EXPLANATORY NOTE

On March 1, 2017, MPLX LP (the “Partnership”) entered into a Membership Interests Contributions Agreement (the “Contributions Agreement”) with MPLX GP LLC (the “General Partner”), MPLX Logistics Holdings LLC (“MPLX Logistics”), MPLX Holdings Inc. (“MPLX Holdings”) and MPC Investment LLC (“MPC Investment”), each a wholly owned subsidiary of Marathon Petroleum Corporation (“MPC”). Pursuant to the Contributions Agreement, MPC Investment agreed to contribute the outstanding membership interests in Xxxxxx Street Transportation LLC (“HST”), Woodhaven Cavern LLC (“WHC”) and MPLX Terminals LLC (“MPLXT”) through a series of intercompany contributions to the Partnership for approximately $1.5 billion in cash and equity consideration valued at approximately $504 million (the “Transaction”). The number of common units representing the equity consideration was determined by dividing the contribution amount by the simple average of the ten day trailing volume weighted average New York Stock Exchange price of a common unit for the ten trading days ending at market close on February 28, 2017. The fair value of the common and general partner units issued was approximately $503 million and consisted of (i) 9,197,900 common units representing limited partner interests in the Partnership to the General Partner, (ii) 2,630,427 common units to MPLX Logistics and (iii) 1,132,049 common units to MPLX Holdings. The Partnership also issued 264,497 general partner units to the General Partner in order to maintain its two percent general partner interest in the Partnership.

HST owns and operates various private crude oil and refined product pipeline systems and associated storage tanks. These pipeline systems consist of 174 miles of crude oil pipelines and 430 miles of refined products pipelines. WHC owns and operates nine butane and propane storage caverns located in Michigan with approximately 1.75 million barrels of natural gas liquids storage capacity. MPLXT owns and operates 59 terminals for the receipt, storage, blending, additization, handling and redelivery of refined petroleum products. Additionally, MPLXT operates one leased terminal and has partial ownership interest in two terminals. Collectively, these 62 terminals have a combined total shell capacity of approximately 23.6 million barrels. The terminal facilities are located primarily in the Midwest, Gulf Coast and Southeast regions of the United States. The Partnership accounts for these businesses within the Logistics and Storage (“L&S”) segment.

The information in Items 6, 7 and 8 below includes periods prior to the Transaction. MPC contributed the assets of HST, WHC and MPLXT to newly created and wholly-owned subsidiaries and entered into commercial agreements related to services provided by these new entities to MPC on January 1, 2015 for HST and WHC and April 1, 2016 for MPLXT. Prior to these dates, these entities were not considered businesses. The Partnership’s consolidated financial statements have been retrospectively recast for all periods to give effect to the acquisition of HST and WHC as if the Transaction had occurred on January 1, 2015 and MPLXT as if the Transaction had occurred on April 1, 2016, as required for transactions between entities under common control. See Item 8. Financial Statements and Supplementary Data – Note 4 and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for more information on the Transaction.

Unless the context otherwise requires, references in this report to “MPLX LP,” “the Partnership,” “we,” “our,” “us,” or like terms refer to MPLX LP and its subsidiaries, including MPLX Operations LLC (“MPLX Operations”), MPLX Terminal and Storage LLC (“MPLX Terminal and Storage”), MarkWest Energy Partners, L.P. (“MarkWest”), MarkWest Hydrocarbon, L.L.C. (“MarkWest Hydrocarbon”), MPLX Pipe Line Holdings LLC (“Pipe Line Holdings”), Marathon Pipe Line LLC (“MPL”), Ohio River Pipe Line LLC (“ORPL”), Xxxxxx Street Marine LLC (“HSM”), HST, WHC and MPLXT. We have partial ownership interests in a number of joint venture legal entities, including MarkWest Pioneer, L.L.C. (“MarkWest Pioneer”), MarkWest Utica EMG, L.L.C. (“MarkWest Utica EMG”) and its subsidiary Ohio Gathering Company, L.L.C. (“Ohio Gathering”), Ohio Condensate Company, L.L.C. (“Ohio Condensate”), Xxxxx Gathering Partnership (“Xxxxx”), MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. (“Jefferson Dry Gas”), Xxxxxxxx County Terminal, LLC (“Xxxxxxxx Terminal”) and Guilford County Terminal Company, LLC (“Guilford Terminal”). References to “MPC” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other than the Partnership. Unless otherwise specified, references to “Predecessor” refer collectively to HSM’s, HST’s, WHC’s and MPLXT’s related assets, liabilities and results of operations prior to the dates of their respective acquisitions and as if they had occurred on January 1, 2014 for HSM, January 1, 2015 for HST and WHC and April 1, 2016 for MPLXT.

Part II

Item 6. Selected Financial Data

The following table shows selected historical consolidated financial data of MPLX LP as of the dates and for the years indicated. On May 1, 2013, we acquired a five percent interest in Pipe Line Holdings, resulting in a 56 percent indirect ownership interest at December 31, 2013. We then acquired a 13 percent interest in Pipe Line Holdings on March 1, 2014, and a 30.5 percent interest on December 1, 2014, resulting in a 99.5 percent indirect ownership interest at December 31, 2014. The remaining 0.5 percent interest was purchased on December 4, 2015. On this same date, a wholly-owned subsidiary of MPLX LP merged with MarkWest. This information includes periods prior to the acquisition of HSM, which occurred on March 31, 2016, and prior to the acquisition of HST, WHC and MPLXT, which occurred on March 1, 2017.

The following table also presents the non-GAAP financial measures of Adjusted EBITDA and DCF, which we use in our business. For the definitions of Adjusted EBITDA and DCF and a reconciliation to our most directly comparable financial measures calculated and presented in accordance with GAAP, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Information and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.



(In millions, except per unit data)	2016			2015			2014			2013			2012
Consolidated Statements of Income Data
Total revenues and other income	$	3,029		$	1,101		$	793		$	713		$	686
Income from operations	683			381			245			213			204
Net income	434			333			239			211			204
Net income attributable to MPLX LP	233			156			121			78			13
Limited partners’ interest in net income attributable to MPLX LP	1			99			115			76			13
Per Unit Data
Net income attributable to MPLX LP per limited partner unit (basic and diluted):
Common - basic	$	—		$	1.23		$	1.55		$	1.05		$	0.18
Common - diluted	—			1.22			1.55			1.05			0.18
Subordinated - basic and diluted	—			0.11			1.50			1.01			0.17
Cash distributions declared per limited partner common unit	$	2.0500		$	1.8200		$	1.4100		$	1.1675		$	0.1769
Consolidated Balance Sheets Data (at period end)
Property, plant and equipment, net	$	11,408		$	10,214		$	1,324		$	1,248		$	1,167
Total assets	17,509			16,404			1,544			1,504			1,572
Long-term debt, including capital leases⁽³⁾	4,422			5,255			644			10			10
Redeemable preferred units	1,000			—			—			—			—
Consolidated Statements of Cash Flows Data
Net cash provided by (used in):
Operating activities	$	1,491		$	427		$	334		$	297		$	273
Investing activities	(1,413		)	(1,686		)	(137		)	(158		)	64
Financing activities	113			1,275			(224		)	(302		)	(120		)
Additions to property, plant and equipment⁽¹⁾	1,313			334			141			151			159
Other Financial Data
Adjusted EBITDA attributable to MPLX LP⁽²⁾⁽⁴⁾	$	1,419		$	498		$	166		$	111		$	18
DCF attributable to MPLX LP⁽²⁾⁽⁴⁾	1,140			399			137			114			17


(1)	Represents cash capital expenditures as reflected on Consolidated Statements of Cash Flows for the periods indicated, which are included in cash used in investing activities.

(2)

The 2012 Adjusted EBITDA attributable to MPLX LP is subsequent to the Initial Offering. The 2015 Adjusted EBITDA attributable to MPLX LP includes pre-merger EBITDA from MarkWest and the 2015 DCF includes undistributed DCF from MarkWest. For a discussion of the non-GAAP financial measures of Adjusted EBITDA and DCF and a reconciliation of Adjusted EBITDA and DCF to our most directly comparable measures calculated and presented in accordance with GAAP, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Information and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.


(3)	Includes amounts due within one year. During 2015, in connection with the MarkWest Merger, MPLX LP assumed MarkWest senior notes with an aggregate principal amount of $4.1 billion and used its credit facility to repay $850 million of the $943 million of borrowings under MarkWest’s credit facility.


(4)	For all years presented, Predecessor is excluded from Adjusted EBITDA attributable to MPLX LP and DCF attributable to MPLX LP.

Operating Data



	2016			2015			2014		2013		2012
L&S
Crude oil transported for (mbpd)⁽¹⁾:
MPC	1,461			1,443			838		853		830
Third parties	182			197			203		222		202
Total	1,643			1,640			1,041		1,075		1,032
% MPC	89		%	88		%	80	%	79	%	80	%

Products transported for (mbpd)⁽²⁾:
MPC⁽³⁾	846			966			852		862		909
Third parties	145			27			26		49		71
Total	991			993			878		911		980
% MPC	85		%	97		%	97	%	95	%	93	%

Average tariff rates ($ per barrel):
Crude oil pipelines	0.57			0.55			0.64		0.60		0.57
Product pipelines	0.68			0.65			0.61		0.56		0.51
Total pipelines	0.61			0.59			0.63		0.58		0.54

Terminal throughput (mbpd)⁽⁴⁾	63,217			n/a			n/a		n/a		n/a

Barges⁽⁵⁾	204			205			199		184		177
Towboats⁽⁵⁾	18			18			18		17		15

G&P⁽⁶⁾
Gathering Throughput (mmcf/d)
Xxxxxxxxx Operations	910			889
Utica Operations⁽⁷⁾⁽⁸⁾	932			745
Southwest Operations⁽⁹⁾	1,433			1,441
Total gathering throughput	3,275			3,075

Natural Gas Processed (mmcf/d)
Xxxxxxxxx Operations	3,210			2,964
Utica Operations⁽⁷⁾	1,072			1,136
Southwest Operations	1,226			1,125
Southern Appalachian Operations	253			243
Total natural gas processed	5,761			5,468

C2 + NGLs Fractionated (mbpd)
Xxxxxxxxx Operations^(10)(11)	260			220
Utica Operations^(7)(11)	42			51
Southwest Operations	18			24
Southern Appalachian Operations⁽¹²⁾	15			12
Total C2 + NGLs fractionated⁽¹³⁾	335			307

Pricing Information
Natural Gas NYMEX HH ($/MMBtu)	$	2.55		$	2.04
C2 + NGL Pricing/gallon⁽¹⁴⁾	$	0.47		$	0.40

(1)

Represents the average aggregate daily number of barrels of crude oil transported on our pipeline systems and at our Wood River barge dock for MPC and for third parties. Volumes shown are 100 percent of the volumes transported on the pipeline systems and barge dock. Volumes shown for all periods exclude volumes transported on two undivided joint interest crude oil pipeline systems not contributed to MPLX LP at the Initial Offering.


(2)	Represents the average aggregate daily number of barrels of products transported on our pipeline systems for MPC and third parties. Volumes shown are 100 percent of the volumes transported on the pipeline systems.

(3)

Includes volumes shipped by MPC on various pipelines under joint tariffs with third parties. For accounting purposes, revenue attributable to these volumes is classified as third-party revenue because we receive payment from those third parties with respect to volumes shipped under the joint tariffs; however, the volumes associated with this revenue are applied towards MPC’s minimum quarterly volume commitments on the applicable pipelines because MPC is the shipper of record.


(4)	Represents the average volumes for the nine months beginning April 1, 2016.


(5)	Represents the number of owned barges and towboats at the end of the period presented.


(6)	G&P volumes represent the volumes after the close of the MarkWest Merger. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Supplemental MD&A – G&P Pro Forma for full-year pro forma information.


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


(8)	The Jefferson Gas System came online in December 2015. The volumes reported for 2015 are the average daily rate for the days of operation.


(9)	Includes approximately 309 mmcf/d and 310 mmcf/d related to unconsolidated equity method investments, Xxxxx and MarkWest Pioneer for the years ended December 31, 2016 and 2015, respectively.


(10)	The Sherwood de-ethanization complex came online in December 2015. The volumes reported for 2015 are the average daily rate for the days of operation.

(11)

Hopedale is jointly owned by Ohio Fractionation and MarkWest Utica EMG. Ohio Fractionation is a subsidiary of MarkWest Liberty Midstream. MarkWest Liberty Midstream and MarkWest Utica EMG are entities that operate in the Marcellus and Utica regions, respectively. The Marcellus Operations includes its portion utilized of the jointly owned Hopedale Fractionation Complex. The Utica Operations includes Utica’s portion utilized of the jointly owned Hopedale Fractionation Complex.


(12)	Includes NGLs fractionated for the Marcellus and Utica Operations.


(13)	Purity ethane makes up approximately 128 and 104 mbpd of total fractionated products for the years ended December 31, 2016 and 2015, respectively.


(14)	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.

Item 7. 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 information included under Item 1. Business, Item 1A. Risk Factors, Item 6. Selected Financial Data and Item 8. Financial Statements and Supplementary Data.

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.

PARTNERSHIP OVERVIEW

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

SIGNIFICANT FINANCIAL AND OTHER HIGHLIGHTS

We have completed a full year of operations following the Partnership’s strategic merger with MarkWest. Given the challenging economic and commodity environment, our priorities during 2016 included delivering solid financial results, carefully managing our capital and expenses, improving our financial leverage metrics and positioning the Partnership for longer term growth. Significant financial and other highlights for the year ended December 31, 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 $131 million, or 41 percent, in 2016 compared to 2015. This increase was primarily due to the acquisition of the inland marine business on March 31, 2016, which continues the diversification of earnings streams and adds additional fee-based revenues to the Partnership. The L&S segment operating income also increased due to higher average pipeline tariffs. See Item 8. Financial Statements and Supplementary Data – Note 4 for further details of the HSM acquisition.

•

G&P segment operating income attributable to MPLX LP increased approximately $1.1 billion, or 1,389 percent, in 2016 compared to 2015, due to the MarkWest Merger. Despite declines in drilling activity by producers, the G&P segment realized volume increases across most of its businesses during 2016. Compared to full-year 2015, gathering volumes were up 11 percent, processing volumes were up 13 percent and fractionated volumes were up 25 percent.


•	Net income for the year ended December 31, 2016 was $434 million, full-year 2016 DCF, a non-GAAP measure, was over $1.1 billion and full-year 2016 distributions were $2.05 per common unit, which represents a 13 percent increase over the full-year distributions of 2015.

•

On March 1, 2017, we purchased HST, WHC and MPLXT from MPC for $1.5 billion in cash and $503 million in equity consideration consisting of 12,960,376 common units and 264,497 general partner units in order for the general partner to maintain its two percent interest. HST owns various crude oil and refined product pipeline systems and associated storage tanks. WHC owns butane and propane storage caverns. MPLXT owns and operates light products terminals. The consolidated financial statements have been retrospectively recast to include the historical results of HST, WHC and MPLXT for all periods subsequent to those companies being established as businesses by MPC, as required for transactions between entities under common control. See Item 8. Financial Statements and Supplementary Data – Note 4 for further details of the acquisition.

During 2016, the Partnership substantially improved its financial leverage. This was accomplished through a balance of managing capital expenditures and costs and opportunistically accessing the capital markets, including:


•	The private placement of approximately 30.8 million 6.5 percent Series A Convertible Preferred units for a cash purchase price of $32.50 per unit during the second quarter of 2016. The aggregate net proceeds of approximately $984 million from the sale of the Preferred units was used for capital expenditures and repayment of debt.


•	The issuance of an aggregate of 26,347,887 common units under the ATM Program during the year ended December 31, 2016, generating net proceeds of approximately $776 million. As of December 31, 2016, $717 million of common units remains available for issuance through the ATM program under the Distribution Agreement.

During 2016, the Partnership also completed several significant organic growth projects, including:

•

On October 11, 2016, the Cornerstone Pipeline became fully operational. This is a key organic growth project within our L&S segment designed to transport condensate and natural gasoline from the Marcellus and Utica regions to MPC’s Canton, Ohio, refinery. The Partnership is expanding the capacity of existing pipelines and constructing new pipelines as part of a larger build-out of Utica Shale infrastructure, seizing a unique opportunity to connect natural gas liquids to downstream markets in the Midwest and Canada through our extensive distribution network.


•	We expanded our presence in the Southwest with the completion of the Xxxxxxx gas processing complex in the Delaware Basin of Texas, and will evaluate further investments in gathering and processing to support the substantial activity our producer-customers are pursuing in the region.

Looking ahead, the Partnership is taking actions that should contribute to long-term value for our investors, including the following recent announcements made in 2017:


•	Planned acquisition of assets from MPC with an estimated $1.4 billion of annual EBITDA, of which, $250 million of EBITDA has already been completed with the March 1, 2017 acquisition of HST, WHC and MPLXT.


•	Our intent to reduce the Partnership’s cost of capital by offering to exchange MPLX LP units for MPC’s IDRs;


•	Strategic joint venture with Antero Midstream to support Antero Resources in the Xxxxxxxxx Xxxxx; and


•	Public debt offering of $2.25 billion principal amount senior notes.

Refer to Item 1. Business – Recent Developments and Liquidity and Capital Resources for further details concerning the above-listed announcements.

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) provision (benefit) for income taxes; (iii) amortization of deferred financing costs; (iv) non-cash equity-based compensation; (v) impairment expense; (vi) net interest and other financial costs; (vii) loss (income) from equity investments; (viii) distributions from unconsolidated subsidiaries; (ix) unrealized derivative losses (gains); and (x) acquisition costs. We also use DCF, which we define as Adjusted EBITDA adjusted for (i) deferred revenue impacts; (ii) net interest and other financial costs; (iii) maintenance capital expenditures; and (iv) other non-cash items. The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, we record changes in the fair value of the derivative as an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously recorded unrealized gain or loss and record the realized gain or loss of the contract.

We believe that the presentation of Adjusted EBITDA and DCF provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and DCF are net income and net cash provided by operating activities. Adjusted EBITDA and DCF should not be considered as alternatives to GAAP net income or net cash provided by operating activities. Adjusted EBITDA and DCF have important limitations as analytical tools because they exclude some but not all items that affect net income and net cash provided by operating activities

or any other measure of financial performance or liquidity presented in accordance with GAAP. Adjusted EBITDA and DCF should not be considered in isolation or as substitutes for analysis of our results as reported under GAAP. Additionally, because Adjusted EBITDA and DCF may be defined differently by other companies in our industry, our definitions of Adjusted EBITDA and DCF may not be comparable to similarly titled measures of other companies, thereby diminishing their utility. For a reconciliation of Adjusted EBITDA and DCF to their most directly comparable measures calculated and presented in accordance with GAAP, see Results of Operations.

Management evaluates contract performance on the basis of net operating margin (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. The use of these measures allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. See Item 8. Financial Statements and Supplementary Data – Note 10 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 and impairments have impacted comparability of our financial results (see Item 8. Financial Statements and Supplementary Data – Notes 4 and 18).

RESULTS OF OPERATIONS

The following table and discussion is a summary of our results of operations for the years ended 2016, 2015 and 2014, 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 for all prior periods presented, for the acquisition of HST and WHC for all periods subsequent to January 1, 2015 and MPLXT for all periods subsequent to April 1, 2016 as these entities were not considered businesses prior to these dates.



(In millions)	2016			2015		$ Change			2014		$ Change
Revenues and other income:
Service revenue	$	958		$	130	$	828		$	70	$	60
Service revenue - related parties	936			701		235			662		39
Rental income	298			20		278			—		20
Rental income - related parties	235			146		89			15		131
Product sales	572			36		536			—		36
Product sales - related parties	11			1		10			—		1
Gain on sale of assets	1			—		1			—		—
(Loss) income from equity method investments	(74		)	3		(77		)	—		3
Other income	6			6		—			6		—
Other income - related parties	86			58		28			40		18
Total revenues and other income	3,029			1,101		1,928			793		308
Costs and expenses:
Cost of revenues (excludes items below)	454			247		207			228		19
Purchased product costs	448			20		428			—		20
Rental cost of sales	57			11		46			1		10
Rental cost of sales - related parties	1			1		—			—		1
Purchases - related parties	388			172		216			153		19
Depreciation and amortization	591			129		462			75		54
Impairment expense	130			—		130			—		—
General and administrative expenses	227			125		102			81		44
Other taxes	50			15		35			10		5
Total costs and expenses	2,346			720		1,626			548		172
Income from operations	683			381		302			245		136
Related party interest and other financial costs	1			—		1			—		—
Interest expense (net of amounts capitalized of $28 million, $5 million, and $1 million, respectively)	210			35		175			4		31
Other financial costs	50			12		38			1		11
Income before income taxes	422			334		88			240		94
(Benefit) provision for income taxes	(12		)	1		(13		)	1		—
Net income	434			333		101			239		94
Less: Net income attributable to noncontrolling interests	2			1		1			57		(56		)
Less: Net income attributable to Predecessor	199			176		23			61		115
Net income attributable to MPLX LP	$	233		$	156	$	77		$	121	$	35

Adjusted EBITDA attributable to MPLX LP⁽¹⁾	$	1,419		$	498	$	921		$	166	$	332
DCF⁽¹⁾	$	1,140		$	399	$	741		$	137	$	262
DCF attributable to GP and LP unitholders⁽¹⁾	$	1,099		$	399	$	700		$	137	$	262


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



(In millions)	2016			2015			2014
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net income:
Net income	$	434		$	333		$	239
Depreciation and amortization	591			129			75
(Benefit) provision for income taxes	(12		)	1			1
Amortization of deferred financing costs	46			5			—
Non-cash equity-based compensation	10			4			2
Impairment expense	130			—			—
Net interest and other financial costs	215			42			5
Loss (income) from equity investments	74			(3		)	—
Distributions from unconsolidated subsidiaries	150			15			—
Unrealized derivative losses (gains)⁽¹⁾	36			(4		)	—
Acquisition costs	(1		)	30			—
Adjusted EBITDA	1,673			552			322
Adjusted EBITDA attributable to noncontrolling interests	(3		)	(1		)	(69		)
Adjusted EBITDA attributable to Predecessor⁽²⁾	(251		)	(215		)	(87		)
MarkWest's pre-merger EBITDA⁽³⁾	—			162			—
Adjusted EBITDA attributable to MPLX LP	1,419			498			166
Deferred revenue impacts	16			6			(3		)
Net interest and other financial costs	(215		)	(35		)	(6		)
Maintenance capital expenditures	(84		)	(49		)	(22		)
Other	(4		)	(6		)	2
Portion of DCF adjustments attributable to Predecessor⁽²⁾	8			17			—
DCF pre-MarkWest undistributed	1,140			431			137
MarkWest undistributed DCF ⁽³⁾	—			(32		)	—
DCF	1,140			399			137
Preferred unit distributions	(41		)	—			—
DCF attributable to GP and LP unitholders	$	1,099		$	399		$	137



(In millions)	2016			2015			2014
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net cash provided by operating activities:
Net cash provided by operating activities	$	1,491		$	427		$	334
Changes in working capital items	(66		)	63			(19		)
All other, net	(26		)	(11		)	(2		)
Non-cash equity-based compensation	10			4			2
Net gain on disposal of assets	1			—			—
Net interest and other financial costs	215			42			5
Current income taxes	5			—			—
Asset retirement expenditures	6			1			2
Unrealized derivative losses (gains)⁽¹⁾	36			(4		)	—
Acquisition costs	(1		)	30			—
Other	2			—			—
Adjusted EBITDA	1,673			552			322
Adjusted EBITDA attributable to noncontrolling interests	(3		)	(1		)	(69		)
Adjusted EBITDA attributable to Predecessor⁽²⁾	(251		)	(215		)	(87		)
MarkWest's pre-merger EBITDA⁽³⁾	—			162			—
Adjusted EBITDA attributable to MPLX LP	1,419			498			166
Deferred revenue impacts	16			6			(3		)
Net interest and other financial costs	(215		)	(35		)	(6		)
Maintenance capital expenditures	(84		)	(49		)	(22		)
Other	(4		)	(6		)	2
Portion of DCF adjustments attributable to Predecessor⁽²⁾	8			17			—
DCF pre-MarkWest undistributed	1,140			431			137
MarkWest undistributed DCF⁽³⁾	—			(32		)	—
DCF	1,140			399			137
Preferred unit distributions	(41		)	—			—
DCF attributable to GP and LP unitholders	$	1,099		$	399		$	137

(1)

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


(2)	The Adjusted EBITDA and DCF adjustments related to Predecessor are excluded from Adjusted EBITDA attributable to

MPLX LP and DCF prior to the acquisition dates.

(3)

The financial and operational results of MarkWest are included in the Partnership’s results from December 4, 2015, the date of the MarkWest Merger, in accordance with GAAP. The Partnership distributes and, prior to the MarkWest Merger, MarkWest distributed, all or a portion of the DCF generated in any given quarter to unitholders in the subsequent quarter. MarkWest had made a distribution for the third quarter of 2015 prior to the MarkWest Merger. However, the DCF generated by MarkWest for the period from October 1, 2015 through December 3, 2015 had not been distributed to MarkWest unitholders as of the date of the MarkWest Merger. By operation of the MarkWest Merger, the Partnership acquired such undistributed cash, along with all other assets of MarkWest, with the intent and obligation to distribute such cash to the Partnership’s unitholders as part of the Partnership’s fourth quarter 2015 distribution. In order to effectively include the amount of Adjusted EBITDA and DCF generated by MarkWest during the fourth quarter of 2015 prior to the date of the MarkWest Merger, and effectively include such previously undistributed cash, we have made adjustments labeled “MarkWest’s pre-merger EBITDA” and “MarkWest undistributed DCF” in our reconciliations of Adjusted EBITDA and DCF to reported net income. MarkWest’s pre-merger EBITDA represents Adjusted EBITDA generated by MarkWest for the period from October 1, 2015 through December 3, 2015. MarkWest undistributed DCF represents the net adjustments made to MarkWest’s pre-merger EBITDA in order to arrive at the DCF generated by MarkWest for the period from October 1, 2015 through December 3, 2015.

The amount of Adjusted EBITDA and DCF generated by MarkWest for the period of October 1, 2015 through December 3, 2015 was considered by the board of directors of the Partnership’s general partner in approving the Partnership’s cash distribution for the fourth quarter of 2015. In addition, we believe the inclusion of the DCF generated by MarkWest for the period of October 1, 2015 through December 3, 2015 allows for a more meaningful calculation of the Partnership’s ratio of DCF generated to distributions declared for the fourth quarter of 2015. We believe the inclusion of these adjustments presents an appropriate basis for analyzing the complete operating results of the Partnership and MarkWest, on a combined basis, for the year ended December 31, 2015.

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



(In millions)	2016			2015			2014
Reconciliation of net operating margin to income from operations:
Segment revenue	$	3,426		$	1,063		$	747
Segment purchased product costs	(426		)	(26		)	—
Realized derivative loss (gain) related to revenues and purchased product costs	3			(4		)	—
Net operating margin	3,003			1,033			747
Revenue adjustment from unconsolidated affiliates⁽¹⁾	(402		)	(28		)	—
Realized derivative (loss) gain related to revenues and purchased product costs⁽²⁾	(3		)	4			—
Unrealized derivative (losses) gains⁽²⁾	(36		)	4			—
(Loss) income from equity method investments	(74		)	3			—
Other income	6			6			6
Other income - related parties	86			58			40
Cost of revenues (excludes items below)	(454		)	(247		)	(228		)
Rental cost of sales	(57		)	(11		)	(1		)
Purchases - related parties	(388		)	(172		)	(153		)
Depreciation and amortization	(591		)	(129		)	(75		)
Impairment expense	(130		)	—			—
General and administrative expenses	(227		)	(125		)	(81		)
Other taxes	(50		)	(15		)	(10		)
Income from operations	$	683		$	381		$	245


(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.

(2)

2016 Compared to 2015

Service revenue increased $828 million in 2016 compared to 2015. This variance was primarily due to an $824 million increase due to the MarkWest Merger, a $3 million increase related to volumes of crude oil and products shipped and a $1 million increase due to higher average tariffs received on the volumes of crude oil and products shipped.

Service revenue-related parties increased $235 million in 2016 compared to 2015. This increase was primarily related to the acquisition of Predecessor, a $13 million increase in higher average tariffs received on the volumes of crude oil and products shipped, a $6 million increase related to volumes in related-party crude oil and products shipped, $3 million increase in storage fees and increased HSM equipment revenue, partially offset by a reduction in fees previously paid by HSM on behalf of MPC that are now paid directly by MPC and a $2 million decrease in revenue related to volume deficiency credits recognized.

Rental income increased $278 million in 2016 compared to 2015. This variance was due to the MarkWest Merger.

Rental income-related parties increased $89 million in 2016 compared to 2015. This increase was primarily related to the acquisition of Predecessor, a $10 million increase in HSM equipment revenue and a $3 million increase in storage fees.

Product sales increased $536 million in 2016 compared to 2015. This variance was due to the MarkWest Merger.

(Loss) income from equity method investments decreased $77 million in 2016 compared to 2015. This variance was primarily due to the MarkWest Merger combined with impairment charges of $88 million related to one of our equity method investments.

