10-K 1 mplx-20161231x10k.htm 10-K Document

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 Form 10-K
x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2016

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the transition period from ___________________ to __________________
Commission file number 001-35714
MPLX LP
(Exact name of registrant as specified in its charter)
Delaware
 
27-0005456
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
200 E. Hardin Street, Findlay, Ohio 45840
(Address of principal executive offices)
(419) 421-2414
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Units Representing Limited Partnership Interests
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    
Yes   x    No  ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes   ¨    No  x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes   x   No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files.)    Yes   x    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    x
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer x    Accelerated filer ¨    Non-accelerated filer ¨    Smaller reporting company ¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes   ¨    No   x
The aggregate market value of common units held by non-affiliates as of June 30, 2016 was approximately $8.4 billion. Common units held by executive officers and directors of the registrant and its affiliates are not included in the computation. The registrant, solely for the purpose of this required presentation, has deemed its directors and executive officers and those of its affiliates to be affiliates.
MPLX LP had 357,257,661 common units, 3,990,878 Class B units and 7,372,419 general partner units outstanding at February 13, 2017.
DOCUMENTS INCORPORATED BY REFERENCE: None



MPLX LP
Unless the context otherwise requires, references in this report to “MPLX LP,” “the Partnership,” “we,” “our,” “us,” or like terms refer to MPLX LP and its subsidiaries, including MPLX Operations LLC (“MPLX Operations”), MPLX Terminal and Storage LLC (“MPLX Terminal and Storage”), MarkWest Energy Partners, L.P. (“MarkWest”), MarkWest Hydrocarbon, L.L.C. (“MarkWest Hydrocarbon”), MPLX Pipe Line Holdings LLC (“Pipe Line Holdings”), Marathon Pipe Line LLC (“MPL”), Ohio River Pipe Line LLC (“ORPL”) and Hardin Street Marine LLC (“HSM”). We have partial ownership interests in a number of joint venture legal entities, including MarkWest Pioneer, L.L.C. (“MarkWest Pioneer”), MarkWest Utica EMG, L.L.C. (“MarkWest Utica EMG”) and its subsidiary Ohio Gathering Company, L.L.C. (“Ohio Gathering”), Ohio Condensate Company, L.L.C. (“Ohio Condensate”), Wirth Gathering Partnership (“Wirth”) and MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. (“Jefferson Dry Gas”). References to “MPC” refer collectively to Marathon Petroleum Corporation and its subsidiaries, other than the Partnership. References to “Predecessor” refer collectively to HSM’s related assets, liabilities and results of operations.

Table of Contents
 
 
 
Page
 
 
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
Item 15.
Item 16.
Form 10-K Summary
 



Glossary of Terms
The abbreviations, acronyms and industry technology used in this report are defined as follows.
ARO
Asset retirement obligation
ASC
Accounting Standards Codification
ATM Program
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
Bbl
Barrels
bcf/d
Billion cubic feet per day
Btu
One British thermal unit, an energy measurement
Condensate
A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions
DCF (a non-GAAP financial measure)
Distributable Cash Flow
DOT
United States Department of Transportation
Dth/d
Dekatherms per day
EBITDA (a non-GAAP financial measure)
Earnings Before Interest, Taxes, Depreciation and Amortization
EIA
United States Energy Information Administration
EPA
United States Environmental Protection Agency
ERCOT
Electric Reliability Council of Texas
FASB
Financial Accounting Standards Board
FERC
Federal Energy Regulatory Commission
GAAP
Accounting principles generally accepted in the United States of America
Gal
Gallon
Gal/d
Gallons per day
IDR
Incentive distribution rights
Initial Offering
Initial public offering on October 12, 2012
IRS
Internal Revenue Service
LIBOR
London Interbank Offered Rate
mbbls
Thousands of barrels
mbpd
Thousand barrels per day
mcf
One thousand cubic feet of natural gas
MMBtu
One million British thermal units, an energy measurement
mmcf/d
One million cubic feet of natural gas per day
Net operating margin (a non-GAAP financial measure)
Segment revenue, less segment purchased product costs, less realized derivative gain (loss)
NGL
Natural gas liquids, such as ethane, propane, butanes and natural gasoline
NYSE
New York Stock Exchange
OTC
Over-the-Counter
Realized derivative gain/loss
The gain or loss recognized when a derivative matures or is settled
PADD
Petroleum Administration for Defense District
PHMSA
Pipeline and Hazardous Materials Safety Administration
PPI
Producer Price Index
SEC
Securities and Exchange Commission
SMR
Steam methane reformer, operated by a third party and located at the Javelina gas processing and fractionation complex in Corpus Christi, Texas
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
USCG
United States Coast Guard
VIE
Variable interest entity
WTI
West Texas Intermediate



Disclosures Regarding Forward-Looking Statements

This Annual Report on Form 10-K, particularly Item 1. Business, Item 1A. Risk Factors, Item 3. Legal Proceedings, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 7A. Quantitative and Qualitative Disclosures about Market Risk, includes forward-looking statements. You can identify our forward-looking statements by words such as “anticipate,” “believe,” “design,” “estimate,” “objective,” “expect,” “forecast,” “goal,” “guidance,” “imply,” “intend,” “opportunity,” “outlook,” “plan,” “position,” “potential,” “predict,” “project,” “prospective,” “pursue,” “seek,” “strategy,” “target,” “could,” “may,” “should,” “would,” “will” or other similar expressions that convey the uncertainty of future events or outcomes. In accordance with “safe harbor” provisions of the Private Securities Litigation Reform Act of 1995, these statements are accompanied by cautionary language identifying important factors, though not necessarily all such factors, that could cause future outcomes to differ materially from those set forth in the forward-looking statements.

Forward-looking statements include, but are not limited to, statements that relate to, or statements that are subject to risks, contingencies or uncertainties that relate to:

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);
anticipated levels of regional, national and worldwide prices of crude oil, natural gas, NGLs and refined products;
anticipated levels of drilling activity, production rates and volumes of throughput of crude oil, natural gas, NGLs, refined products or other hydrocarbon-based products;
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;
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;
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
the anticipated effects of actions of third parties such as competitors, or federal, foreign, state or local regulatory authorities, or plaintiffs in litigation.

