared to the same period of 2015. This variance was primarily due to the MarkWest Merger.

Rental cost of sales increased $39 million in the first nine months of 2016 compared to the same period of 2015. This variance was primarily due to the MarkWest Merger.

Purchases-related parties increased $115 million in the first nine months of 2016 compared to the same period of 2015. The increases were primarily due to higher compensation expenses provided under the omnibus and employee services agreements with MPC due to the MarkWest Merger, partially offset by increased capitalization of employee costs associated with capital projects.

Depreciation and amortization expense increased $349 million in the first nine months of 2016 compared to the same period of 2015. This variance was primarily due to the MarkWest Merger.

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

General and administrative expenses increased $79 million in the first nine months of 2016 compared to the same period of 2015. The increases were primarily due to the MarkWest Merger offset by a reduction in expenses due to changes in allocations provided for in the omnibus and employee services agreements with MPC.

Interest expense and other financial costs increased $179 million in the first nine months of 2016 compared to the same period of 2015. The increases are primarily due to the senior notes assumed as part of the MarkWest Merger.

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

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items when evaluating segment performance. Segment results are also adjusted to exclude the portion of income from operations attributable to the noncontrolling interests related to partially owned entities that are either consolidated or accounted for as equity method investments.

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

L&S Segment



	Three Months Ended September 30,							Nine Months Ended September 30,
(In millions)	2016		2015		Variance			2016		2015		Variance
Revenues and other income:
Segment revenue	$	200	$	195	$	5		$	585	$	571	$	14
Segment other income	16		19		(3		)	53		57		(4		)
Total segment revenues and other income	216		214		2			638		628		10
Costs and expenses:
Segment cost of revenues	92		102		(10		)	269		278		(9		)
Segment operating income before portion attributable to noncontrolling interest and Predecessor	124		112		12			369		350		19
Segment portion attributable to noncontrolling interest and Predecessor	—		31		(31		)	34		99		(65		)
Segment operating income attributable to MPLX LP	$	124	$	81	$	43		$	335	$	251	$	84

Three months ended September 30, 2016 compared to three months ended September 30, 2015

In the third quarter of 2016 compared to the same period of 2015, segment revenue increased due to a $4 million increase in higher average tariffs received on the volumes of crude oil and products shipped in addition to a $1 million increase related to a 40 mbpd increase in product and crude oil volumes shipped.

In the third quarter of 2016 compared to the same period of 2015, segment other income decreased due to a reduction in fees paid to HSM by MPC partially offset by increased storage fees.

In the third quarter of 2016 compared to the same period of 2015, segment cost of revenues decreased primarily due to $5 million in fees previously paid by HSM on behalf of MPC that are now being paid directly by MPC and a $4 million decrease in expenses related to the timing of projects.

In the third quarter of 2016 compared to the same period of 2015, the segment portion attributable to noncontrolling interest and Predecessor decreased due to the acquisition of HSM as of March 31, 2016.

Nine months ended September 30, 2016 compared to nine months ended September 30, 2015

In the first nine months of 2016 compared to the same period of 2015, segment revenue increased due to a $16 million increase in higher average tariffs received on the volumes of crude oil and products shipped and a $3 million increase in storage service income, offset by a $1 million decrease related to a 4 mbpd decline in product and crude oil volumes shipped and a $7 million decrease in revenue related to volume deficiency credits recognized.

In the first nine months of 2016 compared to the same period of 2015, segment other income decreased due to a reduction in fees paid to HSM by MPC partially offset by increased storage fees.

In the first nine months of 2016 compared to the same period of 2015, segment cost of revenues decreased primarily due to a decrease in fees previously paid by HSM on behalf of MPC that are now being paid directly by MPC and a decrease in expenses related to the timing of projects.

In the first nine months of 2016 compared to the same period of 2015, the segment portion attributable to noncontrolling interest and Predecessor decreased due to the acquisition of HSM as of March 31, 2016.

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During both the third quarter and the first nine months of 2016, MPC did not ship its minimum committed volumes on certain of our pipeline systems. As a result, for the first nine months, MPC was obligated to make a $32 million deficiency payment, of which $10 million was paid in the third quarter of 2016. We record deficiency payments as Deferred revenue-related parties on our Consolidated Balance Sheets. In the third quarter and the first nine months of 2016, we recognized revenue of $11 million and $26 million, respectively, related to volume deficiency credits. At September 30, 2016, the cumulative balance of Deferred revenue-related parties on our Consolidated Balance Sheets related to volume deficiencies was $42 million. The following table presents the future expiration dates of the associated deferred revenue credits as of September 30, 2016:



(In millions)
December 31, 2016	$	10
March 31, 2017	7
June 30, 2017	10
September 30, 2017	7
December 31, 2017	1
March 31, 2018	2
June 30, 2018	2
September 30, 2018	3
Total	$	42

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

G&P Segment

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



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2016		2015		Variance		2016		2015		Variance
Revenues and other income:
Segment revenue	$	567	$	—	$	567	$	1,595	$	—	$	1,595
Segment other income	1		—		1		1		—		1
Total segment revenues and other income	568		—		568		1,596		—		1,596
Costs and expenses:
Segment cost of revenues	239		—		239		662		—		662
Segment operating income before portion attributable to noncontrolling interest	329		—		329		934		—		934
Segment portion attributable to noncontrolling interest	36		—		36		113		—		113
Segment operating income attributable to MPLX LP	$	293	$	—	$	293	$	821	$	—	$	821