Other income-related parties increased $28 million in 2016 compared to 2015. The increase was due mainly to the MarkWest Merger and inclusion of management fee revenue for engineering and construction and administrative services for operating our unconsolidated joint ventures, offset by a decrease in fees paid to HSM by MPC.

Cost of revenues increased $207 million in 2016 compared to 2015. This variance was primarily due to the MarkWest Merger and the acquisition of Predecessor, 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 $428 million in 2016 compared to 2015. This variance was due to the MarkWest Merger.

Rental cost of sales increased $46 million in 2016 compared to 2015. This variance was primarily due to the MarkWest Merger.

Purchases-related parties increased $216 million in 2016 compared to 2015. The increase was primarily due to the acquisition of Predecessor and 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 $462 million in 2016 compared to 2015. This variance was primarily due to the depreciation of the fair value of the assets acquired in the MarkWest Merger and the acquisition of Predecessor. During 2017, we expect to record accelerated depreciation related to the decommissioning of a plant in the Houston Complex of approximately $28 million in order to construct an additional 200 mmcf/d processing facility.

Impairment expense increased $130 million in 2016 compared to 2015. This variance was due to a non-cash impairment to goodwill in two reporting units in the G&P segment. See Item 8. Financial Statements and Supplementary Data – Note 18 for more information.

General and administrative expenses increased $102 million in 2016 compared to 2015. The increase was primarily due to the MarkWest Merger and the acquisition of Predecessor, offset by a reduction in expenses due to changes in allocations provided for in the omnibus and employee services agreements with MPC as well as $30 million of acquisition costs incurred in connection with the MarkWest Merger in 2015.

Other taxes increased $35 million in 2016 compared to 2015. The increase was primarily due to property taxes related to the MarkWest Merger.

Interest expense and other financial costs increased $214 million in 2016 compared to 2015. The increase was primarily due to the senior notes assumed as part of the MarkWest Merger.

During 2016 and 2015, MPC did not ship its minimum committed volumes on certain of our pipeline systems. As a result, MPC was obligated to make $56 million and $49 million of deficiency payments in 2016 and 2015, respectively. We record deficiency payments as Deferred revenue-related parties on our Consolidated Balance Sheets. During 2016 and 2015, we recognized revenue of $45 million and $40 million, respectively, related to volume deficiency credits. At December 31, 2016 and 2015, the cumulative balance of Deferred revenue-related parties on our Consolidated Balance Sheets related to volume deficiencies was $47 million and $36 million, respectively. The following table presents the future expiration dates of the associated deferred revenue credits for 2016:



(In millions)
March 31, 2017	$	8
June 30, 2017	10
September 30, 2017	7
December 31, 2017	11
March 31, 2018	2
June 30, 2018	2
September 30, 2018	3
December 31, 2018	4
Total	$	47

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.

2015 Compared to 2014

Service revenue increased $60 million in 2015 compared to 2014. This variance was primarily due to a $63 million increase in the G&P segment from the MarkWest Merger and a $2 million increase resulting from higher average tariffs received on the volumes of crude oil and products shipped, partially offset by a $5 million decrease related to a 13 mbpd reduction in third-party crude oil and products volumes shipped.

Service revenue-related parties increased $39 million in 2015 compared to 2014. This increase was primarily related to the acquisition of Predecessor. This was offset by the reclassification of income from the transportation service agreement entered into by HSM with MPC in 2015. After January 2015, it was considered an operating lease, and therefore, a portion of the revenue was included in rental income-related parties. This was also offset by an agreement entered into by HSM with MPC for the maintenance repair facility which was included in other income in 2015 and a $7 million decrease in revenue related to volume deficiency credits recognized, partially offset by a $32 million increase due to higher average tariffs received on the volumes of crude oil and products shipped.

Rental income increased $20 million in 2015 compared to 2014 related entirely to the MarkWest Merger.

Rental income-related parties increased $131 million in 2015 compared to 2014. This increase was primarily related to the acquisition of Predecessor and a transportation service agreement entered into by HSM with MPC in January 2015. Prior to January 2015, this agreement was not considered an operating lease and the income was included in service revenue-related parties.

Product sales increased $36 million in 2015 compared to 2014. This variance was due to the MarkWest Merger.

Other income and other income-related parties increased a total of $18 million in 2015 compared to 2014. The increase was primarily due to an increase in fees received for operating MPC’s private pipeline systems, a reclassification of fees received from the agreements for the maintenance repair facility and an increase due to the MarkWest Merger, offset by the acquisition of Predecessor.

Cost of revenues increased $19 million in 2015 compared to 2014 primarily due to the acquisition of Predecessor and a decrease in average fuel costs, offset by the MarkWest Merger. The variance was also due to costs associated with rental income from the operating lease entered into in January 2015 which were reclassified to rental cost of sales.

Rental cost of sales increased $10 million in 2015 compared to 2014 primarily due costs associated with rental income which were reclassified from cost of revenues related to the HSM transportation services agreement entered into in January 2015 and the acquisition of Predecessor.

Purchased product costs increased $20 million in 2015 compared to 2014. This variance was due to the MarkWest Merger.

Purchases-related parties increased $19 million in 2015 compared to 2014. The increase was primarily due to higher compensation expenses provided under the omnibus and employee services agreements with MPC and the acquisition of Predecessor, partially offset by increased capitalization of employee costs associated with capital projects.

Depreciation and amortization expense increased $54 million in 2015 compared to 2014 primarily due to the MarkWest Merger and the acquisition of Predecessor.

General and administrative expenses increased $44 million in 2015 compared to 2014. The increase in 2015 was primarily related to $30 million in acquisition costs and the acquisition of Predecessor.

Other taxes increased $5 million in 2015 compared to 2014. The increase was primarily due to property taxes from the MarkWest Merger.

Interest expense and other financial costs increased $42 million in 2015 compared to 2014. The increase was due to borrowings on the bank revolving credit facility, term loan and senior notes in connection with the MarkWest Merger. The increase was also due to $6 million in transaction costs related to the exchange of MarkWest senior notes for MPLX LP senior notes.

SEGMENT REPORTING

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

The tables below present information about segment operating income for the reported segments for the years ended December 31, 2016, 2015 and 2014.

L&S Segment



(In millions)	2016		2015		2014
Revenues and other income:
Segment revenues	$	1,241	$	913	$	747
Segment other income	53		62		46
Total segment revenues and other income	1,294		975		793
Costs and expenses:
Segment cost of revenues	552		416		392
Segment operating income before portion attributable to noncontrolling interest and Predecessor	742		559		401
Segment portion attributable to noncontrolling interest and Predecessor	289		237		188
Segment operating income attributable to MPLX LP	$	453	$	322	$	213

2016 Compared to 2015

Segment revenue increased $328 million primarily due to the acquisition of Predecessor as well as a $14 million increase in higher average tariffs received on the volumes of crude oil and products shipped, $9 million related to increased volumes of crude oil and products shipped, a $6 million increase in storage income and increased HSM equipment revenue, partially offset by a reduction in fees previously paid by HSM on behalf of MPC that are now paid directly by MPC and a $2 million decrease in revenue related to volume deficiency credits recognized.

Segment other income decreased $9 million primarily due to a reduction in fees paid to HSM by MPC.

Segment cost of revenues increased $136 million primarily due to the acquisition of Predecessor offset by 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 maintenance projects.

Segment portion attributable to noncontrolling interest and Predecessor increased primarily due to the acquisition of Predecessor.

2015 Compared to 2014

Segment revenue increased primarily due to the acquisition of Predecessor as well as a $13 million increase in higher average tariffs received on the volumes of crude oil and products shipped, partially offset by a $7 million decrease in revenue related to volume deficiency credits recognized and a decrease due to an agreement entered into by HSM with MPC for the maintenance repair facility which was included in other income in 2015.

Segment other income increased $16 million due to an increase in storage fees, other revenue related to the expansion of the Patoka Tank Farms and an increase from an agreement entered into by HSM with MPC for the maintenance repair facility

which was included in segment revenue prior to 2015 partially offset by the elimination of intercompany activity as a result of the acquisition of Predecessor.

Segment cost of revenues increased $24 million primarily due to the acquisition of Predecessor and higher compensation expenses provided under the omnibus and employee services agreements with MPC, partially offset by a decrease in the average fuel costs and increased capitalization of employee costs associated with capital projects.

Segment portion attributable to noncontrolling interest and Predecessor increased primarily due to the acquisition of Predecessor offset by the acquisition of the remaining interest of Pipe Line Holdings, of which the 0.5 percent was purchased on December 4, 2015.

G&P Segment



(In millions)	2016		2015		2014
Revenues and other income:
Segment revenues	$	2,185	$	150	$	—
Segment other income	1		—		—
Total segment revenues and other income	2,186		150		—
Costs and expenses:
Segment cost of revenues	907		62		—
Segment operating income before portion attributable to noncontrolling interest	1,279		88		—
Segment portion attributable to noncontrolling interest	147		12		—
Segment operating income attributable to MPLX LP	$	1,132	$	76	$	—

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.

Segment Reconciliations

The following tables provide reconciliations of segment operating income to our consolidated income from operations, segment revenue to our consolidated total revenues and other income, and segment portion attributable to noncontrolling interest to our consolidated net income attributable to noncontrolling interests for the years ended December 31, 2016, 2015 and 2014. Adjustments related to unconsolidated affiliates relate to our Partnership-operated non-wholly-owned entities that we consolidate for segment purposes. (Loss) income 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. Other income-related parties consists of operational service fee revenues from our operated unconsolidated affiliates. Unrealized derivative activity is not allocated to segments.



(In millions)	2016			2015			2014
Reconciliation to Income from operations:
L&S segment operating income attributable to MPLX LP	$	453		$	322		$	213
G&P segment operating income attributable to MPLX LP	1,132			76			—
Segment operating income attributable to MPLX LP	1,585			398			213
Segment portion attributable to unconsolidated affiliates	(173		)	(8		)	85
Segment portion attributable to Predecessor	289			236			103
(Loss) income from equity method investments	(74		)	3			—
Other income - related parties	40			2			—
Unrealized derivative (losses) gains⁽¹⁾	(36		)	4			—
Depreciation and amortization	(591		)	(129		)	(75		)
Impairment expense	(130		)	—			—
General and administrative expenses	(227		)	(125		)	(81		)
Income from operations	$	683		$	381		$	245



(In millions)	2016			2015			2014
Reconciliation to Total revenues and other income:
Total segment revenues and other income	$	3,480		$	1,125		$	793
Revenue adjustment from unconsolidated affiliates	(402		)	(28		)	—
(Loss) income from equity method investments	(74		)	3			—
Other income - related parties	40			2			—
Unrealized derivative losses⁽¹⁾	(15		)	(1		)	—
Total revenues and other income	$	3,029		$	1,101		$	793



(in millions)	2016			2015			2014
Reconciliation to Net income attributable to noncontrolling interests and Predecessor:
Segment portion attributable to noncontrolling interest and Predecessor	$	436		$	249		$	188
Portion of noncontrolling interests and Predecessor related to items below segment income from operations	(203		)	(67		)	(70		)
Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates	(32		)	(5		)	—
Net income attributable to noncontrolling interests and Predecessor	$	201		$	177		$	118

(1)

SUPPLEMENTAL MD&A – G&P PRO FORMA

The tables below present financial information, as evaluated by management, for the reported segments for the years ended December 31, 2016, 2015 and 2014. 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, including the removal of approximately $90 million of transaction costs, 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 Item 8. Financial Statements and Supplementary Data – Note 4). Results provided for the year ended December 31, 2016 reflect actual results. 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 Item 8. Financial Statements and Supplementary Data – Note 10).



(In millions)	2016		2015		2014
Revenues and other income:
Segment revenues	$	2,185	$	2,007	$	2,168
Segment other income	1		—		—
Total segment revenues and other income	2,186		2,007		2,168
Costs and expenses:
Segment cost of revenues	907		875		1,197
Segment operating income before portion attributable to noncontrolling interest	1,279		1,132		971
Segment portion attributable to noncontrolling interest	147		121		36
Segment operating income attributable to MPLX LP	$	1,132	$	1,011	$	935

2016 Compared to 2015

Segment revenues and other income increased $179 million in 2016 due to favorable fee revenues from increases in total gathering throughput, total natural gas processed and total C2+ NGLs fractionated volumes of 11 percent, 13 percent and 25 percent, respectively. Volumes increased due to new processing plants in the Marcellus and Southwest areas, additional fractionation capacity in the Marcellus area and increased dry gas gathering in the Utica area. The increased fee revenues were partially offset by lower contributions from commodity derivative settlements.

Segment cost of revenues increased $32 million due to increased operating costs from expanded plant capacities offset by lower product costs due to changes in component mix, lower Marcellus purchases related to inventory, and favorable line fill valuation due to higher liquid pricing.

The change in the segment portion of operating income attributable to noncontrolling interests increased due to ongoing growth in our entities that are not wholly-owned.

2015 Compared to 2014

Segment revenue decreased due to a 39 percent decrease in natural gas prices and a 50 percent decrease in NGL prices over the same period in 2014. There was a $151 million decrease in inventory sold compared to the same period in 2014 due to changes in contractual terms. This decrease was partially offset by an increase in volumes. Total gathering throughput, total natural gas processed and total C2+ NGLs fractionated volumes increased by 28 percent, 36 percent and 30 percent, respectively.

Segment cost of revenues decreased mainly due to a decrease of $152 million in inventory sold compared to the same period in 2014 due to changes in contractual terms and decreases in natural gas purchased prices and NGL prices. Segment cost of revenues as a percentage of segment revenue decreased 13 percent for the year ended December 31, 2015 compared to the same period in 2014. This decrease was primarily due to an increase in fee revenue as a percent of total revenue by 16 percent. The decreases were partially offset by increased expenses related to the expansion of Utica and Marcellus operations.

The change in the segment portion of operating income attributable to noncontrolling interests increased due to ongoing growth in our entities that are not wholly owned.

Reconciliation of Segment Operating Income to Consolidated Income Before Provision 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 years ended December 31, 2016, 2015 and 2014, respectively. The 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.



(In millions)	2016			2015			2014
Pro forma reconciliation to total revenues and other income:
Total G&P segment revenues and other income	$	2,186		$	2,007		$	2,168
Revenue adjustment from unconsolidated affiliates⁽¹⁾	(402		)	(159		)	(41		)
(Loss) income from equity method investments	(74		)	8			(12		)
G&P other income (loss) - related parties	40			(4		)	19
Unrealized derivative (losses) gains related to revenue⁽²⁾	(15		)	(10		)	25
Total pro forma G&P revenues and other income	1,735			1,842			2,159
Total pro forma L&S revenues and other income	1,294			975			813
Total pro forma revenues and other income	$	3,029		$	2,817		$	2,972



(In millions)	2016			2015			2014
Pro forma reconciliation to pro forma net income attributable to MPLX LP:
L&S segment operating income attributable to MPLX LP	$	453		$	322		$	266
G&P segment operating income attributable to MPLX LP	1,132			76			—
Pro forma G&P segment operating income attributable to MPLX LP	—			935			935
Segment portion attributable to unconsolidated affiliates⁽¹⁾	(173		)	20			13
Segment portion attributable to Predecessor	289			236			103
(Loss) income from equity method investments	(74		)	8			(12		)
Other income (loss) - related parties	40			(5		)	19
Unrealized derivative (losses) gains⁽²⁾	(36		)	(10		)	82
Depreciation and amortization	(591		)	(588		)	(481		)
Impairment expense	(130		)	(26		)	(62		)
General and administrative expenses	(227		)	(216		)	(130		)
Pro forma income from operations	683			752			733
Related party interest and other financial costs	1			—			—
Debt retirement expense	—			118			—
Net interest and other financial costs	260			258			189
Pro forma income before income taxes	422			376			544
(Benefit) provision for income taxes	(12		)	(10		)	46
Pro forma net income	434			386			498
Less: Net income attributable to noncontrolling interests and Predecessor	201			139			169
Pro forma net income attributable to MPLX LP	$	233		$	247		$	329


(1)	The Partnership consolidated the Utica Operations until December 4, 2015 at which point these were accounted for as unconsolidated affiliates.

(2)



Pro Forma Operating Statistics	2016		2015		2014
Gathering Throughput (mmcf/d)
Xxxxxxxxx Operations	910		858		668
Utica Operations⁽¹⁾	932		673		289
Southwest Operations⁽²⁾	1,433		1,413		1,336
Total gathering throughput	3,275		2,944		2,293

Natural Gas Processed (mmcf/d)
Marcellus Operations	3,210		2,861		2,064
Utica Operations⁽¹⁾	1,072		883		416
Southwest Operations	1,226		1,077		991
Southern Appalachian Operations	253		267		280
Total natural gas processed	5,761		5,088		3,751

C2 + NGLs Fractionated (mbpd)
Xxxxxxxxx Operations⁽³⁾	260		194		147
Utica Operations⁽¹⁾⁽³⁾	42		40		19
Southwest Operations	18		18		21
Southern Appalachian Operations⁽⁴⁾	15		15		19
Total C2 + NGLs fractionated⁽⁵⁾	335		267		206

Pricing Information
Natural Gas NYMEX HH ($/MMBtu)	$	2.55	$	2.63	$	4.28
C2 + NGL Pricing/gallon⁽⁶⁾	$	0.47	$	0.46	$	0.92


(1)	Utica was a consolidated equity method investment prior to December 4, 2015. After this date, it became an unconsolidated equity method investment but is consolidated for segment purposes only.


(2)	Includes approximately 309 mmcf/d, 242 mmcf/d and 228 mmcf/d related to unconsolidated equity method investments, Xxxxx and MarkWest Pioneer, for the years ended December 31, 2016, 2015 and 2014, respectively.

(3)


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


(5)	Purity ethane makes up approximately 128 mbpd, 79 mbpd and 67 mbpd of total fractionated products for the years ended December 31, 2016, 2015 and 2014, 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.

LIQUIDITY AND CAPITAL RESOURCES

Cash Flows

Our cash and cash equivalents balance was $234 million at December 31, 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 for the past three years were as follows:



(In millions)	2016			2015			2014
Net cash provided by (used in):
Operating activities	$	1,491		$	427		$	334
Investing activities	(1,413		)	(1,686		)	(137		)
Financing activities	113			1,275			(224		)
Total	$	191		$	16		$	(27	)

Cash Flows Provided by Operating Activities. Net cash provided by operating activities increased $1,064 million in 2016 compared to 2015, primarily due to increased operating results as result of the MarkWest Merger and the acquisition of MPLXT, as it was not a business prior to April 1, 2016, as well as favorable changes in working capital of approximately $129 million compared to 2015.

For 2016, changes in working capital were a net $66 million source of cash. Accounts payable and accrued liabilities increased $102 million from year-end 2015 due mainly to an increase in our product and freight accruals as a result of higher NGL prices as well as timing related to general operating payables. Current receivables increased $52 million primarily due to higher NGL prices and volumes as compared to 2015, and there was an increase in the liability positions of our derivatives due to changes in the fair value of $43 million that were primarily due to increases in commodity prices during 2016 and an increase of $19 million in receivables from related parties due primarily to the acquisition of Predecessor.

For 2015, changes in working capital were a net $63 million use of cash. Current receivables increased $29 million primarily due to higher third-party tariff revenue receivables. Net receivables to related parties increased $34 million due to timing of receivables from related parties, as well as the acquisition of Predecessor.

For 2014, changes in working capital were a net $19 million source of cash, primarily due to an increase in net liabilities to related parties and a decrease in current receivables. Net liabilities to related parties increased $15 million, primarily due to an increase in payables to related parties under the omnibus and employee services agreements and a decrease in receivables from related parties.

Cash Flows Used in Investing Activities. Net cash used in investing activities decreased $273 million in 2016 compared to 2015, primarily due to a $979 million use of cash for additions to property, plant and equipment and a $73 million use of cash for investments in unconsolidated affiliates, offset by a $1.2 billion decrease in acquisitions due to the MarkWest Merger and $101 million source of cash from investment loans between HSM and the Predecessor prior to the HSM acquisition.

Net cash used in investing activities increased $1.5 billion in 2015 compared to 2014, primarily due to a $1.2 billion increase in acquisitions due to the MarkWest Merger and a $193 million increase in additions to property, plant and equipment.

Net cash used in investing activities in 2014 was primarily used for additions to property, plant, and equipment.

Cash Flows from Financing Activities. Net cash provided by financing activities in 2016 was $113 million compared to $1.3 billion in 2015. The sources of cash in 2016 primarily consisted of $984 million in net proceeds from the issuance of Preferred units and $792 million of net cash proceeds from the issuance of common units and general partner units, as well as contributions of $225 million from MPC as part of the Class A Reorganization. The uses of cash in 2016 primarily consisted of net repayments of long-term debt and distributions to unitholders.

The sources of cash in 2015 primarily consisted of contributions of $1.2 billion from MPC for the MarkWest Merger and proceeds of $169 million from issuances of general partner units. The uses of cash in 2015 primarily consisted of distributions to unitholders.

The sources of cash in 2014 primarily consisted of net long-term borrowings and proceeds from the issuance of common units. The uses of cash in 2014 primarily consisted of distributions of $910 million to MPC for the acquisition of an interest in Pipe Line Holdings, as well as distributions to unitholders.

Cash used in distributions to unitholders totaled $845 million in 2016, $158 million in 2015, and $103 million in 2014. The increase in 2016 was primarily due to the issuance of units to MarkWest unitholders in connection with the merger on December 4, 2015.

Long-term debt borrowings and repayments were a net $878 million use of cash in 2016 compared to a $38 million source of cash in 2015 and a $631 million source of cash in 2014. During 2016, we used proceeds from the issuance of Preferred units to repay amounts outstanding under the bank revolving credit facility. During 2015, we used proceeds from the issuance of $500 million aggregate of principal amount of senior notes to repay $385 million outstanding under the bank revolving credit facility. See Item 8. Financial Statements and Supplemental Data – Note 17 for additional information on our long-term debt.

Debt and Liquidity Overview

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



	December 31,
(In millions)	2016			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⁾	(428		)	(472		)
Amounts due within one year	(1		)	(1		)
Total long-term debt due after one year	$	4,422		$	5,255


(1)	Includes $420 million and $464 million discount as of December 31, 2016 and 2015, respectively, related to the difference between the fair value and the principal amount of the assumed MarkWest debt.

On November 20, 2014, MPLX LP entered into a credit agreement with a syndicate of lenders (“MPLX Credit Agreement”) which provides for a five-year, $1 billion bank revolving credit facility and a $250 million term loan facility. In connection with the closing of the MarkWest Merger, we amended our MPLX Credit Agreement to, among other things, increase the aggregate amount of revolving credit capacity under the credit agreement by $1 billion, for total aggregate commitments of $2 billion, and to extend the maturity of the revolving credit facility to December 4, 2020. The term loan facility was not amended and matures on November 20, 2019. Also in connection with the closing of the MarkWest Merger, MarkWest’s bank revolving credit facility was terminated and the approximately $943 million outstanding under MarkWest’s bank revolving credit facility was repaid with $850 million of borrowings under MPLX LP’s bank revolving credit facility and $93 million of cash. We incurred approximately $2 million of costs related to the borrowing on the bank revolving credit facility.

The bank revolving credit facility includes letter of credit issuing capacity of up to $250 million and swingline capacity of up to $100 million. The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional $500 million, subject to certain conditions, including the consent of lenders whose commitments would increase. In addition, the maturity date may be extended from time-to-time during its term to a date that is one year after the then-effective maturity subject to the approval of lenders holding the majority of the commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the then-effective maturity date. During 2016, we borrowed $434 million under the bank revolving credit facility, at an average interest rate of 1.9 percent, and repaid $1.3 billion under the bank

revolving credit facility. At December 31, 2016, we had no borrowings and $3 million in letters of credit outstanding under this facility, resulting in total unused loan availability of $2.0 billion, or 99.9 percent of the borrowing capacity.

The term loan facility was drawn in full on November 20, 2014. The maturity date for the term loan facility may be extended for up to two additional one-year periods subject to the consent of the lenders holding a majority of the outstanding term loan borrowings, provided that the portion of the term loan borrowings held by any non-consenting lenders will continue to be due and payable on the then-effective maturity date. The borrowings under this facility during 2016 were at an average interest rate of 1.954 percent.

Borrowings under the MPLX Credit Agreement bear interest at either the Adjusted LIBOR or the Alternate Base Rate (as defined in the MPLX Credit Agreement), at our election, plus a specified margin. We are charged various fees and expenses in connection with the agreement, including administrative agent fees, commitment fees on the unused portion of the bank revolving credit facility and fees with respect to issued and outstanding letters of credit. The applicable margins to the benchmark interest rates and certain of the fees fluctuate based on the credit ratings in effect from time to time on our long-term debt.

The MPLX Credit Agreement includes certain representations and warranties, affirmative and negative covenants and events of default that we consider usual and customary for an agreement of that type and that could, among other things, limit our ability to pay distributions to our unitholders. The financial covenant requires us to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA (both as defined in the MPLX Credit Agreement) for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 for up to two fiscal quarters following certain acquisitions). Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period. Other covenants restrict us and certain of our subsidiaries from incurring debt, creating liens on our assets and entering into transactions with affiliates. As of December 31, 2016, we were in compliance with this financial covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of 3.26 to 1.0, as well as all other covenants contained in the MPLX Credit Agreement.

As of December 31, 2016, we had five series of senior notes outstanding: $750 million in aggregate principal amount on the senior notes issued in August 2012 and due February 2023; $1.0 billion aggregate principal amount on senior notes issued in January 2013 and due July 2023; $1.2 billion aggregate principal amount on senior notes issued in November 2014 and due in December 2024; $500 million aggregate principal amount on senior notes issued in February 2015 and due February 2025; and $1.2 billion aggregate principal amount on senior notes issued in June 2015 and due in June 2025 (altogether the “Senior Notes Outstanding”). As of December 31, 2016, there were no minimum principal payments on the Senior Notes Outstanding due during the next five years. For further discussion of the Senior Notes Outstanding and other debt related information, see Item 8. Financial Statements and Supplementary Data – Note 17.

On February 10, 2017, the Partnership completed a public offering of $1.25 billion aggregate principal amount of 4.125 percent unsecured senior notes due March 2027 (the “2027 Senior Notes”) and $1.0 billion aggregate principal amount of 5.200 percent unsecured senior notes due March 2047 (the “2047 Senior Notes” and, collectively with the 2027 Senior Notes, the “New Senior Notes”). The 2027 Senior Notes and the 2047 Senior Notes were offered at a price to the public of 99.834 percent and 99.304 percent of par, respectively. The Partnership intends to use the net proceeds from this offering for general partnership purposes, which may include, from time to time, acquisitions (including the previously announced planned dropdown of assets from MPC, the acquisition of the Ozark pipeline, and the acquisition of a partial, indirect equity interest in the Xxxxxx Pipeline system) and capital expenditures.

Our intention is to maintain an investment grade credit profile. As of January 31, 2017, we had the following credit rating grade levels.



Rating Agency		Rating
Fitch		BBB- (stable outlook)
Xxxxx’x		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.

Our liquidity totaled $2.7 billion at December 31, 2016, consisting of:



	December 31, 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	$	2,500	$	(3	)	$	2,497
Cash and cash equivalents						234
Total liquidity						$	2,731


(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, acquisitions, contractual obligations, repayment of debt maturities and quarterly cash distributions. MPC manages our cash and cash equivalents on our behalf directly with third-party institutions as part of the treasury services that it provides to us under our omnibus agreement. From time to time, we may also consider utilizing other sources of liquidity, including the formation of joint ventures or sales of non-strategic assets.

Equity and Preferred Units Overview

The table below summarizes the changes in the number of units outstanding through December 31, 2016:



(In units)	Common	Class B		Subordinated		General Partner		Total
Balance at December 31, 2013	36,951,515	—		36,951,515		1,508,225		75,411,255
Unit-based compensation awards	15,479	—		—		316		15,795
Contribution of interest in Pipe Line Holdings	2,924,104	—		—		59,676		2,983,780
December 2014 equity offering	3,450,000	—		—		70,408		3,520,408
Balance at December 31, 2014	43,341,098	—		36,951,515		1,638,625		81,931,238
Unit-based compensation awards	18,932	—		—		386		19,318
Issuance of units under the ATM program	25,166	—		—		514		25,680
Subordinated unit conversion	36,951,515	—		(36,951,515	)	—		—
MarkWest Merger	216,350,465	7,981,756		—		5,160,950		229,493,171
Balance at December 31, 2015	296,687,176	7,981,756		—		6,800,475		311,469,407
Unit-based compensation awards	120,989	—		—		2,470		123,459
Issuance of units under the ATM Program	26,347,887	—		—		537,710		26,885,597
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 December 31, 2016	357,193,288	3,990,878		—		7,371,105		368,555,271

For more details on equity activity, see Item 8. Financial Statements and Supplementary Data – Notes 8 and 9.

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.

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. Distributions paid to Preferred unit holders for the year ended December 31, 2016 was $25 million.

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 also received 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 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 year ended December 31, 2016, the sale of common units under the ATM Program generated net proceeds of approximately $776 million.

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 Item 8. Financial Statements and Supplementary Data – Notes 8 and 12.

