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Delaware
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27-0005456
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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Title of each class
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Name of each exchange on which registered
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Common Units Representing Limited Partnership Interests
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New York Stock Exchange
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Page
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Item 1.
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Item 1A.
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Item 1B.
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Item 2.
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Item 3.
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Item 4.
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Item 5.
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Item 6.
|
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Item 7.
|
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Item 7A.
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Item 8.
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Item 9.
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Item 9A.
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Item 9B.
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Item 10.
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Item 11.
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Item 12.
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Item 13.
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Item 14.
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Item 15.
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Item 16.
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Form 10-K Summary
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ARO
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Asset retirement obligation
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ASC
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Accounting Standards Codification
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ATM Program
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A continuous offering, or at-the-market program, by which the Partnership may offer up to an aggregate of $1.2 billion of common units, in amounts, at prices and on terms to be determined by market conditions and other factors at the time of any offerings, as defined by the prospectus supplement filed with the SEC on August 4, 2016
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Bbl
|
Barrels
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bcf/d
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Billion cubic feet per day
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Btu
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One British thermal unit, an energy measurement
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Condensate
|
A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions
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DCF (a non-GAAP financial measure)
|
Distributable Cash Flow
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DOT
|
United States Department of Transportation
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Dth/d
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Dekatherms per day
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EBITDA (a non-GAAP financial measure)
|
Earnings Before Interest, Taxes, Depreciation and Amortization
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EIA
|
United States Energy Information Administration
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EPA
|
United States Environmental Protection Agency
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ERCOT
|
Electric Reliability Council of Texas
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FASB
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Financial Accounting Standards Board
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FERC
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Federal Energy Regulatory Commission
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GAAP
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Accounting principles generally accepted in the United States of America
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Gal
|
Gallon
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Gal/d
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Gallons per day
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IDR
|
Incentive distribution rights
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Initial Offering
|
Initial public offering on October 12, 2012
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IRS
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Internal Revenue Service
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LIBOR
|
London Interbank Offered Rate
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mbbls
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Thousands of barrels
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mbpd
|
Thousand barrels per day
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mcf
|
One thousand cubic feet of natural gas
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MMBtu
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One million British thermal units, an energy measurement
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mmcf/d
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One million cubic feet of natural gas per day
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Net operating margin (a non-GAAP financial measure)
|
Segment revenue, less segment purchased product costs, less realized derivative gain (loss)
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NGL
|
Natural gas liquids, such as ethane, propane, butanes and natural gasoline
|
NYSE
|
New York Stock Exchange
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OTC
|
Over-the-Counter
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Realized derivative gain/loss
|
The gain or loss recognized when a derivative matures or is settled
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PADD
|
Petroleum Administration for Defense District
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PHMSA
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Pipeline and Hazardous Materials Safety Administration
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PPI
|
Producer Price Index
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SEC
|
Securities and Exchange Commission
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SMR
|
Steam methane reformer, operated by a third party and located at the Javelina gas processing and fractionation complex in Corpus Christi, Texas
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Unrealized derivative gain/loss
|
The gain or loss recognized on a derivative due to changes in fair value prior to the instrument maturing or settling
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USCG
|
United States Coast Guard
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VIE
|
Variable interest entity
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WTI
|
West Texas Intermediate
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•
|
future levels of revenues and other income, income from operations, net income attributable to MPLX LP, earnings per unit, Adjusted EBITDA or DCF (please read Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Information for the definitions of Adjusted EBITDA and DCF);
|
•
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anticipated levels of regional, national and worldwide prices of crude oil, natural gas, NGLs and refined products;
|
•
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anticipated levels of drilling activity, production rates and volumes of throughput of crude oil, natural gas, NGLs, refined products or other hydrocarbon-based products;
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•
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future levels of capital, environmental or maintenance expenditures, general and administrative and other expenses;
|
•
|
the success or timing of completion of ongoing or anticipated capital or maintenance projects;
|
•
|
expectations regarding the MarkWest Merger (as defined below), joint venture arrangements and other acquisitions, including the dropdowns proposed by MPC, or divestitures of assets;
|
•
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business strategies, growth opportunities and expected investments;
|
•
|
the effect of restructuring or reorganization of business components;
|
•
|
the potential effects of judicial or other proceedings on our business, financial condition, results of operations and cash flows;
|
•
|
the potential effects of changes in tariff rates on our business, financial condition, results of operations and cash flows;
|
•
|
the adequacy of our capital resources and liquidity, including, but not limited to, availability of sufficient cash flow to pay distributions and execute our business plan;
|
•
|
our ability to successfully implement our growth strategy, whether through organic growth or acquisitions;
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•
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capital market conditions, including the cost of capital, and our ability to raise adequate capital to execute our business plan and implement our growth strategy; and
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•
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the anticipated effects of actions of third parties such as competitors, or federal, foreign, state or local regulatory authorities, or plaintiffs in litigation.
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•
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changes in general economic, market or business conditions;
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•
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changes in the economic and financial condition of MPLX LP;
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•
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risks and uncertainties associated with intangible assets, including any future goodwill or intangible assets impairment charges;
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•
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changes in producer customers’ drilling plans or in volumes of throughput of crude oil, natural gas, NGLs, refined products or other hydrocarbon-based products;
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•
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changes in regional, national and worldwide prices of crude oil, natural gas, NGLs and refined products;
|
•
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domestic and foreign supplies of crude oil and other feedstocks, natural gas, NGLs and refined products such as gasoline, diesel fuel, jet fuel, home heating oil and petrochemicals;
|
•
|
foreign imports and exports of crude oil, refined products, natural gas and NGLs;
|
•
|
midstream and refining industry overcapacity or undercapacity;
|
•
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changes in the cost or availability of third-party vessels, pipelines, railcars and other means of transportation for crude oil, natural gas, NGLs, feedstocks and refined products;
|
•
|
price, availability and acceptance of alternative fuels and alternative-fuel vehicles and laws mandating such fuels or vehicles;
|
•
|
fluctuations in consumer demand for refined products, natural gas and NGLs, including seasonal fluctuations;
|
•
|
changes in maintenance capital expenditure requirements or changes in costs of planned capital projects;
|
•
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political and economic conditions in nations that consume refined products, natural gas and NGLs, including the United States, and in crude oil producing regions, including the Middle East, Africa, Canada and South America;
|
•
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actions taken by our competitors and the expansion and retirement of pipeline, processing, fractionation and treating capacity in response to market conditions;
|
•
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changes in fuel and utility costs for our facilities;
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•
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failure to realize the benefits projected for capital projects, or cost overruns associated with such projects;
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•
|
the ability to successfully implement growth strategies, whether through organic growth or acquisitions;
|
•
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the time, costs and ability to obtain regulatory and other approvals, waivers or consents required to consummate the strategic initiatives proposed by MPC, such as the proposed accelerated dropdown of assets to MPLX LP;
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•
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accidents or other unscheduled shutdowns affecting our pipelines, processing, fractionation and treating facilities or equipment, or those of our suppliers or customers or facilities upstream or downstream of our facilities;
|
•
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unusual weather conditions and natural disasters;
|
•
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disruptions due to equipment interruption or failure;
|
•
|
acts of war, terrorism or civil unrest that could impair our ability to gather, process, fractionate or transport crude oil, natural gas, NGLs or refined products;
|
•
|
legislative or regulatory action, which may adversely affect our business or operations;
|
•
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rulings, judgments or settlements in litigation or other legal, tax or regulatory matters, including unexpected environmental remediation costs, in excess of any reserves or insurance coverage;
|
•
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political pressure and influence of environmental groups upon policies and decisions related to the production, gathering, processing, fractionation, refining, transportation and marketing of natural gas, oil, NGLs or other carbon-based fuels;
|
•
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labor and material shortages;
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•
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the ability and willingness of parties with whom we have material relationships to perform their obligations to us;
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•
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capital market conditions, including a persistence or increase of the current yield on MPLX LP common units, adversely affecting MPLX LP’s ability to meet its distribution growth guidance;
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•
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increases in and availability of equity capital, changes in the availability of unsecured credit and changes affecting the credit markets generally; and
|
•
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the other factors described in Item 1A. Risk Factors.
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|
|
2016
|
||||||||||
(In millions)
|
|
L&S
|
|
G&P
|
|
Total
|
||||||
Revenues and other income:
|
|
|
|
|
|
|
||||||
Segment revenues
|
|
$
|
787
|
|
|
$
|
2,185
|
|
|
$
|
2,972
|
|
Segment other income
|
|
68
|
|
|
1
|
|
|
69
|
|
|||
Total segment revenues and other income
|
|
855
|
|
|
2,186
|
|
|
3,041
|
|
|||
Costs and expenses:
|
|
|
|
|
|
|
||||||
Segment cost of revenues
|
|
368
|
|
|
907
|
|
|
1,275
|
|
|||
Segment operating income before portion attributable to noncontrolling interest and Predecessor
|
|
487
|
|
|
1,279
|
|
|
1,766
|
|
|||
Segment portion attributable to noncontrolling interest and Predecessor
|
|
34
|
|
|
147
|
|
|
181
|
|
|||
Segment operating income attributable to MPLX LP
|
|
$
|
453
|
|
|
$
|
1,132
|
|
|
$
|
1,585
|
|
•
|
Our L&S assets are strategically located and collectively comprise approximately
81
percent of total United States crude distillation capacity and approximately
81
percent of total United States finished products demand for the year ended
December 31, 2016
, according to the EIA. These assets are integral to the success of MPC’s operations, which include
seven
refineries in the Midwest and Gulf Coast regions of the United States with an aggregate crude oil refining capacity of approximately
1.8 million
barrels per calendar day.
|
•
|
Our G&P segment is focused on regions of natural gas supply growth. We are one of the largest processors and
|
◦
|
We are the largest processor and fractionator in the Marcellus and Utica shale plays. As of
February 13, 2017
, our assets in the northeastern United States have combined processing capacity of approximately
6.1
bcf/d and combined fractionation capacity of approximately
518
mbpd as well as an integrated NGL pipeline network and extensive logistics and marketing infrastructure. We believe our significant asset base and full-service midstream model provides us with strategic competitive advantages in capturing and contracting for gathering, processing and fractionating of new supplies of natural gas as production in the Northeast continues to increase.
|
◦
|
We also have a significant presence in the southwestern portion of the United States with an existing strong competitive position; access to a significant reserve or customer base with a stable or growing production profile; ample opportunities for long-term continued organic growth; ready access to markets; and close proximity to other expansion opportunities. We have
1.4
bcf/d of processing capacity in the southwestern portion of the United States.
|
|
Remaining contract term
|
|
% of volumes
|
|
L&S segment
|
6 years
|
|
72
|
%
|
G&P segment
|
4 to 19 years
|
|
85
|
%
|
•
|
Our common units are publicly traded on the NYSE under the symbol “MPLX.”
|
•
|
The Preferred units rank senior to all common units with respect to distributions and rights upon liquidation. The holders of the Preferred units are entitled to receive cumulative quarterly distributions equal to $0.528125 per unit commencing for the quarter ended June 30, 2016, with a prorated amount from the date of issuance. Following the second anniversary of the issuance of the Preferred units, the holders of the Preferred units will receive as a distribution the greater of $0.528125 per unit or the amount of per unit distributions paid to common units. The purchasers may convert their Preferred units into common units, at any time after the third anniversary of the issuance date or prior to liquidation, dissolution or winding up of the Partnership, in full or in part, subject to minimum conversion amounts and conditions. After the fourth anniversary of the issuance date, the Partnership may convert the Preferred units into common units at any time, in whole or in part, subject to certain minimum conversion amounts and conditions, if the closing price of MPLX LP common units is greater than $48.75 for the 20 day trading period immediately preceding the conversion notice date. The conversion rate for the Preferred units shall be the quotient of (a) the sum of (i) $32.50, plus (ii) any unpaid cash distributions on the applicable Preferred unit, divided by (b) $32.50. The holders of the Preferred units are entitled to vote on an as-converted basis with the common unitholders and will have certain other class voting rights with respect to any amendment to the partnership agreement that would adversely affect any rights, preferences or privileges of the Preferred units. In addition, upon certain events involving a change in control the holders of Preferred units may elect, among other potential elections, to convert their Preferred units to common units at the then change of control conversion rate.
|
•
|
All of the Class B units were issued to and are held by M&R MWE Liberty LLC and certain of its affiliates (“M&R”), an affiliate of The Energy & Minerals Group (“EMG”). Each Class B unit of MarkWest issued and outstanding immediately prior to the effective time of the MarkWest Merger was converted into the right to receive one Class B unit of MPLX LP. Each Class B unit of MPLX LP will convert into 1.09 common units of MPLX LP and the right to receive $6.20 in cash, and the conversion of the Class B units will occur in equal installments, the first of which occurred on July 1, 2016 and the second of which will occur on July 1, 2017. Class B units (i) share in our taxable income and losses, (ii) are not entitled to participate in any distributions of available cash prior to their conversion and (iii) do not have the right to vote on, approve or disapprove, or otherwise consent to or not consent to any matter (including mergers, unit exchanges and similar statutory authorizations) other than those matters that disproportionately and adversely affect the rights and preferences of the Class B units. Upon conversion of the Class B units, the right of M&R and certain of its affiliates to vote as a common unitholder of the Partnership will be limited to a maximum of five percent of the Partnership’s outstanding common units. Upon the conversion of each tranche of Class B units, M&R will have the right with respect to such converted units to participate in the Partnership’s underwritten offerings of our common units including continuous equity or similar programs in an amount up to 20 percent of the total number of common units offered by the Partnership. In addition, M&R may freely transfer such converted units, and M&R will have the right to demand that we conduct up to three underwritten offerings beginning in 2017, but restricted to no more than one offering in any twelve-month period. M&R is not permitted to transfer its Class B units without the prior written consent of our general partner’s board of directors.
|
•
|
Logistics
. Crude oil is the primary raw material for transportation fuels and the basis for many products including plastics and petrochemicals, in addition to heating oil for homes once it is refined and prepared for use. While many forms of transportation are used to move this product to storage hubs and refineries, we believe pipelines and marine vessels are among the safest, most efficient and cost-effective ways to move this resource to refineries and to market. Pipelines bring advantaged North American crude oil from the upper Great Plains, Texas and Canada to numerous refiners. Pipelines and marine vessels are also used to effectively move refined products from refineries to customers and end markets.
|
•
|
Storage
. The hydrocarbon market is often volatile and the ability to take advantage of fast moving market conditions is enhanced by our ability to store crude oil and other hydrocarbon-based products at our tank farms and butane cavern. Storage facilities provide flexibility and logistics optionality, which enhances MPC’s ability to maximize returns for refined products.
|
•
|
Gathering.
The natural gas production process begins with the drilling of wells into gas-bearing rock formations. At the initial stages of the midstream value chain, a network of pipelines known as gathering systems directly connect to wellheads in the production area. These gathering systems transport raw, or untreated, natural gas to a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow gathering of additional production without significant incremental capital expenditures.
|
◦
|
Compression.
Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which allows the natural gas to be gathered more efficiently and delivered into a higher pressure system, processing plant or pipeline. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure system. Since wells produce at progressively lower field pressures as they deplete, field compression is needed to maintain throughput across the gathering system.
|
◦
|
Treating and dehydration.
To the extent that gathered natural gas contains contaminants, such as water vapor, carbon dioxide and/or hydrogen sulfide, such natural gas is dehydrated to remove the saturated water and treated to separate the carbon dioxide and hydrogen sulfide from the gas stream.
|
•
|
Processing.
Natural gas has a widely varying composition depending on the field, formation reservoir or facility from which it is produced. Processing removes the heavier and more valuable hydrocarbon components, which are extracted as a mixed NGL stream that includes ethane, propane, butanes and natural gasoline (also referred to
|
•
|
Fractionation.
Fractionation is the separation of the mixture of extracted NGLs into individual components for end-use sale. It is accomplished by controlling the temperature and pressure of the stream of mixed NGLs in order to take advantage of the different boiling points and vapor pressures of separate products. Fractionation systems typically exist either as an integral part of a gas processing plant or as a central fractionator, often located many miles from the primary production and processing complex. A central fractionator may receive mixed streams of NGLs from many processing plants. A fractionator can fractionate one product or in a central fractionator, multiple products. We operate fractionation facilities at certain processing facilities that separate ethane from the remainder of the y-grade stream. We also operate central fractionation facilities that separate y-grade into propane, butanes and natural gasoline.
|
•
|
Storage, transportation and marketing.
Once the raw natural gas has been treated or processed and the raw NGL mix has been fractionated into individual NGL components, the natural gas is delivered to downstream transmission pipelines and NGL components are stored, transported and marketed to end-use markets. We market NGLs domestically as well as for export to international markets. NGLs are transported via pipeline, railcar, including unit trains, and truck. Each pipeline system typically has storage capacity located both throughout the pipeline network and at major market centers to help temper seasonal demand and daily operational or supply-demand shifts. We have caverns for propane storage in the northeastern United States.
|
•
|
Ethane
is used primarily as feedstock in the production of ethylene, one of the basic building blocks for a wide range of plastics and other chemical products.
|
•
|
Propane
is used for heating, engine and industrial fuels, agricultural burning and drying and as a petrochemical feedstock for the production of ethylene and propylene.
|
•
|
Normal butane
is mainly used for gasoline blending, as a fuel gas, either alone or in a mixture with propane, and as a feedstock for the manufacture of ethylene and butadiene, a key ingredient of synthetic rubber.
|
•
|
Isobutane
is primarily used by refiners to enhance the octane content of motor gasoline.
|
•
|
Natural gasoline
is principally used as a motor gasoline blend stock or petrochemical feedstock.
|
•
|
Ethylene
is primarily used in the production of a wide range of plastics and other chemical products.
|
•
|
Propylene
is primarily used in manufacturing plastics, synthetic fibers and foams. It is also used in the manufacture of polypropylene, which has a variety of end-uses including packaging film, carpet and upholstery fibers and plastic parts for appliances, automobiles, housewares and medical products.
|
Crude Oil Pipeline System Name
|
|
Capacity
(mbpd)
|
|
Associated MPC refineries
|
|
Patoka to Lima crude system
|
|
267
|
|
|
Detroit, MI; Canton, OH
|
Catlettsburg and Robinson crude system
|
|
515
|
|
|
Robinson, IL; Catlettsburg, KY
|
Detroit crude system
|
|
197
|
|
|
Detroit, MI
|
Wood River to Patoka crude system
|
|
314
|
|
|
All Midwest refineries
|
Total crude oil pipelines
|
|
1,293
|
|
|
|
Product Pipeline System Name
|
|
Capacity
(mbpd)
|
|
Associated MPC refineries
|
|
Cornerstone products system
|
|
238
|
|
|
Canton, OH
|
Garyville products system
|
|
389
|
|
|
Garyville, LA
|
Texas City products system
|
|
215
|
|
|
Texas City, TX; Galveston Bay, TX
|
ORPL products system
|
|
244
|
|
|
Catlettsburg, KY; Canton, OH
|
Robinson products system
|
|
513
|
|
|
Robinson, IL
|
Louisville airport products system
|
|
29
|
|
|
Robinson, IL
|
Total product pipelines
|
|
1,628
|
|
|
|
Other L&S Assets
|
|
Capacity
(1)
|
|
Associated MPC refineries
|
Wood River barge dock
|
|
78 mbpd
|
|
Garyville, LA
|
Neal butane cavern
|
|
1,000 mbbls
|
|
Catlettsburg, KY
|
Tank farms
|
|
4,533 mbbls
|
|
All Midwest refineries
|
Marine Repair Facility
|
|
N/A
|
|
Catlettsburg, KY
|
(1)
|
All capacity shown is for
100 percent
of the available storage capacity of our butane cavern and tank farms and
100 percent
of the barge dock’s average capacity.
|
Marine Vessels
|
|
Number at December 31, 2016
|
|
Capacity
(thousand barrels)
|
|
Associated MPC refineries
|
||
Inland tank barges:
(1)
|
|
|
|
|
|
Catlettsburg, KY; Garyville, LA
|
||
Less than 25,000 barrels
|
|
64
|
|
|
963
|
|
|
|
25,000 barrels and over
|
|
158
|
|
|
4,631
|
|
|
|
Total
|
|
222
|
|
|
5,594
|
|
|
|
Inland towboats:
|
|
|
|
|
|
Catlettsburg, KY; Garyville, LA
|
||
Less than 2,000 horsepower
|
|
2
|
|
|
|
|
|
|
2,000 horsepower and over
|
|
16
|
|
|
|
|
|
|
Total
|
|
18
|
|
|
|
|
|
(1)
|
All of our barges are double-hulled.
|
Plant
|
|
Existing capacity (mmcf/d)
|
|
Expansion capacity under construction (mmcf/d)
|
|
Expected in-service of expansion capacity
|
|
Geographic Region
|
||
Keystone Complex
|
|
410
|
|
|
—
|
|
|
N/A
|
|
Marcellus Operations
|
Harmon Creek Complex
|
|
—
|
|
|
200
|
|
|
2018
|
|
Marcellus Operations
|
Houston Complex
(1)
|
|
555
|
|
|
200
|
|
|
Q1 2018
|
|
Marcellus Operations
|
Majorsville Complex
(1)
|
|
1,070
|
|
|
200
|
|
|
2018
|
|
Marcellus Operations
|
Mobley Complex
|
|
920
|
|
|
—
|
|
|
N/A
|
|
Marcellus Operations
|
Sherwood Complex
|
|
1,200
|
|
|
600
|
|
|
Q2 2017, Q4 2017 and Q1 2018
|
|
Marcellus Operations
|
Cadiz Complex
(2)
|
|
525
|
|
|
200
|
|
|
2018
|
|
Utica Operations
|
Seneca Complex
(2)
|
|
800
|
|
|
—
|
|
|
N/A
|
|
Utica Operations
|
Kenova Complex
|
|
160
|
|
|
—
|
|
|
N/A
|
|
Southern Appalachian Operations
|
Boldman Complex
|
|
70
|
|
|
—
|
|
|
N/A
|
|
Southern Appalachian Operations
|
Cobb Complex
|
|
65
|
|
|
—
|
|
|
N/A
|
|
Southern Appalachian Operations
|
Langley Complex
|
|
325
|
|
|
—
|
|
|
N/A
|
|
Southern Appalachian Operations
|
Carthage Complex
|
|
600
|
|
|
—
|
|
|
N/A
|
|
Southwest Operations
|
Western Oklahoma Complex
|
|
425
|
|
|
—
|
|
|
N/A
|
|
Southwest Operations
|
Hidalgo Complex
|
|
200
|
|
|
—
|
|
|
N/A
|
|
Southwest Operations
|
Javelina Complex
|
|
142
|
|
|
—
|
|
|
N/A
|
|
Southwest Operations
|
Total
|
|
7,467
|
|
|
1,400
|
|
|
|
|
|
(1)
|
We have the operational flexibility to process gas for producer customers at either complex.
|
(2)
|
We have the operational flexibility to process gas for producer customers at either complex.
|
|
|
Marcellus Operations
|
|
Utica Operations
|
|
Southern Appalachian Operations
|
|
Southwest Operations
|
Key Producer Customers
|
|
Range Resources, Antero
(1)
, EQT
(1)
, CNX, Noble
(1)
, Southwestern
(1)
, Rex and others
|
|
Antero
(1)
, Gulfport, Ascent, Rice, Rex, PDC and others
|
|
Chesapeake
(1)(2)
, EQT
(1)
and
NiSource
(1)
|
|
Anadarko, Newfield, BP, PetroQuest and others
|
Volume Protection
|
|
65% of 2016 capacity contains minimum volume commitments
|
|
27% of 2016 capacity contains minimum volume commitments
|
|
24% of 2016 capacity contains minimum volume commitments
|
|
15% of 2016 capacity contains minimum volume commitments
|
Area Dedications
|
|
4 million acres
|
|
3.9 million acres
|
|
None
|
|
1.5 million acres
|
(1)
|
We do not provide gathering services for these producer customers.
|
(2)
|
In the fourth quarter of 2016, Chesapeake executed a purchase and sale agreement to sell the majority of its upstream and midstream assets in the Devonian Shale located in West Virginia and Kentucky. The new owner continues to utilize our processing facilities in the Southern Appalachian Operations.
|
Facility
|
|
Existing propane and heavier NGLs + capacity (mbpd)
|
|
Market outlets
|
|
Geographic Region
|
|
Keystone Complex
|
|
47
|
|
|
Railcar and truck loading
|
|
Marcellus Operations
|
Hopedale Complex
(1)
|
|
180
|
|
|
Key interstate pipeline access
Railcar and truck loading
Marine vessels
|
|
Marcellus and Utica Operations
|
Houston Complex
|
|
60
|
|
|
Key interstate pipeline access
Railcar and truck loading
Marine vessels
|
|
Marcellus Operations
|
Siloam Complex
|
|
24
|
|
|
Railcar and truck loading
Marine vessels
|
|
Southern Appalachian Operations
|
Javelina Complex
|
|
11
|
|
|
Key interstate pipeline access
|
|
Southwest Operations
|
Total
|
|
322
|
|
|
|
|
|
(1)
|
The Hopedale Complex is jointly owned by MarkWest Ohio Fractionation Company, L.L.C. (“Ohio Fractionation”) and MarkWest Utica EMG. Ohio Fractionation is a subsidiary of MarkWest Liberty Midstream & Resources, L.L.C (“MarkWest Liberty Midstream”). MarkWest Liberty Midstream and MarkWest Utica EMG are entities that operate in the
|
Facility
|
|
Existing ethane capacity (mbpd)
|
|
Ethane expansion capacity under construction (mbpd)
|
|
Expected in-service of expansion capacity
|
|
Geographic Region
|
||
Keystone Complex
|
|
14
|
|
|
20
|
|
|
Q3 2017
|
|
Marcellus Operations
|
Harmon Creek Complex
|
|
—
|
|
|
20
|
|
|
2018
|
|
Marcellus Operations
|
Houston Complex
|
|
40
|
|
|
—
|
|
|
N/A
|
|
Marcellus Operations
|
Majorsville Complex
|
|
40
|
|
|
40
|
|
|
Q4 2017
|
|
Marcellus Operations
|
Mobley Complex
|
|
10
|
|
|
—
|
|
|
N/A
|
|
Marcellus Operations
|
Sherwood Complex
|
|
40
|
|
|
—
|
|
|
N/A
|
|
Marcellus Operations
|
Cadiz Complex
|
|
40
|
|
|
—
|
|
|
N/A
|
|
Utica Operations
|
Javelina Complex
|
|
18
|
|
|
—
|
|
|
N/A
|
|
Southwest Operations
|
Total
|
|
202
|
|
|
80
|
|
|
|
|
|
•
|
We transport purity ethane produced at the Majorsville Complex and the Sherwood Complex to the Houston Complex on a FERC pipeline. Beginning in April 2016, purity ethane produced at the Mobley Complex began being transported on this same FERC pipeline to the Houston Complex.
|
•
|
We deliver purity ethane to Sunoco Logistics Partners L.P.’s (“Sunoco”) Mariner West pipeline (“Mariner West”) from the Houston Complex and from the Keystone Complex.
|
•
|
We deliver purity ethane to Enterprise Products Partners L.P.’s Appalachia-to-Texas Express (“ATEX”) pipeline from the Houston Complex and the Cadiz Complex.
|
•
|
Sunoco developed the Mariner East project (“Mariner East”), a pipeline and marine project that originates at our Houston Complex. Beginning in December 2014, Mariner East began transporting propane to Sunoco’s terminal near Philadelphia, Pennsylvania (“Marcus Hook Facility”) where it is loaded onto marine vessels and delivered to international markets. Beginning in May 2016, Mariner East began transporting purity ethane in addition to propane to the Marcus Hook Facility.
|
•
|
Sunoco has announced phase two of Mariner East (“Mariner East II”) with plans to construct a pipeline from our Houston and Hopedale Complexes in western Pennsylvania and eastern Ohio, respectively, to transport propane and butane to the Marcus Hook Facility where it will be loaded onto marine vessels and delivered to domestic and international markets. The Mariner East II pipeline is expected to be operational in late 2017.
|
Agreement
|
|
Initiation Date
|
|
Term (years)
|
|
MPC minimum
commitment
(1)
|
||
Transportation Services (mbpd):
|
|
|
|
|
|
|
||
Crude systems
|
|
October 31, 2012
|
|
5-10
|
|
|
745
|
|
Product systems
|
|
Various
|
|
10-15
|
|
|
900
|
|
Marine
|
|
January 1, 2015
|
|
6
|
|
|
N/A
(2)
|
|
Storage Services (mbbls):
|
|
|
|
|
|
|
||
Neal Butane Cavern
|
|
October 31, 2012
|
|
10
|
|
|
1,000
|
|
Tank Farms
|
|
Various
|
|
3
|
|
|
4,963
|
|
(1)
|
Quarterly commitment for our transportation services agreements in thousands of barrels per day and committed storage for our storage services agreements in thousands of barrels. Volumes shown for crude oil transportation services agreements are adjusted for crude viscosities.
|
(2)
|
MPC has committed to utilize 100 percent of our available capacity of tanks and barges.
|
•
|
Omnibus Agreement.
As of October 31, 2012, we entered into an omnibus agreement with MPC that 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, as well as MPC’s indemnification of us for certain matters, including certain environmental, title and tax matters. In addition, we will indemnify MPC for certain matters under this agreement.
|
•
|
Employee Services Agreements.
We have four employee services agreements with MPC. Two of the employee services agreements with MPC were entered into effective October 1, 2012, under which we agreed to reimburse MPC for the provision of certain operational and management services to us in support of our pipelines, barge dock, butane cavern
|
•
|
Fee-based arrangements
– Under fee-based arrangements, we receive a fee or fees for one or more of the following services: transportation and storage of crude oil; gathering, processing and transmission of natural gas; gathering, transportation, fractionation and storage of NGLs; and gathering and transportation of crude oil. The revenue we earn from these arrangements is generally directly related to the volume of natural gas, NGLs or crude oil that flows through our systems and facilities and is not normally directly dependent on commodity prices. In certain cases, our arrangements provide for minimum annual payments or fixed demand charges. Fee-based arrangements are reported as
Service revenue
on the Consolidated Statements of Income. In certain instances when specifically stated in the contract terms, we purchase product after fee-based services have been provided. Costs to purchase such products are reported as
Purchased product costs
and revenue from the sale of such products is reported as
Product sales
and recognized on a gross basis as we are the principal in the transaction.
|
•
|
Percent-of-proceeds arrangements
–
Under percent-of-proceeds arrangements, we gather and process natural gas on behalf of producers, sell the resulting residue gas, condensate and NGLs at market prices and remit to
|
•
|
Keep-whole arrangements
–
Under keep-whole arrangements, we gather natural gas from the producer, process the natural gas and sell 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, we 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 us 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 we are the principal in the arrangement. Natural gas purchased to return to the producer and shared NGL profits are recorded as
Purchased product costs
in the Consolidated Statements of Income.
|
•
|
Percent-of-index arrangements
–
Under percent-of-index arrangements, we purchase 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. We then gather and deliver the natural gas to pipelines where we resell 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 we purchase and take title to the product prior to sale and are the principal in the transaction.
|
|
Fee-Based
|
|
Percent-of-Proceeds
(1)
|
|
Keep-Whole
(2)
|
|||
L&S
(3)
|
100
|
%
|
|
—
|
%
|
|
—
|
%
|
G&P
(3)(4)
|
90
|
%
|
|
9
|
%
|
|
1
|
%
|
Total
|
93
|
%
|
|
6
|
%
|
|
1
|
%
|
(1)
|
Includes condensate sales and other types of arrangements tied to NGL prices.
|
(2)
|
Includes condensate sales and other types of arrangements tied to both NGL and natural gas prices.
|
(3)
|
Detail on contract types above.
|
(4)
|
Includes unconsolidated affiliates (See Item 8. Financial Statements and Supplementary Data – Note
5
).
|
•
|
natural gas midstream providers, of varying financial resources and experience, that gather, transport, process, fractionate, store and market natural gas and NGLs;
|
•
|
major integrated oil companies and refineries;
|
•
|
medium and large sized independent exploration and production companies;
|
•
|
major interstate and intrastate pipelines; and
|
•
|
other marine and land-based transporters of natural gas and NGLs.
|
•
|
the overall cost of service, including operating costs and overhead;
|
•
|
the allocation of overhead and other administrative and general expenses to the regulated entity;
|
•
|
the appropriate capital structure to be utilized in calculating rates;
|
•
|
the appropriate rate of return on equity and interest rates on debt;
|
•
|
the rate base, including the proper starting rate base;
|
•
|
the throughput underlying the rate; and
|
•
|
the proper allowance for federal and state income taxes.
|
•
|
rates and rate structures;
|
•
|
return on equity;
|
•
|
recovery of costs;
|
•
|
the services that our regulated assets are permitted to perform;
|
•
|
the acquisition, construction, expansion, operation and disposition of assets;
|
•
|
affiliate interactions; and
|
•
|
to an extent, the level of competition in that regulated industry.
|
•
|
We may have difficulties obtaining additional financing for working capital, capital expenditures, acquisitions, including the dropdowns proposed by MPC, or general partnership purposes on favorable terms, if at all, or our cost of borrowing may increase. Our funds available for operations, business opportunities and distributions to unitholders will also be reduced by that portion of our cash flow required to make interest payments on our debt.
|
•
|
We may be at a competitive disadvantage compared to our competitors who have proportionately less debt, or we may be more vulnerable to, and have limited flexibility to respond to, competitive pressures or a downturn in our business or the economy generally.
|
•
|
If our operating results are not sufficient to service our indebtedness, we may be required to reduce our distributions, reduce or delay our business activities, investments or capital expenditures, sell assets or issue equity, which could materially and adversely affect our financial condition, results of operations, cash flows and ability to make distributions to unitholders, as well as the trading price of our common units.
|
•
|
The operating and financial restrictions and covenants in our revolving credit facility and any future financing agreements could restrict our ability to finance our operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make distributions to our unitholders. Our ability to comply with these covenants may be impaired from time to time if the fluctuations in our working capital needs are not consistent with the timing for our receipt of funds from our operations.
|
•
|
If we fail to comply with our debt obligations and an event of default occurs, our lenders could declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable, which may trigger defaults under our other debt instruments or other contracts. Our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of their investment.
|
•
|
the fees and tariff rates we charge and the margins we realize for our services and sales;
|
•
|
the prices of, level of production of and demand for oil, natural gas, NGLs and refined products;
|
•
|
the volumes of natural gas, crude oil, NGLs and refined products we gather, process, store, transport and fractionate;
|
•
|
the level of our operating costs including repairs and maintenance;
|
•
|
the relative prices of NGLs and crude oil, which impact the effectiveness of our hedging program; and
|
•
|
prevailing economic conditions.
|
•
|
the amount of our operating expenses and general and administrative expenses, including cost reimbursements to MPC in respect of those expenses;
|
•
|
our debt service requirements and other liabilities;
|
•
|
fluctuations in our working capital needs;
|
•
|
our ability to borrow funds and access capital markets;
|
•
|
restrictions in our joint venture agreements, revolving credit facility or other agreements governing our debt;
|
•
|
the level and timing of capital expenditures we make, including capital expenditures incurred in connection with our enhancement projects;
|
•
|
the cost of acquisitions, if any; and
|
•
|
the amount of cash reserves established by our general partner in its discretion.
|
•
|
more stringent permitting and other regulatory requirements;
|
•
|
a limited supply of qualified fabrication and construction contractors, which could delay or increase the cost of the construction and installation of our facilities or increase the cost of operating our existing facilities;
|
•
|
unexpected increases in the volume of oil, natural gas, NGLs and refined products being delivered to our facilities, which could adversely affect our ability to expand our facilities in a manner that is consistent with our customers’ production or delivery schedules;
|
•
|
changes in, or inability to meet, downstream gas, NGL, crude oil or refined product pipeline quality specifications, which could reduce the volumes of gas, NGLs, crude oil and refined products that we receive;
|
•
|
scheduled maintenance, unexpected outages or downtime at our facilities or at upstream or downstream third-party facilities, which could reduce the volumes of oil, gas, NGLs and refined products that we receive; and
|
•
|
market and capacity constraints affecting downstream oil, natural gas, NGL and refined products facilities, including limited gas and NGL capacity downstream of our facilities, limited railcar and NGL pipeline facilities and reduced demand or limited markets for certain NGL or refined products, which could reduce the volumes of oil, gas, NGLs and refined products that we receive and adversely affect the pricing received for NGLs.
|
•
|
availability of sufficient railcar, tanker and terminalling facility capacity;
|
•
|
currency fluctuations, particularly to the extent sales are denominated in foreign currencies as we do not currently hedge against currency fluctuations;
|
•
|
compliance with additional governmental regulations and maritime requirements, including U.S. export controls and foreign laws, sanctions regulations and the Foreign Corrupt Practices Act;
|
•
|
risks of loss resulting from non-payment or non-performance by international purchasers; and
|
•
|
political and economic disturbances in the countries to which NGLs are being exported.
|
•
|
the validity of our assumptions about revenues, capital expenditures and operating costs of the acquired business or assets, as well as assumptions about achieving synergies with our existing business;
|
•
|
the validity of our assessment of environmental and other liabilities, including legacy liabilities;
|
•
|
the costs associated with additional debt or equity capital, which may result in a significant increase in our interest expense and financial leverage resulting from any additional debt incurred to finance such acquisitions, or the issuance of additional common units or preferred units on which we will make distributions, either of which could offset the expected accretion to our unitholders from such acquisition and could be exacerbated by volatility in the equity or debt capital markets;
|
•
|
a failure to realize anticipated benefits, such as increased available cash per unit, enhanced competitive position or new customer relationships;
|
•
|
a decrease in our liquidity by using a significant portion of our available cash or borrowing capacity to finance the acquisition;
|
•
|
the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges; and
|
•
|
the risk that our existing financial controls, information systems, management resources and human resources will need to grow to support future growth and we may not be able to react timely.
|
•
|
operating a significantly larger combined organization and integrating additional operations into ours;
|
•
|
difficulties in the assimilation of the assets and operations of the acquired businesses, especially if the assets acquired are in a new business segment or geographical area;
|
•
|
the loss of customers or key employees from the acquired businesses;
|
•
|
the diversion of management’s attention from other existing business concerns;
|
•
|
the failure to realize expected synergies and cost savings;
|
•
|
coordinating geographically disparate organizations, systems and facilities;
|
•
|
integrating personnel from diverse business backgrounds and organizational cultures; and
|
•
|
consolidating corporate and administrative functions.
|
•
|
damage to pipelines, plants, storage facilities, barges, related equipment and surrounding properties caused by floods, hurricanes and other natural disasters and acts of terrorism;
|
•
|
inadvertent damage from vehicles and construction and farm equipment;
|
•
|
leakage of crude oil, natural gas, NGLs, refined products and other hydrocarbons into the environment, including groundwater;
|
•
|
fires and explosions; and
|
•
|
other hazards and conditions, including those associated with various hazardous pollutant emissions, high-sulfur content, or sour gas, and proximity to businesses, homes, or other populated areas, that could also result in personal injury and loss of life, pollution and suspension of operations.
|
•
|
perform ongoing assessments of pipeline integrity;
|
•
|
identify and characterize applicable threats to pipeline segments that could impact a high consequence area;
|
•
|
improve data collection, integration and analysis;
|
•
|
repair and remediate the pipeline as necessary; and
|
•
|
implement preventive and mitigating actions.