We have based our forward-looking statements on our current expectations, estimates and projections about our industry and our partnership. We caution that these statements are not guarantees of future performance and you should not rely unduly on them, as they involve risks, uncertainties and assumptions that we cannot predict. In addition, we have based many of these forward-looking statements on assumptions about future events that may prove to be inaccurate. While our management considers these assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond our control. Accordingly, our actual results may differ materially from the future performance that we have expressed or forecast in our forward-looking statements. Differences between actual results and any future performance suggested in our forward-looking statements could result from a variety of factors, including the following:

changes in general economic, market or business conditions;
changes in the economic and financial condition of MPLX LP;

1


risks and uncertainties associated with intangible assets, including any future goodwill or intangible assets impairment charges;
changes in producer customers’ drilling plans or in volumes of throughput of crude oil, natural gas, NGLs, refined products or other hydrocarbon-based products;
changes in regional, national and worldwide prices of crude oil, natural gas, NGLs and refined products;
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;
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;
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;
actions taken by our competitors and the expansion and retirement of pipeline, processing, fractionation and treating capacity in response to market conditions;
changes in fuel and utility costs for our facilities;
failure to realize the benefits projected for capital projects, or cost overruns associated with such projects;
the ability to successfully implement growth strategies, whether through organic growth or acquisitions;
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;
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;
unusual weather conditions and natural disasters;
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;
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;
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;
labor and material shortages;
the ability and willingness of parties with whom we have material relationships to perform their obligations to us;
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;
increases in and availability of equity capital, changes in the availability of unsecured credit and changes affecting the credit markets generally; and
the other factors described in Item 1A. Risk Factors.

We undertake no obligation to update any forward-looking statements except to the extent required by applicable law.

2


Part I

Item 1. Business

OVERVIEW

We are a diversified, growth-oriented master limited partnership (“MLP”) formed in 2012 by MPC to own, operate, develop and acquire midstream energy infrastructure assets. We are engaged in the gathering, processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of NGLs; and the gathering, transportation and storage of crude oil and refined petroleum products.

Our assets include infrastructure to support MPC including approximately 2,900 miles of crude oil and refined product pipelines across nine states. We own a barge dock facility with approximately 78 mbpd of crude oil and refined product throughput capacity, as well as crude oil and product storage facilities (tank farms) with approximately 4,533 mbbls of available storage capacity. We also own a butane cavern with approximately 1,000 mbbls of available storage capacity. Effective March 31, 2016, the Partnership acquired MPC’s inland marine business, comprised of 18 tow boats and 205 tank barges. This business is operated through HSM and the related assets, liabilities and results of operations are collectively referred to as the “Predecessor.” On December 4, 2015, we completed the merger with MarkWest (the “MarkWest Merger”), which is one of the largest processors of natural gas in the United States and the largest processor and fractionator in the Marcellus and Utica shale plays. These assets include gathering and processing infrastructure of more than 5,600 miles of gas and NGL pipelines, 54 gas processing plants, 14 NGL fractionation facilities and two condensate stabilization facilities.

MPC is our sponsor and a large source of our revenues. We have multiple transportation and storage services agreements with MPC. These agreements are long-term, fee-based agreements with minimum volume commitments and, therefore, MPC will continue to be an important source of our revenues for the foreseeable future. Furthermore, as a result of the MarkWest Merger, we also have long-term relationships with a diverse set of producer customers in many natural gas resource plays including the Marcellus Shale, Utica Shale, Huron/Berea Shale, Haynesville Shale, Woodford Shale, Granite Wash formation and the Permian Basin.

As of February 13, 2017, MPC owned our general partner, MPLX GP LLC (“MPLX GP”), and the associated incentive distribution rights, in addition to an approximate 23.5 percent limited partner interest (including the Class B units on an as-converted basis) in us. Given MPC’s significant interest in us, and its stated intent to grow its midstream business, MPC has recently announced plans to offer its MLP-qualifying assets estimated to generate $1.4 billion of annual EBITDA from its portfolio of midstream assets. MPC expects to offer us these assets as soon as practicable in 2017, subject to market conditions, requisite approvals and regulatory clearances, including tax. In conjunction with the completion of the announced dropdowns, MPC also expects to exchange its economic interests in MPLX GP for newly issued MPLX LP units in order to optimize the Partnership’s cost of capital. We also have significant organic growth opportunities to expand midstream services throughout major shale plays in the United States. Furthermore, we may pursue third-party midstream acquisitions independently or with MPC to complement our existing geographic footprint or expand our activities into new areas. MPC is under no obligation, however, to offer to sell us additional assets or to pursue acquisitions cooperatively with us, and we are under no obligation to acquire any such additional assets or pursue any such cooperative acquisitions.

Finally, we have an investment grade credit profile that provides the Partnership strong financial flexibility in order to fund growth projects and execute its strategic plans.


3


We conduct our operations in the following operating segments: Logistics and Storage (“L&S”) and Gathering and Processing (“G&P”). For more information on these segments, see Our Operating Segments discussion below. The following map details our individual assets:
mplxoperationmap022417.jpg


The following table summarizes the operating performance for each segment for the year ended December 31, 2016. For further discussion of our segments and a reconciliation to our Consolidated Statements of Income, see Item 8. Financial Statements and Supplementary Data – Note 10.
 
 
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



4


RECENT DEVELOPMENTS

On March 14, 2016, the Partnership entered into a Membership Interests Contribution Agreement (the “Contribution Agreement”) with MPLX GP, MPLX Logistics Holdings LLC and MPC Investment LLC (“MPC Investment”), each a wholly-owned subsidiary of MPC, related to the acquisition of HSM, MPC’s inland marine business, from MPC. Pursuant to the Contribution Agreement, the transaction was valued at $600 million consisting of a fixed number of common units and general partner units. The general partner units maintained MPC’s two percent general partner interest in the Partnership. The acquisition closed on March 31, 2016. MPC waived distributions in the first quarter of 2016 on MPLX LP common units issued in connection with this transaction.

The inland marine business, which transports light products, heavy oils, crude oil, renewable fuels, chemicals and feedstocks in the Midwest and U.S. Gulf Coast regions, accounted for nearly 60 percent of the total volumes MPC shipped by inland marine vessels as of March 31, 2016. The Partnership accounts for HSM as a reporting unit of the L&S segment. See Item 8. Financial Statements and Supplementary Data – Note 4 for more information on this transaction.

