EXPLANATORY NOTE

On March 14, 2016, MPLX LP (the “Partnership”) entered into a Membership Interests Contribution Agreement (the “Contribution Agreement”) with MPLX GP LLC, the general partner of the Partnership (the “General Partner”), MPLX Logistics Holdings LLC (“MPLX Logistics”) and MPC Investment LLC (“MPC Investment”), each a wholly-owned subsidiary of Marathon Petroleum Corporation (“MPC”). Pursuant to the Contribution Agreement, the Partnership agreed to acquire from MPC Investment for equity consideration valued at approximately $600 million consisting of a fixed number of MPLX common units and general partner units (the “Equity Consideration”), all of the limited liability company interests of Xxxxxx Street Maine LLC (“HSM”), through a series of intercompany contributions (the “Transaction”). The Transaction closed on March 31, 2016 and the fair value of the MPLX common units and general partner units issued was $669 million and $14 million, respectively.

In exchange for all of the limited liability company interests of HSM, the Partnership issued the Equity Consideration consisting of (i) 22,534,002 MPLX common units to MPLX Logistics and (ii) 459,878 general partner units to the General Partner in order to maintain its 2% general partner interest in the Partnership. MPLX Logistics agreed to waive distributions on the MPLX common units issued in connection with the Transaction for the Partnership’s first quarter 2016 cash distribution, and the General Partner will not receive general partner distributions or incentive distribution rights that would otherwise accrue on such MPLX common units with respect to the Partnership’s first quarter 2016 cash distribution.

The information in Items 6, 7 and 8 below includes periods prior to the acquisition of HSM. Consequently, the Partnership’s combined consolidated financial statements have been retrospectively recast for all periods presented to include the historical results of HSM because the Transaction was between entities under common control. HSM owns and operates towboats (i.e., towing vessels), barges and third-party chartered equipment for the transportation of crude oil, feedstocks, refined products and other hydrocarbon-based products to and from refineries and terminals owned by MPC.

Unless the context otherwise requires, references herein to “MPLX LP,” the “Partnership,” “we,” “our,” “us,” or like terms refer to MPLX LP and its subsidiaries, including MPLX Operations LLC (“MPLX Operations”), MPLX Terminal and Storage LLC (“MPLX Terminal and Storage”), MarkWest Energy Partners, L.P. (“MarkWest”), MarkWest Hydrocarbon, Inc. (“MarkWest Hydrocarbon”) and MPLX Pipe Line Holdings LLC (“Pipe Line Holdings”). Pipe Line Holdings owns Marathon Pipe Line LLC (“MPL”) and Ohio River Pipe Line LLC (“ORPL”). 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”), Centrahoma Processing LLC (“Centrahoma”) and MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. (“Jefferson Dry Gas”). References to “MPC” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other than the Partnership.

Part II

Item 6. Selected Financial Data

The following table shows selected historical consolidated financial data of MPLX LP and MPLX LP Predecessor, our predecessor for accounting purposes, as of the dates and for the years indicated. MPLX LP Predecessor consisted of a 100 percent interest in all of the assets and operations of MPL and ORPL that MPC contributed to us at the closing of the Initial Offering, as well as minority undivided joint interests in two crude oil pipeline systems (the “Joint Interest Assets”) that were not contributed to us. In connection with the closing of the Initial Offering, MPC transferred the Joint Interest Assets from MPLX LP Predecessor to other MPC subsidiaries and then contributed to us a 51 percent indirect ownership interest in Pipe Line Holdings, which owns MPLX LP Predecessor’s assets and operations (other than the Joint Interest Assets), and a 100 percent indirect ownership in our butane cavern. 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. 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 MarkWest Merger. In addition, we recorded the contributions at historical cost, as they are considered transactions between entities under common control. The information in Items 6, 7 and 8 includes periods prior to the acquisition of HSM by MPLX LP, which occurred on March 31, 2016, all of which are entities under common control. Consequently, the Partnership’s combined consolidated financial statements have been retrospectively recast for all periods presented to include the historical results of HSM. HSM owns and operates boats (i.e., towing vessels), barges and third-party chartered equipment for the transportation of crude oil, feedstocks, refined products and other hydrocarbon-based products to and from refineries and terminals owned by MPC.

The selected historical consolidated financial data as of and for the year ended December 31, 2011 were derived from audited combined financial statements of MPLX LP Predecessor.

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)	2015			2014			2013			2012			2011
Consolidated Statements of Income data:
Service revenue	$	130		$	70		$	79		$	75		$	62
Service revenue - related parties	593			662			586			579			513
Rental income	20			—			—			—			—
Rental income - related parties	101			15			15			3			—
Product sales	36			—			—			—			—
Product sales - related parties	1			—			—			—			—
Other income	9			6			5			7			5
Other income - related parties	71			40			28			22			18
Total revenues and other income	961			793			713			686			598
Total costs and expenses	663			548			500			482			436
Income from operations	$	298		$	245		$	213		$	204		$	162
Net income	$	249		$	239		$	211		$	204		$	164
Net income attributable to MPLX LP	156			121			78			13			164
Limited partners’ interest in net income attributable to MPLX LP	99			115			76			13
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	$	1.8200		$	1.4100		$	1.1675		$	0.1769
Consolidated Balance Sheets data (at period end):
Property, plant and equipment, net	$	9,997		$	1,324		$	1,248		$	1,167		$	1,123
Total assets	16,104			1,544			1,504			1,572			1,573
Long-term debt, including capital leases	5,255			644			10			10			11
Consolidated Statements of Cash Flows data:
Net cash provided by (used in):
Operating activities	$	340		$	334		$	297		$	273		$	233
Investing activities	(1,599		)	(137		)	(158		)	64			(225		)
Financing activities	1,275			(224		)	(302		)	(120		)	(8		)
Additions to property, plant and equipment⁽¹⁾	288			141			151			159			57
Other financial data⁽²⁾:
Adjusted EBITDA attributable to MPLX LP⁽³⁾	486			166			111			18
DCF attributable to MPLX LP⁽³⁾	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⁾

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⁾

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 attributable to MPLX LP includes undistributed DCF from MarkWest. See Item 7. Management’s Discussion and Analysis - Results of Operations for a reconciliation of non-GAAP measures. For all years presented, HSM is excluded from Adjusted EBITDA attributable to MPLX LP and DCF attributable to MPLX LP.

Operating Data



	2015			2014		2013		2012		2011
L&S
Crude oil transported for (mbpd)⁽¹⁾:
MPC	864			838		853		830		811
Third parties	197			203		222		202		182
Total	1,061			1,041		1,075		1,032		993
% MPC	81		%	80	%	79	%	80	%	82	%

Products transported for (mbpd)⁽²⁾:
MPC⁽³⁾	887			852		862		909		971
Third parties	27			26		49		71		60
Total	914			878		911		980		1,031
% MPC	97		%	97	%	95	%	93	%	94	%

Average tariff rates ($ per barrel):
Crude oil pipelines	0.66			0.64		0.60		0.57		0.40
Product pipelines	0.65			0.61		0.56		0.51		0.44
Total pipelines	0.65			0.63		0.58		0.54		0.42

Barges⁽⁴⁾	205			199		184		177		167
Towboats⁽⁴⁾	18			18		17		15		15

G&P⁽⁵⁾
Gathering Throughput (mmcf/d)
Marcellus operations	889
Utica operations⁽⁶⁾⁽⁷⁾	745
Southwest operations⁽⁸⁾	1,441
Total gathering throughput	3,075

Natural Gas Processed (mmcf/d)
Marcellus operations	2,964
Utica operations⁽⁶⁾	1,136
Southwest operations	1,125
Southern Appalachian operations	243
Total natural gas processed	5,468

C2 + NGLs Fractionated (mbpd)
Marcellus operations^(9)(10)	220
Utica operations^(6)(10)	51
Southwest operations	24
Southern Appalachian operations⁽¹¹⁾	12
Total C2 + NGLs fractionated⁽¹²⁾	307

Pricing Information
Natural Gas NYMEX HH ($/MMBtu)	$	2.04
C2 + NGL Pricing/gallon⁽¹³⁾	$	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 number of barges and towboats at the end of the period presented.


⁽⁵⁾	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 for full year pro-forma information.


⁽⁶⁾	Utica is an unconsolidated equity method investment and is consolidated for segment purposes only.


⁽⁷⁾	The Jefferson Gas System came online in December 2015. The volumes reported for 2015 are the average daily rate for the days of operation.


⁽⁸⁾	Includes approximately 310 mmcf/d related to unconsolidated equity method investments, Xxxxx and MarkWest Pioneer.


⁽⁹⁾	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.


⁽¹⁰⁾	Hopedale is jointly owned by MarkWest Liberty Midstream and MarkWest Utica EMG, respectively. The Marcellus Operations includes its portion utilized of the jointly owned Hopedale Fractionation Complex. The Utica Operations includes Utica’s portion utilized of the jointly owned Hopedale Fractionation Complex.


⁽¹¹⁾	Includes NGLs fractionated for the Marcellus and Utica operations.


⁽¹²⁾	Purity ethane makes up approximately 104 mbpd of total fractionated products.


⁽¹³⁾	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.

Risk Factors

We are subject to various risks and uncertainties in the course of our business. The discussion of such risks and uncertainties may be found under Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2015. Prior to the date of this report, additional risk factors related to the acquisition of HSM arose in addition to those previously set forth in our Annual Report on Form 10-K for the year ended December 31, 2015. The additional risk factor is presented below.

If foreign ownership of our stock exceeds certain levels, we could be prohibited from operating inland river vessels, which could materially and adversely affect our business, financial condition, results of operations and cash flows.

The Shipping Act of 1916 and Merchant Marine Act of 1920, which we refer to collectively as the Maritime Laws, generally require that vessels engaged in U.S. coastwise trade be owned by U.S. citizens. Among other requirements to establish citizenship, entities that own such vessels must be owned at least 75 percent by U.S. citizens. If we fail to maintain compliance with the Maritime Laws, we would be prohibited from operating vessels in the U.S. inland waters. Such a prohibition could materially and adversely affect our business, financial condition, results of operations and cash flows.

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 gathering, transportation and storage of crude oil and refined petroleum products.

SIGNIFICANT FINANCIAL AND OTHER HIGHLIGHTS

Significant financial and other highlights for the year ended December 31, 2015 are listed below. Refer to Results of Operations and Liquidity and Capital Resources for further details.

•

On March 31, 2016, we purchased HSM from MPC for $600 million, as agreed to in the Contribution Agreement, in equity consideration consisting of 22,534,002 common units and 459,878 general partner units in order for the general partner to maintain its two percent interest. HSM owns and operates towboats (i.e., towing vessels), barges and third party chartered equipment for the transportation of crude oil, feedstocks, refined products and other hydrocarbon-based products to and from refineries and terminals owned by MPC, which are primarily located in the Midwest and Gulf Coast regions of the United States. The consolidated financial statements have been retrospectively recast for all periods presented to include the historical results of HSM because the transaction was between entities under common control.


•	On December 4, 2015, we completed the MarkWest Merger. MarkWest is now a wholly-owned subsidiary of MPLX LP. See Item 8. Financial Statements and Supplementary Data - Note 4 for more information.


•	Total segment operating income attributable to MPLX LP increased approximately $185 million, or 87 percent, in 2015 compared to 2014. The increase was comprised of the following:


•	An increase of approximately $84 million in our L&S segment is primarily due to the acquisition of the remaining interest in Pipe Line Holdings.


•	An increase of approximately $76 million in our G&P segment is due to the MarkWest Merger.


•	The offer to exchange MarkWest senior notes for MPLX senior notes and cash expired in December 2015. Approximately $4.0 billion aggregate principal amount of MarkWest senior notes were exchanged for MPLX senior notes. We incurred approximately $16 million of expenses related to this exchange.

•

On October 27, 2015, in connection with the MarkWest Merger, we amended our $1.0 billion bank revolving credit facility to, among other things, (i) extend the term of the bank revolving credit facility to a five-year term commencing on the date of the closing of the MarkWest Merger and (ii) increase the borrowing capacity of the bank revolving credit facility to up to $2.0 billion. The amendment became effective in connection with the MarkWest Merger.


•	In December 2015, we purchased the remaining 0.5 percent interest in Pipe Line Holdings from MPC for $12 million.

•

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

•

On February 12, 2015, we completed an underwritten public offering of $500 million aggregate principal amount of four percent unsecured senior notes due February 15, 2025 (the “Senior Notes”). The Senior Notes were offered at a price to the public of 99.64 percent of par. The net proceeds of this offering were used to repay the amounts outstanding under our bank revolving credit facility, as well as for general partnership purposes.

In connection with the MarkWest Merger, we recorded approximately $2.5 billion of goodwill. Goodwill is not amortized, but rather is tested for impairment annually or more frequently if warranted due to events or changes in circumstances. See Critical Accounting Estimates - Impairment Assessments of Long-Lived Assets, Intangible Assets, Goodwill and Equity Investments for discussion of recent circumstances that may impact the assessment of goodwill impairment.

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.

We define Adjusted EBITDA as net income adjusted for (i) depreciation and amortization; (ii) provision for income taxes; (iii)non-cash equity-based compensation; (iv) net interest and other financial costs; (v) equity investment income; (vi) equity method distributions; and (vii) acquisition costs. We also use DCF, which we define as Adjusted EBITDA plus (i) the current period cash received/deferred revenue for committed volume deficiencies less (iii) net interest and other financial costs; (iv) unrealized gain on commodity xxxxxx; (v) equity investment capital expenditures paid out; (vi) equity investment cash contributions; (vii) maintenance capital expenditures paid; (viii) volume deficiency credits recognized; and (ix) other non-cash items.

We believe that the presentation of Adjusted EBITDA and DCF provides useful information to investors in assessing our financial condition and results of operations. The GAAP measures most directly comparable to Adjusted EBITDA and DCF are net income and net cash provided by operating activities. Adjusted EBITDA and DCF should not be considered as alternatives 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 purchased product costs less any derivative gain (loss). These charges have been excluded for the purpose of enhancing the understanding by both management and investors of the underlying baseline operating performance of our contractual arrangements, which management uses to evaluate our financial performance for purposes of planning and forecasting. Net operating margin does not have any standardized definition and, therefore, is unlikely to be comparable to similar measures presented by other reporting companies. Net operating margin results should not be evaluated in isolation of, or as a substitute for, our financial results prepared in accordance with GAAP. Our use of net operating margin and the underlying methodology in excluding certain charges is not necessarily an indication of the results of operations expected in the future, or that we will not, in fact, incur such charges in future periods.

In evaluating our financial performance, management utilizes the segment performance measures, segment revenues and segment operating income, including total segment operating income. These financial measures are presented in Item 8.

Financial Statements and Supplementary Data - Note 9 and are considered non-GAAP financial measures when presented outside of the Notes to the Consolidated Financial Statements. The use of these measures allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. See Item 8. Financial Statements and Supplementary Data - Note 9 for the reconciliations of these segment measures, including total segment operating income to their respective most directly comparable GAAP measure.

COMPARABILITY OF OUR FINANCIAL RESULTS

Our acquisitions have impacted comparability of our financial results (see Item 8. Financial Statements and Supplementary Data - Note 4).

RESULTS OF OPERATIONS



	Year Ended December 31,
(In millions)	2015		2014		$ Change			2013		$ Change
Revenues and other income:
Service revenue	$	130	$	70	$	60		$	79	$	(9	)
Service revenue - related parties	593		662		(69		)	586		76
Rental income	20		—		20			—		—
Rental income - related parties	101		15		86			15		—
Product sales	36		—		36			—		—
Product sales - related parties	1		—		1			—		—
Other income	9		6		3			5		1
Other income - related parties	71		40		31			28		12
Total revenues and other income	961		793		168			713		80
Costs and expenses:
Cost of revenues (excludes items below)	225		228		(3		)	200		28
Purchased product costs	20		—		20			—		—
Rental cost of sales	5		1		4			1		—
Purchases - related parties	166		153		13			151		2
Depreciation and amortization	116		75		41			70		5
General and administrative expenses	118		81		37			69		12
Other taxes	13		10		3			9		1
Total costs and expenses	663		548		115			500		48
Income from operations	298		245		53			213		32
Interest expense (net of amounts capitalized of $5 million, $1 million and $1 million, respectively)	35		4		31			—		4
Other financial costs	13		1		12			1		—
Income before income taxes	250		240		10			212		28
Provision for income taxes	1		1		—			1		—
Net income	249		239		10			211		28
Less: Net income attributable to noncontrolling interests	1		57		(56		)	68		(11		)
Net income attributable to Predecessor	92		61		31			65		(4		)
Net income attributable to MPLX LP	$	156	$	121	$	35		$	78	$	43

Adjusted EBITDA attributable to MPLX LP⁽¹⁾	$	486	$	166	$	320		$	111	$	55
DCF attributable to MPLX LP⁽¹⁾	399		137		262			114		23


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

The following tables present a reconciliation of Adjusted EBITDA and DCF to net income and net cash provided by operating activities, the most directly comparable GAAP financial measures. Items from Adjusted EBITDA attributable to MPLX LP to DCF attributable to MPLX LP are shown net of noncontrolling interest.