We intend to pay a minimum quarterly distribution of $0.2625 per unit, which equates to $96 million per quarter, or $384 million per year, based on the number of common and general partner units. On January 25, 2017, we announced that the board of directors of our general partner had declared a distribution of $0.5200 per unit that was paid on February 14, 2017 to unitholders of record on February 6, 2017. This represents a four percent increase over the fourth quarter 2015 distribution. On February 1, 2017, we announced distribution growth guidance of 12 to 15 percent for 2017. This increase in the distribution is consistent with our intent to maintain an attractive distribution growth profile over the long term. 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 common unit.

The allocation of total quarterly cash distributions to general and limited partners is as follows for the years ended December 31, 2016, 2015 and 2014. 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.



(In millions)	2016		2015		2014
Distribution declared:
Limited partner units - public	$	533	$	151	$	29
Limited partner units - MPC	159		104		77
General partner units - MPC	18		6		2
Incentive distribution rights - MPC	187		54		4
Total GP & LP distribution declared	897		315		112
Redeemable preferred units	41		—		—
Total distribution declared	$	938	$	315	$	112

Cash distributions declared per limited partner common unit:
Quarter ended March 31	$	0.5050	$	0.4100	$	0.3275
Quarter ended June 30	0.5100		0.4400		0.3425
Quarter ended September 30	0.5150		0.4700		0.3575
Quarter ended December 31	0.5200		0.5000		0.3825
Year ended December 31	$	2.0500	$	1.8200	$	1.4100

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 the Partnership.

Our capital expenditures for the past three years are shown in the table below:



(In millions)	2016			2015		2014
Capital expenditures:
Maintenance	$	84		$	51	$	30
Expansion	1,213			311		124
Total capital expenditures	1,297			362		154
Less: (Decrease) increase in capital accruals	(22		)	27		11
Asset retirement expenditures	6			1		2
Additions to property, plant and equipment	1,313			334		141
Capital expenditures of unconsolidated subsidiaries⁽¹⁾	131			24		—
Total gross capital expenditures	1,444			358		141
Less: Joint venture partner contributions⁽²⁾	64			8		—
Total capital expenditures, net	1,380			350		141
Less: Maintenance capital	88			51		30
Total growth capital	1,292			299		111
Acquisition, net of cash acquired	—			1,218		—
Total growth capital and acquisition	$	1,292		$	1,517	$	111


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


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

Our growth capital plan range for 2017 is $1.4 billion to $1.7 billion, not including the entities acquired on March 1, 2017 or the dropdowns or acquisitions previously discussed in Item 1. Business – Competitive Strengths, or their respective subsequent capital spending. The G&P segment capital plan includes investments that are expected to support producer customers. The L&S segment capital plan includes the development of various crude oil and refined petroleum products infrastructure projects, including a build out of Utica Shale infrastructure in connection with the recently completed Cornerstone Pipeline, a butane cavern and a tank farm expansion. We also have large organic growth prospects associated with the anticipated growth of MPC’s operations and third-party activity in our areas of operation that we anticipate will provide attractive returns and cash flows. We continuously evaluate our capital plan and make changes as conditions warrant.

We have revised our timeline for completion of certain capital projects that are classified as construction-in-progress within Property, plant and equipment, net in the accompanying Consolidated Balance Sheets. The expected completion dates of these projects have been updated to more closely align with the expected timing of utilization by their respective producer customers as part of the just-in-time component of our capital program. We continue to believe all amounts capitalized will be recoverable as we expect these projects to be completed.

Other Capital Requirements and Strategic Actions

On January 3, 2017, MPC announced plans to significantly accelerate the dropdown of assets with an estimated $1.4 billion of MLP-eligible annual EBITDA to MPLX LP now expected to be completed in 2017, subject to requisite approvals and regulatory clearances, including tax, and market and other conditions. We expect these dropdowns to be valued consistent with recent industry precedent valuation multiples ranging between 7.0x and 9.0x EBITDA, subject to the MPLX LP conflicts committee review process and receipt of customary fairness opinions. We also expect the Partnership to finance the dropdown transactions with debt and equity in approximately equal proportions in the aggregate for all planned dropdown of assets. The equity financing is expected to be funded through MPLX LP common units issued to MPC. In conjunction with the completion of the dropdowns, MPC also expects to exchange its economic interests in our general partner, including incentive distribution rights, for newly issued MPLX LP common units. MPC would continue to retain control of the general partner following this exchange. The acquisition of HST, WHC and MPLXT, completed on March 1, 2017, was the first step in implementing the planned dropdowns and represents $250 million of the estimated $1.4 billion of EBITDA available for dropdown.

On February 6, 2017, we announced the formation of a strategic joint venture to support the development of Antero Resources extensive rich-gas position in the Marcellus Shale. The 50-50 joint venture with Antero Midstream will include the ongoing development of incremental gas processing, including three additional processing plants at the Sherwood Complex in West Virginia by the first quarter of 2018 and the ownership of 20,000 bpd of the newly constructed Hopedale III fractionation train

and an option to invest in additional fractionation expansions at the Hopedale Complex in Ohio, subject to the production of incremental NGLs from the joint venture’s processing facilities. In connection with this transaction, the Partnership contributed approximately $134 million of assets currently under construction at the Sherwood Complex and Antero Midstream made an initial capital contribution of approximately $155 million.

On February 13, 2017, we also announced the acquisition of Ozark pipeline from Enbridge Ozark for approximately $220 million. The Ozark pipeline is a 433-mile, 22-inch crude oil pipeline originating in Cushing, Oklahoma and terminating in Wood River, Illinois, capable of transporting approximately 230,000 barrels per day. This purchase transaction is expected to close in the first quarter of 2017 and will be funded with cash on hand.

On February 15, 2017, we also acquired a joint venture interest in the Xxxxxx Pipeline system from ETP and SXL. MPLX LP contributed $500 million of the $2 billion purchase price. The Xxxxxx Pipeline system is currently expected to deliver in excess of 470,000 barrels per day of crude oil from the Xxxxxx/ Three Forks production area in North Dakota to the Midwest through Patoka, Illinois and ultimately to the Gulf Coast. MPLX LP funded this acquisition with cash on hand.

Contractual Cash Obligations

The table below provides aggregated information on our consolidated obligations to make future payments under existing contracts as of December 31, 2016:



(In millions)	Total		2017		2018-2019		2020-2021		Later Years
Bank revolving credit facility⁽¹⁾	$	16	$	4	$	8	$	4	$	—
Term loan⁽¹⁾	267		6		261		—		—
Long-term debt⁽¹⁾	6,300		221		442		442		5,195
Capital lease obligations	9		1		3		5		—
Operating lease and long-term storage agreements⁽²⁾	302		61		93		72		76
Purchase obligations:
Contracts to acquire property, plant & equipment	588		556		32		—		—
Other contracts	42		38		1		1		2
Total purchase obligations⁽³⁾	630		594		33		1		2
Natural gas purchase obligations⁽⁴⁾	103		19		34		33		17
SMR liability⁽⁵⁾	228		17		34		34		143
Transportation and terminalling⁽⁶⁾	608		46		123		122		317
Other long-term liabilities reflected on the Consolidated Balance Sheets:
Other liabilities⁽⁷⁾	26		26		—		—		—
AROs⁽⁸⁾	25		—		—		—		25
Total contractual cash obligations	$	8,514	$	995	$	1,031	$	713	$	5,775


(1)	Amounts represent outstanding borrowings at December 31, 2016, plus any commitment and administrative fees and interest.


(2)	Amounts relate primarily to a long-term propane storage agreement and our office and vehicle leases.

(3)

Represents purchase orders and contracts related to the purchase or build out of property, plant and equipment. Purchase obligations exclude current and long-term unrealized losses on derivative instruments included on the accompanying Consolidated Balance Sheets, which represent the current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts are generally settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the underlying commodity.

(4)

Natural gas purchase obligations consist primarily of a purchase agreement with a producer in our Southern Appalachia Operations. The contract provides for the purchase of keep-whole volumes at a specific price and is a component of a broader regional arrangement. The contract price is designed to share a portion of the frac spread with the producer and as a result, the amounts reflected for the obligation exceed the cost of purchasing the keep-whole volumes at a market price. The contract is considered an embedded derivative (see Item 8. Financial Statements and Supplementary Data – Note 16

for the fair value of the frac spread sharing component). We use the estimated future frac spreads as of December 31, 2016 for calculating this obligation. The counterparty to the contract has the option to renew the gas purchase agreement and the related keep-whole processing agreement for two successive five-year terms after 2022, which is not included in the natural gas purchase obligations line item.


(5)	Represents amounts due under a product supply agreement (see Item 8. Financial Statements and Supplementary Data – Note 23 for further discussion of the product supply agreement).


(6)	Represents transportation and terminalling agreements that obligate us to minimum volume, throughput or payment commitments over the terms of the agreements, which will range from three to ten years. We expect to pass any minimum payment commitments through to producer customers. Minimum fees due under transportation agreements do not include potential fee increases as required by FERC.


(7)	Includes the payable for Class B units recorded in connection with the MarkWest Merger (see Item 8. Financial Statements and Supplementary Data – Note 4 for further discussion).


(8)	Excludes estimated accretion expense of $29 million. The total amount to be paid is approximately $54 million.

In addition to the obligations included in the table above, we have an omnibus agreement and employee services agreements with MPC. The omnibus agreement with MPC addresses our payment of a fixed annual fee to MPC for the provision of executive management services by certain executive officers of our general partner and our reimbursement to MPC for the provision of certain general and administrative services to us. The omnibus agreement remains in full force and effect as long as MPC controls our general partner. Under the omnibus agreement, we pay to MPC in equal monthly installments an annual amount of approximately $51 million in 2016 for the provision of services by MPC, such as information technology, engineering, legal, accounting, treasury, human resources and other administrative services. The annual amount includes a fixed annual fee of approximately $12 million for the provision of certain executive management services by certain officers of our general partner.

We also pay MPC additional amounts based on the costs actually incurred by MPC in providing other services, except for the portion of the amount attributable to engineering services, which is based on the amounts actually incurred by MPC and its affiliates plus six percent of such costs. In addition, we are obligated to reimburse MPC for any out-of-pocket costs and expenses incurred by MPC on our behalf.

We have five employee services agreements with MPC. Two of the employee services agreements with MPC were entered into effective October 1, 2012, under which we agreed to reimburse MPC for the provision of certain operational and management services to us in support of our pipelines, barge dock, butane cavern and tank farms within the L&S segment. Effective December 28, 2015, we entered into an additional employee services agreement with MPC, which requires that we reimburse MPC for certain operational and management services to us in support of our G&P segment and certain of our other operations. We have another employee services agreement with MPC dated as of January 1, 2015, assumed by us in connection with the HSM acquisition, pursuant to which HSM reimburses MPC for employee benefit expenses along with certain operation and management services provided in support of HSM’s areas of operation. The agreement is effective until December 31, 2019. Lastly, we have an employee services agreement with MPC dated as of December 21, 2015, assumed by us in connection with the MPLXT acquisition, pursuant to which MPLXT reimburses MPC for employee benefit expenses along with certain operational and management services provided in support of the operations of MPLXT. We incurred $449 million of expenses under the employee services agreements for 2016.

Off-Balance Sheet Arrangements

As of December 31, 2016, we have not entered into any transactions, agreements or other arrangements that would result in off-balance sheet liabilities.

Forward-looking Statements

Our opinions concerning liquidity and capital resources and our ability to avail ourselves in the future of the financing options mentioned in the above forward-looking statements are based on currently available information. If this information proves to be inaccurate, future availability of financing may be adversely affected. Factors that affect the availability of financing include our performance (as measured by various factors, including cash provided by operating activities), the state of worldwide debt and equity markets, investor perceptions and expectations of past and future performance, the global financial climate, and, in particular, with respect to borrowings, the levels of our outstanding debt and future credit ratings by rating agencies. The discussion of liquidity and capital resources above also contains forward-looking statements regarding expected capital spending. The forward-looking statements about our capital budget are based on current expectations, estimates and projections and are not guarantees of future performance. Actual results may differ materially from these expectations, estimates and projections and are subject to certain risks, uncertainties and other factors, some of which are beyond our control and are

difficult to predict. Some factors that could cause actual results to differ materially include negative capital market conditions, including a persistence or increase of the current yield on common units, which is higher than historical yields, adversely affecting the Partnership’s ability to meet its distribution growth guidance; the time, costs and ability to obtain regulatory or other approvals and consents and otherwise consummate the strategic initiatives discussed herein and other proposed transactions; the satisfaction or waiver of conditions in the agreements governing the strategic initiatives discussed herein and other proposed transactions; our ability to achieve the strategic and other objectives related to the strategic initiatives and transactions discussed herein, including the dropdowns proposed by MPC, the joint venture with Antero Midstream Partners LP, the Ozark pipeline, and other proposed transactions; adverse changes in laws including with respect to tax and regulatory matters; inability to agree with respect to the timing of and value attributed to assets identified for dropdown; the adequacy of the Partnership’s capital resources and liquidity, including, but not limited to, availability of sufficient cash flow to pay distributions, and the ability to successfully execute its business plans and growth strategy; continued/further volatility in and/or degradation of market and industry conditions; changes to the expected construction costs and timing of projects; completion of midstream infrastructure by competitors; disruptions due to equipment interruption or failure, including electrical shortages and power grid failures; the suspension, reduction or termination of MPC's obligations under the Partnership’s commercial agreements; modifications to earnings and distribution growth objectives; the level of support from MPC, including dropdowns, alternative financing arrangements, taking equity units, and other methods of sponsor support, as a result of the capital allocation needs of the enterprise as a whole and its ability to provide support on commercially reasonable terms; compliance with federal and state environmental, economic, health and safety, energy and other policies and regulations and/or enforcement actions initiated thereunder; changes to the Partnership’s capital budget; prices of and demand for natural gas, NGLs, crude oil and refined products, delays in obtaining necessary third-party approvals and governmental permits, changes in labor, material and equipment costs and availability, planned and unplanned outages, the delay of, cancellation of or failure to implement planned capital projects, project overruns, disruptions or interruptions of our operations due to the shortage of skilled labor 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. For additional information on forward-looking statements and risks that can affect our business, see “Disclosures Regarding Forward-Looking Statements” and Item 1A. Risk Factors in this Annual Report on Form 10-K.

Effects of Inflation

Inflation did not have a material impact on our results of operations for the years ended December 31, 2016, 2015 or 2014. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire, build or replace property, plant and equipment. It may also increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and expect to continue to pass along all or a portion of increased costs to our customers in the form of higher fees.

TRANSACTIONS WITH RELATED PARTIES

MPC owns our general partner and an approximate 23.5 percent limited partner interest (including the Class B units on an as-converted basis) in us as of February 13, 2017 and all of our incentive distribution rights.

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 41 percent, 82 percent and 90 percent of our total revenues and other income for 2016, 2015 and 2014, 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, 34 percent and 41 percent for 2016, 2015 and 2014, respectively. MPC performed certain services for us related to information technology, engineering, legal, accounting, treasury, human resources and other administrative services.

We believe that transactions with related parties were conducted under terms comparable to those with unrelated parties. For further discussion of agreements and activity with MPC and related parties see Item 1. Business – Our Transportation and Storage Services Agreements with MPC, – Operating and Management Services Agreements with MPC and Third Parties, – Other Agreements with MPC and Item 8. Financial Statements and Supplementary Data – Note 6.

ENVIRONMENTAL MATTERS AND COMPLIANCE COSTS

We are subject to extensive federal, state and local environmental laws and regulations. These laws, which change frequently, regulate the discharge of materials into the environment or otherwise relate to protection of the environment. Compliance with these laws and regulations may require us to remediate environmental damage from any discharge of hazardous, petroleum or chemical substances from our facilities or require us to install additional pollution control equipment on our equipment and facilities. Our failure to comply with these or any other environmental or safety-related regulations could result in the assessment of administrative, civil or criminal penalties, the imposition of investigatory and remedial liabilities, and the issuance of injunctions that may subject us to additional operational constraints.

Future expenditures may be required to comply with the Clean Air Act and other federal, state and local requirements for our various facilities. The impact of these legislative and regulatory developments, if enacted or adopted, could result in increased compliance costs and additional operating restrictions on our business, each of which could have an adverse impact on our financial position, results of operations and liquidity. MPC will indemnify us for certain of these costs under the omnibus agreement.

If these expenditures, as with all costs, are not ultimately reflected in the fees and tariff rates we receive for our 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. Our environmental expenditures for each of the past three years were:



(In millions)	2016			2015			2014
Capital	$	10		$	5		$	2
Percent of total capital expenditures	1		%	1		%	3		%
Compliance:
Operating and maintenance	$	102		$	25		$	22
Remediation⁽¹⁾	5			7			2
Total	$	107		$	32		$	24


(1)	These amounts include spending charged against remediation reserves, where permissible, but exclude non-cash accruals for environmental remediation.

We accrue for environmental remediation activities when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. As environmental remediation matters proceed toward ultimate resolution or as additional remediation obligations arise, charges in excess of those previously accrued may be required.

New or expanded environmental requirements, which could increase our environmental costs, may arise in the future. We believe we comply with all legal requirements regarding the environment, but since not all of them are fixed or presently determinable (even under existing legislation) and may be affected by future legislation or regulations, it is not possible to predict all of the ultimate costs of compliance, including remediation costs that may be incurred and penalties that may be imposed.

Our environmental capital expenditures are expected to approximate $5 million in 2017. Actual expenditures may vary as the number and scope of environmental projects are revised as a result of improved technology or changes in regulatory requirements and could increase if additional projects are identified or additional requirements are imposed. The amount of expenditures in 2017 is also dependent upon the resolution of the matters described in Item 3 – Legal Proceedings, which may require us to complete additional projects and increase our actual environmental capital and operating expenditures.

CRITICAL ACCOUNTING ESTIMATES

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Accounting estimates are considered to be critical if (1) the nature of the estimates and assumptions is material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and (2) the impact of the estimates and assumptions on financial condition or operating performance is material. Actual results could differ from the estimates and assumptions used.

The policies and estimates discussed below are considered by management to be critical to an understanding of our financial statements because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See Item 8 Financial Statements and Supplementary Data – Note 2 for additional information on these policies and estimates, as well as a discussion of additional accounting policies and estimates.



Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Acquisitions
In accounting for business combinations, acquired assets and liabilities, noncontrolling interests, if any, and contingent consideration are recorded based on estimated fair values as of the date of acquisition. Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. There are three approaches for measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence. Valuation techniques that maximize the use of observable inputs are favored. The excess or shortfall of the purchase price when compared to the fair value of the net tangible and identifiable intangible assets acquired, if any, and noncontrolling interests, if any, is recorded as goodwill or a bargain purchase gain, respectively. A significant amount of judgment is involved in estimating the individual fair values of property, plant and equipment, intangible assets, equity method investments, contingent consideration, other assets and liabilities and noncontrolling interests. We use all available information to make these fair value determinations and, for certain acquisitions, engage third-party consultants for assistance. We adjust the preliminary purchase price allocation, as necessary, after the acquisition closing date through the end of the measurement period of up to one year as we finalize valuations for the assets acquired, liabilities assumed, and noncontrolling interest, if any.	The fair value of assets, liabilities, including contingent consideration, and noncontrolling interests as of the acquisition date are often estimated using a combination of approaches, including the income approach, which requires us to project related future cash inflows and outflows and apply an appropriate discount rate; the cost approach, which requires estimates of replacement costs and useful life and obsolescence estimates; and the market approach which uses market data and adjusts for entity-specific differences. Additionally, for customer contract intangibles we must estimate the expected life of the relationship with our customers on a reporting unit basis. The estimates used in determining fair values are based on assumptions believed to be reasonable but which are inherently uncertain. Accordingly, actual results may differ from the projected results used to determine fair value.	If estimates or assumptions used to complete the purchase price allocation and estimate the fair value of acquired assets, liabilities and noncontrolling interests significantly differed from assumptions made, the allocation of purchase price between goodwill, intangibles, noncontrolling interests, equity method investments and property plant and equipment could significantly differ. Such a difference would impact future earnings through depreciation and amortization expense. In addition, if forecasts supporting the valuation of the intangibles or goodwill are not achieved, impairments could arise. Further, if customer relationships terminate prior to the expected useful life, we will be required to record a charge to operations to write-off any remaining unamortized balance of the intangible asset assigned to that customer. See Item 8. Financial Statements and Supplementary Data – Note 4 for additional information on the MarkWest Merger. That acquisition was completed effective December 4, 2015.



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 a reporting unit 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, 2016, there were no indicators of impairment for any of our long-lived assets.



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 as of November 30, 2016. We 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 2016 impairment analysis. This type of analysis requires 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. For the 2016 qualitative analysis, we analyzed the changes in the assumptions above in light of current economic conditions to determine if it was more likely than not that impairment exists. We looked at factors, including changes in the forecasted operating income and volumes for the three reporting units with goodwill, changes in the commodity price environment, changes in our per unit market value, changes in our peers’ market value and changes in industry EBITDA multiples. 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.	The Partnership recorded approximately $130 million of impairment expense related to charges recorded during the first and second quarters of the fiscal year. We recorded no impairment charge related to our annual impairment review of goodwill as of November 30, 2016. The fair value of the reporting units for our 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 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 7.8 percent to 14.5 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 impairment tests will prove to be an accurate prediction of the future. As of December 31, 2016, the Partnership had six reporting units with goodwill: Xxxxxxxxx ($1.8 billion), East Texas ($228 million), West Texas ($41 million), HSM ($11 million), MPL ($132 million) and MPLXT ($21 million). Step 1 of the fourth quarter impairment analysis resulted in the fair value of the reporting units exceeding their carrying value by approximately 28 percent, 8 percent, 44 percent, 303 percent and 167 percent, respectively. An increase of 0.50 percent to the discount rate used to estimate the fair value of the reporting units would not have resulted in a goodwill impairment charge as of December 31, 2016. Our fourth quarter analysis resulted in a significant increase in the fair value of the reporting units as compared to the interim analyses performed during 2016. This increase was generally supported by an increase in our market capitalization of approximately 49 percent. Significant assumptions used to estimate the reporting units’ 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 the reporting units were to decline, the overall reporting units’ fair value would decrease, resulting in potential goodwill impairment charges. Additionally, an increase in the cost of capital would result in a decrease in the fair value of the reporting units, causing their value to decline and goodwill to potentially be impaired.



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 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.	A fixed asset impairment analysis was performed during the second quarter for Ohio Condensate Company (OCC) resulting in an impairment charge of $96 million within OCC’s financial statements. Approximately $58 million of the charge was attributable to the Partnership based on its 60 percent ownership of OCC and was recorded in (Loss) income from equity method investments on the accompanying Consolidated Statements of Income. Furthermore, to determine the potential equity method impairment charge, an impairment analysis in accordance with ASC Topic 323 was performed during the second quarter resulting in an additional impairment charge of approximately $31 million, recorded in (Loss) income from equity method investments on the accompanying Consolidated Statements of Income. For purposes of the second quarter impairment analysis, the fair value of OCC 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 significant assumptions used to estimate the fair value under the discounted cash flow method included management’s best estimates of the expected results using a probability weighted average set of cash flow forecasts and using a discount rate of 11.2 percent. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As such, the fair value of the OCC equity method investment and its underlying fixed assets represents a Level 3 measurement. As of December 31, 2016, Management determined that there were no material events or changes in circumstances that would indicate an other-than-temporary decline in our equity method investments.
Accounting for Risk Management Activities and Derivative Financial Instruments
Our derivative financial instruments are recorded at fair value in the accompanying Consolidated Balance Sheets. Changes in fair value and settlements are reflected in our earnings in the accompanying Consolidated Statements of Income as gains and losses related to revenue, purchased product costs, and cost of revenues.	When available, quoted market prices or prices obtained through external sources are used to determine a financial instrument’s fair value. The valuation of Level 2 financial instruments is based on quoted market prices for similar assets and liabilities in active markets and other inputs that are observable. However, for other financial instruments for which quoted market prices are not available, the fair value is based on inputs that are largely unobservable such as option volatilities and NGL prices that are interpolated and extrapolated due to inactive markets. These instruments are classified as Level 3 under the fair value hierarchy. All fair value measurements are appropriately adjusted for non-performance risk.	If the assumptions used in the pricing models for our Level 2 and 3 financial instruments are inaccurate or if we had used an alternative valuation methodology, the estimated fair value may have been different and we may be exposed to unrealized losses or gains that could be material. A 10 percent difference in our estimated fair value of Level 2 and 3 derivatives at December 31, 2016 would have affected income before income taxes by approximately $6 million for the year ended December 31, 2016.



Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Accounting for Significant Embedded Derivative Instruments
Identifying and embedded derivatives is complex and requires significant judgment. We have a gas purchase agreement with a producer customer in which we are required to purchase natural gas based on a complex formula designed to share some of the frac spread with the producer customer, through December 31, 2022. Additionally, we have a keep-whole gas processing agreement with the same producer customer. For accounting purposes, these two contracts have been aggregated into a single contract, and are evaluated together. The agreements have primary terms that expire on December 31, 2022 and contain two successive term-extending options under which the producer customer can extend the purchase and processing agreements an additional five years each. Neither contract may be extended without an election to extend the other contract. The feature of the gas purchase contract to purchase gas based on a complex formula designed to share some of the frac spread with the producer customer and the option to extend both contracts have been identified as a single embedded derivative (“Natural Gas Embedded Derivative”) that requires a complex valuation based on significant judgment. The option to extend the contracts is part of the embedded feature and thus is required to be considered in the valuation of the embedded derivative. We are required to make a significant judgment about the probability that the option would be exercised when determining the value of the embedded derivative.	We carry the Natural Gas Embedded Derivative at fair value with changes in fair value recognized in income each period. The valuation requires significant judgment when forming the assumptions used. Third-party forward curves for certain commodity prices utilized in the valuation do not extend through the term of the arrangement. Thus, pricing is required to be extrapolated for those periods. We utilize multiple cash flow techniques to extrapolate NGL pricing. Due to the illiquidity of future markets, we do not believe one method is more indicative of fair value than the other methods. The fair value is also appropriately adjusted for non-performance risk each period. We evaluated various factors in order to determine the probability that the term-extending options would be exercised by the producer customer, such as estimates of future gas reserves in the region, the competitive environment in which the producer customer operates, the commodity price environment and the producer customer’s business strategy. As of December 31, 2016, we have estimated the probability that the producer customer will exercise its option to extend the agreements for the first renewal period is 50 percent, and for the second renewal period is 75 percent based on the inherent uncertainty of the variables that would impact its decision.	The Natural Gas Embedded Derivative is an instrument that is not exchange-traded. The valuation of the instrument is complex and requires significant judgment. The inputs used in the valuation model require specialized knowledge, as NGL price curves do not exist for the entire term of the arrangement. The valuation is sensitive to NGL and natural gas future price curves. Holding the natural gas curves constant, a 10 percent increase (decrease) in NGL price curves causes an 18 percent increase (decrease) in the liability as of December 31, 2016. Holding the NGL curves constant, a 10 percent increase (decrease) in the natural gas curves causes a 6 percent (decrease) increase in the liability as of December 31, 2016. The determination of the fair value of the option to extend is based on our judgment about the probability of the producer customer exercising the extension. If it were determined that the probability of exercise was 25 percent for the first renewal period and 50 percent for the second renewal period as of December 31, 2016, the liability would be reduced by 23 percent. If it were determined that the probability of exercise was 75 percent for the first renewal period and 100 percent for the second renewal period as of December 31, the liability would be increased by 88 percent. See Item 8. Financial Statements and Supplementary Data – Note 15 for more information related to the Natural Gas Embedded Derivative.



Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Variable Interest Entities
We evaluate all legal entities in which we hold an ownership or other pecuniary interest to determine if the entity is a VIE. Our interests in a VIE are referred to as variable interests. Variable interests can be contractual, ownership or other pecuniary interests in an entity that change with changes in the fair value of the VIE’s assets. When we conclude that we hold an interest in a VIE we must determine if we are the entity’s primary beneficiary. A primary beneficiary is deemed to have a controlling financial interest in a VIE. This controlling financial interest is evidenced by both (a) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses that could potentially be significant to the VIE or the right to receive benefits that could potentially be significant to the VIE. We consolidate any VIE when we determine that we are the primary beneficiary. We must disclose the nature of any interests in a VIE that is not consolidated.	Significant judgment is exercised in determining that a legal entity is a VIE and in evaluating our interest in a VIE. We use primarily a qualitative analysis to determine if an entity is a VIE. We evaluate the entity’s need for continuing financial support; the equity holder’s lack of a controlling financial interest; and/or if an equity holder’s voting interests are disproportionate to its obligation to absorb expected losses or receive residual returns. We evaluate our interests in a VIE to determine whether we are the primary beneficiary. We use a primarily qualitative analysis to determine if we are deemed to have a controlling financial interest in the VIE, either on a standalone basis or as part of a related party group. We continually monitor our interests in legal entities for changes in the design or activities of an entity and changes in our interests, including our status as the primary beneficiary to determine if the changes require us to revise our previous conclusions.	MarkWest Utica EMG, Ohio Condensate and Jefferson Dry Gas are VIEs; however, we are not considered to be the primary beneficiary. As a result, they are accounted for under the equity method. Changes in the design or nature of the activities of these entities, or our involvement with an entity, may require us to reconsider our conclusions on the entity’s status as a VIE and/or our status as the primary beneficiary. Such reconsideration requires significant judgment and understanding of the organization. This could result in the deconsolidation or consolidation of the affected subsidiary, which would have a significant impact on our financial statements. Ohio Gathering is a subsidiary of MarkWest Utica EMG and is a VIE. If we were to consolidate MarkWest Utica EMG, Ohio Gathering would need to be assessed for consolidation or deconsolidation. We account for our ownership interest in Centrahoma and MarkWest Pioneer under the equity method and have determined that these entities are not VIEs. However, changes in the design or nature of the activities of either entities may require us to reconsider our conclusions. Such reconsideration would require the identification of the variable interests in the entity and a determination on which party is the entity’s primary beneficiary. If an equity investment were considered a VIE and we were determined to be the primary beneficiary, the change could cause us to consolidate the entity. The consolidation of an entity that is currently accounted for under the equity method could have a significant impact on our financial statements. See Item 8. Financial Statements and Supplementary Data – Note 5 for more information on our other investments.



Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Contingent Liabilities
We accrue contingent liabilities for legal actions, claims, litigation, environmental remediation, tax deficiencies related to operating taxes and third-party indemnities for specified tax matters when such contingencies are both probable and can be reasonably estimated.	We regularly assess these estimates in consultation with legal counsel to consider resolved and new matters, material developments in court proceedings or settlement discussions, new information obtained as a result of ongoing discovery and past experience in defending and settling similar matters. Actual costs can differ from estimates for many reasons. For instance, settlement costs for claims and litigation can vary from estimates based on differing interpretations of laws, opinions on degree of responsibility and assessments of the amount of damages. Similarly, liabilities for environmental remediation may vary from estimates because of changes in laws, regulations and their interpretation, additional information on the extent and nature of site contamination and improvements in technology.	An estimate of the sensitivity to net income if other assumptions had been used in recording these liabilities is not practical because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, in terms of both the probability of loss and the estimates of such loss. For additional information on contingent liabilities, see Item 8. Financial Statements and Supplementary Data – Note 23.

Recent Accounting Pronouncements

From time to time, new accounting pronouncements are issued by the FASB that we adopt as of the specified effective date. If not discussed in Item 8. Financial Statements and Supplementary Data – Note 3, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on our financial statements upon adoption.

Item 8. Financial Statements and Supplementary Data

INDEX



	Page
Report of Independent Registered Public Accounting Firm	37
Audited Consolidated Financial Statements:
Consolidated Statements of Income	38
Consolidated Balance Sheets	39
Consolidated Statements of Cash Flows	40
Consolidated Statements of Equity	41
Notes to Consolidated Financial Statements	42
Select Quarterly Financial Data (Unaudited)	102

Management’s Report on Internal Control over Financial Reporting

MPLX LP’s management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended). An evaluation of the design and effectiveness of our internal control over financial reporting, based on the framework in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Xxxxxxxx Commission, was conducted under the supervision and with the participation of management, including our chief executive officer and chief financial officer. Based on the results of this evaluation, MPLX LP’s management concluded that its internal control over financial reporting was effective as of December 31, 2016.

On March 1, 2017, the Partnership acquired all of the outstanding membership interests of Xxxxxx Street Transportation LLC (“HST”), Woodhaven Cavern LLC (“WHC”) and MPLX Terminals LLC (“MPLXT”) in a transaction between entities under common control. The Partnership’s consolidated financial statements have been retrospectively adjusted for all periods to give effect to the acquisition of HST and WHC as if the acquisition had occurred on January 1, 2015, and MPLXT as if the acquisition had occurred on April 1, 2016. The controls of HST, WHC and MPLXT were not a part of the Partnership’s internal control over financial reporting as of December 31, 2016. Accordingly, the controls operated at HST, WHC and MPLXT were not included in our evaluation of the design and effectiveness of our internal control over financial reporting. HST, WHC and MPLXT are wholly-owned subsidiaries whose total assets and total revenues and other income represent 5% and 15%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2016.

The effectiveness of MPLX LP’s internal control over financial reporting as of December 31, 2016 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.



/s/ Xxxx X. Xxxxxxxx		/s/ Xxxxxx X.X. Xxxxx
Xxxx X. Xxxxxxxx Chairman of the Board of Directors and Chief Executive Officer of MPLX GP LLC (the general partner of MPLX LP)		Xxxxxx X.X. Beall Director, Executive Vice President and Chief Financial Officer of MPLX GP LLC (the general partner of MPLX LP)

Introductory Note to Combined Consolidated Financial Statements

On March 1, 2017, MPLX LP (the “Partnership”) entered into a Membership Interests Contributions Agreement (the “Contributions Agreement”) with MPLX GP LLC (the “General Partner”), MPLX Logistics Holdings LLC (“MPLX Logistics”), MPLX Holdings Inc. (“MPLX Holdings”) and MPC Investment LLC (“MPC Investment”). Pursuant to the Contributions Agreement, MPC Investment agreed to contribute the outstanding membership interests in Xxxxxx Street Transportation LLC (“HST”), Woodhaven Cavern LLC (“WHC”) and MPLX Terminals LLC (“MPLXT”) through a series of intercompany contributions to the Partnership for approximately $1.5 billion in cash and equity consideration valued at approximately $504 million (the “Transaction”). The number of common units representing the equity consideration was determined by dividing the contribution amount by the simple average of the ten day trailing volume weighted average New York Stock Exchange price of a common unit for the ten trading days ending at market close on February 28, 2017. The fair value of the common and general partner units issued was approximately $503 million and consisted of (i) 9,197,900 common units representing limited partner interests in the Partnership to the General Partner, (ii) 2,630,427 common units to MPLX Logistics and (iii) 1,132,049 common units to MPLX Holdings. The Partnership also issued 264,497 general partner units to the General Partner in order to maintain its two percent general partner interest in the Partnership.

The Partnership’s combined consolidated financial statements includes periods prior to the acquisition of HST, WHC and MPLXT. MPC contributed the assets of HST, WHC and MPLXT to newly created and wholly owned subsidiaries and entered into commercial agreements related to services provided by these new entities to MPC on January 1, 2015 for HST and WHC and April 1, 2016 for MPLXT. Prior to these dates, these entities were not considered businesses. The Partnership’s consolidated financial statements have been retrospectively recast for all periods to give effect to the acquisition of the HST and WHC as if the Transaction had occurred on January 1, 2015 and MPLXT as if the Transaction had occurred on April 1, 2016, as required for transactions between entities under common control. See Item 8. Financial Statements and Supplementary Data – Note 4 for more information on acquisition of HST, WHC and MPLXT.

Report of Independent Registered Public Accounting Firm

To the Partners of MPLX LP and the Board of Directors of MPLX GP LLC

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, of equity and of cash flows present fairly, in all material respects, the financial position of MPLX LP and its subsidiaries at December 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Xxxxxxxx Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

On March 1, 2017, the Company acquired Xxxxxx Street Transportation LLC, Woodhaven Cavern LLC and MPLX Terminals LLC in a transaction between entities under common control. The consolidated financial statements referred to above have been retrospectively adjusted to include these entities as if the transaction had been consummated as of April 1, 2016 for MPLX Terminals LLC and as of January 1, 2015 for Xxxxxx Street Transportation LLC and Woodhaven Cavern LLC. The controls of these entities were not a part of the Company’s internal control over financial reporting as of December 31, 2016. Accordingly, the controls operated at these entities were not included in either management’s assessment of internal control over financial reporting or our audit of the Company’s internal control over financial reporting. These entities are wholly-owned subsidiaries whose total assets and total revenues and other income represent 5% and 15%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2016.

/s/PricewaterhouseCoopers LLP

Toledo, Ohio

February 24, 2017, except with respect to our opinion on the consolidated financial statements insofar as it relates to the effects of the transaction discussed in Note 4 to the consolidated financial statements and the matter described in the second paragraph of Management’s Report on Internal Control over Financial Reporting, as to which the date is May 1, 2017

MPLX LP

Consolidated Statements of Income



(In millions, except per unit data)	2016			2015		2014
Revenues and other income:
Service revenue	$	958		$	130	$	70
Service revenue - related parties	936			701		662
Rental income	298			20		—
Rental income - related parties	235			146		15
Product sales	572			36		—
Product sales - related parties	11			1		—
Gain on sale of assets	1			—		—
(Loss) income from equity method investments	(74		)	3		—
Other income	6			6		6
Other income - related parties	86			58		40
Total revenues and other income	3,029			1,101		793
Costs and expenses:
Cost of revenues (excludes items below)	454			247		228
Purchased product costs	448			20		—
Rental cost of sales	57			11		1
Rental cost of sales - related parties	1			1		—
Purchases - related parties	388			172		153
Depreciation and amortization	591			129		75
Impairment expense	130			—		—
General and administrative expenses	227			125		81
Other taxes	50			15		10
Total costs and expenses	2,346			720		548
Income from operations	683			381		245
Related party interest and other financial costs	1			—		—
Interest expense (net of amounts capitalized of $28 million, $5 million, and $1 million, respectively)	210			35		4
Other financial costs	50			12		1
Income before income taxes	422			334		240
(Benefit) provision for income taxes	(12		)	1		1
Net income	434			333		239
Less: Net income attributable to noncontrolling interests	2			1		57
Less: Net income attributable to Predecessor	199			176		61
Net income attributable to MPLX LP	233			156		121
Less: Preferred unit distributions	41			—		—
Less: General partner’s interest in net income attributable to MPLX LP	191			57		6
Limited partners’ interest in net income attributable to MPLX LP	$	1		$	99	$	115
Per Unit Data (See Note 7)
Net income attributable to MPLX LP per limited partner unit:
Common - basic	$	—		$	1.23	$	1.55
Common - diluted	—			1.22		1.55
Subordinated - basic and diluted	—			0.11		1.50
Weighted average limited partner units outstanding:
Common - basic	331			79		37
Common - diluted	338			80		37
Subordinated - basic and diluted	—			18		37
Cash distributions declared per limited partner common unit	$	2.0500		$	1.8200	$	1.4100

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

MPLX LP

Consolidated Balance Sheets



	December 31,
(In millions)	2016		2015
Assets
Current assets:
Cash and cash equivalents	$	234	$	43
Receivables, net	299		247
Receivables - related parties	247		241
Inventories	55		52
Other current assets	33		51
Total current assets	868		634
Equity method investments	2,471		2,458
Property, plant and equipment, net	11,408		10,214
Intangibles, net	492		466
Goodwill	2,245		2,595
Long-term receivables - related parties	11		25
Other noncurrent assets	14		12
Total assets	$	17,509	$	16,404
Liabilities
Current liabilities:
Accounts payable	$	140	$	96
Accrued liabilities	232		189
Payables - related parties	87		56
Deferred revenue	2		—
Deferred revenue - related parties	38		32
Accrued property, plant and equipment	146		174
Accrued taxes	38		28
Accrued interest payable	53		54
Other current liabilities	27		16
Total current liabilities	763		645
Long-term deferred revenue	12		4
Long-term deferred revenue - related parties	19		9
Long-term debt	4,422		5,255
Deferred income taxes	6		378
Deferred credits and other liabilities	177		167
Total liabilities	5,399		6,458
Commitments and contingencies (see Note 23)
Redeemable preferred units	1,000		—
Equity
Common unitholders - public (271 million and 240 million units issued and outstanding)	8,086		7,691
Class B unitholders (4 million and 8 million units issued and outstanding)	133		266
Common unitholder - MPC (86 million and 57 million units issued and outstanding)	1,069		465
General partner - MPC (7 million units issued and outstanding)	1,013		819
Equity of Predecessor	791		692
Total MPLX LP partners’ capital	11,092		9,933
Noncontrolling interest	18		13
Total equity	11,110		9,946
Total liabilities, preferred units and equity	$	17,509	$	16,404

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

MPLX LP

Consolidated Statements of Cash Flows



(In millions)	2016			2015			2014
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	434		$	333		$	239
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred financing costs	46			5			1
Depreciation and amortization	591			129			75
Impairment expense	130			—			—
Deferred income taxes	(17		)	1			—
Asset retirement expenditures	(6		)	(1		)	(2		)
Gain on disposal of assets	(1		)	—			—
Loss (income) from equity method investments	74			(3		)	—
Distributions from unconsolidated affiliates	148			15			—
Changes in:
Current receivables	(52		)	(29		)	2
Inventories	(8		)	1			1
Change in fair value of derivatives	43			(6		)	—
Current accounts payable and accrued liabilities	102			5			1
Receivables from / liabilities to related parties	(19		)	(34		)	15
All other, net	26			11			2
Net cash provided by operating activities	1,491			427			334
Investing activities:
Additions to property, plant and equipment	(1,313		)	(334		)	(141		)
Acquisitions, net of cash acquired	—			(1,218		)	—
Investments - loans to (from) related parties	(17		)	(118		)	—
Disposal of assets	1			—			—
Investments in unconsolidated affiliates	(87		)	(14		)	—
All other, net	3			(2		)	4
Net cash used in investing activities	(1,413		)	(1,686		)	(137		)
Financing activities:
Long-term debt - borrowings	434			1,490			1,160
- repayments	(1,312		)	(1,441		)	(526		)
Related party debt - borrowings	2,532			301			—
- repayments	(2,540		)	(293		)	—
Debt issuance costs	—			(11		)	(3		)
Net proceeds from equity offerings	792			1			230
Issuance of redeemable preferred units	984			—			—
Issuance of units in MarkWest Merger	—			169			—
Contributions from MPC - MarkWest Merger	—			1,230			—
Distributions to preferred unitholders	(25		)	—			—
Distributions to unitholders and general partner	(845		)	(158		)	(103		)
Distributions to noncontrolling interests	(3		)	(1		)	(47		)
Contributions from noncontrolling interests	6			—			—
Consideration payment to Class B unitholders	(25		)	—			—
Contribution from MPC	225			1			—
Distributions related to purchase of additional interest in Pipe Line Holdings	—			(12		)	(910		)
Distributions to MPC from Predecessor	(104		)	—			(25		)
All other, net	(6		)	(1		)	—
Net cash provided by (used in) financing activities	113			1,275			(224		)
Net increase in cash and cash equivalents	191			16			(27		)
Cash and cash equivalents at beginning of period	43			27			54
Cash and cash equivalents at end of period	$	234		$	43		$	27

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

MPLX LP

Consolidated Statements of Equity



	Partnership
(In millions)	Common Unitholders Public			Class B Unitholders Public			Common Unitholder MPC			Subordinated Unitholder MPC			General Partner MPC			Noncontrolling Interest			Equity of Predecessor			Total
Balance at December 31, 2013	$	412		$	—		$	57		$	209		$	(32	)	$	468		$	285		$	1,399
Purchase/contribution of additional interest in Pipe Line Holdings	—			—			200			—			(638		)	(472		)	—			(910		)
Equity offering, net of issuance costs	221			—			—			—			9			—			—			230
Net income	31			—			27			58			5			57			61			239
Distributions to MPC from Predecessor	—			—			—			—			—			—			(25		)	(25		)
Distributions to unitholders and general partner	(26		)	—			(23		)	(50		)	(4		)	—			—			(103		)
Distributions to noncontrolling interest retained by MPC	—			—			—			—			—			(47		)	—			(47		)
Equity-based compensation	1			—			—			—			—			—			—			1
Balance at December 31, 2014	639			—			261			217			(660		)	6			321			784
Purchase of additional interest in Pipe Line Holdings	—			—			—			—			(6		)	(6		)	—			(12		)
Contributions from MPC - MarkWest Merger	—			—			—			—			1,280			—			—			1,280
Issuance of units under ATM program	1			—			—			—			—			—			—			1
Net income	15			—			36			48			57			1			176			333
Distributions to unitholders and general partner	(40		)	—			(52		)	(45		)	(21		)	—			—			(158		)
Distributions to noncontrolling interests	—			—			—			—			—			(1		)	—			(1		)
Subordinated unit conversion							220			(220		)										—
Non-cash contribution from MPC	—			—			—			—			—			—			194			194
Contribution from MPC	—			—			—			—			—			—			1			1
Equity-based compensation	17			—			—			—			—			—			—			17
Deferred income tax impact from changes in equity	(1		)	—			—			—			—			—			—			(1		)
Issuance of units in MarkWest Merger	7,060			266			—			—			169			—			—			7,495
Noncontrolling interest assumed in MarkWest Merger	—			—			—			—			—			13			—			13
Balance at December 31, 2015	7,691			266			465			—			819			13			692			9,946
Distributions to MPC from Predecessor	—			—			—			—			—			—			(104		)	(104		)
Contribution from MPC	—			—			84			—			141			—			—			225
Contribution of MarkWest Hydrocarbon from MPC	—			—			—			—			(188		)	—			—			(188		)
Distribution of MarkWest Hydrocarbon to MPC	—			—			—			—			563			—			—			563
Issuance of units under ATM Program	776			—			—			—			16			—			—			792
Net (loss) income	(5		)	—			6			—			191			2			199			393
Allocation of MPC's net investment at acquisition	—			—			669			—			(337		)	—			(332		)	—
Distributions to unitholders and general partner	(513		)	—			(142		)	—			(190		)	—			—			(845		)
Distributions to noncontrolling interest	—			—			—			—			—			(3		)	—			(3		)
Contributions from noncontrolling interest	—			—			—			—			—			6			—			6
Class B unit conversion	133			(133		)	—			—			—			—			—			—
Non-cash contribution from MPC	—			—			—			—			—			—			336			336
Equity-based compensation	6			—			—			—			—			—			—			6
Deferred income tax impact from changes in equity	(2		)	—			(13		)	—			(2		)	—			—			(17		)
Balance at December 31, 2016	$	8,086		$	133		$	1,069		$	—		$	1,013		$	18		$	791		$	11,110

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

Notes to Consolidated Financial Statements

1. Description of the Business and Basis of Presentation

Description of the Business – MPLX LP is a diversified, growth-oriented master limited partnership formed by Marathon Petroleum Corporation. MPLX LP and its subsidiaries (collectively, the “Partnership”) are engaged in the gathering, processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of NGLs; and the transportation, storage and distribution of crude oil and refined petroleum products. The Partnership’s principal executive office is located in Findlay, Ohio.

The Partnership was formed on March 27, 2012 as a Delaware limited partnership and completed its initial public offering (the “Initial Offering”) on October 31, 2012. On December 4, 2015, a wholly-owned subsidiary of the Partnership merged with MarkWest Energy Partners L.P. (the “MarkWest Merger”), which is one of the largest processors of natural gas in the United States and the largest processor and fractionator in the Marcellus and Utica shale plays. Effective March 31, 2016, the Partnership acquired MPC’s inland marine business, Xxxxxx Street Marine LLC (“HSM”). Effective March 1, 2017, the Partnership acquired from MPC, Xxxxxx Street Transportation LLC (“HST”), Woodhaven Cavern LLC (“WHC”) and MPLX Terminals LLC (“MPLXT”). These acquisitions are described further in Note 4. References to “MPC” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other than the Partnership. References to “Predecessor” refer collectively to HSM’s, HST’s, WHC’s and MPLXT’s related assets, liabilities and results of the operations prior to the dates of their respective acquisitions.

The Partnership’s business consists of two segments: Logistics and Storage (“L&S”) and Gathering and Processing (“G&P”). See Note 10 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.

2. Summary of Principal Accounting Policies

Use of Estimates – The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ materially from those estimates. Estimates are subject to uncertainties due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change and affect items such as valuing identified intangible assets; determining the fair value of derivative instruments; valuing inventory; evaluating impairments of long-lived assets, goodwill and equity investments; establishing estimated useful lives for long-lived assets; acquisition accounting; recognizing share-based compensation expense; estimating revenues, expense accruals and capital expenditures; valuing AROs; and determining liabilities, if any, for environmental and legal contingencies.

Revenue Recognition – The Partnership’s assessment of each of the revenue recognition criteria as they relate to its revenue producing activities are as follows: persuasive evidence of an arrangement exists, delivery, the fee is fixed or determinable and collectability is reasonably assured. It is upon delivery or title transfer to the customer that the Partnership meets all four revenue recognition criteria and it is at such time that the Partnership recognizes Product sales. Additionally, it is upon completion of services provided that the Partnership meets all four revenue recognition criteria and it is at such time that the Partnership recognizes Service revenue. The Partnership also recognizes Rental income over the term of the implicit operating leases which generate this revenue, as discussed below.

L&S Segment

Revenues are recognized in the L&S segment for crude oil and product pipeline transportation based on the delivery of actual volumes transported at regulated tariff rates or at contractually agreed upon rates. When MPC ships volumes on our pipeline systems under a joint tariff with a third party, those revenues are recorded as sales and other operating revenues, and not as sales to related parties, because we receive payment from the third party. Revenues are recognized for crude oil and refined product storage as performed based on contractual rates. Operating fees received for operating pipeline systems are recognized as a component of other income in the period the service is performed. All such amounts are reported as Service revenue or Service revenue - related parties on the Consolidated Statements of Income.

Under our MPC transportation services agreements, if MPC fails to transport its minimum throughput volumes during any quarter, then MPC will pay us a deficiency payment equal to the volume of the deficiency multiplied by the tariff rate then in effect. MPC may then apply the amount of any such deficiency payments as a credit for volumes transported on the applicable pipeline system in excess of its minimum volume commitment during the following four or eight quarters under the terms of the applicable transportation services agreement. The deficiency payments are initially recorded as Deferred revenue - related parties in the Consolidated Balance Sheets. The Partnership recognizes revenues for the deficiency payments at the earlier of when credits are used for volumes transported in excess of minimum volume commitments, when it becomes impossible to physically transport volumes necessary to utilize the credits or upon the expiration of the applicable four or eight quarter period. The use or expiration of the credits is a decrease in Deferred revenue - related parties. In addition, capital projects the Partnership undertakes at the request of MPC are reimbursed in cash and recognized in income over the remaining term of the applicable transportation services agreements.

Under our terminal services agreement, the Partnership generates revenue for the operation, storage, and other terminal related services for MPC. Revenues are recognized for refined petroleum product throughput based on the receipt of actual volumes at a fixed contractual fee. All such amounts are reported as Service revenue - related parties on the Consolidated Statements of Income. If MPC fails to meet its minimum volume commitment during any quarter, then MPC will pay us a deficiency payment equal to the volume of the deficiency multiplied by the contractual fee then in effect. The deficiency payments are recorded as Deferred revenue - related parties in the Consolidated Balance Sheets. Revenue for the deficiency payments is recognized at the end of each quarter that MPC does not meet its minimum volume commitment. Contingent revenue is recognized for volume throughput above MPC's minimum volume commitment.

Based on the terms of the Partnership’s fee-based transportation services and storage services agreements with MPC, we are considered to be a lessor of our pipelines, marine equipment, terminals and storage facilities. Our implicit lease arrangements related to the processing facilities contain contingent rental provisions whereby we receive additional fees if the producer customer exceeds the monthly minimum processed volumes. Revenue generated under the implicit lease arrangements is reported as Rental revenue or Rental revenue - related parties on the Consolidated Statements of Income. Expenses generated in order to facilitate these agreements are reported as Rental cost of sales or Rental cost of sales - related parties.

G&P Segment

The Partnership generates the majority of its G&P segment revenues from natural gas gathering, transportation and processing; NGL gathering, transportation, fractionation, marketing and storage; and crude oil gathering and transportation. The Partnership disaggregates revenue as Product sales, Service revenue and Rental income on the Consolidated Statements of Income. Revenue is reported as follows:


•	Product sales – Product sales represent the sale of NGLs, condensate and natural gas. The product is primarily obtained as consideration for or related to providing midstream services.


•	Service revenue – Service revenue represents all other revenue generated as the result of performing the services listed above.


•	Rental income – Rental income represents revenue generated as the result of implicit operating lease arrangements.

The Partnership enters into a variety of contract types in order to generate Product sales and Service revenue. The Partnership provides services under the following different types of arrangements:

•

Fee-based arrangements – Under fee-based arrangements, the Partnership receives a fee or fees for one or more of the following services: gathering, processing and transportation of natural gas; gathering, transportation, fractionation, exchange and storage of NGLs; and gathering and transportation of crude oil. The revenue the Partnership earns from these arrangements is generally directly related to the volume of natural gas, NGLs or crude oil that flows through the Partnership’s systems and facilities and is not normally directly dependent on commodity prices. In certain cases, the Partnership’s arrangements provide for minimum annual payments or fixed demand charges.

◦

Fee-based arrangements are reported as Service revenue on the Consolidated Statements of Income. In certain instances when specifically stated in the contract terms, the Partnership purchases product after fee-based services have been provided. Revenue from the sale of products purchased after services are provided is reported as Product sales on the Consolidated Statements of Income and recognized on a gross basis as the Partnership is the principal in the transaction.

•

Percent-of-proceeds arrangements – Under percent-of-proceeds arrangements, the Partnership gathers and processes natural gas on behalf of producers, sells the resulting residue gas, condensate and NGLs at market prices and remits to producers an agreed-upon percentage of the proceeds. In other cases, instead of remitting cash payments to the producer, the Partnership delivers an agreed-upon percentage of the residue gas and NGLs to the producer (take-in-kind arrangements) and sells the volumes the Partnership retains to third parties. Revenue from these arrangements is reported on a gross basis where the Partnership acts as the principal, as the Partnership has physical inventory risk and does not earn a fixed dollar amount. The agreed-upon percentage paid to the producer is reported as Purchased product costs on the Consolidated Statements of Income. Revenue is recognized on a net basis when the Partnership acts as an agent and earns a fixed dollar amount of physical product and does not have risk of loss of the gross amount of gas and/or NGLs. Percent-of-proceeds revenue is reported as Product sales on the Consolidated Statements of Income.

•

Keep-whole arrangements – Under keep-whole arrangements, the Partnership gathers natural gas from the producer, processes the natural gas and sells the resulting condensate and NGLs to third parties at market prices. Because the extraction of the condensate and NGLs from the natural gas during processing reduces the Btu content of the natural gas, the Partnership must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the energy content of this natural gas. Certain keep-whole arrangements also have provisions that require the Partnership to share a percentage of the keep-whole profits with the producers based on the oil to gas ratio or the NGL to gas ratio. Sales of NGLs under these arrangements are reported as Product sales on the Consolidated Statements of Income and are reported on a gross basis as the Partnership is the principal in the arrangement. Natural gas purchased to return to the producer and shared NGL profits are recorded as Purchased product costs in the Consolidated Statements of Income.

•

Percent-of-index arrangements – Under percent-of-index arrangements, the Partnership purchases natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount. The Partnership then gathers and delivers the natural gas to pipelines where the Partnership resells the natural gas at the index price or at a different percentage discount to the index price. Revenue generated from percent-of-index arrangements are reported as Product sales on the Consolidated Statements of Income and are recognized on a gross basis as the Partnership purchases and takes title to the product prior to sale and is the principal in the transaction.

In many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements described above. When fees are charged (in addition to product received) under keep-whole arrangements, percent-of-proceeds arrangements or percent-of-index arrangements, the Partnership records such fees as Service revenue on the Consolidated Statements of Income. The terms of the Partnership’s contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements.

Amounts billed to customers for shipping and handling, including fuel costs, are included in Product sales on the Consolidated Statements of Income, except under contracts where we are acting as an agent. Shipping and handling costs associated with product sales are included in Purchased product costs on the Consolidated Statements of Income. Taxes collected from customers and remitted to the appropriate taxing authority are excluded from revenue. Facility expenses and depreciation represent those expenses related to operating our various facilities and are necessary to provide both Product sales and Service revenue.

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.

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.

Revenue and Expense Accruals – The Partnership routinely makes accruals based on estimates for both revenues and expenses due to the timing of compiling billing information, receiving certain third-party information and reconciling the Partnership’s records with those of third parties. The delayed information from third parties includes, among other things, actual volumes purchased, transported or sold, adjustments to inventory and invoices for purchases, actual natural gas and NGL deliveries and other operating expenses. The Partnership makes accruals to reflect estimates for these items based on its internal records and information from third parties. Estimated accruals are adjusted when actual information is received from third parties and the Partnership’s internal records have been reconciled.

Cash and Cash Equivalents – Cash and cash equivalents include cash on hand and on deposit and investments in highly liquid debt instruments with initial maturities of three months or less.

Restricted Cash – Restricted cash consists of cash and investments that must be maintained as collateral for letters of credit issued to certain third-party producer customers. The balances will be outstanding until certain capital projects are completed and the third party releases the restriction. Restricted cash also consists of cash advances to be used for the operation and maintenance of an operated pipeline system. At December 31, 2016 and 2015, the amount of restricted cash included in Other current assets on the Consolidated Balance Sheets was $5 million and $9 million, respectively.

Receivables – Receivables primarily consist of customer accounts receivable, which are recorded at the invoiced amount and generally do not bear interest. Management reviews the allowance quarterly. Past-due balances over 90 days and other higher risk amounts are reviewed individually for collectability. Balances that remain outstanding after reasonable collection efforts have been unsuccessful are written off through a charge to the valuation allowance and a credit to accounts receivable.