On May 13, 2016, MPLX LP completed the private placement of approximately 30.8 million 6.5 percent Series A Convertible Preferred units (the "Preferred units") for a cash purchase price of $32.50 per unit. The aggregate net proceeds of approximately $984 million from the sale of the Preferred units were used for capital expenditures, repayment of debt and general partnership purposes. The Preferred units rank senior to all common units with respect to distributions and rights upon liquidation. The holders of the Preferred units are entitled to receive cumulative quarterly distributions equal to $0.528125 per unit commencing for the quarter ended June 30, 2016, with a prorated amount from the date of issuance. Following the second anniversary of the issuance of the Preferred units, the holders of the Preferred units will receive as a distribution the greater of $0.528125 per unit or the amount of per unit distributions paid to common units. See Item 8. Financial Statements and Supplementary Data – Note 9 for more information on this transaction.

On August 4, 2016, MPLX LP entered into a Second Amended and Restated Distribution Agreement (the “Distribution
Agreement”) providing for the continuous issuance of MPLX LP common units, in amounts, at prices and on terms to be
determined by market conditions and other factors at the time of any offerings (such continuous offering program, or at-the-market program, referred to as the “ATM Program”). MPLX LP expects to use the net proceeds from sales under the ATM
Program for general partnership purposes including repayment of debt and funding for acquisitions, working capital
requirements and capital expenditures.

During the year ended December 31, 2016, the Partnership issued an aggregate of 26 million common units under the ATM Program generating net proceeds of approximately $776 million. As of December 31, 2016, $717 million of common units remains available for issuance through the ATM Program under the Distribution Agreement.

On September 1, 2016, the Partnership and various affiliates initiated a series of reorganization transactions in order to simplify the Partnership’s ownership structure and its financial and tax reporting requirements (the "Class A Reorganization"). In connection with these transactions, all of the issued and outstanding MPLX LP Class A units, all of which were held by MarkWest Hydrocarbon (MarkWest Hydrocarbon, Inc. prior to the Class A Reorganization), were either distributed to or purchased by MPC in exchange for $84 million in cash and a fixed number of MPLX LP common units and MPLX LP general partner units. Following these preparatory transactions, all of the MPLX LP Class A units were exchanged on a one-for-one basis for newly issued common units representing limited partner interests in MPLX LP. MPC also contributed $141 million to facilitate the repayment of intercompany debt between MarkWest Hydrocarbon and MarkWest. As a result of these transactions, the MPLX LP Class A units were eliminated, are no longer outstanding and no longer participate in distributions of cash from the Partnership. Cash that is derived from or attributable to MarkWest Hydrocarbon’s operations is now treated in the same manner as cash derived from or attributable to other operations of the Partnership and its subsidiaries. See Item 8. Financial Statements and Supplementary Data – Note 8 for more information on this transaction.

On October 11, 2016, the Cornerstone Pipeline became fully operational and in December 2016, the Hopedale pipeline connection was completed. This project is reported within our L&S segment. This pipeline is designed to transport condensate and natural gasoline from origination facilities in Harrison County, OH, to a tank farm in East Sparta, OH, where the condensate and natural gasoline can then continue on to MPC’s refinery in Canton, OH. The completion of this key organic growth project has created transportation and marketing options for Utica and Marcellus shale production. Additional pipelines are currently under construction and will provide further distribution to the Midwest and Canada.

On January 3, 2017, MPC announced its plans to offer the Partnership the opportunity to acquire assets contributing an estimated $1.4 billion of annual EBITDA in 2017. These planned dropdowns are subject to market conditions, requisite approvals and regulatory clearances, including tax clearance.

5



On December 5, 2016, MPC offered up to 100 percent of MPLX Terminals LLC (“MPLX Terminals”), Hardin Street Transportation LLC (“Hardin Street Transportation”) and Woodhaven Cavern LLC (“Woodhaven Cavern”) to MPLX. MPLX Terminals owns and operates light products terminals. Hardin Street Transportation owns and operates various private crude oil and refined product pipeline systems and associated storage tanks. Woodhaven Cavern owns and operates butane and propane storage caverns. The transaction is expected to close in the first quarter of 2017, pending requisite approvals.

The Partnership's plans for funding these dropdowns would likely include debt and equity in approximately equal proportions, with the equity financing to be funded through transactions with MPC. In February 2017, we issued an additional $2.25 billion aggregate principal amount of senior notes, as described below. In addition to the expected dropdowns, MPC announced its intentions to offer to exchange its IDRs for MPLX LP units in conjunction with the completion of the dropdowns in order to reduce the Partnership's cost of capital.

On January 25, 2017, we announced the board of directors of our general partner had declared a distribution of $0.5200 per unit that was paid on February 14, 2017 to unitholders of record on February 6, 2017.

On February 6, 2017, the Partnership and Antero Midstream Partners LP (“Antero Midstream”) formed a strategic joint venture to support Antero Resources Corporation (“Antero Resources”) in the Marcellus Shale. Antero Midstream Partners released to the joint venture its dedication from Antero Resources of approximately 195,000 gross operated acres located in Tyler, Wetzel and Ritchie counties of West Virginia. The joint venture will support the ongoing development of incremental gas processing required by Antero Resources in the Marcellus Shale. The joint venture is also investing in fractionation capacity at MarkWest's Hopedale Complex in Ohio and has an option to invest in future fractionation expansions that support Antero Resources’ liquids production. See Item 8. Financial Statements and Supplementary Data – Note 24 for additional information.

On February 10, 2017, the Partnership completed a public offering of $1.25 billion aggregate principal amount of 4.125 percent unsecured senior notes due March 2027 (the “2027 Senior Notes”) and $1.0 billion aggregate principal amount of 5.200 percent unsecured senior notes due March 2047 (the “2047 Senior Notes” and, collectively with the 2027 Senior Notes, the “New Senior Notes”). The 2027 Senior Notes and the 2047 Senior Notes were offered at a price to the public of 99.834 percent and 99.304 percent of par, respectively. The Partnership intends to use the net proceeds from this offering for general partnership purposes, which may include, from time to time, acquisitions (including the previously announced planned dropdown of assets from MPC, the acquisition of the Ozark pipeline, and the acquisition of a partial, indirect equity interest in the Bakken Pipeline system) and capital expenditures. See Item 8. Financial Statements and Supplementary Data – Note 24 for additional information.