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

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



	Three Months Ended September 30,									Nine Months Ended September 30,
(In millions)	2016			2015			Variance			2016			2015			Variance
Reconciliation to Income from operations:
L&S segment operating income attributable to MPLX LP	$	124		$	81		$	43		$	335		$	251		$	84
G&P segment operating income attributable to MPLX LP	293			—			293			821			—			821
Segment operating income attributable to MPLX LP	417			81			336			1,156			251			905
Segment portion attributable to unconsolidated affiliates	(77		)	—			(77		)	(243		)	—			(243		)
Segment portion attributable to noncontrolling interest and Predecessor	36			31			5			147			99			48
Income (loss) from equity method investments	6			—			6			(72		)	—			(72		)
Other income - related parties	11			—			11			29			—			29
Unrealized derivative losses	(2		)	—			(2		)	(23		)	—			(23		)
Depreciation and amortization	(138		)	(19		)	(119		)	(407		)	(58		)	(349		)
Impairment expense	—			—			—			(130		)	—			(130		)
General and administrative expenses	(46		)	(25		)	(21		)	(147		)	(68		)	(79		)
Income from operations	$	207		$	68		$	139		$	310		$	224		$	86



	Three Months Ended September 30,								Nine Months Ended September 30,
(In millions)	2016			2015		Variance			2016			2015		Variance
Reconciliation to Total revenues and other income:
Total segment revenues and other income	$	784		$	214	$	570		$	2,234		$	628	$	1,606
Revenue adjustment from unconsolidated affiliates	(100		)	—		(100		)	(303		)	—		(303		)
Income (loss) from equity method investments	6			—		6			(72		)	—		(72		)
Other income - related parties	11			—		11			29			—		29
Unrealized derivative loss	2			—		2			(12		)	—		(12		)
Total revenues and other income	$	703		$	214	$	489		$	1,876		$	628	$	1,248



	Three Months Ended September 30,									Nine Months Ended September 30,
(In millions)	2016			2015			Variance			2016			2015			Variance
Reconciliation to Net income attributable to noncontrolling interests and Predecessor
Segment portion attributable to noncontrolling interest and Predecessor	$	36		$	31		$	5		$	147		$	99		$	48
Portion of noncontrolling interests and Predecessor related to items below segment income from operations	(16		)	(9		)	(7		)	(101		)	(30		)	(71		)
Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates	(18		)	—			(18		)	(20		)	—			(20		)
Net income attributable to noncontrolling interests and Predecessor	$	2		$	22		$	(20	)	$	26		$	69		$	(43	)

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

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

The change in fair value of our Product sales derivative instruments resulted in an unrealized gain of $2 million for the three months ended September 30, 2016 and an unrealized loss of $12 million for the nine months ended September 30, 2016. Unrealized loss from the change in fair value of our Purchased product costs derivative instruments for the three and nine months ended September 30, 2016 was $3 million and $12 million, respectively. The change in fair value of our Cost of revenues derivative instruments resulted in an unrealized loss of $1 million for the three months ended September 30, 2016 and an unrealized gain of $1 million for the nine months ended September 30, 2016. Unrealized derivative activity is not allocated to segments.

OUR G&P CONTRACTS WITH THIRD PARTIES

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

The following table does not give effect to our active commodity risk management program. We manage our business by taking into account the partial offset of short natural gas positions primarily in the Southwest region of our G&P segment. The calculated percentages for net operating margin for percent-of-proceeds, percent-of-index and keep-whole contracts reflect the partial offset of our natural gas positions. The calculated percentages are less than one percent for percent-of-index due to the offset of our natural gas positions and, therefore, not meaningful to the table below.

For the three months ended September 30, 2016, 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⁾	89	%	11	%	—	%
Total	93	%	7	%	—	%

For the nine months ended September 30, 2016, 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⁾	91	%	8	%	1	%
Total	94	%	5	%	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).

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



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2016			2015			2016			2015
Reconciliation of net operating margin to income from operations:
Segment revenue	$	767		$	195		$	2,180		$	571
Less: Segment purchased product costs	113			—			299			—
Realized derivative gain related to revenues and purchased product costs	—			—			6			—
Net operating margin	654			195			1,875			571
Revenue adjustment from unconsolidated affiliates⁽¹⁾	(100		)	—			(303		)	—
Realized derivative gain related to revenues and purchased product costs	—			—			6			—
Unrealized derivative losses	(2		)	—			(23		)	—
Income (loss) from equity method investments	6			—			(72		)	—
Other income	2			1			5			4
Other income - related parties	26			18			78			53
Cost of revenues (excludes items below)	(90		)	(59		)	(263		)	(147		)
Rental cost of sales	(11		)	—			(39		)	—
Purchases - related parties	(84		)	(43		)	(238		)	(123		)
Depreciation and amortization	(138		)	(19		)	(407		)	(58		)
Impairment expense	—			—			(130		)	—
General and administrative expenses	(46		)	(25		)	(147		)	(68		)
Other taxes	(10		)	—			(32		)	(8		)
Income from operations	$	207		$	68		$	310		$	224


(1)	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

Many effects of seasonality on the L&S segment’s revenues will be mitigated through the use of our fee-based transportation and storage services agreements with MPC that include minimum volume commitments. Historically, the L&S segment has spent approximately two-thirds of both our budgeted maintenance capital expenditures and budgeted pipeline integrity, repair and maintenance expenses during the third and fourth quarter of each calendar year due to our budgeting cycle, operating conditions, weather and safety concerns.

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

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OPERATING DATA



	Three Months Ended September 30,				Nine Months Ended September 30,
	2016		2015		2016		2015
L&S
Pipeline throughput (mbpd)
Crude oil pipelines	1,180		1,135		1,090		1,091
Product pipelines	907		896		909		907
Total pipelines	2,087		2,031		1,999		1,998

Average tariff rates ($ per barrel)⁽¹⁾
Crude oil pipelines	$	0.64	$	0.66	$	0.67	$	0.66
Product pipelines	0.70		0.65		0.68		0.64
Total pipelines	0.67		0.66		0.68		0.65

Marine Assets (number in operation)⁽²⁾
Barges	205		202		205		202
Towboats	18		18		18		18

G&P⁽³⁾
Gathering Throughput (mmcf/d)
Marcellus operations	946				922
Utica operations⁽⁴⁾	916				936
Southwest operations⁽⁵⁾	1,444				1,455
Total gathering throughput	3,306				3,313

Natural Gas Processed (mmcf/d)
Marcellus operations	3,273				3,166
Utica operations⁽⁴⁾	1,050				1,068
Southwest operations	1,339				1,209
Southern Appalachian operations	244				248
Total natural gas processed	5,906				5,691

C2 + NGLs Fractionated (mbpd)
Marcellus operations⁽⁶⁾	274				254
Utica operations⁽⁴⁾⁽⁶⁾	41				43
Southwest operations	19				17
Southern Appalachian operations⁽⁷⁾	14				16
Total C2 + NGLs fractionated⁽⁸⁾	348				330

Pricing Information
Natural Gas NYMEX HH ($ per MMBtu)	$	2.80			$	2.34
C2 + NGL Pricing ($ per gallon)⁽⁹⁾	$	0.46			$	0.44


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


(2)	Represents total at end of period.