Inventories – Inventories consist primarily of natural gas, propane, other NGLs and materials and supplies to be used in operations. Natural gas, propane, and other NGLs are valued at the lower of weighted-average cost or net realizable value. Materials and supplies are stated at the lower of cost or net realizable value. Cost for materials and supplies is determined primarily using the weighted-average cost method. Processed natural gas and NGL inventories include material, labor and overhead. Shipping and handling costs related to purchases of natural gas and NGLs are included in inventory.

Imbalances – Within our pipelines and storage assets we experience volume gains and losses due to pressure and temperature changes, evaporation and variances in meter readings and other measurement methods. Until settled, positive imbalances are recorded as other current assets and negative imbalances are recorded as accounts payable. Positive and negative product imbalances are settled in cash, settled by physical delivery of gas from a different source, or tracked and settled in the future.

Property, Plant and Equipment – Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of assets are capitalized. Repairs, maintenance and renewals that do not extend the useful lives of the assets are expensed as incurred. Interest costs for the construction or development of long-lived assets are capitalized and amortized over the related asset’s estimated useful life. Leasehold improvements are amortized over the shorter of the useful life or lease term.

When items of property, plant and equipment are sold or otherwise disposed of, any gains or losses are reported in the Consolidated Statements of Income. Gains on the disposal of property, plant and equipment are recognized when they occur, which is generally at the time of closing. If a loss on disposal is expected, such losses are recognized when the assets are classified as held for sale. The Partnership evaluates transactions involving the sale of property, plant and equipment to determine if they are, in-substance, the sale of real estate. Tangible assets may be considered real estate if the costs to relocate them for use in a different location exceed 10 percent of the asset’s fair value. Financial assets, primarily in the form of

ownership interests in an entity, may be in-substance real estate based on the significance of the real estate in the entity. Sales of real estate are not considered consummated if the Partnership maintains an interest in the asset after it is sold or has certain other forms of continuing involvement. Significant judgment is required to determine if a transaction is a sale of real estate and if a transaction has been consummated. If a sale of real estate is not considered consummated, the Partnership cannot record the transaction as a sale and must account for the transaction under an alternative method of accounting such as a financing or leasing arrangement.

The Partnership’s policy is to evaluate whether there has been an impairment in the value of long-lived assets when certain events indicate that the remaining balance may not be recoverable. 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 a reporting unit is not recoverable, a loss is recorded for the difference between the fair value and the carrying value. The Partnership evaluates the carrying value of its property, plant and equipment on at least a segment level and at lower levels where the cash flows for specific assets can be identified, which generally is the component level for our G&P and L&S segments. Management considers the dedicated volume of producer customers’ reserves and future NGL product and natural gas prices to estimate cash flows. The amount of additional producer customers’ reserves developed by future drilling activity depends, in part, on expected commodity prices. Projections of producer customers’ reserves, drilling activity and future commodity prices are inherently subjective and contingent upon a number of variable factors, many of which are difficult to forecast. Any significant variance in any of these assumptions or factors could materially affect future cash flows, which could result in the impairment of an asset group.

For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value, less the cost to sell, to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is redetermined when related events or circumstances change.

Intangibles – The Partnership’s intangibles are mainly comprised of customer contracts and related relationships acquired in business combinations and recorded under the acquisition method of accounting at their estimated fair values at the date of acquisition. Using relevant information and assumptions, management determines the fair value of acquired identifiable intangible assets. Fair value was calculated using the multi-period excess earnings method under the income approach for each reporting unit. This valuation method is based on first forecasting gross profit for the existing customer base and then applying expected attrition rates. The operating cash flows are calculated by determining the costs required to generate gross profit from the existing customer base. The key assumptions include overall gross profit growth, attrition rate of existing customers over time and the discount rate. Amortization of intangibles with definite lives is calculated using the straight-line method which is reflective of benefit pattern in which the estimated economic benefit is expected to be received over the estimated useful life of the intangible asset. The estimated economic life is determined by assessing the life of the assets related to the contracts and relationships, likelihood of renewals, the projected reserves, competitive factors, regulatory or legal provisions and maintenance and renewal costs.

Intangibles with indefinite lives are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of the intangible may not be recoverable. If the sum of the expected undiscounted future cash flows related to the asset is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset. The Partnership has no intangibles with indefinite lives.

Goodwill – Goodwill is the cost of an acquisition less the fair value of the net identifiable assets and noncontrolling interest, if any, of the acquired business. The Partnership evaluates goodwill for impairment annually as of November 30, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The Partnership determined its reporting units based on the criteria included in ASC 280 which requires a component to be a business with discrete financial information that management reviews on a regular basis. Management reviews its determination of reporting units on an annual basis. The Partnership may first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Partnership may elect to perform the two-step goodwill impairment test without completing a qualitative assessment. If a two-step process goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit to which goodwill has been allocated, with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss. During 2016, impairment charges of approximately $130 million were recorded. There were no impairments as a result of the Partnership’s November 30, 2015 and November 30, 2016 goodwill impairment analyses.

Other Taxes – Other taxes primarily include real estate taxes.

Environmental Costs – Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. The Partnership recognizes remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure. A receivable is recorded for environmental costs indemnified by MPC.

Asset Retirement Obligations – An ARO is a legal obligation associated with the retirement of tangible long-lived assets that generally result from the acquisition, construction, development or normal operation of the asset. AROs are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a credit adjusted risk free interest rate and increases due to the passage of time based on the time value of money until the obligation is settled. The Partnership recognizes a liability of a conditional ARO as soon as the fair value of the liability can be reasonably estimated. A conditional ARO is defined as an unconditional legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity. AROs have not been recognized for certain assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminate. Such obligations will be recognized in the period when sufficient information becomes available to estimate a range of potential settlement dates.

Investment in Unconsolidated Affiliates – Equity investments in which the Partnership exercises significant influence, but does not control and is not the primary beneficiary, are accounted for using the equity method and are reported in Equity method investments in the accompanying Consolidated Balance Sheets. This includes entities in which we hold majority ownership but the minority shareholders have substantive participating rights. Differences in the basis of the investments and the separate net asset values of the investees, if any, are amortized into net income over the remaining useful lives of the underlying assets and liabilities, except for the excess related to goodwill.

The Partnership believes the equity method is an appropriate means for it to recognize increases or decreases measured by GAAP in the economic resources underlying the investments. Regular evaluation of these investments is appropriate to evaluate any potential need for impairment. The Partnership uses evidence of a loss in value to identify if an investment has an other than a temporary decline.

Deferred Financing Costs – Deferred financing costs are an asset for credit facility costs and netted against debt for senior notes. These costs are amortized over the contractual term of the related obligations using the effective interest method or, in certain circumstances, accelerated if the obligation is refinanced.

Derivative Instruments – Derivative instruments (including derivative instruments embedded in other contracts) are recorded at fair value and are reflected in the Consolidated Balance Sheets on a net basis, as either an asset or liability, as they are governed by the master netting agreements. The Partnership discloses the fair value of all of its derivative instruments under the captions Other noncurrent assets, Other current liabilities and Deferred credits and other liabilities on the Consolidated Balance Sheets, inclusive of option premiums, if any. Changes in the fair value of derivative instruments are reported in the Consolidated Statements of Income in accounts related to the item whose value or cash flows are being managed. All derivative instruments were marked to market through Product sales, Purchased product costs, or Cost of revenues on the Consolidated Statements of Income. Revenue gains and losses relate to contracts utilized to manage the cash flow for the sale of a product. Purchased product costs gains and losses relate to contracts utilized to manage the cost of natural gas purchases, typically related to keep‑whole arrangements. Cost of revenues gains and losses relate to a contract utilized to manage electricity costs. Changes in risk management for unrealized activities are reported as an adjustment to net income in computing cash flow from operating activities on the accompanying Consolidated Statements of Cash Flows.

During the years ended December 31, 2016, 2015 and 2014, the Partnership did not designate any xxxxxx or designate any contracts as normal purchases and normal sales, with the exception of electricity contracts, for which the normal purchases and normal sales designation was elected during the year ended December 31, 2016.

Fair Value of Financial Instruments – Management believes the carrying amount of financial instruments, including cash and cash equivalents, receivables, receivables from related parties, other current assets, accounts payable, accounts payable to related parties and accrued liabilities approximate fair value because of the short-term maturity of these instruments. The recorded value of the amounts outstanding under the bank revolving credit facility, if any, approximate fair value due to the

variable interest rate that approximates current market rates (see Note 15). Derivative instruments are recorded at fair value, based on available market information (see Note 16).

Fair Value Measurement – Financial assets and liabilities recorded at fair value in the Consolidated Balance Sheets are categorized based upon a fair value hierarchy established by GAAP, which classifies the inputs used to measure fair value into the following levels:


•	Level 1 inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.


•	Level 2 inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.


•	Level 3 inputs to the valuation methodology are unobservable and significant to the fair value measurement.

A financial instrument’s categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.

The determination to classify a financial instrument within Level 3 of the valuation hierarchy is based upon the significance of the unobservable inputs to the overall fair value measurement. However, Level 3 financial instruments typically include, in addition to the unobservable or Level 3 inputs, observable inputs (that is, inputs that are actively quoted and can be validated to external sources); accordingly, the gains and losses for Level 3 financial instruments include changes in fair value due in part to observable inputs that are part of the valuation methodology. Level 3 financial instruments include crude oil options, all NGL derivatives and the embedded derivatives in commodity contracts discussed in Note 15 as they have significant unobservable inputs.

The methods and assumptions described above may produce a fair value that may not be realized in future periods upon settlement. Furthermore, while the Partnership believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. For further discussion see Note 15.

Equity-Based Compensation Arrangements – The Partnership issues phantom units under its share-based compensation plan as described further in Note 20. A phantom unit entitles the grantee a right to receive a common unit upon the issuance of the phantom unit. The fair value of phantom unit awards granted to employees and non-employee directors is based on the fair market value of MPLX LP common units on the date of grant. The fair value of the units awarded is amortized into earnings using a straight-line amortization schedule over the period of service corresponding with the vesting period. For phantom units that vest immediately and are not forfeitable, equity-based compensation expense is recognized at the time of grant.

Performance units paying out in cash are accounted for as liability awards and recorded at fair value with a mark-to-market adjustment made each quarter. The performance units paying out in units are accounted for as equity awards and use a Monte Carlo valuation model to calculate a grant date fair value.

To satisfy common unit awards, the Partnership may issue new common units, acquire common units in the open market or use common units already owned by the general partner.

Tax Effects of Share-Based Compensation – The Partnership elected to adopt the simplified method to establish the beginning balance of the additional paid-in capital pool (“APIC Pool”) related to the tax effects of employee share-based compensation and to determine the subsequent impact on the APIC Pool and Consolidated Statements of Cash Flows of the tax effects of share-based compensation awards that were outstanding upon adoption. Additional paid-in capital is reported as Common unitholders - public in the accompanying Consolidated Balance Sheets.

Income Taxes – The Partnership is not a taxable entity for federal income tax purposes. As a result of the MarkWest Xxxxxx, discussed further in Note 4, MarkWest was the surviving entity for tax purposes. MarkWest is not a taxable entity for federal income tax purposes. As such, the Partnership does not directly pay federal income tax. Taxes on the Partnership’s net income generally are borne by its partners through the allocation of taxable income. The Partnership’s taxable income or loss, which may vary substantially from the net income or loss reported in the Consolidated Statements of Income, is includable in the federal income tax returns of each partner. The Partnership and certain legal entities are, however, taxable entities under certain state jurisdictions.

As a result of the Class A Reorganization discussed in Note 8, 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. Prior to the Class A Reorganization, in addition to paying tax on its own earnings, MarkWest Hydrocarbon recognized a tax expense or a tax benefit on its proportionate share of Partnership income or loss resulting from MarkWest Hydrocarbon’s ownership of Class A units of the Partnership, even though for financial reporting purposes such income or loss was eliminated in consolidation. The Class A units represented limited partner interests with the same rights as common units except that the Class A units did not have voting rights, except as required by law. Class A units were not treated as outstanding common units in the Consolidated Balance Sheets as they were eliminated in the consolidation of MarkWest Hydrocarbon. The deferred income tax component prior to the reorganization related to the change in the temporary book to tax basis difference in the carrying amount of the investment in the Partnership which resulted primarily from timing differences in MarkWest Hydrocarbon’s proportionate share of the book income or loss as compared with the MarkWest Hydrocarbon’s proportionate share of the taxable income or loss of the Partnership.

The Partnership accounts for income taxes under the asset and liability method. Deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis, capital loss carryforwards and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates applied to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized as tax expense (benefit) from continuing operations in the period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to reflect the deferred tax assets at net realizable value as determined by management. All deferred tax balances are classified as long-term in the accompanying Consolidated Balance Sheets. All changes in the tax bases of assets and liabilities are allocated among operations and items charged or credited directly to equity.

Distributions – 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 9, and subsequently allocated to the general partner and limited partner unitholders. Distributions, although earned, are not accrued as a liability 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 below.

Net Income Per Limited Partner Unit – The Partnership uses the two-class method when calculating the net income per unit applicable to limited partners, because there is more than one class of participating security. The classes of participating securities include common units, subordinated units, general partner units, Preferred units, certain equity-based compensation awards and incentive distribution rights. Class B units are considered to be a separate class of common units that do not participate in distributions.

Net income attributable to MPLX LP is allocated to the unitholders differently for preparation of the Consolidated Statements of Equity and the calculation of net income per limited partner unit. In preparing the Consolidated Statements of Equity, net income attributable to MPLX LP is allocated to Preferred unitholders based on a fixed distribution schedule 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, except Class B unitholders, based on their respective ownership percentages.

In preparing net income per limited partner units, during periods in which a net loss attributable to the Partnership is reported or periods in which the total distributions exceed the reported net income attributable to the Partnership’s unitholders, the amount allocable to certain equity-based compensation awards is based on actual distributions to the equity-based compensation awards. Diluted earnings per unit is calculated by dividing net income attributable to the Partnership’s common unitholders, after deducting amounts allocable to other participating securities, by the weighted average number of common units and potential common units outstanding during the period. Potential common units are excluded from the calculation of diluted earnings per unit during periods in which net income attributable to the Partnership’s unitholders, after deducting amounts that are allocable to the outstanding equity-based compensation awards, Preferred units, and incentive distribution rights, is a loss as the impact would be anti-dilutive.

Business Combinations – The Partnership recognizes and measures the assets acquired and liabilities assumed in a business combination based on their estimated fair values at the acquisition date, with any remaining difference recorded as goodwill or gain from a bargain purchase. For all material acquisitions, management engages an independent valuation specialist to assist

with the determination of fair value of the assets acquired, liabilities assumed, noncontrolling interest, if any, and goodwill, based on recognized business valuation methodologies. If the initial accounting for the business combination is incomplete by the end of the reporting period in which the acquisition occurs, an estimate will be recorded. Subsequent to the acquisition, and not later than one year from the acquisition date, the Partnership will record any material adjustments to the initial estimate based on new information obtained about facts and circumstances that existed as of the acquisition date. An income, market or cost valuation method may be utilized to estimate the fair value of the assets acquired, liabilities assumed, and noncontrolling interest, if any, in a business combination. The income valuation method represents the present value of future cash flows over the life of the asset using: (i) discrete financial forecasts, which rely on management’s estimates of volumes, NGL prices, revenue and operating expenses; (ii) long-term growth rates; and (iii) appropriate discount rates. The market valuation method uses prices paid for a reasonably similar asset by other purchasers in the market, with adjustments relating to any differences between the assets. The cost valuation method is based on the replacement cost of a comparable asset at prices at the time of the acquisition reduced for depreciation of the asset. Acquisition-related costs are expensed as incurred in connection with each business combination. See Note 4 for more information about the MarkWest Merger.

Accounting for Changes in Ownership Interests in Subsidiaries – The Partnership’s ownership interest in a consolidated subsidiary may change if it sells a portion of its interest or acquires additional interest or if the subsidiary issues or repurchases its own shares. If the transaction does not result in a change in control over the subsidiary, the transaction is accounted for as an equity transaction. If a sale results in a loss of control, it would result in the deconsolidation of a subsidiary with a gain or loss recognized in the Consolidated Statements of Income unless the subsidiary meets the definition of in-substance real estate. Deconsolidation of in-substance real estate is recorded at cost with no gain or loss recognized. If the purchase of additional interest occurs which changes the acquirer’s ownership interest from noncontrolling to controlling, the acquirer’s preexisting interest in the acquiree is remeasured to its fair value, with a resulting gain or loss recorded in earnings upon consummation of the business combination. Once an entity has control of a subsidiary, its acquisitions of some or all of the noncontrolling interests in that subsidiary are accounted for as equity transactions and are not considered to be a business combination.

3. 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 4 and 18 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 financial statements.

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 financial statements.

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 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 are required if conditions give rise to substantial doubt and the type of disclosure is determined based on whether management’s plans will be able to alleviate the substantial doubt. The change was effective for the first fiscal period ending after December 15, 2016, and for fiscal periods and interim periods thereafter. The adoption of this accounting standard update in the fourth quarter of 2016 did not have a material impact on the Partnership’s disclosures.

Not Yet Adopted

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

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

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

In October 2016, the FASB issued an accounting standard update to amend the consolidation guidance issued in February 2015 to require that a decision maker consider, in the determination of the primary beneficiary, its indirect interest in a VIE held by a related party that is under common control on a proportionate basis only. The change is effective for the financial statements for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years, with early adoption permitted. The Partnership is required to apply the standard retrospectively to January 1, 2016. The Partnership has analyzed the accounting standard update and does not expect an impact on the consolidated financial statements.

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

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

In 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. Under the new guidance, the Partnership intends to continue estimating forfeiture rates to calculate compensation cost. The application of this accounting standard update will not have a material impact on the Partnership’s consolidated financial statements.

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

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 application of this accounting standard update will not have a material impact on the Partnership’s consolidated financial statements.

In May 2014, the FASB issued 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 currently evaluating the impact of the revenue recognition standard on the Partnership’s financial statements and disclosures, internal controls, and accounting policies. This evaluation process includes a phased approach, the first phase of which includes reviewing a sample of our contracts and transaction types across our segments. The Partnership is currently in the process of completing this first phase and evaluating the methods of adoption.

Based on the results of the first phase assessment to date, the Partnership has reached tentative conclusions for some contract types and does not believe revenue recognition patterns for fee-based or percent-of-proceeds contracts will change materially. The Partnership is currently working to understand the accounting impact on keep-whole and percent-of-liquids agreements under the new standard, specifically related to the accounting for noncash consideration received in the form of a commodity product. The Partnership does expect certain amounts to be grossed up in revenue as a result of implementation. The Partnership continues to work through implementation efforts and will provide updates as qualitative and quantitative conclusions are reached throughout 2017.

4. Acquisitions

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

On March 1, 2017, the Partnership entered into a Membership Interests Contributions Agreement (the “Contributions Agreement”) with MPLX GP LLC (the “General Partner”), MPLX Logistics Holdings LLC (“MPLX Logistics”), MPLX Holdings Inc. (“MPLX Holdings”) and MPC Investment LLC (“MPC Investment”). Pursuant to the Contributions Agreement, MPC Investment agreed to contribute the outstanding membership interests in HST, WHC and MPLXT through a series of intercompany contributions to the Partnership for approximately $1.5 billion in cash and equity consideration valued at approximately $504 million (the “Transaction”). The number of common units representing the equity consideration was determined by dividing the contribution amount by the simple average of the ten day trailing volume weighted average New York Stock Exchange price of a common unit for the ten trading days ending at market close on February 28, 2017. The fair value of the common and general partner units issued was approximately $503 million and consisted of (i) 9,197,900 common units representing limited partner interests in the Partnership to the General Partner, (ii) 2,630,427 common units to MPLX Logistics and (iii) 1,132,049 common units to MPLX Holdings. The Partnership also issued 264,497 general partner units to the General Partner in order to maintain its two percent general partner interest in the Partnership.

The Partnership’s combined consolidated financial statements includes periods prior to the acquisition of HST, WHC and MPLXT. MPC contributed the assets of HST, WHC and MPLXT to newly created and wholly-owned subsidiaries and entered into commercial agreements related to services provided by these new entities to MPC on January 1, 2015 for HST and WHC and April 1, 2016 for MPLXT. Prior to these dates, these entities were not considered businesses. The Partnership’s consolidated financial statements have been retrospectively recast for all periods to give effect to the acquisition of the HST and WHC as if the Transaction had occurred on January 1, 2015 and MPLXT as if the Transaction had occurred on April 1, 2016, as required for transactions between entities under common control.

In the following tables, information shown as Previously Reported means information disclosed in MPLX’s most recent Annual Report on Form 10-K for the year ended December 31, 2016, as filed with the SEC February 24, 2017.

The following table presents the Partnership’s previously reported Consolidated Statements of Income for the year ended December 31, 2016 retrospectively adjusted for the acquisition of HST, WHC and MPLXT:



	2016
(In millions, except per unit data)	MPLX LP (Previously Reported)			HST/WHC			MPLXT		Eliminations ⁽¹⁾			MPLX LP (Currently Reported)
Revenues and other income:
Service revenue	$	958		$	—		$	—	$	—		$	958
Service revenue - related parties	603			113			220		—			936
Rental income	298			—			—		—			298
Rental income - related parties	114			44			77		—			235
Product sales	572			—			—		—			572
Product sales - related parties	11			—			—		—			11
Gain on sale of assets	1			—			—		—			1
Loss from equity method investments	(74		)	—			—		—			(74		)
Other income	6			—			—		—			6
Other income - related parties	101			—			—		(15		)	86
Total revenues and other income	2,590			157			297		(15		)	3,029
Costs and expenses:
Cost of revenues (excludes items below)	354			37			63		—			454
Purchased product costs	448			—			—		—			448
Rental cost of sales	53			4			—		—			57
Rental cost of sales - related parties	—			2			—		(1		)	1
Purchases - related parties	316			19			67		(14		)	388
Depreciation and amortization	546			15			30		—			591
Impairment expense	130			—			—		—			130
General and administrative expenses	193			6			28		—			227
Other taxes	43			3			4		—			50
Total costs and expenses	2,083			86			192		(15		)	2,346
Income from operations	507			71			105		—			683
Related party interest and other financial income	1			(1		)	1		—			1
Interest expense (net of amounts capitalized of $28 million)	210			—			—		—			210
Other financial costs	50			—			—		—			50
Income before income taxes	246			72			104		—			422
Benefit for income taxes	(12		)	—			—		—			(12		)
Net income	258			72			104		—			434
Less: Net income attributable to noncontrolling interests	2			—			—		—			2
Less: Net income attributable to Predecessor	23			72			104		—			199
Net income attributable to MPLX LP	233			—			—		—			233
Less: Preferred units distributions	41			—			—		—			41
Less: General partner’s interest in net income attributable to MPLX LP	191			—			—		—			191
Limited partners’ interest in net income attributable to MPLX LP	$	1		$	—		$	—	$	—		$	1


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

The following table presents the Partnership’s previously reported Consolidated Statements of Income for the year ended December 31, 2015 retrospectively adjusted for the acquisition of HST and WHC:



	2015
(In millions, except per unit data)	MPLX LP (Previously Reported)		HST/WHC			Eliminations ⁽¹⁾			MPLX LP (Currently Reported)
Revenues and other income:
Service revenue	$	130	$	—		$	—		$	130
Service revenue - related parties	593		108			—			701
Rental income	20		—			—			20
Rental income - related parties	101		45			—			146
Product sales	36		—			—			36
Product sales - related parties	1		—			—			1
Income from equity method investments	3		—			—			3
Other income	6		—			—			6
Other income - related parties	71		—			(13		)	58
Total revenues and other income	961		153			(13		)	1,101
Costs and expenses:
Cost of revenues (excludes items below)	225		22			—			247
Purchased product costs	20		—			—			20
Rental cost of sales	5		6			—			11
Rental cost of sales - related parties	—		2			(1		)	1
Purchases - related parties	166		18			(12		)	172
Depreciation and amortization	116		13			—			129
Impairment expense	—		—			—			—
General and administrative expenses	118		7			—			125
Other taxes	13		2			—			15
Total costs and expenses	663		70			(13		)	720
Income from operations	298		83			—			381
Related party interest and other financial income	—		—			—			—
Interest expense (net of amounts capitalized of $5 million)	35		—			—			35
Other financial costs	13		(1		)	—			12
Income before income taxes	250		84			—			334
Provision for income taxes	1		—			—			1
Net income	249		84			—			333
Less: Net income attributable to noncontrolling interests	1		—			—			1
Less: Net income attributable to Predecessor	92		84			—			176
Net income attributable to MPLX LP	156		—			—			156
Less: General partner’s interest in net income attributable to MPLX LP	57		—			—			57
Limited partners’ interest in net income attributable to MPLX LP	$	99	$	—		$	—		$	99


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

The following table presents the Partnership’s previously reported Consolidated Balance Sheets as of December 31, 2016 retrospectively adjusted for the acquisition of HST, WHC and MPLXT:



	December 31, 2016
(In millions)	MPLX LP (Previously Reported)		HST/WHC		MPLXT		Eliminations ⁽¹⁾			MPLX LP (Currently Reported)
Assets
Current assets:
Cash and cash equivalents	$	234	$	—	$	—	$	—		$	234
Receivables, net	297		1		1		—			299
Receivables from related parties	122		91		38		(4		)	247
Inventories	54		1		—		—			55
Other current assets	33		—		—		—			33
Total current assets	740		93		39		(4		)	868
Equity method investments	2,467		—		4		—			2,471
Property, plant and equipment, net	10,730		265		413		—			11,408
Intangibles, net	492		—		—		—			492
Goodwill	2,199		25		21		—			2,245
Long-term receivables from related parties	4		—		7		—			11
Other noncurrent assets	14		—		—		—			14
Total assets	$	16,646	$	383	$	484	$	(4	)	$	17,509
Liabilities
Current liabilities:
Accounts payable	$	123	$	5	$	12	$	—		$	140
Accrued liabilities	228		4		—		—			232
Payables to related parties	75		4		12		(4		)	87
Deferred revenue	2		—		—		—			2
Deferred revenue - related parties	34		4		—		—			38
Accrued property, plant and equipment	132		9		5		—			146
Accrued taxes	33		2		3		—			38
Accrued interest payable	53		—		—		—			53
Other current liabilities	24		1		2		—			27
Total current liabilities	704		29		34		(4		)	763
Long-term deferred revenue	12		—		—		—			12
Long-term deferred revenue - related parties	15		—		4		—			19
Long-term debt	4,422		—		—		—			4,422
Deferred income taxes	5		—		1		—			6
Deferred credits and other liabilities	169		2		6		—			177
Total liabilities	5,327		31		45		(4		)	5,399
Redeemable preferred units	1,000		—		—		—			1,000
Equity
Common unitholders - public	8,086		—		—		—			8,086
Class B unitholders	133		—		—		—			133
Common unitholder - MPC	1,069		—		—		—			1,069
General partner - MPC	1,013		—		—		—			1,013
Equity of Predecessor	—		352		439		—			791
Total MPLX LP partners’ capital	10,301		352		439		—			11,092
Noncontrolling interest	18		—		—		—			18
Total equity	10,319		352		439		—			11,110
Total liabilities and equity	$	16,646	$	383	$	484	$	(4	)	$	17,509


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

The following table presents the Partnership’s previously reported Consolidated Balance Sheets as of December 31, 2015 retrospectively adjusted for the acquisition of HST and WHC:



	December 31, 2015
(In millions)	MPLX LP (Previously Reported)		HST/WHC		Eliminations ⁽¹⁾			MPLX LP (Currently Reported)
Assets
Current assets:
Cash and cash equivalents	$	43	$	—	$	—		$	43
Receivables, net	245		2		—			247
Receivables from related parties	187		56		(2		)	241
Inventories	51		1		—			52
Other current assets	50		1		—			51
Total current assets	576		60		(2		)	634
Equity method investments	2,458		—		—			2,458
Property, plant and equipment, net	9,997		217		—			10,214
Intangibles, net	466		—		—			466
Goodwill	2,570		25		—			2,595
Long-term receivables from related parties	25		—		—			25
Other noncurrent assets	12		—		—			12
Total assets	$	16,104	$	302	$	(2	)	$	16,404
Liabilities
Current liabilities:
Accounts payable	$	91	$	5	$	—		$	96
Accrued liabilities	187		2		—			189
Payables to related parties	54		4		(2		)	56
Deferred revenue - related parties	32		—		—			32
Accrued property, plant and equipment	168		6		—			174
Accrued taxes	27		1		—			28
Accrued interest payable	54		—		—			54
Other current liabilities	12		4		—			16
Total current liabilities	625		22		(2		)	645
Long-term deferred revenue	4		—		—			4
Long-term deferred revenue - related parties	9		—		—			9
Long-term debt	5,255		—		—			5,255
Deferred income taxes	378		—		—			378
Deferred credits and other liabilities	166		1		—			167
Total liabilities	6,437		23		(2		)	6,458
Equity
Common unitholders - public	7,691		—		—			7,691
Class B unitholders	266		—		—			266
Common unitholder - MPC	465		—		—			465
General partner - MPC	819		—		—			819
Equity of Predecessor	413		279		—			692
Total MPLX LP partners’ capital	9,654		279		—			9,933
Noncontrolling interest	13		—		—			13
Total equity	9,667		279		—			9,946
Total liabilities and equity	$	16,104	$	302	$	(2	)	$	16,404