(In millions)	2015			2014			2013
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to MPLX LP from Net Income:
Net income	$	249		$	239		$	211
Plus: Depreciation and amortization	116			75			70
Provision for income taxes	1			1			1
Non-cash equity-based compensation	4			2			1
Net interest and other financial costs	48			5			1
Income from equity investments	(3		)	—			—
Distributions from unconsolidated subsidiaries	15			—			—
Acquisition costs	30			—			—
Adjusted EBITDA	460			322			284
Less: Adjusted EBITDA attributable to noncontrolling interests	1			69			86
Adjusted EBITDA attributable to pre-acquisition HSM	119			87			87
MarkWest's pre-merger EBITDA ⁽¹⁾	146			—			—
Adjusted EBITDA attributable to MPLX LP	486			166			111
Plus: Current period cash received/deferred revenue for committed volume deficiencies	44			31			19
Less: Net interest and other financial costs	36			6			2
Unrealized gain on commodity xxxxxx	4			—			—
Equity investment capital expenditures paid out	(14		)	—			—
Investment in unconsolidated affiliates	14			—			—
Maintenance capital expenditures paid	31			22			19
Volume deficiency credits recognized	38			34			2
Other	7			—			—
Adjustments attributable to pre-acquisition HSM	(1		)	(2		)	(7		)
DCF pre-MarkWest undistributed	415			137			114
MarkWest undistributed DCF⁽¹⁾	(16		)	—			—
DCF attributable to MPLX LP	$	399		$	137		$	114


⁽¹⁾	MarkWest pre-merger EBITDA and undistributed DCF relates to MarkWest's EBITDA and DCF from Oct. 1, 2015, through Dec. 3, 2015.



(In millions)	2015			2014			2013
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to MPLX LP from Net Cash Provided by Operating Activities:
Net cash provided by operating activities	$	340		$	334		$	297
Less: Changes in working capital items	(54		)	19			22
All other, net	17			2			1
Plus: Non-cash equity-based compensation	4			2			1
Net interest and other financial costs	48			5			1
Asset retirement expenditures	1			2			8
Acquisition costs	30			—			—
Adjusted EBITDA	460			322			284
Less: Adjusted EBITDA attributable to MPC-retained interest	1			69			86
Adjusted EBITDA attributable to pre-acquisition HSM	119			87			87
MarkWest's pre-merger EBITDA ⁽¹⁾	146			—			—
Adjusted EBITDA attributable to MPLX LP	486			166			111
Plus: Current period cash received/deferred revenue for committed volume deficiencies	44			31			19
Less: Net interest and other financial costs	36			6			2
Unrealized gain on commodity xxxxxx	4			—			—
Equity investment capital expenditures paid out	(14		)	—			—
Equity investment cash contributions	14			—			—
Maintenance capital expenditures paid	31			22			19
Volume deficiency credits recognized	38			34			2
Other	7			—			—
Adjustments attributable to pre-acquisition HSM	(1		)	(2		)	(7		)
DCF pre-MarkWest undistributed	415			137			114
MarkWest undistributed DCF⁽¹⁾	(16		)	—			—
DCF attributable to MPLX LP	$	399		$	137		$	114


⁽¹⁾	MarkWest pre-merger EBITDA and undistributed DCF relates to MarkWest's EBITDA and DCF from Oct. 1, 2015, through Dec. 3, 2015.

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



(In millions)	2015			2014			2013
Reconciliation of net operating margin to income from operations:
Segment revenue	$	910		747			680
Purchased product costs	20			—			—
Less: Unrealized derivative gain related to purchased product costs	5			—			—
Less: Realized derivative gain related to revenues and purchased product costs	4			—			—
Net operating margin	881			747			680
Revenue adjustment from unconsolidated affiliates⁽¹⁾	(28		)	—			—
Realized derivative gain related to revenues and purchased product costs	4			—			—
Total unrealized derivative gain	4			—			—
Other income	9			6			5
Other income - related parties	71			40			28
Cost of revenues (excludes items below)	(225		)	(228		)	(200		)
Rental expenses	(5		)	(1		)	(1		)
Purchases - related parties	(166		)	(153		)	(151		)
Depreciation and amortization	(116		)	(75		)	(70		)
General and administrative expenses	(118		)	(81		)	(69		)
Other taxes	(13		)	(10		)	(9		)
Income from operations	$	298		$	245		$	213


⁽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.

2015 Compared to 2014

Service revenue increased $60 million in 2015 compared to 2014. This variance was primarily due to an $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 decreased $69 million in 2015 compared to 2014. This decrease was primarily related to the income from the transportation service agreement entered into by HSM with MPC in 2015 as it was then considered an operating lease so a portion of the revenue was included in rental income-related parties. This decrease was also related to 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 and a $3 million increase in storage fees and other revenue related to the expansion of the Patoka Tank Farms.

Rental income increased $20 million in 2015 compared to 2014. This increase was primarily related to a rental income from the G&P segment due to MarkWest Merger.

Rental income-related parties increased $86 million in 2015 compared to 2014. This increase was primarily related to the transportation service agreement entered into by HSM with MPC in January 2015. Prior to January 2015, there 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 primarily due to the MarkWest Merger.

Other income and other income-related parties increased a total of $34 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 reclass in fees received from the agreements for the maintenance repair facility and an increase due to the MarkWest Merger.

Cost of revenues decreased $3 million in 2015 compared to 2014 primarily due to the MarkWest Merger, partially offset by decrease in average fuel costs. The variance was also due to costs associated with rental income from the operating lease entered into in January 2015 which moved to rental cost of sales.

Rental cost of sales increased $4 million in 2015 compared to 2014 primarily due costs associated with rental income which were moved from cost of revenues related to the operating lease entered into in January 2015.

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

Purchases-related parties increased $13 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, partially offset by increased capitalization of employee costs associated with capital projects.

Depreciation and amortization expense increased $41 million in 2015 compared to 2014 primarily due to the MarkWest Merger.

General and administrative expenses increased $37 million in 2015 compared to 2014. The increase in 2015 was primarily related to $30 million in acquisition costs.

Other taxes increased $3 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 $43 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 senior notes.

During 2015 and 2014, MPC did not ship its minimum committed volumes on certain of our pipeline systems. As a result, MPC was obligated to make $44 million and $41 million of deficiency payments in 2015 and 2014, respectively. We record deficiency payments as Deferred revenue-related parties on our Consolidated Balance Sheets. During 2015 and 2014, we recognized revenue of $38 million and $45 million, respectively, related to volume deficiency credits. At December 31, 2015

and 2014, the cumulative balance of Deferred revenue-related parties on our Consolidated Balance Sheets related to volume deficiencies was $36 million and $30 million, respectively. The following table presents the future expiration dates of the associated deferred revenue credits for 2015:



(In millions)
March 31, 2016	$	7
June 30, 2016	5
September 30, 2016	9
December 31, 2016	10
March 31, 2017	2
June 30, 2017	1
September 30, 2017	1
December 31, 2017	1
Total	$	36

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 and when it becomes impossible to physically transport volumes necessary to utilize the accumulated credits or upon expiration of the make-up period. However, deficiency payments are included in the determination of DCF in the period in which a deficiency occurs since the cash has been received.

2014 Compared to 2013

Service revenue decreased $9 million in 2014 compared to 2013. This variance was primarily due to a $14 million decrease related to a 47 mbpd reduction in third-party crude oil and products volumes shipped, offset by a $4 million increase resulting from higher average tariffs received on the volumes of crude oil and products shipped.

Service revenue-related parties increased $76 million in 2014 compared to 2013. This increase was primarily related to a $40 million increase in revenue related to volume deficiency credits, $25 million due to higher average tariffs received on the volumes of crude oil and products shipped and increased revenue from 15 additional barges and one additional towboat.

Other income and other income-related parties increased a total of $13 million in 2014 compared to 2013. The net increase was primarily due to an increase in fees received for operating MPC’s private pipeline systems and the maintenance repair facility for the inland marine business.

Cost of revenues increased $28 million in 2014 compared to 2013. The increase was primarily due to an increase in contract services used for maintenance activities and increased average fuel costs.

Purchases-related parties increased $2 million in 2014 compared to 2013. The increase was primarily due to higher compensation expenses provided under the omnibus and employee services agreements with MPC.

Depreciation and amortization expense increased $5 million in 2014 compared to 2013 due to the completion of various capital projects.

General and administrative expenses increased $12 million in 2014 compared to 2013. The increase in 2014 is primarily related to services provided under the omnibus and employee services agreements with MPC and increased consulting fees related to the acquisitions in 2014.

Other taxes increased $1 million in 2014 compared to 2013. The increase was primarily due to increased property taxes from investment activities in 2014.

Interest expense and other financial costs increased $4 million in 2014 compared to 2013. The increase was due to borrowings on the bank revolving credit facility and new term loan in 2014.

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. L&S segment information for prior periods include HSM as it is an entity under common control. 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) and depreciation are not allocated to the reportable segments. Management does not consider these items allocable to or controllable by any individual segment and, therefore, excludes these items when evaluating segment performance. Segment results are also adjusted to exclude the portion of income from operations attributable to the noncontrolling interests related to partially owned entities that are either consolidated or accounted for as equity method investments.

The tables below present information about segment operating income for the reported segments for the years ended December 31, 2015 and 2014. For information for the year ended December 31, 2013, see Results of Operations.

L&S Segment



(In millions)	2015		2014		$ Change			% Change
Revenues and other income:
Segment revenue	$	760	$	747	$	13		2	%
Segment other income	75		46		29			63	%
Total segment revenues and other income	835		793		42			5	%
Costs and expenses:
Segment cost of revenues	379		392		(13		)	(3	)%
Segment operating income before portion attributable to noncontrolling interest	456		401		55			14	%
Segment portion attributable to noncontrolling interest and Predecessor	134		188		(54		)	(29	)%
Segment operating income attributable to MPLX LP	$	322	$	213	$	109		51	%

Segment revenue increased due to 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 $29 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.

Segment cost of revenues decreased $13 million primarily due a decrease in the average fuel costs and increased capitalization of employee costs associated with capital projects, partially offset by higher compensation expenses provided under the omnibus and employee services agreements with MPC.

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

G&P Segment



(In millions)	2015		2014		$ Change		% Change
Revenues and other income:
Segment revenue	$	150	$	—	$	150	—	%
Segment other income	—		—		—		—	%
Total segment revenues and other income	150		—		150		—	%
Costs and expenses:
Segment cost of revenues	62		—		62		—	%
Segment operating income before portion attributable to noncontrolling interest	88		—		88		—	%
Segment portion attributable to noncontrolling interest	12		—		12		—	%
Segment operating income attributable to MPLX LP	$	76	$	—	$	76	—	%

The G&P segment increased overall due to the MarkWest Merger.

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, 2015 and 2014.



(In millions)	2015			2014
Reconciliation to Income from operations:
L&S segment operating income attributable to MPLX	$	322		$	213
G&P segment operating income attributable to MPLX	76			—
Segment operating income attributable to MPLX	398			213
Segment portion attributable to unconsolidated affiliates	(21		)	—
Segment portion attributable to noncontrolling interest	146			188
Income from equity method investments	3			—
Other income - related parties	2			—
Unrealized derivative gains	4			—
Depreciation and amortization	(116		)	(75		)
General and administrative expenses	(118		)	(81		)
Income from operations	$	298		$	245



(In millions)	2015			2014
Reconciliation to Total revenues and other income:
Total segment revenues and other income	$	985		$	793
Revenue adjustment from unconsolidated affiliates	(28		)	—
Income from equity method investments	3			—
Other income - related parties	2			—
Unrealized derivative loss	(1		)	—
Total revenues and other income	$	961		$	793



(in millions)	2015			2014
Reconciliation to Net income attributable to noncontrolling interests
Segment portion attributable to noncontrolling interest and Predecessor	$	146		$	188
Portion of noncontrolling interests and Predecessor related to items below segment income from operations	(48		)	(70		)
Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates	(5		)	—
Net income attributable to noncontrolling interests and Predecessor	$	93		$	118

SUPPLEMENTAL MD&A - G&P PRO FORMA

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

The tables below present financial information, as evaluated by management, for the reported segments for the years ended December 31, 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). We believe this full year 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 9).



(In millions)	2015		2014		$ Change			% Change
Revenues and other income:
Segment revenue	$	2,151	$	2,168	$	(17	)	(1	)%
Total segment revenues and other income	2,151		2,168		(17		)	(1	)%
Costs and expenses:
Segment cost of revenues	903		1,197		(294		)	(25	)%
Segment operating income before portion attributable to noncontrolling interest	1,248		971		277			29	%
Segment portion attributable to noncontrolling interest	156		36		120			333	%
Segment operating income attributable to MPLX LP	$	1,092	$	935	$	157		17	%

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%. 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’s segment operating income attributable to MPLX LP to G&P income from operations, G&P segment revenues and other income to G&P total revenues and other income, and G&P segment portion attributable to noncontrolling interests for the years ended December 31, 2015 and 2014, respectively. The ensuing items listed below the Other income-related parties lines are not allocated to business segments as management does not consider these items allocable to any individual segment.



(In millions)	2015			2014
Pro forma reconciliation to total revenues and other income:
Total G&P segment revenues and other income	2,151			2,168
Revenue adjustment from unconsolidated affiliates	(303		)	(41		)
Income (loss) from equity method investments	13			(12		)
G&P Other income - related parties	(4		)	19
Unrealized derivative (losses) gains related to revenue	(10		)	25
Total pro forma G&P revenues and other income	$	1,847		$	2,159
Total pro forma L&S revenues and other income	835			813
Total pro forma revenues and other income	$	2,682		$	2,972



(In millions)	2015			2014
Pro Forma reconciliation to pro forma net income attributable to MPLX LP:
Segment operating income attributable to G&P	$	1,092		$	935
G&P Segment portion attributable to unconsolidated affiliates	(101		)	(8		)
G&P Segment portion attributable to noncontrolling interest	38			21
G&P Income (loss) from equity method investments	13			(12		)
G&P Other income - related parties	(4		)	19
Unrealized derivative (losses) gains	(10		)	82
Impairment expense	(26		)	(62		)
G&P Depreciation	(500		)	(481		)
G&P General and administrative expenses	(125		)	(130		)
Pro forma G&P income from operations	$	377		$	364
Pro forma L&S income from operations	292			266
Pro forma income from operations	669			630
G&P Debt retirement expense	118			—
Net interest and other financial costs	259			189
Pro forma income before income taxes	292			441
Provision (benefit) for income taxes	(10		)	46
Pro forma net income	302			395
Less: Net income attributable to noncontrolling interests	55			66
Pro forma net income attributable to MPLX LP	$	247		$	329



Pro Forma Operating Statistics	2015		2014		% Change
Gathering Throughput (mmcf/d)
Xxxxxxxxx operations	858		668		28	%
Utica operations⁽¹⁾	673		289		133	%
Southwest operations⁽²⁾	1,413		1,336		6	%
Total gathering throughput	2,944		2,293		28	%

Natural Gas Processed (mmcf/d)
Marcellus operations	2,861		2,064		39	%
Utica operations⁽¹⁾	883		416		112	%
Southwest operations	1,077		991		9	%
Southern Appalachian operations	267		280		(5	)%
Total natural gas processed	5,088		3,751		36	%

C2 + NGLs Fractionated (mbpd)
Marcellus operations⁽³⁾⁽⁴⁾	194		147		32	%
Utica operations⁽¹⁾⁽⁴⁾	40		19		111	%
Southwest operations	18		21		(14	)%
Southern Appalachian operations⁽⁵⁾	15		19		(21	)%
Total C2 + NGLs fractionated⁽⁶⁾	267		206		30	%

Pricing Information
Natural Gas NYMEX HH ($/MMBtu)	$	2.63	$	4.28	(39	)%
C2 + NGL Pricing/gallon⁽⁷⁾	$	0.46	$	0.92	(50	)%


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


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


⁽³⁾	The Keystone ethane fractionation complex began operations in June 2014. The volumes reported for 2014 are the average daily rate for the days of operation.