On February 13, 2017, the Partnership announced that it has entered into an asset purchase agreement with Enbridge Pipelines (Ozark) LLC (“Enbridge Ozark”), under which an affiliate of Pipe Line Holdings has agreed to purchase the Ozark pipeline for approximately $220 million from Enbridge Ozark. The Ozark pipeline is a 433-mile, 22-inch crude oil pipeline originating in Cushing, Oklahoma, and terminating in Wood River, Illinois, capable of transporting approximately 230,000 barrels per day. This purchase transaction is expected to close in the first quarter of 2017. See Item 8. Financial Statements and Supplementary Data – Note 24 for additional information.

On February 15, 2017, the Partnership closed on its previously announced intent to participate in a joint venture with Enbridge Energy Partners L.P. (“Enbridge Energy Partners”) to acquire a 9.1875 percent indirect interest in the Dakota Access Pipeline
(“DAPL”) and Energy Transfer Crude Oil Company Pipeline (“ETCOP”) projects, collectively referred to as the Bakken
Pipeline system, from Energy Transfer Partners, L.P. (“ETP”) and Sunoco Logistics Partners, L.P. (“SXL”) for $500 million.
Furthermore, MPC expects to become a committed shipper on the Bakken Pipeline system under terms of an on-going open
season. The Bakken Pipeline system is currently expected to deliver in excess of 470,000 barrels per day of crude oil from the Bakken/Three Forks production area in North Dakota to the Midwest through Patoka, Illinois and ultimately to the Gulf Coast. ETP and SXL collectively own a 75 percent interest in each of the two joint ventures that are developing the Bakken Pipeline system. MPLX LP and Enbridge Energy Partners intend to form a new joint venture to acquire 49 percent of ETP and SXL’s 75 percent indirect interest in the Bakken Pipeline system. MPLX LP will own 25 percent of this new joint venture with Enbridge, which results in its 9.1875 percent indirect ownership interest in the Bakken Pipeline system. The Partnership expects to account for its investment using the equity method of accounting. See Item 8. Financial Statements and Supplementary Data – Note 24 for additional information.


6


BUSINESS STRATEGIES

Our primary business objectives are to enhance unitholder returns through the generation of stable cash flows. We intend to accomplish these objectives by executing the following strategies:

Maintain Long-Term Integrated Relationships with Our Producer Customers. We develop long-term integrated relationships with our producer customers. Our relationships are characterized by an intense focus on customer service and a deep understanding of our producer customers’ requirements coupled with the ability to increase the level of our midstream services in response to their midstream requirements. Through collaborative planning, we construct midstream infrastructure and provide unique solutions that are critical to the ongoing success of our producer customers’ development plans. As a result of delivering high-quality midstream services, MarkWest has been a top-rated midstream service provider since 2006 as determined by an independent research provider.

Grow through Acquisitions. In addition to the MarkWest Merger and HSM acquisition, we plan to continue pursuing acquisitions of complementary assets from MPC as well as third parties, such as the Ozark pipeline acquisition and the acquisition of the joint venture interest in the Bakken Pipeline system. As discussed above, we announced that we expect to acquire assets from MPC with an estimated $1.4 billion of annual EBITDA as soon as practicable, subject to requisite approvals, and regulatory clearance, including tax. We may also pursue third-party midstream acquisitions independently or with MPC that complement our existing geographic footprint or expand our activities into new areas.

Increase Operating Cash Flow and Pursue Organic Growth Opportunities. We intend to increase operating cash flow by continuing to grow in our primary areas of operation to meet anticipated demand for additional midstream services. In addition, we intend to increase operating cash flow by evaluating and capitalizing on organic investment opportunities that may arise in our areas of operations and increasing the utilization of our existing facilities by providing additional services for new and existing customers. We will evaluate organic growth projects both within our geographic footprint as well as in new areas that we consider strategic. With the support of MPC as our sponsor, we have the ability to develop incremental infrastructure to support growth across the hydrocarbon value chain.

Focus on Fee-Based Businesses. We are focused on generating stable cash flows by providing fee-based midstream services to our customers. For the full year ending December 31, 2017, we expect fee-based contracts to be approximately 95 percent of our net operating margin (for more information on net operating margin, which is a non-GAAP measure, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Measures).

Sustain Long-Term Growth. Our goal is to maintain an attractive distribution growth profile over the long term. Since the Initial Offering, we have increased our distribution for 16 consecutive quarters, which represents a compound annual growth rate of 18.6 percent over the minimum quarterly distribution. Our goal is to also optimize our cost of capital by maintaining an investment grade credit profile, providing visibility to future growth, and eliminating IDR distributions to MPC. On January 3, 2017, we announced that we expect to exchange MPLX LP units for MPC’s economic interests in MPLX GP, including IDR’s, in conjunction with the completion of the MPC asset acquisitions described above. We believe our plans, along with the support of our sponsor, provide multiple avenues to support our distribution growth profile over the long-term.

Maintain Safe and Reliable Operations. We believe that providing safe, reliable and efficient services is a key component in generating stable cash flows, and we are committed to maintaining and improving the safety, reliability and efficiency of our operations. We intend to continue promoting a high standard for safety and environmental stewardship.

COMPETITIVE STRENGTHS

We believe we are well positioned to execute our business strategies based on the following competitive strengths:

Strategically Located Assets. Our L&S segment assets are primarily located in the Midwest and Gulf Coast regions of the United States and our G&P segment assets are primarily located in the Northeast and Southwest regions of the United States.

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

7


fractionators in the United States.
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.

Leading Midstream Positions Drive Investment Opportunities. Our organic growth capital plan range for 2017 is $1.4 billion to $1.7 billion, which does not include the anticipated dropdowns or acquisitions previously discussed or their respective subsequent capital spending. The G&P segment capital plan includes investments that are expected to support producer customers. During 2017, we expect to complete 400 mmcf/d of additional natural gas processing capacity and 120 mbpd of additional fractionation capacity (of which 60 mbpd of fractionation capacity has already been completed), primarily in the Marcellus Shale. The L&S segment capital plan includes the development of various crude oil and refined petroleum products infrastructure projects, including a build out of Utica Shale infrastructure in connection with the recently completed Cornerstone Pipeline, a butane cavern and a tank farm expansion. We also have large organic growth prospects associated with the anticipated growth of MPC’s operations and third-party activity in our areas of operation that will provide attractive returns and cash flows. We also plan to pursue acquisitions of other midstream assets on a standalone basis or cooperatively with MPC.