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

The following table presents the Partnership’s previously reported Consolidated Statements of Cash Flows for the year ended December 31, 2016 retrospectively adjusted for the acquisition of HST, WHC and MPLXT:



	2016
(In millions)	MPLX LP (Previously Reported)			HST/WHC			MPLXT			MPLX LP (Currently Reported)
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	258		$	72		$	104		$	434
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred financing costs	46			—			—			46
Depreciation and amortization	546			15			30			591
Impairment expense	130			—			—			130
Deferred income taxes	(17		)	—			—			(17		)
Asset retirement expenditures	(5		)	(1		)	—			(6		)
Gain on disposal of assets	(1		)	—			—			(1		)
Loss from equity methods investments	74			—			—			74
Distributions from unconsolidated affiliates	148			—			—			148
Changes in:							—
Current receivables	(52		)	1			(1		)	(52		)
Inventories	(8		)	—			—			(8		)
Change in fair value of derivatives	43			—			—			43
Current accounts payable and accrued liabilities	100			—			2			102
Receivables from / liabilities to related parties	6			2			(27		)	(19		)
All other, net	20			5			1			26
Net cash provided by operating activities	1,288			94			109			1,491
Investing activities:
Additions to property, plant and equipment	(1,206		)	(60		)	(47		)	(1,313		)
Acquisitions, net of cash acquired	—			—			—			—
Investments - loans from related parties	77			(33		)	(61		)	(17		)
Disposal of assets	1			—			—			1
Investments in unconsolidated affiliates	(87		)	—			—			(87		)
All other, net	3			—			—			3
Net cash used in investing activities	(1,212		)	(93		)	(108		)	(1,413		)
Financing activities:
Long-term debt - borrowings	434			—			—			434
- repayments	(1,312		)	—			—			(1,312		)
Related party debt - borrowings	2,532			—			—			2,532
- repayments	(2,540		)	—			—			(2,540		)
Net proceeds from equity offerings	792			—			—			792
Issuance of redeemable preferred units	984			—			—			984
Distributions to preferred unitholders	(25		)	—			—			(25		)
Distributions to unitholders and general partner	(845		)	—			—			(845		)
Distributions to noncontrolling interests	(3		)	—			—			(3		)
Contributions from noncontrolling interests	6			—			—			6
Consideration payment to Class B unitholders	(25		)	—			—			(25		)
Contribution from MPC	225			—			—			225
Distributions to MPC from Predecessor	(104		)	—			—			(104		)
All other, net	(4		)	(1		)	(1		)	(6		)
Net cash provided by (used in) financing activities	115			(1		)	(1		)	113
Net increase in cash and cash equivalents	191			—			—			191
Cash and cash equivalents at beginning of period	43			—			—			43
Cash and cash equivalents at end of period	$	234		$	—		$	—		$	234

The following table presents the Partnership’s previously reported Consolidated Statements of Cash Flows for the year ended December 31, 2015 retrospectively adjusted for the acquisition of HST and WHC:



	2015
(In millions)	MPLX LP (Previously Reported)			HST/WHC			MPLX LP (Currently Reported)
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	249		$	84		$	333
Adjustments to reconcile net income to net cash provided by operating activities:
Amortization of deferred financing costs	5			—			5
Depreciation and amortization	116			13			129
Deferred income taxes	1			—			1
Asset retirement expenditures	(1		)	—			(1		)
Income from equity methods investments	(3		)	—			(3		)
Distributions from unconsolidated affiliates	15			—			15
Changes in:
Current receivables	(29		)	—			(29		)
Inventories	1			—			1
Change in fair value of derivatives	(6		)	—			(6		)
Current accounts payable and accrued liabilities	2			3			5
Receivables from / liabilities to related parties	(22		)	(12		)	(34		)
All other, net	12			(1		)	11
Net cash provided by operating activities	340			87			427
Investing activities:
Additions to property, plant and equipment	(288		)	(46		)	(334		)
Acquisitions, net of cash acquired	(1,218		)	—			(1,218		)
Investments - loans from related parties	(77		)	(41		)	(118		)
Investments in unconsolidated affiliates	(14		)	—			(14		)
All other, net	(2		)	—			(2		)
Net cash used in investing activities	(1,599		)	(87		)	(1,686		)
Financing activities:
Long-term debt - borrowings	1,490			—			1,490
- repayments	(1,441		)	—			(1,441		)
Related party debt - borrowings	301			—			301
- repayments	(293		)	—			(293		)
Debt issuance costs	(11		)	—			(11		)
Net proceeds from equity offerings	1			—			1
Issuance of units in MarkWest Merger	169			—			169
Contributions from MPC - MarkWest Merger	1,230			—			1,230
Distributions to unitholders and general partner	(158		)	—			(158		)
Distributions to noncontrolling interests	(1		)	—			(1		)
Contribution from MPC	1			—			1
Distributions related to purchase of additional interest in Pipe Line Holdings	(12		)	—			(12		)
All other, net	(1		)	—			(1		)
Net cash provided by financing activities	1,275			—			1,275
Net increase in cash and cash equivalents	16			—			16
Cash and cash equivalents at beginning of period	27			—			27
Cash and cash equivalents at end of period	$	43		$	—		$	43

Acquisition of Xxxxxx Street Marine LLC

On March 14, 2016, the Partnership entered into a Membership Interests Contribution Agreement (the “Contribution Agreement”) with the General Partner, MPLX Logistics and MPC Investment, each a wholly-owned subsidiary of MPC, related to the acquisition of HSM, MPC’s inland marine business, from MPC. Pursuant to the Contribution Agreement, the transaction was valued at $600 million, consisting of a fixed number of common units and general partner units of 22,534,002 and 459,878, respectively. The general partner units maintain MPC’s two percent 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 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 Partnership has retrospectively adjusted the historical financial results for all periods to include HSM.

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 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 December 31, 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 18, 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 18.

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 year ended December 31, 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 complimentary 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 Partnership recognized $36 million of acquisition-related costs associated with the MarkWest Merger. These costs were expensed, with $30 million included in General and administrative expenses and $6 million included in Other financial costs.

The fair value of the common units issued was determined on the basis of the closing market price of the Partnership’s units as of the effective time of the transaction and is considered a Level 1 measurement. The fair value of the Class B units issued was determined based on reference to the value of the common units, adjusted for a lack of distributions prior to their stated conversion dates, and is considered a Level 2 measurement. The fair values of the long-term debt and SMR liabilities were determined as of the acquisition date using the methods discussed in Note 15.

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 Xxxxxx 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 in the Consolidated Statements of Income for 2015 are as follows:



(In millions)	2015
Revenues and other income	$	126
Income from operations	32

Unaudited Pro Forma Financial Information

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



(In millions, except per unit data)	2015		2014
Revenues and other income	$	2,817	$	2,972
Net income attributable to MPLX LP	228		330
Net income attributable to MPLX LP per unit - basic	0.47		1.09
Net income attributable to MPLX LP per unit - diluted	0.45		1.03

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 for the years ended December 31, 2015 and 2014, respectively. MarkWest Utica EMG’s inability to fund its planned activities without subordinated financial support qualify it as a VIE. The financing structure for MarkWest Utica EMG at its inception resulted in a de-facto agent relationship under which MarkWest was deemed to be the primary beneficiary of MarkWest Utica EMG. Therefore, MarkWest consolidated MarkWest Utica EMG in its historical financial statements. In the fourth quarter of 2015, based on economic conditions and other pertinent factors, the accounting for its investment in MarkWest Utica EMG was re-assessed. As of December 4, 2015, the entity has been deconsolidated. For purposes of this pro forma financial information, MarkWest Utica EMG has been consolidated for the period prior to the acquisition consistent with its treatment in the historical periods presented.

A summary of the amounts included in the historical financial statements of MarkWest for the year ended December 31, 2014 and the period from January 1, 2015 through December 3, 2015 related to MarkWest Utica EMG are as follows:



(in millions)	2015			2014
Revenue and other income	$	152		$	85
Cost of revenue excluding depreciation and amortization	27			48
Depreciation and amortization	61			50
Net income attributable to noncontrolling interest	64			31
Net loss	(5		)	(46		)

EMG Utica, LLC (“EMG Utica”), a joint venture partner in MarkWest Utica EMG, received a special non-cash allocation of income of approximately $41 million and $37 million for the period from January 1, 2015 through December 3, 2015 and the year ended December 31, 2014, respectively. See Note 5 for a description of the transaction and its impact on the financial statements. Net income of MarkWest would not have changed had MarkWest Utica EMG been deconsolidated for the year ended December 31, 2014 and the period from January 1, 2015 through December 3, 2015.

Purchases of Pipe Line Holdings

Effective December 4, 2015, the Partnership purchased the remaining 0.5 percent interest in Pipe Line Holdings from subsidiaries of MPC for consideration of $12 million. This resulted in Pipe Line Holdings becoming a wholly-owned subsidiary of the Partnership. The Partnership recorded the 0.5 percent interest at its historical carrying value of $6 million and the excess cash paid and equity contributed over historical carrying value of $6 million as a decrease to general partner equity. Prior to this transaction, the 0.5 percent interest was held by MPC and was reflected as the noncontrolling interest retained by MPC in the consolidated financial statements.

Effective December 1, 2014, the Partnership purchased a 22.875 percent interest in Pipe Line Holdings from subsidiaries of MPC for consideration of $600 million, which was financed through borrowings under our bank revolving credit facility, as discussed in Note 17. In addition, the Partnership accepted a contribution of 7.625 percent of outstanding partnership interests of Pipe Line Holdings from subsidiaries of MPC in exchange for the issuance of equity valued at $200 million, as discussed in Note 8. The Partnership recorded the combined 30.5 percent interest at its historical carrying value of $335 million and the excess cash paid and equity contributed over historical carrying value of $465 million as a decrease to general partner equity. Prior to this transaction, the 30.5 percent interest was held by MPC and was reflected as part of the noncontrolling interest retained by MPC in the consolidated financial statements. Beginning December 1, 2014, the consolidated financial statements reflect the 99.5 percent general partner interest in Pipe Line Holdings owned by MPLX LP, while the 0.5 percent limited partner interest held by MPC is reflected as a noncontrolling interest.

On March 1, 2014, the Partnership acquired a 13 percent interest in Pipe Line Holdings from MPC for consideration of $310 million, which was funded with $40 million of cash on hand and $270 million of borrowings on the bank revolving credit facility. The Partnership recorded the 13 percent interest in Pipe Line Holdings at its historical carrying value of $138 million and the excess cash paid over historical carrying value of $172 million as a decrease to general partner equity.

In addition, on May 1, 2013, the Partnership acquired a five percent interest in Pipe Line Holdings from MPC for consideration of $100 million, which was funded with cash on hand. The Partnership recorded the five percent interest in Pipe Line Holdings at its historical carrying value of $54 million and the excess cash paid over historical carrying value of $46 million as a decrease to general partner equity.

These acquisitions were accounted for on a prospective basis and the terms of the acquisitions were approved by the conflicts committee of the board of directors of the general partner, which is comprised entirely of independent directors.

Changes in MPLX LP’s equity resulting from changes in its ownership interest in Pipe Line Holdings were as follows:



(In millions)	2015			2014
Net income attributable to MPLX LP	$	156		$	121
Transfer to noncontrolling interest:
Decrease in general partner-MPC equity for purchases of additional interest in Pipe Line Holdings	(6		)	(638		)
Change from net income attributable to MPLX LP and transfer to noncontrolling interest	$	150		$	(517	)

5. 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 December 31, 2016, EMG Utica has contributed $1 billion and Utica Operating has contributed approximately $1.5 billion to MarkWest Utica EMG.

Under the Amended LLC Agreement, after EMG Utica has contributed more than $500 million to MarkWest Utica EMG and prior to December 31, 2016, EMG Utica’s investment balance will also be 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 $16 million and approximately $4 million for the year ended December 31, 2016 and for the 28 days ended December 31, 2015, respectively.

Under the Amended LLC Agreement, Utica Operating continued to receive 60 percent of cash generated by MarkWest Utica EMG that was available for distribution until the earlier of December 31, 2016 or the date on which Utica Operating’s investment balance equaled 60 percent of the aggregate investment balances of the Members. After December 31, 2016, cash generated by MarkWest Utica EMG that is available for distribution will be allocated to the Members in proportion to their respective investment balances. As of December 31, 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 December 31, 2016 and 2015, respectively, is reported under the caption Equity Method Investments on the Consolidated Balance Sheets. The Partnership’s maximum exposure to loss as a result of its involvement with MarkWest Utica EMG includes its equity investment, any additional capital contribution commitments and any operating expenses incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. The Partnership did not provide any financial support to MarkWest Utica EMG that it was not contractually obligated to provide during the year ended December 31, 2016 and the 28 days ended December 31, 2015. The Partnership receives management fee revenue for engineering and construction and administrative services for operating MarkWest Utica EMG, and is also reimbursed for personnel services (“Operational Service” revenue). The amount of Operational Service revenue related to MarkWest Utica EMG for the year ended December 31, 2016 and for the 28 days ended December 31, 2015 was $16 million and less than $1 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 of December 31, 2016, we have a 34 percent indirect ownership interest in Ohio Gathering. As Ohio Gathering is a subsidiary of MarkWest Utica EMG, which is accounted for as an equity method investment, the Partnership reports its portion of Ohio Gathering’s net assets as a component of its investment in MarkWest Utica EMG. The Partnership receives Operational Service revenue for operating Ohio Gathering. The amount of Operational Service revenue related to Ohio Gathering for the year ended December 31, 2016 and the 28 days ended December 31, 2015 was approximately $15 million and $2 million, respectively, and is reported as Other income - related parties in the Consolidated Statements of Income.

Ohio Condensate

Ohio Condensate is a joint venture between MarkWest Utica EMG Condensate, L.L.C., a wholly-owned and consolidated subsidiary of MarkWest, and Summit formed for the purpose of gathering (by pipeline), stabilization, terminalling, transportation and storage of well-head condensate within certain defined areas in the state of Ohio. 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, which was $10 million and $100 million at December 31, 2016 and 2015, respectively, 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 year ended December 31, 2016 and the 28 days ended December 31, 2015 was $4 million and less than $1 million, respectively, and is reported as Other income - related parties in the Consolidated Statements of Income.

Summarized financial information for the year ended December 31, 2016 and from the date of the MarkWest Merger through December 31, 2015 for equity method investments is as follows:



	Year Ended December 31, 2016
(In millions)	MarkWest Utica EMG		Ohio Condensate			Other VIEs		Non-VIEs		Total
Revenue and other income	$	216	$	15		$	3	$	148	$	382
Cost and expenses	100		110			1		117		328
Income (loss) from operations	116		(95		)	2		31		54
Net income (loss)	114		(95		)	2		31		52
Income (loss) from equity method investments⁽²⁾	8		(89		)	—		7		(74		)



	Year Ended December 31, 2015
(In millions)	MarkWest Utica EMG		Ohio Condensate		Other VIEs		Non-VIEs		Total
Revenue and other income	$	18	$	2	$	—	$	9	$	29
Cost and expenses	9		2		—		8		19
Income from operations	9		—		—		1		10
Net income	10		—		—		1		11
Income from equity method investments⁽²⁾	2		1		—		—		3

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



	December 31, 2016
(In millions)	MarkWest Utica EMG ⁽¹⁾		Ohio Condensate		Other VIEs		Non-VIEs		Total
Current assets	$	45	$	2	$	—	$	40	$	87
Noncurrent assets	2,173		30		102		390		2,695
Current liabilities	30		3		1		26		60
Noncurrent liabilities	2		13		—		—		15



	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 $794 million and $781 million as of December 31, 2016 and 2015, respectively.


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

As of December 31, 2016 and 2015, the carrying value of our equity method investments was $1.1 billion and $961 million, respectively, higher than the underlying net assets of investees. This basis difference is being amortized or accreted into net income over the remaining estimated useful lives of the underlying net assets, except for $459 million of excess related to goodwill as of December 31, 2016.

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 (Loss) income 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 (Loss) income 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.

6. 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 56 percent interest as of December 31, 2016. MarkWest Utica EMG is engaged in significant natural gas processing and NGL fractionation, transportation and marketing in the state of Ohio.


•	Ohio Gathering, in which MPLX LP has a 34 percent indirect interest as of December 31, 2016. Ohio Gathering is a subsidiary of MarkWest Utica EMG providing natural gas gathering service in the Utica Shale region of eastern 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.

Commercial Agreements

The Partnership has various long-term, fee-based transportation services and storage services agreements with MPC. Under these long term, fee based agreements, the Partnership provides transportation and storage services to MPC, and MPC has committed to provide the Partnership with minimum quarterly throughput volumes on crude oil and products systems and minimum storage volumes of crude oil, products and butane. The Partnership believes the terms and conditions under these agreements, as well as the initial agreements with MPC described below, are generally no less favorable to either party than those that could have been negotiated with unaffiliated parties with respect to similar services.

The commercial agreements with MPC include:


•	three separate 10-year transportation services agreements and one five-year transportation services agreement under which MPC pays the Partnership fees for transporting crude oil on various of our crude oil pipeline systems;


•	four separate 10-year transportation services agreements under which MPC pays the Partnership fees for transporting products on each of our refined product pipeline systems;


•	a 10-year transportation services agreement under which MPC pays the Partnership fees for transporting crude oil and refined products various of our crude oil and refined product pipeline systems;


•	a 10-year terminal services agreement under which MPC pays the Partnership fees for terminal storage for refined products


•	a five-year transportation services agreement under which MPC pays the Partnership fees for handling crude oil and products at our Wood River, Illinois barge dock;


•	two separate 10-year storage services agreements under which MPC pays the Partnership fees for providing storage services at our Xxxx, West Xxxxxxxx butane cavern and Woodhaven, Michigan LPG caverns;


•	five separate three-year storage services agreements under which MPC pays the Partnership fees for providing storage services at our tank farms; and


•	a six-year transportation services agreement under which MPC pays the Partnership fees for providing marine transportation of crude oil, feedstocks and refined petroleum products, and related services.

All of the transportation services agreements and the terminal services agreement with MPC include automatic renewal terms ranging from two to five years, unless terminated by either party. The Partnership’s butane cavern storage services agreement with MPC does not automatically renew. The storage services agreements with MPC for the Partnership’s tank farms automatically renew for additional one-year terms unless terminated by either party.

Under all of our transportation services agreements, except for our marine agreement, if MPC fails to transport its minimum throughput volumes during any quarter, then MPC will pay us a deficiency payment equal to the volume of the deficiency multiplied by the tariff rate then in effect (the “Quarterly Deficiency Payment”). Under these transportation services agreements, the amount of any Quarterly Deficiency Payment paid by MPC may be applied as a credit for any volumes transported on the applicable pipeline system in excess of MPC’s minimum volume commitment during any of the succeeding four quarters, or eight quarters in the case of the transportation services agreements covering our Wood River to Patoka crude system and our Wood River barge dock, after which time any unused credits will expire. Upon the expiration or termination of a transportation services agreement, MPC will have the opportunity to apply any such remaining credit amounts until the completion of any such four-quarter or eight-quarter period, as applicable. Any such remaining credits may be used against any volumes shipped by MPC on the applicable pipeline system, without regard to any minimum volume commitment that may have been in place during the term of the agreement.

Under the terminal services agreement, MPC pays the Partnership monthly based on contractual fees relating to MPC product deliveries as well as any viscosity surcharges, loading, handling, transfers or other related charges. If MPC fails to meet its quarterly minimum volume throughput commitments, MPC will pay a deficiency payment equal to the volume of the deficiency multiplied by the rate then in effect. If the average daily capacity of a terminal falls below the level of MPC’s commitment during a quarter, depending on the cause of the reduction in capacity, MPC’s throughput commitment will be reduced to equal the average daily capacity available during such quarter.

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

On January 1, 2015, HSM entered into a long-term, fee-based transportation services agreement with MPC for a period of six years. Under the agreement, the Partnership 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. On the anniversary of the contract, pursuant to the amended and restated fee-based transportation services agreement effective July 1, 2015, the day rates and charges for services related to transportation are adjusted for inflation. Prior to January 1, 2015, this agreement did not exist.

On January 1, 2015, MPC conveyed various operating leases to HSM for third-party barges and fleeting property within the states of Indiana, Kentucky, Louisiana, Ohio and West Virginia in which MPC was either the lessor or lessee.

Operating Agreements

The Partnership operates various pipeline systems owned by MPC under operating services agreements. Under these operating services agreements, the Partnership receives an operating fee for operating the assets and is reimbursed for all direct and indirect costs associated with operating the assets. Most of these agreements are indexed for inflation. These agreements range from one to five years in length and automatically renew unless terminated by either party.

Management Services Agreements

The Partnership has two management services agreements with MPC under which it provides management services to MPC with respect to certain of MPC’s retained pipeline assets. The Partnership may adjust annually for inflation and based on changes in the scope of management services provided.

The Partnership also receives engineering and construction and administrative management fee revenue and other direct personnel costs for operating some joint venture entities.

The Partnership, through its subsidiary, HSM, has a management services agreement with MPC under which it provides management services to assist MPC in the oversight and management of the marine business. HSM receives a fixed annual fee 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. This agreement expires on June 30, 2020.

Omnibus Agreement

The Partnership has an omnibus agreement with MPC that addresses its payment of a fixed annual fee to MPC for the provision of executive management services by certain executive officers of the general partner and the Partnership’s reimbursement of MPC for the provision of certain general and administrative services to it. It also provides for MPC’s indemnification of the Partnership for certain matters, including environmental, title and tax matters; as well as our indemnification of MPC for certain matters under this agreement.

Employee Services Agreements

The Partnership has five employee services agreements with MPC under which the Partnership reimburses MPC for employee benefit expenses, along with the provision of operational and management services in support of both our L&S and G&P segments’ operations.

Loan Agreements

On December 4, 2015, the Partnership entered into a loan agreement with MPC Investment LLC (“MPC Investment”), a wholly-owned subsidiary of MPC. Under the terms of the agreement, MPC Investment will make a loan or loans to the Partnership on a revolving basis as requested by the Partnership and as agreed to by MPC Investment, in an amount or amounts that do not result in the aggregate principal amount of all loans outstanding exceeding $500 million at any one time. The entire unpaid principal amount of the loan, together with all accrued and unpaid interest and other amounts (if any), shall become due and payable on December 4, 2020. MPC Investment may demand payment of all or any portion of the outstanding principal amount of the loan, together with all accrued and unpaid interest and other amounts (if any), at any time prior to December 4,

2020. Borrowings under the loan will bear interest at LIBOR plus 1.50 percent. Borrowings were at an average interest rate of 1.939 percent and 1.744 percent, per annum for 2016 and 2015, respectively. In connection with this loan agreement, the Partnership terminated the previous revolving credit agreement of $50 million with MPC, effective December 31, 2015.

During 2016, the Partnership borrowed $2.5 billion and repaid $2.5 billion, resulting in no outstanding balance at December 31, 2016. During 2015, the Partnership borrowed $301 million and repaid $293 million, for an outstanding balance at December 31, 2015 of $8 million, which is included in Payables to related parties on the Consolidated Balance Sheets.

Related Party Transactions

The Partnership believes that transactions with related parties were conducted on terms comparable to those with unrelated parties. Related party sales to MPC consisted of crude oil and refined products pipeline transportation services based on regulated tariff rates and storage services based on contracted rates. Related party sales to MPC also consist of revenue related to volume deficiency credits.

Revenue received from related parties related to service and product sales were as follows:



(In millions)	2016		2015		2014
Service revenue
MPC	$	936	$	701	$	662
Rental income
MPC	$	235	$	146	$	15
Product sales ⁽¹⁾
MPC	$	11	$	1	$	—


(1)	For 2016 and 2015, there were $46 million and $1 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. There were no such transactions in 2014.

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 on the Consolidated Balance Sheets. MPC may then apply the amount of any such deficiency payments as a credit for volumes transported on the applicable pipeline system in excess of its minimum volume commitment during the following four or eight quarters under the terms of the applicable transportation services agreement. The Partnership recognizes revenues for the deficiency payments when credits are used for volumes transported in excess of minimum quarterly volume commitments, when it becomes impossible to physically transport volumes necessary to utilize the credits or upon the expiration of the credits. The use or expiration of the credits is a decrease in Deferred revenue-related parties.

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



(In millions)	2016		2015		2014
MPC	$	45	$	55	$	39
MarkWest Utica EMG	16		—		—
Centennial	1		1		1
Ohio Gathering	15		2		—
Ohio Condensate	4		—		—
Other	5		—		—
Total	$	86	$	58	$	40

MPC provides executive management services and certain general and administrative services to the Partnership under the terms of the omnibus agreement. Expenses incurred under these agreements are shown in the table below by the income

statement line where they were recorded. These expenses also include similar charges incurred by HSM for the time period prior to the acquisition and therefore not covered by the omnibus agreement. Charges for services included in Purchases from related parties primarily relate to services that support the Partnership’s operations and maintenance activities, as well as compensation expenses. Charges for services included in General and administrative expenses primarily relate to services that support the Partnership’s executive management, accounting and human resources activities. These charges were as follows:



(In millions)	2016		2015		2014
Purchases from related parties	$	39	$	32	$	30
General and administrative expenses	45		53		46
Total	$	84	$	85	$	76

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



(In millions)	2016		2015		2014
MPC	$	47	$	16	$	8

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

Employee services expenses from related parties were as follows:



(In millions)	2016		2015		2014
Purchases - related parties	$	349	$	140	$	123
General and administrative expenses	100		22		24
Total	$	449	$	162	$	147

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:



	December 31,
(In millions)	2016		2015
MPC	$	242	$	229
MarkWest Utica EMG	2		4
Ohio Gathering	2		5
Other	1		3
Total	$	247	$	241

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:



	December 31,
(In millions)	2016		2015
MPC	$	11	$	25

Payables to related parties were as follows:



	December 31,
(In millions)	2016		2015
MPC	$	63	$	35
MarkWest Utica EMG	24		21
Total	$	87	$	56

In recent years, 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:



	December 31,
(In millions)	2016		2015
Minimum volume deficiencies - MPC	$	48	$	36
Project reimbursements - MPC	9		5
Total	$	57	$	41

7. 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 attributable to MPLX LP by the weighted average number of common units and subordinated units outstanding. Because the Partnership has more than one class of participating securities, it uses the two-class method when calculating the net income per unit applicable to limited partners. The classes of participating securities include common units, subordinated units, general partner units, Preferred units, certain equity-based compensation awards and incentive distribution rights.

The HSM, HST, WHC and MPLXT acquisitions were transfers 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, HST, WHC and MPLXT will be included in the net income (loss) per unit calculation prospectively as described above.

As discussed further in Note 8, the subordinated units, all of which were owned by MPC, were converted into common units during the third quarter of 2015. For purposes of calculating net income (loss) per unit, the subordinated units were treated as if they converted to common units on July 1, 2015.

In 2016 and 2015, the Partnership had dilutive potential common units consisting of certain equity-based compensation awards and Class B units. Diluted net income per limited partner unit for the 2014 reporting period is the same as basic net income per limited partner unit as there were no potentially dilutive common or subordinated units outstanding as of December 31, 2014.



(In millions)	2016			2015			2014
Net income attributable to MPLX LP	$	233		$	156		$	121
Less: Distributions declared on Preferred units⁽¹⁾	41			—			—
General partner’s distributions declared (including IDRs)⁽¹⁾	205			60			6
Limited partners’ distributions declared on common units⁽¹⁾	692			224			54
Limited partner’s distributions declared on subordinated units⁽¹⁾	—			31			52
Undistributed net (loss) income attributable to MPLX LP	$	(705	)	$	(159	)	$	9


(1)	See Note 8 for information regarding the distribution.



	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)	$	205		$	692		$	41	$	938
Undistributed net loss attributable to MPLX LP	(14		)	(691		)	—		(705		)
Net income attributable to MPLX LP⁽¹⁾	$	191		$	1		$	41	$	233
Weighted average units outstanding:
Basic	7			331					338
Diluted	7			338					345
Net income attributable to MPLX LP per limited partner unit:
Basic				$	—
Diluted				$	—



	2015
(In millions, except per-unit data)	General Partner			Limited Partners’ Common Units			Limited Partner’s Subordinated Units			Total
Basic and diluted net income attributable to MPLX LP per unit:
Net income attributable to MPLX LP:
Distributions declared (including IDRs)	$	60		$	224		$	31		$	315
Undistributed net loss attributable to MPLX LP	(3		)	(127		)	(29		)	(159		)
Net income attributable to MPLX LP⁽¹⁾	$	57		$	97		$	2		$	156
Weighted average units outstanding:
Basic	2			79			18			99
Diluted	2			80			18			100
Net income attributable to MPLX LP per limited partner unit:
Basic				$	1.23		$	0.11
Diluted				$	1.22		$	0.11



	2014
(In millions, except per-unit data)	General Partner		Limited Partners’ Common Units		Limited Partner’s Subordinated Units		Total
Basic and diluted net income attributable to MPLX LP per unit:
Net income attributable to MPLX LP:
Distribution declared	$	6	$	54	$	52	$	112
Undistributed net income attributable to MPLX LP	2		4		3		9
Net income attributable to MPLX LP⁽¹⁾	$	8	$	58	$	55	$	121
Weighted average units outstanding:
Basic	2		37		37		76
Diluted	2		37		37		76
Net income attributable to MPLX LP per limited partner unit:
Basic			$	1.55	$	1.50
Diluted			$	1.55	$	1.50


(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.