|
•
|
unscheduled turnarounds or catastrophic events, including damages to pipelines and facilities, related equipment and surrounding properties caused by earthquakes, tornadoes, hurricanes, floods, fires, severe weather, explosions and other natural disasters;
|
•
|
restrictions imposed by governmental authorities or court proceedings;
|
•
|
labor difficulties that result in a work stoppage or slowdown;
|
•
|
a disruption in the supply of natural gas, NGLs, crude oil or refined products to our pipelines, barges, processing and fractionation plants and associated facilities;
|
•
|
disruption in our supply of power, water and other resources necessary to operate our facilities;
|
•
|
a marine accident or spill event could close a portion of the inland waterway system;
|
•
|
damage to our facilities resulting from gas, crude oil, NGLs or refined products that do not comply with applicable specifications; and
|
•
|
inadequate fractionation, transportation or storage capacity or market access to support production volumes, including lack of availability of rail cars, barges, trucks and pipeline capacity, or market constraints, including reduced demand or limited markets for certain NGL products.
|
•
|
the timing and extent of changes in commodity prices and demand for MPC’s products, and the availability and costs of crude oil and other refinery feedstocks;
|
•
|
a material decrease in the refining margins at MPC’s refineries;
|
•
|
the risk of contract cancellation, non-renewal or failure to perform by MPC’s customers, and MPC’s inability to replace such contracts and/or customers;
|
•
|
disruptions due to equipment interruption or failure at MPC’s facilities or at third-party facilities on which MPC’s business is dependent;
|
•
|
any decision by MPC to temporarily or permanently alter, curtail or shut down operations at one or more of its refineries or other facilities and reduce or terminate its obligations under our transportation and storage services agreements;
|
•
|
changes to the routing of volumes shipped by MPC on our crude oil and product pipeline systems or the ability of MPC to utilize third-party pipeline connections to access our pipeline systems;
|
•
|
MPC’s ability to remain in compliance with the terms of its outstanding indebtedness;
|
•
|
changes in the cost or availability of third-party pipelines, terminals and other means of delivering and transporting crude oil, feedstocks, refined products and other hydrocarbon-based products;
|
•
|
state and federal environmental, economic, health and safety, energy and other policies and regulations, and any changes in those policies and regulations;
|
•
|
environmental incidents and violations and related remediation costs, fines and other liabilities;
|
•
|
operational hazards and other incidents at MPC’s refineries and other facilities, such as explosions and fires, that result in temporary or permanent shut downs of those refineries and facilities;
|
•
|
changes in crude oil and product inventory levels and carrying costs; and
|
•
|
disruptions due to hurricanes, tornadoes or other forces of nature.
|
•
|
neither our partnership agreement nor any other agreement requires MPC to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by MPC to increase or decrease refinery production, shut down or reconfigure a refinery, or pursue and grow particular markets. MPC’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of MPC;
|
•
|
MPC, as a significant customer, has an economic incentive to cause us to not seek higher tariff rates, even if such higher rates or fees would reflect rates and fees that could be obtained in arm’s-length, third-party transactions;
|
•
|
MPC may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;
|
•
|
our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner’s liabilities and restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;
|
•
|
except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
|
•
|
our general partner will determine the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;
|
•
|
our general partner will determine the amount and timing of many of our cash expenditures and whether a cash expenditure is classified as an expansion capital expenditure, which would not reduce operating surplus, or a maintenance capital expenditure, which would reduce our operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the amount of adjusted operating surplus generated in any given period;
|
•
|
our general partner will determine which costs incurred by it are reimbursable by us and may cause us to pay it or its affiliates for any services rendered to us;
|
•
|
our general partner may cause us to borrow funds in order to permit the payment of distributions, even if the borrowing is to allow us to pay the general partner’s incentive distribution rights;
|
•
|
our partnership agreement permits us to classify up to $60 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of the general partner interest or the incentive distribution rights;
|
•
|
our partnership agreement does not restrict our general partner from entering into additional contractual arrangements with it or its affiliates on our behalf;
|
•
|
our general partner intends to limit its liability regarding our contractual and other obligations;
|
•
|
our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 85 percent of the common units;
|
•
|
our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including our transportation and storage services agreements with MPC;
|
•
|
our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and
|
•
|
our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner, which we refer to as our conflicts committee, or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.
|
•
|
provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;
|
•
|
provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith;
|
•
|
provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and
|
•
|
provides that our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.
|
•
|
our unitholders’ proportionate ownership interest in us will decrease;
|
•
|
it may be more difficult to maintain or increase our distributions to unitholders, and the amount of cash available for distribution on each unit may decrease;
|
•
|
the ratio of taxable income to distributions may increase;
|
•
|
the relative voting strength of each previously outstanding unit may be diminished; and
|
•
|
the market price of our common units may decline.
|
•
|
we were conducting business in a state but had not complied with that particular state’s partnership statute; or
|
•
|
a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.
|
System name
|
|
Diameter
(inches) |
|
Length
(miles) |
|
Capacity
(mbpd) (1) |
|
Associated MPC refineries
|
||
Patoka to Lima crude system
|
|
|
|
|
|
|
|
|
||
Patoka, IL to Lima, OH
|
|
20”/22”
|
|
304
|
|
|
267
|
|
|
Detroit, MI; Canton, OH
|
Catlettsburg and Robinson crude system
|
|
|
|
|
|
|
|
|
||
Patoka, IL to Robinson, IL
|
|
20”
|
|
78
|
|
|
245
|
|
|
Robinson, IL
|
Patoka, IL to Catlettsburg, KY
|
|
24”/20”
|
|
406
|
|
|
270
|
|
|
Catlettsburg, KY
|
Subtotal
|
|
|
|
484
|
|
|
515
|
|
|
|
Detroit crude system
|
|
|
|
|
|
|
|
|
||
Samaria, MI to Detroit, MI
|
|
16”
|
|
44
|
|
|
117
|
|
|
Detroit, MI
|
Romulus, MI to Detroit, MI
(2)
|
|
16”
|
|
17
|
|
|
80
|
|
|
Detroit, MI
|
Subtotal
|
|
|
|
61
|
|
|
197
|
|
|
|
Wood River to Patoka crude system
|
|
|
|
|
|
|
|
|
||
Wood River, IL to Patoka, IL
|
|
22”
|
|
57
|
|
|
215
|
|
|
All Midwest refineries
|
Roxanna, IL to Patoka, IL
(3)
|
|
12”
|
|
58
|
|
|
99
|
|
|
All Midwest refineries
|
Subtotal
|
|
|
|
115
|
|
|
314
|
|
|
|
Inactive pipelines
|
|
|
|
44
|
|
|
N/A
|
|
|
|
Total crude oil pipelines
|
|
|
|
1,008
|
|
|
1,293
|
|
|
|
(1)
|
Capacity shown is
100 percent
of the capacity of these pipeline systems and based on physical barrels.
|
(2)
|
Includes approximately
16 miles
of pipeline leased from a third party.
|
(3)
|
This pipeline is leased from a third party.
|
System name
|
|
Diameter
(inches) |
|
Length
(miles) |
|
Capacity
(mbpd)
(1)
|
|
Associated MPC refineries
|
||
Cornerstone products system
|
||||||||||
Cornerstone to East Sparta, OH
|
|
16"
|
|
50
|
|
|
198
|
|
|
Canton, OH
|
East Sparta, OH to Canton, OH
|
|
8"
|
|
8
|
|
|
40
|
|
|
Canton, OH
|
Subtotal
|
|
|
|
58
|
|
|
238
|
|
|
|
Garyville products system
|
||||||||||
Garyville, LA to Zachary, LA
|
|
20”
|
|
70
|
|
|
389
|
|
|
Garyville, LA
|
Zachary, LA to connecting pipelines
(2)
|
|
36”
|
|
2
|
|
|
—
|
|
|
Garyville, LA
|
Subtotal
|
|
|
|
72
|
|
|
389
|
|
|
|
Texas City products system
|
||||||||||
Texas City, TX to Pasadena, TX
|
|
16”
|
|
39
|
|
|
215
|
|
|
Texas City, TX; Galveston Bay, TX
|
Pasadena, TX to connecting pipelines
(2)
|
|
36”/30”
|
|
3
|
|
|
—
|
|
|
Texas City, TX; Galveston Bay, TX
|
Subtotal
|
|
|
|
42
|
|
|
215
|
|
|
|
ORPL products system
|
||||||||||
Kenova, WV to Columbus, OH
|
|
14”
|
|
150
|
|
|
68
|
|
|
Catlettsburg, KY
|
Canton, OH to East Sparta, OH
(3,4)
|
|
6”
|
|
17
|
|
|
73
|
|
|
Canton, OH
|
East Sparta, OH to Heath, OH
(4)
|
|
8”
|
|
81
|
|
|
29
|
|
|
Canton, OH
|
East Sparta, OH to Midland, PA
(4)
|
|
8”
|
|
62
|
|
|
32
|
|
|
Canton, OH
|
Heath, OH to Dayton, OH
|
|
6”
|
|
108
|
|
|
24
|
|
|
Catlettsburg, KY; Canton, OH
|
Heath, OH to Findlay, OH
|
|
10”/8”
|
|
100
|
|
|
18
|
|
|
Catlettsburg, KY; Canton, OH
|
Subtotal
|
|
|
|
518
|
|
|
244
|
|
|
|
Robinson products system
|
||||||||||
Robinson, IL to Lima, OH
|
|
10”
|
|
250
|
|
|
51
|
|
|
Robinson, IL
|
Robinson, IL to Louisville, KY
(5)
|
|
16”
|
|
129
|
|
|
82
|
|
|
Robinson, IL
|
Robinson, IL to Mt. Vernon, IN
(6)
|
|
10”
|
|
79
|
|
|
77
|
|
|
Robinson, IL
|
Wood River, IL to Clermont, IN
|
|
10”
|
|
317
|
|
|
48
|
|
|
Robinson, IL
|
Wabash Pipeline System:
|
|
|
|
|
|
|
|
|
||
West leg—Wood River, IL to Champaign, IL
|
|
12”
|
|
130
|
|
|
71
|
|
|
Robinson, IL
|
East leg—Robinson, IL to Champaign, IL
|
|
12”
|
|
86
|
|
|
99
|
|
|
Robinson, IL
|
Champaign, IL to Hammond, IN
(7)
|
|
16”/12”
|
|
140
|
|
|
85
|
|
|
Robinson, IL
|
Subtotal
|
|
|
|
1,131
|
|
|
513
|
|
|
|
Louisville airport products system
|
||||||||||
Louisville, KY to Louisville International Airport
|
|
8”/6”
|
|
14
|
|
|
29
|
|
|
Robinson, IL
|
Inactive pipelines
(8)
|
|
123
|
|
|
N/A
|
|
|
|
||
Total product pipelines
|
|
|
|
1,958
|
|
|
1,628
|
|
|
|
(1)
|
Capacity shown is
100 percent
of the capacity of these pipeline systems.
|
(2)
|
Capacity not shown, as the pipeline is designed to meet outgoing capacity for connecting third-party pipelines.
|
(3)
|
Consists of two separate approximately
8.5
-mile pipelines.
|
(4)
|
This pipeline is bi-directional.
|
(5)
|
Drag-reducing agent for this pipeline is currently not active and can be reactivated at any time resulting in a capacity increase of 10 mbpd.
|
(6)
|
This pipeline is leased from a third party.
|
(7)
|
Capacity not shown for
16
miles on this system due to complexities associated with bi-directional capability.
|
(8)
|
Includes
77
miles of pipeline leased from a third party.
|
Asset name
|
|
Quantity
|
|
Associated MPC refineries
|
Barges
|
|
204
|
|
Catlettsburg, KY; Garyville, LA
|
Towboats
|
|
18
|
|
Catlettsburg, KY; Garyville, LA
|
Marine Repair Facility
|
|
N/A
|
|
Catlettsburg, KY
|
Asset name
|
|
Capacity
(1)
|
|
Associated MPC refineries
|
Wood River Barge Dock
|
|
78 mbpd
|
|
Garyville, LA
|
Neal Butane Cavern
|
|
1,000 mbbls
|
|
Catlettsburg, KY
|
Patoka Tank Farm
|
|
2,626 mbbls
|
|
All Midwest refineries
|
Wood River Tank Farm
|
|
419 mbbls
|
|
All Midwest refineries
|
Martinsville Tank Farm
|
|
738 mbbls
|
|
Detroit, MI; Canton, OH
|
Lebanon Tank Farm
|
|
750 mbbls
|
|
Detroit, MI; Canton, OH
|
Hartford Tank Farm
(2)
|
|
430 mbbls
|
|
All Midwest refineries
|
(1)
|
All capacity shown is for
100 percent
of the available storage capacity of our butane cavern and tank farms and
100 percent
of the barge dock’s average capacity.
|
(2)
|
MPLX LP leases the Hartford Tank Farm from Wood River Pipe Lines LLC and Buckeye Terminals, LLC.
|
Plant
|
|
Location
|
|
Design Throughput Capacity (mmcf/d)
|
|
Natural Gas Throughput
(1)
(mmcf/d) |
|
Utilization of Design Capacity
(1)
|
|||
Marcellus Shale:
|
|
|
|
|
|
|
|
|
|||
Keystone Complex
|
|
Butler County, PA
|
|
410
|
|
|
265
|
|
|
65
|
%
|
Houston Complex
(5)
|
|
Washington County, PA
|
|
555
|
|
|
446
|
|
|
80
|
%
|
Majorsville Complex
|
|
Marshall County, WV
|
|
1,070
|
|
|
789
|
|
|
74
|
%
|
Mobley Complex
|
|
Wetzel County, WV
|
|
920
|
|
|
690
|
|
|
80
|
%
|
Sherwood Complex
|
|
Doddridge County, WV
|
|
1,200
|
|
|
1,020
|
|
|
85
|
%
|
Total Marcellus Shale
|
|
|
|
4,155
|
|
|
3,210
|
|
|
78
|
%
|
Utica Shale:
|
|
|
|
|
|
|
|
|
|||
Cadiz Complex
|
|
Harrison County, OH
|
|
525
|
|
|
477
|
|
|
91
|
%
|
Seneca Complex
|
|
Noble County, OH
|
|
800
|
|
|
595
|
|
|
74
|
%
|
Total Utica Shale
|
|
|
|
1,325
|
|
|
1,072
|
|
|
81
|
%
|
Southern Appalachia:
|
|
|
|
|
|
|
|
|
|||
Kenova Complex
(2)
|
|
Wayne County, WV
|
|
160
|
|
|
102
|
|
|
64
|
%
|
Boldman Complex
(2)
|
|
Pike County, KY
|
|
70
|
|
|
30
|
|
|
43
|
%
|
Cobb Complex
|
|
Kanawha County, WV
|
|
65
|
|
|
22
|
|
|
34
|
%
|
Kermit Complex
(2)(3)
|
|
Mingo County, WV
|
|
32
|
|
|
N/A
|
|
|
N/A
|
|
Langley Complex
|
|
Langley, KY
|
|
325
|
|
|
99
|
|
|
30
|
%
|
Total Southern Appalachia
(3)
|
|
|
|
620
|
|
|
253
|
|
|
41
|
%
|
Southwest:
|
|
|
|
|
|
|
|
|
|||
Carthage Complex
|
|
Panola County, TX
|
|
600
|
|
|
493
|
|
|
82
|
%
|
Western Oklahoma Complex
|
|
Custer and Beckham Counties, OK
|
|
425
|
|
|
333
|
|
|
78
|
%
|
Hidalgo Complex
|
|
Culberson County, TX
|
|
200
|
|
|
105
|
|
|
81
|
%
|
Javelina Complex
|
|
Corpus Christi, TX
|
|
142
|
|
|
99
|
|
|
70
|
%
|
Total Southwest
(4)
|
|
|
|
1,367
|
|
|
1,030
|
|
|
79
|
%
|
Total Gas Processing
|
|
|
|
7,467
|
|
|
5,565
|
|
|
76
|
%
|
(1)
|
Natural gas throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.
|
(2)
|
A portion of the gas processed at the Boldman plant, and all of the gas processed at the Kermit plant, is further processed at the Kenova plant to recover additional NGLs.
|
(3)
|
The Kermit processing plant is operated by a third party solely to prevent liquids from condensing in the gathering and transmission pipelines upstream of our Kenova plant. We do not receive Kermit gas volume information but do receive all of the liquids produced at the Kermit Complex. As such, the design capacity has been excluded from the subtotal.
|
(4)
|
Centrahoma processing capacity of
300
mmcf/d and actual throughput of
196
mmcf/d, that exceeded our capacity of 120 mmcf/d, are not included in this table as we own a non-operating interest.
|
(5)
|
Approximately 35 mmcf/d of processing capacity at the Houston Complex will be decommissioned during the first quarter of 2017 and replaced with 200 mmcf/d of processing capacity.
|
Facility
|
|
Location
|
|
Design Throughput Capacity
(mbpd) |
|
NGL Throughput
(mbpd) |
|
Utilization
of Design Capacity |
|||
Marcellus Shale:
|
|
|
|
|
|
|
|
|
|||
Keystone Complex
(1)(2)
|
|
Butler County, PA
|
|
47
|
|
|
14
|
|
|
30
|
%
|
Houston Complex
(1)
|
|
Washington County, PA
|
|
60
|
|
|
60
|
|
|
100
|
%
|
Total Marcellus Shale
|
|
|
|
107
|
|
|
74
|
|
|
69
|
%
|
Hopedale Complex
(1)(3)
|
|
Harrison County, OH
|
|
120
|
|
|
110
|
|
|
92
|
%
|
Utica Shale:
|
|
|
|
|
|
|
|
|
|||
Ohio Condensate Complex
(4)
|
|
Harrison County, OH
|
|
23
|
|
|
14
|
|
|
61
|
%
|
Total Utica Shale
|
|
|
|
23
|
|
|
14
|
|
|
61
|
%
|
Southern Appalachia:
|
|
|
|
|
|
|
|
|
|||
Siloam Complex
(5)
|
|
South Shore, KY
|
|
24
|
|
|
15
|
|
|
63
|
%
|
Total Southern Appalachia
|
|
|
|
24
|
|
|
15
|
|
|
63
|
%
|
Southwest:
|
|
|
|
|
|
|
|
|
|||
Javelina Complex
|
|
Corpus Christi, TX
|
|
11
|
|
|
7
|
|
|
64
|
%
|
Total Southwest
|
|
|
|
11
|
|
|
7
|
|
|
64
|
%
|
Total C3+ Fractionation and Condensate Stabilization
|
|
|
|
285
|
|
|
220
|
|
|
77
|
%
|
(1)
|
Our Houston, Hopedale and Keystone Complexes have above-ground NGL storage with a usable capacity of
28 million
gallons, large-scale truck and rail loading. In addition, our Houston Complex has large-scale truck unloading. We also have access to up to an additional
50 million
gallons of propane storage capacity that can be utilized by our assets in the Marcellus Shale, Utica Shale, and Appalachia region under an agreement with a third party that expires in 2018. Lastly, we have up to
9 million
gallons of butane storage and
8 million
gallons of propane storage with third parties that can be utilized by our assets in the Marcellus Shale and Utica Shale.
|
(2)
|
Includes
33
mbpd of de-propanization only capacity.
|
(3)
|
Our Hopedale Complex is jointly owned by Ohio Fractionation and MarkWest Utica EMG. Ohio Fractionation is a subsidiary of MarkWest Liberty Midstream. MarkWest Liberty Midstream and MarkWest Utica EMG are entities that operate in the Marcellus and Utica regions, respectively. We account for MarkWest Utica EMG as an equity method investment. See discussion in Item 8. Financial Statements and Supplementary Data – Note
5
.
|
(4)
|
The Ohio Condensate Complex has up to
7 million
gallons of condensate storage. The Ohio Condensate Complex is partially-owned by MarkWest Utica EMG Condensate, L.L.C. We account for Ohio Condensate as an equity method investment. See discussion in Item 8. Financial Statements and Supplementary Data – Note
5
.
|
(5)
|
Our Siloam Complex has both above-ground, pressurized NGL storage facilities, with usable capacity of
two million
gallons, and underground storage facilities, with usable capacity of
10 million
gallons. Product can be received by truck, pipeline or rail and can be transported from the facility by truck, rail or barge. This facility has large-scale truck and rail loading and unloading capabilities, and a river barge facility capable of loading barges up to
860,000
gallons.
|
Facility
|
|
Location
|
|
Design Throughput Capacity
(mbpd) |
|
NGL Throughput
(1)
(mbpd) |
|
Utilization
of Design Capacity (1) |
|||
Marcellus Shale:
|
|
|
|
|
|
|
|
|
|||
Keystone Complex
|
|
Butler County, PA
|
|
14
|
|
|
11
|
|
|
79
|
%
|
Houston Complex
|
|
Washington County, PA
|
|
40
|
|
|
37
|
|
|
93
|
%
|
Majorsville Complex
|
|
Marshall County, WV
|
|
40
|
|
|
42
|
|
|
105
|
%
|
Mobley Complex
|
|
Wetzel County, WV
|
|
10
|
|
|
6
|
|
|
82
|
%
|
Sherwood Complex
|
|
Doddridge County, WV
|
|
40
|
|
|
18
|
|
|
45
|
%
|
Total Marcellus Shale
|
|
|
|
144
|
|
|
114
|
|
|
80
|
%
|
Utica Shale:
|
|
|
|
|
|
|
|
|
|||
Cadiz Complex
|
|
Harrison County, OH
|
|
40
|
|
|
4
|
|
|
10
|
%
|
Total Utica Shale
|
|
|
|
40
|
|
|
4
|
|
|
10
|
%
|
Southwest:
|
|
|
|
|
|
|
|
|
|||
Javelina Complex
|
|
Corpus Christi, TX
|
|
18
|
|
|
11
|
|
|
61
|
%
|
Total Southwest
|
|
|
|
18
|
|
|
11
|
|
|
61
|
%
|
Total De-ethanization
|
|
|
|
202
|
|
|
129
|
|
|
64
|
%
|
(1)
|
NGL throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.
|
System
|
|
Location
|
|
Design Throughput Capacity
(mmcf/d) |
|
Natural Gas Throughput
(1)
(mmcf/d) |
|
Utilization of Design Capacity
(1)
|
|||
Marcellus Shale:
|
|
|
|
|
|
|
|
|
|||
Keystone System
|
|
Butler County, PA
|
|
227
|
|
|
194
|
|
|
85
|
%
|
Houston System
|
|
Washington County, PA
|
|
984
|
|
|
716
|
|
|
74
|
%
|
Total Marcellus Shale
|
|
|
|
1,211
|
|
|
910
|
|
|
77
|
%
|
Utica Shale:
|
|
|
|
|
|
|
|
|
|||
Ohio Gathering System
(2)
|
|
Harrison, Monroe, Belmont, Guernsey and Noble Counties, OH
|
|
1,393
|
|
|
867
|
|
|
63
|
%
|
Jefferson Gas System
(3)
|
|
Jefferson County, OH
|
|
250
|
|
|
65
|
|
|
26
|
%
|
Total Utica Shale
|
|
|
|
1,643
|
|
|
932
|
|
|
58
|
%
|
Southwest
|
|
|
|
|
|
|
|
|
|||
East Texas System
|
|
Harrison and Panola Counties, TX
|
|
680
|
|
|
578
|
|
|
85
|
%
|
Western Oklahoma System
|
|
Wheeler County, TX and Roger Mills, Ellis, Custer, Beckham and Washita Counties, OK
|
|
585
|
|
|
364
|
|
|
62
|
%
|
Southeast Oklahoma System
|
|
Hughes, Pittsburg and Coal Counties, OK
|
|
1,205
|
|
|
449
|
|
|
37
|
%
|
Eagle Ford System
|
|
Dimmit County, TX
|
|
45
|
|
|
31
|
|
|
69
|
%
|
Other Systems
(4)
|
|
Various
|
|
70
|
|
|
11
|
|
|
16
|
%
|
Total Southwest
|
|
|
|
2,585
|
|
|
1,433
|
|
|
55
|
%
|
Total Natural Gas Gathering
|
|
|
|
5,439
|
|
|
3,275
|
|
|
61
|
%
|
(1)
|
Natural gas throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.
|
(2)
|
The Ohio Gathering System is owned by Ohio Gathering. We account for Ohio Gathering as an equity method investment. See discussion in Item 8. Financial Statements and Supplementary Data – Note
5
.
|
(3)
|
The Jefferson Gas System is owned by Jefferson Dry Gas, which is a consolidated joint venture between MarkWest Liberty Midstream and EMG MWE Dry Gas Holdings, LLC. We account for Jefferson Dry Gas as an equity method investment.
|
(4)
|
Excludes lateral pipelines where revenue is not based on throughput.
|
Pipeline
|
|
Location
|
|
Design Throughput Capacity (mbpd)
|
|
NGL Throughput (mbpd)
|
|
Utilization of Design Capacity
|
|||
Marcellus Shale:
|
|
|
|
|
|
|
|
|
|||
Sherwood to Mobley propane and heavier liquids pipeline
|
|
Doddridge County, WV to Wetzel County, WV
|
|
45
|
|
|
40
|
|
|
89
|
%
|
Mobley to Majorsville propane and heavier liquids pipeline
|
|
Wetzel County, WV to Marshall County, WV
|
|
80
|
|
|
64
|
|
|
80
|
%
|
Majorsville to Houston propane and heavier liquids pipeline
|
|
Marshall County, WV to Washington County, PA
|
|
47
|
|
|
34
|
|
|
72
|
%
|
Majorsville to Hopedale propane and heavier liquids pipeline
|
|
Marshall County, WV to Harrison County, OH
|
|
90
|
|
|
72
|
|
|
80
|
%
|
Third-party processing plant to Keystone ethane and heavier liquids pipeline
|
|
Butler County, PA
|
|
32
|
|
|
7
|
|
|
22
|
%
|
Keystone to Mariner West ethane pipeline
(1)
|
|
Butler County, PA to Beaver County, PA
|
|
35
|
|
|
12
|
|
|
34
|
%
|
Houston to Ohio River ethane pipeline
(2)
|
|
Washington County, PA to Beaver County, PA
|
|
57
|
|
|
16
|
|
|
28
|
%
|
Majorsville to Houston ethane pipeline
(1)
|
|
Marshall County, WV to Washington County, PA
|
|
60
|
|
|
66
|
|
|
110
|
%
|
Sherwood to Mobley ethane pipeline
|
|
Doddridge County, WV to Wetzel County, WV
|
|
27
|
|
|
18
|
|
|
67
|
%
|
Mobley to Fort Beeler ethane pipeline
|
|
Wetzel County, WV to Marshall County, WV
|
|
64
|
|
|
24
|
|
|
38
|
%
|
Fort Beeler to Majorsville ethane pipeline
|
|
Marshall County, WV
|
|
45
|
|
|
24
|
|
|
53
|
%
|
Utica Shale:
|
|
|
|
|
|
|
|
|
|||
Seneca to Cadiz liquids pipeline
|
|
Noble County, OH to Harrison County, OH
|
|
90
|
|
|
20
|
|
|
22
|
%
|
Cadiz to Hopedale liquids pipeline
|
|
Harrison County, OH
|
|
90
|
|
|
38
|
|
|
42
|
%
|
Appalachia:
|
|
|
|
|
|
|
|
|
|||
Langley to Siloam liquids pipeline
(3)
|
|
Langley, KY to South Shore, KY
|
|
17
|
|
|
12
|
|
|
71
|
%
|
Southwest:
|
|
|
|
|
|
|
|
|
|||
East Texas liquids pipeline
|
|
Panola County, TX
|
|
39
|
|
|
27
|
|
|
69
|
%
|
(1)
|
This pipeline is FERC-regulated.
|
(2)
|
This is a section of the Mariner West pipeline, which is FERC-regulated and is leased to and operated by Sunoco.
|
(3)
|
NGLs transported through the Langley to Ranger and Ranger to Kenova pipelines are combined with NGLs recovered at the Kenova Complex. The design capacity and volume reported for the Langley to Siloam pipeline represent the combined NGL stream.
|
(1)
|
Represents cash distributions attributable to the quarter and declared and paid in accordance with our partnership agreement.
|
•
|
less the amount of cash reserves established by our general partner to:
|
•
|
provide for the proper conduct of our business (including reserves for our future capital expenditures, anticipated future debt service requirements and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law subsequent to that quarter);
|
•
|
comply with applicable law, any of our debt instruments or other agreements; or
|
•
|
provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);
|
•
|
plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.
|
|
|
|
|
Marginal percentage interest
in distributions
|
||||||
|
|
Total quarterly distribution
per unit target amount
|
|
Unitholders
(1)
|
|
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
|
%
|
(1)
|
The unitholders’ percentage of distributions is paid to common unitholders and subordinated unitholders, if any.
|
(In millions, except per unit data)
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
||||||||||
Consolidated Statements of Income Data
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Total revenues and other income
|
|
$
|
2,590
|
|
|
$
|
961
|
|
|
$
|
793
|
|
|
$
|
713
|
|
|
$
|
686
|
|
Income from operations
|
|
507
|
|
|
298
|
|
|
245
|
|
|
213
|
|
|
204
|
|
|||||
Net income
|
|
258
|
|
|
249
|
|
|
239
|
|
|
211
|
|
|
204
|
|
|||||
Net income attributable to MPLX LP
|
|
233
|
|
|
156
|
|
|
121
|
|
|
78
|
|
|
13
|
|
|||||
Limited partners’ interest in net income attributable to MPLX LP
|
|
1
|
|
|
99
|
|
|
115
|
|
|
76
|
|
|
13
|
|
|||||
Per Unit Data
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net income attributable to MPLX LP per limited partner unit (basic and diluted):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Common - basic
|
|
$
|
—
|
|
|
$
|
1.23
|
|
|
$
|
1.55
|
|
|
$
|
1.05
|
|
|
$
|
0.18
|
|
Common - diluted
|
|
—
|
|
|
1.22
|
|
|
1.55
|
|
|
1.05
|
|
|
0.18
|
|
|||||
Subordinated - basic and diluted
|
|
—
|
|
|
0.11
|
|
|
1.50
|
|
|
1.01
|
|
|
0.17
|
|
|||||
Cash distributions declared per limited partner common unit
|
|
$
|
2.0500
|
|
|
$
|
1.8200
|
|
|
$
|
1.4100
|
|
|
$
|
1.1675
|
|
|
$
|
0.1769
|
|
Consolidated Balance Sheets Data (at period end)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Property, plant and equipment, net
|
|
$
|
10,730
|
|
|
$
|
9,997
|
|
|
$
|
1,324
|
|
|
$
|
1,248
|
|
|
$
|
1,167
|
|
Total assets
|
|
16,646
|
|
|
16,104
|
|
|
1,544
|
|
|
1,504
|
|
|
1,572
|
|
|||||
Long-term debt, including capital leases
(3)
|
|
4,422
|
|
|
5,255
|
|
|
644
|
|
|
10
|
|
|
10
|
|
|||||
Redeemable preferred units
|
|
1,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
Consolidated Statements of Cash Flows Data
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Net cash provided by (used in):
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating activities
|
|
$
|
1,288
|
|
|
$
|
340
|
|
|
$
|
334
|
|
|
$
|
297
|
|
|
$
|
273
|
|
Investing activities
|
|
(1,212
|
)
|
|
(1,599
|
)
|
|
(137
|
)
|
|
(158
|
)
|
|
64
|
|
|||||
Financing activities
|
|
115
|
|
|
1,275
|
|
|
(224
|
)
|
|
(302
|
)
|
|
(120
|
)
|
|||||
Additions to property, plant and equipment
(1)
|
|
1,206
|
|
|
288
|
|
|
141
|
|
|
151
|
|
|
159
|
|
|||||
Other Financial Data
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Adjusted EBITDA attributable to MPLX LP
(2)
|
|
$
|
1,419
|
|
|
$
|
498
|
|
|
$
|
166
|
|
|
$
|
111
|
|
|
$
|
18
|
|
DCF
(2)
|
|
1,140
|
|
|
399
|
|
|
137
|
|
|
114
|
|
|
17
|
|
(1)
|
Represents cash capital expenditures as reflected on Consolidated Statements of Cash Flows for the periods indicated, which are included in cash used in investing activities.
|
(2)
|
The 2012 Adjusted EBITDA attributable to MPLX LP is subsequent to the Initial Offering. The 2015 Adjusted EBITDA attributable to MPLX LP includes pre-merger EBITDA from MarkWest and the 2015 DCF includes undistributed DCF from MarkWest. For a discussion of the non-GAAP financial measures of Adjusted EBITDA and DCF and a reconciliation of Adjusted EBITDA and DCF to our most directly comparable measures calculated and presented in accordance with GAAP, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Information and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations.
|
(3)
|
Includes amounts due within one year. During 2015, in connection with the MarkWest Merger, MPLX LP assumed MarkWest senior notes with an aggregate principal amount of $4.1 billion and used its credit facility to repay $850 million of the $943 million of borrowings under MarkWest’s credit facility.
|
|
|
2016
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|||||||
L&S
|
|
|
|
|
|
|
|
|
|
|
|||||||
Crude oil transported for (mbpd)
(1)
:
|
|
|
|
|
|
|
|
|
|
|
|||||||
MPC
|
|
906
|
|
|
864
|
|
|
838
|
|
|
853
|
|
|
830
|
|
||
Third parties
|
|
182
|
|
|
197
|
|
|
203
|
|
|
222
|
|
|
202
|
|
||
Total
|
|
1,088
|
|
|
1,061
|
|
|
1,041
|
|
|
1,075
|
|
|
1,032
|
|
||
% MPC
|
|
83
|
%
|
|
81
|
%
|
|
80
|
%
|
|
79
|
%
|
|
80
|
%
|
||
|
|
|
|
|
|
|
|
|
|
|
|||||||
Products transported for (mbpd)
(2)
:
|
|
|
|
|
|
|
|
|
|
|
|||||||
MPC
(3)
|
|
763
|
|
|
887
|
|
|
852
|
|
|
862
|
|
|
909
|
|
||
Third parties
|
|
145
|
|
|
27
|
|
|
26
|
|
|
49
|
|
|
71
|
|
||
Total
|
|
908
|
|
|
914
|
|
|
878
|
|
|
911
|
|
|
980
|
|
||
% MPC
|
|
84
|
%
|
|
97
|
%
|
|
97
|
%
|
|
95
|
%
|
|
93
|
%
|
||
|
|
|
|
|
|
|
|
|
|
|
|||||||
Average tariff rates ($ per barrel):
|
|
|
|
|
|
|
|
|
|
|
|||||||
Crude oil pipelines
|
|
0.67
|
|
|
0.66
|
|
|
0.64
|
|
|
0.60
|
|
|
0.57
|
|
||
Product pipelines
|
|
0.69
|
|
|
0.65
|
|
|
0.61
|
|
|
0.56
|
|
|
0.51
|
|
||
Total pipelines
|
|
0.68
|
|
|
0.65
|
|
|
0.63
|
|
|
0.58
|
|
|
0.54
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|||||||
Barges
(4)
|
|
204
|
|
|
205
|
|
|
199
|
|
|
184
|
|
|
177
|
|
||
Towboats
(4)
|
|
18
|
|
|
18
|
|
|
18
|
|
|
17
|
|
|
15
|
|
||
|
|
|
|
|
|
|
|
|
|
|
|||||||
G&P
(5)
|
|
|
|
|
|
|
|
|
|
|
|||||||
Gathering Throughput (mmcf/d)
|
|
|
|
|
|
|
|
|
|
|
|||||||
Marcellus Operations
|
|
910
|
|
|
889
|
|
|
|
|
|
|
|
|||||
Utica Operations
(6)(7)
|
|
932
|
|
|
745
|
|
|
|
|
|
|
|
|||||
Southwest Operations
(8)
|
|
1,433
|
|
|
1,441
|
|
|
|
|
|
|
|
|||||
Total gathering throughput
|
|
3,275
|
|
|
3,075
|
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|||||||
Natural Gas Processed (mmcf/d)
|
|
|
|
|
|
|
|
|
|
|
|||||||
Marcellus Operations
|
|
3,210
|
|
|
2,964
|
|
|
|
|
|
|
|
|||||
Utica Operations
(6)
|
|
1,072
|
|
|
1,136
|
|
|
|
|
|
|
|
|||||
Southwest Operations
|
|
1,226
|
|
|
1,125
|
|
|
|
|
|
|
|
|||||
Southern Appalachian Operations
|
|
253
|
|
|
243
|
|
|
|
|
|
|
|
|||||
Total natural gas processed
|
|
5,761
|
|
|
5,468
|
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|||||||
C2 + NGLs Fractionated (mbpd)
|
|
|
|
|
|
|
|
|
|
|
|||||||
Marcellus Operations
(9)(10)
|
|
260
|
|
|
220
|
|
|
|
|
|
|
|
|||||
Utica Operations
(6)(10)
|
|
42
|
|
|
51
|
|
|
|
|
|
|
|
|||||
Southwest Operations
|
|
18
|
|
|
24
|
|
|
|
|
|
|
|
|||||
Southern Appalachian Operations
(11)
|
|
15
|
|
|
12
|
|
|
|
|
|
|
|
|||||
Total C2 + NGLs fractionated
(12)
|
|
335
|
|
|
307
|
|
|
|
|
|
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
|||||||
Pricing Information
|
|
|
|
|
|
|
|
|
|
|
|||||||
Natural Gas NYMEX HH ($/MMBtu)
|
|
$
|
2.55
|
|
|
$
|
2.04
|
|
|
|
|
|
|
|
|||
C2 + NGL Pricing/gallon
(13)
|
|
$
|
0.47
|
|
|
$
|
0.40
|
|
|
|
|
|
|
|
(1)
|
Represents the average aggregate daily number of barrels of crude oil transported on our pipeline systems and at our Wood River barge dock for MPC and for third parties. Volumes shown are 100 percent of the volumes transported on the pipeline systems and barge dock. Volumes shown for all periods exclude volumes transported on two undivided joint interest crude oil pipeline systems not contributed to MPLX LP at the Initial Offering.
|
(2)
|
Represents the average aggregate daily number of barrels of products transported on our pipeline systems for MPC and third parties. Volumes shown are 100 percent of the volumes transported on the pipeline systems.
|
(3)
|
Includes volumes shipped by MPC on various pipelines under joint tariffs with third parties. For accounting purposes, revenue attributable to these volumes is classified as third-party revenue because we receive payment from those third parties with respect to volumes shipped under the joint tariffs; however, the volumes associated with this revenue are applied towards MPC’s minimum quarterly volume commitments on the applicable pipelines because MPC is the shipper of record.
|
(4)
|
Represents the number of owned 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 – Supplemental MD&A
– G&P Pro Forma 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
309
mmcf/d and
310
mmcf/d related to unconsolidated equity method investments, Wirth and MarkWest Pioneer for the years ended
December 31, 2016
and
2015
, respectively.
|
(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 Ohio Fractionation and MarkWest Utica EMG. Ohio Fractionation is a subsidiary of MarkWest Liberty Midstream. MarkWest Liberty Midstream and MarkWest Utica EMG are entities that operate in the Marcellus and Utica regions, respectively. The Marcellus Operations includes its portion utilized of the jointly owned Hopedale Fractionation Complex. The Utica Operations includes Utica’s portion utilized of the jointly owned Hopedale Fractionation Complex.
|
(11)
|
Includes NGLs fractionated for the Marcellus and Utica Operations.