Strategic Relationship with MPC. We have a strategic relationship with MPC and MPC views us as integral to its operations and is aligned with our success. We believe MPC to be the largest crude oil refiner in the Midwest and the third-largest in the United States based on crude oil refining capacity. MPC is well-capitalized, with investment grade credit ratings, and owns our general partner, an approximate 23.5 percent limited partner interest (including the Class B units on an as-converted basis) as of February 13, 2017 and all of our incentive distribution rights. We expect to acquire a portfolio of midstream assets from MPC, as recently announced in its plan to dropdown an estimated $1.4 billion of EBITDA in 2017, subject to regulatory and tax clearance. In conjunction with the completion of the announced dropdowns, MPC also expects to exchange its economic interest in MPLX GP for newly issued MPLX LP units in order to optimize the Partnership’s cost of capital. We believe that our relationship with MPC will provide us with significant growth opportunities, as well as a base of stable cash flows.

High-Quality, Well-Maintained Asset Base. We continually invest in the maintenance and integrity of our assets and have developed various programs to help us efficiently monitor and maintain them. For example, we utilize MPC’s patented integrity management program that employs state-of-the-art mechanical integrity inspection and repair programs to enhance the safety of certain of our pipelines.

Stable and Predictable Cash Flows. We generate a substantial majority of our revenue through long-term, fee-based agreements. We believe our long-term contracts, which we define as contracts with remaining terms of four years or more, lend greater stability to our cash flow profile. The table below provides long-term contract details by segment as of December 31, 2016:
 
Remaining contract term
 
% of volumes
L&S segment
6 years
 
72
%
G&P segment
4 to 19 years
 
85
%

Financial Flexibility. As of December 31, 2016, we had $234 million of cash and $2.5 billion available on our revolving credit facilities. We believe that we will have the financial flexibility to execute our growth strategy through excess cash reserves, borrowing capacity under our revolving credit facilities and access to the debt and equity capital markets. See Item 8. Financial Statements and Supplementary Data – Note 17 and Note 8 for additional information regarding our recent transactions related to debt and common unit offerings.


8


Experienced Management Team. Our management team has substantial experience in the management and operation of midstream assets. Our management team also has expertise in acquiring and integrating assets as well as executing growth strategies in the midstream sector.

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


9


ORGANIZATIONAL STRUCTURE

The following diagram depicts our organizational structure and MPC’s ownership interests in us as of February 13, 2017.
orgstructure201610ka02.jpg

10


We are an MLP with outstanding common units, Preferred units, and Class B units.

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.


11


INDUSTRY OVERVIEW

We provide diversified services in the midstream sector across the hydrocarbon value chain. The types of midstream services provided by both our L&S and G&P segments are as follows:

L&S:

Our L&S assets are integral to the success of MPC’s operations related to transportation and storage across the hydrocarbon value chain.

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.
G&P:

The midstream natural gas industry is the link between the exploration for and production of natural gas and the delivery of its hydrocarbon components to end-use markets, and the components of this value chain are graphically depicted and further described below:
midstreamdiagrama04.jpg

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

12


as “y-grade”). Processing aids in allowing the residue gas remaining after extraction of NGLs to meet the quality specifications for long-haul pipeline transportation and commercial use.
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.

Historically, the majority of the domestic on-shore natural gas supply has been produced from conventional reservoirs that are characterized by large pockets of natural gas that are accessed using vertical drilling techniques. In the past decade, the supply of natural gas production from the conventional sources has declined as these reservoirs are being depleted. Due to advances in well completion technology and horizontal drilling techniques, unconventional sources, such as shale and tight sand formations, have become the most significant source of current and expected future natural gas production. The industry as a whole is characterized by regional competition, based on the proximity of gathering systems and processing/fractionation plants to producing natural gas wells, or to facilities that produce natural gas as a byproduct of refining crude oil. Due to the shift in the source of natural gas production, midstream providers with a significant presence in the shale plays will likely have a competitive advantage. Well-positioned operations allow access to all major NGL markets and provide for the development of export solutions for producers. This proximity is enhanced by infrastructure build-out and pipeline projects.

Basic NGL products and their typical uses are discussed below. The following basic NGL products are sold in our G&P segment.

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.

The other primary products also produced and sold in our G&P segment are discussed below.

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.


13


OUR OPERATING SEGMENTS

We conduct our operations in the following operating segments: L&S and G&P. Our assets and operations in each of these segments are described below.

L&S:

The L&S segment includes transportation and storage of crude oil, refined products and other hydrocarbon-based products, primarily in the Midwest and Gulf Coast regions of the United States. These assets consist of a network of common carrier crude oil and refined product pipeline systems and associated storage assets and an inland marine business. We believe our network of petroleum pipelines is one of the largest in the United States, based on total annual volumes delivered. We also own a butane cavern in Neal, West Virginia with approximately 1,000 mbbls of liquefied petroleum gas storage capacity. Our marine business owns and operates boats, barges, and third-party chartered equipment and includes a Marine Repair Facility (“MRF”), which is a full service marine shipyard located on the Ohio River adjacent to MPC’s Catlettsburg, Kentucky refinery. We have completed the Cornerstone pipeline project, which is the building block for other projects that we expect to become a critical solution for the industry to move condensate and NGLs out of the Marcellus and Utica regions into refining centers in the Midwest and connect to the pipelines to Canada. We are also constructing a butane cavern in Robinson, Illinois, which will be a 1,400-mbbl hard rock mined storage cavern. Our L&S assets are integral to the success of MPC’s operations.

We generate revenue in the L&S segment primarily by charging tariffs for transporting crude oil, refined products and other hydrocarbon-based products through our pipelines and at our barge dock and fees for storing crude oil and refined products at our storage facilities. Our marine business generates revenue under a fee-for-capacity contract with MPC. We are also the operator of additional crude oil and refined product pipelines owned by MPC and third parties for which we are paid operating fees. For the year ended December 31, 2016, approximately 92 percent of L&S segment revenue and other income was generated from MPC. In this segment, we do not take ownership of the crude oil or products that we transport and store for our customers, and we do not engage in the trading of any commodities. However, we could be required to purchase or sell crude oil volumes in the open market to make up negative or positive imbalances.

The following is a summary of the significant assets owned by the L&S segment:
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

 
 

14



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.

As of December 31, 2016, our marine transportation operations included 18 owned towboats as well as 204 owned and 18 leased barges that transport refined products and crude oil on the Ohio, Mississippi and Illinois rivers and their tributaries and inter-coastal waterways. The following table sets forth additional details about MPLX LP’s barges and towboats.
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.