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


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

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(5)	Includes approximately 307 mmcf/d and 299 mmcf/d related to unconsolidated equity method investments, Wirth and MarkWest Pioneer, for the three and nine months ended September 30, 2016, respectively.


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


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


(8)	Purity ethane makes up approximately 137 mbpd and 125 mbpd of total fractionated products for the three and nine months ended September 30, 2016, respectively.


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

SUPPLEMENTAL MD&A - G&P PRO FORMA

Three and Nine Months Ended September 30, 2016 Compared to Three and Nine Months Ended September 30, 2015

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



	Three Months Ended September 30,						Nine Months Ended September 30,
(In millions)	2016		2015		Variance		2016		2015		Variance
Revenues and other income:
Segment revenue and other income	$	568	$	509	$	59	$	1,596	$	1,498	$	98
Total segment revenues and other income	568		509		59		1,596		1,498		98
Costs and expenses:
Segment cost of revenues	239		209		30		662		662		—
Segment operating income before portion attributable to noncontrolling interest	329		300		29		934		836		98
Segment portion attributable to noncontrolling interest	36		34		2		113		82		31
Segment operating income attributable to MPLX LP	$	293	$	266	$	27	$	821	$	754	$	67

Three months ended September 30, 2016 compared to three months ended September 30, 2015

In the third quarter of 2016 compared to the same period of 2015, segment revenue increased slightly due to an increase in volumes as well as increased natural gas and NGL prices. Total gathering throughput, total natural gas processed and total C2+ NGLs fractionated volumes increased by 8 percent, 15 percent and 27 percent, respectively. These volume increases mainly related to our expansions in Marcellus and Utica operations. Additionally, there was a three percent increase in natural gas prices and a 10 percent increase in NGL prices over the same period in 2015.

In the third quarter of 2016 compared to the same period of 2015, segment cost of revenues increased mainly due to increases in natural gas purchased prices and NGL prices. Segment cost of revenues as a percentage of segment revenues and other income increased one percent for the third quarter of 2016 compared to the same period of 2015. This was primarily due to the increase in percent-of-proceeds revenue as a percentage of total revenue by one percent as a result of higher pricing.

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

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Nine months ended September 30, 2016 compared to nine months ended September 30, 2015

In the first nine months of 2016 compared to the same period of 2015, segment revenue increased slightly due to an increase in volumes. Total gathering throughput, total natural gas processed and total C2+ NGLs fractionated volumes increased by 15 percent, 13 percent and 27 percent, respectively. These volume increases mainly related to our expansions in Marcellus and Utica operations. This increase was offset by a 15 percent decrease in natural gas prices and a 6 percent decrease in NGL prices over the same period in 2015.

In the first nine months of 2016 compared to the same period of 2015, segment cost of revenues remained stable. Product purchases decreased 14 percent primarily due to lower prices offset by increases to operating expenses related to expansions of plant and gathering system assets. Segment cost of revenues as a percentage of segment revenues and other income decreased three percent for the first nine months of 2016 compared to the same period of 2015.

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

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

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



	Three Months Ended September 30,									Nine Months Ended September 30,
(In millions)	2016			2015			Variance			2016			2015			Variance
Pro forma reconciliation to total revenues and other income:
Total G&P segment revenues and other income	$	568		$	509		$	59		$	1,596		$	1,498		$	98
Revenue adjustment from unconsolidated affiliates	(100		)	(41		)	(59		)	(303		)	(100		)	(203		)
Income (loss) from equity method investments	6			6			—			(72		)	4			(76		)
G&P Other income (loss) - related parties	11			(2		)	13			29			(3		)	32
Unrealized derivative losses related to revenue	2			3			(1		)	(12		)	(6		)	(6		)
Total pro forma G&P revenues and other income	487			475			12			1,238			1,393			(155		)
Total pro forma L&S revenues and other income	216			214			2			638			628			10
Total pro forma revenues and other income	$	703		$	689		$	14		$	1,876		$	2,021		$	(145	)

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	Three Months Ended September 30,									Nine Months Ended September 30,
(In millions)	2016			2015			Variance			2016			2015			Variance
Pro Forma reconciliation to pro forma net income attributable to MPLX LP:
Segment operating income attributable to G&P	$	293		$	266		$	27		$	821		$	754		$	67
Segment operating income attributable to L&S	124			81			43			335			251			84
Segment portion attributable to unconsolidated affiliates	(77		)	(7		)	(70		)	(243		)	(13		)	(230		)
Segment portion attributable to noncontrolling interest and Predecessor	36			45			(9		)	147			135			12
Income (loss) from equity method investments	6			6			—			(72		)	4			(76		)
Other income (loss) - related parties	11			(2		)	13			29			(2		)	31
Unrealized derivative losses	(2		)	7			(9		)	(23		)	(9		)	(14		)
Depreciation and amortization	(138		)	(148		)	10			(407		)	(427		)	20
Impairment expense	—			—			—			(130		)	(26		)	(104		)
General and administrative expenses	(46		)	(55		)	9			(147		)	(165		)	18
Pro forma income from operations	207			193			14			310			502			(192		)
Related party interest and other financial costs	—			—			—			1			—			1
Debt retirement expense	—			—			—			—			118			(118		)
Net interest and other financial costs	64			66			(2		)	195			192			3
Pro forma income before income taxes	143			127			16			114			192			(78		)
Provision (benefit) for income taxes	—			3			(3		)	(12		)	(11		)	(1		)
Pro forma net income	143			124			19			126			203			(77		)
Less: Net income attributable to noncontrolling interests	2			17			(15		)	26			43			(17		)
Pro forma net income attributable to MPLX LP	$	141		$	107		$	34		$	100		$	160		$	(60	)