|
(12)
|
Purity ethane makes up approximately
128
and
104
mbpd of total fractionated products for the years ended
December 31, 2016
and
2015
, respectively.
|
(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.
|
•
|
L&S segment operating income attributable to MPLX LP increased approximately
$131 million
, or
41 percent
, in
2016
compared to
2015
. This increase was primarily due to the acquisition of the inland marine business on March 31, 2016, which continues the diversification of earnings streams and adds additional fee-based revenues to the Partnership. The L&S segment operating income also increased due to higher average pipeline tariffs. See Item 8. Financial Statements and Supplementary Data – Note
4
for further details of the HSM acquisition.
|
•
|
G&P segment operating income attributable to MPLX LP increased approximately
$1.1 billion
, or
1,389 percent
, in
2016
compared to
2015
, due to the MarkWest Merger. Despite declines in drilling activity by producers, the G&P segment realized volume increases across most of its businesses during
2016
. Compared to full-year 2015, gathering volumes were up 11 percent, processing volumes were up 13 percent and fractionated volumes were up 25 percent.
|
•
|
Net income for the year ended December 31, 2016 was
$258 million
, full-year 2016 DCF, a non-GAAP measure, was over $1.1 billion and full-year 2016 distributions were $2.05 per common unit, which represents a 13 percent increase over the full-year distributions of 2015.
|
•
|
The private placement of approximately
30.8 million
6.5 percent Series A Convertible Preferred units for a cash purchase price of $32.50 per unit during the second quarter of 2016. The aggregate net proceeds of approximately $984 million from the sale of the Preferred units was used for capital expenditures and repayment of debt.
|
•
|
The issuance of an aggregate of
26,347,887
common units under the ATM Program during the year ended
December 31, 2016
, generating net proceeds of approximately
$776 million
. As of
December 31, 2016
,
$717 million
of common units remains available for issuance through the ATM program under the Distribution Agreement.
|
•
|
On October 11, 2016, the Cornerstone Pipeline became fully operational. This is a key organic growth project within our L&S segment designed to transport condensate and natural gasoline from the Marcellus and Utica regions to MPC’s Canton, Ohio, refinery. The Partnership is expanding the capacity of existing pipelines and constructing new pipelines as part of a larger build-out of Utica Shale infrastructure, seizing a unique opportunity to connect natural gas liquids to downstream markets in the Midwest and Canada through our extensive distribution network.
|
•
|
We expanded our presence in the Southwest with the completion of the Hidalgo gas processing complex in the Delaware Basin of Texas, and will evaluate further investments in gathering and processing to support the substantial activity our producer-customers are pursuing in the region.
|
•
|
Planned acquisition of assets from MPC with an estimated $1.4 billion of annual EBITDA, along with our intentions to reduce the Partnership’s cost of capital by offering to exchange MPLX LP units for MPC’s IDRs;
|
•
|
Strategic joint venture with Antero Midstream to support Antero Resources in the Marcellus Shale; and
|
•
|
Public debt offering of $2.25 billion principal amount senior notes.
|
(In millions)
|
|
2016
|
|
2015
|
|
$ Change
|
|
2014
|
|
$ Change
|
||||||||||
Revenues and other income:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Service revenue
|
|
$
|
958
|
|
|
$
|
130
|
|
|
$
|
828
|
|
|
$
|
70
|
|
|
$
|
60
|
|
Service revenue - related parties
|
|
603
|
|
|
593
|
|
|
10
|
|
|
662
|
|
|
(69
|
)
|
|||||
Rental income
|
|
298
|
|
|
20
|
|
|
278
|
|
|
—
|
|
|
20
|
|
|||||
Rental income - related parties
|
|
114
|
|
|
101
|
|
|
13
|
|
|
15
|
|
|
86
|
|
|||||
Product sales
|
|
572
|
|
|
36
|
|
|
536
|
|
|
—
|
|
|
36
|
|
|||||
Product sales - related parties
|
|
11
|
|
|
1
|
|
|
10
|
|
|
—
|
|
|
1
|
|
|||||
Gain on sale of assets
|
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|||||
(Loss) income from equity method investments
|
|
(74
|
)
|
|
3
|
|
|
(77
|
)
|
|
—
|
|
|
3
|
|
|||||
Other income
|
|
6
|
|
|
6
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|||||
Other income - related parties
|
|
101
|
|
|
71
|
|
|
30
|
|
|
40
|
|
|
31
|
|
|||||
Total revenues and other income
|
|
2,590
|
|
|
961
|
|
|
1,629
|
|
|
793
|
|
|
168
|
|
|||||
Costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cost of revenues (excludes items below)
|
|
354
|
|
|
225
|
|
|
129
|
|
|
228
|
|
|
(3
|
)
|
|||||
Purchased product costs
|
|
448
|
|
|
20
|
|
|
428
|
|
|
—
|
|
|
20
|
|
|||||
Rental cost of sales
|
|
53
|
|
|
5
|
|
|
48
|
|
|
1
|
|
|
4
|
|
|||||
Purchases - related parties
|
|
316
|
|
|
166
|
|
|
150
|
|
|
153
|
|
|
13
|
|
|||||
Depreciation and amortization
|
|
546
|
|
|
116
|
|
|
430
|
|
|
75
|
|
|
41
|
|
|||||
Impairment expense
|
|
130
|
|
|
—
|
|
|
130
|
|
|
—
|
|
|
—
|
|
|||||
General and administrative expenses
|
|
193
|
|
|
118
|
|
|
75
|
|
|
81
|
|
|
37
|
|
|||||
Other taxes
|
|
43
|
|
|
13
|
|
|
30
|
|
|
10
|
|
|
3
|
|
|||||
Total costs and expenses
|
|
2,083
|
|
|
663
|
|
|
1,420
|
|
|
548
|
|
|
115
|
|
|||||
Income from operations
|
|
507
|
|
|
298
|
|
|
209
|
|
|
245
|
|
|
53
|
|
|||||
Related party interest and other financial costs
|
|
1
|
|
|
—
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|||||
Interest expense (net of amounts capitalized of $28 million, $5 million, and $1 million, respectively)
|
|
210
|
|
|
35
|
|
|
175
|
|
|
4
|
|
|
31
|
|
|||||
Other financial costs
|
|
50
|
|
|
13
|
|
|
37
|
|
|
1
|
|
|
12
|
|
|||||
Income before income taxes
|
|
246
|
|
|
250
|
|
|
(4
|
)
|
|
240
|
|
|
10
|
|
|||||
(Benefit) provision for income taxes
|
|
(12
|
)
|
|
1
|
|
|
(13
|
)
|
|
1
|
|
|
—
|
|
|||||
Net income
|
|
258
|
|
|
249
|
|
|
9
|
|
|
239
|
|
|
10
|
|
|||||
Less: Net income attributable to noncontrolling interests
|
|
2
|
|
|
1
|
|
|
1
|
|
|
57
|
|
|
(56
|
)
|
|||||
Less: Net income attributable to Predecessor
|
|
23
|
|
|
92
|
|
|
(69
|
)
|
|
61
|
|
|
31
|
|
|||||
Net income attributable to MPLX LP
|
|
$
|
233
|
|
|
$
|
156
|
|
|
$
|
77
|
|
|
$
|
121
|
|
|
$
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Adjusted EBITDA attributable to MPLX LP
(1)
|
|
$
|
1,419
|
|
|
$
|
498
|
|
|
$
|
921
|
|
|
$
|
166
|
|
|
$
|
332
|
|
DCF
(1)
|
|
$
|
1,140
|
|
|
$
|
399
|
|
|
$
|
741
|
|
|
$
|
137
|
|
|
$
|
262
|
|
DCF attributable to GP and LP unitholders
(1)
|
|
$
|
1,099
|
|
|
$
|
399
|
|
|
$
|
700
|
|
|
$
|
137
|
|
|
$
|
262
|
|
(1)
|
Non-GAAP financial measure. See the following tables for reconciliations to the most directly comparable GAAP measures.
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net income:
|
|
|
|
|
|
|
||||||
Net income
|
|
$
|
258
|
|
|
$
|
249
|
|
|
$
|
239
|
|
Depreciation and amortization
|
|
546
|
|
|
116
|
|
|
75
|
|
|||
(Benefit) provision for income taxes
|
|
(12
|
)
|
|
1
|
|
|
1
|
|
|||
Amortization of deferred financing costs
|
|
46
|
|
|
5
|
|
|
—
|
|
|||
Non-cash equity-based compensation
|
|
10
|
|
|
4
|
|
|
2
|
|
|||
Impairment expense
|
|
130
|
|
|
—
|
|
|
—
|
|
|||
Net interest and other financial costs
|
|
215
|
|
|
43
|
|
|
5
|
|
|||
Loss (income) from equity investments
|
|
74
|
|
|
(3
|
)
|
|
—
|
|
|||
Distributions from unconsolidated subsidiaries
|
|
150
|
|
|
15
|
|
|
—
|
|
|||
Unrealized derivative losses (gains)
(1)
|
|
36
|
|
|
(4
|
)
|
|
—
|
|
|||
Acquisition costs
|
|
(1
|
)
|
|
30
|
|
|
—
|
|
|||
Adjusted EBITDA
|
|
1,452
|
|
|
456
|
|
|
322
|
|
|||
Adjusted EBITDA attributable to noncontrolling interests
|
|
(3
|
)
|
|
(1
|
)
|
|
(69
|
)
|
|||
Adjusted EBITDA attributable to Predecessor
(2)
|
|
(30
|
)
|
|
(119
|
)
|
|
(87
|
)
|
|||
MarkWest's pre-merger EBITDA
(3)
|
|
—
|
|
|
162
|
|
|
—
|
|
|||
Adjusted EBITDA attributable to MPLX LP
|
|
1,419
|
|
|
498
|
|
|
166
|
|
|||
Deferred revenue impacts
|
|
8
|
|
|
6
|
|
|
(3
|
)
|
|||
Net interest and other financial costs
|
|
(215
|
)
|
|
(36
|
)
|
|
(6
|
)
|
|||
Maintenance capital expenditures
|
|
(68
|
)
|
|
(31
|
)
|
|
(22
|
)
|
|||
Other
|
|
(4
|
)
|
|
(6
|
)
|
|
2
|
|
|||
DCF pre-MarkWest undistributed
|
|
1,140
|
|
|
431
|
|
|
137
|
|
|||
MarkWest undistributed DCF
(2)
|
|
—
|
|
|
(32
|
)
|
|
—
|
|
|||
DCF
|
|
1,140
|
|
|
399
|
|
|
137
|
|
|||
Preferred unit distributions
|
|
(41
|
)
|
|
—
|
|
|
—
|
|
|||
DCF attributable to GP and LP unitholders
|
|
$
|
1,099
|
|
|
$
|
399
|
|
|
$
|
137
|
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net cash provided by operating activities:
|
|
|
|
|
|
|
||||||
Net cash provided by operating activities
|
|
$
|
1,288
|
|
|
$
|
340
|
|
|
$
|
334
|
|
Changes in working capital items
|
|
(89
|
)
|
|
54
|
|
|
(19
|
)
|
|||
All other, net
|
|
(20
|
)
|
|
(12
|
)
|
|
(2
|
)
|
|||
Non-cash equity-based compensation
|
|
10
|
|
|
4
|
|
|
2
|
|
|||
Net gain on disposal of assets
|
|
1
|
|
|
—
|
|
|
—
|
|
|||
Net interest and other financial costs
|
|
215
|
|
|
43
|
|
|
5
|
|
|||
Current income taxes
|
|
5
|
|
|
—
|
|
|
—
|
|
|||
Asset retirement expenditures
|
|
5
|
|
|
1
|
|
|
2
|
|
|||
Unrealized derivative losses (gains)
(1)
|
|
36
|
|
|
(4
|
)
|
|
—
|
|
|||
Acquisition costs
|
|
(1
|
)
|
|
30
|
|
|
—
|
|
|||
Other
|
|
2
|
|
|
—
|
|
|
—
|
|
|||
Adjusted EBITDA
|
|
1,452
|
|
|
456
|
|
|
322
|
|
|||
Adjusted EBITDA attributable to noncontrolling interests
|
|
(3
|
)
|
|
(1
|
)
|
|
(69
|
)
|
|||
Adjusted EBITDA attributable to Predecessor
(2)
|
|
(30
|
)
|
|
(119
|
)
|
|
(87
|
)
|
|||
MarkWest's pre-merger EBITDA
(3)
|
|
—
|
|
|
162
|
|
|
—
|
|
|||
Adjusted EBITDA attributable to MPLX LP
|
|
1,419
|
|
|
498
|
|
|
166
|
|
|||
Deferred revenue impacts
|
|
8
|
|
|
6
|
|
|
(3
|
)
|
|||
Net interest and other financial costs
|
|
(215
|
)
|
|
(36
|
)
|
|
(6
|
)
|
|||
Maintenance capital expenditures
|
|
(68
|
)
|
|
(31
|
)
|
|
(22
|
)
|
|||
Other
|
|
(4
|
)
|
|
(6
|
)
|
|
2
|
|
|||
DCF pre-MarkWest undistributed
|
|
1,140
|
|
|
431
|
|
|
137
|
|
|||
MarkWest undistributed DCF
(3)
|
|
—
|
|
|
(32
|
)
|
|
—
|
|
|||
DCF
|
|
1,140
|
|
|
399
|
|
|
137
|
|
|||
Preferred unit distributions
|
|
(41
|
)
|
|
—
|
|
|
—
|
|
|||
DCF attributable to GP and LP unitholders
|
|
$
|
1,099
|
|
|
$
|
399
|
|
|
$
|
137
|
|
(1)
|
The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, we record changes in the fair value of the derivative as an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously recorded unrealized gain or loss and record the realized gain or loss of the contract.
|
(2)
|
The Adjusted EBITDA adjustments related to the Predecessor are excluded from Adjusted EBITDA attributable to MPLX LP and DCF prior to the March 31, 2016 HSM acquisition.
|
(3)
|
The financial and operational results of MarkWest are included in the Partnership’s results from December 4, 2015, the date of the MarkWest Merger, in accordance with GAAP. The Partnership distributes and, prior to the MarkWest Merger, MarkWest distributed, all or a portion of the DCF generated in any given quarter to unitholders in the subsequent quarter. MarkWest had made a distribution for the third quarter of 2015 prior to the MarkWest Merger. However, the DCF generated by MarkWest for the period from October 1, 2015 through December 3, 2015 had not been distributed to MarkWest unitholders as of the date of the MarkWest Merger. By operation of the MarkWest Merger, the Partnership acquired such undistributed cash, along with all other assets of MarkWest, with the intent and obligation to distribute such cash to the Partnership’s unitholders as part of the Partnership’s fourth quarter 2015 distribution. In order to effectively include the amount of Adjusted EBITDA and DCF generated by MarkWest during the fourth quarter of 2015 prior to the date of the MarkWest Merger, and effectively include such previously undistributed cash, we have made adjustments labeled “MarkWest’s pre-merger EBITDA” and “MarkWest undistributed DCF” in our reconciliations of Adjusted EBITDA and DCF to reported net income. MarkWest’s pre-merger EBITDA represents Adjusted EBITDA generated by MarkWest for the period from October 1, 2015 through December 3, 2015. MarkWest undistributed DCF represents the net adjustments made to MarkWest’s pre-merger EBITDA in order to arrive at the DCF generated by MarkWest for the period from October 1, 2015 through December 3, 2015.
|
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Reconciliation of net operating margin to income from operations:
|
|
|
|
|
|
||||||
Segment revenue
|
$
|
2,972
|
|
|
$
|
910
|
|
|
$
|
747
|
|
Segment purchased product costs
|
(425
|
)
|
|
(25
|
)
|
|
—
|
|
|||
Realized derivative loss (gain) related to revenues and purchased product costs
|
3
|
|
|
(4
|
)
|
|
—
|
|
|||
Net operating margin
|
2,550
|
|
|
881
|
|
|
747
|
|
|||
Revenue adjustment from unconsolidated affiliates
(1)
|
(402
|
)
|
|
(28
|
)
|
|
—
|
|
|||
Realized derivative (loss) gain related to revenues and purchased product costs
(2)
|
(3
|
)
|
|
4
|
|
|
—
|
|
|||
Unrealized derivative (losses) gains
(2)
|
(36
|
)
|
|
4
|
|
|
—
|
|
|||
(Loss) income from equity method investments
|
(74
|
)
|
|
3
|
|
|
—
|
|
|||
Other income
|
6
|
|
|
6
|
|
|
6
|
|
|||
Other income - related parties
|
101
|
|
|
71
|
|
|
40
|
|
|||
Cost of revenues (excludes items below)
|
(354
|
)
|
|
(225
|
)
|
|
(228
|
)
|
|||
Rental cost of sales
|
(53
|
)
|
|
(5
|
)
|
|
(1
|
)
|
|||
Purchases - related parties
|
(316
|
)
|
|
(166
|
)
|
|
(153
|
)
|
|||
Depreciation and amortization
|
(546
|
)
|
|
(116
|
)
|
|
(75
|
)
|
|||
Impairment expense
|
(130
|
)
|
|
—
|
|
|
—
|
|
|||
General and administrative expenses
|
(193
|
)
|
|
(118
|
)
|
|
(81
|
)
|
|||
Other taxes
|
(43
|
)
|
|
(13
|
)
|
|
(10
|
)
|
|||
Income from operations
|
$
|
507
|
|
|
$
|
298
|
|
|
$
|
245
|
|
(1)
|
These amounts relate to Partnership-operated unconsolidated affiliates. The chief operating decision maker and management include these to evaluate the segment performance as we continue to operate and manage the operations. Therefore, the impact of the revenue is included for segment reporting purposes, but removed for GAAP purposes.
|
(2)
|
The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, we record changes in the fair value of the derivative as an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously recorded unrealized gain or loss and record the realized gain or loss of the contract.
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues and other income:
|
|
|
|
|
|
|
||||||
Segment revenues
|
|
$
|
787
|
|
|
$
|
760
|
|
|
$
|
747
|
|
Segment other income
|
|
68
|
|
|
75
|
|
|
46
|
|
|||
Total segment revenues and other income
|
|
855
|
|
|
835
|
|
|
793
|
|
|||
Costs and expenses:
|
|
|
|
|
|
|
||||||
Segment cost of revenues
|
|
368
|
|
|
379
|
|
|
392
|
|
|||
Segment operating income before portion attributable to noncontrolling interest and Predecessor
|
|
487
|
|
|
456
|
|
|
401
|
|
|||
Segment portion attributable to noncontrolling interest and Predecessor
|
|
34
|
|
|
134
|
|
|
188
|
|
|||
Segment operating income attributable to MPLX LP
|
|
$
|
453
|
|
|
$
|
322
|
|
|
$
|
213
|
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues and other income:
|
|
|
|
|
|
|
||||||
Segment revenues
|
|
$
|
2,185
|
|
|
$
|
150
|
|
|
$
|
—
|
|
Segment other income
|
|
1
|
|
|
—
|
|
|
—
|
|
|||
Total segment revenues and other income
|
|
2,186
|
|
|
150
|
|
|
—
|
|
|||
Costs and expenses:
|
|
|
|
|
|
|
||||||
Segment cost of revenues
|
|
907
|
|
|
62
|
|
|
—
|
|
|||
Segment operating income before portion attributable to noncontrolling interest
|
|
1,279
|
|
|
88
|
|
|
—
|
|
|||
Segment portion attributable to noncontrolling interest
|
|
147
|
|
|
12
|
|
|
—
|
|
|||
Segment operating income attributable to MPLX LP
|
|
$
|
1,132
|
|
|
$
|
76
|
|
|
$
|
—
|
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Reconciliation to Income from operations:
|
|
|
|
|
|
|
||||||
L&S segment operating income attributable to MPLX LP
|
|
$
|
453
|
|
|
$
|
322
|
|
|
$
|
213
|
|
G&P segment operating income attributable to MPLX LP
|
|
1,132
|
|
|
76
|
|
|
—
|
|
|||
Segment operating income attributable to MPLX LP
|
|
1,585
|
|
|
398
|
|
|
213
|
|
|||
Segment portion attributable to unconsolidated affiliates
|
|
(173
|
)
|
|
(8
|
)
|
|
85
|
|
|||
Segment portion attributable to Predecessor
|
|
34
|
|
|
133
|
|
|
103
|
|
|||
(Loss) income from equity method investments
|
|
(74
|
)
|
|
3
|
|
|
—
|
|
|||
Other income - related parties
|
|
40
|
|
|
2
|
|
|
—
|
|
|||
Unrealized derivative (losses) gains
(1)
|
|
(36
|
)
|
|
4
|
|
|
—
|
|
|||
Depreciation and amortization
|
|
(546
|
)
|
|
(116
|
)
|
|
(75
|
)
|
|||
Impairment expense
|
|
(130
|
)
|
|
—
|
|
|
—
|
|
|||
General and administrative expenses
|
|
(193
|
)
|
|
(118
|
)
|
|
(81
|
)
|
|||
Income from operations
|
|
$
|
507
|
|
|
$
|
298
|
|
|
$
|
245
|
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Reconciliation to Total revenues and other income:
|
|
|
|
|
|
|
||||||
Total segment revenues and other income
|
|
$
|
3,041
|
|
|
$
|
985
|
|
|
$
|
793
|
|
Revenue adjustment from unconsolidated affiliates
|
|
(402
|
)
|
|
(28
|
)
|
|
—
|
|
|||
(Loss) income from equity method investments
|
|
(74
|
)
|
|
3
|
|
|
—
|
|
|||
Other income - related parties
|
|
40
|
|
|
2
|
|
|
—
|
|
|||
Unrealized derivative losses
(1)
|
|
(15
|
)
|
|
(1
|
)
|
|
—
|
|
|||
Total revenues and other income
|
|
$
|
2,590
|
|
|
$
|
961
|
|
|
$
|
793
|
|
(in millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Reconciliation to Net income attributable to noncontrolling interests and Predecessor:
|
|
|
|
|
|
|
||||||
Segment portion attributable to noncontrolling interest and Predecessor
|
|
$
|
181
|
|
|
$
|
146
|
|
|
$
|
188
|
|
Portion of noncontrolling interests and Predecessor related to items below segment income from operations
|
|
(124
|
)
|
|
(48
|
)
|
|
(70
|
)
|
|||
Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates
|
|
(32
|
)
|
|
(5
|
)
|
|
—
|
|
|||
Net income attributable to noncontrolling interests and Predecessor
|
|
$
|
25
|
|
|
$
|
93
|
|
|
$
|
118
|
|
(1)
|
The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, we record changes in the fair value of the derivative as an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously recorded unrealized gain or loss and record the realized gain or loss of the contract.
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues and other income:
|
|
|
|
|
|
|
||||||
Segment revenues
|
|
$
|
2,185
|
|
|
$
|
2,007
|
|
|
$
|
2,168
|
|
Segment other income
|
|
1
|
|
|
—
|
|
|
—
|
|
|||
Total segment revenues and other income
|
|
2,186
|
|
|
2,007
|
|
|
2,168
|
|
|||
Costs and expenses:
|
|
|
|
|
|
|
||||||
Segment cost of revenues
|
|
907
|
|
|
875
|
|
|
1,197
|
|
|||
Segment operating income before portion attributable to noncontrolling interest
|
|
1,279
|
|
|
1,132
|
|
|
971
|
|
|||
Segment portion attributable to noncontrolling interest
|
|
147
|
|
|
121
|
|
|
36
|
|
|||
Segment operating income attributable to MPLX LP
|
|
$
|
1,132
|
|
|
$
|
1,011
|
|
|
$
|
935
|
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Pro forma reconciliation to total revenues and other income:
|
|
|
|
|
|
|
||||||
Total G&P segment revenues and other income
|
|
$
|
2,186
|
|
|
$
|
2,007
|
|
|
$
|
2,168
|
|
Revenue adjustment from unconsolidated affiliates
(1)
|
|
(402
|
)
|
|
(159
|
)
|
|
(41
|
)
|
|||
(Loss) income from equity method investments
|
|
(74
|
)
|
|
8
|
|
|
(12
|
)
|
|||
G&P other income (loss) - related parties
|
|
40
|
|
|
(4
|
)
|
|
19
|
|
|||
Unrealized derivative (losses) gains related to revenue
(2)
|
|
(15
|
)
|
|
(10
|
)
|
|
25
|
|
|||
Total pro forma G&P revenues and other income
|
|
1,735
|
|
|
1,842
|
|
|
2,159
|
|
|||
Total pro forma L&S revenues and other income
|
|
855
|
|
|
835
|
|
|
813
|
|
|||
Total pro forma revenues and other income
|
|
$
|
2,590
|
|
|
$
|
2,677
|
|
|
$
|
2,972
|
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Pro forma reconciliation to pro forma net income attributable to MPLX LP:
|
|
|
|
|
|
|
||||||
L&S segment operating income attributable to MPLX LP
|
|
$
|
453
|
|
|
$
|
322
|
|
|
$
|
266
|
|
G&P segment operating income attributable to MPLX LP
|
|
1,132
|
|
|
76
|
|
|
—
|
|
|||
Pro forma G&P segment operating income attributable to MPLX LP
|
|
—
|
|
|
935
|
|
|
935
|
|
|||
Segment portion attributable to unconsolidated affiliates
(1)
|
|
(320
|
)
|
|
(29
|
)
|
|
(8
|
)
|
|||
Segment portion attributable to noncontrolling interest and Predecessor
|
|
181
|
|
|
182
|
|
|
21
|
|
|||
(Loss) income from equity method investments
|
|
(74
|
)
|
|
8
|
|
|
(12
|
)
|
|||
Other income (loss) - related parties
|
|
40
|
|
|
(5
|
)
|
|
19
|
|
|||
Unrealized derivative (losses) gains
(2)
|
|
(36
|
)
|
|
(10
|
)
|
|
82
|
|
|||
Depreciation and amortization
|
|
(546
|
)
|
|
(575
|
)
|
|
(481
|
)
|
|||
Impairment expense
|
|
(130
|
)
|
|
(26
|
)
|
|
(62
|
)
|
|||
General and administrative expenses
|
|
(193
|
)
|
|
(209
|
)
|
|
(130
|
)
|
|||
Pro forma income from operations
|
|
507
|
|
|
669
|
|
|
630
|
|
|||
Related party interest and other financial costs
|
|
1
|
|
|
—
|
|
|
—
|
|
|||
Debt retirement expense
|
|
—
|
|
|
118
|
|
|
—
|
|
|||
Net interest and other financial costs
|
|
260
|
|
|
259
|
|
|
189
|
|
|||
Pro forma income before income taxes
|
|
246
|
|
|
292
|
|
|
441
|
|
|||
(Benefit) provision for income taxes
|
|
(12
|
)
|
|
(10
|
)
|
|
46
|
|
|||
Pro forma net income
|
|
258
|
|
|
302
|
|
|
395
|
|
|||
Less: Net income attributable to noncontrolling interests
|
|
25
|
|
|
55
|
|
|
66
|
|
|||
Pro forma net income attributable to MPLX LP
|
|
$
|
233
|
|
|
$
|
247
|
|
|
$
|
329
|
|
(1)
|
The Partnership consolidated the Utica Operations until December 4, 2015 at which point these were accounted for as unconsolidated affiliates.
|
(2)
|
The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, we record changes in the fair value of the derivative as an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously recorded unrealized gain or loss and record the realized gain or loss of the contract.
|
Pro Forma Operating Statistics
|
|
2016
|
|
2015
|
|
2014
|
||||||
Gathering Throughput (mmcf/d)
|
|
|
|
|
|
|
||||||
Marcellus Operations
|
|
910
|
|
|
858
|
|
|
668
|
|
|||
Utica Operations
(1)
|
|
932
|
|
|
673
|
|
|
289
|
|
|||
Southwest Operations
(2)
|
|
1,433
|
|
|
1,413
|
|
|
1,336
|
|
|||
Total gathering throughput
|
|
3,275
|
|
|
2,944
|
|
|
2,293
|
|
|||
|
|
|
|
|
|
|
||||||
Natural Gas Processed (mmcf/d)
|
|
|
|
|
|
|
||||||
Marcellus Operations
|
|
3,210
|
|
|
2,861
|
|
|
2,064
|
|
|||
Utica Operations
(1)
|
|
1,072
|
|
|
883
|
|
|
416
|
|
|||
Southwest Operations
|
|
1,226
|
|
|
1,077
|
|
|
991
|
|
|||
Southern Appalachian Operations
|
|
253
|
|
|
267
|
|
|
280
|
|
|||
Total natural gas processed
|
|
5,761
|
|
|
5,088
|
|
|
3,751
|
|
|||
|
|
|
|
|
|
|
||||||
C2 + NGLs Fractionated (mbpd)
|
|
|
|
|
|
|
||||||
Marcellus Operations
(3)
|
|
260
|
|
|
194
|
|
|
147
|
|
|||
Utica Operations
(1)(3)
|
|
42
|
|
|
40
|
|
|
19
|
|
|||
Southwest Operations
|
|
18
|
|
|
18
|
|
|
21
|
|
|||
Southern Appalachian Operations
(4)
|
|
15
|
|
|
15
|
|
|
19
|
|
|||
Total C2 + NGLs fractionated
(5)
|
|
335
|
|
|
267
|
|
|
206
|
|
|||
|
|
|
|
|
|
|
||||||
Pricing Information
|
|
|
|
|
|
|
||||||
Natural Gas NYMEX HH ($/MMBtu)
|
|
$
|
2.55
|
|
|
$
|
2.63
|
|
|
$
|
4.28
|
|
C2 + NGL Pricing/gallon
(6)
|
|
$
|
0.47
|
|
|
$
|
0.46
|
|
|
$
|
0.92
|
|
(1)
|
Utica was a consolidated equity method investment prior to December 4, 2015. After this date, it became an unconsolidated equity method investment but is consolidated for segment purposes only.
|
(2)
|
Includes approximately
309
mmcf/d,
242
mmcf/d and 228 mmcf/d related to unconsolidated equity method investments, Wirth and MarkWest Pioneer, for the years ended
December 31, 2016
, 2015 and 2014, respectively.
|
(3)
|
Hopedale is jointly owned by Ohio Fractionation and MarkWest Utica EMG. Ohio Fractionation is a subsidiary of MarkWest Liberty Midstream. MarkWest Liberty Midstream and MarkWest Utica EMG are entities that operate in the Marcellus and Utica regions, respectively. The Marcellus Operations includes its portion utilized of the jointly owned Hopedale Fractionation Complex. The Utica Operations includes Utica’s portion utilized of the jointly owned Hopedale Fractionation Complex.
|
(4)
|
Includes NGLs fractionated for the Marcellus and Utica Operations.
|
(5)
|
Purity ethane makes up approximately
128
mbpd,
79
mbpd and 67 mbpd of total fractionated products for the years ended
December 31, 2016
, 2015 and 2014, respectively.
|
(6)
|
C2 + NGL pricing based on Mont Belvieu prices assuming an NGL barrel of approximately 35 percent ethane, 35 percent propane, 6 percent Iso-Butane, 12 percent normal butane and 12 percent natural gasoline.
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Net cash provided by (used in):
|
|
|
|
|
|
|
||||||
Operating activities
|
|
$
|
1,288
|
|
|
$
|
340
|
|
|
$
|
334
|
|
Investing activities
|
|
(1,212
|
)
|
|
(1,599
|
)
|
|
(137
|
)
|
|||
Financing activities
|
|
115
|
|
|
1,275
|
|
|
(224
|
)
|
|||
Total
|
|
$
|
191
|
|
|
$
|
16
|
|
|
$
|
(27
|
)
|
|
|
December 31,
|
||||||
(In millions)
|
|
2016
|
|
2015
|
||||
MPLX LP:
|
|
|
|
|
||||
Bank revolving credit facility due 2020
|
|
$
|
—
|
|
|
$
|
877
|
|
Term loan facility due 2019
|
|
250
|
|
|
250
|
|
||
5.500% senior notes due 2023
|
|
710
|
|
|
710
|
|
||
4.500% senior notes due 2023
|
|
989
|
|
|
989
|
|
||
4.875% senior notes due 2024
|
|
1,149
|
|
|
1,149
|
|
||
4.000% senior notes due 2025
|
|
500
|
|
|
500
|
|
||
4.875% senior notes due 2025
|
|
1,189
|
|
|
1,189
|
|
||
Consolidated subsidiaries:
|
|
|
|
|
||||
MarkWest - 4.500% - 5.500%, due 2023 - 2025
|
|
63
|
|
|
63
|
|
||
MPL - capital lease obligations due 2020
|
|
8
|
|
|
9
|
|
||
Total
|
|
4,858
|
|
|
5,736
|
|
||
Unamortized debt issuance costs
|
|
(7
|
)
|
|
(8
|
)
|
||
Unamortized discount
(1)
|
|
(428
|
)
|
|
(472
|
)
|
||
Amounts due within one year
|
|
(1
|
)
|
|
(1
|
)
|
||
Total long-term debt due after one year
|
|
$
|
4,422
|
|
|
$
|
5,255
|
|
(1)
|
Includes
$420 million
and
$464 million
discount as of December 31, 2016 and 2015, respectively, related to the difference between the fair value and the principal amount of the assumed MarkWest debt.
|
Rating Agency
|
|
Rating
|
Fitch
|
|
BBB- (stable outlook)
|
Moody’s
|
|
Baa3 (stable outlook)
|
Standard & Poor’s
|
|
BBB- (stable outlook)
|
|
December 31, 2016
|
||||||||||
(In millions)
|
Total Capacity
|
|
Outstanding Borrowings
|
|
Available
Capacity
|
||||||
MPLX LP - bank revolving credit facility(1)
|
$
|
2,000
|
|
|
$
|
(3
|
)
|
|
$
|
1,997
|
|
MPC Investment - loan agreement
|
500
|
|
|
—
|
|
|
500
|
|
|||
Total
|
$
|
2,500
|
|
|
$
|
(3
|
)
|
|
$
|
2,497
|
|
Cash and cash equivalents
|
|
|
|
|
234
|
|
|||||
Total liquidity
|
|
|
|
|
$
|
2,731
|
|
(1)
|
Outstanding borrowings include
$3 million
in letters of credit outstanding under this facility.
|
(In units)
|
Common
|
|
Class B
|
|
Subordinated
|
|
General Partner
|
|
Total
|
|||||
Balance at December 31, 2013
|
36,951,515
|
|
|
—
|
|
|
36,951,515
|
|
|
1,508,225
|
|
|
75,411,255
|
|
Unit-based compensation awards
|
15,479
|
|
|
—
|
|
|
—
|
|
|
316
|
|
|
15,795
|
|
Contribution of interest in Pipe Line Holdings
|
2,924,104
|
|
|
—
|
|
|
—
|
|
|
59,676
|
|
|
2,983,780
|
|
December 2014 equity offering
|
3,450,000
|
|
|
—
|
|
|
—
|
|
|
70,408
|
|
|
3,520,408
|
|
Balance at December 31, 2014
|
43,341,098
|
|
|
—
|
|
|
36,951,515
|
|
|
1,638,625
|
|
|
81,931,238
|
|
Unit-based compensation awards
|
18,932
|
|
|
—
|
|
|
—
|
|
|
386
|
|
|
19,318
|
|
Issuance of units under the ATM program
|
25,166
|
|
|
—
|
|
|
—
|
|
|
514
|
|
|
25,680
|
|
Subordinated unit conversion
|
36,951,515
|
|
|
—
|
|
|
(36,951,515
|
)
|
|
—
|
|
|
—
|
|
MarkWest Merger
|
216,350,465
|
|
|
7,981,756
|
|
|
—
|
|
|
5,160,950
|
|
|
229,493,171
|
|
Balance at December 31, 2015
|
296,687,176
|
|
|
7,981,756
|
|
|
—
|
|
|
6,800,475
|
|
|
311,469,407
|
|
Unit-based compensation awards
|
120,989
|
|
|
—
|
|
|
—
|
|
|
2,470
|
|
|
123,459
|
|
Issuance of units under the ATM Program
|
26,347,887
|
|
|
—
|
|
|
—
|
|
|
537,710
|
|
|
26,885,597
|
|
Contribution of HSM
|
22,534,002
|
|
|
—
|
|
|
—
|
|
|
459,878
|
|
|
22,993,880
|
|
Class B conversion
|
4,350,057
|
|
|
(3,990,878
|
)
|
|
—
|
|
|
7,330
|
|
|
366,509
|
|
Class A Reorganization
|
7,153,177
|
|
|
—
|
|
|
—
|
|
|
(436,758
|
)
|
|
6,716,419
|
|
Balance at December 31, 2016
|
357,193,288
|
|
|
3,990,878
|
|
|
—
|
|
|
7,371,105
|
|
|
368,555,271
|
|
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Distribution declared:
|
|
|
|
|
|
||||||
Limited partner units - public
|
$
|
533
|
|
|
$
|
151
|
|
|
$
|
29
|
|
Limited partner units - MPC
|
159
|
|
|
104
|
|
|
77
|
|
|||
General partner units - MPC
|
18
|
|
|
6
|
|
|
2
|
|
|||
Incentive distribution rights - MPC
|
187
|
|
|
54
|
|
|
4
|
|
|||
Total GP & LP distribution declared
|
897
|
|
|
315
|
|
|
112
|
|
|||
Redeemable preferred units
|
41
|
|
|
—
|
|
|
—
|
|
|||
Total distribution declared
|
$
|
938
|
|
|
$
|
315
|
|
|
$
|
112
|
|
|
|
|
|
|
|
||||||
Cash distributions declared per limited partner common unit:
|
|
|
|
|
|
||||||
Quarter ended March 31
|
$
|
0.5050
|
|
|
$
|
0.4100
|
|
|
$
|
0.3275
|
|
Quarter ended June 30
|
0.5100
|
|
|
0.4400
|
|
|
0.3425
|
|
|||
Quarter ended September 30
|
0.5150
|
|
|
0.4700
|
|
|
0.3575
|
|
|||
Quarter ended December 31
|
0.5200
|
|
|
0.5000
|
|
|
0.3825
|
|
|||
Year ended December 31
|
$
|
2.0500
|
|
|
$
|
1.8200
|
|
|
$
|
1.4100
|
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Capital expenditures:
|
|
|
|
|
|
|
||||||
Maintenance
|
|
$
|
68
|
|
|
$
|
33
|
|
|
$
|
30
|
|
Expansion
|
|
1,118
|
|
|
282
|
|
|
124
|
|
|||
Total capital expenditures
|
|
1,186
|
|
|
315
|
|
|
154
|
|
|||
Less: (Decrease) increase in capital accruals
|
|
(25
|
)
|
|
26
|
|
|
11
|
|
|||
Asset retirement expenditures
|
|
5
|
|
|
1
|
|
|
2
|
|
|||
Additions to property, plant and equipment
|
|
1,206
|
|
|
288
|
|
|
141
|
|
|||
Capital expenditures of unconsolidated subsidiaries
(1)
|
|
131
|
|
|
24
|
|
|
—
|
|
|||
Total gross capital expenditures
|
|
1,337
|
|
|
312
|
|
|
141
|
|
|||
Less: Joint venture partner contributions
(2)
|
|
64
|
|
|
8
|
|
|
—
|
|
|||
Total capital expenditures, net
|
|
1,273
|
|
|
304
|
|
|
141
|
|
|||
Less: Maintenance capital
|
|
72
|
|
|
33
|
|
|
30
|
|
|||
Total growth capital
|
|
1,201
|
|
|
271
|
|
|
111
|
|
|||
Acquisition, net of cash acquired
|
|
—
|
|
|
1,218
|
|
|
—
|
|
|||
Total growth capital and acquisition
|
|
$
|
1,201
|
|
|
$
|
1,489
|
|
|
$
|
111
|
|
(1)
|
Includes amounts related to unconsolidated, Partnership-operated subsidiaries.
|
(2)
|
This represents estimated joint venture partners share of growth capital.
|
(In millions)
|
|
Total
|
|
2017
|
|
2018-2019
|
|
2020-2021
|
|
Later Years
|
||||||||||
Bank revolving credit facility
(1)
|
|
$
|
16
|
|
|
$
|
4
|
|
|
$
|
8
|
|
|
$
|
4
|
|
|
$
|
—
|
|
Term loan
(1)
|
|
267
|
|
|
6
|
|
|
261
|
|
|
—
|
|
|
—
|
|
|||||
Long-term debt
(1)
|
|
6,300
|
|
|
221
|
|
|
442
|
|
|
442
|
|
|
5,195
|
|
|||||
Capital lease obligations
|
|
9
|
|
|
1
|
|
|
3
|
|
|
5
|
|
|
—
|
|
|||||
Operating lease and long-term storage agreements
(2)
|
|
302
|
|
|
61
|
|
|
93
|
|
|
72
|
|
|
76
|
|
|||||
Purchase obligations:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Contracts to acquire property, plant & equipment
|
|
588
|
|
|
556
|
|
|
32
|
|
|
—
|
|
|
—
|
|
|||||
Other contracts
|
|
42
|
|
|
38
|
|
|
1
|
|
|
1
|
|
|
2
|
|
|||||
Total purchase obligations
(3)
|
|
630
|
|
|
594
|
|
|
33
|
|
|
1
|
|
|
2
|
|
|||||
Natural gas purchase obligations
(4)
|
|
103
|
|
|
19
|
|
|
34
|
|
|
33
|
|
|
17
|
|
|||||
SMR liability
(5)
|
|
228
|
|
|
17
|
|
|
34
|
|
|
34
|
|
|
143
|
|
|||||
Transportation and terminalling
(6)
|
|
608
|
|
|
46
|
|
|
123
|
|
|
122
|
|
|
317
|
|
|||||
Other long-term liabilities reflected on the Consolidated Balance Sheets:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Other liabilities
(7)
|
|
26
|
|
|
26
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|||||
AROs
(8)
|
|
25
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
25
|
|
|||||
Total contractual cash obligations
|
|
$
|
8,514
|
|
|
$
|
995
|
|
|
$
|
1,031
|
|
|
$
|
713
|
|
|
$
|
5,775
|
|
(1)
|
Amounts represent outstanding borrowings at
December 31, 2016
, plus any commitment and administrative fees and interest.
|
(2)
|
Amounts relate primarily to a long-term propane storage agreement and our office and vehicle leases.
|
(3)
|
Represents purchase orders and contracts related to the purchase or build out of property, plant and equipment. Purchase obligations exclude current and long-term unrealized losses on derivative instruments included on the accompanying Consolidated Balance Sheets, which represent the current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts are generally settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the underlying commodity.
|
(4)
|
Natural gas purchase obligations consist primarily of a purchase agreement with a producer in our Southern Appalachia Operations. The contract provides for the purchase of keep-whole volumes at a specific price and is a component of a broader regional arrangement. The contract price is designed to share a portion of the frac spread with the producer and as a result, the amounts reflected for the obligation exceed the cost of purchasing the keep-whole volumes at a market price. The contract is considered an embedded derivative (see Item 8. Financial Statements and Supplementary Data – Note
16
for the fair value of the frac spread sharing component). We use the estimated future frac spreads as of
December 31, 2016
|
(5)
|
Represents amounts due under a product supply agreement (see Item 8. Financial Statements and Supplementary Data – Note
23
for further discussion of the product supply agreement).
|
(6)
|
Represents transportation and terminalling agreements that obligate us to minimum volume, throughput or payment commitments over the terms of the agreements, which will range from three to ten years. We expect to pass any minimum payment commitments through to producer customers. Minimum fees due under transportation agreements do not include potential fee increases as required by FERC.
|
(7)
|
Includes the payable for Class B units recorded in connection with the MarkWest Merger (see Item 8. Financial Statements and Supplementary Data – Note
4
for further discussion).
|
(8)
|
Excludes estimated accretion expense of
$29 million
. The total amount to be paid is approximately
$54 million
.