⁽⁴⁾

Hopedale is jointly owned by MarkWest Liberty Midstream and MarkWest Utica EMG, respectively. The Marcellus Operations includes its portion utilized of the jointly owned Hopedale Fractionation Complex. The Utica Operations includes Utica’s portion utilized of the jointly owned Hopedale Fractionation Complex. Operations began in January 2014 and December 2014. The volumes reported for 2014 are the average daily rate for the days of operation.


⁽⁵⁾	Includes NGLs fractionated for the Marcellus and Utica operations.


⁽⁶⁾	Purity ethane makes up approximately 79 mbpd and 67 mbpd of total fractionated products for the years ended December 31, 2015 and December 31, 2014, respectively.


⁽⁷⁾	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 $43 million at December 31, 2015 compared to $27 million at December 31, 2014. 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)	2015			2014			2013
Net cash provided by (used in):
Operating activities	$	340		$	334		$	297
Investing activities	(1,599		)	(137		)	(158		)
Financing activities	1,275			(224		)	(302		)
Total	$	16		$	(27	)	$	(163	)

Cash Flows Provided by Operating Activities. Net cash provided by operating activities increased $6 million in 2015 compared to 2014, primarily due to a $10 million increase in net income and a $35 million unfavorable impact from changes in working capital as discussed below, partially offset by a $11 million increase in all other, net.

For 2015, changes in working capital were a net $54 million use of cash. Third-party receivables were a $29 million use of cash primarily due to higher third-party tariff revenue receivables. Net liabilities to related parties were a $22 million use of cash. Third-party accounts payables and liabilities were a $2 million source of cash due to the timing of project expenditures.

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 third-party receivables. Net liabilities to related parties increased $15 million from 2013, 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. Third-party receivables decreased $2 million primarily associated with lower tariff revenue receivables from lower product volumes shipped and timing of collections.

For 2013, changes in working capital were a net $23 million source of cash, primarily due to an increase in net liabilities to related parties and a decrease in third-party receivables. Net liabilities to related parties increased $19 million from 2012, primarily due to an increase in deferred revenue associated with deficiency payments, partially offset by an increase in receivables from related parties. Third-party receivables decreased $6 million primarily due to lower tariff revenue receivables from lower product volumes shipped.

Cash Flows Used in Investing Activities. Net cash used in investing activities increased $1.5 billion in 2015 compared to 2014, primarily due to $1.2 billion increase in acquisitions due to the MarkWest Merger and $147 million increase in additions to property, plant and equipment.

Net cash used in investing activities decreased $21 million in 2014 compared to 2013, primarily due to a $10 million decrease in additions to property, plant and equipment. Xxxx used for additions to property, plant and equipment were $141 million in 2014 and $151 million in 2013. The reduction was primarily associated with lower expansion capital expenditures in 2014.

Cash Flows from Financing Activities. Net cash provided by financing activities in 2015 was $1.3 billion compared to net cash used in 2014 of $224 million. The source of cash in 2015 was primarily due to $1.2 billion of contributions from MPC for the MarkWest Merger, $38 million in increased net long-term debt borrowings, $8 million in net proceeds from related party debt with MPC and $169 million in net proceeds from MPLX GP in exchange for a number of general partnership units that allowed it to maintain its general partnership interest, partially offset by $159 million in distributions to unitholders, the general partner and noncontrolling interests. The use of cash in 2014 was primarily due to $910 million in distributions to MPC related to the acquisition of an interest in Pipe Line Holdings and $150 million in distributions to unitholders, the general partner and noncontrolling interests, partially offset by $631 million in net long-term debt borrowings and $230 million in net proceeds from equity offerings.

Net cash used in financing activities decreased $78 million in 2014 compared to 2013, primarily due to $632 million in increased net long-term debt borrowings and $230 million in net proceeds from the equity offerings of common units representing limited partnership interests and contributions from MPLX GP LLC in exchange for a number of general

partnership units that allowed it to maintain its two percent general partnership interest, partially offset by $810 million in increased distributions to MPC related to the acquisition of interests in Pipe Line Holdings.

Debt and Liquidity Overview

Our outstanding borrowings at December 31, 2015 and 2014 consisted of the following:



	December 31,
(In millions)	2015			2014
MPLX LP:
Bank revolving credit facility due 2020	$	877		$	385
Term loan facility due 2019	250			250
5.500% senior notes due 2023	710			—
4.500% senior notes due 2023	989			—
4.875% senior notes due 2024	1,149			—
4.000% senior notes due 2025	500			—
4.875% senior notes due 2025	1,189			—
Consolidated subsidiaries:
MarkWest - 5.500% senior notes due 2023	40			—
MarkWest - 4.500% senior notes due 2023	11			—
MarkWest - 4.875% senior notes due 2024	1			—
MarkWest - 4.875% senior notes due 2025	11			—
MPL - capital lease obligations due 2020	9			10
Total	5,736			645
Unamortized debt issuance costs⁽¹⁾	(8		)	—
Unamortized discount⁽²⁾	(472		)	—
Amounts due within one year	(1		)	(1		)
Total long-term debt due after one year	$	5,255		$	644


⁽¹⁾	We adopted the updated FASB debt issuance cost standard as of June 30, 2015. This has been applied retrospectively and there was no effect to the prior period presented.


⁽²⁾	2015 includes $465 million discount related to the difference between the fair value and the principal amount of the assumed MarkWest debt.

As described in further detail below, the increase in debt as of year-end 2015 compared to year-end 2014 was primarily related to debt assumed in the MarkWest Merger during 2015.

On November 20, 2014, MPLX 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 entered into an amendment to 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’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 2015, we borrowed $992 million under the bank revolving credit facility, at an average interest rate of 1.617 percent, and repaid $500 million of these borrowings. At December 31, 2015, we had $877 million of borrowings and $8 million in letters of credit outstanding under this facility, resulting in total unused loan availability of $1.1 billion, or 55.8 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 2015 were at an average interest rate of 1.670 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 restrictive covenants and events of default that we consider to be usual and customary for an agreement of that type. 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, 2015, we were in compliance with this financial covenant with a ratio of Consolidated Total Debt to Consolidated EBITDA of 4.6 to 1.0, as well as other covenants contained in the Credit Agreement.

As of December 31, 2015, 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, 2015, 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 16.

Our intention is to maintain an investment grade credit profile. As of December 31, 2015, 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 for our senior unsecured debt to below investment grade credit 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 $1.7 billion at December 31, 2015 consisting of:



	December 31, 2015
(In millions)	Total Capacity		Outstanding Borrowings			Available Capacity
MPLX - bank revolving credit facility⁽¹⁾	$	2,000	$	(885	)	$	1,115
MPC Investment - loan agreement	500		$	(8	)	492
Total	$	2,500	$	(893	)	1,607
Cash and cash equivalents						43
Total liquidity						$	1,650


⁽¹⁾	Outstanding borrowings includes $8 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, funding from MPC and opportunistically issuing additional debt and equity securities. We believe that cash generated from these sources will be sufficient to meet our short-term and long-term funding requirements, including working capital requirements, capital expenditure requirements, contractual obligations, repayment of debt maturities and quarterly cash distributions. MPC manages some of our cash and cash equivalents on our behalf directly with third-party institutions as part of the treasury services that it provides to us under our omnibus agreement. From time to time we may also consider other sources of liquidity, including formation of joint ventures or sales of non-strategic assets.

Equity Overview

The table below summarizes the changes in the number of units outstanding through December 31, 2015:



(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 for Pipe Line Holdings acquisition	—	—	—		—	—
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

For more details on equity activity, see Item 8. Financial Statements and Supplementary Data - Note 8.

We intend to pay a minimum quarterly distribution of $0.2625 per unit, which equates to $79.7 million per quarter, or $318.8 million per year, based on the number of common and general partner units. On January 25, 2016, we announced that the board of directors of our general partner had declared a distribution of $0.5000 per unit that was paid on February 12, 2016 to unitholders of record on February 4, 2016. This represents a 29 percent increase in 2015. 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 year ended December 31, 2015, 2014 and 2013. 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)	2015		2014		2013
Distribution declared:
Limited partner units - public	$	151	$	29	$	23
Limited partner units - MPC	104		77		63
General partner units - MPC	6		2		2
Incentive distribution rights - MPC	54		4		—
Total distribution declared	$	315	$	112	$	88

Cash distributions declared per limited partner common unit:
Quarter ended March 31	$	0.4100	$	0.3275	$	0.2725
Quarter ended June 30	0.4400		0.3425		0.2850
Quarter ended September 30	0.4700		0.3575		0.2975
Quarter ended December 31	0.5000		0.3825		0.3125
Year ended December 31	$	1.8200	$	1.4100	$	1.1675

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 development or acquisition of additional pipeline 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)	2015			2014		2013
Maintenance	$	33		$	30	$	29
Growth	282			124		126
Total capital expenditures	315			154		155
Less: Increase in capital accruals	26			11		(4		)
Asset retirement expenditures	1			2		8
Additions to property, plant and equipment	288			141		151
Capital expenditures of unconsolidated subsidiaries⁽¹⁾	24			—		—
Total gross capital expenditures	312			141		151
Joint venture partner contributions⁽²⁾	(8		)	—		—
Total gross capital expenditures, net	$	304		$	141	$	151


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


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

Our board originally approved a 2016 growth capital plan of $1.7 billion. In light of current market conditions, we expect capital spending to be between $800 million and $1.2 billion. This growth capital plan excludes the HSM acquisition. The G&P segment capital plan is primarily for investment in gathering, processing, and fractionation infrastructure in the Marcellus and Utica shale plays, as well as the STACK and SCOOP formations in the Cana-Woodford Shale in Oklahoma and the Permian Basin in New Mexico and Texas. The L&S segment capital plan is primarily related to the Cornerstone project and downstream Utica infrastructure development. The Cornerstone project is the building block for the other projects that will become a critical solution for the industry to move condensate and natural gas liquids out of the Utica region into refining centers in Northwest

Ohio and connect the pipelines to Canada. We continuously evaluate our capital plan and make changes as conditions warrant. On February 3, 2016, we announced that MPC has offered to contribute its inland marine business in exchange for securities, which would be in addition to the capital plan amounts above.

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 timing by which we expect that they will be utilized 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.

Contractual Cash Obligations

The table below provides aggregated information on our consolidated obligations to make future payments under existing contracts as of December 31, 2015:



(In millions)	Total		2016		2017-2018		2019-2020		Later Years
Bank revolving credit facility⁽¹⁾	$	972	$	19	$	39	$	914	$	—
Term loan⁽¹⁾	268		5		9		254		—
Long-term debt⁽¹⁾	6,520		221		442		442		5,415
Capital lease obligations	11		1		3		7		—
Operating lease and long-term storage agreements⁽²⁾	303		49		89		65		100
Purchase obligations:
Contracts to acquire property, plant & equipment	144		142		2		—		—
Other contracts	42		34		6		—		2
Total purchase obligations⁽³⁾	186		176		8		—		2
Natural gas purchase obligations⁽⁴⁾	91		12		25		26		28
SMR liability⁽⁵⁾	247		17		34		34		162
Transportation and terminalling⁽⁶⁾	619		68		134		118		299
Other long-term liabilities reflected on the Consolidated Balance Sheets:
Other liabilities⁽⁷⁾	50		25		25		—		—
AROs⁽⁸⁾	17		—		—		—		17
Total contractual cash obligations	$	9,284	$	593	$	808	$	1,860	$	6,023


⁽¹⁾	Amounts represent outstanding borrowings at December 31, 2015 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 15 for the fair value of the frac spread sharing component). We use the estimated future frac spreads as of December 31, 2015 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 22 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⁾	Represents 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 $20 million. The total amount to be paid is approximately $37 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 so long as MPC controls our general partner. Under the omnibus agreement, we pay to MPC in equal monthly installments an annual amount of approximately $37 million in 2015 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 $4 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.

One of the employee services agreement with MPC addresses reimbursement to MPC for the provision of certain operational and management services to us in support of our pipelines, barge dock and tank farms. This employee services agreement has an initial term that extends through September 30, 2017. We pay MPC a monthly fee that reflects the total employee-based salary and wage costs (including accruals) incurred in providing these services during such month, including a monthly allocated portion of estimated employee benefit costs, bonus accrual, MPC stock-based compensation expense and employer payroll taxes, plus an additional $125,000. On December 28, 2015, MPLX LP entered into an employee services agreement with MW Logistics Services LLC (“MWLS”). Pursuant to the terms of the agreement, MWLS provides operational and management services to MPLX in support of the assets owned or operated by MarkWest, as well as certain other services to support the MPLX business. Under the terms of the agreement, MPLX pays MWLS a monthly fee to reflect the total employee-based salary, wage and benefits costs and other expenses incurred by MWLS in providing the services during such month. The agreement is effective until December 28, 2020 and automatically renews for two additional renewal terms for up to five years each unless terminated earlier under the provisions of the agreement. We incurred $158 million of expenses under the employee services agreements for 2015.

Off-Balance Sheet Arrangements

We do not engage in off-balance sheet financing activities. As of December 31, 2015, 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 prices of and demand for natural gas, NGLs, crude oil and refined products, actions of competitors, 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.

Effects of Inflation

Inflation did not have a material impact on our results of operations for the years ended December 31, 2015, 2014 or 2013. 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 18.2 percent limited partner interest (excluding the Class A units owned by MarkWest Hydrocarbon, a wholly-owned subsidiary of the Partnership, and including the Class B units on an as-converted basis) in us as of February 12, 2016 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 79 percent, 90 percent and 88 percent of our total revenues and other income for 2015, 2014 and 2013. We provide to MPC crude oil and product pipeline transportation services based on regulated tariff rates and storage services based on contracted rates.

Of our total costs and expenses, MPC accounted for 35 percent, 41 percent and 43 percent for 2015, 2014 and 2013. 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, other than certain transactions with MPC for periods prior to the Initial Offering, related to the provision of administrative services, have generally been conducted under terms comparable to those with unrelated parties. For further discussion of activity with related parties and MPC 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)	2015			2014			2013
Capital	$	2		$	2		$	1
Percent of total capital expenditures	1		%	3		%	—		%
Compliance:
Operating and maintenance	$	22		$	22		$	41
Remediation⁽¹⁾	2			2			5
Total	$	24		$	24		$	46


⁽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 $1 million in 2016. 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.

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. Therefore, it is possible that adjustments will be made to the purchase price allocation during the year-ending December 31, 2016.



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, 2015, there were no indicators of impairment for any of our long-lived assets, primarily as a result of the G&P segment’s assets and customer contract intangible assets being recorded at fair value as of December 4, 2015. A significant variance in any of the assumptions or factors used to estimate future cash flows would have resulted in a different allocation of the purchase price, resulting in an increased/(decreased) carrying value of goodwill recorded as of December 4, 2015. This would have changed depreciation/amortization expense on a prospective basis as long-lived assets are depreciated/amortized and goodwill is not amortized. See Item 8. Financial Statements and Supplementary Data - Note 4 for additional information on the MarkWest Merger.
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 and determined the fair value of our reporting units using the income and market approaches for our 2015 impairment analysis. These types of analyses require us to make assumptions and estimates regarding industry and economic factors such as relevant commodity prices, contract renewals, and production volumes. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations. Management also performed a quantitative analysis on the goodwill reported in the L&S segment. For the current year qualitative analysis, we analyzed whether there were any changes in the assumptions used to perform our December 4, 2015 purchase price allocation in light of current economic conditions to determine if it was more likely than not that impairment exists in the G&P segment. Management also performed a qualitative analysis on the goodwill reported in the L&S segment. 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.	As of December 31, 2015, there were no indicators of impairment for our goodwill, primarily as a result of the goodwill allocated to reporting units in the G&P segment being recorded at their fair values in connection with the December 4, 2015 MarkWest Merger. The carrying values of the G&P segment reporting units equaled their fair values as of the date of the merger. Any decrease in the fair value of these reporting units going forward could result in an impairment charge to the approximate $2.5 billion of goodwill recorded in connection with the MarkWest Merger. In February of 2016, our units were trading at a price per unit significantly lower that the price per unit used to calculate the merger consideration and the resulting goodwill that was assigned to certain reporting units in our G&P segment. The significant assumptions that were used to develop the estimates of the fair values recorded in acquisition accounting and the resulting goodwill assigned to the reporting units included discount rates, growth rates and customer attrition rates. If we experience negative events related to these assumptions or if the market price of our units continues to trade at a low level in 2016, we may need to assess whether this is a change in circumstances that indicates it is more likely than not that the fair value of the reporting units to which the goodwill was assigned in connection with the merger is less than the carrying value and, if so, evaluate goodwill for impairment. See Item 8. Financial Statements and Supplementary Data - Note 4 for additional information on the MarkWest Merger.



Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Impairment of Equity Investments
We evaluate our equity method investments in Centrahoma, Jefferson Dry Gas, MarkWest Utica EMG and MarkWest Pioneer, for impairment whenever events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced a decline in value. When evidence of an other-than-temporary loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment should be recorded.	Our impairment assessment requires us to apply judgment in estimating future cash flows received from or attributable to our equity method investments. The primary estimates may include the expected volumes, the terms of related customer agreements and future commodity prices.	Our investments in Centrahoma, Jefferson Dry Gas, MarkWest Utica EMG and MarkWest Pioneer were recorded at fair value based on the MarkWest Merger on December 4, 2015. If expected cash flows used to determine the fair value as of December 4, 2015 are not realized our equity method investments may be subject to future impairment charges. See Item 8. Financial Statements and Supplementary Data - Note 4 for additional information on the MarkWest Merger.
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% difference in our estimated fair value of Level 2 and 3 derivatives at December 31, 2015 would have affected income before income taxes by approximately $3 million for the year ended December 31, 2015.



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, 2015, we have estimated the probability that the producer customer will exercise its option to extend the agreements for the first renewal period is 50%, and for the second renewal period is 75% 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% increase (decrease) in NGL price curves causes a 46% increase (decrease) in the liability as of December 31, 2015. Holding the NGL curves constant, a 10% increase (decrease) in the natural gas curves causes a 56% (decrease) increase in the liability as of December 31, 2015. 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% for the first renewal period and 50% for the second renewal period as of December 31, 2015, the liability would be reduced by 18%. If it were determined that the probability of exercise was 75% for the first renewal period and 100% for the second renewal period as of December 31, the liability would be increased by 21%. 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 and Ohio Condensate 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 either 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.
Income Taxes
Under the asset and liability method of income tax accounting, deferred tax assets and liabilities are determined based on differences between the financial reporting and the tax basis of assets and liabilities and are measured using the tax rates and laws that are expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A deferred tax asset must be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized prior to expiration.	We have deferred tax assets related to NOL carryforwards. Management’s assessment of our ability to utilize the NOL carryforwards depends upon our estimates of future taxable income. There are many risks and other factors that could cause our actual future taxable income to be significantly different than our estimates. These factors include but are not limited to, changes in production volumes of natural gas by our producer customers, our ability to retain customers, changes in laws or regulations impacting our operations, changes in commodity prices, etc.	As of December 31, 2015, we had tax-effected NOL carryforwards for federal and state income tax purposes of approximately $58 million and $4 million, respectively. We believe that we will be able to fully utilize these NOL carryforwards and therefore have not recorded a valuation allowance. If for any reason our future taxable income is less than we have estimated, we may not realize the full benefit of these NOL carryforwards.



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 22.

Recent Accounting Pronouncements

From time to time, new accounting pronouncements are issued by 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
Introductory Note to Combined Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm	31
Audited Consolidated Financial Statements:
Combined Consolidated Statements of Income	32
Combined Consolidated Balance Sheets	33
Combined Consolidated Statements of Cash Flows	34
Combined Consolidated Statements of Equity	35
Notes to Combined Consolidated Financial Statements	36
Select Quarterly Financial Data (Unaudited)	90

Introductory Note to Combined Consolidated Financial Statements

On March 14, 2016, MPLX LP (the “Partnership”) entered into a Membership Interests Contribution Agreement (the “Contribution Agreement”) with MPLX GP LLC, the general partner of the Partnership (the “General Partner”), MPLX Logistics Holdings LLC (“MPLX Logistics”) and MPC Investment LLC (“MPC Investment”), each a wholly-owned subsidiary of Marathon Petroleum Corporation (“MPC”). Pursuant to the Contribution Agreement, the Partnership agreed to acquire from MPC Investment for equity consideration valued at approximately $600 million (the “Equity Consideration”), all of the limited liability company interests of Xxxxxx Street Marine LLC (“HSM”), through a series of intercompany contributions (the “Transaction”).

The Transaction closed on March 31, 2016. In exchange for all of the limited liability company interests of HSM, the Partnership issued the Equity Consideration consisting of (i) 22,534,002 MPLX common units to MPLX Logistics and (ii) 459,878 general partner units to the General Partner in order to maintain its 2% general partner interest in the Partnership. MPLX Logistics agreed to waive distributions on the MPLX common units issued in connection with the Transaction for the Partnership’s first quarter 2016 cash distribution, and the General Partner will not be entitled to receive general partner distributions or incentive distribution rights that would otherwise accrue on such MPLX common units with respect to the Partnership’s first quarter 2016 cash distribution.

The Partnership’s combined consolidated financial statements include periods prior to the acquisition of HSM. Consequently, the Partnership’s combined consolidated financial statements have been retrospectively recast for all periods presented to include the historical results of HSM because the transaction was between entities under common control. HSM owns and operates boats (i.e., towing vessels), barges and third party chartered equipment for the transportation of crude oil, feedstocks, refined products and other hydrocarbon-based products to and from refineries and terminals owned by MPC.

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, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015 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, 2015, 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 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.

As described in Management’s Report on Internal Control over Financial Reporting, management has excluded MarkWest (as defined in Note 1) from the Company’s assessment of internal control over financial reporting as of December 31, 2015 as it was acquired by the Company in a business combination on December 4, 2015. We have also excluded MarkWest from our audit of internal control over financial reporting. MarkWest represents approximately 72% of consolidated total assets as of December 31, 2015 and 18% of consolidated total revenues and other income for the year ended December 31, 2015.

/s/PricewaterhouseCoopers LLP

Toledo, Ohio

February 26, 2016, except for the effect of the changes discussed in Note 4 to the consolidated financial statements, as to which the date is May 2, 2016

MPLX LP

Combined Consolidated Statements of Income



(In millions, except per unit data)	2015		2014		2013
Revenues and other income:
Service revenue	$	130	$	70	$	79
Service revenue - related parties	593		662		586
Rental income	20		—		—
Rental income - related parties	101		15		15
Product sales	36		—		—
Product sales - related parties	1		—		—
Other income	9		6		5
Other income - related parties	71		40		28
Total revenues and other income	961		793		713
Costs and expenses:
Cost of revenues (excludes items below)	225		228		200
Purchased product costs	20		—		—
Rental cost of sales	5		1		1
Purchases - related parties	166		153		151
Depreciation and amortization	116		75		70
General and administrative expenses	118		81		69
Other taxes	13		10		9
Total costs and expenses	663		548		500
Income from operations	298		245		213
Interest expense (net of amounts capitalized of $5 million, $1 million and $1 million, respectively)	35		4		—
Other financial costs	13		1		1
Income before income taxes	250		240		212
Provision for income taxes	1		1		1
Net income	249		239		211
Less: Net income attributable to noncontrolling interests	1		57		68
Net income attributable to Predecessor	92		61		65
Net income attributable to MPLX LP	156		121		78
Less: General partner’s interest in net income attributable to MPLX LP	57		6		2
Limited partners’ interest in net income attributable to MPLX LP	$	99	$	115	$	76

Per Unit Data (See Note 7)
Net income attributable to MPLX LP per limited partner unit:
Common - basic	$	1.23	$	1.55	$	1.05
Common - diluted	1.22		1.55		1.05
Subordinated - basic and diluted	0.11		1.50		1.01
Weighted average limited partner units outstanding:
Common - basic	79		37		37
Common - diluted	80		37		37
Subordinated - basic and diluted	18		37		37
Cash distributions declared per limited partner common unit	$	1.8200	$	1.4100	$	1.1675

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

MPLX LP

Combined Consolidated Balance Sheets



	December 31,
(In millions)	2015		2014
Assets
Current assets:
Cash and cash equivalents	$	43	$	27
Receivables, net	245		10
Receivables - related parties	187		41
Inventories	51		15
Other current assets	50		7
Total current assets	576		100
Equity method investments	2,458		—
Property, plant and equipment, net	9,997		1,324
Intangibles, net	466		—
Goodwill	2,570		116
Long-term receivables - related parties	25		—
Other noncurrent assets	12		4
Total assets	$	16,104	$	1,544
Liabilities
Current liabilities:
Accounts payable	$	91	$	17
Accrued liabilities	187		14
Payables - related parties	54		20
Deferred revenue - related parties	32		31
Accrued property, plant and equipment	168		17
Accrued taxes	27		6
Accrued interest payable	54		1
Other current liabilities	12		2
Total current liabilities	625		108
Long-term deferred revenue	4		—
Long-term deferred revenue - related parties	9		4
Long-term debt	5,255		644
Deferred income taxes	378		2
Deferred credits and other liabilities	166		2
Total liabilities	6,437		760
Commitments and contingencies (see Note 22)
Equity
Common unitholders - public (240 million and 23 million units issued and outstanding)	7,691		639
Class B unitholders (8 million and 0 units issued and outstanding)	266		—
Common unitholder - MPC (57 million and 20 million units issued and outstanding)	465		261
Subordinated unitholder - MPC (0 and 37 million units issued and outstanding)	—		217
General partner - MPC (7 million and 2 million units issued and outstanding)	819		(660		)
Equity of Predecessor	413		321
Total MPLX LP partners’ capital	9,654		778
Noncontrolling interest	13		6
Total equity	9,667		784
Total liabilities and equity	$	16,104	$	1,544

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

MPLX LP

Combined Consolidated Statements of Cash Flows



(In millions)	2015			2014			2013
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	249		$	239		$	211
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	116			75			70
Deferred income taxes	1			—			—
Asset retirement expenditures	(1		)	(2		)	(8		)
Net loss on disposal of assets	—			—			—
Equity in earnings from unconsolidated affiliates	(3		)	—			—
Distributions from unconsolidated affiliates	15			—			—
Changes in:
Current receivables	(29		)	2			6
Materials and supplies inventories	1			1			1
Change in fair value of derivatives	(6		)	—			—
Current accounts payable and accrued liabilities	2			1			(3		)
Receivables from / liabilities to related parties	(22		)	15			19
All other, net	17			3			1
Net cash provided by operating activities	340			334			297
Investing activities:
Additions to property, plant and equipment	(288		)	(141		)	(151		)
Acquisitions, net of cash acquired	(1,218		)	—			—
Investments - loans (from) to related parties	(77		)	—			—
Investments in unconsolidated affiliates	(14		)	—			—
All other, net	(2		)	4			(7		)
Net cash used in investing activities	(1,599		)	(137		)	(158		)
Financing activities:
Long-term debt - borrowings	1,490			1,160			—
- repayments	(1,441		)	(526		)	(1		)
Related party debt - borrowings	301			—			—
- repayments	(293		)	—			—
Debt issuance costs	(11		)	(3		)	—
Net proceeds from equity offerings	1			230			—
Issuance of units in MarkWest Merger	169			—			—
Contributions from MPC - MarkWest Merger	1,230			—			—
Distributions to unitholders and general partner	(158		)	(103		)	(78		)
Distributions to noncontrolling interests	(1		)	(47		)	(82		)
Distributions related to purchase of additional interest in Pipe Line Holdings	(12		)	(910		)	(100		)
Distributions to MPC from Predecessor	—			(25		)	(41		)
Net cash provided by (used in) financing activities	1,275			(224		)	(302		)
Net increase (decrease) in cash and cash equivalents	16			(27		)	(163		)
Cash and cash equivalents at beginning of period	27			54			217
Cash and cash equivalents at end of period	$	43		$	27		$	54

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

MPLX LP

Combined 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, 2012	$	411		—		$	57		$	209		$	14		$	536		$	261		$	1,488
Purchase of additional interest in Pipe Line Holdings	—			—		—			—			(46		)	(54		)	—			(100		)
Net income	20			—		18			38			2			68			65			211
Distributions to MPC from Predecessor	—			—		—			—			—			—			(41		)	(41		)
Quarterly distributions to unitholders and general partner	(20		)	—		(18		)	(38		)	(2		)	—			—			(78		)
Quarterly distributions to noncontrolling interest retained by MPC	—			—		—			—			—			(82		)	—			(82		)
Equity-based compensation	1			—		—			—			—			—			—			1
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		)
Quarterly distributions to unitholders and general partner	(26		)	—		(23		)	(50		)	(4		)	—			—			(103		)
Quarterly 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			92			249
Distributions to MPC from Predecessor	—			—		—			—			—			—			—			—
Quarterly distributions to unitholders and general partner	(40		)	—		(52		)	(45		)	(21		)	—			—			(158		)
Quarterly distributions to noncontrolling interest	—			—		—			—			—			(1		)	—			(1		)
Subordinated unit conversion	—			—		220			(220		)	—			—			—			—
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		$	413		$	9,667

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

Notes to Combined 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 gathering, transportation and storage 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. This acquisition is discussed further in Note 4. Unless the context otherwise requires, references in this report to “MPLX LP,” the “Partnership,” 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”) and MPLX Pipe Line Holdings LLC (“Pipe Line Holdings”). Pipe Line Holdings owns Marathon Pipe Line LLC (“MPL”) and Ohio River Pipe Line LLC (“ORPL”). References to “MPC” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other than the Partnership. References to “Predecessor” refer collectively to Xxxxxx Street Marine LLC (“HSM”)’s related assets, liabilities and results of the operations.

The Partnership’s business consists of two segments: Logistics and Storage (“L&S”) and Gathering and Processing (“G&P”). See Note 9 for additional information regarding operations.

Basis of Presentation – The Partnership’s consolidated financial statements include all majority-owned and controlled subsidiaries. For non-wholly-owned consolidated subsidiaries, the interests owned by third parties, including MPC, have been recorded as Noncontrolling interest in the accompanying Consolidated Balance Sheets. Intercompany investments, accounts and transactions have been eliminated. The Partnership’s investments in which the Partnership exercises significant influence but does not control and does not have a controlling financial interest, are accounted for using the equity method. The Partnership’s investments in a VIE in which the Partnership exercises significant influence but does not control and is not the primary beneficiary are accounted for using the equity method. The accompanying consolidated financial statements of the Partnership have been prepared in accordance with GAAP. Reclassifications have been made in connection with the MarkWest Merger and HSM acquisition to conform to current classifications.

2. Summary of Principal Accounting Policies

Use of Estimates – The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates affect, among other items, 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. It is upon completion of services provided that the Partnership meets all four criteria and it is at such time that the Partnership recognizes Service revenue.

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. 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 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.

HSM is a provider of marine transportation services for its customers and does not assume ownership of the products it transports. The Partnership transports cargo from a designated origin to a designated destination at a pre-established fixed rate. Costs incurred as part of moving the products and their subsequent reimbursements are recorded on a gross basis.

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 and Service revenue 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.

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:

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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.

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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 and recognized on a gross basis as the Partnership is the principal in the transaction.

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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.

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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.

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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. Similarly, the Partnership is considered to be the lessor under implicit operating lease arrangements with MPC in accordance with GAAP. The Partnership’s primary implicit lease operations with MPC relate to the transportation agreement between HSM and MPC. The rental expense related to the HSM implicit lease is depreciation of the HSM assets. These revenues and costs from implicit leases are recorded as Rental income, Rental income-related parties and Rental cost of sales, respectively, on the Consolidated Statements of Income. 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, 2015 and 2014, the amount of restricted cash included in Other current assets in the Consolidated Balance Sheets was $9 million and $4 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. 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 business unit level for our G&P segment and the pipeline system level for our L&S segment, and are largely independent from other asset groups. A long-lived asset group is considered impaired when the estimated undiscounted cash flows from such asset group are less than the asset group’s carrying value. In that event, a loss is recognized to the extent that the carrying value exceeds the fair value of the long-lived asset group. Fair value is determined primarily using estimated discounted cash flows. Management considers the volume of producer customers’ reserves behind the asset 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 natural gas 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.

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 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. There were no impairments as a result of the Partnership’s 2015 and 2014 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 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. 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 in 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 in 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. 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, 2015, 2014 and 2013, the Partnership did not designate any xxxxxx or designate any contracts as normal purchases and normal sales (except for electricity contracts, for which the normal purchases and normal sales designation has been elected during the year ended December 31, 2015).

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 14). Derivative instruments are recorded at fair value, based on available market information (see Note 15).

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 14 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 14.