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	Three Months Ended September 30,						Nine Months Ended September 30,
	2016		2015		% Change		2016		2015		% Change
Pro Forma Operating Statistics
Gathering Throughput (mmcf/d)
Marcellus operations	946		875		8	%	922		849		9	%
Utica operations⁽¹⁾	916		763		20	%	936		617		52	%
Southwest operations⁽²⁾	1,444		1,414		2	%	1,455		1,419		3	%
Total gathering throughput	3,306		3,052		8	%	3,313		2,885		15	%

Natural Gas Processed (mmcf/d)
Marcellus operations	3,273		2,865		14	%	3,166		2,868		10	%
Utica operations⁽¹⁾	1,050		929		13	%	1,068		816		31	%
Southwest operations	1,339		1,089		23	%	1,209		1,074		13	%
Southern Appalachian operations	244		275		(11	)%	248		273		(9	)%
Total natural gas processed	5,906		5,158		15	%	5,691		5,031		13	%

C2 + NGLs Fractionated (mbpd)
Marcellus operations⁽³⁾	274		198		38	%	254		191		33	%
Utica operations⁽¹⁾⁽³⁾	41		42		(2	)%	43		37		16	%
Southwest operations	19		19		—	%	17		17		—	%
Southern Appalachian operations⁽⁴⁾	14		16		(13	)%	16		15		7	%
Total C2 + NGLs fractionated⁽⁵⁾	348		275		27	%	330		260		27	%

Pricing Information
Natural Gas NYMEX HH ($ per MMBtu)	$	2.80	$	2.73	3	%	$	2.34	$	2.76	(15	)%
C2 + NGL Pricing ($ per gallon)⁽⁶⁾	$	0.46	$	0.42	10	%	$	0.44	$	0.47	(6	)%


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

(2)

Includes approximately 307 mmcf/d and 247 mmcf/d related to unconsolidated equity method investments, Wirth and MarkWest Pioneer, for the three months ended September 30, 2016 and September 30, 2015, respectively. Includes approximately 299 mmcf/d and 233 mmcf/d related to unconsolidated equity method investments, Wirth and MarkWest Pioneer, for the nine months ended September 30, 2016 and September 30, 2015, respectively.


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


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


(5)	Purity ethane makes up approximately 137 mbpd and 82 mbpd of total fractionated products for the three months ended September 30, 2016 and September 30, 2015, respectively, and approximately 125 mbpd and 75 mbpd of total fractionated products for the nine months ended September 30, 2016 and September 30, 2015, respectively.


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

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LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Our cash and cash equivalents balance was $208 million at September 30, 2016 compared to $43 million at December 31, 2015. The change in cash and cash equivalents was due to the factors discussed below. Net cash provided by (used in) operating activities, investing activities and financing activities were as follows:



	Nine Months Ended September 30,
(In millions)	2016			2015
Net cash provided by (used in):
Operating activities	$	932		$	258
Investing activities	(849		)	(191		)
Financing activities	82			(4		)
Total	$	165		$	63

Net cash provided by operating activities increased $674 million in the first nine months of 2016 compared to the first nine months of 2015, the majority of which is related to the MarkWest Merger.

Net cash used in investing activities increased $658 million in the first nine months of 2016 compared to the first nine months of 2015, primarily due to a $745 million use of cash for additions to property, plant and equipment related to various capital projects, mainly due to the acquisition of MarkWest, and a $56 million use of cash for investments in unconsolidated affiliates, partially offset by a $141 million source of cash from investment loans between HSM and related parties.

Financing activities were a $82 million source of cash in the first nine months of 2016 compared to a $4 million use of cash in the first nine months of 2015. The source of cash in the first nine months of 2016 was primarily due to $510 million of net proceeds from sales of common units under the ATM Program, $984 million of net proceeds from the issuance of the Preferred Units and contributions of $225 million from MPC as part of the Class A Reorganization, partially offset by $878 million in net repayments on the bank revolving credit facility, $8 million of net repayments from the related party debt borrowings, distributions of $612 million and $104 million in distributions to MPC from Predecessor. The use of cash in the first nine months of 2015 was primarily due to $416 million in repayments on the bank revolving credit facility and distributions of $111 million, partially offset by $495 million of net proceeds from the issuance of the senior notes due 2025 and borrowings of $30 million under the bank revolving credit facility.

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Debt and Liquidity Overview

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



(In millions)	September 30, 2016			December 31, 2015
MPLX LP:
Bank revolving credit facility due 2020	$	—		$	877
Term loan facility due 2019	250			250
5.500% senior notes due 2023	710			710
4.500% senior notes due 2023	989			989
4.875% senior notes due 2024	1,149			1,149
4.000% senior notes due 2025	500			500
4.875% senior notes due 2025	1,189			1,189
Consolidated subsidiaries:
MarkWest - 4.500% - 5.500%, due 2023 - 2025	63			63
MPL - capital lease obligations due 2020	8			9
Total	4,858			5,736
Unamortized debt issuance costs	(7		)	(8		)
Unamortized discount⁽¹⁾	(439		)	(472		)
Amounts due within one year	(1		)	(1		)
Total long-term debt due after one year	$	4,411		$	5,255


(1)	Includes $431 million and $465 million discount as of September 30, 2016 and December 31, 2015, respectively, related to the difference between the fair value and the principal amount of the assumed MarkWest debt.

The decrease in debt as of September 30, 2016 compared to year-end 2015 was primarily related to the repayment of the bank revolving credit facility using proceeds from the issuance of the Preferred Units.