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Capital
|
|
$
|
10
|
|
|
$
|
2
|
|
|
$
|
2
|
|
Percent of total capital expenditures
|
|
1
|
%
|
|
1
|
%
|
|
3
|
%
|
|||
Compliance:
|
|
|
|
|
|
|
||||||
Operating and maintenance
|
|
$
|
75
|
|
|
$
|
22
|
|
|
$
|
22
|
|
Remediation
(1)
|
|
2
|
|
|
2
|
|
|
2
|
|
|||
Total
|
|
$
|
77
|
|
|
$
|
24
|
|
|
$
|
24
|
|
(1)
|
These amounts include spending charged against remediation reserves, where permissible, but exclude non-cash accruals for environmental remediation.
|
Description
|
Judgments and Uncertainties
|
Effect if Actual Results Differ from
Estimates and Assumptions
|
Impairment of Goodwill
|
|
|
Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate goodwill for impairment annually as of November 30 and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The first step of the evaluation is a qualitative analysis to determine if it is “more likely than not” that the carrying value of a reporting unit with goodwill exceeds its fair value. The additional quantitative steps in the goodwill impairment test may be performed if we determine that it is more likely than not that the carrying value is greater than the fair value.
|
Management performed a quantitative analysis as of November 30, 2016. We determined the fair value of our reporting units in both the G&P and L&S segments using the income and market approaches for our 2016 impairment analysis. This type of analysis requires us to make assumptions and estimates regarding industry and economic factors such as relevant commodity prices, contract renewals, and production volumes. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations.
For the 2016 qualitative analysis, we analyzed the changes in the assumptions above in light of current economic conditions to determine if it was more likely than not that impairment exists. We looked at factors, including changes in the forecasted operating income and volumes for the three reporting units with goodwill, changes in the commodity price environment, changes in our per unit market value, changes in our peers’ market value and changes in industry EBITDA multiples.
Management is also required to make certain assumptions when identifying the reporting units and determining the amount of goodwill allocated to each reporting unit. The method of allocating goodwill resulting from the acquisitions involved estimating the fair value of the reporting units and allocating the purchase price for each acquisition to each reporting unit. Goodwill is then calculated for each reporting unit as the excess of the allocated purchase price over the estimated fair value of the net assets.
|
The Partnership recorded approximately $130 million of impairment expense related to charges recorded during the first and second quarters of the fiscal year. We recorded no impairment charge related to our annual impairment review of goodwill as of November 30, 2016. The fair value of the reporting units for our goodwill impairment analysis was determined based on applying the discounted cash flow method, which is an income approach, and the guideline public company method, which is a market approach. The discounted cash flow fair value estimate is based on known or knowable information at the measurement date. The significant assumptions that were used to develop the estimates of the fair values under the discounted cash flow method include management’s best estimates of the expected future results and discount rates, which range from 7.8 percent to 14.5 percent. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the impairment tests will prove to be an accurate prediction of the future.
As of December 31, 2016, the Partnership had five reporting units with goodwill: Marcellus ($1.8 billion), East Texas ($228 million), West Texas ($41 million), HSM ($11 million), and MPL ($105 million). Step 1 of the fourth quarter impairment analysis resulted in the fair value of the reporting units exceeding their carrying value by approximately 28 percent, 8 percent, 44 percent, 303 percent and 167 percent, respectively. An increase of 0.50 percent to the discount rate used to estimate the fair value of the reporting units would not have resulted in a goodwill impairment charge as of December 31, 2016. Our fourth quarter analysis resulted in a significant increase in the fair value of the reporting units as compared to the interim analyses performed during 2016. This increase was generally supported by an increase in our market capitalization of approximately 49 percent. Significant assumptions used to estimate the reporting units’ fair value included estimates of future cash flows. If estimates for future cash flows, which are impacted primarily by commodity prices and producers' production plans, for the reporting units were to decline, the overall reporting units’ fair value would decrease, resulting in potential goodwill impairment charges. Additionally, an increase in the cost of capital would result in a decrease in the fair value of the reporting units, causing their value to decline and goodwill to potentially be impaired.
|
Description
|
Judgments and Uncertainties
|
Effect if Actual Results Differ from
Estimates and Assumptions
|
Impairment of Equity Method Investments
|
|
|
We evaluate our equity method investments for impairment whenever events or changes in circumstances indicate, in management’s judgment, that the carrying value of such investment may have experienced a decline in value. When evidence of an other-than-temporary loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether impairment should be recorded.
|
Our impairment assessment requires us to apply judgment in estimating future cash flows received from or attributable to our equity method investments. The primary estimates may include the expected volumes, the terms of related customer agreements and future commodity prices.
|
A fixed asset impairment analysis was performed during the second quarter for Ohio Condensate Company (OCC) resulting in an impairment charge of $96 million within OCC’s financial statements. Approximately $58 million of the charge was attributable to the Partnership based on its 60 percent ownership of OCC and was recorded in
(Loss) income from equity method investments
on the accompanying Consolidated Statements of Income. Furthermore, to determine the potential equity method impairment charge, an impairment analysis in accordance with ASC Topic 323 was performed during the second quarter resulting in an additional impairment charge of approximately $31 million, recorded in
(Loss) income from equity method investments
on the accompanying Consolidated Statements of Income.
For purposes of the second quarter impairment analysis, the fair value of OCC was determined based on applying the discounted cash flow method, which is an income approach, and the guideline public company method, which is a market approach. The significant assumptions used to estimate the fair value under the discounted cash flow method included management’s best estimates of the expected results using a probability weighted average set of cash flow forecasts and using a discount rate of 11.2 percent. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As such, the fair value of the OCC equity method investment and its underlying fixed assets represents a Level 3 measurement.
As of December 31, 2016, Management determined that there were no material events or changes in circumstances that would indicate an other-than-temporary decline in our equity method investments.
|
Accounting for Risk Management Activities and Derivative Financial Instruments
|
|
|
Our derivative financial instruments are recorded at fair value in the accompanying Consolidated Balance Sheets. Changes in fair value and settlements are reflected in our earnings in the accompanying Consolidated Statements of Income as gains and losses related to revenue, purchased product costs, and cost of revenues.
|
When available, quoted market prices or prices obtained through external sources are used to determine a financial instrument’s fair value. The valuation of Level 2 financial instruments is based on quoted market prices for similar assets and liabilities in active markets and other inputs that are observable. However, for other financial instruments for which quoted market prices are not available, the fair value is based on inputs that are largely unobservable such as option volatilities and NGL prices that are interpolated and extrapolated due to inactive markets. These instruments are classified as Level 3 under the fair value hierarchy. All fair value measurements are appropriately adjusted for non-performance risk.
|
If the assumptions used in the pricing models for our Level 2 and 3 financial instruments are inaccurate or if we had used an alternative valuation methodology, the estimated fair value may have been different and we may be exposed to unrealized losses or gains that could be material. A 10 percent difference in our estimated fair value of Level 2 and 3 derivatives at December 31, 2016 would have affected income before income taxes by approximately $6 million for the year ended December 31, 2016.
|
Description
|
Judgments and Uncertainties
|
Effect if Actual Results Differ from
Estimates and Assumptions
|
Contingent Liabilities
|
|
|
We accrue contingent liabilities for legal actions, claims, litigation, environmental remediation, tax deficiencies related to operating taxes and third-party indemnities for specified tax matters when such contingencies are both probable and can be reasonably estimated.
|
We regularly assess these estimates in consultation with legal counsel to consider resolved and new matters, material developments in court proceedings or settlement discussions, new information obtained as a result of ongoing discovery and past experience in defending and settling similar matters. Actual costs can differ from estimates for many reasons. For instance, settlement costs for claims and litigation can vary from estimates based on differing interpretations of laws, opinions on degree of responsibility and assessments of the amount of damages. Similarly, liabilities for environmental remediation may vary from estimates because of changes in laws, regulations and their interpretation, additional information on the extent and nature of site contamination and improvements in technology.
|
An estimate of the sensitivity to net income if other assumptions had been used in recording these liabilities is not practical because of the number of contingencies that must be assessed, the number of underlying assumptions and the wide range of reasonably possible outcomes, in terms of both the probability of loss and the estimates of such loss.
For additional information on contingent liabilities, see Item 8. Financial Statements and Supplementary Data – Note 23. |
WTI Crude Swaps
|
|
Volumes (Bbl/d)
|
|
WAVG Price (Per Bbl)
|
|
Fair Value (in thousands)
|
|||||
2017
|
|
100
|
|
|
$
|
52.10
|
|
|
$
|
(152
|
)
|
Natural Gas Swaps
|
|
Volumes (MMBtu/d)
|
|
WAVG Price (Per MMBtu)
|
|
Fair Value (in thousands)
|
|||||
2017
|
|
814
|
|
|
$
|
2.93
|
|
|
$
|
149
|
|
Ethane Swaps
|
|
Volumes (Gal/d)
|
|
WAVG Price (Per Gal)
|
|
Fair Value (in thousands)
|
|||||
2017
|
|
42,000
|
|
|
$
|
0.26
|
|
|
$
|
(433
|
)
|
Propane Swaps
|
|
Volumes (Gal/d)
|
|
WAVG Price (Per Gal)
|
|
Fair Value (in thousands)
|
|||||
2017
|
|
74,370
|
|
|
$
|
0.56
|
|
|
$
|
(3,173
|
)
|
IsoButane Swaps
|
|
Volumes (Gal/d)
|
|
WAVG Price (Per Gal)
|
|
Fair Value (in thousands)
|
|||||
2017
|
|
5,063
|
|
|
$
|
0.71
|
|
|
$
|
(314
|
)
|
Normal Butane Swaps
|
|
Volumes (Gal/d)
|
|
WAVG Price (Per Gal)
|
|
Fair Value (in thousands)
|
|||||
2017
|
|
22,862
|
|
|
$
|
0.71
|
|
|
$
|
(1,051
|
)
|
Natural Gasoline Swaps
|
|
Volumes (Gal/d)
|
|
WAVG Price (Per Gal)
|
|
Fair Value (in thousands)
|
|||||
2017
|
|
31,628
|
|
|
$
|
1.10
|
|
|
$
|
(1,208
|
)
|
WTI Crude Swaps
|
|
Volumes (Bbl/d)
|
|
WAVG Price (Per Bbl)
|
|||
2017 (Apr. - Dec.)
|
|
112
|
|
|
$
|
56.40
|
|
Natural Gas Swaps
|
|
Volumes (MMBtu/d)
|
|
WAVG Price (Per MMBtu)
|
|||
2017 (Apr. - Dec.)
|
|
1,141
|
|
|
$
|
3.11
|
|
Natural Gas Swaps
|
|
Volumes (MMBtu/d)
|
|
WAVG Price (Per MMBtu)
|
|||
2018
|
|
2,542
|
|
|
$
|
2.78
|
|
Ethane Swaps
|
|
Volumes (Gal/d)
|
|
WAVG Price (Per Gal)
|
|||
2017 (Apr. - Dec.)
|
|
14,143
|
|
|
$
|
0.28
|
|
Propane Swaps
|
|
Volumes (Gal/d)
|
|
WAVG Price (Per Gal)
|
|||
2017 (Apr. - Dec.)
|
|
49,180
|
|
|
$
|
0.67
|
|
Propane Swaps
|
|
Volumes (Gal/d)
|
|
WAVG Price (Per Gal)
|
|||
2018
|
|
16,925
|
|
|
$
|
0.64
|
|
IsoButane Swaps
|
|
Volumes (Gal/d)
|
|
WAVG Price (Per Gal)
|
|||
2017 (Apr. - Dec.)
|
|
7,206
|
|
|
$
|
0.87
|
|
IsoButane Swaps
|
|
Volumes (Gal/d)
|
|
WAVG Price (Per Gal)
|
|||
2018
|
|
1,655
|
|
|
$
|
0.80
|
|
Normal Butane Swaps
|
|
Volumes (Gal/d)
|
|
WAVG Price (Per Gal)
|
|||
2017 (Apr. - Dec.)
|
|
8,591
|
|
|
$
|
0.85
|
|
Normal Butane Swaps
|
|
Volumes (Gal/d)
|
|
WAVG Price (Per Gal)
|
|||
2018
|
|
4,595
|
|
|
$
|
0.75
|
|
Natural Gasoline Swaps
|
|
Volumes (Gal/d)
|
|
WAVG Price (Per Gal)
|
|||
2017 (Apr. - Dec.)
|
|
8,494
|
|
|
$
|
1.21
|
|
Natural Gasoline Swaps
|
|
Volumes (Gal/d)
|
|
WAVG Price (Per Gal)
|
|||
2018
|
|
3,089
|
|
|
$
|
1.18
|
|
(In millions)
|
|
Fair Value as of December 31, 2016
(1)
|
|
Change in Fair Value
(2)
|
|
Change in income before income taxes for the Year Ended
December 31, 2016
(3)
|
||||||
Long-term debt
|
|
|
|
|
|
|
||||||
Fixed-rate
|
|
$
|
4,703
|
|
|
$
|
304
|
|
|
N/A
|
|
|
Variable-rate
|
|
$
|
250
|
|
|
N/A
|
|
|
$
|
5
|
|
(1)
|
Fair value was based on market prices, where available, or current borrowing rates for financings with similar terms and maturities.
|
(2)
|
Assumes a 100-basis-point decrease in the weighted average yield-to-maturity at
December 31, 2016
.
|
(3)
|
Assumes a 100-basis-point change in interest rates. The change to net income was based on the weighted average balance of all outstanding variable-rate debt for the year ended
December 31, 2016
.
|
|
Page
|
Audited Consolidated Financial Statements:
|
|
/s/ Gary R. Heminger
|
|
/s/ Pamela K.M. Beall
|
|
/s/ Paula L. Rosson
|
Gary R. Heminger
Chairman of the Board of Directors and Chief Executive Officer of MPLX GP LLC (the general partner of MPLX LP) |
|
Pamela K.M. Beall
Director, Executive Vice President and Chief Financial Officer of MPLX GP LLC
(the general partner of MPLX LP)
|
|
Paula L. Rosson
Senior Vice President and Chief Accounting Officer of MPLX GP LLC
(the general partner of MPLX LP)
|
/s/ Gary R. Heminger
|
|
/s/ Pamela K.M. Beall
|
|
|
Gary R. Heminger
Chairman of the Board of Directors and Chief Executive Officer of MPLX GP LLC (the general partner of MPLX LP) |
|
Pamela K.M. Beall
Director, Executive Vice President and Chief Financial Officer of MPLX GP LLC
(the general partner of MPLX LP)
|
|
|
(In millions, except per unit data)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Revenues and other income:
|
|
|
|
|
|
|
||||||
Service revenue
|
|
$
|
958
|
|
|
$
|
130
|
|
|
$
|
70
|
|
Service revenue - related parties
|
|
603
|
|
|
593
|
|
|
662
|
|
|||
Rental income
|
|
298
|
|
|
20
|
|
|
—
|
|
|||
Rental income - related parties
|
|
114
|
|
|
101
|
|
|
15
|
|
|||
Product sales
|
|
572
|
|
|
36
|
|
|
—
|
|
|||
Product sales - related parties
|
|
11
|
|
|
1
|
|
|
—
|
|
|||
Gain on sale of assets
|
|
1
|
|
|
—
|
|
|
—
|
|
|||
(Loss) income from equity method investments
|
|
(74
|
)
|
|
3
|
|
|
—
|
|
|||
Other income
|
|
6
|
|
|
6
|
|
|
6
|
|
|||
Other income - related parties
|
|
101
|
|
|
71
|
|
|
40
|
|
|||
Total revenues and other income
|
|
2,590
|
|
|
961
|
|
|
793
|
|
|||
Costs and expenses:
|
|
|
|
|
|
|
||||||
Cost of revenues (excludes items below)
|
|
354
|
|
|
225
|
|
|
228
|
|
|||
Purchased product costs
|
|
448
|
|
|
20
|
|
|
—
|
|
|||
Rental cost of sales
|
|
53
|
|
|
5
|
|
|
1
|
|
|||
Purchases - related parties
|
|
316
|
|
|
166
|
|
|
153
|
|
|||
Depreciation and amortization
|
|
546
|
|
|
116
|
|
|
75
|
|
|||
Impairment expense
|
|
130
|
|
|
—
|
|
|
—
|
|
|||
General and administrative expenses
|
|
193
|
|
|
118
|
|
|
81
|
|
|||
Other taxes
|
|
43
|
|
|
13
|
|
|
10
|
|
|||
Total costs and expenses
|
|
2,083
|
|
|
663
|
|
|
548
|
|
|||
Income from operations
|
|
507
|
|
|
298
|
|
|
245
|
|
|||
Related party interest and other financial costs
|
|
1
|
|
|
—
|
|
|
—
|
|
|||
Interest expense (net of amounts capitalized of $28 million, $5 million, and $1 million, respectively)
|
|
210
|
|
|
35
|
|
|
4
|
|
|||
Other financial costs
|
|
50
|
|
|
13
|
|
|
1
|
|
|||
Income before income taxes
|
|
246
|
|
|
250
|
|
|
240
|
|
|||
(Benefit) provision for income taxes
|
|
(12
|
)
|
|
1
|
|
|
1
|
|
|||
Net income
|
|
258
|
|
|
249
|
|
|
239
|
|
|||
Less: Net income attributable to noncontrolling interests
|
|
2
|
|
|
1
|
|
|
57
|
|
|||
Less: Net income attributable to Predecessor
|
|
23
|
|
|
92
|
|
|
61
|
|
|||
Net income attributable to MPLX LP
|
|
233
|
|
|
156
|
|
|
121
|
|
|||
Less: Preferred unit distributions
|
|
41
|
|
|
—
|
|
|
—
|
|
|||
Less: General partner’s interest in net income attributable to MPLX LP
|
|
191
|
|
|
57
|
|
|
6
|
|
|||
Limited partners’ interest in net income attributable to MPLX LP
|
|
$
|
1
|
|
|
$
|
99
|
|
|
$
|
115
|
|
Per Unit Data (See Note 7)
|
|
|
|
|
|
|
||||||
Net income attributable to MPLX LP per limited partner unit:
|
|
|
|
|
|
|
||||||
Common - basic
|
|
$
|
—
|
|
|
$
|
1.23
|
|
|
$
|
1.55
|
|
Common - diluted
|
|
—
|
|
|
1.22
|
|
|
1.55
|
|
|||
Subordinated - basic and diluted
|
|
—
|
|
|
0.11
|
|
|
1.50
|
|
|||
Weighted average limited partner units outstanding:
|
|
|
|
|
|
|
||||||
Common - basic
|
|
331
|
|
|
79
|
|
|
37
|
|
|||
Common - diluted
|
|
338
|
|
|
80
|
|
|
37
|
|
|||
Subordinated - basic and diluted
|
|
—
|
|
|
18
|
|
|
37
|
|
|||
Cash distributions declared per limited partner common unit
|
|
$
|
2.0500
|
|
|
$
|
1.8200
|
|
|
$
|
1.4100
|
|
|
|
December 31,
|
||||||
(In millions)
|
|
2016
|
|
2015
|
||||
Assets
|
|
|
|
|
||||
Current assets:
|
|
|
|
|
||||
Cash and cash equivalents
|
|
$
|
234
|
|
|
$
|
43
|
|
Receivables, net
|
|
297
|
|
|
245
|
|
||
Receivables - related parties
|
|
122
|
|
|
187
|
|
||
Inventories
|
|
54
|
|
|
51
|
|
||
Other current assets
|
|
33
|
|
|
50
|
|
||
Total current assets
|
|
740
|
|
|
576
|
|
||
Equity method investments
|
|
2,467
|
|
|
2,458
|
|
||
Property, plant and equipment, net
|
|
10,730
|
|
|
9,997
|
|
||
Intangibles, net
|
|
492
|
|
|
466
|
|
||
Goodwill
|
|
2,199
|
|
|
2,570
|
|
||
Long-term receivables - related parties
|
|
4
|
|
|
25
|
|
||
Other noncurrent assets
|
|
14
|
|
|
12
|
|
||
Total assets
|
|
$
|
16,646
|
|
|
$
|
16,104
|
|
Liabilities
|
|
|
|
|
||||
Current liabilities:
|
|
|
|
|
||||
Accounts payable
|
|
$
|
123
|
|
|
$
|
91
|
|
Accrued liabilities
|
|
228
|
|
|
187
|
|
||
Payables - related parties
|
|
75
|
|
|
54
|
|
||
Deferred revenue
|
|
2
|
|
|
—
|
|
||
Deferred revenue - related parties
|
|
34
|
|
|
32
|
|
||
Accrued property, plant and equipment
|
|
132
|
|
|
168
|
|
||
Accrued taxes
|
|
33
|
|
|
27
|
|
||
Accrued interest payable
|
|
53
|
|
|
54
|
|
||
Other current liabilities
|
|
24
|
|
|
12
|
|
||
Total current liabilities
|
|
704
|
|
|
625
|
|
||
Long-term deferred revenue
|
|
12
|
|
|
4
|
|
||
Long-term deferred revenue - related parties
|
|
15
|
|
|
9
|
|
||
Long-term debt
|
|
4,422
|
|
|
5,255
|
|
||
Deferred income taxes
|
|
5
|
|
|
378
|
|
||
Deferred credits and other liabilities
|
|
169
|
|
|
166
|
|
||
Total liabilities
|
|
5,327
|
|
|
6,437
|
|
||
Commitments and contingencies (see Note 23)
|
|
|
|
|
||||
Redeemable preferred units
|
|
1,000
|
|
|
—
|
|
||
Equity
|
|
|
|
|
||||
Common unitholders - public (271 million and 240 million units issued and outstanding)
|
|
8,086
|
|
|
7,691
|
|
||
Class B unitholders (4 million and 8 million units issued and outstanding)
|
|
133
|
|
|
266
|
|
||
Common unitholder - MPC (86 million and 57 million units issued and outstanding)
|
|
1,069
|
|
|
465
|
|
||
General partner - MPC (7 million units issued and outstanding)
|
|
1,013
|
|
|
819
|
|
||
Equity of Predecessor
|
|
—
|
|
|
413
|
|
||
Total MPLX LP partners’ capital
|
|
10,301
|
|
|
9,654
|
|
||
Noncontrolling interest
|
|
18
|
|
|
13
|
|
||
Total equity
|
|
10,319
|
|
|
9,667
|
|
||
Total liabilities, preferred units and equity
|
|
$
|
16,646
|
|
|
$
|
16,104
|
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Increase (decrease) in cash and cash equivalents
|
|
|
|
|
|
|
||||||
Operating activities:
|
|
|
|
|
|
|
||||||
Net income
|
|
$
|
258
|
|
|
$
|
249
|
|
|
$
|
239
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
|
||||||
Amortization of deferred financing costs
|
|
46
|
|
|
5
|
|
|
1
|
|
|||
Depreciation and amortization
|
|
546
|
|
|
116
|
|
|
75
|
|
|||
Impairment expense
|
|
130
|
|
|
—
|
|
|
—
|
|
|||
Deferred income taxes
|
|
(17
|
)
|
|
1
|
|
|
—
|
|
|||
Asset retirement expenditures
|
|
(5
|
)
|
|
(1
|
)
|
|
(2
|
)
|
|||
Gain on disposal of assets
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|||
Loss (income) from equity method investments
|
|
74
|
|
|
(3
|
)
|
|
—
|
|
|||
Distributions from unconsolidated affiliates
|
|
148
|
|
|
15
|
|
|
—
|
|
|||
Changes in:
|
|
|
|
|
|
|
||||||
Current receivables
|
|
(52
|
)
|
|
(29
|
)
|
|
2
|
|
|||
Inventories
|
|
(8
|
)
|
|
1
|
|
|
1
|
|
|||
Change in fair value of derivatives
|
|
43
|
|
|
(6
|
)
|
|
—
|
|
|||
Current accounts payable and accrued liabilities
|
|
100
|
|
|
2
|
|
|
1
|
|
|||
Receivables from / liabilities to related parties
|
|
6
|
|
|
(22
|
)
|
|
15
|
|
|||
All other, net
|
|
20
|
|
|
12
|
|
|
2
|
|
|||
Net cash provided by operating activities
|
|
1,288
|
|
|
340
|
|
|
334
|
|
|||
Investing activities:
|
|
|
|
|
|
|
||||||
Additions to property, plant and equipment
|
|
(1,206
|
)
|
|
(288
|
)
|
|
(141
|
)
|
|||
Acquisitions, net of cash acquired
|
|
—
|
|
|
(1,218
|
)
|
|
—
|
|
|||
Investments - loans to (from) related parties
|
|
77
|
|
|
(77
|
)
|
|
—
|
|
|||
Disposal of assets
|
|
1
|
|
|
—
|
|
|
—
|
|
|||
Investments in unconsolidated affiliates
|
|
(87
|
)
|
|
(14
|
)
|
|
—
|
|
|||
All other, net
|
|
3
|
|
|
(2
|
)
|
|
4
|
|
|||
Net cash used in investing activities
|
|
(1,212
|
)
|
|
(1,599
|
)
|
|
(137
|
)
|
|||
Financing activities:
|
|
|
|
|
|
|
||||||
Long-term debt - borrowings
|
|
434
|
|
|
1,490
|
|
|
1,160
|
|
|||
- repayments
|
|
(1,312
|
)
|
|
(1,441
|
)
|
|
(526
|
)
|
|||
Related party debt - borrowings
|
|
2,532
|
|
|
301
|
|
|
—
|
|
|||
- repayments
|
|
(2,540
|
)
|
|
(293
|
)
|
|
—
|
|
|||
Debt issuance costs
|
|
—
|
|
|
(11
|
)
|
|
(3
|
)
|
|||
Net proceeds from equity offerings
|
|
792
|
|
|
1
|
|
|
230
|
|
|||
Issuance of redeemable preferred units
|
|
984
|
|
|
—
|
|
|
—
|
|
|||
Issuance of units in MarkWest Merger
|
|
—
|
|
|
169
|
|
|
—
|
|
|||
Contributions from MPC - MarkWest Merger
|
|
—
|
|
|
1,230
|
|
|
—
|
|
|||
Distributions to preferred unitholders
|
|
(25
|
)
|
|
—
|
|
|
—
|
|
|||
Distributions to unitholders and general partner
|
|
(845
|
)
|
|
(158
|
)
|
|
(103
|
)
|
|||
Distributions to noncontrolling interests
|
|
(3
|
)
|
|
(1
|
)
|
|
(47
|
)
|
|||
Contributions from noncontrolling interests
|
|
6
|
|
|
—
|
|
|
—
|
|
|||
Consideration payment to Class B unitholders
|
|
(25
|
)
|
|
—
|
|
|
—
|
|
|||
Contribution from MPC
|
|
225
|
|
|
—
|
|
|
—
|
|
|||
Distributions related to purchase of additional interest in Pipe Line Holdings
|
|
—
|
|
|
(12
|
)
|
|
(910
|
)
|
|||
Distributions to MPC from Predecessor
|
|
(104
|
)
|
|
—
|
|
|
(25
|
)
|
|||
All other, net
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|||
Net cash provided by (used in) financing activities
|
|
115
|
|
|
1,275
|
|
|
(224
|
)
|
|||
Net increase in cash and cash equivalents
|
|
191
|
|
|
16
|
|
|
(27
|
)
|
|||
Cash and cash equivalents at beginning of period
|
|
43
|
|
|
27
|
|
|
54
|
|
|||
Cash and cash equivalents at end of period
|
|
$
|
234
|
|
|
$
|
43
|
|
|
$
|
27
|
|
|
Partnership
|
|
|
|
|
|
|
||||||||||||||||||||||||
(In millions)
|
Common
Unitholders Public |
|
Class B Unitholders Public
|
|
Common
Unitholder MPC |
|
Subordinated
Unitholder MPC |
|
General Partner
MPC |
|
Noncontrolling
Interest |
Equity of Predecessor
|
|
Total
|
|||||||||||||||||
Balance at December 31, 2013
|
$
|
412
|
|
|
$
|
—
|
|
|
$
|
57
|
|
|
$
|
209
|
|
|
$
|
(32
|
)
|
|
$
|
468
|
|
|
$
|
285
|
|
|
$
|
1,399
|
|
Purchase/contribution of additional interest in Pipe Line Holdings
|
—
|
|
|
—
|
|
|
200
|
|
|
—
|
|
|
(638
|
)
|
|
(472
|
)
|
|
—
|
|
|
(910
|
)
|
||||||||
Equity offering, net of issuance costs
|
221
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9
|
|
|
—
|
|
|
—
|
|
|
230
|
|
||||||||
Net income
|
31
|
|
|
—
|
|
|
27
|
|
|
58
|
|
|
5
|
|
|
57
|
|
|
61
|
|
|
239
|
|
||||||||
Distributions to MPC from Predecessor
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(25
|
)
|
|
(25
|
)
|
||||||||
Distributions to unitholders and general partner
|
(26
|
)
|
|
—
|
|
|
(23
|
)
|
|
(50
|
)
|
|
(4
|
)
|
|
—
|
|
|
—
|
|
|
(103
|
)
|
||||||||
Distributions to noncontrolling interest retained by MPC
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(47
|
)
|
|
—
|
|
|
(47
|
)
|
||||||||
Equity-based compensation
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||||||
Balance at December 31, 2014
|
639
|
|
|
—
|
|
|
261
|
|
|
217
|
|
|
(660
|
)
|
|
6
|
|
|
321
|
|
|
784
|
|
||||||||
Purchase of additional interest in Pipe Line Holdings
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6
|
)
|
|
(6
|
)
|
|
—
|
|
|
(12
|
)
|
||||||||
Contributions from MPC - MarkWest Merger
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,280
|
|
|
—
|
|
|
—
|
|
|
1,280
|
|
||||||||
Issuance of units under ATM program
|
1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||||||
Net income
|
15
|
|
|
—
|
|
|
36
|
|
|
48
|
|
|
57
|
|
|
1
|
|
|
92
|
|
|
249
|
|
||||||||
Distributions to unitholders and general partner
|
(40
|
)
|
|
—
|
|
|
(52
|
)
|
|
(45
|
)
|
|
(21
|
)
|
|
—
|
|
|
—
|
|
|
(158
|
)
|
||||||||
Distributions to noncontrolling interests
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(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
|
|
||||||||
Distributions to MPC from Predecessor
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(104
|
)
|
|
(104
|
)
|
||||||||
Contribution from MPC
|
—
|
|
|
—
|
|
|
84
|
|
|
—
|
|
|
141
|
|
|
—
|
|
|
—
|
|
|
225
|
|
||||||||
Contribution of MarkWest Hydrocarbon from MPC
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(188
|
)
|
|
—
|
|
|
—
|
|
|
(188
|
)
|
||||||||
Distribution of MarkWest Hydrocarbon to MPC
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
563
|
|
|
—
|
|
|
—
|
|
|
563
|
|
||||||||
Issuance of units under ATM Program
|
776
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
792
|
|
||||||||
Net (loss) income
|
(5
|
)
|
|
—
|
|
|
6
|
|
|
—
|
|
|
191
|
|
|
2
|
|
|
23
|
|
|
217
|
|
||||||||
Allocation of MPC's net investment at acquisition
|
—
|
|
|
—
|
|
|
669
|
|
|
—
|
|
|
(337
|
)
|
|
—
|
|
|
(332
|
)
|
|
—
|
|
||||||||
Distributions to unitholders and general partner
|
(513
|
)
|
|
—
|
|
|
(142
|
)
|
|
—
|
|
|
(190
|
)
|
|
—
|
|
|
—
|
|
|
(845
|
)
|
||||||||
Distributions to noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(3
|
)
|
|
—
|
|
|
(3
|
)
|
||||||||
Contributions from noncontrolling interest
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
|
—
|
|
|
6
|
|
||||||||
Class B unit conversion
|
133
|
|
|
(133
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Equity-based compensation
|
6
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
6
|
|
||||||||
Deferred income tax impact from changes in equity
|
(2
|
)
|
|
—
|
|
|
(13
|
)
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
—
|
|
|
(17
|
)
|
||||||||
Balance at December 31, 2016
|
$
|
8,086
|
|
|
$
|
133
|
|
|
$
|
1,069
|
|
|
$
|
—
|
|
|
$
|
1,013
|
|
|
$
|
18
|
|
|
$
|
—
|
|
|
$
|
10,319
|
|
•
|
Product sales
–
Product sales represent the sale of NGLs, condensate and natural gas. The product is primarily obtained as consideration for or related to providing midstream services.
|
•
|
Service revenue
–
Service revenue represents all other revenue generated as the result of performing the services listed above.
|
•
|
Rental income
–
Rental income represents revenue generated as the result of implicit operating lease arrangements.
|
•
|
Fee-based arrangements
–
Under fee-based arrangements, the Partnership receives a fee or fees for one or more of the following services: gathering, processing and transportation of natural gas; gathering, transportation, fractionation, exchange and storage of NGLs; and gathering and transportation of crude oil. The revenue the Partnership earns from these arrangements is generally directly related to the volume of natural gas, NGLs or crude oil that flows through the Partnership’s systems and facilities and is not normally directly dependent on commodity prices. In certain cases, the Partnership’s arrangements provide for minimum annual payments or fixed demand charges.
|
◦
|
Fee-based arrangements are reported as
Service revenue
on the Consolidated Statements of Income. In certain instances when specifically stated in the contract terms, the Partnership purchases product after fee-based services have been provided. Revenue from the sale of products purchased after services are provided is reported as
Product sales
on the Consolidated Statements of Income and recognized on a gross basis as the Partnership is the principal in the transaction.
|
•
|
Percent-of-proceeds arrangements
–
Under percent-of-proceeds arrangements, the Partnership gathers and processes natural gas on behalf of producers, sells the resulting residue gas, condensate and NGLs at market prices and remits to producers an agreed-upon percentage of the proceeds. In other cases, instead of remitting cash payments to the producer, the Partnership delivers an agreed-upon percentage of the residue gas and NGLs to the producer (take-in-kind arrangements) and sells the volumes the Partnership retains to third parties. Revenue from these arrangements is
|
•
|
Keep-whole arrangements
–
Under keep-whole arrangements, the Partnership gathers natural gas from the producer, processes the natural gas and sells the resulting condensate and NGLs to third parties at market prices. Because the extraction of the condensate and NGLs from the natural gas during processing reduces the Btu content of the natural gas, the Partnership must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the energy content of this natural gas. Certain keep-whole arrangements also have provisions that require the Partnership to share a percentage of the keep-whole profits with the producers based on the oil to gas ratio or the NGL to gas ratio. Sales of NGLs under these arrangements are reported as
Product sales
on the Consolidated Statements of Income and are reported on a gross basis as the Partnership is the principal in the arrangement. Natural gas purchased to return to the producer and shared NGL profits are recorded as
Purchased product costs
in the Consolidated Statements of Income.
|
•
|
Percent-of-index arrangements
–
Under percent-of-index arrangements, the Partnership purchases natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount. The Partnership then gathers and delivers the natural gas to pipelines where the Partnership resells the natural gas at the index price or at a different percentage discount to the index price. Revenue generated from percent-of-index arrangements are reported as
Product sales
on the Consolidated Statements of Income and are recognized on a gross basis as the Partnership purchases and takes title to the product prior to sale and is the principal in the transaction.