Employee Benefit Plans – Neither we nor our subsidiaries have any employees as of January 1, 2016. The Partnership entered into an employee services agreement, effective December 28, 2015, with a subsidiary of MPC for the services provided by the employees from the MarkWest Merger. The Partnership also has two other employee services agreements with MPC.

Equity-Based Compensation Arrangements – The Partnership issues phantom units under its share-based compensation plan as described further in Note 19. 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. 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 is, however, a taxable entity under certain state jurisdictions. MarkWest Hydrocarbon is a tax paying entity for both federal and state purposes.

In addition to paying tax on its own earnings, MarkWest Hydrocarbon recognizes 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 is eliminated in consolidation. The Class A units represent limited partner interests with the same rights as common units except that the Class A units do not have voting rights, except as required by law. Class A units are not treated as outstanding common units in the Consolidated Balance Sheets as they are eliminated in the consolidation of MarkWest Hydrocarbon. The deferred income tax component relates to the change in the temporary book to tax basis difference in the carrying amount of the investment in the Partnership which results primarily from its 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 and MarkWest Hydrocarbon account 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.

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 participating security. The classes of participating securities include common units, subordinated units, general partner 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 unitholders in accordance with their respective ownership percentages. However, when distributions related to the incentive distribution rights are made, earnings equal to the amount of those distributions are first allocated to the general partner before the remaining earnings are allocated to the unitholders based on their respective ownership percentages.

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 and Class B units is based on actual distributions to the equity-based compensation awards and Class B unitholders. Diluted earnings per unit is calculated by dividing net income attributable to the Partnership’s unitholders, after deducting amounts allocable to the outstanding equity-based compensation awards and Class B units, by the weighted average number of 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 and Class B units, 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 November 2015, the FASB issued an accounting standards update to simplify the balance sheet classification of deferred taxes. The update requires that deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. The update does not change the existing requirement that only permits offsetting within a jurisdiction. The change is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2016. The guidance may be applied either prospectively or retrospectively with early adoption permitted. Our adoption of this standard in the fourth quarter of 2015 did not have a material impact on the consolidated results of operations, financial position or cash flows. We have elected to apply this standard prospectively, therefore, prior periods have not been retrospectively adjusted.

In April 2015, the FASB issued an accounting standards update to simplify the presentation of debt issuance costs. The update requires that debt issue costs for term debt are to be presented on the balance sheet as a direct reduction of the term debt liability as opposed to a deferred charge within other noncurrent assets. The change is effective for fiscal years and interim

periods within those fiscal years beginning after December 15, 2015. Retrospective application is required and early adoption is permitted. The Partnership’s early adoption of this standard in the second quarter of 2015 did not have a material impact on the consolidated results of operations, financial position or cash flows. In August 2015, the FASB subsequently issued a clarification as to the handling of debt issuance costs related to line-of-credit arrangements that allows for the presentation of these costs as an asset which would be amortized over the term of the line-of-credit arrangements. This clarification did not have any impact on the consolidated results of operations, financial position or cash flows.

In April 2014, the FASB issued an accounting standards update that redefines the criteria for determining discontinued operations and introduces new disclosures related to these disposals. The updated definition of a discontinued operation is the disposal of a component (or components) of an entity or the classification of a component (or components) of an entity as held for sale that represents a strategic shift for an entity and has (or will have) a major impact on an entity’s operations and financial results. The standard requires disclosure of additional financial information for discontinued operations and individually material components not qualifying for discontinued operation presentation, as well as information regarding an entity’s continuing involvement with the discontinued operation. The accounting standards update was effective prospectively for annual periods beginning on or after December 15, 2014, and interim periods within those years. Adoption of this standards update in the first quarter of 2015 did not impact the consolidated results of operations, financial position or cash flows.

Not Yet Adopted

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

In September 2015, the FASB issued an accounting standards update that eliminates the requirement to restate prior period financial statements for measurement period adjustments for business combinations. This update requires that the cumulative impact of a measurement period adjustment be recognized in the reporting period in which the adjustment is identified. The standard is effective for interim and annual periods beginning after December 15, 2015 with early application permitted. Adoption of this standard is not expected to have a material impact on the consolidated results of operations, financial position or cash flows.

In April 2015, the FASB issued an accounting standards 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 is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2015. Retrospective application is required and early adoption is permitted. Adoption of this standard is not expected to have a material impact on the consolidated results of operations, financial position or cash flows.

In April 2015, the FASB issued an accounting standards 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 is effective for fiscal years and interim periods within those fiscal years beginning after December 15, 2015. Retrospective or prospective application is allowed and early adoption is permitted. Adoption of this standard is not expected to have a material impact on the consolidated results of operations, financial position or cash flows.

In February 2015, the FASB issued an accounting standards update making targeted changes to the current consolidation guidance. The new standard changes the considerations related to substantive rights, related parties, and decision making fees when applying the variable interest entity consolidation model and eliminates certain guidance for limited partnerships and similar entities under the voting interest consolidation model. The update is effective for fiscal years and interim periods within

those fiscal years beginning after December 15, 2015. Early adoption is permitted. Adoption of this standard is not expected to have a material impact on the consolidated results of operations, financial position or cash flows.

In August 2014, the FASB issued an accounting standards 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 will be required to assess if there is substantial doubt about an entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. Disclosures will be required if conditions give rise to substantial doubt and the type of disclosure will be determined based on whether management’s plans will be able to alleviate the substantial doubt. This accounting standards update will be effective for the first annual period ending after December 15, 2016, and for annual periods and interim periods thereafter with early application permitted. We do not expect application of this standard to have an impact on our financial reporting.

In May 2014, the FASB issued an initial accounting standards update for revenue recognition, which has had subsequent updates. The new standard is aligned with the International Accounting Standards Board’s revenue recognition standard. The guidance in the 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 accounting standards update will be effective on a retrospective or modified retrospective basis for annual reporting periods beginning after December 15, 2017, and interim periods within those years, with early adoption permitted no earlier than January 1, 2017. The Partnership is in the process of determining the impact of the new standard on the consolidated financial statements.

4. Acquisitions

Acquisition of Xxxxxx Street Marine LLC

The Partnership retrospectively adjusted the financial results for all periods to include HSM as required for transactions amongst entities under common control. The following table presents the Partnership’s previously reported Consolidated Statement of Income for the years ended December 31, 2015, 2014 and 2013 retrospectively adjusted for the acquisition of HSM:



	2015
(In millions, except per unit data)	MPLX LP (Previously Reported)		HSM		MPLX LP (Currently Reported)
Revenues and other income:
Service revenue	$	130	$	—	$	130
Service revenue - related parties	465		128		593
Rental income	20		—		20
Rental income - related parties	16		85		101
Product sales	36		—		36
Product sales - related parties	1		—		1
Other income	8		1		9
Other income - related parties	27		44		71
Total revenues and other income	703		258		961
Costs and expenses:
Cost of revenues (excludes items below)	167		58		225
Purchased product costs	20		—		20
Rental cost of sales	5		—		5
Purchases - related parties	102		64		166
Depreciation and amortization	89		27		116
General and administrative expenses	104		14		118
Other taxes	10		3		13
Total costs and expenses	497		166		663
Income from operations	206		92		298
Interest expense (net of amounts capitalized of $5 million)	35		—		35
Other financial costs	13		—		13
Income before income taxes	158		92		250
Provision for income taxes	1		—		1
Net income	157		92		249
Less: Net income attributable to noncontrolling interests	1		—		1
Net income attributable to Predecessor	—		92		92
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



	2014
(In millions, except per unit data)	MPLX LP (Previously Reported)		HSM		MPLX LP (Currently Reported)
Revenues and other income:
Service revenue	$	69	$	1	$	70
Service revenue - related parties	436		226		662
Rental income - related parties	15		—		15
Other income	5		1		6
Other income - related parties	23		17		40
Total revenues and other income	548		245		793
Costs and expenses:
Cost of revenues (excludes items below)	144		84		228
Rental cost of sales	1		—		1
Purchases - related parties	98		55		153
Depreciation and amortization	50		25		75
General and administrative expenses	65		16		81
Other taxes	7		3		10
Total costs and expenses	365		183		548
Income from operations	183		62		245
Interest expense (net of amounts capitalized of $1 million)	4		—		4
Other financial costs	1		—		1
Income before income taxes	178		62		240
Provision for income taxes	—		1		1
Net income	178		61		239
Less: Net income attributable to noncontrolling interests	57		—		57
Net income attributable to Predecessor	—		61		61
Net income attributable to MPLX LP	121		—		121
Less: General partner’s interest in net income attributable to MPLX LP	6		—		6
Limited partners’ interest in net income attributable to MPLX LP	$	115	$	—	$	115



	2013
(In millions, except per unit data)	MPLX LP (Previously Reported)		HSM		MPLX LP (Currently Reported)
Revenues and other income:
Service revenue	$	79	$	—	$	79
Service revenue - related parties	369		217		586
Rental income - related parties	15		—		15
Other income	4		1		5
Other income - related parties	19		9		28
Total revenues and other income	486		227		713
Costs and expenses:
Cost of revenues (excludes items below)	135		65		200
Rental cost of sales	1		—		1
Purchases - related parties	95		56		151
Depreciation and amortization	49		21		70
General and administrative expenses	53		16		69
Other taxes	6		3		9
Total costs and expenses	339		161		500
Income from operations	147		66		213
Other financial costs	1		—		1
Income before income taxes	146		66		212
Provision for income taxes	—		1		1
Net income	146		65		211
Less: Net income attributable to noncontrolling interests	68		—		68
Net income attributable to Predecessor	—		65		65
Net income attributable to MPLX LP	78		—		78
Less: General partner’s interest in net income attributable to MPLX LP	2		—		2
Limited partners’ interest in net income attributable to MPLX LP	$	76	$	—	$	76

The following table presents the Partnership’s previously reported Consolidated Balance Sheet as of December 31, 2015 and 2014 retrospectively adjusted for the acquisition of HSM:



	December 31, 2015
(In millions)	MPLX LP (Previously Reported)		HSM		MPLX LP (Currently Reported)
Assets
Current assets:
Cash and cash equivalents	$	43	$	—	$	43
Receivables, net	244		1		245
Receivables - related parties	88		99		187
Inventories	49		2		51
Other current assets	50		—		50
Total current assets	474		102		576
Equity method investments	2,458		—		2,458
Property, plant and equipment, net	9,683		314		9,997
Intangibles, net	466		—		466
Goodwill	2,559		11		2,570
Long-term receivables - related parties	25		—		25
Other noncurrent assets	12		—		12
Total assets	$	15,677	$	427	$	16,104
Liabilities
Current liabilities:
Accounts payable	$	89	$	2	$	91
Accrued liabilities	186		1		187
Payables - related parties	47		7		54
Deferred revenue - related parties	32		—		32
Accrued property, plant and equipment	166		2		168
Accrued taxes	26		1		27
Accrued interest payable	54		—		54
Other current liabilities	12		—		12
Total current liabilities	612		13		625
Long-term deferred revenue	4		—		4
Long-term deferred revenue - related parties	9		—		9
Long-term debt	5,255		—		5,255
Deferred income taxes	377		1		378
Deferred credits and other liabilities	166		—		166
Total liabilities	6,423		14		6,437
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		413
Total MPLX LP partners’ capital	9,241		413		9,654
Noncontrolling interest	13		—		13
Total equity	9,254		413		9,667
Total liabilities and equity	$	15,677	$	427	$	16,104



	December 31, 2014
(In millions)	MPLX LP (Previously Reported)			HSM		MPLX LP (Currently Reported)
Assets
Current assets:
Cash and cash equivalents	$	27		$	—	$	27
Receivables, net	10			—		10
Receivables - related parties	41			—		41
Inventories	12			3		15
Other current assets	7			—		7
Total current assets	97			3		100
Property, plant and equipment, net	1,008			316		1,324
Goodwill	105			11		116
Other noncurrent assets	4			—		4
Total assets	$	1,214		$	330	$	1,544
Liabilities
Current liabilities:
Accounts payable	$	14		$	3	$	17
Accrued liabilities	11			3		14
Payables - related parties	20			—		20
Deferred revenue - related parties	31			—		31
Accrued property, plant and equipment	17			—		17
Accrued taxes	5			1		6
Accrued interest payable	1			—		1
Other current liabilities	2			—		2
Total current liabilities	101			7		108
Long-term deferred revenue - related parties	4			—		4
Long-term debt	644			—		644
Deferred income taxes	—			2		2
Deferred credits and other liabilities	2			—		2
Total liabilities	751			9		760
Equity
Common unitholders - public	639			—		639
Common unitholder - MPC	261			—		261
Subordinated unitholder - MPC	217			—		217
General partner - MPC	(660		)	—		(660		)
Equity of Predecessor	—			321		321
Total MPLX LP partners’ capital	457			321		778
Noncontrolling interest	6			—		6
Total equity	463			321		784
Total liabilities and equity	$	1,214		$	330	$	1,544

The following table presents the Partnership’s previously reported Consolidated Statement of Cash Flows for the years ended December 31, 2015, 2014 and 2013 retrospectively adjusted for the acquisition of HSM.



	2015
(In millions)	MPLX LP (Previously Reported)			HSM			MPLX LP (Currently Reported)
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	157		$	92		$	249
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	89			27			116
Deferred income taxes	2			(1		)	1
Asset retirement expenditures	(1		)	—			(1		)
Net loss on disposal of assets	1			(1		)	—
Equity in earnings from unconsolidated affiliates	(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	4			(2		)	2
Receivables from / liabilities to related parties	(8		)	(14		)	(22		)
All other, net	17			—			17
Net cash provided by operating activities	239			101			340
Investing activities:
Additions to property, plant and equipment	(264		)	(24		)	(288		)
Acquisitions, net of cash acquired	(1,218		)	—			(1,218		)
Investments - loans from related parties	—			(77		)	(77		)
Investments in unconsolidated affiliates	(14		)	—			(14		)
All other, net	(2		)	—			(2		)
Net cash used in investing activities	(1,498		)	(101		)	(1,599		)
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		)
Distributions related to purchase of additional interest in Pipe Line Holdings	(12		)	—			(12		)
Net cash provided by (used in) financing activities	1,275			—			1,275
Net increase (decrease) 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



	2014
(In millions)	MPLX LP (Previously Reported)			HSM			MPLX LP (Currently Reported)
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	178		$	61		$	239
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	50			25			75
Asset retirement expenditures	(2		)	—			(2		)
Changes in:
Current receivables	2			—			2
Inventories	1			—			1
Current accounts payable and accrued liabilities	1			—			1
Receivables from / liabilities to related parties	15			—			15
All other, net	2			1			3
Net cash provided by operating activities	247			87			334
Investing activities:
Additions to property, plant and equipment	(79		)	(62		)	(141		)
All other, net	4			—			4
Net cash used in investing activities	(75		)	(62		)	(137		)
Financing activities:
Long-term debt - borrowings	1,160			—			1,160
- repayments	(526		)	—			(526		)
Debt issuance costs	(3		)	—			(3		)
Net proceeds from equity offerings	230			—			230
Distributions to unitholders and general partner	(103		)	—			(103		)
Distributions to noncontrolling interests	(47		)	—			(47		)
Distributions related to purchase of additional interest in Pipe Line Holdings	(910		)	—			(910		)
Distributions to MPC	—			(25		)	(25		)
Net cash provided by (used in) financing activities	(199		)	(25		)	(224		)
Net increase (decrease) in cash and cash equivalents	(27		)	—			(27		)
Cash and cash equivalents at beginning of period	54			—			54
Cash and cash equivalents at end of period	$	27		$	—		$	27



	2013
(In millions)	MPLX LP (Previously Reported)			HSM			MPLX LP (Currently Reported)
Increase (decrease) in cash and cash equivalents
Operating activities:
Net income	$	146		$	65		$	211
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	49			21			70
Asset retirement expenditures	(8		)	—			(8		)
Changes in:
Current receivables	5			1			6
Inventories	1			—			1
Current accounts payable and accrued liabilities	(3		)	—			(3		)
Receivables from / liabilities to related parties	19			—			19
All other, net	3			(2		)	1
Net cash provided by operating activities	212			85			297
Investing activities:
Additions to property, plant and equipment	(107		)	(44		)	(151		)
All other, net	(7		)	—			(7		)
Net cash used in investing activities	(114		)	(44		)	(158		)
Financing activities:
Long-term debt - repayments	(1		)	—			(1		)
Distributions to unitholders and general partner	(78		)	—			(78		)
Distributions to noncontrolling interests	(82		)	—			(82		)
Distributions related to purchase of additional interest in Pipe Line Holdings	(100		)	—			(100		)
Distributions to MPC	—			(41		)	(41		)
Net cash provided by (used in) financing activities	(261		)	(41		)	(302		)
Net increase (decrease) in cash and cash equivalents	(163		)	—			(163		)
Cash and cash equivalents at beginning of period	217			—			217
Cash and cash equivalents at end of period	$	54		$	—		$	54

Purchase of MarkWest Energy Partners, L.P.