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 September 30, 2016, we were in compliance with this financial covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of 3.5 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 September 30, 2016, the credit ratings on our senior unsecured debt were at or above investment grade level as follows.



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

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Our liquidity totaled $2.7 billion at September 30, 2016 consisting of:



	September 30, 2016
(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						208
Total liquidity						$	2,705


(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, 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.

Equity and Preferred Unit Overview

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



(In units)	Common	Class B		General Partner		Total
Balance at December 31, 2015	296,687,176	7,981,756		6,800,475		311,469,407
Unit-based compensation awards	39,637	—		810		40,447
Issuance of units under the ATM Program	17,725,000	—		361,732		18,086,732
Contribution of HSM	22,534,002	—		459,878		22,993,880
Class B conversion	4,350,057	(3,990,878	)	7,330		366,509
Class A Reorganization	7,153,177	—		(436,758	)	6,716,419
Balance at September 30, 2016	348,489,049	3,990,878		7,193,467		359,673,394

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

On May 13, 2016, the Partnership completed the private placement of approximately 30.8 million 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 will be used for capital expenditures, repayment of debt and general partnership purposes. With the completion of its $1.3 billion of financing earlier this year, the Partnership has provided for its forecast funding needs through the remainder of 2016 and into 2017.

On July 1, 2016, 3,990,878 Class B units automatically converted into 1.09 MPLX LP common units and the right to receive $6.20 per unit in cash. They are also eligible to receive the second quarter distribution. MPC funded this cash payment, which reduced our liability payable to Class B unitholders by approximately $25 million on July 1, 2016. As a result of the Class B units conversion on July 1, 2016, MPLX GP contributed less than $1 million in exchange for 7,330 general partner units to maintain its two percent general partner interest.

On August 4, 2016, the Partnership entered into a second amended and restated distribution agreement providing for the continuous issuance of up to an aggregate of $1.2 billion of common units, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of any offerings. The Partnership expects the net proceeds from sales under the ATM Program will be used for general partnership purposes including repayment or refinancing of debt and funding for acquisitions, working capital requirements and capital expenditures. During the nine months ended September 30, 2016, the sale of common units under the ATM Program generated net proceeds of approximately $499 million.

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On September 1, 2016, the Partnership and various affiliates initiated a series of reorganization transactions in order to simplify the Partnership’s ownership structure and its financial and tax reporting requirements. In connection with these transactions, all issued and outstanding MPLX LP Class A units were either distributed to or purchased by MPC in exchange for $84 million in cash, 21,401,137 MPLX LP common units and 436,758 MPLX LP general partner units. MPC also contributed $141 million to facilitate the repayment of intercompany debt between MarkWest Hydrocarbon and MarkWest. As a result of these transactions, the MPLX LP Class A units were eliminated, are no longer outstanding and no longer participate in distributions of cash from the Partnership. See additional discussion in Notes 7 and 10 of the Notes to Consolidated Financial Statements.

We intend to pay at least the minimum quarterly distribution of $0.2625 per unit per quarter, which equates to $93 million per quarter, or $373 million per year, based on the number of common and general partner units outstanding at September 30, 2016. On October 25, 2016, we announced the board of directors of our general partner had declared a distribution of $0.5150 per unit that will be paid on November 14, 2016 to unitholders of record on November 4, 2016. This represents an increase of 0.0050 per unit, or one percent, above the second quarter 2016 distribution of $0.5100 per unit and an increase of 10 percent over the third quarter 2015 distribution. This increase in the distribution is consistent with our intent to maintain an attractive distribution growth profile over an extended period of time. Although our partnership agreement requires that we distribute all of our available cash each quarter, we do not otherwise have a legal obligation to distribute any particular amount per unit.

The allocation of total quarterly cash distributions to general and limited partners is as follows for the three and nine months ended September 30, 2016 and 2015. Our distributions are declared subsequent to quarter end; therefore, the following table represents total cash distributions applicable to the period in which the distributions were earned.



	Three Months Ended September 30,				Nine Months Ended September 30,
(In millions)	2016		2015		2016		2015
Distribution declared:
Limited partner units - public	$	135	$	11	$	393	$	31
Limited partner units - MPC	44		27		114		75
General partner units - MPC	5		1		13		3
Incentive distribution rights - MPC	49		8		135		17
Total GP & LP distribution declared	233		47		655		126
Redeemable preferred units	16		—		25		—
Total distribution declared	$	249	$	47	$	680	$	126

Cash distributions declared per limited partner common unit	$	0.5150	$	0.4700	$	1.5300	$	1.3200

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

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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:



	Nine months ended September 30,
(In millions)	2016			2015
Capital expenditures:
Maintenance	$	48		$	19
Expansion	825			130
Total capital expenditures	873			149
Less: (Decrease) increase in capital accruals	(4		)	19
Asset retirement expenditures	3			1
Additions to property, plant and equipment	874			129
Capital expenditures of unconsolidated subsidiaries⁽¹⁾	94			—
Total gross capital expenditures	968			129
Less: Joint venture partner contributions⁽²⁾	45			—
Total gross capital expenditures, net	$	923		$	129


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


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

Our gross organic growth capital plan for 2016 was narrowed to a range of $1.1 billion to $1.2 billion. The expected 2016 capital spending and investments excludes our anticipated investment in the Bakken Pipeline system. The preliminary 2017 forecast for gross organic growth capital expenditures is $1.2 billion to $1.6 billion and maintenance capital is expected to be approximately $100 million. We continuously evaluate our capital plan and make changes as conditions warrant.

Contractual Cash Obligations

As of September 30, 2016, our contractual cash obligations included long-term debt, capital and operating lease obligations, purchase obligations for services and to acquire property, plant and equipment, and other liabilities. During the nine months ended September 30, 2016, our bank revolving credit facility committed payments decreased $955 million due to the repayment of the bank revolving credit facility and contracts to acquire property, plant and equipment increased $58 million largely due to the spending associated with various projects. There were no other material changes to these obligations outside the ordinary course of business since December 31, 2015.