|
•
|
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.
|
(In millions)
|
|
As Originally Reported
|
|
Adjustments
|
|
As Adjusted
|
||||||
Cash and cash equivalents
|
|
$
|
12
|
|
|
$
|
—
|
|
|
$
|
12
|
|
Receivables
|
|
164
|
|
|
—
|
|
|
164
|
|
|||
Inventories
|
|
33
|
|
|
(1
|
)
|
|
32
|
|
|||
Other current assets
|
|
44
|
|
|
—
|
|
|
44
|
|
|||
Equity method investments
|
|
2,457
|
|
|
143
|
|
|
2,600
|
|
|||
Property, plant and equipment
|
|
8,474
|
|
|
43
|
|
|
8,517
|
|
|||
Intangibles
|
|
468
|
|
|
65
|
|
|
533
|
|
|||
Other noncurrent assets
|
|
5
|
|
|
—
|
|
|
5
|
|
|||
Total assets acquired
|
|
11,657
|
|
|
250
|
|
|
11,907
|
|
|||
Accounts payable
|
|
322
|
|
|
—
|
|
|
322
|
|
|||
Accrued liabilities
|
|
13
|
|
|
6
|
|
|
19
|
|
|||
Accrued taxes
|
|
21
|
|
|
—
|
|
|
21
|
|
|||
Other current liabilities
|
|
44
|
|
|
—
|
|
|
44
|
|
|||
Long-term debt
|
|
4,567
|
|
|
—
|
|
|
4,567
|
|
|||
Deferred income taxes
|
|
374
|
|
|
3
|
|
|
377
|
|
|||
Deferred credits and other liabilities
|
|
151
|
|
|
—
|
|
|
151
|
|
|||
Noncontrolling interest
|
|
13
|
|
|
—
|
|
|
13
|
|
|||
Total liabilities and noncontrolling interest assumed
|
|
5,505
|
|
|
9
|
|
|
5,514
|
|
|||
Net assets acquired excluding goodwill
|
|
6,152
|
|
|
241
|
|
|
6,393
|
|
|||
Goodwill
|
|
2,454
|
|
|
(241
|
)
|
|
2,213
|
|
|||
Net assets acquired
|
|
$
|
8,606
|
|
|
$
|
—
|
|
|
$
|
8,606
|
|
(In millions)
|
|
2015
|
||
Revenues and other income
|
|
$
|
126
|
|
Income from operations
|
|
32
|
|
(In millions, except per unit data)
|
|
2015
|
|
2014
|
||||
Revenues and other income
|
|
$
|
2,677
|
|
|
$
|
2,972
|
|
Net income attributable to MPLX LP
|
|
247
|
|
|
330
|
|
||
Net income attributable to MPLX LP per unit - basic
|
|
0.47
|
|
|
1.09
|
|
||
Net income attributable to MPLX LP per unit - diluted
|
|
0.45
|
|
|
1.03
|
|
(in millions)
|
|
2015
|
|
2014
|
||||
Revenue and other income
|
|
$
|
152
|
|
|
$
|
85
|
|
Cost of revenue excluding depreciation and amortization
|
|
27
|
|
|
48
|
|
||
Depreciation and amortization
|
|
61
|
|
|
50
|
|
||
Net income attributable to noncontrolling interest
|
|
64
|
|
|
31
|
|
||
Net loss
|
|
(5
|
)
|
|
(46
|
)
|
(In millions)
|
2015
|
|
2014
|
||||
Net income attributable to MPLX LP
|
$
|
156
|
|
|
$
|
121
|
|
Transfer to noncontrolling interest:
|
|
|
|
||||
Decrease in general partner-MPC equity for purchases of additional interest in Pipe Line Holdings
|
(6
|
)
|
|
(638
|
)
|
||
Change from net income attributable to MPLX LP and transfer to noncontrolling interest
|
$
|
150
|
|
|
$
|
(517
|
)
|
|
Year Ended December 31, 2016
|
||||||||||||||||||
(In millions)
|
MarkWest Utica EMG
|
|
Ohio Condensate
|
|
Other VIEs
|
|
Non-VIEs
|
|
Total
|
||||||||||
Revenue and other income
|
$
|
216
|
|
|
$
|
15
|
|
|
$
|
3
|
|
|
$
|
148
|
|
|
$
|
382
|
|
Cost and expenses
|
100
|
|
|
110
|
|
|
1
|
|
|
117
|
|
|
328
|
|
|||||
Income (loss) from operations
|
116
|
|
|
(95
|
)
|
|
2
|
|
|
31
|
|
|
54
|
|
|||||
Net income (loss)
|
114
|
|
|
(95
|
)
|
|
2
|
|
|
31
|
|
|
52
|
|
|||||
Income (loss) from equity method investments
(2)
|
8
|
|
|
(89
|
)
|
|
—
|
|
|
7
|
|
|
(74
|
)
|
|
Year Ended December 31, 2015
|
||||||||||||||||||
(In millions)
|
MarkWest Utica EMG
|
|
Ohio Condensate
|
|
Other VIEs
|
|
Non-VIEs
|
|
Total
|
||||||||||
Revenue and other income
|
$
|
18
|
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
9
|
|
|
$
|
29
|
|
Cost and expenses
|
9
|
|
|
2
|
|
|
—
|
|
|
8
|
|
|
19
|
|
|||||
Income from operations
|
9
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
10
|
|
|||||
Net income
|
10
|
|
|
—
|
|
|
—
|
|
|
1
|
|
|
11
|
|
|||||
Income from equity method investments
(2)
|
2
|
|
|
1
|
|
|
—
|
|
|
—
|
|
|
3
|
|
|
December 31, 2016
|
||||||||||||||||||
(In millions)
|
MarkWest Utica EMG
(1)
|
|
Ohio Condensate
|
|
Other VIEs
|
|
Non-VIEs
|
|
Total
|
||||||||||
Current assets
|
$
|
45
|
|
|
$
|
2
|
|
|
$
|
—
|
|
|
$
|
40
|
|
|
$
|
87
|
|
Noncurrent assets
|
2,173
|
|
|
30
|
|
|
102
|
|
|
375
|
|
|
2,680
|
|
|||||
Current liabilities
|
30
|
|
|
3
|
|
|
1
|
|
|
26
|
|
|
60
|
|
|||||
Noncurrent liabilities
|
2
|
|
|
13
|
|
|
—
|
|
|
—
|
|
|
15
|
|
|
December 31, 2015
|
||||||||||||||||||
(In millions)
|
MarkWest Utica EMG
(1)
|
|
Ohio Condensate
|
|
Other VIEs
|
|
Non-VIEs
|
|
Total
|
||||||||||
Current assets
|
$
|
113
|
|
|
$
|
7
|
|
|
$
|
—
|
|
|
$
|
30
|
|
|
$
|
150
|
|
Noncurrent assets
|
2,207
|
|
|
127
|
|
|
42
|
|
|
243
|
|
|
2,619
|
|
|||||
Current liabilities
|
77
|
|
|
6
|
|
|
1
|
|
|
18
|
|
|
102
|
|
|||||
Noncurrent liabilities
|
1
|
|
|
12
|
|
|
—
|
|
|
—
|
|
|
13
|
|
(1)
|
MarkWest Utica EMG’s noncurrent assets includes its investment in its subsidiary Ohio Gathering, which does not appear elsewhere in this table. The investment was
$794 million
and
$781 million
as of
December 31, 2016
and
2015
, respectively.
|
(2)
|
Income (loss) from equity method investments
includes the impact of any basis differential amortization or accretion.
|
•
|
MPC, which refines, markets and transports crude oil and petroleum products, primarily in the Midwest, Gulf Coast, East Coast and Southeast regions of the United States.
|
•
|
Centennial Pipeline LLC (“Centennial”), in which MPC has a
50 percent
interest. Centennial owns a products pipeline and storage facility.
|
•
|
Muskegon Pipeline LLC (“Muskegon”), in which MPC has a
60 percent
interest. Muskegon owns a common carrier products pipeline.
|
•
|
MarkWest Utica EMG, in which MPLX LP has a
56 percent
interest as of
December 31, 2016
. MarkWest Utica EMG is engaged in significant natural gas processing and NGL fractionation, transportation and marketing in the state of Ohio.
|
•
|
Ohio Gathering, in which MPLX LP has a
34 percent
indirect interest as of
December 31, 2016
. Ohio Gathering is a subsidiary of MarkWest Utica EMG providing natural gas gathering service in the Utica Shale region of eastern Ohio.
|
•
|
Ohio Condensate, in which MPLX LP has a
60 percent
interest. Ohio Condensate is engaged in wellhead condensate gathering, stabilization, terminalling, transportation and storage within certain defined areas of Ohio.
|
•
|
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 Neal, West Virginia butane cavern;
|
•
|
five
separate
three
-year storage services agreements under which MPC pays the Partnership fees for providing storage services at our tank farms; and
|
•
|
a
six
-year transportation services agreement under which MPC pays the Partnership fees for providing marine transportation of crude oil, feedstocks and refined petroleum products, and related services.
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Service revenue
|
|
|
|
|
|
|
||||||
MPC
|
|
$
|
603
|
|
|
$
|
593
|
|
|
$
|
662
|
|
Rental income
|
|
|
|
|
|
|
||||||
MPC
|
|
$
|
114
|
|
|
$
|
101
|
|
|
$
|
15
|
|
Product sales
(1)
|
|
|
|
|
|
|
||||||
MPC
|
|
$
|
11
|
|
|
$
|
1
|
|
|
$
|
—
|
|
(1)
|
For 2016 and 2015, there were
$46 million
and
$1 million
, respectively, of additional product sales to MPC that net to
zero
within the consolidated financial statements, as the transactions are recorded net due to the terms of the agreements under which such product was sold. There were no such transactions in 2014.
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
MPC
|
|
$
|
60
|
|
|
$
|
68
|
|
|
$
|
39
|
|
MarkWest Utica EMG
|
|
16
|
|
|
—
|
|
|
—
|
|
|||
Centennial
|
|
1
|
|
|
1
|
|
|
1
|
|
|||
Ohio Gathering
|
|
15
|
|
|
2
|
|
|
—
|
|
|||
Ohio Condensate
|
|
4
|
|
|
—
|
|
|
—
|
|
|||
Other
|
|
5
|
|
|
—
|
|
|
—
|
|
|||
Total
|
|
$
|
101
|
|
|
$
|
71
|
|
|
$
|
40
|
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Purchases from related parties
|
|
$
|
29
|
|
|
$
|
30
|
|
|
$
|
30
|
|
General and administrative expenses
|
|
39
|
|
|
46
|
|
|
46
|
|
|||
Total
|
|
$
|
68
|
|
|
$
|
76
|
|
|
$
|
76
|
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
MPC
|
|
$
|
38
|
|
|
$
|
13
|
|
|
$
|
8
|
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Purchases - related parties
|
|
$
|
287
|
|
|
$
|
136
|
|
|
$
|
123
|
|
General and administrative expenses
|
|
72
|
|
|
22
|
|
|
24
|
|
|||
Total
|
|
$
|
359
|
|
|
$
|
158
|
|
|
$
|
147
|
|
|
|
December 31,
|
||||||
(In millions)
|
|
2016
|
|
2015
|
||||
MPC
|
|
$
|
117
|
|
|
$
|
175
|
|
MarkWest Utica EMG
|
|
2
|
|
|
4
|
|
||
Ohio Gathering
|
|
2
|
|
|
5
|
|
||
Other
|
|
1
|
|
|
3
|
|
||
Total
|
|
$
|
122
|
|
|
$
|
187
|
|
|
December 31,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
MPC
|
$
|
4
|
|
|
$
|
25
|
|
|
|
December 31,
|
||||||
(In millions)
|
|
2016
|
|
2015
|
||||
MPC
|
|
$
|
51
|
|
|
$
|
33
|
|
MarkWest Utica EMG
|
|
24
|
|
|
21
|
|
||
Total
|
|
$
|
75
|
|
|
$
|
54
|
|
|
December 31,
|
||||||
(In millions)
|
2016
|
|
2015
|
||||
Minimum volume deficiencies - MPC
|
$
|
44
|
|
|
$
|
36
|
|
Project reimbursements - MPC
|
5
|
|
|
5
|
|
||
Total
|
$
|
49
|
|
|
$
|
41
|
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Net income attributable to MPLX LP
|
|
$
|
233
|
|
|
$
|
156
|
|
|
$
|
121
|
|
Less: Distributions declared on Preferred units
(1)
|
|
41
|
|
|
—
|
|
|
—
|
|
|||
General partner’s distributions declared (including IDRs)
(1)
|
|
205
|
|
|
60
|
|
|
6
|
|
|||
Limited partners’ distributions declared on common units
(1)
|
|
692
|
|
|
224
|
|
|
54
|
|
|||
Limited partner’s distributions declared on subordinated
units
(1)
|
|
—
|
|
|
31
|
|
|
52
|
|
|||
Undistributed net (loss) income attributable to MPLX LP
|
|
$
|
(705
|
)
|
|
$
|
(159
|
)
|
|
$
|
9
|
|
(1)
|
See Note
8
for information regarding the distribution.
|
|
|
2016
|
||||||||||||||
(In millions, except per-unit data)
|
|
General
Partner
|
|
Limited Partners’
Common Units
|
|
Redeemable Preferred Units
|
|
Total
|
||||||||
Basic and diluted net income attributable to MPLX LP per unit:
|
|
|
|
|
|
|
|
|
||||||||
Net income attributable to MPLX LP:
|
|
|
|
|
|
|
|
|
||||||||
Distributions declared (including IDRs)
|
|
$
|
205
|
|
|
$
|
692
|
|
|
$
|
41
|
|
|
$
|
938
|
|
Undistributed net loss attributable to MPLX LP
|
|
(14
|
)
|
|
(691
|
)
|
|
—
|
|
|
(705
|
)
|
||||
Net income attributable to MPLX LP
(1)
|
|
$
|
191
|
|
|
$
|
1
|
|
|
$
|
41
|
|
|
$
|
233
|
|
Weighted average units outstanding:
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
7
|
|
|
331
|
|
|
|
|
338
|
|
|||||
Diluted
|
|
7
|
|
|
338
|
|
|
|
|
345
|
|
|||||
Net income attributable to MPLX LP per limited partner unit:
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
|
|
$
|
—
|
|
|
|
|
|
||||||
Diluted
|
|
|
|
$
|
—
|
|
|
|
|
|
|
|
2015
|
||||||||||||||
(In millions, except per-unit data)
|
|
General
Partner
|
|
Limited Partners’
Common Units
|
|
Limited Partner’s Subordinated Units
|
|
Total
|
||||||||
Basic and diluted net income attributable to MPLX LP per unit:
|
|
|
|
|
|
|
|
|
||||||||
Net income attributable to MPLX LP:
|
|
|
|
|
|
|
|
|
||||||||
Distributions declared (including IDRs)
|
|
$
|
60
|
|
|
$
|
224
|
|
|
$
|
31
|
|
|
$
|
315
|
|
Undistributed net loss attributable to MPLX LP
|
|
(3
|
)
|
|
(127
|
)
|
|
(29
|
)
|
|
(159
|
)
|
||||
Net income attributable to MPLX LP
(1)
|
|
$
|
57
|
|
|
$
|
97
|
|
|
$
|
2
|
|
|
$
|
156
|
|
Weighted average units outstanding:
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
2
|
|
|
79
|
|
|
18
|
|
|
99
|
|
||||
Diluted
|
|
2
|
|
|
80
|
|
|
18
|
|
|
100
|
|
||||
Net income attributable to MPLX LP per limited partner unit:
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
|
|
$
|
1.23
|
|
|
$
|
0.11
|
|
|
|
||||
Diluted
|
|
|
|
$
|
1.22
|
|
|
$
|
0.11
|
|
|
|
|
|
2014
|
||||||||||||||
(In millions, except per-unit data)
|
|
General
Partner
|
|
Limited Partners’
Common Units
|
|
Limited
Partner’s
Subordinated
Units
|
|
Total
|
||||||||
Basic and diluted net income attributable to MPLX LP per unit:
|
|
|
|
|
|
|
|
|
||||||||
Net income attributable to MPLX LP:
|
|
|
|
|
|
|
|
|
||||||||
Distribution declared
|
|
$
|
6
|
|
|
$
|
54
|
|
|
$
|
52
|
|
|
$
|
112
|
|
Undistributed net income attributable to MPLX LP
|
|
2
|
|
|
4
|
|
|
3
|
|
|
9
|
|
||||
Net income attributable to MPLX LP
(1)
|
|
$
|
8
|
|
|
$
|
58
|
|
|
$
|
55
|
|
|
$
|
121
|
|
Weighted average units outstanding:
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
2
|
|
|
37
|
|
|
37
|
|
|
76
|
|
||||
Diluted
|
|
2
|
|
|
37
|
|
|
37
|
|
|
76
|
|
||||
Net income attributable to MPLX LP per limited partner unit:
|
|
|
|
|
|
|
|
|
||||||||
Basic
|
|
|
|
$
|
1.55
|
|
|
$
|
1.50
|
|
|
|
||||
Diluted
|
|
|
|
$
|
1.55
|
|
|
$
|
1.50
|
|
|
|
(1)
|
Allocation of net income (loss) attributable to MPLX LP assumes all earnings for the period had been distributed based on the current period distribution priorities.
|
(In units)
|
Common
|
|
Class B
|
|
Subordinated
|
|
General Partner
|
|
Total
|
|||||
Balance at December 31, 2013
|
36,951,515
|
|
|
—
|
|
|
36,951,515
|
|
|
1,508,225
|
|
|
75,411,255
|
|
Unit-based compensation awards
|
15,479
|
|
|
—
|
|
|
—
|
|
|
316
|
|
|
15,795
|
|
Contribution of interest in Pipe Line Holdings
|
2,924,104
|
|
|
—
|
|
|
—
|
|
|
59,676
|
|
|
2,983,780
|
|
December 2014 equity offering
|
3,450,000
|
|
|
—
|
|
|
—
|
|
|
70,408
|
|
|
3,520,408
|
|
Balance at December 31, 2014
|
43,341,098
|
|
|
—
|
|
|
36,951,515
|
|
|
1,638,625
|
|
|
81,931,238
|
|
Unit-based compensation awards
|
18,932
|
|
|
—
|
|
|
—
|
|
|
386
|
|
|
19,318
|
|
Issuance of units under the ATM program
|
25,166
|
|
|
—
|
|
|
—
|
|
|
514
|
|
|
25,680
|
|
Subordinated unit conversion
|
36,951,515
|
|
|
—
|
|
|
(36,951,515
|
)
|
|
—
|
|
|
—
|
|
MarkWest Merger
|
216,350,465
|
|
|
7,981,756
|
|
|
—
|
|
|
5,160,950
|
|
|
229,493,171
|
|
Balance at December 31, 2015
|
296,687,176
|
|
|
7,981,756
|
|
|
—
|
|
|
6,800,475
|
|
|
311,469,407
|
|
Unit-based compensation awards
|
120,989
|
|
|
—
|
|
|
—
|
|
|
2,470
|
|
|
123,459
|
|
Issuance of units under the ATM Program
|
26,347,887
|
|
|
—
|
|
|
—
|
|
|
537,710
|
|
|
26,885,597
|
|
Contribution of HSM (See Note 4)
|
22,534,002
|
|
|
—
|
|
|
—
|
|
|
459,878
|
|
|
22,993,880
|
|
Class B conversion
|
4,350,057
|
|
|
(3,990,878
|
)
|
|
—
|
|
|
7,330
|
|
|
366,509
|
|
Class A Reorganization
|
7,153,177
|
|
|
—
|
|
|
—
|
|
|
(436,758
|
)
|
|
6,716,419
|
|
Balance at December 31, 2016
|
357,193,288
|
|
|
3,990,878
|
|
|
—
|
|
|
7,371,105
|
|
|
368,555,271
|
|
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
Net income attributable to MPLX LP
|
$
|
233
|
|
|
$
|
156
|
|
|
$
|
121
|
|
Less: Preferred unit distributions
|
41
|
|
|
—
|
|
|
—
|
|
|||
General partner's incentive distribution rights and other
|
191
|
|
|
55
|
|
|
4
|
|
|||
Net income attributable to MPLX LP available to general and limited partners
|
$
|
1
|
|
|
$
|
101
|
|
|
$
|
117
|
|
|
|
|
|
|
|
||||||
General partner's two percent interest in net income attributable to MPLX LP
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
2
|
|
General partner's incentive distribution rights and other
|
191
|
|
|
55
|
|
|
4
|
|
|||
General partner's interest in net income attributable to MPLX LP
|
$
|
191
|
|
|
$
|
57
|
|
|
$
|
6
|
|
(In millions)
|
2016
|
|
2015
|
|
2014
|
||||||
General partner's distributions:
|
|
|
|
|
|
||||||
General partner's distributions
|
$
|
18
|
|
|
$
|
6
|
|
|
$
|
2
|
|
General partner's incentive distribution rights distributions
|
187
|
|
|
54
|
|
|
4
|
|
|||
Total general partner's distributions
|
205
|
|
|
60
|
|
|
6
|
|
|||
Limited partners' distributions:
|
|
|
|
|
|
||||||
Common unitholders
|
692
|
|
|
224
|
|
|
54
|
|
|||
Subordinated unitholders
|
—
|
|
|
31
|
|
|
52
|
|
|||
Total limited partners' distributions
|
692
|
|
|
255
|
|
|
106
|
|
|||
Preferred unit distributions
|
41
|
|
|
—
|
|
|
—
|
|
|||
Total cash distributions declared
|
$
|
938
|
|
|
$
|
315
|
|
|
$
|
112
|
|
(In millions)
|
Redeemable Preferred Units
|
||
Issuance of MPLX LP redeemable Preferred units on May 13, 2016
|
$
|
984
|
|
Net income allocated for May 13, 2016 through December 31, 2016
|
41
|
|
|
Distributions received by Preferred unitholders
|
(25
|
)
|
|
Balance at December 31, 2016
|
$
|
1,000
|
|
•
|
L&S - transports and stores crude oil and refined petroleum products. Segment information for prior periods includes HSM as it is an entity under common control.
|
•
|
G&P - gathers, processes and transports natural gas; gathers, transports, fractionates, stores and markets NGLs. This segment is the result of the MarkWest Merger on
December 4, 2015
discussed in more detail in Note
4
. Segment information for periods prior to the MarkWest Merger does not include amounts for these operations.
|
|
|
2016
|
||||||||||
(In millions)
|
|
L&S
|
|
G&P
|
|
Total
|
||||||
Revenues and other income:
|
|
|
|
|
|
|
||||||
Segment revenues
|
|
$
|
787
|
|
|
$
|
2,185
|
|
|
$
|
2,972
|
|
Segment other income
|
|
68
|
|
|
1
|
|
|
69
|
|
|||
Total segment revenues and other income
|
|
855
|
|
|
2,186
|
|
|
3,041
|
|
|||
Costs and expenses:
|
|
|
|
|
|
|
||||||
Segment cost of revenues
|
|
368
|
|
|
907
|
|
|
1,275
|
|
|||
Segment operating income before portion attributable to noncontrolling interest and Predecessor
|
|
487
|
|
|
1,279
|
|
|
1,766
|
|
|||
Segment portion attributable to noncontrolling interest and Predecessor
|
|
34
|
|
|
147
|
|
|
181
|
|
|||
Segment operating income attributable to MPLX LP
|
|
$
|
453
|
|
|
$
|
1,132
|
|
|
$
|
1,585
|
|
|
|
2015
|
||||||||||
(In millions)
|
|
L&S
|
|
G&P
|
|
Total
|
||||||
Revenues and other income:
|
|
|
|
|
|
|
||||||
Segment revenues
|
|
$
|
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 and Predecessor
|
|
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 and Predecessor
|
|
401
|
|
|
Segment portion attributable to noncontrolling interest and Predecessor
|
|
188
|
|
|
Segment operating income attributable to MPLX LP
|
|
$
|
213
|
|
(in millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Reconciliation to Income from operations:
|
|
|
|
|
|
|
||||||
L&S segment operating income attributable to MPLX LP
|
|
$
|
453
|
|
|
$
|
322
|
|
|
$
|
213
|
|
G&P segment operating income attributable to MPLX LP
|
|
1,132
|
|
|
76
|
|
|
—
|
|
|||
Segment operating income attributable to MPLX LP
|
|
1,585
|
|
|
398
|
|
|
213
|
|
|||
Segment portion attributable to unconsolidated affiliates
|
|
(173
|
)
|
|
(8
|
)
|
|
85
|
|
|||
Segment portion attributable to Predecessor
|
|
34
|
|
|
133
|
|
|
103
|
|
|||
(Loss) income from equity method investments
|
|
(74
|
)
|
|
3
|
|
|
—
|
|
|||
Other income - related parties
|
|
40
|
|
|
2
|
|
|
—
|
|
|||
Unrealized derivative (losses) gains
(1)
|
|
(36
|
)
|
|
4
|
|
|
—
|
|
|||
Depreciation and amortization
|
|
(546
|
)
|
|
(116
|
)
|
|
(75
|
)
|
|||
Impairment expense
|
|
(130
|
)
|
|
—
|
|
|
—
|
|
|||
General and administrative expenses
|
|
(193
|
)
|
|
(118
|
)
|
|
(81
|
)
|
|||
Income from operations
|
|
$
|
507
|
|
|
$
|
298
|
|
|
$
|
245
|
|
(in millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Reconciliation to Total revenues and other income:
|
|
|
|
|
|
|
||||||
Total segment revenues and other income
|
|
$
|
3,041
|
|
|
$
|
985
|
|
|
$
|
793
|
|
Revenue adjustment from unconsolidated affiliates
|
|
(402
|
)
|
|
(28
|
)
|
|
—
|
|
|||
(Loss) income from equity method investments
|
|
(74
|
)
|
|
3
|
|
|
—
|
|
|||
Other income - related parties
|
|
40
|
|
|
2
|
|
|
—
|
|
|||
Unrealized derivative losses
(1)
|
|
(15
|
)
|
|
(1
|
)
|
|
—
|
|
|||
Total revenues and other income
|
|
$
|
2,590
|
|
|
$
|
961
|
|
|
$
|
793
|
|
(in millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Reconciliation to Net income attributable to noncontrolling interests and Predecessor:
|
|
|
|
|
|
|
||||||
Segment portion attributable to noncontrolling interest and Predecessor
|
|
$
|
181
|
|
|
$
|
146
|
|
|
$
|
188
|
|
Portion of noncontrolling interests and Predecessor related to items below segment income from operations
|
|
(124
|
)
|
|
(48
|
)
|
|
(70
|
)
|
|||
Portion of operating income attributable to noncontrolling interests of unconsolidated affiliates
|
|
(32
|
)
|
|
(5
|
)
|
|
—
|
|
|||
Net income attributable to noncontrolling interests and Predecessor
|
|
$
|
25
|
|
|
$
|
93
|
|
|
$
|
118
|
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
L&S segment capital expenditures
|
|
$
|
443
|
|
|
$
|
212
|
|
|
$
|
141
|
|
G&P segment capital expenditures
|
|
894
|
|
|
100
|
|
|
—
|
|
|||
Total segment capital expenditures
|
|
1,337
|
|
|
312
|
|
|
141
|
|
|||
Less: Capital expenditures for Partnership-operated, non-wholly-owned subsidiaries in G&P segment
|
|
131
|
|
|
24
|
|
|
—
|
|
|||
Total capital expenditures
|
|
$
|
1,206
|
|
|
$
|
288
|
|
|
$
|
141
|
|
|
|
December 31,
|
||||||
(In millions)
|
|
2016
|
|
2015
|
||||
Cash and cash equivalents
|
|
$
|
234
|
|
|
$
|
43
|
|
L&S
|
|
2,115
|
|
|
1,842
|
|
||
G&P
|
|
14,297
|
|
|
14,219
|
|
||
Total assets
|
|
$
|
16,646
|
|
|
$
|
16,104
|
|
|
|
December 31,
|
||||||
(In millions)
|
|
2016
|
|
2015
|
||||
Current income tax expense:
|
|
|
|
|
||||
Federal
|
|
$
|
4
|
|
|
$
|
—
|
|
State
|
|
1
|
|
|
—
|
|
||
Total current
|
|
5
|
|
|
—
|
|
||
Deferred income tax (benefit) expense:
|
|
|
|
|
||||
Federal
|
|
(16
|
)
|
|
3
|
|
||
State
|
|
(1
|
)
|
|
(2
|
)
|
||
Total deferred
|
|
(17
|
)
|
|
1
|
|
||
(Benefit) provision for income tax
|
|
$
|
(12
|
)
|
|
$
|
1
|
|
|
|
December 31, 2016
|
||||||||||||||
(In millions)
|
|
MarkWest Hydrocarbon
(1)
|
|
Partnership
|
|
Eliminations
|
|
Consolidated
|
||||||||
(Loss) income before (benefit) provision for income tax
|
|
$
|
(41
|
)
|
|
$
|
285
|
|
|
$
|
2
|
|
|
$
|
246
|
|
Federal statutory rate
|
|
35
|
%
|
|
—
|
%
|
|
—
|
%
|
|
|
|||||
Federal income tax at statutory rate
|
|
(14
|
)
|
|
—
|
|
|
—
|
|
|
(14
|
)
|
||||
State income taxes net of federal benefit
|
|
(2
|
)
|
|
1
|
|
|
—
|
|
|
(1
|
)
|
||||
Provision on income from MPLX LP Class A units
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||
Change in state statutory rate
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
||||
Other
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||
(Benefit) provision for income tax
|
|
$
|
(13
|
)
|
|
$
|
1
|
|
|
$
|
—
|
|
|
$
|
(12
|
)
|
|
|
December 31, 2015
|
||||||||||||||
(In millions)
|
|
MarkWest Hydrocarbon
(1)
|
|
Partnership
|
|
Eliminations
|
|
Consolidated
|
||||||||
Income before provision (benefit) for income tax
|
|
$
|
9
|
|
|
$
|
240
|
|
|
$
|
1
|
|
|
$
|
250
|
|
Federal statutory rate
|
|
35
|
%
|
|
—
|
%
|
|
—
|
%
|
|
|
|||||
Federal income tax at statutory rate
|
|
3
|
|
|
—
|
|
|
—
|
|
|
3
|
|
||||
State income taxes net of federal benefit
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
||||
Provision on income from MPLX LP Class A units
|
|
1
|
|
|
—
|
|
|
—
|
|
|
1
|
|
||||
Other
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
(1
|
)
|
||||
Provision (benefit) for income tax
|
|
$
|
3
|
|
|
$
|
(2
|
)
|
|
$
|
—
|
|
|
$
|
1
|
|
(1)
|
MarkWest Hydrocarbon paid tax on its share of the Partnership’s income or loss as a result of its ownership of MPLX LP Class A units through September 1, 2016.
|
|
|
December 31,
|
||||||
(In millions)
|
|
2016
|
|
2015
|
||||
Deferred tax assets:
|
|
|
|
|
||||
Derivatives
|
|
$
|
—
|
|
|
$
|
9
|
|
Net operating loss carryforwards
|
|
—
|
|
|
62
|
|
||
Total deferred tax assets
|
|
—
|
|
|
71
|
|
||
Deferred tax liabilities:
|
|
|
|
|
||||
Property, plant and equipment
|
|
5
|
|
|
7
|
|
||
Investments in subsidiaries and affiliates
|
|
—
|
|
|
442
|
|
||
Total deferred tax liabilities
|
|
5
|
|
|
449
|
|
||
Net deferred tax liabilities
|
|
$
|
5
|
|
|
$
|
378
|
|
|
|
December 31,
|
||||||
(In millions)
|
|
2016
|
|
2015
|
||||
NGLs
|
|
$
|
2
|
|
|
$
|
3
|
|
Line fill
|
|
9
|
|
|
5
|
|
||
Spare parts, materials and supplies
|
|
43
|
|
|
43
|
|
||
Total inventories
|
|
$
|
54
|
|
|
$
|
51
|
|
|
|
Estimated
Useful Lives
|
|
December 31,
|
||||||
(In millions)
|
|
2016
|
|
2015
|
||||||
Natural gas gathering and NGL transportation pipelines and facilities
|
|
5 - 30 years
|
|
$
|
4,748
|
|
|
$
|
4,307
|
|
Processing, fractionation and storage facilities
|
|
25 - 30 years
|
|
3,467
|
|
|
3,185
|
|
||
Pipelines and related assets
|
|
19 - 42 years
|
|
1,492
|
|
|
1,128
|
|
||
Barges and towing vessels
|
|
20 years
|
|
479
|
|
|
475
|
|
||
Land, building, office equipment and other
|
|
3 - 30 years
|
|
701
|
|
|
606
|
|
||
Construction-in-progress
|
|
|
|
958
|
|
|
946
|
|
||
Total
|
|
|
|
11,845
|
|
|
10,647
|
|
||
Less accumulated depreciation
|
|
|
|
1,115
|
|
|
650
|
|
||
Property, plant and equipment, net
|
|
|
|
$
|
10,730
|
|
|
$
|
9,997
|
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||||||
(In millions)
|
Assets
|
|
Liabilities
|
|
Assets
|
|
Liabilities
|
||||||||
Significant other observable inputs (Level 2)
|
|
|
|
|
|
|
|
||||||||
Commodity contracts
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2
|
|
|
$
|
—
|
|
Significant unobservable inputs (Level 3)
|
|
|
|
|
|
|
|
||||||||
Commodity contracts
|
—
|
|
|
(6
|
)
|
|
7
|
|
|
—
|
|
||||
Embedded derivatives in commodity contracts
|
—
|
|
|
(54
|
)
|
|
—
|
|
|
(32
|
)
|
||||
Total carrying value in Consolidated Balance Sheets
|
$
|
—
|
|
|
$
|
(60
|
)
|
|
$
|
9
|
|
|
$
|
(32
|
)
|
Level 3 Instrument
|
|
Balance Sheet Classification
|
|
Unobservable Inputs
|
|
Value Range
|
|
Time Period
|
Commodity contracts
|
|
Liabilities
|
|
Forward ethane prices (per gallon)
(1)
|
|
$0.28 - $0.31
|
|
Jan. 17 - Dec. 17
|
|
|
|
|
Forward propane prices (per gallon)
(1)
|
|
$0.66 - $0.72
|
|
Jan. 17 - Dec. 17
|
|
|
|
|
Forward isobutane prices (per gallon)
(1)
|
|
$0.85 - $0.97
|
|
Jan. 17 - Dec. 17
|
|
|
|
|
Forward normal butane prices (per gallon)
(1)
|
|
$0.79 - $0.93
|
|
Jan. 17 - Dec. 17
|
|
|
|
|
Forward natural gasoline prices (per gallon)
(1)
|
|
$1.16 - $1.24
|
|
Jan. 17 - Dec. 17
|
|
|
|
|
|
|
|
|
|
Embedded derivatives in commodity contracts
|
|
Liabilities
|
|
Forward propane prices (per gallon)
(1)
|
|
$0.62 - $0.72
|
|
Jan. 17 - Dec. 22
|
|
|
|
|
Forward isobutane prices (per gallon)
(1)
|
|
$0.82 - $0.97
|
|
Jan. 17 - Dec. 22
|
|
|
|
|
Forward normal butane prices (per gallon)
(1)
|
|
$0.78 - $0.93
|
|
Jan. 17 - Dec. 22
|
|
|
|
|
Forward natural gasoline prices (per gallon)
(1)
|
|
$1.16 - $1.27
|
|
Jan. 17 - Dec. 22
|
|
|
|
|
Forward natural gas prices (per mmbtu)
(2)
|
|
$2.37 - $3.72
|
|
Jan. 17 - Dec. 22
|
|
|
|
|
Probability of renewal
(3)
|
|
50.0%
|
|
|
|
|
|
|
Probability of renewal for second 5-yr term
(3)
|
|
75.0%
|
|
|
(1)
|
NGL prices used in the valuations decrease in the early years and increase over time.
|
(2)
|
Natural gas prices used in the valuations are higher in the early years and decrease over time.
|
(3)
|
The producer counterparty to the embedded derivative has the option to renew the gas purchase agreement and the related keep-whole processing agreement for
two
successive
five
-year terms after 2022. The embedded gas purchase agreement cannot be renewed without the renewal of the related keep-whole processing agreement. Due to the significant number of years until the renewal options are exercisable and the high level of uncertainty regarding the counterparty’s future business strategy, the future commodity price environment, and the future competitive environment for midstream services in the Southern Appalachian region, management determined that a
50 percent
probability of renewal for the first five-year term and
75 percent
for the second five-year term are appropriate assumptions. Included in this assumption is a further extension of management’s estimates of future frac spreads through 2032.
|
•
|
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.
|
|
2016
|
|
2015
|
||||||||||||
(In millions)
|
Commodity Derivative Contracts (net)
|
|
Embedded Derivatives in Commodity Contracts (net)
|
|
Commodity Derivative Contracts (net)
|
|
Embedded Derivatives in Commodity Contracts (net)
|
||||||||
Fair value at beginning of period
|
$
|
7
|
|
|
$
|
(32
|
)
|
|
$
|
—
|
|
|
$
|
—
|
|
Net positions assumed in conjunction with the MarkWest Merger
|
—
|
|
|
—
|
|
|
7
|
|
|
(38
|
)
|
||||
Total (loss) gain (realized and unrealized) included in earnings
(1)
|
(13
|
)
|
|
(29
|
)
|
|
3
|
|
|
5
|
|
||||
Settlements
|
—
|
|
|
7
|
|
|
(3
|
)
|
|
1
|
|
||||
Fair value at end of period
|
$
|
(6
|
)
|
|
$
|
(54
|
)
|
|
$
|
7
|
|
|
$
|
(32
|
)
|
The amount of total (losses) gains for the period included in earnings attributable to the change in unrealized gains or losses relating to liabilities still held at end of period
|
$
|
(6
|
)
|
|
$
|
(26
|
)
|
|
$
|
2
|
|
|
$
|
5
|
|
(1)
|
Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in
Product sales
in the accompanying Consolidated Statements of Income. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in
Cost of revenues
and
Purchased product costs
.
|
|
December 31,
|
||||||||||||||
|
2016
|
|
2015
|
||||||||||||
(In millions)
|
Fair Value
|
|
Carrying Value
|
|
Fair Value
|
|
Carrying Value
|
||||||||
Long-term debt
|
$
|
4,953
|
|
|
$
|
4,422
|
|
|
$
|
5,212
|
|
|
$
|
5,255
|
|
SMR liability
|
$
|
108
|
|
|
$
|
96
|
|
|
$
|
99
|
|
|
$
|
100
|
|
Derivative contracts not designated as hedging instruments
|
|
Financial Position
|
|
Notional Quantity (net)
|
|
Crude Oil (bbl)
|
|
Short
|
|
36,500
|
|
Natural Gas (MMBtu)
|
|
Long
|
|
297,017
|
|
NGLs (gal)
|
|
Short
|
|
64,211,702
|
|
(In millions)
|
|
December 31, 2016
|
|
December 31, 2015
|
||||||||||||
Derivative contracts not designated as hedging instruments and their balance sheet location
|
|
Asset
|
|
Liability
|
|
Asset
|
|
Liability
|
||||||||
Commodity contracts
(1)
|
|
|
|
|
|
|
|
|
||||||||
Other current assets / other current liabilities
|
|
$
|
—
|
|
|
$
|
(13
|
)
|
|
$
|
9
|
|
|
$
|
(5
|
)
|
Other noncurrent assets / deferred credits and other liabilities
|
|
—
|
|
|
(47
|
)
|
|
—
|
|
|
(27
|
)
|
||||
Total
|
|
$
|
—
|
|
|
$
|
(60
|
)
|
|
$
|
9
|
|
|
$
|
(32
|
)
|
(1)
|
Includes embedded derivatives in commodity contracts as discussed above.