8. Equity

Units Outstanding – The Partnership had 357,193,288 common units outstanding as of December 31, 2016. Of that number, 86,619,313 were owned by MPC, which also owned the two percent general partner interest, represented by 7,371,105 general partner units.

Subordinated Unit Conversion – 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.

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, all of the issued and outstanding MPLX LP Class A units, all of which were held by MarkWest Hydrocarbon, were either distributed to or purchased by MPC in exchange for $84 million in cash, 21,401,137 MPLX LP common units and 436,758 MPLX LP general partner units. Following these initial transactions, all of the MPLX LP Class A units were exchanged on a one-for-one basis for newly issued common units representing limited partner interests in MPLX LP. MPC also contributed $141 million to facilitate the repayment of intercompany debt between MarkWest Hydrocarbon and MarkWest. As a result of these transactions, the MPLX LP Class A units were eliminated, are no longer outstanding and no longer participate in distributions of cash from the Partnership. Cash that is derived from or attributable to MarkWest Hydrocarbon’s operations is now treated in the same manner as cash derived from or attributable to other operations of the Partnership and its subsidiaries.

MarkWest Merger – On December 4, 2015, the Partnership completed the MarkWest Merger. As defined in the merger agreement, each common unit of MarkWest issued and outstanding at the effective time of the MarkWest Merger was converted into the right to receive 1.09 common units of MPLX LP. This resulted in the issuance of 216,350,465 common units. The Class A units of MarkWest outstanding immediately prior to the MarkWest Merger were converted into 28,554,313 Class A units of MPLX LP having substantially similar rights and obligations that the Class A units of MarkWest had immediately prior to the combination. Each Class B unit of MarkWest outstanding had immediately prior to the merger converted into the right to receive one Class B unit of MPLX LP having substantially similar rights, including conversion and registration rights, and obligations that the Class B units of MarkWest had immediately prior to the merger. This resulted in the issuance of 7,981,756 MPLX LP Class B units. Each Class B unit of MPLX LP will automatically convert into 1.09 MPLX LP common units and the right to receive $6.20 in cash in equal installments, the first of which occurred on July 1, 2016 and the second of which will occur on July 1, 2017.

ATM Program – On August 4, 2016, the Partnership entered into a second amended and restated distribution agreement (the “Distribution Agreement”) providing for the continuous issuance of common units, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of our offerings (such continuous offering program, or at-the-market program is referred to as our “ATM Program”). The Partnership expects the net proceeds from sales under the ATM Program will be used for general partnership purposes, including repayment or refinancing of debt, and funding for acquisitions, working capital requirements and capital expenditures. During the year ended December 31, 2015, the Partnership issued an aggregate of 25,166 common units under our ATM Program, generating net proceeds of approximately $1 million. During the year ended December 31, 2016, the Partnership issued an aggregate of 26,347,887 common units under the ATM Program generating net proceeds of approximately $776 million. As of December 31, 2016, $717 million of common units remains available for issuance through the ATM program under the Distribution Agreement.

The table below summarizes the changes in the number of units outstanding for the years ended December 31, 2014, 2015, and 2016:



(In units)	Common	Class B		Subordinated		General Partner		Total
Balance at December 31, 2013	36,951,515	—		36,951,515		1,508,225		75,411,255
Unit-based compensation awards	15,479	—		—		316		15,795
Contribution of interest in Pipe Line Holdings	2,924,104	—		—		59,676		2,983,780
December 2014 equity offering	3,450,000	—		—		70,408		3,520,408
Balance at December 31, 2014	43,341,098	—		36,951,515		1,638,625		81,931,238
Unit-based compensation awards	18,932	—		—		386		19,318
Issuance of units under the ATM program	25,166	—		—		514		25,680
Subordinated unit conversion	36,951,515	—		(36,951,515	)	—		—
MarkWest Merger	216,350,465	7,981,756		—		5,160,950		229,493,171
Balance at December 31, 2015	296,687,176	7,981,756		—		6,800,475		311,469,407
Unit-based compensation awards	120,989	—		—		2,470		123,459
Issuance of units under the ATM Program	26,347,887	—		—		537,710		26,885,597
Contribution of HSM (See Note 4)	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 December 31, 2016	357,193,288	3,990,878		—		7,371,105		368,555,271

2016 Activity

On July 1, 2016, 3,990,878 Class B units converted to 4,350,057 common units and received the second quarter distribution. 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.

As a result of the unit-based compensation awards issued during the period, MPLX GP contributed less than $1 million in exchange for 2,470 general partner units to maintain its two percent general partner interest.

As a result of common units issued under the ATM Program during the period, MPLX GP contributed $16 million in exchange for 537,710 general partner units to maintain its two percent general partner interest.

In connection with 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 LP general partner units held by MPLX GP, as discussed above.

2015 Activity

As a result of common units issued under the ATM Program during 2015, MPLX GP contributed less than $1 million in exchange for 514 general partner units to maintain its two percent general partner interest.

In connection with the MarkWest Xxxxxx discussed in Note 4, MPLX GP contributed $169 million in exchange for 5,160,950 general partner units to maintain its two percent general partner interest.

2014 Activity

Effective December 1, 2014, as discussed in Note 4, the Partnership accepted a contribution of 7.625 percent of outstanding partnership interests of Pipe Line Holdings from subsidiaries of MPC in exchange for the issuance of equity valued at $200 million. The equity consideration consisted of 2,924,104 MPLX LP common units and was calculated by dividing $200 million by the average closing price for MPLX LP common units for the ten trading days preceding December 1, 2014, which was $68.397.

On December 8, 2014, the Partnership closed an equity offering of 3,450,000 common units at a public offering price of $66.68 per unit. The Partnership used the net proceeds of $221 million to repay borrowings under its revolving credit facility and for general partnership purposes.

As a result of the contribution mentioned above and the December 2014 equity offering, MPLX GP contributed $9 million in exchange for 130,084 general partner units to maintain its two percent general partnership interest.

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

Incentive Distribution Rights – The following table illustrates the percentage allocations of available cash from operating surplus between the common and subordinated unitholders and the general partner based on the specified target distribution levels. The amounts set forth under “Marginal percentage interest in distributions” are the percentage interests of the general partner and common and subordinated unitholders in any available cash from operating surplus the Partnership distributes up to and including the corresponding amount in the column “Total quarterly distribution per unit target amount.” The percentage interests shown for its common and subordinated unitholders and the general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for the general partner include its two percent general partner interest and assume that the general partner has contributed any additional capital necessary to maintain its two percent general partner interest, the general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.

Net Income Allocation – In preparing the Consolidated Statements of Equity, net income (loss) attributable to MPLX LP is allocated to Preferred unitholders based on a fixed distribution schedule, as discussed in Note 9, and subsequently allocated to the general partner and limited partner unitholders. However, when distributions related to the incentive distribution rights are made, earnings equal to the amount of those distributions are first allocated to the general partner before the remaining earnings are allocated to the limited partner unitholders based on their respective ownership percentages. The following table presents the allocation of the general partner’s interest in net income attributable to MPLX LP:



(In millions)	2016		2015		2014
Net income attributable to MPLX LP	$	233	$	156	$	121
Less: Preferred unit distributions	41		—		—
General partner's incentive distribution rights and other	191		55		4
Net income attributable to MPLX LP available to general and limited partners	$	1	$	101	$	117

General partner's two percent interest in net income attributable to MPLX LP	$	—	$	2	$	2
General partner's incentive distribution rights and other	191		55		4
General partner's interest in net income attributable to MPLX LP	$	191	$	57	$	6

Cash distributions – The partnership agreement sets forth the calculation to be used to determine the amount and priority of cash distributions that the common unitholders and general partner will receive. In accordance with the partnership agreement, on January 25, 2017, the Partnership declared a quarterly cash distribution, based on the results of the fourth quarter of 2016, totaling $242 million, or $0.5200 per unit. This distribution was paid on February 14, 2017 to unitholders of record on February 6, 2017. See the table below for the IDR impact for 2016.

The allocation of total quarterly cash distributions to general, limited, and Preferred unitholders is as follows for the years ended December 31, 2016, 2015 and 2014. The distributions are declared subsequent to quarter end; therefore, the following table represents total cash distributions applicable to the period in which the distributions were earned.



(In millions)	2016		2015		2014
General partner's distributions:
General partner's distributions	$	18	$	6	$	2
General partner's incentive distribution rights distributions	187		54		4
Total general partner's distributions	205		60		6
Limited partners' distributions:
Common unitholders	692		224		54
Subordinated unitholders	—		31		52
Total limited partners' distributions	692		255		106
Preferred unit distributions	41		—		—
Total cash distributions declared	$	938	$	315	$	112

9. Redeemable Preferred Units

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

The Preferred units rank senior to all common units with respect to distributions and rights upon liquidation. The holders of the Preferred units are entitled to receive cumulative quarterly distributions equal to $0.528125 per unit 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 unitholders’ 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 December 31, 2016	41
Distributions received by Preferred unitholders	(25		)
Balance at December 31, 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.

10. 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, stores and distributes crude oil and refined petroleum products. Segment information for prior periods includes HST, WHC and MPLXT as they are entities under common control.


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

The Partnership has investments in entities that are accounted for using the equity method of accounting (see Note 5). However, the CEO views 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 (losses) gains, property, plant and equipment, goodwill impairment and depreciation and amortization are not allocated to the reportable segments. Management does not consider these items allocable to or controllable by any individual segment and, therefore, excludes these items when evaluating segment performance. Segment results are also adjusted to exclude the portion of income from operations attributable to the noncontrolling interests related to partially-owned entities that are either consolidated or accounted for as equity method investments. Segment operating income attributable to MPLX LP excludes the operating income related to the Predecessors of the HSM, HST, WHC and MPLXT businesses, prior to the dates they were acquired by MPLX.

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



	2016
(In millions)	L&S		G&P		Total
Revenues and other income:
Segment revenues	$	1,241	$	2,185	$	3,426
Segment other income	53		1		54
Total segment revenues and other income	1,294		2,186		3,480
Costs and expenses:
Segment cost of revenues	552		907		1,459
Segment operating income before portion attributable to noncontrolling interest and Predecessor	742		1,279		2,021
Segment portion attributable to noncontrolling interest and Predecessor	289		147		436
Segment operating income attributable to MPLX LP	$	453	$	1,132	$	1,585



	2015
(In millions)	L&S		G&P		Total
Revenues and other income:
Segment revenues	$	913	$	150	$	1,063
Segment other income	62		—		62
Total segment revenues and other income	975		150		1,125
Costs and expenses:
Segment cost of revenues	416		62		478
Segment operating income before portion attributable to noncontrolling interest and Predecessor	559		88		647
Segment portion attributable to noncontrolling interest and Predecessor	237		12		249
Segment operating income attributable to MPLX LP	$	322	$	76	$	398



	2014
(In millions)	L&S
Revenues and other income:
Segment revenues	$	747
Segment other income	46
Total segment revenues and other income	793
Costs and expenses:
Segment cost of revenues	392
Segment operating income before portion attributable to noncontrolling interest and Predecessor	401
Segment portion attributable to noncontrolling interest and Predecessor	188
Segment operating income attributable to MPLX LP	$	213



(in millions)	2016			2015			2014
Reconciliation to Income from operations:
L&S segment operating income attributable to MPLX LP	$	453		$	322		$	213
G&P segment operating income attributable to MPLX LP	1,132			76			—
Segment operating income attributable to MPLX LP	1,585			398			213
Segment portion attributable to unconsolidated affiliates	(173		)	(8		)	85
Segment portion attributable to Predecessor	289			236			103
(Loss) income from equity method investments	(74		)	3			—
Other income - related parties	40			2			—
Unrealized derivative (losses) gains⁽¹⁾	(36		)	4			—
Depreciation and amortization	(591		)	(129		)	(75		)
Impairment expense	(130		)	—			—
General and administrative expenses	(227		)	(125		)	(81		)
Income from operations	$	683		$	381		$	245



(in millions)	2016			2015			2014
Reconciliation to Total revenues and other income:
Total segment revenues and other income	$	3,480		$	1,125		$	793
Revenue adjustment from unconsolidated affiliates	(402		)	(28		)	—
(Loss) income from equity method investments	(74		)	3			—
Other income - related parties	40			2			—
Unrealized derivative losses⁽¹⁾	(15		)	(1		)	—
Total revenues and other income	$	3,029		$	1,101		$	793



(in millions)	2016			2015			2014
Reconciliation to Net income attributable to noncontrolling interests and Predecessor:
Segment portion attributable to noncontrolling interest and Predecessor	$	436		$	249		$	188
Portion of noncontrolling interests and Predecessor related to items below segment income from operations	(203		)	(67		)	(70		)
Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates	(32		)	(5		)	—
Net income attributable to noncontrolling interests and Predecessor	$	201		$	177		$	118

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

The following reconciles segment capital expenditures to total capital expenditures:



(In millions)	2016		2015		2014
L&S segment capital expenditures	$	550	$	258	$	141
G&P segment capital expenditures	894		100		—
Total segment capital expenditures	1,444		358		141
Less: Capital expenditures for Partnership-operated, non-wholly-owned subsidiaries in G&P segment	131		24		—
Total capital expenditures	$	1,313	$	334	$	141

Total assets by reportable segment were:



	December 31,
(In millions)	2016		2015
Cash and cash equivalents	$	234	$	43
L&S	2,978		2,142
G&P	14,297		14,219
Total assets	$	17,509	$	16,404

11. Major Customers and Concentration of Credit Risk

MPC accounted for 41 percent, 82 percent and 90 percent of the Partnership’s total revenues and other income for 2016, 2015 and 2014, respectively, excluding revenues attributable to volumes shipped by MPC under joint tariffs with third parties, which are treated as third-party revenue for accounting purposes.

A second customer accounted for 11 percent of the Partnership’s total revenues and other income for 2016. Revenues from this customer are from product sales, gathering, processing and fractionation services in the G&P segment. As of December 31, 2016, the Partnership had $59 million of accounts receivable from this customer.

The Partnership has a concentration of trade receivables due from customers in the same industry, MPC, integrated oil companies, independent refining companies and other pipeline companies. These concentrations of customers may impact the Partnership’s overall exposure to credit risk as they may be similarly affected by changes in economic, regulatory and other factors. The Partnership manages its exposure to credit risk through credit analysis, credit limit approvals and monitoring procedures, and for certain transactions, it may request letters of credit, prepayments or guarantees.

12. 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.

The Partnership and MarkWest Hydrocarbon recorded income tax expense of $12 million, $1 million and $1 million for the years ended December 31, 2016, 2015 and 2014, respectively. The effective tax rate was five percent for 2016, and less than one percent for 2015 and 2014, respectively.

The components of the provision for income tax expense (benefit) are as follows:



	December 31,
(In millions)	2016			2015
Current income tax expense:
Federal	$	4		$	—
State	1			—
Total current	5			—
Deferred income tax (benefit) expense:
Federal	(16		)	3
State	(1		)	(2		)
Total deferred	(17		)	1
(Benefit) provision for income tax	$	(12	)	$	1

A reconciliation of the (benefit) provision for income tax and the amount computed by applying the federal statutory rate of 35 percent to the income before income taxes for each of the years ended December 31, 2016 and 2015 is as follows:



	December 31, 2016
(In millions)	MarkWest Hydrocarbon⁽¹⁾			Partnership⁽²⁾			Eliminations			Consolidated⁽²⁾
(Loss) income before (benefit) provision for income tax	$	(41	)	$	461		$	2		$	422
Federal statutory rate	35		%	—		%	—		%
Federal income tax at statutory rate	(14		)	—			—			(14		)
State income taxes net of federal benefit	(2		)	1			—			(1		)
Provision on income from MPLX LP Class A units	3			—			—			3
Change in state statutory rate	(1		)	—			—			(1		)
Other	1			—			—			1
(Benefit) provision for income tax	$	(13	)	$	1		$	—		$	(12	)



	December 31, 2015
(In millions)	MarkWest Hydrocarbon⁽¹⁾			Partnership⁽²⁾			Eliminations			Consolidated⁽²⁾
Income before provision (benefit) for income tax	$	9		$	324		$	1		$	334
Federal statutory rate	35		%	—		%	—		%
Federal income tax at statutory rate	3			—			—			3
State income taxes net of federal benefit	—			(2		)	—			(2		)
Provision on income from MPLX LP Class A units	1			—			—			1
Other	(1		)	—			—			(1		)
Provision (benefit) for income tax	$	3		$	(2	)	$	—		$	1


(1)	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.


(2)	Financial information has been retrospectively adjusted for the acquisition of HSM, HST, WHC and MPLXT from MPC. See Notes 1 and 3. Prior to these acquisitions, MPC paid all income taxes related to Predecessor.

Deferred tax assets and liabilities consist of the following:



	December 31,
(In millions)	2016		2015
Deferred tax assets:
Derivatives	$	—	$	9
Net operating loss carryforwards	—		62
Total deferred tax assets	—		71
Deferred tax liabilities:
Property, plant and equipment	5		7
Investments in subsidiaries and affiliates	—		442
Total deferred tax liabilities	5		449
Net deferred tax liabilities	$	5	$	378

At December 31, 2016, MarkWest Hydrocarbon had no tax-effected federal or state operating loss carryforwards. These were assumed by MPC on September 1, 2016 in connection with the Class A Reorganization discussed in Note 8.

Significant judgment is required in evaluating tax positions and determining the Partnership and MarkWest Hydrocarbon’s provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. However, the Partnership and MarkWest Hydrocarbon did not have any material uncertain tax positions for the years ended December 31, 2016, 2015 or 2014.

Any interest and penalties related to income taxes were recorded as a part of the provision for income taxes. Such interest and penalties were a net expense of less than $1 million in 2016 and 2015, respectively, and a net benefit of less than $1 million in 2014. As of December 31, 2016 and 2015, less than $1 million, respectively, of interest and penalties were accrued related to income taxes. In addition, the Partnership and MarkWest Hydrocarbon’s former corporate entity have federal tax years 2013 through 2015 and state tax years 2012 through 2015 open to examination.

13. Inventories

Inventories consist of the following:



	December 31,
(In millions)	2016		2015
NGLs	$	2	$	3
Line fill	9		5
Spare parts, materials and supplies	44		44
Total inventories	$	55	$	52

14. Property, Plant and Equipment

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



	Estimated Useful Lives	December 31,
(In millions)	Estimated Useful Lives	2016		2015
Natural gas gathering and NGL transportation pipelines and facilities	5 - 30 years	$	4,748	$	4,307
Processing, fractionation and storage facilities	25 - 30 years	3,467		3,185
Pipelines and related assets	19 - 42 years	1,799		1,381
Barges and towing vessels	20 years	479		475
Terminals and related assets	4 - 31 years	839		42
Land, building, office equipment and other	3 - 30 years	757		612
Construction-in-progress		1,013		983
Total		13,102		10,985
Less accumulated depreciation		1,694		771
Property, plant and equipment, net		$	11,408	$	10,214

Property, plant and equipment includes gross assets acquired under capital leases of approximately $25 million at December 31, 2016 and 2015, respectively, with related amounts in accumulated depreciation of approximately $8 million and $7 million at December 31, 2016 and 2015, respectively.

15. Fair Value Measurements

Fair Values – Recurring

Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions as discussed in Note 16. As part of the MarkWest Merger, the MarkWest opening balance sheet was valued at fair value (see Note 4).

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. The derivative contracts are measured at fair value on a recurring basis and classified within Level 2 and Level 3 of the valuation hierarchy. The Level 2 and Level 3 measurements are obtained using a market approach. LIBOR rates are an observable input for the measurement of all derivative contracts. The measurements for all commodity contracts contain observable inputs in the form of forward prices based on WTI crude oil prices; and Columbia Appalachia, Xxxxx Hub, PEPL and Houston Ship Channel natural gas prices. Level 2 instruments include crude oil and natural gas swap contracts. The valuations are based on the appropriate commodity prices and contain no significant unobservable inputs. Level 3 instruments include all NGL transactions and embedded derivatives in commodity contracts. The significant unobservable inputs for NGL transactions and embedded derivatives in commodity contracts include NGL prices interpolated and extrapolated due to inactive markets, electricity price curves, and probability of renewal. The following table presents the financial instruments carried at fair value classified by the valuation hierarchy:



	December 31, 2016					December 31, 2015
(In millions)	Assets		Liabilities			Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	—	$	—		$	2	$	—
Significant unobservable inputs (Level 3)
Commodity contracts	—		(6		)	7		—
Embedded derivatives in commodity contracts	—		(54		)	—		(32		)
Total carrying value in Consolidated Balance Sheets	$	—	$	(60	)	$	9	$	(32	)

The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments as of December 31, 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⁾	$0.28 - $0.31	Jan. 17 - Dec. 17
		Forward propane prices (per gallon)⁽¹⁾	$0.66 - $0.72	Jan. 17 - Dec. 17
		Forward isobutane prices (per gallon)⁽¹⁾	$0.85 - $0.97	Jan. 17 - Dec. 17
		Forward normal butane prices (per gallon)⁽¹⁾	$0.79 - $0.93	Jan. 17 - Dec. 17
		Forward natural gasoline prices (per gallon)⁽¹⁾	$1.16 - $1.24	Jan. 17 - Dec. 17

Embedded derivatives in commodity contracts	Liabilities	Forward propane prices (per gallon)⁽¹⁾	$0.62 - $0.72	Jan. 17 - Dec. 22
		Forward isobutane prices (per gallon)⁽¹⁾	$0.82 - $0.97	Jan. 17 - Dec. 22
		Forward normal butane prices (per gallon)⁽¹⁾	$0.78 - $0.93	Jan. 17 - Dec. 22
		Forward natural gasoline prices (per gallon)⁽¹⁾	$1.16 - $1.27	Jan. 17 - Dec. 22
		Forward natural gas prices (per mmbtu)⁽²⁾	$2.37 - $3.72	Jan. 17 - Dec. 22
		Probability of renewal⁽³⁾	50.0%
		Probability of renewal for second 5-yr term⁽³⁾	75.0%


(1)	NGL prices used in the valuations decrease in the early years and increase over time.


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

(3)

The producer counterparty to the embedded derivative has the option to renew the gas purchase agreement and the related keep-whole processing agreement for two successive five-year terms after 2022. The embedded gas purchase agreement cannot be renewed without the renewal of the related keep-whole processing agreement. Due to the significant number of years until the renewal options are exercisable and the high level of uncertainty regarding the counterparty’s future 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 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 16. 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.

Embedded derivatives in utility contracts – The Partnership had an embedded derivative contract that fixed a component of the utilities costs at a plant in the Southwest operations to an index price of electricity which expired as of December 31, 2016. Increases (decreases) in the index price for electricity resulted in a decrease (increase) in the realized losses presented in Cost of Revenues on the Income Statement.

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


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


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


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

Changes in Level 3 Fair Value Measurements

The tables below include a roll forward of the balance sheet amounts for the years ended December 31, 2016 and 2015 (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 5 for detail of the Ohio Condensate equity method impairment charge, which included a Level 3 valuation adjustment for the year ended December 31, 2016. See Note 18 for a rollforward of goodwill, which included a Level 3 valuation adjustment for the year ended December 31, 2016.



	2016						2015
(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	$	7		$	(32	)	$	—		$	—
Net positions assumed in conjunction with the MarkWest Merger	—			—			7			(38		)
Total (loss) gain (realized and unrealized) included in earnings⁽¹⁾	(13		)	(29		)	3			5
Settlements	—			7			(3		)	1
Fair value at end of period	$	(6	)	$	(54	)	$	7		$	(32	)
The amount of total (losses) gains for the period included in earnings attributable to the change in unrealized gains or losses relating to liabilities still held at end of period	$	(6	)	$	(26	)	$	2		$	5


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

Fair Values – Reported

The Partnership’s primary financial instruments are cash and cash equivalents, receivables, receivables from related parties, accounts payable, payables to related parties and long-term debt. The Partnership’s fair value assessment incorporates a variety of considerations, including (1) the short-term duration of the instruments, (2) MPC’s investment-grade credit rating and (3) 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 16).

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.



	December 31,
	2016				2015
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Long-term debt	$	4,953	$	4,422	$	5,212	$	5,255
SMR liability	$	108	$	96	$	99	$	100

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

Volume of Commodity Derivative Activity

As of December 31, 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	36,500
Natural Gas (MMBtu)	Long	297,017
NGLs (gal)	Short	64,211,702

Embedded Derivatives in Commodity Contracts

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

During the years ended December 31, 2016 and 2015, the Partnership had a commodity contract that allowed for the Partnership to fix a component of the utilities cost to an index price on electricity at a plant location in the Southwest Operations which expired as of December 31, 2016. Changes in the fair value of the derivative component of this contract were recognized as Cost of revenues in the Consolidated Statements of Income. As of December 31, 2015, the estimated fair value of this contract was a liability of $1 million.

Financial Statement Impact of Derivative Contracts

Certain derivative positions are subject to master netting agreements, therefore the Partnership has elected to offset derivative assets and liabilities that are legally permissible to be offset. As of December 31, 2016 and 2015, there were no derivative assets or liabilities that were offset in the Consolidated Balance Sheets. The impact of the Partnership’s derivative instruments on its Consolidated Balance Sheets is summarized below:



(In millions)	December 31, 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	$	—	$	(13	)	$	9	$	(5	)
Other noncurrent assets / deferred credits and other liabilities	—		(47		)	—		(27		)
Total	$	—	$	(60	)	$	9	$	(32	)


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

In the table above, the Partnership does not offset a counterparty’s current derivative contracts with the counterparty’s non-current derivative contracts, although the Partnership’s master netting arrangements would allow current and non-current positions to be offset in the event of default. Additionally, in the event of a default, the Partnership’s master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of

transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions and other forms of non-cash collateral (such as letters of credit).

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



	December 31,
(In millions)	2016			2015
Product sales
Realized gain	$	2		$	4
Unrealized loss	(15		)	(1		)
Total revenue: derivative (loss) gain from product sales	(13		)	3
Purchased product costs
Realized loss	(5		)	—
Unrealized (loss) gain	(22		)	5
Total purchased product costs: derivative (loss) gain from product purchases	(27		)	5
Cost of revenues
Realized loss	(3		)	—
Unrealized gain	1			—
Total cost of revenues: derivative loss from cost of revenues	(2		)	—
Total derivative (losses) gains	$	(42	)	$	8

17. Debt

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



	December 31,
(In millions)	2016			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⁾	(428		)	(472		)
Amounts due within one year	(1		)	(1		)
Total long-term debt due after one year	$	4,422		$	5,255


(1)	Includes $420 million and $464 million discount as of December 31, 2016 and 2015, respectively, related to the difference between the fair value and the principal amount of the assumed MarkWest debt.

The following table shows five years of scheduled debt payments.



(In millions)
2017	$	1
2018	1
2019	251
2020	5
2021	—

Credit Agreements

On November 20, 2014, MPLX LP entered into a credit agreement with a syndicate of lenders (“MPLX Credit Agreement”) which provided for a five-year, $1 billion bank revolving credit facility and a $250 million term loan facility. In connection with the closing of the MarkWest Merger, the Partnership amended the MPLX Credit Agreement to, among other things, increase the aggregate amount of revolving credit capacity under the credit agreement by $1 billion, for total aggregate commitments of $2 billion, and to extend the maturity for the bank revolving credit facility to December 4, 2020. The term loan facility was not amended and matures on November 20, 2019. Also in connection with the closing of the MarkWest Merger, MarkWest’s bank revolving credit facility was terminated and the approximately $943 million outstanding under MarkWest’s bank revolving credit facility was repaid with $850 million of borrowings under MPLX LP’s bank revolving credit facility and $93 million of cash.

The bank revolving credit facility includes a letter of credit issuing capacity of up to $250 million and swingline capacity of up to $100 million. The borrowing capacity under the MPLX Credit Agreement may be increased by up to an additional $500 million, subject to certain conditions, including the consent of lenders whose commitments would increase. In addition, the maturity date may be extended from time-to-time during its term to a date that is one year after the then-effective maturity subject to the approval of lenders holding the majority of the commitments then outstanding, provided that the commitments of any non-consenting lenders will be terminated on the then-effective maturity date.

Borrowings under the MPLX Credit Agreement bear interest at either the Adjusted LIBOR or the Alternate Base Rate (as defined in the MPLX Credit Agreement), at our election, plus a specified margin. The Partnership is charged various fees and expenses in connection with the agreement, including administrative agent fees, commitment fees on the unused portion of the bank revolving credit facility and fees with respect to issued and outstanding letters of credit. The applicable margins to the benchmark interest rates and certain fees fluctuate based on the credit ratings in effect from time to time on the Partnership’s long-term debt.