Off-Balance Sheet Arrangements

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

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MPC Strategic Actions

On October 26, 2016, MPC announced it plans to offer the Partnership assets contributing approximately $350 million of annual EBITDA in 2017, with the first drop of approximately $235 million of annual EBITDA by the end of the first quarter. The Partnership's plans for funding these dropdowns would likely include transactions with MPC, including the potential for a substantial amount of equity to MPC. MPC intends to execute on additional value-enhancing dropdowns totaling an estimated $1.0 billion of annual EBITDA to the Partnership by December 31, 2019. The dropdown strategy is subject to market and other conditions, as well as requisite approvals. In addition to the expected dropdowns, MPC announced the evaluation of opportunities to optimize the Partnership's cost of capital through a strategic review of its general partner interest.

Forward-looking Statements

The above discussion contains forward-looking statements with respect to certain strategic actions announced by MPC, including MPC’s dropdown strategy and the Partnership’s plans for funding such dropdowns. Factors that could affect strategic actions announced by MPC, including MPC’s dropdown strategy and the Partnership’s plans for funding such dropdowns, include, but are not limited to, the time, costs and ability to obtain regulatory or other approvals and consents and otherwise consummate such strategic actions; the satisfaction or waiver of conditions in the agreements governing such strategic actions; the ability to achieve the strategic and other objectives related to the strategic actions; the impact of adverse market conditions affecting the Partnership’s businesses; adverse changes in laws including with respect to tax and regulatory matters; the MPLX conflicts committee review process with respect to the timing of and value attributed to assets expected to be offered to the Partnership. Our opinions concerning liquidity and capital resources, including 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 prices of and demand for natural gas, NGLs, crude oil and refined petroleum products, actions of competitors, delays in obtaining necessary third-party approvals, 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 and 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.

TRANSACTIONS WITH RELATED PARTIES

At September 30, 2016, MPC held a two percent general partner interest and a 24.86 percent limited partner interest in MPLX LP.

Excluding revenues attributable to volumes shipped by MPC under joint tariffs with third parties that are treated as third-party revenues for accounting purposes, MPC accounted for 28 percent and 91 percent of our total revenues and other income for the third quarter of 2016 and 2015, respectively. MPC accounted for 31 percent and 91 percent of our total revenues and other income for the first nine months of 2016 and 2015, respectively. We provide 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 42 percent for the third quarter of 2016 and 2015, respectively, and 20 percent and 44 percent for the first nine months of 2016 and 2015, respectively. MPC performed certain services for us related to information technology, engineering, legal, accounting, treasury, human resources and other administrative services.

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

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ENVIRONMENTAL MATTERS AND COMPLIANCE COSTS

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

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

On April 17, 2016, a release of diesel fuel was discovered near Crawleyville, Indiana from our pipeline that transports products from Robinson, Illinois to Mount Vernon, Indiana. The estimated volume of the release is 1,150 barrels. During the nine months ended September 30, 2016, we incurred approximately $2 million in remediation expenses, and we do not anticipate that there will be any material incremental costs incurred in connection with this matter. We have submitted this incident to our insurers.

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

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CRITICAL ACCOUNTING ESTIMATES

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



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

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Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Impairment of Goodwill
Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate goodwill for impairment annually as of November 30 and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The first step of the evaluation is a qualitative analysis to determine if it is “more likely than not” that the carrying value of a reporting unit with goodwill exceeds its fair value. The additional quantitative steps in the goodwill impairment test may be performed if we determine that it is more likely than not that the carrying value is greater than the fair value.	Management performed a quantitative analysis during the first quarter of 2016, and determined the fair value of our reporting units in both the G&P and L&S segments using the income and market approaches for our first quarter 2016 impairment analysis. Management performed a qualitative analysis during the second quarter of 2016 and concluded that there were no indicators that would cause us to proceed to a quantitative analysis for the second quarter. These types of analyses require us to make assumptions and estimates regarding industry and economic factors such as relevant commodity prices, contract renewals, and production volumes. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations. Management is also required to make certain assumptions when identifying the reporting units and determining the amount of goodwill allocated to each reporting unit. The method of allocating goodwill resulting from the acquisitions involved estimating the fair value of the reporting units and allocating the purchase price for each acquisition to each reporting unit. Goodwill is then calculated for each reporting unit as the excess of the allocated purchase price over the estimated fair value of the net assets.	During the first quarter of 2016, we determined that an interim impairment analysis of the goodwill recorded in connection with the MarkWest Merger was necessary based on consideration of a number of first quarter events and circumstances, including i) continued deterioration of near term commodity prices as well as longer term pricing trends, ii) recent guidance on reductions to forecasted capital spending, the slowing of drilling activity and the resulting reduced production growth forecasts released or communicated by our producer customers and iii) increases in cost of capital. The combination of these factors was considered to be a triggering event requiring an interim impairment test. Based on the first step of the interim goodwill impairment analysis, the fair value for the three reporting units to which goodwill was assigned in connection with the merger was less than the respective carrying value. In step two of the impairment analysis, the implied fair values of the goodwill were compared to the carrying values within those reporting units. Based on this assessment, it was determined that goodwill was impaired in two of the three reporting units. Accordingly, we recorded an impairment charge of approximately $129 million in the first quarter of 2016. The fair value of the reporting units for the interim goodwill impairment analysis was determined based on applying the discounted cash flow method, which is an income approach, and the guideline public company method, which is a market approach. The discounted cash flow fair value estimate is based on known or knowable information at the interim measurement date. The significant assumptions that were used to develop the estimates of the fair values under the discounted cash flow method include management’s best estimates of the expected future results and discount rates, which range from 10.5 percent to 11.5 percent. The fair value of the intangibles was determined based on applying the multi-period excess earnings method, which is an income approach. Key assumptions include attrition rates by reporting unit ranging from 5.0 percent to 10.0 percent and discount rates by reporting unit ranging from 11.5 percent to 12.8 percent. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the first quarter interim goodwill impairment test will prove to be an accurate prediction of the future. We did not record an impairment charge in the Marcellus reporting unit within the G&P segment, which is the only other reporting unit within the G&P segment that has assigned goodwill. As of March 31, 2016, our allocation of the purchase price was provisional. Based on our assessment as of that date, the Marcellus reporting unit had $1,814 million of goodwill assigned to it (which amount was not adjusted as of June 30, 2016 when we finalized our purchase price allocation). Step 1 of the first quarter 2016 interim impairment analysis resulted in the carrying value of the Marcellus reporting unit exceeding its fair value by 0.62%; therefore, we completed Step 2 of the goodwill impairment analysis. Step 2 of the goodwill impairment analysis requires us to determine the fair value of all assets, liabilities and noncontrolling interests, if any, of the reporting unit, whether or not currently recognized. The implied fair value of goodwill is the residual value of the reporting unit's fair value, less the fair value of the assets, liabilities and noncontrolling interests, if any. The results of our Step 2 first quarter 2016 interim impairment analysis concluded that the fair value of the goodwill of the Marcellus reporting unit exceeded its carrying value of $1,814 million by approximately $20 million, or 1.2%. An increase of 0.50% to the discount rate used to estimate Marcellus' fair value as of the first quarter 2016 interim impairment analysis would have resulted in an additional goodwill impairment charge of more than $400 million for the three months ended March 31, 2016. The other significant assumption used to estimate the Marcellus reporting unit's fair value included estimates of future cash flows. If estimates for future cash flows, which are impacted primarily by commodity prices and producers' production plans, for this reporting unit were to decline, the overall reporting unit's fair value would decrease, resulting in a potential goodwill impairment charge. Additionally, an increase in the cost of capital would result in a decrease in the fair value of the Marcellus reporting unit, causing its value to decline and goodwill to potentially be impaired. During the second quarter of 2016, we determined that an interim impairment analysis of the goodwill recorded in connection with the MarkWest Merger was not necessary. The stabilization or improvement in the second quarter of the circumstances considered during our first quarter impairment analysis, the date of our last full goodwill impairment analysis, lead to our conclusion that it is not more likely than not that the fair value of our reporting units is less than their respective carrying values. In the second quarter of 2016, we completed our purchase price accounting for the MarkWest Merger. The completion of this accounting resulted in additional goodwill attributed to the reporting units for which an impairment charge had been taken in the first quarter of 2016. We therefore recorded an additional $1 million of impairment expense in the second quarter of 2016.