On December 4, 2015, a wholly-owned subsidiary of the Partnership merged with MarkWest Energy Partners, L.P. 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 of MPLX representing limited partner interests in MPLX, plus a one-time cash payment of $6.20 per unit. 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 will be paid in equal amounts in July 2016 and 2017 in connection with the conversion of the Class B units to common units. The Partnership’s financial results and operating statistics reflect the results of MarkWest from the date of the acquisition forward.

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



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

The following table summarizes the preliminary purchase price allocation. Due to the proximity of the MarkWest Merger to

December 31, 2015, the Partnership is still completing its analysis of the final purchase price allocation for property, plant and equipment, intangibles and deferred taxes. The estimated fair value of assets acquired and liabilities and noncontrolling interests assumed at the acquisition date are as follows:



(In millions)
Cash and cash equivalents	$	12
Receivables	164
Inventories	33
Other current assets	44
Equity method investments	2,457
Property, plant and equipment	8,474
Intangibles	468
Other noncurrent assets	5
Total assets acquired	11,657
Accounts payable	322
Accrued liabilities	13
Accrued taxes	21
Other current liabilities	44
Long-term debt	4,567
Deferred income taxes	374
Deferred credits and other liabilities	151
Noncontrolling interest	13
Total liabilities and noncontrolling interest assumed	5,505
Net assets acquired excluding goodwill	6,152
Goodwill	2,454
Net assets acquired	$	8,606

The purchase price allocation resulted in the recognition of $2.5 billion in goodwill by 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 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 14.

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 11.0 percent to 13.0 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. 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.



(In millions, except per unit data)	2015		2014
Revenues and other income	$	2,682	$	2,972
Net income attributable to MPLX LP	245		330
Net income attributable to MPLX LP per unit - basic	0.46		1.09
Net income attributable to MPLX LP per unit - diluted	0.44		1.03

The unaudited pro forma information includes adjustments primarily to align accounting policies, to adjust depreciation expense to reflect the fair value of property, plant and equipment, increase amortization expense related to identifiable intangible assets, adjust interest expense related to the fair value of MarkWest’s long-term debt and remove approximately $90 million of transaction related costs, as well as the related income tax effects.

MarkWest has a 60 percent legal ownership interest in MarkWest Utica EMG. MarkWest Utica EMG’s inability to fund its planned activities without subordinated financial support qualify it as a VIE. The financing structure for MarkWest Utica EMG at its inception resulted in a de-facto agent relationship under which MarkWest was deemed to be the primary beneficiary of MarkWest Utica EMG. Therefore, MarkWest consolidated MarkWest Utica EMG in its historical financial statements. In the fourth quarter of 2015, based on economic conditions and other pertinent factors, the accounting for its investment in MarkWest Utica EMG was re-assessed. As of December 4, 2015, the entity has been deconsolidated. For purposes of this pro forma financial information, MarkWest Utica EMG has been consolidated for the period prior to the acquisition consistent with its treatment in the historical periods presented.

A summary of the amounts included in the historical financial statements of MarkWest 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 income	(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 16. 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			2013
Net income attributable to MPLX LP	$	156		$	121		$	78
Transfer to noncontrolling interest:
Decrease in general partner-MPC equity for purchases of additional interest in Pipe Line Holdings	(6		)	(638		)	(46		)
Change from net income attributable to MPLX LP and transfer to noncontrolling interest	$	150		$	(517	)	$	32

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 LLC agreement has been amended from time to time (the LLC 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, 2015, EMG Utica has contributed $996 million and Utica Operating has contributed approximately $1.5 billion to MarkWest Utica EMG.

Under the Amended LLC Agreement, after EMG Utica has contributed more than $500 million to MarkWest Utica EMG and prior to December 31, 2016, EMG Utica’s investment balance will also be increased by a quarterly special non-cash allocation of income (“Preference Amount”) that is based upon the amount of capital contributed by EMG Utica in excess of $500 million. No Preference Amount will accrue to EMG Utica’s investment balance after December 31, 2016. EMG Utica received a special non-cash allocation of income of approximately $4 million for the 28 days ended December 31, 2015.

Under the Amended LLC Agreement, Utica Operating will continue to receive 60 percent of cash generated by MarkWest Utica EMG that is available for distribution until the earlier of December 31, 2016 and the date on which Utica Operating’s investment balance equals 60 percent of the aggregate investment balances of the Members. After the earlier of those dates, cash generated by MarkWest Utica EMG that is available for distribution will be allocated to the Members in proportion to their respective investment balances. As of December 31, 2015, 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, 2015, 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 28 days ended December 31, 2015. The Partnership receives engineering and construction and administrative management fee revenue and other direct personnel costs (“Operational Service” revenue) for operating MarkWest Utica EMG. The amount of Operational Service revenue related to MarkWest Utica EMG for the 28 days ended December 31, 2015 was less than $1 million 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 (“Summit”). As this entity 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 28 days ended December 31, 2015 was approximately $2 million and is reported as Other income-related parties in the Consolidated Statements of Income.

Ohio Condensate

In December 2013, MarkWest formed Utica Condensate for the purpose of engaging in wellhead condensate gathering, stabilization, terminalling, storage and marketing in the state of Ohio. As of December 31, 2015 the Partnership owned 100 percent of Utica Condensate. Utica Condensate’s business is conducted solely through its subsidiary, Ohio Condensate Company L.L.C. (“Ohio Condensate”), which is a joint venture between Utica Condensate and Summit. As of December 31, 2015, Xxxxx Xxxxxxxxxx owned 60 percent of Ohio Condensate. The Partnership accounts for Ohio Condensate, which is a VIE, as an equity method investment as MPLX exercises significant influence, but does not control Ohio Condensate and is not its primary beneficiary due to Summit’s voting rights on significant matters. The Partnership’s portion of Ohio Condensate’s net assets are reported under the caption Equity method investments on the Consolidated Balance Sheets. The Partnership receives Operational Service revenue for operating Ohio Condensate. The amount of Operational Service revenue related to Ohio Condensate for the 28 days ended December 31, 2015 was less than $1 million and is reported as Other income-related parties in the Consolidated Statements of Income.

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



(In millions)	MarkWest Utica EMG ⁽¹⁾	Other VIEs	Non-VIEs	Total
Income statement data:
Revenue	18	2	9	29
Income from operations	9	—	1	10
Net income	10	—	1	11
Balance sheet data:
Current assets	113	7	30	150
Noncurrent assets	2,207	169	243	2,619
Current liabilities	77	7	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 $781 million as of December 31, 2015.

As of December 31, 2015, the carrying value of our equity method investments was $961 million 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 $371 million of excess related to goodwill.

6. Related Party Agreements and Transactions

The Partnership’s material related parties included:


•	MPC, which refines, markets and transports crude oil and petroleum products, primarily in the Midwest, Gulf 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 has a 60 percent interest. MarkWest Utica EMG is engaged in significant natural gas processing and NGL fractionation, transportation and marketing in eastern Ohio.


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


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


•	Ohio Condensate, in which MPLX 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 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.

These 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 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;


•	a 10-year storage services agreement under which MPC pays the Partnership fees for providing storage services at our Xxxx, West Xxxxxxxx butane cavern; and


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

All of the transportation services agreements with MPC for the Partnership’s crude oil and product pipeline systems (other than the Wood River, Illinois to Patoka, Illinois crude system) automatically renew for up to two additional five-year terms unless terminated by either party. The transportation services agreements with MPC for the Wood River to Patoka crude system and the barge dock automatically renew for up to four additional two-year terms 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 the 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. If the minimum capacity of the pipeline falls below the level of MPC’s commitment at any time or if capacity on the pipeline is required to be allocated among shippers because volume nominations exceed available capacity, depending on the cause of the reduction in capacity, MPC’s commitment may be reduced or MPC will receive a credit for its minimum volume commitment for that period. In addition to MPC’s minimum volume commitment, MPC is also responsible for any loading, handling, transfer and other charges with respect to volumes we transport for MPC. If the Partnership agrees to make any capital expenditures at MPC’s request, MPC will reimburse it for, or we will have the right in certain circumstances, to file for an increased tariff rate to recover the actual cost of such capital expenditures. The transportation services agreements include provisions that permit MPC to suspend, reduce or terminate its obligations under the applicable agreement if certain events occur. These events include MPC deciding to permanently or indefinitely suspend refining operations at one or more of its refineries for at least twelve consecutive months and certain force majeure events that would prevent the Partnership or MPC from performing required services under the applicable agreement.

Effective June 11, 2015, MPL entered into a transportation services agreement with MPC pursuant to which MPL will charge fees to MPC, at applicable FERC tariff rates, for transporting products on the Cornerstone pipeline system and related Utica build-out projects. MPC will be obligated to transport certain minimum quarterly volumes of products on the associated pipeline systems. If MPC fails to transport its minimum volume during any quarter, then MPC will pay MPL a quarterly deficiency payment. 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, after which time any unused credits will expire. Upon the expiration or termination of this agreement, MPC will have the opportunity to apply any remaining credit amounts until the completion of the succeeding four quarter period, without regard to the minimum volume commitment under the agreement. This agreement has an initial term of 15 years after the project’s in-service date and automatically renews for up to two renewal terms of five years each unless either party provides the other party with written notice of its intent to terminate at least six months prior to the end of the primary term or any renewal term, as applicable.

Under the storage services agreements, the Partnership is obligated to make available to MPC on a firm basis the available storage capacity at our tank farms and butane cavern, and MPC pays the Partnership a per-barrel fee for such storage capacity, regardless of whether MPC fully utilizes the available capacity. The Partnership may adjust the per-barrel fee by a percentage equal to an increase in the PPI in early 2015.

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.

HSM entered into a guaranteed supply agreement with MPC on January 1, 2015 for the supply of fuel for use by HSM's towing vessels and barges. HSM must purchase 90 percent of the guaranteed volume by terminal each month or the volume can be reduced by MPC per the contract. 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.

On September 17, 2015, MPL entered into an amendment (the “First Amendment”) to its existing Patoka, Illinois tank farm Storage Services Agreement with MPC dated September 24, 2012 (the “Storage Services Agreement”). Under the Storage Services Agreement, MPC pays a monthly fee to store crude oil at MPL’s Patoka, Illinois tank farm. MPC’s fees under the Storage Services Agreement are for the use of the available shell capacity of MPL’s Patoka, Illinois tank farm, regardless of whether MPC fully utilizes all of its contractual capacity. The First Amendment provides for an increase in available shell capacity at the Patoka, Illinois tank farm from 1,386,000 barrels to 2,626,000 barrels due to the addition of four newly constructed tanks at the facility.

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.

On January 1, 2015, MPC and MPL amended the Amended and Restated Operating Agreement to reflect the transfer of certain assets from MPC to Xxxxxx Street Transportation LLC (“HST”), an indirect, wholly-owned subsidiary of MPC. This amended agreement, with an annual operating fee of $1 million, now covers only the assets not transferred to HST. Also on January 1, 2015, MPL entered into a new agreement with HST (the “HST Operating Agreement”) for operation of the transferred assets with an annual fee of $12 million. The HST Operating Agreement has an initial term of one year and automatically renews for additional one-year terms, unless either party provides the other party with written notice of its intent to terminate the agreement at least six months prior to the end of the initial term or any renewal term. In combination, the amended and new agreement did not change the fees received by MPL or the services provided under the agreements. Prior to January 1, 2015 this agreement did not exist.

Management Services Agreements

The Partnership has two management services agreements with MPC under which it provides certain management services to MPC with respect to certain of MPC’s retained pipeline assets. The Partnership received $1 million in fees under these agreements in 2015. 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.

HSM entered into a management services agreement with MPC on January 1, 2015 which expires on June 30, 2020. Under this agreement, HSM provides management services to assist MPC in the oversight and management of the MPC marine business. Pursuant to the amended and restated management services agreement, effective July 1, 2015, 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. The initial annual fee total is $13 million. Prior to January 1, 2015 this agreement did not exist.

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, as well as MPC’s indemnification of the Partnership for certain matters, including environmental, title and tax matters.

Employee Services Agreements

The Partnership has two employee services agreements with MPC under which it reimburses MPC for the provision of certain operational and management services to the Partnership in support of its pipelines, barge dock, butane cavern and tank farms within the L&S segment. Effective December 28, 2015, the Partnership entered into an additional employee services agreement under which it reimburses MPC for the same type of services in support of its midstream assets utilized in the natural gas and NGLs businesses within the G&P segment as well as certain other services in support of the Partnership.

On January 1, 2015, under an employee services agreement, HSM employees were transferred to Marathon Petroleum Logistics Services LLC ("MPLS"), a wholly owned subsidiary of MPC. Under the agreement HSM reimburses MPLS for

employee benefit expenses along with certain operational and management services provided in support of HSM’s areas of operation. The agreement is effective until December 31, 2019. Prior to January 1, 2015 this agreement did not exist.

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. 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-related parties on the Consolidated Balance Sheets. Borrowings were at an average interest rate of 1.744 percent, per annum. In connection with this loan agreement, the Partnership terminated the previous revolving credit agreement of $50 million with MPC, effective December 31, 2015.

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)	2015		2014		2013
Service revenue
MPC	$	593	$	662	$	586
Rental income
MPC	$	101	$	15	$	15
Product sales
MPC	$	1	$	—	$	—

The revenue received for operating pipelines for related parties included in Other income-related parties on the Consolidated Statements of Income were as follows:



(In millions)	2015		2014		2013
MPC	$	68	$	39	$	27
Centennial	1		1		1
Ohio Gathering	2		—		—
Total	$	71	$	40	$	28

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. Charges for services included in Purchases-related parties primarily relate to services that support the Partnership’s operations and maintenance activities, as well as compensation expenses. Charges for services included in General and administrative expenses primarily relate to services that support the Partnership’s executive management, accounting and human resources activities. These charges were as follows:



(In millions)	2015		2014		2013
Purchases - related parties	$	30	$	30	$	27
General and administrative expenses	46		46		46
Total	$	76	$	76	$	73

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)	2015		2014		2013
MPC	$	13	$	8	$	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-related parties. The costs of personnel involved in executive management, accounting and human resources activities are classified as General and administrative expenses.

Employee services expenses from related parties were as follows:



(In millions)	2015		2014		2013
Purchases - related parties	$	136	$	123	$	124
General and administrative expenses	22		24		16
Total	$	158	$	147	$	140

Receivables from related parties were as follows:



	December 31,
(In millions)	2015		2014
MPC	$	175	$	41
Centennial	1		—
Jefferson Dry Gas	2		—
MarkWest Utica EMG	4		—
Ohio Gathering	5		—
Total	$	187	$	41

Long-term receivables related to reimbursements from the MarkWest Merger to be provided by MPC for the conversion of Class B units were as follows:



	December 31,
(In millions)	2015		2014
MPC	$	25	$	—

Payables to related parties were as follows:



	December 31,
(In millions)	2015		2014
MPC	$	33	$	20
MarkWest Utica EMG	21		—
Total	$	54	$	20

Under the Partnership’s transportation services agreements, if MPC fails to transport its minimum throughput volumes during any quarter, then MPC will pay the Partnership a deficiency payment equal to the volume of the deficiency multiplied by the tariff rate then in effect. The deficiency amounts are recorded as deferred revenue-related parties. MPC may then apply the amount of any such deficiency payments as a credit for volumes transported on the applicable pipeline system in excess of its minimum volume commitment during the following four or eight quarters under the terms of the applicable transportation services agreement. The Partnership recognizes revenues for the deficiency payments at the earlier of 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 applicable four or eight quarter period. The use or expiration of the credits is a decrease in deferred revenue-related parties.

During 2015 and 2014, MPC did not transport its minimum committed volumes on certain pipeline systems. In addition, capital projects we are 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 associated with the minimum volume deficiencies and project reimbursements were as follows:



	December 31,
(In millions)	2015		2014
Minimum volume deficiencies - MPC	$	36	$	30
Project reimbursements - MPC	5		5
Total	$	41	$	35

Certain asset transfers between the Partnership and MPC, including additions to property, plant and equipment related to capitalized interest incurred by MPC on the Partnership’s behalf, and certain expenses, such as stock-based compensation, incurred by MPC on the Partnership’s behalf have been recorded as non-cash capital contributions or distributions. The non-cash contributions from MPC were less than $1 million in 2015, 2014 and 2013.