|
|
|
December 31,
|
||||||
(In millions)
|
|
2016
|
|
2015
|
||||
Product sales
|
|
|
|
|
||||
Realized gain
|
|
$
|
2
|
|
|
$
|
4
|
|
Unrealized loss
|
|
(15
|
)
|
|
(1
|
)
|
||
Total revenue: derivative (loss) gain from product sales
|
|
(13
|
)
|
|
3
|
|
||
Purchased product costs
|
|
|
|
|
||||
Realized loss
|
|
(5
|
)
|
|
—
|
|
||
Unrealized (loss) gain
|
|
(22
|
)
|
|
5
|
|
||
Total purchased product costs: derivative (loss) gain from product purchases
|
|
(27
|
)
|
|
5
|
|
||
Cost of revenues
|
|
|
|
|
||||
Realized loss
|
|
(3
|
)
|
|
—
|
|
||
Unrealized gain
|
|
1
|
|
|
—
|
|
||
Total cost of revenues: derivative loss from cost of revenues
|
|
(2
|
)
|
|
—
|
|
||
Total derivative (losses) gains
|
|
$
|
(42
|
)
|
|
$
|
8
|
|
|
|
December 31,
|
||||||
(In millions)
|
|
2016
|
|
2015
|
||||
MPLX LP:
|
|
|
|
|
||||
Bank revolving credit facility due 2020
|
|
$
|
—
|
|
|
$
|
877
|
|
Term loan facility due 2019
|
|
250
|
|
|
250
|
|
||
5.500% senior notes due 2023
|
|
710
|
|
|
710
|
|
||
4.500% senior notes due 2023
|
|
989
|
|
|
989
|
|
||
4.875% senior notes due 2024
|
|
1,149
|
|
|
1,149
|
|
||
4.000% senior notes due 2025
|
|
500
|
|
|
500
|
|
||
4.875% senior notes due 2025
|
|
1,189
|
|
|
1,189
|
|
||
Consolidated subsidiaries:
|
|
|
|
|
||||
MarkWest - 4.500% - 5.500% senior notes, due 2023 - 2025
|
|
63
|
|
|
63
|
|
||
MPL - capital lease obligations due 2020
|
|
8
|
|
|
9
|
|
||
Total
|
|
4,858
|
|
|
5,736
|
|
||
Unamortized debt issuance costs
|
|
(7
|
)
|
|
(8
|
)
|
||
Unamortized discount
(1)
|
|
(428
|
)
|
|
(472
|
)
|
||
Amounts due within one year
|
|
(1
|
)
|
|
(1
|
)
|
||
Total long-term debt due after one year
|
|
$
|
4,422
|
|
|
$
|
5,255
|
|
(1)
|
Includes
$420 million
and
$464 million
discount as of December 31, 2016 and 2015, respectively, related to the difference between the fair value and the principal amount of the assumed MarkWest debt.
|
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
|
(In millions)
|
|
December 31, 2016
|
|
December 31, 2015
|
||||
Assets
|
|
|
|
|
||||
Property, plant and equipment, net of accumulated depreciation
|
|
$
|
61
|
|
|
$
|
69
|
|
Liabilities
|
|
|
|
|
||||
Accrued liabilities
|
|
5
|
|
|
4
|
|
||
Deferred credits and other liabilities
|
|
91
|
|
|
96
|
|
(In millions)
|
L&S
|
|
G&P
|
|
Total
|
||||||
Gross goodwill as of December 31, 2014
|
$
|
116
|
|
|
$
|
—
|
|
|
$
|
116
|
|
Accumulated impairment losses
|
—
|
|
|
—
|
|
|
—
|
|
|||
Balance as of December 31, 2014
|
116
|
|
|
—
|
|
|
116
|
|
|||
Acquisitions
|
—
|
|
|
2,454
|
|
|
2,454
|
|
|||
Gross goodwill as of December 31, 2015
|
116
|
|
|
2,454
|
|
|
2,570
|
|
|||
Accumulated impairment losses
|
—
|
|
|
—
|
|
|
—
|
|
|||
Balance as of December 31, 2015
|
116
|
|
|
2,454
|
|
|
2,570
|
|
|||
Purchase price allocation adjustments
(1)
|
—
|
|
|
(241
|
)
|
|
(241
|
)
|
|||
Impairment losses
|
—
|
|
|
(130
|
)
|
|
(130
|
)
|
|||
Balance as of December 31, 2016
|
$
|
116
|
|
|
$
|
2,083
|
|
|
$
|
2,199
|
|
|
|
|
|
|
|
||||||
Gross goodwill as of December 31, 2016
|
$
|
116
|
|
|
$
|
2,213
|
|
|
$
|
2,329
|
|
Accumulated impairment losses
|
—
|
|
|
(130
|
)
|
|
(130
|
)
|
|||
Balance as of December 31, 2016
|
$
|
116
|
|
|
$
|
2,083
|
|
|
$
|
2,199
|
|
(1)
|
See Note
4
for further discussion on purchase price allocation adjustments.
|
|
|
December 31, 2016
|
|
December 31, 2015
|
|
|
||||||||||||||||||||
(In millions)
|
|
Gross
|
|
Accumulated Amortization
|
|
Net
|
|
Gross
|
|
Accumulated Amortization
|
|
Net
|
|
Useful Life
|
||||||||||||
L&S
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
N/A
|
G&P
|
|
533
|
|
|
(41
|
)
|
|
492
|
|
|
468
|
|
|
(2
|
)
|
|
466
|
|
|
11-25 years
|
||||||
|
|
$
|
533
|
|
|
$
|
(41
|
)
|
|
$
|
492
|
|
|
$
|
468
|
|
|
$
|
(2
|
)
|
|
$
|
466
|
|
|
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Net cash provided by operating activities included:
|
|
|
|
|
|
|
||||||
Interest paid (net of amounts capitalized)
|
|
$
|
212
|
|
|
$
|
13
|
|
|
$
|
3
|
|
Income taxes paid
|
|
3
|
|
|
—
|
|
|
—
|
|
|||
Non-cash investing and financing activities:
|
|
|
|
|
|
|
||||||
Net transfers of property, plant and equipment from materials and supplies inventories
|
|
$
|
4
|
|
|
$
|
5
|
|
|
$
|
1
|
|
Contribution - common units issued
(1)
|
|
669
|
|
|
—
|
|
|
200
|
|
|||
Acquisition:
|
|
|
|
|
|
|
||||||
Fair value of MPLX LP units issued
(1)
|
|
—
|
|
|
7,326
|
|
|
—
|
|
|||
Payable to seller
|
|
—
|
|
|
50
|
|
|
—
|
|
(1)
|
See Note
4
.
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
(Decrease) increase in capital accruals
|
|
$
|
(25
|
)
|
|
$
|
26
|
|
|
$
|
11
|
|
|
|
Phantom Units
|
|||||||||
|
|
Number
of Units
|
|
Weighted
Average
Fair Value
|
|
Aggregate Intrinsic Value (In millions)
|
|||||
Outstanding at December 31, 2015
|
|
1,031,219
|
|
|
$
|
35.49
|
|
|
|
||
Granted
|
|
458,727
|
|
|
29.42
|
|
|
|
|||
Settled
|
|
(166,576
|
)
|
|
38.12
|
|
|
|
|||
Forfeited
|
|
(149,959
|
)
|
|
32.72
|
|
|
|
|||
Outstanding at December 31, 2016
|
|
1,173,411
|
|
|
33.09
|
|
|
|
|||
Vested and expected to vest at December 31, 2016
|
|
1,157,676
|
|
|
33.12
|
|
|
$
|
40
|
|
|
Convertible at December 31, 2016
|
|
494,189
|
|
|
34.11
|
|
|
$
|
17
|
|
|
|
Phantom Units
|
||||||
|
|
Intrinsic Value of Units Issued During the Period (in millions)
|
|
Weighted Average Grant Date Fair Value of Units Granted During the Period
|
||||
2016
|
|
$
|
5
|
|
|
$
|
29.42
|
|
2015
|
|
3
|
|
|
35.00
|
|
||
2014
|
|
1
|
|
|
49.56
|
|
|
|
Performance Units
|
|||||
|
|
Number of Units
|
|
Weighted
Average Fair Value |
|||
Outstanding at December 31, 2015
|
|
1,521,392
|
|
|
$
|
1.00
|
|
Granted
|
|
789,375
|
|
|
0.63
|
|
|
Settled
|
|
(458,011
|
)
|
|
0.79
|
|
|
Forfeited
|
|
(53,507
|
)
|
|
1.06
|
|
|
Outstanding at December 31, 2016
|
|
1,799,249
|
|
|
0.89
|
|
|
|
2016
|
|
2015
|
|
2014
|
||||||
Risk-free interest rate
|
|
0.96
|
%
|
|
0.95
|
%
|
|
0.63
|
%
|
|||
Look-back period
|
|
2.83 years
|
|
|
2.84 years
|
|
|
2.84 years
|
|
|||
Expected volatility
|
|
47.59
|
%
|
|
30.12
|
%
|
|
17.17
|
%
|
|||
Grant date fair value of performance units granted
|
|
$
|
0.63
|
|
|
$
|
1.03
|
|
|
$
|
1.16
|
|
(In millions)
|
Intercompany
|
|
Third Party
|
|
Total
|
||||||
2017
|
$
|
101
|
|
|
$
|
197
|
|
|
$
|
298
|
|
2018
|
101
|
|
|
200
|
|
|
301
|
|
|||
2019
|
101
|
|
|
202
|
|
|
303
|
|
|||
2020
|
101
|
|
|
201
|
|
|
302
|
|
|||
2021
|
—
|
|
|
185
|
|
|
185
|
|
|||
2022 and thereafter
|
—
|
|
|
460
|
|
|
460
|
|
|||
Total minimum future rentals
|
$
|
404
|
|
|
$
|
1,445
|
|
|
$
|
1,849
|
|
|
|
December 31,
|
||||||
(In millions)
|
|
2016
|
|
2015
|
||||
Natural gas gathering and NGL transportation pipelines and facilities
|
|
$
|
650
|
|
|
$
|
619
|
|
Natural gas processing facilities
|
|
844
|
|
|
753
|
|
||
Barges
|
|
388
|
|
|
360
|
|
||
Towing vessels
|
|
91
|
|
|
91
|
|
||
Construction in progress
|
|
219
|
|
|
110
|
|
||
Property, plant and equipment
|
|
2,192
|
|
|
1,933
|
|
||
Less: accumulated depreciation
|
|
(266
|
)
|
|
(170
|
)
|
||
Total property, plant and equipment
|
|
$
|
1,926
|
|
|
$
|
1,763
|
|
(In millions)
|
2016
|
|
2015
|
||||
ARO at beginning of period
|
$
|
17
|
|
|
$
|
—
|
|
Liabilities assumed in conjunction with the MarkWest Merger
|
—
|
|
|
15
|
|
||
Liabilities incurred
|
8
|
|
|
2
|
|
||
Adjustments to AROs
|
(1
|
)
|
|
—
|
|
||
Accretion expense
|
1
|
|
|
—
|
|
||
ARO at end of period
|
$
|
25
|
|
|
$
|
17
|
|
(In millions)
|
|
Capital
Lease
Obligations
|
|
Operating
Lease
Obligations
|
||||
2017
|
|
$
|
1
|
|
|
$
|
61
|
|
2018
|
|
1
|
|
|
51
|
|
||
2019
|
|
2
|
|
|
42
|
|
||
2020
|
|
5
|
|
|
37
|
|
||
2021
|
|
—
|
|
|
36
|
|
||
Later years
|
|
—
|
|
|
76
|
|
||
Total minimum lease payments
|
|
9
|
|
|
$
|
303
|
|
|
Less: imputed interest costs
|
|
1
|
|
|
|
|||
Present value of net minimum lease payments
|
|
$
|
8
|
|
|
|
(In millions)
|
|
2016
|
|
2015
|
|
2014
|
||||||
Minimum rental expense
|
|
$
|
57
|
|
|
$
|
21
|
|
|
$
|
17
|
|
|
|
2016
(3)
|
|
2015
|
||||||||||||||||||||||||||||
(In millions, except per unit data)
|
|
1st Qtr.
(1)
|
|
2nd Qtr.
(2)
|
|
3rd Qtr.
|
|
4th Qtr.
|
|
1st Qtr.
|
|
2nd Qtr.
|
|
3rd Qtr.
|
|
4th Qtr.
(3)
|
||||||||||||||||
Total revenues and other income
|
|
$
|
609
|
|
|
$
|
564
|
|
|
$
|
703
|
|
|
$
|
714
|
|
|
$
|
201
|
|
|
$
|
213
|
|
|
$
|
214
|
|
|
$
|
333
|
|
Income from operations
|
|
27
|
|
|
76
|
|
|
207
|
|
|
197
|
|
|
74
|
|
|
82
|
|
|
68
|
|
|
74
|
|
||||||||
Net (loss) income
|
|
(37
|
)
|
|
20
|
|
|
143
|
|
|
132
|
|
|
68
|
|
|
76
|
|
|
63
|
|
|
42
|
|
||||||||
Net (loss) income attributable to MPLX LP
|
|
(60
|
)
|
|
19
|
|
|
141
|
|
|
133
|
|
|
46
|
|
|
51
|
|
|
41
|
|
|
18
|
|
||||||||
Net (loss) income attributable to MPLX LP per limited partner unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Common - basic
|
|
$
|
(0.33
|
)
|
|
$
|
(0.11
|
)
|
|
$
|
0.22
|
|
|
$
|
0.17
|
|
|
$
|
0.46
|
|
|
$
|
0.50
|
|
|
$
|
0.41
|
|
|
$
|
(0.14
|
)
|
Common - diluted
|
|
(0.33
|
)
|
|
(0.11
|
)
|
|
0.21
|
|
|
0.17
|
|
|
0.46
|
|
|
0.50
|
|
|
0.41
|
|
|
(0.14
|
)
|
||||||||
Subordinated - basic and diluted
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.46
|
|
|
0.50
|
|
|
—
|
|
|
—
|
|
||||||||
Cash distributions declared per limited partner common unit
|
|
$
|
0.5050
|
|
|
$
|
0.5100
|
|
|
$
|
0.5150
|
|
|
$
|
0.5200
|
|
|
$
|
0.4100
|
|
|
$
|
0.4400
|
|
|
$
|
0.4700
|
|
|
$
|
0.5000
|
|
Distributions declared:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||
Limited partner units - Public
|
|
$
|
127
|
|
|
$
|
131
|
|
|
$
|
135
|
|
|
$
|
140
|
|
|
$
|
10
|
|
|
$
|
10
|
|
|
$
|
11
|
|
|
$
|
120
|
|
Limited partner units - MPC
|
|
29
|
|
|
41
|
|
|
44
|
|
|
45
|
|
|
23
|
|
|
25
|
|
|
27
|
|
|
29
|
|
||||||||
General partner units - MPC
|
|
4
|
|
|
4
|
|
|
5
|
|
|
5
|
|
|
1
|
|
|
1
|
|
|
1
|
|
|
3
|
|
||||||||
Incentive distribution rights - MPC
|
|
40
|
|
|
46
|
|
|
49
|
|
|
52
|
|
|
3
|
|
|
6
|
|
|
8
|
|
|
37
|
|
||||||||
Redeemable preferred units
|
|
—
|
|
|
9
|
|
|
16
|
|
|
16
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||||
Total distributions declared
|
|
$
|
200
|
|
|
$
|
231
|
|
|
$
|
249
|
|
|
$
|
258
|
|
|
$
|
37
|
|
|
$
|
42
|
|
|
$
|
47
|
|
|
$
|
189
|
|
(1)
|
First quarter 2016 results included goodwill impairment expense of
$129 million
. See Note
18
for more information.
|
(2)
|
Second quarter 2016 results included impairment expense related to equity method investments of
$89 million
. See Note
5
for more information.
|
(3)
|
These amounts include results from the MarkWest Merger which closed on December 4, 2015. See Note
4
for more information on the MarkWest Merger.
|
Name
|
|
Age as of
January 31, 2017
|
|
Position with MPLX GP LLC
|
|
Gary R. Heminger
|
|
63
|
|
|
Chairman of the Board of Directors and Chief Executive Officer
|
Donald C. Templin
|
|
53
|
|
|
Director and President
|
Pamela K.M. Beall
|
|
60
|
|
|
Director, Executive Vice President and Chief Financial Officer
|
Michael L. Beatty
|
|
69
|
|
|
Director
|
David A. Daberko
|
|
71
|
|
|
Director
|
Timothy T. Griffith
|
|
47
|
|
|
Director
|
Christopher A. Helms
|
|
62
|
|
|
Director
|
Garry L. Peiffer
|
|
65
|
|
|
Director
|
Dan D. Sandman
|
|
68
|
|
|
Director
|
Frank M. Semple
|
|
65
|
|
|
Director
|
John P. Surma
|
|
62
|
|
|
Director
|
C. Richard Wilson
|
|
72
|
|
|
Director
|
C. Corwin Bromley
|
|
59
|
|
|
Executive Vice President and General Counsel (Chief Legal Officer)
|
Gregory S. Floerke
|
|
53
|
|
|
Executive Vice President and Chief Operating Officer, MarkWest Operations
|
Randy S. Nickerson
|
|
55
|
|
|
Executive Vice President and Chief Commercial Officer, MarkWest Assets
|
Paula L. Rosson
|
|
50
|
|
|
Senior Vice President and Chief Accounting Officer
|
Timothy J. Aydt
(1)
|
|
53
|
|
|
Vice President, Operations
|
Molly R. Benson
(1)
|
|
50
|
|
|
Vice President, Corporate Secretary and Chief Compliance Officer
|
Peter Gilgen
(1)
|
|
60
|
|
|
Vice President and Treasurer
|
Frank A. Quintana
(1)
|
|
43
|
|
|
Vice President, Tax
|
John S. Swearingen
|
|
57
|
|
|
Vice President, Crude Oil and Refined Products Pipelines
|
(1)
|
Corporate officer.
|
Audit Committee Chair
|
|
auditchair@mplx.com
|
Conflicts Committee Chair
|
|
conflictschair@mplx.com
|
Independent Directors
|
|
non-managedirectors@mplx.com
|
•
|
act with honesty and integrity, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;
|
•
|
provide full, fair, accurate, timely and understandable disclosure in reports and documents filed with, or submitted to, the SEC, and in other public communications;
|
•
|
comply with applicable laws, governmental rules and regulations, including insider trading laws; and
|
•
|
promote the prompt internal reporting of potential violations or other concerns related to this code of ethics to the chair of the audit committee and to the appropriate person or persons identified in the code of business conduct.
|
Name
|
|
Title
|
Gary R. Heminger
|
|
Chairman of the Board and Chief Executive Officer
|
Pamela K.M. Beall
|
|
Executive Vice President and Chief Financial Officer
|
Nancy K. Buese
|
|
Former Executive Vice President and Chief Financial Officer
|
Donald C. Templin
|
|
President
|
C. Corwin Bromley
|
|
Executive Vice President and General Counsel (Chief Legal Officer)
|
Gregory S. Floerke
|
|
Executive Vice President and Chief Operating Officer, MarkWest Operations
|
Name
|
|
Title
|
|
Previous Base Salary ($)
|
|
Base Salary Effective Dec. 31, 2016 ($)
|
|
Increase
(%)
|
|
Pamela K.M. Beall
|
|
Executive Vice President and Chief Financial Officer
|
|
475,000
|
|
|
525,000
|
|
10.5
|
Nancy K. Buese
|
|
Former Executive Vice President and Chief Financial Officer
|
|
450,000
|
|
|
475,000
|
|
5.6
|
Donald C. Templin
|
|
Executive Vice President and President MPLX
|
|
675,000
|
|
|
720,000
|
|
6.7
|
C. Corwin Bromley
|
|
Executive Vice President and General Counsel (Chief Legal Officer)
|
|
450,000
|
|
|
465,000
|
|
3.3
|
Gregory S. Floerke
|
|
Executive Vice President and Chief Operating Officer, MarkWest Operations
|
|
400,000
|
|
|
420,000
|
|
5.0
|
Performance Metric
|
|
Description
|
|
Type of Measure
|
Operating Income Per Barrel
(1)
|
|
Measures domestic operating income per barrel of crude oil throughput, adjusted for unusual business items and accounting changes. This metric compares a group of nine integrated or downstream companies, including MPC.
|
|
Financial (relative)
|
EBITDA
(2)
|
|
As derived from the consolidated financial statements and as disclosed to investors as part of the quarterly earnings materials.
|
|
Financial (absolute)
|
Mechanical Availability
(3)
|
|
Measures the mechanical availability and reliability of the processing equipment in MPC’s refining, pipeline, terminal and marine operations.
|
|
Operational (absolute)
|
Selling, General and Administrative Costs (SG&A)
(4)
|
|
Actual selling, general and administrative expenses adjusted for certain items.
|
|
Financial (absolute)
|
MPLX LP/MarkWest Commercial Synergies
|
|
Measures revenue enhancements or cost savings at either MPLX LP or MPC resulting from the combination for which committed actions were taken in 2016.
|
|
Financial
(absolute)
|
Responsible Care
|
|
The metrics below measure MPC’s success in meeting MPC’s goals for the health and safety of its employees, contractors and neighboring communities, while continuously improving on MPC’s environmental stewardship commitment by minimizing MPC’s environmental impact.
|
|
|
Marathon Safety Performance Index
(5)
|
|
Measurement of MPC’s success and commitment to employee safety. Goals are set annually at best-in-class industry performance, focusing on continual improvement. This includes common industry metrics such as Occupational Safety and Health Administration (or OSHA) Recordable Incident Rates and Days Away Rates.
|
|
Operational (absolute)
|
Process Safety Events Score
|
|
Measures the success of MPC’s ability to identify, understand and control process hazards, which can be defined as unplanned or uncontrolled releases of highly hazardous chemicals or materials that have the potential to cause catastrophic fires, explosions, injury, plant damage and high-potential near misses or toxic exposures.
|
|
Operational (absolute)
|
Designated Environmental Incidents
|
|
Measures environmental performance and consists of tracking certain: a) releases of hazardous substances into air, water or land; b) permit exceedences; and c) government agency enforcement actions.
|
|
Operational (absolute)
|
Quality
|
|
Measures the impact of product quality incidents and cumulative costs to MPC (no Category 4 Incident, and costs of Category 3 Incidents).
(6)
|
|
Operational (absolute)
|
(1)
|
This is a per barrel measure of throughput - U.S. downstream segment income adjusted for certain items. It includes a total of nine comparator companies (including MPC). Comparator company income is adjusted for special items or other like items as adjusted by MPC. The comparator companies for 2016 were: BP p.l.c.; Chevron Corporation; ExxonMobil Corporation; HollyFrontier Corporation; PBF Energy; Phillips 66; Tesoro Corporation; and Valero Energy Corporation. This is a non-GAAP performance metric which is calculated as income before taxes, as presented in MPC’s audited consolidated financial statements, as adjusted, divided by the total number of barrels of crude oil throughput at the peer’s respective U.S. refinery operations. To ensure consistency of this metric when comparing results to the comparator group, adjustments to MPC’s and peer company segment income before taxes are sometimes necessary to remove certain items reflected in their results such as the gain/loss on assets, certain asset impairment expense or tax law changes.
|
(2)
|
This is a non-GAAP performance metric. It is calculated as earnings before interest and financing costs, interest income, income taxes, depreciation and amortization expense, impairment expense and inventory market valuation adjustments.
|
(3)
|
Mechanical availability represents the percentage of capacity available for critical downstream equipment to perform its primary function for the full year.
|
(4)
|
This represents SG&A costs adjusted to exclude costs related to employee bonus program accruals, pension settlement expense, insurance expense and certain other expenses.
|
(5)
|
This metric excluded Speedway. In the event of a fatality, payout is determined by the MPC Compensation Committee. The OSHA Recordable Incident Rate is calculated by taking the total number of OSHA recordable incidents, multiplied by 200,000 and divided by the total number of hours worked.
|
(6)
|
A Category 4 Incident is one that involves a fatality. Category 3 Incidents include those in which: MPC incurs out-of-pocket costs for incident response and recovery activities, mitigation of customer claims or regulatory penalties in excess of $50,000; a media advisory is issued; or the extenuating circumstances are deemed to be of such severity by MPC’s Quality Committee that a recommendation for this category is made to the MPC Quality Steering Committee and is subsequently approved.
|
Performance Metric
|
|
Threshold Level
|
|
Target Level
|
|
Maximum Level
|
|
Performance Achieved
|
|
Target Weighting
|
|
Performance Achieved
|
Operating Income Per Barrel
|
|
5
th
or 6
th
Position
|
|
3
rd
or 4
th
Position
|
|
1
st
or 2
nd
Position
|
|
3
rd
Position (100% of target)
|
|
20.0%
|
|
20.0%
|
EBITDA
(1)
|
|
$3,650
|
|
$4,750
|
|
$6,670
|
|
$4,501 (89% of target)
|
|
10.0%
|
|
8.9%
|
Mechanical Availability
|
|
92.4%
|
|
93.4%
|
|
94.4%
|
|
94.9% (200% of target)
|
|
10.0%
|
|
20.0%
|
Selling, General and Administrative Costs
(1)
|
|
$1,339
|
|
$1,309
|
|
$1,279
|
|
$1,243 (200% of target)
|
|
5.0%
|
|
10.0%
|
MPLX LP/MarkWest Commercial Synergies
|
|
$25,000,000
|
|
$35,000,000
|
|
$50,000,000
|
|
$75,500,000 (200% of target)
|
|
5.0%
|
|
10.0%
|
Responsible Care
|
|
|
|
|
|
|
|
|
|
|
|
|
Marathon Safety Performance Index
|
|
.90
|
|
.60
|
|
.40
|
|
0.95 (0% of target)
|
|
5.0%
|
|
0.0%
|
Process Safety Events Score
|
|
120
|
|
80
|
|
60
|
|
56 (200% of target)
|
|
5.0%
|
|
10.0%
|
Designated Environmental Incidents
|
|
72
|
|
51
|
|
30
|
|
30 (200% of target)
|
|
5.0%
|
|
10.0%
|
Quality
|
|
$500,000
|
|
$250,000
|
|
$125,000
|
|
$135,000 (192% of target)
|
|
5.0%
|
|
9.6%
|
|
|
|
|
|
|
|
|
Total
|
|
70.0%
|
|
98.5%
|
(1)
|
Represented in millions.
|
|
|
Mr. Templin
|
|
Ms. Beall
|
|
Mr. Floerke
|
|
Mr. Bromley
|
Talent development, retention, succession and acquisition
|
|
ü
|
|
ü
|
|
ü
|
|
ü
|
Enhancement of unitholder value through return of capital and unlocking midstream asset value
|
|
ü
|
|
ü
|
|
ü
|
|
|
System integration, optimization and debottlenecking
|
|
ü
|
|
|
|
ü
|
|
ü
|
Growth through organic expansion and acquisition opportunities
|
|
ü
|
|
ü
|
|
ü
|
|
ü
|
Preparation of assets for potential dropdown to MPLX LP
|
|
ü
|
|
ü
|
|
ü
|
|
ü
|
Progress on diversity initiatives
|
|
ü
|
|
ü
|
|
ü
|
|
ü
|
•
|
net income attributable to MPC decreased 59 percent to $1.17 billion in 2016 from $2.85 billion in 2015;
|
•
|
MPC’s TSR for 2016 of -1.8 percent compared to the median TSR of -1.5 percent for its performance unit peer group;
|
•
|
sustained focus on shareholder returns with $916 million returned to shareholders through dividends and share repurchases; and
|
•
|
continued integration of the MarkWest assets into the MPLX LP portfolio.
|
Annualized
Base Salary
(as of 12/31/16)
|
X
|
Bonus Target
(as a percent of base salary)
|
X
|
Final Award Percent
(as a percent of target)
|
=
|
Final
Award
|
|
Name
|
|
Annualized Base Salary (as of 12/31/16) ($)
(1)
|
|
Bonus Target as a % of Base Salary (%)
|
|
Target Bonus ($)
|
|
Final Award as a % of Target (%)
|
|
Final Award ($)
(2)
|
Pamela K.M. Beall
|
|
525,000
|
|
70
|
|
367,500
|
|
149.6
|
|
550,000
|
Donald C. Templin
|
|
720,000
|
|
100
|
|
720,000
|
|
162.5
|
|
1,170,000
|
C. Corwin Bromley
|
|
465,000
|
|
80
|
|
372,000
|
|
120.9
|
|
450,000
|
Gregory S. Floerke
|
|
420,000
|
|
80
|
|
336,000
|
|
126.4
|
|
425,000
|
(1)
|
Mr. Templin’s salary reflects his allocation of 90 percent to our General Partner.
|
(2)
|
The final award is rounded to the nearest $5,000.
|
Form of LTI Award
|
|
Form of Settlement
|
|
Compensation Realized
|
Performance Units
|
|
25 percent in MPLX LP common units and 75 percent in cash
|
|
$0.00 to $2.00 per unit based on our relative ranking among a group of peer companies
|
Phantom Units
|
|
MPLX LP common units
|
|
Value of common units upon vesting
|
TUR
Percentile
|
|
Payout
(% of Target)*
|
100
th
(Highest)
|
|
200%
|
50
th
|
|
100%
|
25
th
|
|
50%
|
Below 25
th
|
|
0%
|
*
|
Payout for performance between quartiles will be determined using linear interpolation.
|
Performance Period
|
|
Actual TUR
(%)
|
|
Position
|
|
Percentile Ranking (%)
|
|
Payout
(% of target)
|
January 1, 2014 - December 31, 2014
|
|
68.4
|
|
2
nd
|
|
90.91
|
|
181.82
|
January 1, 2015 - December 31, 2015
|
|
(45.3)
|
|
10
th
|
|
10.00
|
|
—
|
January 1, 2016 - December 31, 2016
|
|
3.2
|
|
9
th
|
|
20.00
|
|
—
|
January 1, 2014 - December 31, 2016
|
|
(3.7)
|
|
9
th
|
|
20.00
|
|
—
|
|
|
|
|
|
|
Average:
|
|
45.46
|
Name
|
|
Target Number of Performance Units
|
|
Compensation Committee Approved Payout
($)
|
Gary R. Heminger
|
|
1,000,000
|
|
454,600
|
Pamela K.M. Beall
|
|
85,000
|
|
38,641
|
Donald C. Templin
|
|
220,000
|
|
100,012
|
- Buckeye Partners, L.P.
|
|
- Plains All American Pipeline, L.P.
|
- Enbridge Energy Partners, L.P.
|
|
- Sunoco Logistics Partners L.P.
|
- Energy Transfer Partners, L.P.
|
|
- Tesoro Logistics LP
|
- Enterprise Products Partners L.P.
|
|
- Valero Energy Partners LP
|
- Magellan Midstream Partners, L.P.
|
|
- Western Gas Partners, LP
|
- ONEOK Partners, L.P.
|
|
- Williams Partners L.P.
|
- Phillips 66 Partners LP
|
|
|
MPC Performance Units
|
|
25 percent in MPC common stock and 75 percent cash
|
|
$0.00 to $2.00 per unit based on its relative TSR ranking among a group of peer companies
|
MPC Stock Options
|
|
Stock
|
|
Stock price appreciation from grant date to exercise date
|
MPC Restricted Stock
|
|
Stock
|
|
Full value of stock upon vesting
|
TUR Percentile
|
|
Payout (% of Target)*
|
100
th
(Highest)
|
|
200%
|
50
th
|
|
100%
|
25
th
|
|
50%
|
Below 25
th
|
|
0%
|
*
|
Payout for performance between quartiles will be determined using linear interpolation.
|
Performance Period
|
|
Actual TSR (%)
|
|
Position
|
|
Percentile Ranking (%)
|
|
Payout (% of target)
|
January 1, 2014 - December 31, 2014
|
|
3.2
|
|
3
rd
|
|
71.43
|
|
142.86
|
January 1, 2015 - December 31, 2015
|
|
20.2
|
|
4
th
|
|
57.14
|
|
114.28
|
January 1, 2016 - December 31, 2016
|
|
(1.8)
|
|
5
th
|
|
42.85
|
|
85.70
|
January 1, 2014 - December 31, 2016
|
|
21.5
|
|
4
th
|
|
57.14
|
|
114.28
|
|
|
|
|
|
|
Average:
|
|
114.28
|
Name
|
|
Target Number of Performance Shares
|
|
MPC Compensation Committee Approved Payout ($)
|
Pamela K.M. Beall
|
|
272,000
|
|
310,842
|
•
|
Chevron Corporation
|
•
|
HollyFrontier Corporation
|
•
|
PBF Energy
|
•
|
Valero Energy Corporation
|
•
|
Phillips 66
|
•
|
Tesoro Corporation
|
•
|
S&P 500 Energy Index
|
•
|
based on the executive’s position and responsibilities, and
|
•
|
expected to be reached within five years of the executive officer’s assumption of the position.
|
•
|
Chairman of the Board and Chief Executive Officer - 25,000 units;
|
•
|
President - 20,000 units;
|
•
|
Executive Vice President - 15,000 units;
|
•
|
Senior Vice President - 10,000 units; and
|
•
|
Vice President - 5,000 units.
|
•
|
knowingly engaged in misconduct;
|
•
|
was grossly negligent with respect to misconduct;
|
•
|
knowingly failed or was grossly negligent in failing to prevent misconduct; or
|
•
|
engaged in fraud, embezzlement or other similar misconduct materially detrimental to us.
|
|
|
Salary
(2)
|
Stock
Awards
(3)
|
Option Awards
(3)
|
Non-Equity Incentive Plan Compensation
(4)
|
Change in Pension Value and Nonqualified Deferred Compensation Earnings
(5)
|
All Other Compensation
(6)
|
Total
|
|||||||
Name and Principal Position
(1)
|
Year
|
($)
|
($)
|
($)
|
($)
|
($)
|
($)
|
($)
|
|||||||
Gary R. Heminger
Chairman of the Board and Chief Executive Officer
|
2016
|
1,220,000
|
|
1,801,593
|
|
—
|
|
—
|
|
—
|
|
—
|
|
3,021,593
|
|
2015
|
1,220,000
|
|
2,239,071
|
|
—
|
|
—
|
|
—
|
|
—
|
|
3,459,071
|
|
|
2014
|
1,175,000
|
|
2,160,047
|
|
—
|
|
—
|
|
—
|
|
—
|
|
3,335,047
|
|
|
Pamela K.M. Beall
Executive Vice President and Chief Financial Officer
|
2016
|
499,667
|
|
530,482
|
|
170,008
|
|
550,000
|
|
226,408
|
|
86,067
|
|
2,062,632
|
|
2015
|
234,375
|
|
173,033
|
|
—
|
|
262,500
|
|
56,514
|
|
39,282
|
|
765,704
|
|
|
2014
|
225,000
|
|
183,603
|
|
—
|
|
—
|
|
—
|
|
—
|
|
408,603
|
|
|
Nancy K. Buese
Former Executive Vice President and Chief Financial Officer
|
2016
|
389,583
|
|
—
|
|
—
|
|
—
|
|
71,037
|
|
75,762
|
|
536,382
|
|
2015
|
34,615
|
|
4,191,872
|
|
—
|
|
—
|
|
—
|
|
—
|
|
4,226,487
|
|
|
Donald C. Templin
President
|
2016
|
720,000
|
|
1,228,353
|
|
—
|
|
1,170,000
|
|
217,355
|
|
134,794
|
|
3,470,502
|
|
2015
|
515,000
|
|
508,906
|
|
—
|
|
—
|
|
—
|
|
—
|
|
1,023,906
|
|
|
2014
|
475,000
|
|
475,212
|
|
—
|
|
—
|
|
—
|
|
—
|
|
950,212
|
|
|
C. Corwin Bromley
Executive Vice President and General Counsel
|
2016
|
461,250
|
|
—
|
|
—
|
|
450,000
|
|
90,448
|
|
61,251
|
|
1,062,949
|
|
2015
|
34,615
|
|
3,525,011
|
|
—
|
|
—
|
|
—
|
|
—
|
|
3,559,626
|
|
|
Gregory S. Floerke
Executive Vice President and Chief Operating Officer, MarkWest Operations
|
2016
|
415,000
|
|
—
|
|
—
|
|
425,000
|
|
62,847
|
|
55,179
|
|
958,026
|
|
2015
|
30,769
|
|
3,092,492
|
|
—
|
|
—
|
|
—
|
|
—
|
|
3,123,261
|
|
(1)
|
Except where indicated, amounts shown reflect only compensation amounts allocable to MPLX LP and do not include compensation amounts for other services that are not allocable to MPLX LP. For 2016, compensation amounts were allocated based on the relative percentage each NEO's business time was dedicated to MPLX LP’s business. For 2016, percentage allocations for each NEO were as follows: Mr. Templin - 90 percent; Mses. Beall and Buese and Messrs. Bromley and Floerke - 100 percent.
|
(2)
|
The amounts shown in this column reflect the annualized fixed fee for Mr. Heminger for 2016, 2015, and 2014; for Mr. Templin for 2015 and 2014; and for Ms. Beall for 2014. The amounts shown for Messrs. Bromley and Floerke for 2016 reflect three months at their January 1, 2016, annualized base salary and nine months at their April 1, 2016, annualized base salary, respectively. The amount for Ms. Beall reflects three months at her January 1, 2016, annualized base salary, her annualized base salary for the period from April 1, 2016, until October 5, 2016, and her annualized base salary for the period from October 6, 2016, until December 31, 2016. The amount shown for Ms. Buese for 2016 reflects three months at her January 1, 2016, annualized base salary and seven months at her April 1, 2016, annualized base salary.
|
(3)
|
The amounts shown in this column reflect the aggregate grant date fair value in accordance with provisions of the Financial Accounting Standards Board Accounting Standards Codification 718, Compensation-Stock Compensation (FASB ASC Topic 718.) See Item 8. Financial Statements and Supplementary Data-Note 20 for assumptions used in the calculation of the amounts related to MPLX LP equity for the year ended December 31, 2016, Note 19 to financial statements as reported on our Annual Report on Form 10-K for assumptions used in the calculation of the amounts related to MPLX LP equity for the year ended December 31, 2015, and Note 16 to financial statements as reported on our Annual Report on Form 10-K for assumptions used in the calculation of the amounts related to MPLX LP equity for the year ended December 31, 2014, and Note 23 to MPC’s financial statements as reported on its Annual Report on Form 10-K for the year ended December 31, 2016, for amounts related to MPC equity. The maximum value of the performance units reported in the “Unit Awards” column assuming the highest level of performance is achieved for Ms. Beall and Messrs. Heminger and Templin for 2016 is $425,000, $2,200,000, and $1,500,000, respectively; for Ms. Beall and Messrs. Heminger and
|
(4)
|
The amounts shown in this column reflect the total value of ACB awards earned in the year indicated, which were paid in the following year.