G&P:

Natural Gas Gathering

We operate several natural gas gathering systems that have a combined 5,439 mmcf/d throughput capacity in six states. The scope of gathering services that we provide depends on the composition of the raw, or untreated, gas at our producer customers’ wellheads. For dry gas, we gather and, if necessary, treat the gas and deliver it to downstream transmission systems. For wet gas that contains heavier and more valuable hydrocarbons, we gather the gas for processing at a processing complex. The capacities of these gathering systems are supported by long-term fee-based agreements with major producer customers.

Natural Gas Processing

Our natural gas processing complexes remove the heavier and more valuable hydrocarbon components from natural gas. This allows the residue gas remaining after extraction of the NGLs to meet the quality specifications for long-haul transmission pipeline transportation or commercial use.

We currently operate five complexes in the Marcellus Shale, including: processing, gathering, and C2+ fractionation at the Houston Complex located in Washington County, Pennsylvania (the “Houston Complex”); processing and de-ethanization at the Majorsville Complex located in Marshall County, West Virginia (the “Majorsville Complex”); processing and de-ethanization at the Mobley Complex located in Wetzel County, West Virginia (the “Mobley Complex”); processing and de-ethanization at the Sherwood Complex located in Doddridge County, West Virginia (the “Sherwood Complex”); and processing, gathering, and C2+ fractionation at the Keystone Complex located in Butler County, Pennsylvania (the “Keystone Complex”). Further, we operate one condensate stabilization facility with two mbpd of capacity near the Houston Complex.

MarkWest Utica EMG, our joint venture with an affiliate of EMG, operates two complexes in the Utica Shale, including: processing and de-ethanization at the Cadiz Complex in Harrison County, Ohio (the “Cadiz Complex”) and processing at the Seneca Complex in Noble County, Ohio (the “Seneca Complex”). We also operate a C3+ fractionation complex at the

15


Hopedale Complex located in Harrison County, Ohio (the “Hopedale Complex”). Ohio Condensate, our joint venture with Summit, operates one condensate stabilization facility with 23 mbpd of capacity.

We operate four processing complexes in the Appalachia region, including: the Kenova Complex located in Wayne County, West Virginia (the “Kenova Complex”); the Boldman Complex located in Pike County, Kentucky (the “Boldman Complex”); the Cobb Complex located in Kanawha County, West Virginia (the “Cobb Complex”); and the Langley Complex located in Langley, Kentucky (the “Langley Complex”). Further, we operate a C3+ fractionation complex at the Siloam Complex in South Shore, Kentucky (the “Siloam Complex”).

We also operate four complexes in the Southwest region, including: processing and gathering at the Carthage Complex located in Panola County, Texas (the “Carthage Complex”); processing and gathering at the Western Oklahoma Complex located in Custer and Beckham Counties, Oklahoma (the “Western Oklahoma Complex”); processing at the Hidalgo Complex located in Culberson County, Texas (the “Hidalgo Complex”); and treating, processing and C2+ fractionation at the Javelina Complex located in Corpus Christi, Texas (the “Javelina Complex”). We also own a non-operating interest in the Centrahoma processing complex.

The following table summarizes our current and planned processing assets:
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.

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The following table summarizes our key producer customers and attributes for each geographic region as of December 31, 2016:
 
 
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.

NGL Gathering

Once natural gas has been processed at a natural gas processing complex, the heavier and more valuable hydrocarbon components, which have been extracted as a mixed NGL stream, can be further separated into their component parts through the process of fractionation. We operate several NGL gathering pipelines for these mixed NGL streams that have a combined 818 mbpd throughput capacity in five states.

C3+ NGL Fractionation Complexes

Our NGL fractionation facilities separate the mixture of extracted NGLs into individual purity product components for end-use sale. All NGLs, other than purity ethane as discussed below, produced at our Majorsville Complex, Mobley Complex and Sherwood Complex are gathered to the Houston Complex or to the Hopedale Complex through a system of NGL pipelines to allow for fractionation into purity NGL products. We can also gather NGLs produced at a third-party’s processing facilities to the Houston, Hopedale and Keystone Complexes for fractionation.

Our fractionation facilities for propane and heavier NGLs are supported by long-term, fee-based agreements with our key producer customers. The following tables summarize our current and planned fractionation assets at these facilities:
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

17


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.

Ethane Recovery, Transportation and Associated Market Outlets

As a result of the volume of natural gas production from the liquids-rich areas of the Marcellus and Utica Shales, we have begun recovering ethane from the natural gas stream for producer customers, which allows them to meet residue gas pipeline quality specifications and downstream pipeline commitments. Depending on market conditions, producer customers may also benefit from the potential price uplift received from the sale of their ethane. The following table summarizes our current and planned de-ethanization assets, which are, or are expected to be, supported by a network of purity ethane pipelines:
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 have connections to several downstream ethane pipeline projects from many of our systems as follows:

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.

A significant portion of our business comes from a limited number of key customers. For the year ended December 31, 2016, revenues earned from one customer are significant to the segment, accounting for 17 percent of G&P segment revenue and 12 percent of consolidated revenue and other income. Additionally, revenues earned from a second customer are significant to the segment, accounting for 15 percent of G&P segment revenue and 10 percent of consolidated revenue and other income.

For further financial information regarding our segments, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data included in this Annual Report on Form 10-K.


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Equity Investment in Unconsolidated Affiliates - MarkWest Utica EMG

MarkWest Utica EMG is engaged in providing natural gas gathering, processing, and NGL fractionation, transportation and marketing services in the Utica Shale in eastern Ohio. We own 56 percent of MarkWest Utica EMG as of December 31, 2016.

The financial results for MarkWest Utica EMG and other unconsolidated affiliates are included in (Loss) income from equity method investments in our Consolidated Statements of Income. For a complete discussion of the formation of, and the accounting treatment for, MarkWest Utica EMG and other material unconsolidated affiliates, see Item 8. Financial Statements and Supplementary Data – Note 5.