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

ACCOUNTING STANDARDS NOT YET ADOPTED

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

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Item 3. Quantitative and Qualitative Disclosures about Market Risk

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

Commodity Price Risk

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

Outstanding Derivative Contracts

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



WTI Crude Swaps	Volumes (Bbl/d)	WAVG Price (Per Bbl)		Fair Value (in thousands)
2016 (Oct - Dec)	1,000	$	52.17	$	291



Ethane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2016 (Oct - Dec)	54,600	$	0.23	$	32
2017	25,200	$	0.26	$	96



Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2016 (Oct - Dec)	75,600	$	0.43	$	(835	)
2017 (Jan - Jun)	12,395	$	0.51	$	(87	)



IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2016 (Oct - Dec)	16,517	$	0.59	$	(232	)
2017 (Jan - Mar)	1,375	$	0.65	$	(28	)



Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2016 (Oct - Dec)	12,600	$	0.53	$	(231	)
2017 (Jan - Mar)	2,749	$	0.65	$	(51	)



Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2016 (Oct - Dec)	4,200	$	0.98	$	(37	)

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



Natural Gas Swaps	Volumes (MMBtu/d)	WAVG Price (Per MMBtu)		Fair Value (in thousands)
2016 (Oct - Dec)	5,923	$	2.28	$	292
2017	814	$	2.93	$	(4	)



Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2016 (Oct - Dec)	38,294	$	0.49	$	(220	)
2017	5,325	$	0.53	$	(33	)

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IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2016 (Oct - Dec)	4,222	$	0.60	$	(57	)
2017	548	$	0.68	$	(7	)



Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2016 (Oct - Dec)	11,731	$	0.57	$	(149	)
2017	1,512	$	0.59	$	(15	)



Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2016 (Oct - Dec)	8,306	$	0.91	$	(131	)
2017	1,016	$	1.07	$	(8	)

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



Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2016 (Oct - Dec)	63,000	$	0.48	$	(443	)
2017 (Jan - Jun)	12,395	$	0.51	$	(79	)



IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2016 (Oct - Dec)	8,400	$	0.56	$	(138	)



Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2016 (Oct - Dec)	21,000	$	0.59	$	(235	)



Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)		Fair Value (in thousands)
2016 (Oct - Dec)	46,200	$	0.99	$	(381	)
2017	12,600	$	1.08	$	(64	)

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



Ethane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2017	8,400	$	0.27



Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2017	24,962	$	0.56



IsoButane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2017	3,479	$	0.73



Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2017	7,168	$	0.72



Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2017	7,483	$	1.13

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



Propane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2017	12,600	$	0.57



Normal Butane Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2017	4,200	$	0.68



Natural Gasoline Swaps	Volumes (Gal/d)	WAVG Price (Per Gal)
2017	4,200	$	1.13

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 September 30, 2016, the estimated fair value of this contract was a liability of $44 million.

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

Interest Rate Risk

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



(In millions)	Fair Value as of September 30, 2016⁽¹⁾		Change in Fair Value ⁽²⁾		Change in Income Before Income Taxes for the Nine Months Ended September 30, 2016 ⁽³⁾
Long-term debt
Fixed-rate	$	4,737	$	316	n/a
Variable-rate	$	250	n/a		$	4


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


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


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

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At September 30, 2016, 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 term loan facility, but may affect our results of operations and cash flows. As of September 30, 2016, we did not have any financial derivative instruments to hedge the risks related to interest rate fluctuations; however, we continually monitor the market and our exposure and may enter into these agreements in the future.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

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

Changes in Internal Control Over Financial Reporting

During the quarter ended September 30, 2016, 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.