|
(5)
|
The amounts shown in this column reflect the annual change in actuarial present value of accumulated benefits under the Marathon Petroleum retirement plans. See “Post-Employment Benefits for 2016” and “Marathon Petroleum Retirement Plans” sections of the “Compensation Discussion and Analysis” for more information regarding the defined benefit plans and the assumptions used in the calculation of these amounts. There are no deferred compensation earnings reported in this column as the non-qualified deferred compensation plans do not provide above-market or preferential earnings.
|
(6)
|
In connection with their employment with MPC, our NEOs are eligible for limited perquisites which, together with contributions to defined contribution plans, comprise the amounts reported in the All Other Compensation column. The amounts shown in this column are summarized below:
|
|
Personal Use of Company Aircraft
|
Company Physicals
(a)
|
Tax & Financial Planning
(b)
|
Security
|
Miscellaneous Perks & Tax Allowance Gross Ups
|
Company Contributions to Defined Contribution Plans
(c)
|
Total All Other Compensation
|
|||||||
Name
|
($)
|
($)
|
($)
|
($)
|
($)
|
($)
|
($)
|
|||||||
Gary R. Heminger
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
Pamela K.M. Beall
|
—
|
|
3,587
|
|
8,000
|
|
—
|
|
—
|
|
74,480
|
|
86,067
|
|
Nancy K. Buese
|
—
|
|
3,587
|
|
15,000
|
|
—
|
|
—
|
|
57,175
|
|
75,762
|
|
Donald C. Templin
|
—
|
|
3,587
|
|
4,612
|
|
—
|
|
—
|
|
126,595
|
|
134,794
|
|
C. Corwin Bromley
|
—
|
|
3,587
|
|
—
|
|
—
|
|
—
|
|
57,664
|
|
61,251
|
|
Gregory S. Floerke
|
—
|
|
3,587
|
|
—
|
|
—
|
|
—
|
|
51,592
|
|
55,179
|
|
(a)
|
All MPC employees, including our NEOs, are eligible to receive an annual physical. Executives may receive an enhanced physical under the executive physical program. The amounts shown in this column reflect the average incremental cost of the executive physical program in excess of the average incremental cost of the employee physical program. Due to privacy concerns and Health Insurance Portability and Accountability Act confidentiality requirements, we do not disclose actual usage or cost of this program by individual NEOs.
|
(b)
|
The amounts shown in this column reflect reimbursement for the costs of professional advice related to tax, estate and financial planning up to a specified maximum not to exceed $15,000 per calendar year. For information on this program refer to the "Perquisites" section of the "Compensation Discussion and Analysis."
|
(c)
|
The amounts shown in this column reflect amounts contributed by MPC under the tax-qualified Marathon Petroleum Thrift Plan for Mses. Beall and Buese and Messrs. Templin, Bromley and Floerke, as well as under related non-qualified deferred compensation plans. See “Post-Employment Benefits for 2016” and “Marathon Petroleum Retirement Plans” sections of the "Compensation Discussion and Analysis" for more information.
|
Name
|
Type of Award
|
Grant Date
|
Approval Date
(1)
|
Estimated Future Payouts Under Non-Equity Incentive Plan Awards
(2)
|
Estimated Future Payouts Under Equity Incentive Plan Awards
(3)
|
All Other Shares of Stock or Units
(#)
|
All Other Option Awards: Underlying Options
(#)
|
Exercise or Base Price of Option Awards
($)
|
Grant Date And Option Awards
(4)
($)
|
|||||||||||||
Threshold
($)
|
Target
($)
|
Maximum
($)
|
Threshold
($)
|
Target
($)
|
Maximum
($)
|
|||||||||||||||||
Gary R. Heminger
|
MPLX LP Phantom Units
|
3/1/2016
|
2/23/2016
|
|
|
|
|
|
|
41,463
|
|
|
|
1,100,013
|
|
|||||||
MPLX LP Performance Units
|
3/1/2016
|
2/23/2016
|
|
|
|
137,500
|
|
1,100,000
|
|
2,200,000
|
|
|
|
|
701,580
|
|
||||||
Pamela K.M. Beall
|
MPC Stock Options
|
3/1/2016
|
2/23/2016
|
N/A
|
|
|
|
|
|
|
17,052
|
|
34.63
|
|
170,008
|
|
||||||
MPC Restricted Stock
|
3/1/2016
|
2/23/2016
|
|
|
|
|
|
|
2,455
|
|
|
|
85,017
|
|
||||||||
MPC Performance Units
|
3/1/2016
|
2/23/2016
|
|
|
|
21,250
|
|
170,000
|
|
340,000
|
|
|
|
|
97,427
|
|
||||||
MPC Annual Cash Bonus
|
|
|
N/A
|
367,500
|
|
735,000
|
|
|
|
|
|
|
|
|
||||||||
MPLX LP Phantom Units
|
3/1/2016
|
2/23/2016
|
|
|
|
|
|
|
8,010
|
|
|
|
212,505
|
|
||||||||
MPLX LP Performance Units
|
3/1/2016
|
2/23/2016
|
|
|
|
26,563
|
|
212,500
|
|
425,000
|
|
|
|
|
135,533
|
|
||||||
Nancy K. Buese
|
MPC Annual Cash Bonus
|
|
|
N/A
|
427,500
|
|
855,000
|
|
|
|
|
|
|
|
|
|||||||
Donald C. Templin
|
MPC Annual Cash Bonus
|
|
|
N/A
|
720,000
|
|
1,440,000
|
|
|
|
|
|
|
|
|
|||||||
MPLX LP Phantom Units
|
3/1/2016
|
2/23/2016
|
|
|
|
|
|
|
28,270
|
|
|
|
750,003
|
|
||||||||
MPLX LP Performance Units
|
3/1/2016
|
2/23/2016
|
|
|
|
93,750
|
|
750,000
|
|
1,500,000
|
|
|
|
|
478,350
|
|
||||||
C. Corwin Bromley
|
MPC Annual Cash Bonus
|
|
|
N/A
|
372,000
|
|
744,000
|
|
|
|
|
|
|
|
|
|||||||
Gregory S. Floerke
|
MPC Annual Cash Bonus
|
|
|
N/A
|
336,000
|
|
672,000
|
|
|
|
|
|
|
|
|
(1)
|
The MPC Compensation Committee and our Board approved the awards reported in the table above for Ms. Beall and Messrs. Heminger and Templin on February 23, 2016, with a grant date of March 1, 2016.
|
(2)
|
The target amounts shown in this column reflect the target annual incentive opportunity. No threshold amount is disclosed as the MPC Compensation Committee has discretion to not award an annual incentive under the ACB program. Each NEO may generally earn a maximum of 200 percent of the target.
|
(3)
|
The target amounts shown in this column reflect the number of performance units granted to Ms. Beall and Messrs. Heminger and Templin. Each performance unit has a target value of $1.00. The threshold for the award is the minimum possible payout of the award, which is 12.5 percent. The threshold is achieved when the payout percentage is 50 percent for one performance period and zero percent for the other three performance periods, thus an average payout percentage of 12.5 percent for the performance cycle. The maximum payout for this award is 200 percent of target.
|
(4)
|
The amounts shown in this column reflect the total grant date fair value of MPC stock options, MPC restricted stock, MPLX LP phantom units and MPC/MPLX LP performance units granted in 2016 in accordance with provisions of the Financial Accounting Standards Board Accounting Standards Codification 718, Compensation - Stock Compensation ("FASB ASC Topic 718"). The Black-Scholes value used for the stock options was $9.97 per share. The restricted stock
|
Name
|
Grant Date
|
|
Number of Securities Underlying Unexercised Options Exercisable
|
Number of Securities Underlying Unexercised Options Unexercisable
(#)
|
Option Exercise Price
($)
|
Option Expiration Date
|
Number of Shares or Units of Stock That Have Not Vested
(2)
(#)
|
Market Value of Shares or Units of Stock That Have Not Vested
(3)
($)
|
Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights that Have Not Vested
(4)
(#)
|
Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights that Have Not Vested
(5)
($)
|
|||||
Gary R. Heminger
|
|
MPLX LP
|
|
|
|
|
57,223
|
|
1,981,060
|
|
2,200,000
|
|
1,350,030
|
|
|
Pamela K.M. Beall
|
|
MPLX LP
|
|
|
|
|
9,282
|
|
321,343
|
|
297,500
|
|
168,071
|
|
|
3/1/2016
|
MPC
|
|
17,052
(1)
|
34.63
|
|
3/1/2027
|
2,455
|
|
123,609
|
|
170,000
|
|
582,828
|
|
|
Donald C. Templin
|
|
MPLX LP
|
|
|
|
|
31,803
|
|
1,101,020
|
|
1,000,000
|
|
556,825
|
|
|
C. Corwin Bromley
|
|
MPLX LP
|
|
|
|
|
67,389
|
|
2,333,007
|
|
|
|
|||
|
MPC
|
|
|
|
|
19,861
|
|
1,000,001
|
|
|
|
||||
Gregory S. Floerke
|
|
MPLX LP
|
|
|
|
|
54,126
|
|
1,873,842
|
|
|
|
|||
|
MPC
|
|
|
|
|
19,861
|
|
1,000,001
|
|
|
|
(1)
|
This stock option is scheduled to become exercisable in one-third increments on the first, second and third anniversaries of the grant date – March 1, 2017, March 1, 2018 and March 1, 2019.
|
(2)
|
The amounts shown in this column reflect the number of unvested MPLX LP phantom units and MPC restricted stock held by each of our NEOs on December 31, 2016. Phantom unit and restricted stock grants generally are scheduled to vest in one-third increments on the first, second and third anniversaries of the grant date. The amounts shown in this column also include unvested shares of MPC restricted stock granted to Messrs. Bromley and Floerke as part of their retention grants that occurred at the time of the MarkWest Merger. These MPC restricted stock grants are scheduled to vest in full on the third anniversary of the grant date.
|
MPLX LP Phantom Units
|
||||
Name
|
Grant Date
|
Number of Unvested Units
|
Vesting Dates
|
|
Gary R. Heminger
|
3/1/2014
|
6,840
|
|
3/1/2017
|
3/1/2015
|
8,920
|
|
3/1/2017, 3/1/2018
|
|
3/1/2016
|
41,463
|
|
3/1/2017, 3/1/2018, 3/1/2019
|
|
|
57,223
|
|
|
|
Pamela K.M. Beall
|
3/1/2014
|
582
|
|
3/1/2017
|
3/1/2015
|
690
|
|
3/1/2017, 3/1/2018
|
|
3/1/2016
|
8,010
|
|
3/1/2017, 3/1/2018, 3/1/2019
|
|
|
9,282
|
|
|
|
Donald C. Templin
|
3/1/2014
|
1,505
|
|
3/1/2017
|
3/1/2015
|
2,028
|
|
3/1/2017, 3/1/2018
|
|
3/1/2016
|
28,270
|
|
3/1/2017, 3/1/2018, 3/1/2019
|
|
|
31,803
|
|
|
|
C. Corwin Bromley
|
12/18/2015
|
50,240
|
|
Upon termination without cause
|
|
17,149
|
|
12/18/2017, 12/18/2018
|
|
|
67,389
|
|
|
|
Gregory S. Floerke
|
12/18/2015
|
36,476
|
|
Upon termination without cause
|
|
17,650
|
|
12/18/2017, 12/18/2018
|
|
|
54,126
|
|
|
MPC Restricted Stock
|
|||
Name
|
Grant Date
|
Number of Unvested Shares
|
Vesting Dates
|
Pamela K.M. Beall
|
3/1/2016
|
2,455
|
3/1/2017, 3/1/2018, 3/1/2019
|
C. Corwin Bromley
|
12/18/2015
|
19,861
|
12/18/2018
|
Gregory S. Floerke
|
12/18/2015
|
19,861
|
12/18/2018
|
(3)
|
The amounts shown in this column reflect the aggregate value of all unvested MPLX LP phantom units and MPC restricted stock held by each of our NEOs on December 31, 2016, using the December 30, 2016, MPLX LP common unit closing price of $34.62 per unit and MPC closing price of $50.35 per share. It also includes the value of unvested shares of MPC restricted stock granted to Messrs. Bromley and Floerke as part of their retention grants as discussed in the “Retention Agreements with Former MarkWest Executives” section of our Annual Report on Form10-K for the year ended December 31, 2015. These are valued using the MPC closing price on December 30, 2016, of $50.35 per share.
|
(4)
|
The amounts shown in this column reflect the number of unvested performance units held by Ms. Beall and Messrs. Heminger and Templin on December 31, 2016. Performance unit grants awarded in 2016 have a 36-month performance cycle and are designed to settle 25 percent in MPLX LP common units/MPC stock and 75 percent in cash. Each of these performance unit grants has a target value of $1.00 and payout may vary from $0.00 to $2.00 per unit. Payout is tied to our TUR/TSR as compared to specified peer groups.
|
MPLX LP Performance Units
|
||||
Name
|
Grant Date
|
Number of Unvested Units
|
Performance Period Ending Date
|
|
Gary R. Heminger
|
3/1/2015
|
1,100,000
|
|
12/31/2017
|
3/1/2016
|
1,100,000
|
|
12/31/2018
|
|
|
2,200,000
|
|
|
|
Pamela K.M. Beall
|
3/1/2015
|
85,000
|
|
12/31/2017
|
3/1/2016
|
212,500
|
|
12/31/2016
|
|
|
297,500
|
|
|
|
Donald C. Templin
|
3/1/2015
|
250,000
|
|
12/31/2017
|
3/1/2016
|
750,000
|
|
12/31/2018
|
|
|
1,000,000
|
|
|
MPC Performance Units
|
||||
Name
|
Grant Date
|
Number of Unvested Units
|
Performance Period Ending Date
|
|
Pamela K.M. Beall
|
3/1/2016
|
170,000
|
|
12/31/2018
|
(5)
|
The amount shown in this column for MPC reflects the aggregate value of all performance units held by Ms. Beall on December 31, 2016, assuming a payout of $1.1428 per unit for the March 1, 2015, grant and $1.1428 per unit for the March 1, 2016, grant, which is the next higher performance achievement that exceeds the performance for these grants' performance period that ended December 31, 2016. The amounts shown in this column for MPLX LP reflect the aggregate value of all performance units held by Ms. Beall and Messrs. Heminger and Templin on December 31, 2016, assuming a payout of $0.7273 per unit for the March 1, 2015, grant and $0.50 per unit for the March 1, 2016, grant, which is the next higher performance achievement that exceeds the performance for these grants' performance period that ended December 31, 2016.
|
|
|
Stock Awards
|
|||
Name
|
|
Number of Units/Shares Acquired on Vesting
(#)
|
Value Realized on Vesting
(1)
($)
|
||
Gary R. Heminger
|
MPLX LP
|
20,398
|
|
529,253
|
|
Pamela K.M. Beall
|
MPLX LP
MPC |
1,456
2,938
|
|
37,803
101,281
|
|
Donald C. Templin
|
MPLX LP
|
4,642
|
|
120,432
|
|
C. Corwin Bromley
|
MPLX LP
|
8,574
|
|
276,340
|
|
Gregory S. Floerke
|
MPLX LP
|
8,825
|
|
284,430
|
|
(1)
|
This column reflects the actual pre-tax gain realized upon vesting of phantom units and restricted stock, which is the fair market value of the units or stock on the date of vesting.
|
Name
|
Plan Name
|
Number of Years of Credited Service
(1)
|
Present Value of Accumulated Benefit
(2)
|
Payments During Last Fiscal Year
|
Pamela K.M. Beall
|
Marathon Petroleum Retirement Plan
|
14.67 years
|
716,871
|
—
|
|
Marathon Petroleum Excess Benefit Plan
|
14.67 years
|
1,348,690
|
—
|
Donald C. Templin
|
Marathon Petroleum Retirement Plan
|
5.50 years
|
121,068
|
—
|
|
Marathon Petroleum Excess Benefit Plan
|
5.50 years
|
720,749
|
—
|
C. Corwin Bromley
|
Marathon Petroleum Retirement Plan
|
1.0 year
|
28,577
|
—
|
|
Marathon Petroleum Excess Benefit Plan
|
1.0 year
|
61,871
|
—
|
Gregory S. Floerke
|
Marathon Petroleum Retirement Plan
|
1.0 year
|
22,179
|
—
|
|
Marathon Petroleum Excess Benefit Plan
|
1.0 year
|
40,668
|
—
|
(1)
|
The number of years of credited service shown in this column represents the number of years the NEO has participated in the plan. However, plan participation service used for the purpose of calculating each participant’s benefit under the Marathon Petroleum Retirement Plan legacy final average pay formula was frozen as of December 31, 2009.
|
(2)
|
The present value of accumulated benefit for the Marathon Petroleum Retirement Plan was calculated assuming a discount rate of 3.90 percent, the RP2000 mortality table for lump sums, a 96 percent lump sum election rate and retirement at age 62 (or current age, if later). In accordance with the Marathon Petroleum Retirement Plan provisions and actuarial assumptions, the discount rate for lump sum calculations varied from 1.00 percent to 1.25 percent based on the anticipated year of retirement.
|
[
|
1.6%
|
×
|
Final
Average Pay
|
×
|
Years of
Participation |
]
|
—
|
[
|
1.33%
|
×
|
Estimated
Primary Social Security Benefit |
×
|
Years of
Participation |
]
|
•
|
Participants with less than 50 points receive a seven percent pay credit;
|
•
|
Participants with at least 50 but less than 70 points receive a nine percent pay credit; and
|
•
|
Participants with 70 or more points receive an 11 percent pay credit.
|
Age at
Retirement
|
Early Retirement
Factor
|
|
|
Age at
Retirement
|
Early Retirement
Factor
|
62
|
100%
|
|
|
55
|
75%
|
61
|
97%
|
|
|
54
|
71%
|
60
|
94%
|
|
|
53
|
67%
|
59
|
91%
|
|
|
52
|
63%
|
58
|
87%
|
|
|
51
|
59%
|
57
|
83%
|
|
|
50
|
55%
|
56
|
79%
|
|
|
|
|
Name
|
|
Executive contributions in last fiscal year
|
|
Registrant contributions in last fiscal year
(1)
|
|
Aggregate earnings in last fiscal year
|
|
Aggregate withdrawals/distributions
|
|
Aggregate balance at last fiscal year-end
|
|||||
Pamela K.M. Beall
|
|
|
|
|
|
|
|
|
|
|
|||||
Marathon Petroleum Excess Benefit Plan
|
|
—
|
|
|
—
|
|
|
2,685.00
|
|
|
—
|
|
|
133,053.00
|
|
Marathon Petroleum Deferred Compensation Plan
|
|
—
|
|
|
55,877.00
|
|
|
30,135.00
|
|
|
—
|
|
|
725,976.00
|
|
Donald C. Templin
|
|
|
|
|
|
|
|
|
|
|
|||||
Marathon Petroleum Deferred Compensation Plan
|
|
—
|
|
|
109,852.20
|
|
|
39,194.10
|
|
|
—
|
|
|
545,989.50
|
|
C. Corwin Bromley
|
|
|
|
|
|
|
|
|
|
|
|||||
Marathon Petroleum Deferred Compensation Plan
|
|
—
|
|
|
39,061.00
|
|
|
3,105.00
|
|
|
—
|
|
|
42,166.00
|
|
Gregory S. Floerke
|
|
|
|
|
|
|
|
|
|
|
|||||
Marathon Petroleum Deferred Compensation Plan
|
|
—
|
|
|
32,989.00
|
|
|
2,366.00
|
|
|
—
|
|
|
35,354.00
|
|
(1)
|
The amounts shown in this column are also included in the “All Other Compensation” column of the 2016 Summary Compensation Table.
|
•
|
50 percent in the form of a cash retainer, payable in equal quarterly installments of $21,875 (at the commencement of each calendar quarter); and
|
•
|
50 percent in the form of a phantom unit award (granted at the commencement of each calendar quarter) representing a number of units having a value (based on the closing price of our common units on the date of grant) equal to $21,875. The phantom unit awards are not subject to any risk of forfeiture once granted and are automatically deferred until and settled in common units at the time the non-management director separates from service on the board or upon his or her death, if earlier.
|
•
|
Audit Committee Chair – $15,000;
|
•
|
Conflicts Committee Chair – $15,000;
|
•
|
Lead Director & Executive Committee Member - $15,000; and
|
•
|
Other Committee Chair – $7,500.
|
Name
|
|
Fees
Earned or
Paid in
Cash
(1)
($)
|
|
Unit
Awards
(2)
($)
|
|
Option
Awards
($)
|
|
Non-Equity
Incentive Plan
Compensation
($)
|
|
Change in
Pension Value
and Non-
Qualified
Deferred
Compensation
Earnings
($)
|
|
All Other
Compensation
(3)
($)
|
|
Total
($)
|
|||||||
Michael L. Beatty
|
|
75,000
|
|
|
75,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
150,000
|
|
David A. Daberko
|
|
75,000
|
|
|
75,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
150,000
|
|
Christopher A. Helms
|
|
90,000
|
|
|
75,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,000
|
|
|
175,000
|
|
Garry L. Peiffer
|
|
75,000
|
|
|
75,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
150,000
|
|
Dan D. Sandman
|
|
90,000
|
|
|
75,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
10,000
|
|
|
175,000
|
|
Frank M. Semple
|
|
12,432
|
|
|
12,432
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
24,864
|
|
John P. Surma
|
|
75,000
|
|
|
75,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
150,000
|
|
C. Richard Wilson
|
|
90,000
|
|
|
75,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
165,000
|
|
(1)
|
The amounts shown in this column reflect the director cash retainers and committee chair and lead director fees paid for service from January 1,
2016
, through December 31,
2016
.
|
(2)
|
The amounts shown in this column reflect the aggregate grant date fair value, as computed in accordance with provisions of Financial Accounting Standards Board Accounting Standards Codification 718, Compensation - Stock Compensation (“FASB ASC Topic 718”), for phantom unit awards granted to the non-management directors in
2016
. All phantom unit awards are deferred until departure from the board and distribution equivalents in the form of additional phantom unit awards are credited to non-management director deferred accounts as and when distributions are paid on our common units. The aggregate number of MPLX LP phantom unit awards credited for board service and outstanding as of December 31,
2016
, for each non-employee director is as follows: Messrs. Daberko, Helms, Sandman, Surma, and Wilson, 7,552; Mr. Peiffer, 5,077; Mr. Beatty, 2,563; and Mr. Semple, 366.
|
(3)
|
The amounts shown in this column reflect contributions made on behalf of Messrs. Helms and Sandman to educational institutions under our matching gifts program.
|
Name and Address
of Beneficial Owner
|
|
Number of
Common
Units
Representing
Limited
Partner
Interests
|
|
Percent of
Common
Units
Representing
Limited
Partner
Interests
|
|
Number of
General
Partner
Units
|
|
Percent of
General
Partner
Units
|
|
Percent of
Units
Representing
Total
Partnership
Interests
(2)
|
|||||
Marathon Petroleum Corporation
(1)
|
|
86,619,313
|
|
|
24.2
|
%
|
|
7,371,105
|
|
|
100
|
%
|
|
25.5
|
%
|
539 S. Main Street
|
|
|
|
|
|
|
|
|
|
|
|||||
Findlay, Ohio 45840
|
|
|
|
|
|
|
|
|
|
|
|||||
Tortoise Capital Advisors, L.L.C.
(3)
|
|
18,894,274
|
|
(3)
|
5.4
|
%
|
(3)
|
—
|
|
|
—
|
|
|
5.1
|
%
|
11550 Ash Street, Suite 300
|
|
|
|
|
|
|
|
|
|
|
|||||
Leawood, Kansas 66211
|
|
|
|
|
|
|
|
|
|
|
|||||
ALPS Advisors, Inc.
(4)
|
|
18,146,214
|
|
(4)
|
5.2
|
%
|
(4)
|
—
|
|
|
—
|
|
|
4.9
|
%
|
1290 Broadway, Suite 1100
|
|
|
|
|
|
|
|
|
|
|
|||||
Denver, Colorado 80203
|
|
|
|
|
|
|
|
|
|
|
|||||
Alerian MLP ETF
(4)
|
|
17,970,288
|
|
(4)
|
5.2
|
%
|
(4)
|
—
|
|
|
—
|
|
|
4.9
|
%
|
1290 Broadway, Suite 1100
|
|
|
|
|
|
|
|
|
|
|
|||||
Denver, Colorado 80203
|
|
|
|
|
|
|
|
|
|
|
(1)
|
The 86,619,313 common units representing limited partner interests (“Common Units”) are directly held by MPLX Logistics Holdings LLC and MPLX Holdings Inc. The 7,371,105 general partner units are directly held by MPLX GP LLC and represent its two percent general partner interest in MPLX LP. Marathon Petroleum Corporation is the ultimate parent company of MPLX GP LLC, MPLX Logistics Holdings LLC and MPLX Holdings Inc. and may be deemed to beneficially own the Common Units directly held by MPLX Logistics Holdings LLC and MPLX Holdings Inc., and the general partner units directly owned by MPLX GP LLC. MPC Investment LLC owns all of the membership interests in or shares of MPLX GP LLC, MPLX Logistics Holdings LLC and MPLX Holdings Inc., and MPC owns all of the membership interest in MPC Investment LLC.
|
(2)
|
Percentages were calculated including the Class B units on an as-converted basis. All of the 3,990,878 Class B units currently outstanding are owned by M&R MWE Liberty LLC and will convert into approximately 4.4 million Common Units on July 1, 2017.
|
(3)
|
According to a Schedule 13G/A filed with the SEC on February 14, 2017, by Tortoise Capital Advisors, L.L.C. ("TCA"). According to such Schedule 13G/A, TCA acts as an investment adviser to certain investment companies registered under the Investment Company Act of 1940. TCA, by virtue of investment advisory agreements with these investment companies, has all investment and voting power over securities owned of record by these investment companies. However, despite their delegation of investment and voting power to TCA, these investment companies may be deemed to be the beneficial owners under Rule 13d-3 of the Act, of the securities they own of record because they have the right to acquire investment and voting power through termination of their investment advisory agreement with TCA. Thus, TCA has reported that it shares voting power and dispositive power over the securities owned of record by these investment companies. TCA also acts as an investment adviser to certain managed accounts. Under contractual agreements with these managed account clients, TCA, with respect to the securities held in these client accounts, has investment and voting power with respect to certain of these client accounts, and has investment power but no voting power with respect to certain other of these client accounts. TCA has reported that it shares voting and/or investment power over the securities held by these client managed accounts despite a delegation of voting and/or investment power to TCA because the clients have the right to acquire investment and voting power through termination of their agreements with TCA. TCA may be deemed the beneficial owner of the securities covered by this statement under Rule 13d-3 of the Act that are held by its clients. Subject to the above, TCA reported that it has beneficial ownership of 18,894,274 Common Units or 5.4% of the Common Units outstanding, sole voting power over 344,682 of our Common Units, shared voting power over 16,345,231
|
(4)
|
According to a Schedule 13G/A filed with the SEC on January 26, 2017, by ALPS Advisors, Inc. (“AAI”) and Alerian MLP ETF. According to such Schedule 13G/A, AAI, an investment adviser registered under Section 203 of the Investment Advisors Act of 1940, furnishes investment advice to investment companies registered under the Investment Company Act of 1940 (collectively referred to as the “Funds”). In its role as investment advisor, AAI has voting and/or investment power over the securities of the Issuer that are owned by the Funds, and may be deemed to be the beneficial owner of the shares of the Issuer held by the Funds. However, all securities reported in this schedule are owned by the Funds. AAI disclaims beneficial ownership of such securities. In addition, the filing of this Schedule 13G/A shall not be construed as an admission that the reporting person or any of its affiliates is the beneficial owner of any securities covered by this Schedule 13G/A for any other purposes than Section 13(d) of the Securities Exchange Act of 1934. Alerian MLP ETF is an investment company registered under the Investment Company Act of 1940 and is one of the Funds to which AAI provides investment advice. Subject to the above, AAI reported that it has beneficial ownership of 18,146,214 Common Units or 5.21% of the Common Units outstanding, sole voting power over none of our Common Units, shared voting power over 18,146,214 of our Common Units, sole dispositive power over none of our Common Units and shared dispositive power over 18,146,214 of our Common Units. Subject to the above, and according to the Schedule 13G/A, Alerian MLP ETF reported that it has beneficial ownership of 17,970,288 Common Units or 5.16% of the Common Units outstanding, sole voting power over none of our Common Units, shared voting power over 17,970,288 of our Common Units, sole dispositive power over none of our Common Units and shared dispositive power over 17,970,288 of our Common Units.
|
Name of Beneficial Owner
|
|
Amount and Nature of
Beneficial Ownership
(1)
|
|
Percent of
Total
Outstanding
|
||
Directors / Named Executive Officers
|
|
|
|
|
|
|
Gary R. Heminger
|
|
174,753
|
|
(2)(5)(6)(7)
|
|
*
|
Pamela K.M. Beall
|
|
21,892
|
|
(2)(5)(7)
|
|
*
|
Michael L. Beatty
|
|
30,554
|
|
(2)(4)
|
|
*
|
C. Corwin Bromley
|
|
118,314
|
|
(2)(5)
|
|
*
|
Nancy K. Buese
|
|
76,830
|
|
(2)(5)
|
|
*
|
David A. Daberko
|
|
19,843
|
|
(2)(3)(4)
|
|
*
|
Gregory S. Floerke
|
|
77,181
|
|
(2)(5)
|
|
*
|
Timothy T. Griffith
|
|
18,302
|
|
(2)(5)(7)
|
|
*
|
Christopher A. Helms
|
|
19,173
|
|
(2)(4)
|
|
*
|
Garry L. Peiffer
|
|
37,395
|
|
(4)(6)
|
|
*
|
Dan D. Sandman
|
|
52,173
|
|
(2)(4)
|
|
*
|
Frank M. Semple
|
|
577,461
|
|
(2)(3)(4)(6)
|
|
*
|
John P. Surma
|
|
17,343
|
|
(2)(3)(4)
|
|
*
|
Donald C. Templin
|
|
57,409
|
|
(2)(5)(7)
|
|
*
|
C. Richard Wilson
|
|
18,173
|
|
(2)(4)
|
|
*
|
All Directors and Executive Officers as a group (18 reporting persons)
|
|
1,553,318
|
|
(2)(3)(4)(5)(6)(7)
|
|
*
|
(1)
|
None of the common units reported in this column are pledged as security.
|
(2)
|
Includes common units directly or indirectly held in beneficial form.
|
(3)
|
Includes phantom unit awards granted pursuant to the MPLX LP 2012 Incentive Compensation Plan and credited within a deferred account pursuant to the Marathon Petroleum Corporation Deferred Compensation Plan for Non-Employee Directors. The aggregate number of phantom unit awards credited as of January 31, 2017, for each of Messrs. Daberko and Surma is 1,670; and Mr. Semple 180.
|
(4)
|
Includes phantom unit awards granted pursuant to the MPLX LP 2012 Incentive Compensation Plan and credited within a deferred account pursuant to the MPLX GP LLC Non-Management Director Compensation Policy and Director Equity Award Terms. The aggregate number of phantom unit awards credited as of January 31, 2017, for the non-management directors of our general partner is as follows: Messrs. Daberko, Helms, Sandman, Surma and Wilson, 8,173 each; Mr. Beatty, 3,184; Mr. Peiffer, 5,698; and Mr. Semple, 987.
|
(5)
|
Includes phantom unit awards granted pursuant to the MPLX LP 2012 Incentive Compensation Plan, which may be forfeited under certain conditions.
|
(6)
|
Includes common units indirectly beneficially owned in trust. The number of common units held in trust as of January 31, 2017, by each applicable director or named executive officer of our general partner is as follows: Mr. Heminger, 26,750; Mr. Peiffer, 31,697; and Mr. Semple, 527,517.
|
(7)
|
Includes common units issued in settlement of performance units within sixty days of January 31, 2017.
|
*
|
The percentage of common units beneficially owned by each director or each executive officer of our general partner does not exceed one percent of the common units outstanding, and the percentage of common units beneficially owned by all directors and executive officers of our general partner as a group does not exceed one percent of the common units outstanding.
|
Name of Beneficial Owner
|
|
Amount and Nature of
Beneficial Ownership
(1)
|
|
Percent of
Total
Outstanding
|
||
Directors/Named Executive Officers
|
|
|
|
|
|
|
Gary R. Heminger
|
|
2,589,729
|
|
(2)(5)(6)(8)(9)(10)
|
|
*
|
Pamela K.M. Beall
|
|
138,293
|
|
(2)(5)(9)(10)
|
|
*
|
Michael L. Beatty
|
|
—
|
|
|
|
*
|
C. Corwin Bromley
|
|
19,861
|
|
(5)
|
|
*
|
Nancy K. Buese
|
|
—
|
|
|
|
*
|
David A. Daberko
|
|
144,998
|
|
(2)(3)
|
|
*
|
Gregory S. Floerke
|
|
19,950
|
|
(5)(6)
|
|
*
|
Timothy T. Griffith
|
|
160,261
|
|
(2)(5)(9)(10)
|
|
*
|
Christopher A. Helms
|
|
—
|
|
|
|
*
|
Garry L. Peiffer
|
|
277,084
|
|
(8)(9)
|
|
*
|
Dan D. Sandman
|
|
—
|
|
|
|
*
|
Frank M. Semple
|
|
1,170
|
|
(3)
|
|
*
|
John P. Surma
|
|
37,375
|
|
(3)(8)
|
|
*
|
Donald C. Templin
|
|
482,296
|
|
(2)(5)(9)(10)
|
|
*
|
C. Richard Wilson
|
|
—
|
|
|
|
*
|
|
|
|
|
|
|
|
All Directors and Executive Officers as a group (18 reporting persons)
|
|
4,161,343
|
|
(2)(3)(4)(5)(6)(7)(8)(9)(10)
|
|
*
|
(1)
|
None of the shares of common stock reported in this column are pledged as security.
|
(2)
|
Includes shares of common stock directly or indirectly held in registered or beneficial form.
|
(3)
|
Includes restricted stock unit awards granted pursuant to the Second Amended and Restated Marathon Petroleum Corporation 2011 Incentive Compensation Plan and/or the Marathon Petroleum Corporation 2012 Incentive Compensation Plan, and credited within a deferred account pursuant to the Marathon Petroleum Corporation Deferred Compensation Plan for Non-Employee Directors. The aggregate number of restricted stock unit awards credited as of January 31, 2017, is as follows: Mr. Daberko, 140,998; Mr. Semple, 1,170; and Mr. Surma, 27,375.
|
(4)
|
Includes restricted stock unit awards granted pursuant to the Marathon Petroleum Corporation 2012 Incentive Compensation Plan, a portion of which may be forfeited under certain conditions.
|
(5)
|
Includes shares of restricted stock issued pursuant to the Marathon Petroleum Corporation 2012 Incentive Compensation Plan, which are subject to limits on sale and transfer, and may be forfeited under certain conditions.
|
(6)
|
Includes shares of common stock held within the Marathon Petroleum Thrift Plan.
|
(7)
|
Includes shares of common stock held within the Marathon Petroleum Corporation Dividend Reinvestment and Direct Stock Purchase Plan.
|
(8)
|
Includes shares of common stock indirectly beneficially owned in trust. The number of shares held in trust as of January 31, 2017, by each applicable director or named executive officer of our general partner is as follows: Mr. Heminger, 21,228; Mr. Peiffer, 63,394; and Mr. Surma, 10,000.
|
(9)
|
Includes stock options exercisable within sixty days of January 31, 2017, including 255,210 stock options exercisable by the applicable directors and named executive officers but not in the money as of January 31, 2017.
|
(10)
|
Includes shares of common stock issued in settlement of performance units within sixty days of January 31, 2017.
|
*
|
The percentage of shares beneficially owned by each director or each executive officer of our general partner does not exceed one percent of the MPC common shares outstanding, and the percentage of shares beneficially owned by all directors and executive officers of our general partner as a group does not exceed one percent of the MPC common shares outstanding.
|
Plan category
|
|
Number of
securities to
be issued
upon
exercise of
outstanding
options,
warrants
and rights
(1)
|
|
Weighted
average
exercise
price of
outstanding
options,
warrants
and
rights
(2)
|
|
Number of
securities
remaining
available for
future
issuance
under equity
compensation
plans
(3)
|
|||
Equity compensation plans approved by security holders
|
|
1,277,354
|
|
|
N/A
|
|
|
1,229,440
|
|
Equity compensation plans not approved by security holders
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
1,277,354
|
|
|
|
|
1,229,440
|
|
(1)
|
Includes the following:
|
(a)
|
1,173,411 phantom unit awards granted pursuant to the MPLX 2012 Plan for common units unissued and not forfeited, cancelled or expired as of
December 31, 2016
.
|
(b)
|
103,943 units as the maximum potential number of common units that could be issued in settlement of performance units outstanding as of
December 31, 2016
, pursuant to the MPLX 2012 Plan based on the closing price of our common units on
December 31, 2016
, of $34.62 per unit. The number of units reported for this award vehicle may overstate dilution. See Item 8. Financial Statements and Supplementary Data – Note
20
for more information on performance unit awards granted under the MPLX 2012 Plan.
|
(2)
|
There is no exercise price associated with phantom unit awards.
|
(3)
|
Reflects the common units available for issuance pursuant to the MPLX 2012 Plan. The number of units reported in this column assumes 103,943 as the maximum potential number of common units that could be issued in settlement of performance units outstanding as of
December 31, 2016
, pursuant to the MPLX 2012 Plan based on the closing price of our common units on
December 31, 2016
, of $34.62 per unit. The number of units assumed for this award vehicle may understate the number of common units available for issuance pursuant to the MPLX 2012 Plan. See Item 8. Financial Statements and Supplementary Data – Note
20
for more information on performance unit awards issued pursuant to the MPLX 2012 Plan.
|
•
|
Payment of compensation to an executive officer or director of our general partner if the compensation is otherwise required to be disclosed in our filings with the SEC;
|
•
|
Any ongoing employment relationship provided that such employment relationship will be subject to initial review and approval; and
|
•
|
Any transaction between the Partnership or any of its subsidiaries, on the one hand, and our general partner or any of its affiliates, on the other hand; provided, however, that such transaction is approved consistent with our partnership agreement.
|
•
|
the impact on a director’s independence in the event the related person is a director or an immediate family member of a director;
|
Fees
(1)
(In millions)
|
2016
|
|
2015
|
||||
Audit
|
$
|
4
|
|
|
$
|
4
|
|
Audit-Related
|
—
|
|
|
—
|
|
||
Tax
|
1
|
|
|
1
|
|
||
All Other
|
—
|
|
|
—
|
|
||
Total
|
$
|
5
|
|
|
$
|
5
|
|
(1)
|
The Partnership’s Pre-Approval of Audit, Audit-Related, Tax and Permissible Non-Audit Services Policy is summarized in this Annual Report on Form 10-K. See “Audit Committee Policy for Pre-Approval of Audit, Audit-Related, Tax and Permissible Non-Audit Services.” In
2016
and
2015
, all of these services were pre-approved by the Audit Committee of our general partner in accordance with its pre-approval policy. Our Audit Committee did not utilize the Policy’s de minimis exception in
2016
or
2015
.
|
|
|
Exhibit Description
|
|
Incorporated by Reference
|
|
Filed
Herewith
|
|
Furnished
Herewith
|
||||||
Exhibit
Number
|
|
Form
|
|
Exhibit
|
|
Filing Date
|
|
SEC File No.