7. Net Income Per Limited Partner Unit

Net income 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, certain equity-based compensation awards and incentive distribution rights.

As mentioned previously, the HSM acquisition was a transfer between entities under common control. As an entity under common control with MPC, prior periods are 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 per unit calculation. The earnings for HSM will be included in the net income 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 per unit, the subordinated units were treated as if they converted to common units on July 1, 2015.

In 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 2014 and 2013 reporting periods 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 or 2013.



(In millions)	2015			2014		2013
Net income attributable to MPLX LP	$	156		$	121	$	78
Less: General partner’s distributions declared (including IDRs)⁽¹⁾	60			6		2
Limited partners’ distributions declared on common units⁽¹⁾	224			54		43
Limited partner’s distributions declared on subordinated units⁽¹⁾	31			52		43
Undistributed net (loss) income attributable to MPLX LP	$	(159	)	$	9	$	(10	)


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



	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	$	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	$	8	$	58	$	55	$	121
Weighted average units outstanding:
Basic	2		37		37		76
Diluted	2		37		37		76
Net income attributable to MPLX LP:
Basic			$	1.55	$	1.50
Diluted			$	1.55	$	1.50



	2013
(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	$	2	$	43		$	43		$	88
Undistributed net loss attributable to MPLX LP	—		(4		)	(6		)	(10		)
Net income attributable to MPLX LP	$	2	$	39		$	37		$	78
Weighted average units outstanding:
Basic	1		37			37			75
Diluted	1		37			37			75
Net income attributable to MPLX LP per limited partner unit:
Basic			$	1.05		$	1.01
Diluted			$	1.05		$	1.01

8. Equity

Units Outstanding - The Partnership had 296,687,176 common units outstanding as of December 31, 2015. Of that number, 56,932,134 were owned by MPC. The two percent general partner interest, represented by 6,800,475 general partner units, was owned by MPC. See below for discussion of units issued in connection with the MarkWest Merger.

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.

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. On July 1, 2016 and July 1, 2017 (unless earlier converted upon certain fundamental changes regarding MPLX LP), 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.

ATM Program - On May 18, 2015, the Partnership filed a prospectus supplement to its shelf registration statement filed with the SEC on March 27, 2015, authorizing the continuous issuance of up to an aggregate of $500 million 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. 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.

The table below summarizes the changes in the number of units outstanding through December 31, 2015:



(In units)	Common	Class B	Subordinated		General Partner	Total
Balance at December 31, 2012	36,951,515	—	36,951,515		1,508,225	75,411,255
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

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 common units and was calculated by dividing $200 million by the average closing price for MPLX 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 general partnership interest.

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 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 general partner 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.



				Marginal percentage interest in distributions
	Total quarterly distribution per unit target amount			Unitholders		General Partner
Minimum quarterly distribution	$	0.2625		98.0	%	2.0	%
First target distribution	above $0.2625		up to $0.301875	98.0	%	2.0	%
Second target distribution	above $0.301875		up to $0.328125	85.0	%	15.0	%
Third target distribution	above $0.328125		up to $0.393750	75.0	%	25.0	%
Thereafter	above $0.393750			50.0	%	50.0	%

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



(In millions)	2015		2014		2013
Net income attributable to MPLX LP	$	156	$	121	$	78
Less: General partner's incentive distribution rights and other	55		4		—
Net income attributable to MPLX LP available to general and limited partners	$	101	$	117	$	78

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

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, 2016, the Partnership declared a quarterly cash distribution, based on the results of the fourth quarter of 2015, totaling $189 million, or $0.50 per unit. This distribution was paid on February 12, 2016 to unitholders of record on February 4, 2016. See the table below for the IDR impact for 2015.

The allocation of total quarterly cash distributions to general and limited partners is as follows for the year ended December 31, 2015, 2014 and 2013. 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)	2015		2014		2013
General partner's distributions:
General partner's distributions	$	6	$	2	$	2
General partner's incentive distribution rights distributions	54		4		—
Total general partner's distributions	$	60	$	6	$	2
Limited partners' distributions:
Common unitholders	$	224	$	54	$	43
Subordinated unitholders	31		52		43
Total limited partners' distributions	255		106		86
Total cash distributions declared	$	315	$	112	$	88

9. Segment Information

The Partnership’s chief operating decision maker is the chief executive officer (“CEO”) of its general partner. The CEO reviews the Partnership’s discrete financial information, makes operating decisions, assesses financial performance and allocates resources on a type of service basis. The Partnership has two reportable segments: L&S and G&P. Each of these segments is organized and managed based upon the nature of the products and services it offers.


•	L&S - transports and stores crude oil, refined products and other hydrocarbon-based products.


•	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 financial information as if those investments were consolidated.

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

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



	2015
(In millions)	L&S		G&P		Total
Revenues and other income:
Segment revenues	$	760	$	150	$	910
Segment other income	75		—		75
Total segment revenues and other income	835		150		985
Costs and expenses:
Segment cost of revenues	379		62		441
Segment operating income before portion attributable to noncontrolling interest	456		88		544
Segment portion attributable to noncontrolling interest and Predecessor	134		12		146
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	401
Segment portion attributable to noncontrolling interest and Predecessor	188
Segment operating income attributable to MPLX LP	$	213



	2013
(In millions)	L&S
Revenues and other income:
Segment revenues	$	680
Segment other income	33
Total segment revenues and other income	713
Costs and expenses:
Segment cost of revenues	361
Segment operating income before portion attributable to noncontrolling interest	352
Segment portion attributable to noncontrolling interest and Predecessor	209
Segment operating income attributable to MPLX LP	$	143



(in millions)	2015			2014			2013
Reconciliation to Income from operations:
Segment operating income attributable to MPLX	$	398		$	213		$	143
Segment portion attributable to unconsolidated affiliates	(21		)	—			—
Segment portion attributable to noncontrolling interest and Predecessor	146			188			209
Income from equity method investments	3			—			—
Other income - related parties	2			—			—
Unrealized derivative gains	4			—			—
Depreciation and amortization	(116		)	(75		)	(70		)
General and administrative expenses	(118		)	(81		)	(69		)
Income from operations	$	298		$	245		$	213



(in millions)	2015			2014		2013
Reconciliation to Total revenues and other income:
Total segment revenues and other income	$	985		$	793	$	713
Revenue adjustment from unconsolidated affiliates	(28		)	—		—
Income from equity method investments	3			—		—
Other income - related parties	2			—		—
Unrealized derivative loss	(1		)	—		—
Total revenues and other income	$	961		$	793	$	713



(in millions)	2015			2014			2013
Reconciliation to Net income attributable to noncontrolling interests
Segment portion attributable to noncontrolling interest and Predecessor	$	146		$	188		$	209
Portion of noncontrolling interests and Predecessor related to items below segment income from operations	(48		)	(70		)	(76		)
Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates	(5		)	—			—
Net income attributable to noncontrolling interests and Predecessor	$	93		$	118		$	133

The following reconciles segment capital expenditures to total capital expenditures:



(In millions)	2015			2014		2013
L&S segment capital expenditures	$	212		$	141	$	151
G&P segment capital expenditures⁽¹⁾	100			—		—
Total segment capital expenditures	312			141		151
Less: Capital expenditures for Partnership operated, non-wholly owned subsidiaries	(24		)	—		—
Total capital expenditures	$	288		$	141	$	151


⁽¹⁾	The G&P segment includes $24 million of capital expenditures related to Partnership operated, non-wholly owned subsidiaries.

Total assets by reportable segment were:



	December 31,
(In millions)	2015		2014
L&S	$	1,858	$	1,544
G&P	14,246		—
Total assets	$	16,104	$	1,544

10. Major Customer and Concentration of Credit Risk

MPC accounted for 79 percent, 90 percent and 88 percent of the Partnership’s total revenues and other income for 2015, 2014 and 2013, excluding revenues attributable to volumes shipped by MPC under joint tariffs with third parties, which are treated as third-party revenue for accounting purposes. The Partnership provides crude oil and product pipeline transportation and storage services to MPC and operate pipelines on behalf of MPC.

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.

11. 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 provision results from partnership activity in certain state jurisdictions. MarkWest Hydrocarbon is a tax paying entity for both federal and state tax purposes.

The Partnership and MarkWest Hydrocarbon’s income tax expense was $1 million for the years ended December 31, 2015, 2014 and 2013, respectively. Our effective tax rate was less than one percent for 2015, 2014 and 2013.

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



(In millions)	2015
Deferred income tax expense (benefit):
Federal	$	3
State	(2		)
Total deferred	1
Provision for income tax	$	1

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



(In millions)	MarkWest Hydrocarbon			Partnership			Eliminations			Consolidated⁽¹⁾
Income before provision for income tax	$	9		$	240		$	1		$	250
Federal statutory rate	35		%	—		%	—		%
Federal income tax at statutory rate⁽²⁾	3			—			—			3
State income taxes net of federal benefit - MarkWest Hydrocarbon	—			(2		)	—			(2		)
Provision on income from Class A units⁽¹⁾	1			—			—			1
Other	(1		)	—			—			(1		)
Provision for income tax	$	3		$	(2	)	$	—		$	1


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


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

Deferred tax assets and liabilities consist of the following:



	December 31,
(In millions)	2015		2014
Deferred tax assets:
Derivatives	$	9	$	—
Net operating loss carryforwards	62		—
Total deferred tax assets	71		—
Deferred tax liabilities
Property, plant and equipment	7		2
Investments in subsidiaries and affiliates	442		—
Total deferred tax liabilities	449		2
Net deferred tax liabilities⁽¹⁾	$	378	$	2


⁽¹⁾	See Note 3 for discussion regarding a recently adopted accounting standard related to deferred tax assets and liabilities.

At December 31, 2015, MarkWest Hydrocarbon had tax-effected federal operating loss carryforwards of $56 million, which expire in 2033 through 2035 and tax-effected state operating loss carryforwards of $4 million, which expire in 2017 through 2035.

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, 2015, 2014 or 2013.

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 2015, and a net benefit of less than $1 million in 2014 and 2013. As of December 31, 2015 and 2014, less than $1 million of interest and penalties were accrued related to income taxes. In addition, the Partnership and MarkWest Hydrocarbon have federal and state tax years 2011 through 2014 open to examination.

12. Inventories

Inventories consist of the following:



	December 31,
(In millions)	2015		2014
NGLs	$	3	$	—
Line fill	5		—
Spare parts, materials and supplies	43		15
Total inventories	$	51	$	15

13. Property, Plant and Equipment

Property, plant and equipment consist of the following:



	Estimated Useful Lives	December 31,
(In millions)	Estimated Useful Lives	2015		2014
Natural gas gathering and NGL transportation pipelines and facilities	15 - 30 years	$	4,307	$	—
Processing, fractionation and storage facilities	24 - 37 years	3,185		166
Pipelines and related assets	19 - 42 years	1,128		1,081
Barges and towing vessels	20 years	475		455
Land, building, office equipment and other	5 - 25 years	606		75
Construction in progress		946		88
Total		10,647		1,865
Less accumulated depreciation		650		541
Property, plant and equipment, net		$	9,997	$	1,324

Property, plant and equipment includes gross assets acquired under capital leases of approximately $25 million at December 31, 2015 and 2014, with related amounts in accumulated depreciation of approximately $7 million at December 31, 2015 and 2014.

14. Fair Value Measurements

Fair Values – Recurring

Fair value measurements and disclosures relate primarily to the Partnership’s derivative positions as discussed in Note 15. As part of the MarkWest Merger, the MarkWest opening balance sheet was valued at fair value (see Note 4).

Money market funds 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. MPLX settled natural gas swaps during the year ended December 31, 2015; however, no such instruments were outstanding as of December 31, 2015. 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 as of December 31, 2015 classified by the valuation hierarchy.



(In millions)	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	2	$	—
Significant unobservable inputs (Level 3)
Commodity contracts	7		—
Embedded derivatives in commodity contracts	—		(32		)
Total carrying value in Consolidated Balance Sheets	$	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, 2015. The market approach is used for valuation of all instruments.



Level 3 Instrument	Balance Sheet Classification	Unobservable Inputs	Value Range	Time Period
Commodity contracts	Assets	Forward ethane prices (per gallon)	$0.16 - $0.19	Jan. 2016 - Dec. 2016
		Forward propane prices (per gallon)	$0.39 - $0.44	Jan. 2016 - Dec. 2016
		Forward isobutane prices (per gallon)	$0.54 - $0.57	Jan. 2016 - Mar. 2016
		Forward normal butane prices (per gallon)	$0.51 - $0.57	Jan. 2016 - Mar. 2016
		Forward natural gasoline prices (per gallon)	$0.89 - $0.93	Jan. 2016 - Dec. 2016

Embedded derivatives in commodity contracts	Liabilities	Forward propane prices (per gallon)⁽¹⁾	$0.39 - $0.49	Jan. 2016 - Dec. 2022
		Forward isobutane prices (per gallon)⁽¹⁾	$0.53 - $0.64	Jan. 2016 - Dec. 2022
		Forward normal butane prices (per gallon)⁽¹⁾	$0.48 - $0.60	Jan. 2016 - Dec. 2022
		Forward natural gasoline prices (per gallon)⁽¹⁾	$0.89 - $1.04	Jan. 2016 - Dec. 2022
		Forward natural gas prices (per MMBtu)⁽²⁾	$2.18 - $3.39	Jan. 2016 - Dec. 2022
		ERCOT Pricing (per MegaWatt Hour)	$23.08 - $44.58	Jan. 2016 - Dec. 2016
		Probability of renewal⁽³⁾	50.0%


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


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

⁽³⁾

The producer counterparty to the embedded derivative has the option to renew the gas purchase agreement and the related keep-whole processing agreement for two successive five-year terms after 2022. The embedded gas purchase agreement cannot be renewed without the renewal of the related keep-whole processing agreement. Due to the significant number of 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 derivative in commodity contracts - The Natural Gas Embedded Derivative liability is a single embedded derivative comprised of both the purchase of natural gas at prices impacted by the frac spread and the probability of contract renewal as discussed further in Note 15. Increases (decreases) in forward NGL prices result in an increase (decrease) in the fair value of the embedded derivative. An increase in the probability of renewal would result in an increase in the fair value of the related embedded derivative liability.

Level 3 Valuation Process

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

valuations from period to period. The valuations of the Level 3 commodity derivative contracts are performed by a third-party pricing service and reviewed and validated on a quarterly basis by the Risk Department by comparing the pricing and option volatilities to actual market data and/or data provided by at least one other independent third-party pricing service.

Management is responsible for the valuation of the Natural Gas Embedded Derivative discussed in Note 15. 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 and 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 2016 through December 2022) for management’s use in determining the fair value of the Natural Gas Embedded Derivative. In developing the pricing curves for these periods, the Risk Department maximizes its use of the latest known market data and trends as well as its understanding of the historical relationships between forward NGL and natural gas prices and the forward market data that is available for the required period, such as crude oil pricing and natural gas pricing from other markets. However, there is very limited actual market data available to validate the Risk Department’s estimated price curves. Management also assesses the probability of the producer customer’s renewal of the contracts, which includes consideration of:


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


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


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

Changes in Level 3 Fair Value Measurements

The tables below include a roll forward of the balance sheet amounts for the years ended December 31, 2015 (including the change in fair value) for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy.



	2015
(In millions)	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	—		$	—
Net positions assumed in conjunction with the MarkWest Merger	7			(38		)
Total gain (realized and unrealized) included in earnings⁽¹⁾	3			5
Settlements	(3		)	1
Fair value at end of period	$	7		$	(32	)
The amount of total gains for the period included in earnings attributable to the change in unrealized gains relating to assets still held at end of period	$	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 Costs of revenue 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) its 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 Credit Facility, if any, approximate 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 15).

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 fair values are considered Level 3 measurements and SMR liability fair values are considered Level 2 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,
	2015				2014
(In millions)	Fair Value		Carrying Value		Fair Value		Carrying Value
Long-term debt	$	5,212	$	5,255	$	636	$	635
SMR liability	$	99	$	100	$	—	$	—

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

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

To mitigate its cash flow exposure to fluctuations in the price of natural gas, the Partnership primarily utilizes derivative financial instruments relating to the future price of natural gas and takes into account the partial offset of its long and short gas positions resulting from normal operating activities. The Partnership has no such positions outstanding as of December 31, 2015.