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Part II – Other Information

Item 1. Legal Proceedings

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

Litigation

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

As reported in our Annual Report on Form 10-K for the year ended December 31, 2015, 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 loss) for this litigation. Under the omnibus agreement, MPC will indemnify the Partnership for the full cost of any losses should MPL be deemed responsible for any damages in this lawsuit.

Environmental Proceedings

As reported in our Quarterly Report on Form 10-Q for the period ended June 30, 2016, on May 18, 2016, MarkWest Liberty Midstream received a draft Consent Order from the West Virginia Department of Environmental Protection (“WVDEP”) alleging certain air permitting and emissions violations at our Sherwood Facility, a gas processing facility located in West Virginia, including failure to comply with monitoring, tagging, recordkeeping and repair requirements with respect to certain equipment at the facility as well as the failure to comply with certain permit application requirements. On September 6, 2016, MarkWest Liberty Midstream executed a final Consent Order with the WVDEP resolving these matters. Pursuant to the final Consent Order, MarkWest Liberty Midstream paid a $95,000 civil penalty and agreed to implement certain enhancements in connection with our existing leak monitoring program, provide additional training, and provide funding for certain programs and equipment for the WVDEP which is expected to cost approximately $140,000.

As previously reported, 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, with the assistance of EPA’s Criminal Investigation Division proceeded with an investigation of MarkWest’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’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'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.

possible that in connection with any potential or asserted enforcement action associated with this matter, MarkWest Liberty Midstream will incur material assessments, penalties or fines, incur material defense costs and expenses, be required to modify operations or construction activities which could increase operating costs and capital expenditures, or be subject to other obligations or restrictions that could restrict or prohibit our activities, any or all of which could adversely affect our results of operations, financial position or cash flows. The amount of any potential assessments, penalties, fines, restrictions, requirements, modifications, costs or expenses that may be incurred in connection with any potential enforcement action cannot be reasonably estimated or determined at this time.

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

Item 1A. Risk Factors

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

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Item 2. Unregistered Sales of Equity Securities

In connection with 2,386 common units issued upon the vesting of phantom units under the MPLX LP 2012 Incentive Compensation Plan and 359,179 common units issued as a result of the conversion of Class B units to common units our general partner purchased an aggregate of 7,379 general partner units for $243 thousand in cash during the three months ended September 30, 2016, to maintain its two percent general partner interest in us. The general partner units were issued in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended.

On August 31, 2016, in connection with 5,700,000 MPLX LP common units issued under MPLX LP’s ATM Program during the month of August, MPLX GP purchased 116,326 general partner units for $4 million in cash to maintain its two percent general partner interest in MPLX LP. 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.

In connection with the Class A Reorganization, MPLX LP redeemed or exchanged 21,401,137 MPLX LP common units held by MPLX Logistics Holdings LLC and 436,758 general partner units held by MPLX GP. See Note 7 of the Notes to Consolidated Financial Statements for further discussion. The general partner units were redeemed in reliance on an exemption from registration under Section 4(a)(2) of the Securities Act of 1933, as amended.

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Item 5. Other Information

On October 26, 2016, MPLX GP amended and restated the Second Amended and Restated Agreement of Limited Partnership of MPLX LP by executing the Third Amended and Restated Agreement of Limited Partnership of MPLX LP (the “Third Amended and Restated Partnership Agreement”). Set forth is a summary description of the amendments implement by the Third Amended and Restated Partnership Agreement:


•	The rights, preferences, privileges and other terms relating to the MPLX Class A units were removed as the MPLX Class A units were eliminated in connection with the Class A Reorganization. See Note 7 of the Notes to Consolidated Financial Statements for further discussion of the Class A Reorganization.


•	Other amendments MPLX GP determined did not adversely affect the limited partners of the Partnership considered as a whole or any particular class of partnership interests as compared to other classes of partnership interests in any material respect.

The foregoing is a summary and is qualified in its entirety by reference to the Third Amended and Restated Partnership Agreement, attached hereto as Exhibit 3.3, and incorporated by reference into this Item 5.

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Item 6. Exhibits

Incorporated by Reference

Exhibit

Number

Exhibit Description

Form

Exhibit

Filing Date

SEC File No.

Filed

Herewith

Furnished

Herewith

2.1

Membership Interests Contribution Agreement, dated March 14, 2016, between MPLX LP, MPLX Logistics Holdings LLC, MPLX GP LLC and MPC Investment LLC

8-K

2.1

3/17/2016

001-35714

3.1

Certificate of Limited Partnership of MPLX LP

S-1

3.1

7/2/2012

333-182500

3.2

Amendment to the Certificate of Limited Partnership of MPLX LP

S-1/A

3.2

10/9/2012

333-182500

3.3

Third Amended and Restated Agreement of Limited Partnership of MPLX LP, dated as of October 26, 2016

10.1

Master Reorganization Agreement, dated September 1, 2016, by and among MPLX Holdings Inc., MarkWest Energy Partners, L.P., MWE GP LLC, MPLX LP, MPLX GP LLC, MPC Investment LLC, MPLX Logistics Holdings LLC and MarkWest Hydrocarbon, L.L.C.

8-K

10.1

9/6/2016

001-35714

10.2

Second Amendment to Amended and Restated Operating Agreement, dated August 1, 2016, between Marathon Petroleum Company LP and Marathon Pipe Line LLC

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

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SIGNATURES

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



	MPLX LP

	By:	MPLX GP LLC
		Its general partner

Date: October 31, 2016	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 FY2016 Q3

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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	44
Item 3. Quantitative and Qualitative Disclosures about Market Risk	70
Item 4. Controls and Procedures	73

PART II – OTHER INFORMATION
Item 1. Legal Proceedings	74
Item 1A. Risk Factors	75
Item 2. Unregistered Sales of Equity Securities	76
Item 5. Other Information	77
Item 6. Exhibits	78
Signatures	79