OUR TRANSPORTATION AND STORAGE SERVICES AGREEMENTS WITH MPC

Our L&S assets are strategically located within, and integral to, MPC’s operations. We have entered into multiple transportation and storage services agreements with MPC. Under these long-term, fee-based agreements, we provide transportation and storage services to MPC and, other than on our marine transportation service agreement, MPC has committed to provide us with minimum quarterly throughput volumes on crude oil and refined products pipelines systems and minimum storage volumes of crude oil, products and butane. MPC has also committed to provide a fixed fee for 100 percent of available capacity for boats, barges and third-party chartered equipment under the marine transportation service agreement. All of our transportation services agreements for our crude oil and refined products pipeline systems include a 5-15 year term with various automatic renewal terms ranging from multiple 2-5 year terms unless terminated by either party no later than six months prior to the end of the term. Our butane cavern storage services agreement includes a 10-year term but does not automatically renew. Our storage services agreements for our tank farms include a three-year term and automatically renew for additional one-year terms unless terminated by either party no later than six months prior to the end of the term. Our marine transportation service agreement includes an initial six-year term and automatically renews up to two additional five-year terms unless terminated by either party no later than twelve months prior to the end of the current term.

The following table sets forth additional information regarding our transportation and storage services agreements:

Transportation and Storage Services Agreements with MPC
 
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.

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


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MPC’s obligations under these transportation and storage services agreements will not terminate if MPC no longer controls our general partner.

OPERATING AND MANAGEMENT SERVICES AGREEMENTS WITH MPC AND THIRD PARTIES

Operating Agreements

Through MPL, we operate various pipeline systems owned by MPC and third parties under existing operating services agreements that MPL has entered into with MPC and third parties. Under these operating services agreements, MPL receives an operating fee for operating the assets, which include certain MPC wholly-owned or partially-owned crude oil and refined product pipelines, and for providing various operational services with respect to those assets. MPL is generally reimbursed for all direct and indirect costs associated with operating the assets and providing such operational services. These agreements generally range from one to five years in length and automatically renew. Most of the agreements are indexed for inflation.

As noted above, MPL receives an annual fee for operating certain pipeline systems owned by MPC. This fee is currently $16 million and will be adjusted annually for inflation. MPC has agreed to indemnify MPL against any and all damages arising out of the operation of MPC’s pipeline systems unless such occurrence is due to the gross negligence or willful misconduct of MPL. MPL has agreed to indemnify MPC against any and all damages arising out of MPL’s gross negligence or willful misconduct in the operation of the pipeline systems. The initial term of this agreement was for one year and automatically renews from year-to-year unless terminated by either party.

Our existing operating services agreements include an operating agreement with Red Butte Pipe Line Company, which is owned by a third party. Under this agreement, MPL receives an operating fee for operating certain pipelines in Wyoming and Montana. The term of this agreement is through December 2018.

MPL maintains and operates four undivided joint interest pipeline systems including Capline, Centennial, Lou-Lex and Muskegon. MPL receives an operating fee for each of these systems, which is subject to adjustment for inflation. In addition, we are reimbursed for specific costs associated with operating each pipeline system. The length and renewals terms for each agreement vary.

Management Services Agreements

The Partnership has two management services agreements with wholly-owned subsidiaries of MPC under which it provides certain management services to MPC with respect to certain of MPC’s retained pipeline assets. The Partnership received $1 million in fees under these agreements in 2016. The Partnership may adjust annually for inflation and based on changes in the scope of management services provided.

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

The Partnership, through its wholly-owned subsidiary, HSM, has a management services agreement with MPC under which HSM provides management services to assist MPC in the oversight and management of the marine business. HSM receives a fixed annual fee for providing the required management services. This fee is adjusted annually on the anniversary of the contract for inflation and any changes in the scope of the management services provided. The Partnership received $21 million in fees under this agreement in 2016. This agreement expires on June 30, 2020.

OTHER AGREEMENTS WITH MPC

We have the following additional agreements with MPC:

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

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and tank farms within the L&S segment. Effective December 28, 2015, we entered into an additional employee services agreement with MPC, which requires that we reimburse MPC for certain operational and management services to us in support of our G&P segment and certain of our other operations. Lastly, we are party to an employee services agreement dated January 1, 2015, pursuant to which HSM reimburses MPC for employee benefit expenses along with certain operation and management services provided in support of HSM’s areas of operation. The agreement is effective until December 31, 2019. Prior to January 1, 2015, this agreement did not exist.

OUR RELATIONSHIP WITH MPC

One of our competitive strengths is our strategic relationship with MPC, which we believe to be the largest crude oil refiner in the Midwest and the third-largest in the United States based on crude oil refining capacity. MPC owns and operates seven refineries and associated midstream transportation and logistics assets in PADD II and PADD III, which consist of states in the Midwest and Gulf Coast regions of the United States, along with an extensive wholesale and retail refined product marketing operation that serves markets primarily in the Midwest, Gulf Coast and Southeast regions of the United States. MPC markets refined products under the Marathon brand through an extensive network of retail locations owned by independent entrepreneurs, and under the Speedway brand through its wholly-owned subsidiary, Speedway LLC, which operates what we believe to be the nation’s second largest chain of company-owned and operated retail gasoline and convenience stores. In addition, MPC sells refined products in the wholesale markets. MPC had consolidated revenues of approximately $63 billion in 2016. Marathon Petroleum Corporation’s common stock trades on the NYSE under the symbol “MPC.”

MPC’s operations necessitate large-scale movements of crude oil and feedstocks to and among its refineries, as well as large-scale movements of refined products from its refineries to various markets. To this end, MPC has an extensive portfolio of midstream assets that can potentially be sold and/or contributed to us, providing us with a competitive advantage. As of December 31, 2016, these midstream assets included investments in crude oil and refined product pipelines, an ocean vessel joint venture, light product and asphalt terminals, a fuels distribution business and certain refinery assets.

MPC retains a significant interest in us through its ownership of our general partner, an approximate 23.5 percent limited partner interest (including the Class B units on an as-converted basis) in us and all of our incentive distribution rights as of February 13, 2017. We believe MPC will promote and support the successful execution of our business strategies given its significant interest in us and its stated intention to use us to grow its midstream business. This includes an expectation for MPC to offer us assets contributing an estimated $1.4 billion of annual EBITDA by the end of 2017, subject to market and other conditions. The transactions are expected to support increased limited and general partner distributions and provide value creation for investors.

We also may pursue acquisitions cooperatively with MPC which has the balance sheet flexibility and the ability to incubate projects for us to purchase later. However, MPC is under no obligation to offer to sell us additional assets or to pursue acquisitions cooperatively with us, and we are under no obligation to buy any such additional assets or pursue any such cooperative acquisitions.