As a result of its current derivative positions, the Partnership has mitigated a portion of its expected commodity price risk through the fourth quarter of 2016. 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 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.

Volume of Commodity Derivative Activity

As of December 31, 2015, 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	109,800
NGLs (gal)	Short	43,837,756

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, 2015, the estimated fair value of this contract was a liability of $31 million.

The Partnership has a commodity contract that gives it an option to fix a component of the utilities cost to an index price on electricity at its plant location in the Southwest operations through the fourth quarter of 2017. The contract is currently fixed through the fourth quarter of 2016 with the ability to fix the commodity contract for its remaining year. Changes in the fair value of the derivative component of this contract were recognized as Cost of revenues in the Consolidated Statements of Income. As of 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, 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, 2015
Derivative contracts not designated as hedging instruments and their balance sheet location	Asset		Liability
Commodity contracts⁽¹⁾
Other current assets / other current liabilities	$	9	$	(5	)
Other noncurrent assets / deferred credits and other liabilities	—		(27		)
Total	$	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)	2015
Product sales
Realized gain	4
Unrealized loss	(1	)
Total revenue: derivative gain from product sales	3
Purchased product costs
Unrealized gain	5
Total gain	8

16. Debt

The Partnership’s outstanding borrowings at December 31, 2015 and 2014 consisted of the following:



	December 31,
(In millions)	2015			2014
MPLX LP:
Bank revolving credit facility due 2020	$	877		$	385
Term loan facility due 2019	250			250
5.500% senior notes due 2023	710			—
4.500% senior notes due 2023	989			—
4.875% senior notes due 2024	1,149			—
4.000% senior notes due 2025	500			—
4.875% senior notes due 2025	1,189			—
Consolidated subsidiaries:
MarkWest - 5.500% senior notes due 2023	40			—
MarkWest - 4.500% senior notes due 2023	11			—
MarkWest - 4.875% senior notes due 2024	1			—
MarkWest - 4.875% senior notes due 2025	11			—
MPL - capital lease obligations due 2020	9			10
Total	5,736			645
Unamortized debt issuance costs⁽¹⁾	(8		)	—
Unamortized discount⁽²⁾	(472		)	—
Amounts due within one year	(1		)	(1		)
Total long-term debt due after one year	$	5,255		$	644


⁽¹⁾	The Partnership adopted the updated FASB debt issuance cost standard as of June 30, 2015. This has been applied retrospectively and there was no effect to the prior period presented.


⁽²⁾	2015 includes $465 million discount 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)
2016	$	1
2017	1
2018	1
2019	1
2020	1,132

Credit Agreements

On November 20, 2014, MPLX 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 entered into an amendment to 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 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’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, 2015, the Partnership was in compliance with the covenants contained in the MPLX Credit Agreement.

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

During 2015, the Partnership borrowed $992 million under the new 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.

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 in an exchange offer and consent solicitation undertaken by MPLX and MarkWest, leaving approximately $63 million aggregate principal of outstanding senior notes held by MarkWest.

The new MPLX 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 and (iv) approximately $1.19 billion aggregate principal amount of 4.875 percent senior notes due June 1, 2025. Interest on each series of MPLX 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, 2015, 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 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, 2015, the following amounts related to the SMR are included in the accompanying Consolidated Balance Sheets:



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

17. Goodwill and Intangibles

Goodwill

Goodwill is tested for impairment on an annual basis and when events or changes in circumstances indicate the fair value of a reporting unit has been reduced below carrying value. The Partnership has performed its annual impairment tests, and no impairment in the carrying value of goodwill has been identified during the periods presented.

In February of 2016, the Partnership’s units were trading at a price per unit significantly lower than the price per unit used to calculate the merger consideration and the resulting goodwill that was assigned to certain reporting units in the G&P segment. The significant assumptions that were used to develop the estimates of the fair values recorded in acquisition accounting and the resulting goodwill assigned to the reporting units are discussed in Note 4. If negative events related to those assumptions occur or if the market price of the units continues to trade at a low level in 2016, the Partnership may need to assess whether

this is a change in circumstances that indicates it is more likely than not that the fair value of the reporting units to which the goodwill was assigned in connection with the MarkWest Merger is less than their carrying value and, if so, evaluate goodwill for impairment.

There were no changes in the carrying amount of goodwill for 2014. The changes in carrying amount of goodwill for 2015 were as follows:



(In millions)	L&S		G&P		Total
Beginning balance	$	116	$	—	$	116
Acquisitions⁽¹⁾	—		2,454		2,454
Ending balance	$	116	$	2,454	$	2,570


⁽¹⁾	On December 4, 2015, the Partnership completed the MarkWest Merger, see Note 4 for more information.

Intangible Assets

There were no intangible assets as of December 31, 2014. The Partnership’s intangible assets as of December 31, 2015 are comprised of customer contracts and relationships, as follows:



(In millions)	Gross		Accumulated Amortization			Net		Useful Life
L&S	$	—	$	—		$	—	N/A
G&P	468		(2		)	466		11-25 years
	$	468	$	(2	)	$	466

Estimated future amortization expense related to the intangible assets at December 31, 2015 is as follows:



(In millions)
2016	32
2017	32
2018	32
2019	32
2020	32
Thereafter	306
Total	$	466

18. Supplemental Cash Flow Information



(In millions)	2015		2014		2013
Net cash provided by operating activities included:
Interest paid (net of amounts capitalized)	$	13	$	3	$	—
Non-cash investing and financing activities:
Net transfers of property, plant and equipment to inventories	$	5	$	1	$	4
Contribution - common units issued	—		200		—
Acquisition:
Fair value of MPLX 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)	2015		2014		2013
Increase (decrease) in capital accruals	$	26	$	11	$	(4	)

19. 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, 2015 were less than $1 million.

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 $1.03 per unit for 2015 and $1.16 per unit for 2014, 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 2015:



	Phantom Units
	Number of Units		Weighted Average Fair Value		Aggregate Intrinsic Value (In millions)
Outstanding at December 31, 2014	100,769		$	41.66
Granted	962,764		35.00
Settled	(32,314	)	40.18
Forfeited	—
Outstanding at December 31, 2015	1,031,219		35.49
Vested and expected to vest at December 31, 2015	1,001,324		35.52		$	39.40
Convertible at December 31, 2015	472,665		34.26		$	18.60

The 472,665 convertible units are held by our non-employee directors and certain officers. These units are non-forfeitable and issuable upon the director’s departure from our board of directors or the officer’s end of employment.

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
2015	$	3	$	35.00
2014	1		49.56
2013	—		—

As of December 31, 2015, unrecognized compensation cost related to phantom unit awards was $19 million, which is expected to be recognized over a weighted average period of 2.8 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 2015:



	Performance Units
	Number of Units	Weighted Average Fair Value
Outstanding at December 31, 2014	924,143	$	0.98
Granted	597,249	1.03
Forfeited	—	—
Outstanding at December 31, 2015	1,521,392	1.00

As of December 31, 2015, 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 1.7 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:



	2015			2014			2013
Risk-free interest rate	0.95		%	0.63		%	0.35		%
Look-back period	2.84 years			2.84 years			2.84 years
Expected volatility	30.12		%	17.17		%	16.75		%
Grant date fair value of performance units granted	$	1.03		$	1.16		$	0.77

The assumption for expected volatility of our unit price reflects the historical volatility of MPLX 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 $4 million in 2015, $3 million in 2014 and $1 million in 2013. Approximately $15 million was charged to the MarkWest purchase price in 2015 for MPLX unit-based compensation awards granted in connection with the MarkWest Merger.

MPC’s Stock-based Compensation

Stock-based compensation expenses charged to MPLX under our employee services agreement with MPC were $1 million for 2015, 2014 and 2013.

20. 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 2030 and 2023.

The Partnership’s revenue from its implicit lease arrangements, excluding executory costs, totaled approximately $89 million in 2015 and $14 million in 2014 and 2013. Based on the terms of the Partnership’s fee-based transportation services agreement

with MPC, HSM is also considered to be a lessor of its marine equipment in accordance with GAAP. 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 year ended December 31, 2015, the Partnership received less than $1 million in contingent lease payments. No contingent lease payments were received for the year ended December 31, 2014.

The following is a schedule of minimum future rentals on the non-cancellable operating leases as of December 31, 2015:



(In millions)
2016	$	265
2017	276
2018	279
2019	282
2020	283
2021 and thereafter	588
Total minimum future rentals	$	1,973

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



(In millions)
Natural gas gathering and NGL transportation pipelines and facilities	$	619
Natural gas processing facilities	753
Barges	360
Towing vessels	91
Construction in progress	110
Property, plant and equipment	1,933
Less: accumulated depreciation	(170		)
Total property, plant and equipment	$	1,763

As of December 31, 2014, we had no investment in assets held for operating lease.

21. 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, 2015:



	December 31,
(In millions)	2015
Beginning ARO	$	—
Liabilities assumed in conjunction with the MarkWest Merger	15
Liabilities incurred	2
Ending ARO	$	17

At December 31, 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 calculated and is not recorded.

22. 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, 2015 and 2014, accrued liabilities for remediation totaled $1 million. However, it is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties, if any, that may be imposed. There were $1 million in receivables from MPC for indemnification of environmental costs related to incidents occurring prior to the Initial Offering at December 31, 2015. There were no receivables from MPC for indemnification at December 31, 2014.

On July 6, 2015, officials from the EPA and the United States Department of Justice entered a MarkWest Liberty Midstream pipeline launcher/receiver site utilized for pipeline maintenance operations in Washington County, Pennsylvania pursuant to a search warrant issued by the United States District Court for the Western District of Pennsylvania. At the conclusion of the search, the governmental officials presented MarkWest Liberty Midstream with a subpoena to provide documents related to the design, construction, operation, maintenance, modification, inspection, assessment, repair of, and/or emissions from MarkWest Liberty Midstream’s pipeline facilities located in Pennsylvania. MarkWest Liberty Midstream is providing information in response to the subpoena and related requests for information from the relevant agencies, and is in discussions with the relevant agencies regarding issues associated with the search and subpoena and its operations of, and any permit related obligations for, its pipeline facilities in the Northeast. Immediately following the July 6, 2015 search, MarkWest Liberty Midstream commenced its own assessment of its operations of launcher/receiver facilities. MarkWest Liberty Midstream’s review to date has determined that MarkWest Liberty Midstream’s operations have been conducted in a manner fully protective of its employees and the public, and that other than potentially having to obtain minor source Clean Air Act permits at a relatively small number of individual sites, MarkWest Liberty has operated in substantial compliance with applicable laws and regulations. It is possible that, in connection with any potential civil or criminal enforcement action associated with this matter, MarkWest Liberty Midstream will incur material assessments, penalties or fines, incur material defense costs and expenses, be required to modify our operations or construction activities which could increase operating costs and capital expenditures, or be subject to other obligations or restrictions that could restrict or prohibit our activities, any or all of which could adversely affect our results of operations, financial position or cash flows. The amount of any potential assessments, penalties, fines, restrictions, requirements, modifications, costs or expenses that may be incurred in connection with any potential enforcement action cannot be reasonably estimated at this time.

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

Litigation Relating to the MarkWest Merger – In July 2015, a purported class action lawsuit asserting claims challenging the MarkWest Merger was filed in the Court of Chancery of the State of Delaware by a purported unitholder of MarkWest. In August 2015, two similar putative class action lawsuits were filed in the Court of Chancery of the State of Delaware by plaintiffs who purport to be unitholders of MarkWest. On September 9, 2015, these lawsuits were consolidated into one action pending in the Court of Chancery of the State of Delaware, now captioned In re MarkWest Energy Partners, L.P. Unitholder Litigation. On October 1, 2015, the plaintiffs filed a consolidated complaint against the individual members of the board of directors of MarkWest Energy GP, L.L.C. (the “MarkWest GP Board”), MPLX, MPLX GP, MPC and Sapphire Holdco LLC, a subsidiary of MPLX, asserting in connection with the MarkWest Merger and related disclosures that, among other things, (i) the MarkWest GP Board breached its duties in approving the MarkWest Merger with MPLX and (ii) MPC, MPLX, MPLX GP,

and Sapphire Holdco LLC aided and abetted such breaches. On February 4, 2016, the Court approved a stipulation and proposed order to dismiss all claims with prejudice as to the named plaintiffs, but for the Court to retain jurisdiction to adjudicate an application for a mootness fee by plaintiffs' counsel for an award of attorneys’ fees and reimbursement of expenses. We intend to vigorously defend against any application for a mootness fee and do not expect the resolution of such matter to have a material adverse effect.

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. 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 us 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.

Certain significant risks and uncertainties - Weather can be a major factor in the day-to-day operations of the Partnership, specifically its marine operations. Adverse weather conditions, such as high or low water, tropical storms, hurricanes, fog and ice, can impair the operating effectiveness of HSM’s fleet. Shipments of products can be delayed or postponed by weather conditions, which are totally beyond the control of the Partnership. Adverse water conditions are also factors which impair the efficiency of the fleet and can result in delays, diversions and limitations on night passages and dictate horsepower requirements and size of tows. Additionally, much of the inland waterway system is controlled by a series of locks and dams designed to provide flood control, maintain pool levels of water in certain areas of the country and facilitate navigation on the inland river system. Maintenance and operation of the navigable inland waterway infrastructure is a government function handled by the Army Corps of Engineers and associated infrastructure costs are shared by the industry. Significant changes in governmental policies or appropriations with respect to the maintenance and operation of the infrastructure could adversely affect the Partnership.

The Partnership is subject to regulation by the USCG, federal laws, state laws and numerous environmental regulations. Management believes that additional safety, environmental and occupational health regulations may be imposed on the marine industry. There can be no assurance that any such new regulations or requirements, or any discharge of pollutants by HSM, will not have an adverse effect on the consolidated results of operations, financial position or cash flows.

Contractual Commitments and Contingencies – At December 31, 2015 the Partnership’s contractual commitments to acquire property, plant and equipment totaled $147 million. Our contractual commitments at December 31, 2015 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, 2015, 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, 2015 are as follows:



(In millions)
2016	$	68
2017	74
2018	60
2019	59
2020	59
2021 and thereafter	299
Total	$	619

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, 2015, 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
2016	$	1	$	53
2017	1		51
2018	2		41
2019	2		36
2020	5		30
Later years	—		106
Total minimum lease payments	11		$	317
Less imputed interest costs	2
Present value of net minimum lease payments	$	9

Operating lease rental expense was:



(In millions)	2015		2014		2013
Minimum rental expense	$	21	$	17	$	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. 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)
2016	$	17
2017	17
2018	17
2019	17
2020	17
2021 and thereafter	162
Total minimum payments	247
Less: Services element	95
Less: Interest	52
Total SMR liability	100
Less: Current portion of SMR liability	4
Long-term portion of SMR liability	$	96

23. Subsequent Event

On February 3, 2016, the Partnership announced that MPC has offered to contribute its inland marine business in exchange for securities. The transaction closed on March 31, 2016.

Select Quarterly Financial Data (Unaudited)



	2015									2014
(In millions, except per unit data)	1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.⁽¹⁾			1st Qtr.		2nd Qtr.		3rd Qtr.		4th Qtr.
Revenues	$	183	$	193	$	195	$	310		$	184	$	186	$	187	$	190
Income from operations	74		82		68		74			71		60		61		53
Net income	68		76		63		42			70		59		59		51
Net income attributable to MPLX LP	46		51		41		18			34		28		30		29
Net income attributable to MPLX LP per limited partner unit:
Common - basic	$	0.46	$	0.50	$	0.41	$	(0.14	)	$	0.41	$	0.37	$	0.37	$	0.38
Common - diluted	0.46		0.50		0.41		(0.14		)	0.41		0.37		0.37		0.38
Subordinated - basic and diluted	0.46		0.50		—		—			0.41		0.37		0.37		0.33
Distributions declared per limited partner common unit	$	0.4100	$	0.4400	$	0.4700	$	0.5000		$	0.3275	$	0.3425	$	0.3575	$	0.3825

Distributions declared:
Limited partner units - Public	$	10	$	10	$	11	$	120		$	7	$	6	$	7	$	9
Limited partner units - MPC	23		25		27		29			18		19		19		21
General partner units - MPC	1		1		1		3			—		—		1		1
Incentive distribution rights - MPC	3		6		8		37			—		1		1		2
Total distributions declared	$	37	$	42	$	47	$	189		$	25	$	26	$	28	$	33


⁽¹⁾	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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