|
|
|||||
2.1
|
|
Partnership Interests Purchase Agreement dated February 26, 2014, by and between MPLX Operations LLC and MPL Investment LLC
|
|
8-K
|
|
2.1
|
|
3/4/2014
|
|
001-35714
|
|
|
|
|
2.2
|
|
Partnership Interests Purchase and Contribution Agreement, dated December 1, 2014, by and among MPLX Operations LLC, MPLX Logistics Holdings LLC, MPLX LP and MPL Investment LLC
|
|
8-K
|
|
2.1
|
|
12/2/2014
|
|
001-35714
|
|
|
|
|
2.3 †
|
|
Agreement and Plan of Merger, dated as of July 11, 2015, by and among MPLX LP, Sapphire Holdco LLC, MPLX GP LLC, MarkWest Energy Partners, L.P. and, for certain limited purposes set forth therein, Marathon Petroleum Corporation
|
|
10-Q
|
|
2.1
|
|
8/3/2015
|
|
001-35714
|
|
|
|
|
2.4
|
|
Amendment to Agreement and Plan of Merger, dated as of November 10, 2015, by and among MPLX LP, Sapphire Holdco LLC, MPLX GP LLC, MarkWest Energy Partners, L.P. and Marathon Petroleum Corporation
|
|
8-K
|
|
2.1
|
|
11/12/2015
|
|
001-35714
|
|
|
|
|
2.5
|
|
Amendment Number 2 to Agreement and Plan of Merger, dated as of November 16, 2015, by and among MPLX LP, Sapphire Holdco LLC, MPLX GP LLC, MarkWest Energy Partners, L.P. and Marathon Petroleum Corporation
|
|
8-K
|
|
2.1
|
|
11/17/2015
|
|
001-35714
|
|
|
|
|
2.6
|
|
Membership Interests Contribution Agreement, dated March 14, 2016, between MPLX LP, MPLX Logistics Holdings LLC, MPLX GP LLC and MPC Investment LLC
|
|
8-K
|
|
2.1
|
|
3/17/2016
|
|
001-35714
|
|
|
|
|
3.1
|
|
Certificate of Limited Partnership of MPLX LP
|
|
S-1
|
|
3.1
|
|
7/2/2012
|
|
333-182500
|
|
|
|
|
3.2
|
|
Amendment to the Certificate of Limited Partnership of MPLX LP
|
|
S-1/A
|
|
3.2
|
|
10/9/2012
|
|
333-182500
|
|
|
|
|
3.3
|
|
Third Amended and Restated Agreement of Limited Partnership of MPLX LP, dated as of October 31, 2016
|
|
10-Q
|
|
3.3
|
|
10/31/2016
|
|
001-35714
|
|
|
|
|
3.4
|
|
First Amendment to Third Amended and Restated Agreement of Limited Partnership of MPLX LP, dated as of February 23, 2017
|
|
|
|
|
|
|
|
|
|
X
|
|
|
4.1
|
|
Indenture, dated February 12, 2015, between MPLX LP and The Bank of New York Mellon Trust Company, N.A., as Trustee
|
|
8-K
|
|
4.1
|
|
2/12/2015
|
|
001-35714
|
|
|
|
|
4.2
|
|
First Supplemental Indenture, dated February 12, 2015, between MPLX LP and The Bank of New York Mellon Trust Company, N.A., as Trustee (including Form of Notes)
|
|
8-K
|
|
4.2
|
|
2/12/2015
|
|
001-35714
|
|
|
|
|
|
|
Exhibit Description
|
|
Incorporated by Reference
|
|
Filed
Herewith
|
|
Furnished
Herewith
|
||||||
Exhibit
Number
|
|
Form
|
|
Exhibit
|
|
Filing Date
|
|
SEC File No.
|
|
|||||
4.3
|
|
Registration Rights Agreement dated as of December 22, 2015 by and among MPLX LP, MPLX GP LLC, and each of Citigroup Global Markets Inc., J.P. Morgan Securities LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated
|
|
8-K
|
|
4.1
|
|
12/22/2015
|
|
001-35714
|
|
|
|
|
4.4
|
|
Second Supplemental Indenture, dated as of December 22, 2015, by and between MPLX LP and the Bank of New York Mellon Trust Company, N.A. (including Form of Note)
|
|
8-K
|
|
4.2
|
|
12/22/2015
|
|
001-35714
|
|
|
|
|
4.5
|
|
Third Supplemental Indenture, dated as of December 22, 2015, by and between MPLX LP and the Bank of New York Mellon Trust Company, N.A. (including Form of Note)
|
|
8-K
|
|
4.3
|
|
12/22/2015
|
|
001-35714
|
|
|
|
|
4.6
|
|
Fourth Supplemental Indenture, dated as of December 22, 2015, by and between MPLX LP and the Bank of New York Mellon Trust Company, N.A. (including Form of Note)
|
|
8-K
|
|
4.4
|
|
12/22/2015
|
|
001-35714
|
|
|
|
|
4.7
|
|
Fifth Supplemental Indenture, dated as of December 22, 2015, by and between MPLX LP and the Bank of New York Mellon Trust Company, N.A. (including Form of Note)
|
|
8-K
|
|
4.5
|
|
12/22/2015
|
|
001-35714
|
|
|
|
|
4.8
|
|
Registration Rights Agreement, dated as of May 13, 2016, by and between MPLX LP and the Purchasers party thereto
|
|
8-K
|
|
4.1
|
|
5/16/2016
|
|
001-35714
|
|
|
|
|
4.9
|
|
Sixth Supplemental Indenture, dated as of February 10, 2017, between the Issuer and The Bank of New York Mellon Trust Company, N.A., as Trustee
|
|
8-K
|
|
4.1
|
|
2/10/2017
|
|
001-35714
|
|
|
|
|
4.10
|
|
Seventh Supplemental Indenture, dated as of February 10, 2017, between the Issuer and The Bank of New York Mellon Trust Company, N.A., as Trustee
|
|
8-K
|
|
4.2
|
|
2/10/2017
|
|
001-35714
|
|
|
|
|
|
|
Exhibit Description
|
|
Incorporated by Reference
|
|
Filed
Herewith
|
|
Furnished
Herewith
|
||||||
Exhibit
Number
|
|
Form
|
|
Exhibit
|
|
Filing Date
|
|
SEC File No.
|
|
|||||
10.1
|
|
Credit Agreement, dated as of November 20, 2014, among MPLX LP, as borrower, Citibank, N.A., as administrative agent, each of Citigroup Global Markets Inc., Wells Fargo Securities, LLC, Barclays Bank PLC, J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporate and RBS Securities Inc., as joint lead arrangers and joint bookrunners, Wells Fargo Bank, N.A., as syndication agent, and each of Bank of America, N.A., Barclays Bank PLC, JPMorgan Chase Bank, N.A., and The Royal Bank of Scotland PLC, as documentation agents, and the other lenders and issuing banks that are parties thereto
|
|
8-K
|
|
10.1
|
|
11/26/2014
|
|
001-35714
|
|
|
|
|
10.2*
|
|
MPLX LP 2012 Incentive Compensation Plan
|
|
S-1/A
|
|
10.3
|
|
10/9/2012
|
|
333-182500
|
|
|
|
|
10.3
|
|
Contribution, Conveyance and Assumption Agreement, dated as of October 31, 2012, among MPLX LP, MPLX GP LLC, MPLX Operations LLC, MPC Investment LLC, MPLX Logistics Holdings LLC, Marathon Pipe Line LLC, MPL Investment LLC, MPLX Pipe Line Holdings LP and Ohio River Pipe Line LLC
|
|
8-K
|
|
10.1
|
|
11/6/2012
|
|
001-35714
|
|
|
|
|
10.4
|
|
Omnibus Agreement, dated as of October 31, 2012, among Marathon Petroleum Corporation, Marathon Petroleum Company LP, MPL Investment LLC, MPLX Operations LLC, MPLX Terminal and Storage LLC, MPLX Pipe Line Holdings LP, Marathon Pipe Line LLC, Ohio River Pipe Line LLC, MPLX LP and MPLX GP LLC
|
|
8-K
|
|
10.2
|
|
11/6/2012
|
|
001-35714
|
|
|
|
|
10.5
|
|
Employee Services Agreement, dated effective as of October 1, 2012, by and among Marathon Petroleum Logistics Services LLC, MPLX GP LLC and Marathon Pipe Line LLC
|
|
S-1/A
|
|
10.6
|
|
10/9/2012
|
|
333-182500
|
|
|
|
|
10.6
|
|
Employee Services Agreement, dated effective as of October 1, 2012, by and among Catlettsburg Refining LLC, MPLX GP LLC and MPLX Terminal and Storage LLC
|
|
S-1/A
|
|
10.7
|
|
10/9/2012
|
|
333-182500
|
|
|
|
|
10.7
|
|
Management Services Agreement, dated effective as of September 1, 2012, by and between Hardin Street Holdings LLC and Marathon Pipe Line LLC
|
|
S-1/A
|
|
10.8
|
|
9/7/2012
|
|
333-182500
|
|
|
|
|
|
|
Exhibit Description
|
|
Incorporated by Reference
|
|
Filed
Herewith
|
|
Furnished
Herewith
|
||||||
Exhibit
Number
|
|
Form
|
|
Exhibit
|
|
Filing Date
|
|
SEC File No.
|
|
|||||
10.8
|
|
Management Services Agreement, dated effective as of October 10, 2012, by and between MPL Louisiana Holdings LLC and Marathon Pipe Line LLC
|
|
S-1/A
|
|
10.9
|
|
10/18/2012
|
|
333-182500
|
|
|
|
|
10.9
|
|
Amended and Restated Operating Agreement, dated as of October 31, 2012, between Marathon Petroleum Company LP and Marathon Pipe Line LLC
|
|
8-K
|
|
10.3
|
|
11/6/2012
|
|
001-35714
|
|
|
|
|
10.10
|
|
Storage Services Agreement, dated effective as of October 1, 2012, by and between Marathon Pipe Line LLC and Marathon Petroleum Company LP (Patoka tank farm)
|
|
S-1/A
|
|
10.13
|
|
10/9/2012
|
|
333-182500
|
|
|
|
|
10.11
|
|
Storage Services Agreement, dated effective as of October 1, 2012, by and between Marathon Pipe Line LLC and Marathon Petroleum Company LP (Martinsville tank farm)
|
|
S-1/A
|
|
10.14
|
|
10/9/2012
|
|
333-182500
|
|
|
|
|
10.12
|
|
Storage Services Agreement, dated effective as of October 1, 2012, by and between Marathon Pipe Line LLC and Marathon Petroleum Company LP (Lebanon tank farm)
|
|
S-1/A
|
|
10.15
|
|
10/9/2012
|
|
333-182500
|
|
|
|
|
10.13
|
|
Storage Services Agreement, dated effective as of October 1, 2012, by and between Marathon Pipe Line LLC and Marathon Petroleum Company LP (Wood River tank farm)
|
|
S-1/A
|
|
10.16
|
|
10/9/2012
|
|
333-182500
|
|
|
|
|
10.14
|
|
Storage Services Agreement, dated effective as of October 1, 2012, by and between MPLX Terminal and Storage LLC and Marathon Petroleum Company LP (Neal butane cavern)
|
|
S-1/A
|
|
10.17
|
|
10/9/2012
|
|
333-182500
|
|
|
|
|
10.15
|
|
Transportation Services Agreement (Patoka to Lima Crude System), dated as of October 31, 2012, between Marathon Petroleum Company LP and Marathon Pipe Line LLC
|
|
8-K
|
|
10.4
|
|
11/6/2012
|
|
001-35714
|
|
|
|
|
10.16
|
|
Transportation Services Agreement (Catlettsburg and Robinson Crude System), dated as of October 31, 2012, between Marathon Petroleum Company LP and Marathon Pipe Line LLC
|
|
8-K
|
|
10.5
|
|
11/6/2012
|
|
001-35714
|
|
|
|
|
10.17
|
|
Transportation Services Agreement (Detroit Crude System), dated as of October 31, 2012, between Marathon Petroleum Company LP and Marathon Pipe Line LLC
|
|
8-K
|
|
10.6
|
|
11/6/2012
|
|
001-35714
|
|
|
|
|
10.18
|
|
Transportation Services Agreement (Wood River to Patoka Crude System), dated as of October 31, 2012, between Marathon Petroleum Company LP and Marathon Pipe Line LLC
|
|
8-K
|
|
10.7
|
|
11/6/2012
|
|
001-35714
|
|
|
|
|
|
|
Exhibit Description
|
|
Incorporated by Reference
|
|
Filed
Herewith
|
|
Furnished
Herewith
|
||||||
Exhibit
Number
|
|
Form
|
|
Exhibit
|
|
Filing Date
|
|
SEC File No.
|
|
|||||
10.19
|
|
Transportation Services Agreement (Garyville Products System), dated as of October 31, 2012, between Marathon Petroleum Company LP and Marathon Pipe Line LLC
|
|
8-K
|
|
10.8
|
|
11/6/2012
|
|
001-35714
|
|
|
|
|
10.20
|
|
Transportation Services Agreement (Texas City Products System), dated as of October 31, 2012, between Marathon Petroleum Company LP and Marathon Pipe Line LLC
|
|
8-K
|
|
10.9
|
|
11/6/2012
|
|
001-35714
|
|
|
|
|
10.21
|
|
Transportation Services Agreement (ORPL Products System), dated as of October 31, 2012, between Marathon Petroleum Company LP and Ohio River Pipe Line LLC
|
|
8-K
|
|
10.10
|
|
11/6/2012
|
|
001-35714
|
|
|
|
|
10.22
|
|
Transportation Services Agreement (Robinson Products System), dated as of October 31, 2012, between Marathon Petroleum Company LP and Marathon Pipe Line LLC
|
|
8-K
|
|
10.11
|
|
11/6/2012
|
|
001-35714
|
|
|
|
|
10.23
|
|
Transportation Services Agreement (Wood River Barge Dock), dated as of October 31, 2012, between Marathon Petroleum Company LP and Marathon Pipe Line LLC
|
|
8-K
|
|
10.12
|
|
11/6/2012
|
|
001-35714
|
|
|
|
|
10.24*
|
|
MPC Non-Employee Director Phantom Unit Award Policy
|
|
10-K
|
|
10.26
|
|
3/25/2013
|
|
001-35714
|
|
|
|
|
10.25*
|
|
Form of MPLX LP Phantom Unit Award Agreement - Officer
|
|
10-Q
|
|
10.1
|
|
5/9/2013
|
|
001-35714
|
|
|
|
|
10.26*
|
|
Form of MPLX LP Performance Unit Award Agreement - 2013-2015 Performance Cycle
|
|
10-Q
|
|
10.2
|
|
5/9/2013
|
|
001-35714
|
|
|
|
|
10.27*
|
|
MPLX LP - Form of MPC Officer Phantom Unit Agreement
|
|
10-Q
|
|
10.3
|
|
5/9/2013
|
|
001-35714
|
|
|
|
|
10.28*
|
|
MPLX LP - Form of MPC Officer Performance Unit Award Agreement - 2013-2015 Performance Cycle
|
|
10-Q
|
|
10.4
|
|
5/9/2013
|
|
001-35714
|
|
|
|
|
10.29*
|
|
Amendment to Outstanding Phantom Unit Award Agreement of Garry L. Peiffer dated November 18, 2013
|
|
10-K
|
|
10.31
|
|
2/28/2014
|
|
001-35714
|
|
|
|
|
10.30*
|
|
MPLX GP LLC Amended and Restated Non-Management Director Compensation Policy and Equity Award Terms
|
|
|
|
|
|
|
|
|
|
X
|
|
|
10.31
|
|
First Amendment to Amended and Restated Operating Agreement, dated as of January 1, 2015, between Marathon Petroleum Company LP and Marathon Pipe Line LLC
|
|
10-Q
|
|
10.2
|
|
5/4/2015
|
|
001-35714
|
|
|
|
|
10.32
|
|
Operating Agreement, dated as of January 1, 2015, between Hardin Street Transportation LLC and Marathon Pipe Line LLC
|
|
10-Q
|
|
10.3
|
|
5/4/2015
|
|
001-35714
|
|
|
|
|
|
|
Exhibit Description
|
|
Incorporated by Reference
|
|
Filed
Herewith
|
|
Furnished
Herewith
|
||||||
Exhibit
Number
|
|
Form
|
|
Exhibit
|
|
Filing Date
|
|
SEC File No.
|
|
|||||
10.33
|
|
Lock-Up Agreement, dated July 11, 2015, by and among MPLX LP, MPLX GP LLC, Sapphire Holdco LLC, MarkWest Energy Partners, L.P., M&R MWE Liberty, LLC, EMG Utica, LLC and EMG Utica Condensate, LLC
|
|
10-Q
|
|
10.2
|
|
8/3/2015
|
|
001-35714
|
|
|
|
|
10.34
|
|
Transportation Services Agreement (Cornerstone Pipeline System and Utica Build-Out Projects), effective as of June 11, 2015, by and between Marathon Petroleum Company LP and Marathon Pipe Line LLC
|
|
8-K
|
|
10.1
|
|
6/17/2015
|
|
001-35714
|
|
|
|
|
10.35
|
|
First Amendment to Storage Services Agreement, dated as of September 17, 2015, by and between Marathon Petroleum Company LP and Marathon Pipe Line LLC
|
|
8-K
|
|
10.1
|
|
9/23/2015
|
|
001-35714
|
|
|
|
|
10.36
|
|
Amendment Agreement, dated as of October 27, 2015, by and among MPLX LP, Citibank, N.A., Wells Fargo Bank, National Association, and the other institutions named on the signature pages thereto
|
|
8-K
|
|
10.1
|
|
11/2/2015
|
|
001-35714
|
|
|
|
|
10.37
|
|
Loan Agreement, by and between MPLX LP and MPC Investment LLC, dated December 4, 2015
|
|
8-K
|
|
10.1
|
|
12/10/2015
|
|
001-35714
|
|
|
|
|
10.38*
|
|
Retention Agreement, by and between Marathon Petroleum Company LP and Nancy K. Buese, dated September 14, 2015
|
|
8-K
|
|
10.2
|
|
12/10/2015
|
|
001-35714
|
|
|
|
|
10.39*
|
|
Retention Agreement, by and between Marathon Petroleum Company LP and John C. Mollenkopf, dated November 12, 2015
|
|
8-K
|
|
10.3
|
|
12/10/2015
|
|
001-35714
|
|
|
|
|
10.40*
|
|
Letter Agreement, by and between Marathon Petroleum Corporation and Paula L. Rosson, dated October 6, 2015
|
|
8-K
|
|
10.4
|
|
12/10/2015
|
|
001-35714
|
|
|
|
|
10.41*
|
|
Retention Agreement, by and between Marathon Petroleum Company LP and Greg S. Floerke, dated September 14, 2015
|
|
10-K
|
|
10.41
|
|
2/26/2016
|
|
001-35714
|
|
|
|
|
10.42*
|
|
Retention Agreement, by and between Marathon Petroleum Company LP and C. Corwin Bromley, dated September 14, 2015
|
|
10-K
|
|
10.42
|
|
2/26/2016
|
|
001-35714
|
|
|
|
|
10.43
|
|
Employee Services Agreement, dated December 28, 2015, by and between MPLX LP and MW Logistics Services LLC
|
|
8-K
|
|
10.1
|
|
1/4/2016
|
|
001-35714
|
|
|
|
|
10.44*
|
|
Executive Employment Agreement effective September 5, 2007 between MarkWest Hydrocarbon, Inc. and Frank Semple
|
|
8-K
|
|
10.1
|
|
9/11/2007
|
|
001-31239
|
|
|
|
|
|
|
Exhibit Description
|
|
Incorporated by Reference
|
|
Filed
Herewith
|
|
Furnished
Herewith
|
||||||
Exhibit
Number
|
|
Form
|
|
Exhibit
|
|
Filing Date
|
|
SEC File No.
|
|
|||||
10.45
|
|
Voting Agreement, dated July 11, 2015, by and among MPLX LP, MPLX GP LLC, Sapphire Holdco LLC and M&R MWE Liberty, LLC
|
|
10-Q
|
|
10.1
|
|
8/3/2015
|
|
001-35714
|
|
|
|
|
10.46
|
|
Voting Agreement, dated as of November 16, 2015, by and among MPLX LP, MPLX GP LLC, Sapphire Holdco LLC, Kayne Anderson Capital Advisors, L.P. and KA Fund Advisors, LLC
|
|
8-K
|
|
10.1
|
|
11/17/2015
|
|
001-35714
|
|
|
|
|
10.47
|
|
Voting Agreement, dated as of November 16, 2015, by and among MPLX LP, MPLX GP LLC, Sapphire Holdco LLC, and Tortoise Capital Advisors, L.L.C.
|
|
8-K
|
|
10.2
|
|
11/17/2015
|
|
001-35714
|
|
|
|
|
10.48+
|
|
Second Amended and Restated Limited Liability Company Agreement of MarkWest Utica EMG, L.L.C. dated December 4, 2015, between MarkWest Utica Operating Company, L.L.C. and EMG Utica, LLC
|
|
10-K
|
|
10.48
|
|
2/26/2016
|
|
001-35714
|
|
|
|
|
10.49
|
|
Amended and Restated Transportation Services Agreement, dated January 1, 2015, between Hardin Street Marine LLC and Marathon Petroleum Company LP
|
|
8-K
|
|
10.1
|
|
4/6/2016
|
|
001-35714
|
|
|
|
|
10.50
|
|
First Amendment to the Amended and Restated Transportation Services Agreement, dated March 31, 2016, between Hardin Street Marine LLC and Marathon Petroleum Company LP
|
|
8-K
|
|
10.2
|
|
4/6/2016
|
|
001-35714
|
|
|
|
|
10.51
|
|
Amended and Restated Management Services Agreement, dated January 1, 2015, between Hardin Street Marine LLC and Marathon Petroleum Company LP
|
|
8-K
|
|
10.3
|
|
4/6/2016
|
|
001-35714
|
|
|
|
|
10.52
|
|
Second Amended and Restated Employee Services Agreement, dated January 1, 2015, between Hardin Street Marine LLC and Marathon Petroleum Logistics Services LLC
|
|
8-K
|
|
10.4
|
|
4/6/2016
|
|
001-35714
|
|
|
|
|
10.53*
|
|
Form of MPLX LP Performance Unit Award Agreement - Marathon Petroleum Corporation Officer
|
|
10-Q
|
|
10.6
|
|
5/2/2016
|
|
001-35714
|
|
|
|
|
10.54*
|
|
Form of MPLX LP Phantom Unit Award Agreement - Marathon Petroleum Corporation Officer
|
|
10-Q
|
|
10.7
|
|
5/2/2016
|
|
001-35714
|
|
|
|
|
10.55*
|
|
Form of MPLX LP Performance Unit Award Agreement
|
|
10-Q
|
|
10.8
|
|
5/2/2016
|
|
001-35714
|
|
|
|
|
10.56*
|
|
Form of MPLX LP Phantom Unit Award Agreement - Officer
|
|
10-Q
|
|
10.9
|
|
5/2/2016
|
|
001-35714
|
|
|
|
|
10.57
|
|
Series A Preferred Unit Purchase Agreement, dated as of April 27, 2016, by and among MPLX LP and the Purchasers party thereto
|
|
8-K
|
|
10.1
|
|
4/29/2016
|
|
001-35714
|
|
|
|
|
|
|
Exhibit Description
|
|
Incorporated by Reference
|
|
Filed
Herewith
|
|
Furnished
Herewith
|
||||||
Exhibit
Number
|
|
Form
|
|
Exhibit
|
|
Filing Date
|
|
SEC File No.
|
|
|||||
10.58
|
|
Master Reorganization Agreement, dated September 1, 2016, by and among MPLX Holdings Inc., MarkWest Energy Partners, L.P., MWE GP LLC, MPLX LP, MPLX GP LLC, MPC Investment LLC, MPLX Logistics Holdings LLC and MarkWest Hydrocarbon, L.L.C.
|
|
8-K
|
|
10.1
|
|
9/6/2016
|
|
001-35714
|
|
|
|
|
10.59
|
|
Second Amendment to Amended and Restated Operating Agreement, dated August 1, 2016, between Marathon Petroleum Company LP and Marathon Pipe Line LLC
|
|
10-Q
|
|
10.2
|
|
10/31/2016
|
|
001-35714
|
|
|
|
|
10.60
|
|
First Amendment to Employee Services Agreement, dated May 10, 2016, by and between Marathon Petroleum Logistics Services LLC, MPLX GP LLC and Marathon Pipe Line LLC
|
|
10-Q
|
|
10.1
|
|
8/3/2016
|
|
001-35714
|
|
|
|
|
10.61
|
|
First Amendment to Amended and Restated Transportation Services Agreement, effective as of April 1, 2016, by and between Marathon Petroleum Company LP and Hardin Street Marine LLC
|
|
10-Q
|
|
10.2
|
|
8/3/2016
|
|
001-35714
|
|
|
|
|
10.62
|
|
First Amendment to Amended and Restated Management Services Agreement, effective as of November 1, 2016, between Marathon Petroleum Company LP and Hardin Street Marine LLC
|
|
|
|
|
|
|
|
|
|
X
|
|
|
10.63
|
|
First Amendment to Transportation Services Agreement, dated November 1, 2016, between Marathon Pipeline LLC and Marathon Petroleum Company LP (Texas City Products System)
|
|
|
|
|
|
|
|
|
|
X
|
|
|
12.1
|
|
Computation of Ratio of Earnings to Fixed Charges
|
|
|
|
|
|
|
|
|
|
X
|
|
|
14.1
|
|
Code of Ethics for Senior Financial Officers
|
|
|
|
|
|
|
|
|
|
X
|
|
|
21.1
|
|
List of Subsidiaries
|
|
|
|
|
|
|
|
|
|
X
|
|
|
23.1
|
|
Consent of Independent Registered Public Accounting Firm
|
|
|
|
|
|
|
|
|
|
X
|
|
|
24.1
|
|
Power of Attorney of Directors and Officers of MPLX GP LLC
|
|
|
|
|
|
|
|
|
|
X
|
|
|
31.1
|
|
Certification of Chief Executive Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
|
|
|
|
|
|
|
|
|
|
X
|
|
|
31.2
|
|
Certification of Chief Financial Officer pursuant to Rule 13(a)-14 and 15(d)-14 under the Securities Exchange Act of 1934
|
|
|
|
|
|
|
|
|
|
X
|
|
|
32.1
|
|
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350
|
|
|
|
|
|
|
|
|
|
|
|
X
|
|
|
Exhibit Description
|
|
Incorporated by Reference
|
|
Filed
Herewith
|
|
Furnished
Herewith
|
||||||
Exhibit
Number
|
|
Form
|
|
Exhibit
|
|
Filing Date
|
|
SEC File No.
|
|
|||||
32.2
|
|
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350
|
|
|
|
|
|
|
|
|
|
|
|
X
|
101.INS
|
|
XBRL Instance Document
|
|
|
|
|
|
|
|
|
|
X
|
|
|
101.SCH
|
|
XBRL Taxonomy Extension Schema
|
|
|
|
|
|
|
|
|
|
X
|
|
|
101.PRE
|
|
XBRL Taxonomy Extension Presentation Linkbase
|
|
|
|
|
|
|
|
|
|
X
|
|
|
101.CAL
|
|
XBRL Taxonomy Extension Calculation Linkbase
|
|
|
|
|
|
|
|
|
|
X
|
|
|
101.DEF
|
|
XBRL Taxonomy Extension Definition Linkbase
|
|
|
|
|
|
|
|
|
|
X
|
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101.LAB
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XBRL Taxonomy Extension Label Linkbase
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X
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†
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The exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be provided to the Securities and Exchange Commission upon request.
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*
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Indicates management contract or compensatory plan, contract or arrangement in which one or more directors or executive officers of the Registrant may be participants.
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+
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Application has been made to the Securities and Exchange Commission for confidential treatment of certain provisions of these exhibits. Omitted material for which confidential treatment has been requested and has been filed separately with the Securities and Exchange Commission.
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February 24, 2017
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MPLX LP
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By:
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MPLX GP LLC
Its general partner
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By:
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/s/ Paula L. Rosson
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Paula L. Rosson
Senior Vice President and Chief Accounting Officer of MPLX GP LLC
(the general partner of MPLX LP)
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*
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The undersigned, by signing his name hereto, does sign and execute this report pursuant to the Power of Attorney executed by the above-named directors and officers of the general partner of the registrant, which is being filed herewith on behalf of such directors and officers.
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By:
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/s/ Gary R. Heminger
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February 24, 2017
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Gary R. Heminger
Attorney-in-Fact
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GENERAL PARTNER
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MPLX GP LLC
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By:
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/s/ Gary R. Heminger
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Gary R. Heminger
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Chairman of the Board and Chief Executive
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Officer
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MPLX GP LLC
Non-Management Director Compensation Package
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Annual Board Retainer (Cash)
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$87,500
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Annual Director Deferred Phantom Unit Equity Award
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$87,500
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Total Annual Compensation Package –
Exclusive of Chair Retainers
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$175,000
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Audit Committee Annual Chair Retainer (Cash)
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$15,000
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Conflicts Committee Annual Chair Retainer (Cash)
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$15,000
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Lead Director Annual Retainer (Cash)
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$15,000
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Any Other Committees Annual Chair Retainer (Cash)
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$7,500
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1.
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Exhibit B
of the Agreement shall be deleted and replaced with the
Exhibit B
attached to this First Amendment, which amends the Management Fee Rates.
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1.
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Capitalized terms used but not defined in this First Amendment shall have the meaning
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1.
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This First Amendment supersedes any other prior agreements or understandings of the parties relating to this subject matter and the parties are not relying on any statement, representation, promise or inducement not expressly set forth herein.
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2.
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This First Amendment may be executed in one or more counterparts, and in both original form and one or more photocopies, each of which shall be deemed to be an original, but all of which together shall be deemed to constitute one and the same instrument.
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3.
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Except for the provisions of the Agreement specifically addressed in this First Amendment, all other provisions of the Agreement shall remain in full force and effect.
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MARATHON PETROLEUM COMPANY LP
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HARDIN STREET MARINE LLC
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By:
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/s/ J. S. Swearingen, Vice President
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By:
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/s/ M. Todd Sandifer, President
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J. S. Swearingen, Vice President
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M. Todd Sandifer, President
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1.
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Logistics and Commercial Services
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2.
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Vetting Services
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3.
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Loss Control Services
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4.
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Brokerage Services
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1.
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The definition for “Quarterly Throughput Commitment” shall be removed in its entirety and replaced with the following:
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2.
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Except as amended herein, all other terms and conditions of the Agreement shall remain in full force and effect.
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3.
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In the event of any conflict between the terms of the provision of this Amendment and the terms and provisions of the Agreement, the terms and provisions of this Amendment shall prevail.
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4.
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Any terms not defined herein shall have the same meaning as specified in the Agreement.
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MARATHON PETROLEUM COMPANY LP
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MARATHON PIPE LINE LLC
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By: MPC Investment LLC, its General Partner
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By:
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/s/ C. M. Palmer
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By:
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/s/ Craig O. Pierson
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Name:
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C. M. Palmer
Sr. V.P. Supply Distribution and Planning
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Name:
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Craig O. Pierson
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Title:
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Title:
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President
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For the Years Ended December 31,
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2016
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2015
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2014
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2013
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2012
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Portion of rentals representing interest
(1)
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$
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15
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$
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7
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$
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6
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$
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6
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$
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5
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Capitalized interest
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28
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5
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1
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1
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1
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Other interest and fixed charges
(2)
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254
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40
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4
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—
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—
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Total fixed charges (A)
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$
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297
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$
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52
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$
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11
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$
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7
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$
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6
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Preferred dividend requirements
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$
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41
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$
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—
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$
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—
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$
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—
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$
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—
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Ratio of income (loss) before provision for taxes to net income (loss)
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1.0
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1.0
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1.0
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1.0
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1.0
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Total preferred dividends
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$
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41
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$
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—
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$
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—
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$
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—
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$
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—
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Combined fixed charges and preferred dividends (B)
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$
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338
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$
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52
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$
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11
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$
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7
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$
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6
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Earnings-pretax income with applicable adjustments (C)
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$
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740
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$
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310
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$
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252
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$
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220
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$
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211
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Ratio of (C) to (A)
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2.5
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6.0
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22.9
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31.4
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35.2
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Ratio of (C) to (B)
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2.2
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6.0
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22.9
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31.4
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35.2
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a)
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act with honesty and integrity, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;
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b)
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provide full, fair, accurate, timely, and understandable disclosure in reports and documents that the Partnership files with, or submits to, the Securities and Exchange Commission (the “Commission”) and in other public communications made by the Partnership;
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c)
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comply with applicable laws, governmental rules and regulations, including insider trading laws;
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d)
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promote the prompt internal reporting of potential violations or other concerns related to this Code of Ethics to the Chair of the Audit Committee of the General Partner’s Board of Directors and to the appropriate person or persons identified in the Code of Business Conduct, and encourage employees to talk to supervisors, managers or other appropriate personnel when in doubt about the best course of action in a particular situation;
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e)
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avoid (i) taking personal advantage of opportunities that are discovered through the use of Partnership property, information or position; (ii) using Partnership property, information, or position for personal gain; and (iii) competing with the Partnership;
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f)
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respect the confidentiality of information acquired in the course of performing their responsibilities;
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g)
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endeavor to deal fairly with the Partnership’s customers, suppliers, competitors and employees;
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h)
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protect the Partnership’s assets and ensure the efficient use of those assets for legitimate business purposes;
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i)
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maintain the skills necessary and relevant to the Partnership’s needs;
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j)
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promote, as appropriate, contact with the Office of Business Integrity and Compliance or the Chair of the Audit Committee of the General Partner’s Board of Directors for any issues concerning improper accounting or financial reporting of the Partnership without fear of retaliation; and
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k)
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proactively promote ethical and honest behavior within the General Partner and the Partnership.
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Name of Subsidiary
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Jurisdiction of Organization/Incorporation
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*
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Centrahoma Processing LLC
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Delaware
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Hardin Street Marine LLC
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Delaware
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*
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Jefferson Gas Gathering Company, L.L.C.
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Delaware
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Marathon Pipe Line LLC
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Delaware
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MarkWest Blackhawk, L.L.C.
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Texas
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MarkWest Bluestone Ethane Pipeline, L.L.C.
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Delaware
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MarkWest Buffalo Creek Gas Company, L.L.C.
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Oklahoma
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*
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MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C.
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Delaware
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MarkWest Energy Appalachia, L.L.C.
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Delaware
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MarkWest Energy East Texas Gas Company, L.L.C.
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Delaware
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MarkWest Energy Finance Corporation
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Delaware
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MarkWest Energy GP, L.L.C.
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Delaware
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MarkWest Energy Operating Company, L.L.C.
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Delaware
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MarkWest Energy Partners, L.P.
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Delaware
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MarkWest Energy South Texas Gas Company, L.L.C.
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Delaware
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MarkWest Energy West Texas Gas Company, L.L.C.
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Delaware
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MarkWest Gas Marketing, L.L.C.
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Texas
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MarkWest Gas Services, L.L.C.
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Texas
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MarkWest Hydrocarbon, L.L.C.
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Delaware
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MarkWest Javelina Company, L.L.C.
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Texas
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MarkWest Javelina Pipeline Company, L.L.C.
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Texas
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MarkWest Liberty Bluestone, L.L.C.
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Delaware
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MarkWest Liberty Ethane Pipeline, L.L.C.
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Delaware
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MarkWest Liberty Gas Gathering, L.L.C.
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Delaware
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MarkWest Liberty Midstream & Resources, L.L.C.
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Delaware
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MarkWest Mariner Pipeline, L.L.C.
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Delaware
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MarkWest Marketing, L.L.C.
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Delaware
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MarkWest McAlester, L.L.C.
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Oklahoma
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MarkWest Michigan Pipeline Company, L.L.C.
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Michigan
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MarkWest Mountaineer Pipeline Company, L.L.C.
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Delaware
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MarkWest New Mexico, L.L.C.
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Texas
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MarkWest Ohio Fractionation Company, L.L.C.
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Delaware
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MarkWest Oklahoma Gas Company, L.L.C.
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Oklahoma
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MarkWest Panola Pipeline, L.L.C.
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Texas
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MarkWest Pinnacle, L.L.C.
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Texas
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*
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MarkWest Pioneer, L.L.C.
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Delaware
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*
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Indicates a company that is not wholly owned directly or indirectly by MPLX LP.
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Signature
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Title
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/s/ Gary R. Heminger
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Chairman of the Board of Directors and
Chief Executive Officer of MPLX GP LLC
(principal executive officer)
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Gary R. Heminger
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/s/ Pamela K.M. Beall
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Director, Executive Vice President and Chief
Financial Officer of MPLX GP LLC
(principal financial officer)
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Pamela K.M. Beall
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/s/ Paula L. Rosson
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Senior Vice President and Chief Accounting Officer
of MPLX GP LLC
(principal accounting officer)
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Paula L. Rosson
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/s/ Donald C. Templin
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Director, President of MPLX GP LLC
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Donald C. Templin
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/s/ Michael L. Beatty
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Director of MPLX GP LLC
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Michael L. Beatty
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/s/ David A. Daberko
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Director of MPLX GP LLC
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David A. Daberko
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/s/ Timothy T. Griffith
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Director of MPLX GP LLC
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Timothy T. Griffith
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/s/ Christopher A. Helms
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Director of MPLX GP LLC
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Christopher A. Helms
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/s/ Garry L. Peiffer
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Director of MPLX GP LLC
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Garry L. Peiffer
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/s/ Dan D. Sandman
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Director of MPLX GP LLC
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Dan D. Sandman
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/s/ Frank M. Semple
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Director of MPLX GP LLC
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Frank M. Semple
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/s/ John P. Surma
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Director of MPLX GP LLC
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John P. Surma
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/s/ C. Richard Wilson
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Director of MPLX GP LLC
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C. Richard Wilson
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1.
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I have reviewed this report on Form 10-K of MPLX LP;
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
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The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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(a)
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Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
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(b)
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Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
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(c)
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Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
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(d)
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Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
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5.
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The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
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(a)
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All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
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(b)
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Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
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Date: February 24, 2017
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/s/ Gary R. Heminger
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Gary R. Heminger
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Chairman of the Board of Directors and Chief Executive Officer of MPLX GP LLC (the general partner of MPLX LP)
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1.
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I have reviewed this report on Form 10-K of MPLX LP;
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2.
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Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
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3.
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Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
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4.
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The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
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(a)
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Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
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(b)
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Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
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(c)
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Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
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(d)
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Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
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5.
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The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):
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(a)
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All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and
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(b)
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Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.
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Date: February 24, 2017
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/s/ Pamela K.M. Beall
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Pamela K.M. Beall
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Director, Executive Vice President and Chief Financial Officer of MPLX GP LLC
(the general partner of MPLX LP)
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(1)
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
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(2)
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
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February 24, 2017
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/s/ Gary R. Heminger
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Gary R. Heminger
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Chairman of the Board of Directors and Chief Executive Officer of MPLX GP LLC (the general partner of MPLX LP)
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(1)
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The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
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(2)
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The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.
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February 24, 2017
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/s/ Pamela K.M. Beall
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Pamela K.M. Beall
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Director, Executive Vice President and Chief Financial Officer of MPLX GP LLC
(the general partner of MPLX LP)
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