The MPLX Credit Agreement includes certain representations and warranties, affirmative and restrictive covenants and events of default that the Partnership considers to be usual and customary for an agreement of this type. This agreement includes a financial covenant that requires the Partnership to maintain a ratio of Consolidated Total Debt as of the end of each fiscal quarter to Consolidated EBITDA (both as defined in the MPLX Credit Agreement) for the prior four fiscal quarters of no greater than 5.0 to 1.0 (or 5.5 to 1.0 for up to two fiscal quarters following certain acquisitions.) Consolidated EBITDA is subject to adjustments for certain acquisitions completed and capital projects undertaken during the relevant period. Other covenants restrict the Partnership and certain of its subsidiaries from incurring debt, creating liens on its assets and entering into transactions with affiliates. As of December 31, 2016, the Partnership was in compliance with the covenants contained in the MPLX Credit Agreement.

During 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 December 31, 2016, the Partnership had no borrowings against the facility 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.

During 2015, the Partnership borrowed $992 million under the bank revolving credit facility, at an average interest rate of 1.617 percent, per annum, and repaid $500 million of these borrowings. At December 31, 2015, the Partnership had $877 million of borrowings and $8 million letters of credit outstanding under this facility, resulting in total unused loan availability of $1.12 billion, or 55.8 percent of the borrowing capacity.

During 2014, in connection with entering into the above mentioned MPLX Credit Agreement, the Partnership terminated its previously existing $500 million five-year MPLX Operations bank revolving credit agreement, dated as of September 14, 2012. However, during 2014, we borrowed $280 million under the previously existing agreement, at an average interest rate of 1.535 percent, per annum, and repaid all of these borrowings.

Senior Notes

In connection with the MarkWest Merger, MPLX LP assumed MarkWest’s outstanding debt, which included $4.1 billion aggregate principal amount of senior notes. On December 22, 2015, approximately $4.04 billion aggregate principal amount of MarkWest’s outstanding senior notes were exchanged for an aggregate principal amount of approximately $4.04 billion of new unsecured senior notes issued by MPLX LP in an exchange offer and consent solicitation undertaken by MPLX LP and MarkWest, leaving approximately $63 million aggregate principal of outstanding senior notes held by MarkWest.

The MPLX LP senior notes consist of (i) approximately $710 million aggregate principal amount of 5.500 percent senior notes due February 15, 2023, (ii) approximately $989 million aggregate principal amount of 4.500 percent senior notes due July 15, 2023, (iii) approximately $1.15 billion aggregate principal amount of 4.875 percent senior notes due December 1, 2024, (iv) approximately $500 million aggregate principal amount of four percent unsecured senior notes due February 15, 2025, and (v) approximately $1.19 billion aggregate principal amount of 4.875 percent senior notes due June 1, 2025. Interest on each series of MPLX LP senior notes is payable semi-annually in arrears according to the table below.



Senior Notes		Interest payable semi-annually in arrears
5.500% senior notes due 2023		February 15^th and August 15^th
4.500% senior notes due 2023		January 15^th and July 15^th
4.875% senior notes due 2024		June 1^st and December 1^st
4.000% senior notes due 2025		February 15^th and August 15^th
4.875% senior notes due 2025		June 1^st and December 1^st

After giving effect to the exchange offer and consent solicitation referred to above, as of December 31, 2016, MarkWest had outstanding (i) approximately $40 million aggregate principal amount of 5.500 percent senior notes due February 15, 2023, (ii) approximately $11 million aggregate principal amount of 4.500 percent senior notes due July 15, 2023, (iii) approximately $1 million aggregate principal amount of 4.875 percent senior notes due December 1, 2024 and (iv) approximately $11 million aggregate principal amount of 4.875 percent senior notes due June 1, 2025. Interest on each series of the MarkWest senior notes is payable semi-annually in arrears consistent with the table above.

On February 12, 2015, the Partnership completed a public offering of $500 million aggregate principal amount of four percent unsecured senior notes due February 15, 2025 (the “Feb 2025 Notes”). The net proceeds from the offering of the Feb 2025 Notes were approximately $495 million, after deducting underwriting discounts. The net proceeds were used to repay the amounts outstanding under its bank revolving credit facility, as well as for general partnership purposes. Interest is payable semi-annually in arrears, commencing on August 15, 2015.

SMR Transaction

On September 1, 2009, MarkWest completed the sale of the SMR (the “SMR Transaction”). At that time, MarkWest had begun constructing the SMR at its Javelina gas processing and fractionation complex in Corpus Christi, Texas. Under the terms of the agreement, MarkWest received proceeds of $73 million and the purchaser completed the construction of the SMR. MarkWest and the purchaser also executed a related product supply agreement under which the Partnership will receive the entire product produced by the SMR through 2030 in exchange for processing fees and the reimbursement of certain other expenses. The processing fee payments began when the SMR commenced operations in March 2010. MarkWest was deemed to have continuing involvement with the SMR as a result of certain provisions in the related agreements. Therefore, the transaction is treated as a financing arrangement under GAAP. The Partnership imputes interest on the SMR liability at 6.39 percent annually, its incremental borrowing rate at the time of the purchase accounting valuation. Each processing fee payment has multiple elements: reduction of principal of the SMR liability, interest expense associated with the SMR liability and facility expense

related to the operation of the SMR. As part of purchase accounting, the SMR Transaction has been recorded at fair value. As of December 31, 2016 and 2015, the following amounts related to the SMR are included in the accompanying Consolidated Balance Sheets:



(In millions)	December 31, 2016		December 31, 2015
Assets
Property, plant and equipment, net of accumulated depreciation	$	61	$	69
Liabilities
Accrued liabilities	5		4
Deferred credits and other liabilities	91		96

18. Goodwill and Intangibles

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. The Partnership has performed its annual impairment tests, and no additional impairments in the carrying value of goodwill were identified in the periods presented.

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 were as follows for the periods presented:



(In millions)	L&S		G&P			Total
Gross goodwill as of December 31, 2014	$	116	$	—		$	116
Accumulated impairment losses	—		—			—
Balance as of December 31, 2014	116		—			116
Acquisitions	—		2,454			2,454
Acquisitions from MPC	25		—			25
Gross goodwill as of December 31, 2015	141		2,454			2,595
Accumulated impairment losses	—		—			—
Balance as of December 31, 2015	141		2,454			2,595
Purchase price allocation adjustments⁽¹⁾	—		(241		)	(241		)
Impairment losses	—		(130		)	(130		)
Acquisitions from MPC	21		—			21
Balance as of December 31, 2016	$	162	$	2,083		$	2,245

Gross goodwill as of December 31, 2016	$	162	$	2,213		$	2,375
Accumulated impairment losses	—		(130		)	(130		)
Balance as of December 31, 2016	$	162	$	2,083		$	2,245


(1)	See Note 4 for further discussion on purchase price allocation adjustments.

Intangible Assets

The Partnership’s intangible assets as of December 31, 2016 and 2015 are comprised of customer contracts and relationships, as follows:



	December 31, 2016							December 31, 2015
(In millions)	Gross		Accumulated Amortization			Net		Gross		Accumulated Amortization			Net		Useful Life
L&S	$	—	$	—		$	—	$	—	$	—		$	—	N/A
G&P	533		(41		)	492		468		(2		)	466		11-25 years
	$	533	$	(41	)	$	492	$	468	$	(2	)	$	466

Estimated future amortization expense related to the intangible assets at December 31, 2016 is as follows:



(In millions)
2017	$	38
2018	38
2019	38
2020	38
2021	38
Thereafter	302
Total	$	492

19. Supplemental Cash Flow Information



(In millions)	2016			2015		2014
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	213		$	13	$	3
Income taxes paid	4			—		—
Non-cash investing and financing activities:
Net transfers of property, plant and equipment from materials and supplies inventories	$	(3	)	$	5	$	1
Contribution - common units issued⁽¹⁾	669			—		200
Acquisition:
Fair value of MPLX LP units issued⁽¹⁾	—			7,326		—
Payable to seller	—			50		—


(1)	See Note 4.

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



(In millions)	2016			2015		2014
(Decrease) increase in capital accruals	$	(22	)	$	27	$	11

In connection with the acquisition of HSM described in Note 4, 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. In connection with the acquisition of HST, WHC and MPLXT described in Note 4, MPC agreed to waive two-thirds of the first quarter 2017 distributions on the MPLX LP common units issued in connection with the transaction. MPC will 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 is $6 million.

20. Equity-based Compensation Plan

Description of the Plan

The MPLX LP 2012 Incentive Compensation Plan (“MPLX 2012 Plan”) authorizes the MPLX GP board of directors (the “Board”) to grant unit options, unit appreciation rights, restricted units and phantom units, distribution equivalent rights, unit awards, profits interest units, performance units and other unit-based awards to the Partnership’s or any of its affiliates’ employees, officers and directors, including directors and officers of MPC. No more than 2.75 million MPLX LP common limited partner units may be delivered under the MPLX 2012 Plan. Units delivered pursuant to an award granted under the MPLX 2012 Plan may be funded through acquisition on the open market, from the Partnership or from an affiliate of the Partnership, as determined by the Board.

Unit-based awards under the Plan

The Partnership expenses all unit-based payments to employees and non-employee directors based on the grant date fair value of the awards over the requisite service period, adjusted for estimated forfeitures.

Phantom Units – The Partnership grants phantom units under the MPLX 2012 Plan to non-employee directors of MPLX LP’s general partner and of MPC. Awards to non-employee directors are accounted for as non-employee awards. Phantom units granted to non-employee directors vest immediately at the time of the grant, as they are non-forfeitable, but are not issued until the director’s departure from the board of directors. Prior to issuance, non-employee directors do not have the right to vote such units and cash distribution equivalents accrue in the form of additional phantom units and will be issued when the director departs from the board of directors.

The Partnership grants phantom units under the MPLX 2012 Plan to certain officers and non-officers of MPLX LP, MPLX LP’s general partner and MPC who make significant contributions to our business. These grants are accounted for as employee awards. In general, these phantom units will vest over a requisite service period of up to three years. Prior to vesting, these phantom unit recipients will not have the right to vote such units and cash distributions declared will be accrued and paid upon vesting. The accrued distributions at December 31, 2016 and 2015 were $2 million and less than $1 million, respectively.

The fair values of phantom units are based on the fair value of MPLX LP common limited partner units on the grant date.

Performance Units – The Partnership grants performance units under the MPLX 2012 Plan to certain officers of MPLX LP’s general partner and certain eligible MPC officers who make significant contributions to its business. These awards are intended to have a per unit payout determined by the total unitholder return of MPLX LP common units as compared to the total unitholder return of a selected group of peer partnerships. The final per-unit payout will be the average of the results of four measurement periods during the 36 month requisite service period. These performance units will pay out 75 percent in cash and 25 percent in MPLX LP common units. The performance units paying out in cash are accounted for as liability awards and recorded at fair value with a mark-to-market adjustment made each quarter. The performance units paying out in units are accounted for as equity awards and have a weighted average grant date fair value of $0.63 per unit for 2016 and $1.03 per unit for 2015, as calculated using a Monte Carlo valuation model.

Outstanding Phantom Unit Awards

The following is a summary of phantom unit award activity of MPLX LP common limited partner units in 2016:



	Phantom Units
	Number of Units		Weighted Average Fair Value		Aggregate Intrinsic Value (In millions)
Outstanding at December 31, 2015	1,031,219		$	35.49
Granted	458,727		29.42
Settled	(166,576	)	38.12
Forfeited	(149,959	)	32.72
Outstanding at December 31, 2016	1,173,411		33.09
Vested and expected to vest at December 31, 2016	1,157,676		33.12		$	40
Convertible at December 31, 2016	494,189		34.11		$	17

The 494,189 convertible units are held by our non-employee directors and certain officers. These units are non-forfeitable and issuable upon the holder’s departure from service to the company.

The following is a summary of the values related to phantom units held by officers and non-employee directors:



	Phantom Units
	Intrinsic Value of Units Issued During the Period (in millions)		Weighted Average Grant Date Fair Value of Units Granted During the Period
2016	$	5	$	29.42
2015	3		35.00
2014	1		49.56

As of December 31, 2016, unrecognized compensation cost related to phantom unit awards was $17 million, which is expected to be recognized over a weighted average period of 2.0 years.

Outstanding Performance Unit Awards

The following is a summary of activity of performance unit awards paying out in MPLX LP common limited partner units in 2016:



	Performance Units
	Number of Units		Weighted Average Fair Value
Outstanding at December 31, 2015	1,521,392		$	1.00
Granted	789,375		0.63
Settled	(458,011	)	0.79
Forfeited	(53,507	)	1.06
Outstanding at December 31, 2016	1,799,249		0.89

As of December 31, 2016, unrecognized compensation cost related to equity-classified performance unit awards was $1 million, which is expected to be recognized over a weighted average period of 1.6 years.

Performance units paying out in units have a grant date fair value calculated using a Monte Carlo valuation model, which requires the input of subjective assumptions. The following table provides a summary of the weighted average inputs used for these assumptions:



	2016			2015			2014
Risk-free interest rate	0.96		%	0.95		%	0.63		%
Look-back period	2.83 years			2.84 years			2.84 years
Expected volatility	47.59		%	30.12		%	17.17		%
Grant date fair value of performance units granted	$	0.63		$	1.03		$	1.16

The assumption for expected volatility of our unit price reflects the historical volatility of MPLX LP common units. The look-back period reflects the remaining performance period at the grant date. The risk-free interest rate for the remaining performance period as of the grant date is based on the U.S. Treasury yield curve in effect at the time of the grant.

Total Unit-Based Compensation Expense

Total unit-based compensation expense for awards settling in MPLX LP common units was $10 million in 2016, $4 million in 2015 and $3 million in 2014. Approximately $15 million was charged to the MarkWest purchase price in 2015 for MPLX LP unit-based compensation awards granted in connection with the MarkWest Merger.

MPC’s Stock-based Compensation

Stock-based compensation expenses charged to MPLX LP under our employee services agreement with MPC were $5 million for 2016 and $1 million for 2015 and 2014, respectively.

21. Lease Operations

Based on the terms of certain natural gas gathering, transportation and processing agreements, the Partnership is considered to be the lessor under several implicit operating lease arrangements in accordance with GAAP. The Partnership’s primary implicit lease operations relate to a natural gas gathering agreement in the Marcellus Shale for which it earns a fixed-fee for providing gathering services to a single producer using a dedicated gathering system. As the gathering system is expanded, the fixed-fee charged to the producer is adjusted to include the additional gathering assets in the lease. The primary term of the natural gas gathering arrangement expires in 2023 and will continue thereafter on a year to year basis until terminated by either party. Other significant implicit leases relate to a natural gas processing agreement in the Marcellus Shale and a natural gas processing agreement in the Southern Appalachia region for which the Partnership earns minimum monthly fees for providing processing services to a single producer using a dedicated processing plant. The primary term of these natural gas processing agreements expire during 2023 and 2030.

Based on the terms of the Partnership’s fee-based transportation services and storage services agreements with MPC, the Partnership is also considered to be a lessor of its pipelines, marine equipment and storage facilities in accordance with GAAP. The Partnership’s revenue from its implicit lease arrangements, excluding executory costs, totaled approximately $586 million in 2016, $127 million in 2015 and $14 million in 2014.

The Partnership’s implicit lease arrangements related to the processing facilities contain contingent rental provisions whereby the Partnership receives additional fees if the producer customer exceeds the monthly minimum processed volumes. During the years ended December 31, 2016 and 2015, the Partnership received $7 million and less than $1 million, respectively, in contingent lease payments.

The following is a schedule of minimum future rental revenue on the non-cancellable operating leases as of December 31, 2016:



(In millions)	Intercompany		Third Party		Total
2017	$	232	$	197	$	429
2018	226		200		426
2019	228		202		430
2020	230		201		431
2021	131		185		316
2022 and thereafter	542		460		1,002
Total minimum future rentals	$	1,589	$	1,445	$	3,034

The following schedule summarizes the Partnership’s investment in assets held for operating lease by major classes as of December 31, 2016 and 2015:



	December 31,
(In millions)	2016			2015
Natural gas gathering and NGL transportation pipelines and facilities	$	650		$	619
Natural gas processing facilities	844			753
Pipelines and related assets	307			253
Barges	388			360
Terminals and related assets	839			42
Towing vessels	91			91
Construction in progress	275			147
Property, plant and equipment	3,394			2,265
Less: accumulated depreciation	(843		)	(289		)
Total property, plant and equipment, net	$	2,551		$	1,976

22. Asset Retirement Obligations

The Partnership’s assets subject to AROs are primarily certain gas-gathering pipelines and processing facilities, a crude oil pipeline and other related pipeline assets. The Partnership also has land leases that require the Partnership to return the land to its original condition upon termination of the lease. The Partnership reviews current laws and regulations governing obligations for asset retirements and leases, as well as the Partnership’s leases and other agreements.

The following is a reconciliation of the changes in the ARO from January 1, 2015 to December 31, 2016:



(In millions)	2016			2015
ARO at beginning of period	$	17		$	—
Liabilities assumed in conjunction with the MarkWest Merger	—			15
Liabilities incurred	8			2
Adjustments to AROs	(1		)	—
Accretion expense	1			—
ARO at end of period	$	25		$	17

At December 31, 2016 and 2015, there were no assets legally restricted for purposes of settling AROs. The AROs have been recorded as part of Deferred credits and other liabilities in the accompanying Consolidated Balance Sheets.

In addition to recorded AROs, the Partnership has other AROs related to certain gathering, processing and other assets as a result of environmental and other legal requirements. The Partnership is not required to perform such work until it permanently ceases operations of the respective assets. Because the Partnership considers the operational life of these assets to be indeterminable, an associated ARO cannot be estimated and is not recorded.

23. Commitments and Contingencies

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

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

At December 31, 2016 and 2015, accrued liabilities for remediation totaled $8 million and $1 million, respectively, not including the remediation liability related to the Wolverine Pipeline incident, discussed below. However, it is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties, if any, which may be imposed. At December 31, 2016 and 2015, there was less than $1 million, respectively, in receivables from MPC for indemnification of environmental costs related to incidents occurring prior to the Initial Offering.

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

MarkWest Liberty Midstream continues to discuss with the EPA and the State of Pennsylvania civil enforcement allegations associated with permitting or other related regulatory obligations for its launcher/receiver and compressor station facilities in the region. In connection with these discussions, MarkWest Liberty Midstream received an initial proposal from the EPA to settle all civil claims associated with this matter for the combination of a proposed cash penalty of approximately $2.4 million and proposed supplemental environmental projects with an estimated cost of approximately $3.6 million. MarkWest Liberty Midstream will be submitting a response asserting that this action involves novel issues surrounding primarily minor source emissions from facilities that the agencies themselves considered de minimis were not the subject of regulation and consequently that the settlement proposal is excessive. MarkWest will continue to negotiate with EPA regarding the amount and scope of the proposed settlement.

The Partnership is involved in a number of other environmental enforcement matters arising in the ordinary course of business. While the outcome and impact on MPLX LP cannot be predicted with certainty, management believes the resolution of these environmental matters will not, individually or collectively, have a material adverse effect on its consolidated results of operations, financial position or cash flows.

Other Lawsuits – In 2003, the State of Illinois brought an action against the Premcor Refining Group, Inc. (“Premcor”) and Apex Refining Company (“Apex”) asserting claims for environmental cleanup related to the refinery owned by these entities in the Hartford/Wood River, Illinois area. In 2006, Premcor and Apex filed third-party complaints against numerous owners and operators of petroleum products facilities in the Hartford/Wood River, Illinois area, including MPL. These complaints, which have been amended since filing, assert claims of common law nuisance and contribution under the Illinois Contribution Act

and other laws for environmental cleanup costs that may be imposed on Premcor and Apex by the State of Illinois. On September 6, 2016, the trial court approved a settlement between Apex and the State of Illinois whereby Apex agreed to settle all claims against it for a $10 million payment. Premcor has objected to this ruling and is seeking an appeal. There are several third-party defendants in the litigation and MPL has asserted cross-claims in contribution against the various third-party defendants. This litigation is currently pending in the Third Judicial Circuit Court, Madison County, Illinois. While the

ultimate outcome of these litigated matters remains uncertain, neither the likelihood of an unfavorable outcome nor the ultimate liability, if any, with respect to this matter can be determined at this time and the Partnership is unable to estimate a reasonably possible loss (or range of 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 December 31, 2016 the Partnership’s contractual commitments to acquire property, plant and equipment totaled $588 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. Our contractual commitments at December 31, 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 December 31, 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.

Lease and Other Contractual Obligations – The Partnership executed transportation and terminalling agreements that obligate us to minimum volume, throughput or payment commitments over the terms of the agreements, which range from three to ten years. After the minimum volume commitments are met in the transportation and terminalling agreements, the Partnership pays additional amounts based on throughput. There are escalation clauses in the transportation and terminalling agreements, which are based on CPI adjustments. The minimum future payments under these agreements as of December 31, 2016 are as follows:



(In millions)
2017	$	46
2018	62
2019	61
2020	61
2021	61
2022 and thereafter	317
Total	$	608

The Partnership has various non-cancellable operating lease agreements and a long-term propane storage agreement expiring at various times through fiscal year 2040. Most of these leases include renewal options. The Partnership also leases certain pipelines under a capital lease that has a fixed price purchase option in 2020. Future minimum commitments as of December 31, 2016, for capital lease obligations and for operating lease obligations having initial or remaining non-cancellable lease terms in excess of one year are as follows:



(In millions)	Capital Lease Obligations		Operating Lease Obligations
2017	$	1	$	61
2018	1		51
2019	2		42
2020	5		37
2021	—		36
Later years	—		76
Total minimum lease payments	9		$	303
Less: imputed interest costs	1
Present value of net minimum lease payments	$	8

Operating lease rental expense was:



(In millions)	2016		2015		2014
Minimum rental expense	$	57	$	21	$	17

SMR Transaction – On September 1, 2009, MarkWest entered into a product supply agreement creating a long-term contractual obligation for the payment of processing fees in exchange for the entire product processed by the SMR. See Note 17 for additional discussion. The product received under this agreement is sold to a refinery customer pursuant to a corresponding long-term agreement. The minimum amounts payable annually under the product supply agreement, excluding the potential impact of inflation adjustments per the agreement, are as follows:



(In millions)
2017	$	17
2018	17
2019	17
2020	17
2021	17
2022 and thereafter	143
Total minimum payments	228
Less: Services element	87
Less: Interest	45
Total SMR liability	96
Less: Current portion of SMR liability	5
Long-term portion of SMR liability	$	91

100

24. Subsequent Event

On February 6, 2017, MarkWest Liberty Midstream executed definitive agreements with Antero Midstream LLC, and affiliate of Antero Midstream LP (“Antero Midstream”) for the formation of a joint venture, Sherwood Midstream LLC (“Sherwood Midstream”), to process natural gas at the Sherwood Complex and fractionate natural gas liquids at the Hopedale Complex. Sherwood Midstream is owned 50 percent by Antero Midstream and 50 percent by MarkWest Liberty Midstream. These transactions were effective as of January 1, 2017. In connection with these transactions, MarkWest Liberty Midstream contributed approximately $134 million of assets to Sherwood Midstream, comprised of the three 200 mmcf/d gas processing plants under construction at the Sherwood Complex. MarkWest Liberty Midstream will operate Sherwood Midstream’s gas processing facilities and will also retain sole and exclusive ownership and operation of the existing six 200 mmcf/d gas processing plants at the Sherwood Complex. In addition, MarkWest Liberty Midstream and Sherwood Midstream entered into a joint venture, Sherwood Midstream Holdings LLC (“Sherwood Midstream Holdings”), to own certain infrastructure at the Sherwood Complex that is shared by and supports the operation of both the Sherwood Midstream and MarkWest Liberty Midstream gas processing plants. MarkWest Liberty Midstream contributed approximately $207 million of assets to Sherwood Midstream Holdings, and as of February 6, 2017, MarkWest Liberty Midstream owned a 79 percent ownership interest in Sherwood Midstream Holdings, and the remaining 21 percent ownership interest was owned by Xxxxxxxx Xxxxxxxxx. Sherwood Midstream also purchased an interest in 20 mbpd of existing propane and heavier NGL fractionation capacity owned by MarkWest Ohio Fractionation Company, L.L.C. (“Ohio Fractionation”), a subsidiary of MarkWest Liberty Midstream, at the Hopedale Complex for $125 million. Sherwood Midstream will also have the option to purchase an interest in future fractionation train expansions at the Hopedale Complex, subject to the production of incremental NGLs from Sherwood Midstream’s processing facilities. Ohio Fractionation and MarkWest Utica EMG will continue to own and operate the remaining portion of the Hopedale Complex, including all rail and marketing infrastructure, as well as the NGL pipelines connecting MarkWest Liberty Midstream’s and MarkWest Utica EMG’s gas processing plants to the Hopedale Complex. In connection with the foregoing transactions, Antero Midstream made an initial capital contribution to Sherwood Midstream of approximately $154 million, and it is expected that MarkWest Liberty Midstream and Antero Midstream will each contribute 50 percent of capital needed to fund Sherwood Midstream’s operations.

On February 10, 2017, the Partnership completed a public offering of $1.25 billion aggregate principal amount of 4.125 percent unsecured senior notes due March 2027 (the “2027 Senior Notes”) and $1.0 billion aggregate principal amount of 5.200 percent unsecured senior notes due March 2047 (the “2047 Senior Notes” and, collectively with the 2027 Senior Notes, the “New Senior Notes”). The 2027 Senior Notes and the 2047 Senior Notes were offered at a price to the public of 99.834 percent and 99.304 percent of par, respectively, at an interest rate of 4.125 percent and 5.200 percent, respectively. The Partnership intends to use the net proceeds from this offering for general partnership purposes, which may include, from time to time, acquisitions (including the previously announced planned dropdown of assets from MPC, the acquisition of the Ozark pipeline, and the acquisition of a partial, indirect equity interest in the Xxxxxx Pipeline system) and capital expenditures.

On February 13, 2017, the Partnership announced that it has entered into an asset purchase agreement with Enbridge Pipelines (Ozark) LLC (“Enbridge Ozark”), under which an affiliate of Pipe Line Holdings has agreed to purchase Ozark pipeline for approximately $220 million from Enbridge Ozark. The Ozark pipeline is a 433-mile, 22-inch crude oil pipeline originating in Cushing, Oklahoma, and terminating in Wood River, Illinois, and capable of transporting approximately 230,000 barrels per day. This purchase transaction is expected to close in the first quarter of 2017.

On February 15, 2017, MPLX LP closed on its previously announced intent to participate in a joint venture with Enbridge Energy Partners L.P. (“Enbridge Energy Partners”) to acquire a 9.1875 percent indirect interest in the Dakota Access Pipeline (“DAPL”) and Energy Transfer Crude Oil Company Pipeline (“ETCOP”) projects, collectively referred to as the Xxxxxx Pipeline system, from Energy Transfer Partners, L.P. (“ETP”) and Sunoco Logistics Partners, L.P. (“SXL”) for $500 million.

The Xxxxxx Pipeline system is currently expected to deliver in excess of 470,000 barrels per day of crude oil from the Xxxxxx/

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 Xxxxxx Pipeline system.

MPLX LP and Enbridge Energy Partners intend to form a new joint venture to acquire 49 percent of ETP and SXL’s 75 percent

indirect interest in the Xxxxxx Pipeline system. MPLX LP will own 25 percent of this new joint venture with Enbridge, which

results in its 9.1875 percent indirect ownership interest in the Xxxxxx Pipeline system. MPLX LP expects to account for its

investment using the equity method of accounting.

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Select Quarterly Financial Data (Unaudited)



	2016⁽³⁾										2015
(In millions, except per unit data)	1st Qtr.⁽¹⁾			2nd Qtr.⁽²⁾			3rd Qtr.		4th Qtr.		1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.⁽³⁾
Total revenues and other income	$	645		$	698		$	838	$	848	$	235	$	246	$	251	$	369
Income from operations	50			128			258		247		93		99		91		98
Net (loss) income	(14		)	72			194		182		87		93		86		67
Net (loss) income attributable to MPLX LP	(60		)	19			141		133		46		51		41		18
Net (loss) income attributable to MPLX LP per limited partner unit:
Common - basic	$	(0.33	)	$	(0.11	)	$	0.22	$	0.17	$	0.46	$	0.50	$	0.41	$	(0.14	)
Common - diluted	(0.33		)	(0.11		)	0.21		0.17		0.46		0.50		0.41		(0.14		)
Subordinated - basic and diluted	—			—			—		—		0.46		0.50		—		—
Cash distributions declared per limited partner common unit	$	0.5050		$	0.5100		$	0.5150	$	0.5200	$	0.4100	$	0.4400	$	0.4700	$	0.5000
Distributions declared:
Limited partner units - Public	$	127		$	131		$	135	$	140	$	10	$	10	$	11	$	120
Limited partner units - MPC	29			41			44		45		23		25		27		29
General partner units - MPC	4			4			5		5		1		1		1		3
Incentive distribution rights - MPC	40			46			49		52		3		6		8		37
Redeemable preferred units	—			9			16		16		—		—		—		—
Total distributions declared	$	200		$	231		$	249	$	258	$	37	$	42	$	47	$	189


(1)	First quarter 2016 results included goodwill impairment expense of $129 million. See Note 18 for more information.


(2)	Second quarter 2016 results included impairment expense related to equity method investments of $89 million. See Note 5 for more information.


(3)	These amounts include results from the MarkWest Merger which closed on December 4, 2015. See Note 4 for more information on the MarkWest Merger.

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