OUR G&P CONTRACTS WITH THIRD PARTIES

We generate the majority of our revenues in the G&P segment from natural gas gathering, transportation and processing; NGL gathering, transportation, fractionation, marketing and storage; and crude oil gathering and transportation. We enter into a variety of contract types. In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described below. We provide services under the following types of arrangements:

Fee-based 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

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producers an agreed-upon percentage of the proceeds. In other cases, instead of remitting cash payments to the producer, we deliver an agreed-upon percentage of the residue gas and NGLs to the producer (take-in-kind arrangements) and sell the volumes we retain to third parties. Revenue from these arrangements is reported on a gross basis where we act as the principal, as we have physical inventory risk and do not earn a fixed dollar amount. The agreed-upon percentage paid to the producer is reported as Purchased product costs on the Consolidated Statements of Income. Revenue is recognized on a net basis when we act as an agent and earn a fixed dollar amount of physical product and do not have risk of loss of the gross amount of gas and/or NGLs. Percent-of-proceeds revenue is reported as Product sales on the Consolidated Statements of Income.
Keep-whole arrangements Under keep-whole arrangements, 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.

In many cases, we provide services under contracts that contain a combination of more than one of the arrangements described above. When fees are charged (in addition to product received) under keep-whole arrangements, percent-of-proceeds arrangements or percent-of-index arrangements, we record such fees as Service revenue on the Consolidated Statements of Income. When commodities are obtained as a result of providing our services, Product sales is recorded at the time the commodity is sold. The terms of our contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements.

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

The terms of our contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. Our contract mix and, accordingly, our exposure to natural gas and NGL prices may change as a result of changes in producer preferences, our expansion in regions where some types of contracts are more common and other market factors, including current market and financial conditions which have increased the risk of volatility in oil, natural gas and NGL prices. Any change in mix may influence our long-term financial results.


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The following table does not give effect to our active commodity risk management program. For further discussion of how we manage commodity price volatility for the portion of our net operating margin that is not fee-based, see Item 8. Financial Statements and Supplementary Data – Note 16. We manage our business by taking into account the partial offset of short natural gas positions primarily in the Southwest region of our G&P segment. The calculated percentages for net operating margin for percent-of-proceeds, percent-of-index and keep-whole contracts reflect the partial offset of our natural gas positions. The calculated percentages are less than one percent for percent-of-index due to the offset of our natural gas positions and, therefore, not meaningful to the table below. For the year ended December 31, 2016, we calculated the following approximate percentages of our net operating margin from the following types of contracts:
 
Fee-Based
 
Percent-of-Proceeds(1)
 
Keep-Whole(2)
L&S(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).

COMPETITION

Within our L&S segment, as a result of our contractual relationship with MPC under our transportation and storage services agreements, and our connections to MPC’s refineries, we believe that our crude oil and refined product pipelines will not face significant competition for MPC’s crude oil or products transportation requirements.

If MPC’s customers reduced their purchases of products from MPC due to the increased availability of less expensive products from other suppliers or for other reasons, MPC may only ship the minimum volumes through our pipelines (or pay the shortfall payment if it does not ship the minimum volumes), which would cause a decrease in our revenues. MPC competes with integrated petroleum companies, which have their own crude oil supplies and distribution and marketing systems, as well as with independent refiners, many of which also have their own distribution and marketing systems. MPC also competes with other suppliers that purchase refined products for resale. Competition in any particular geographic area is affected significantly by the volume of products produced by refineries in that area and by the availability of products and the cost of transportation to that area from distant refineries.

In our G&P segment, we face competition for natural gas gathering and in obtaining natural gas supplies for our processing and related services; in obtaining unprocessed NGLs for gathering and fractionation; and in marketing our products and services. Competition for natural gas supplies is based primarily on the location of gas gathering systems and gas processing plants, operating efficiency and reliability and the ability to obtain a satisfactory price for products recovered. Competitive factors affecting our fractionation services include availability of capacity, proximity to supply and industry marketing centers and cost efficiency and reliability of service. Competition for customers to purchase our natural gas and NGLs is based primarily on price, delivery capabilities, flexibility and maintenance of high-quality customer relationships.

Our competitors include:

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.

Some of our competitors operate as MLPs and may enjoy a cost of capital comparable to and, in some cases, lower than ours. Other competitors, such as major oil and gas and pipeline companies, have capital resources and contracted supplies of natural gas substantially greater than ours. Smaller local distributors may enjoy a marketing advantage in their immediate service areas.


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We believe that our customer focus, demonstrated by our ability to offer an integrated package of services and our flexibility in considering various types of contractual arrangements, allows us to compete more effectively. Additionally, we believe we have critical connections to a strong sponsor and the key market outlets for NGLs and natural gas. In the Marcellus and Utica regions, our early entrance in the liquids-rich corridors of the Marcellus and Utica shale plays through our strategic gathering and processing agreements with key producers enhances our competitive position to participate in the further development of these resource plays. In the Southern Appalachia region, our operational experience of more than 20 years as the largest processor and fractionator and our existing presence in the Appalachian Basin provide a significant competitive advantage. In the Southwest region, our major gathering systems are less than 15 years old, located primarily in the heart of shale plays with significant long-term growth opportunities and provide producers with low-pressure and fuel-efficient service, which differentiates us from many competing gathering systems in those areas. The strategic location of our assets, including those connected to MPC, and the long-term nature of many of our contracts also provide a significant competitive advantage.

INSURANCE

Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury and loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and business interruption. We are insured under MPC and other third-party insurance policies. The MPC policies are subject to shared deductibles.

SEASONALITY

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

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

REGULATORY MATTERS

Our operations are subject to extensive regulations. The failure to comply with applicable laws and regulations or to obtain, maintain and comply with requisite permits and authorizations can result in substantial penalties and other costs to the Partnership. The regulatory burden on our operations increases our cost of doing business and, consequently, affects our profitability. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors. Due to the myriad of complex federal, state, provincial and local regulations that may affect us, directly or indirectly, reliance on the following discussion of certain laws and regulations should not be considered an exhaustive review of all regulatory considerations affecting our operations.

Pipeline Control Operations. The majority of our pipeline systems are operated from central control rooms. These control centers operate with a SCADA (supervisory control and data acquisition) system equipped with computer systems designed to continuously monitor operational data. Monitored data includes pressures, temperatures, gravities, flow rates and alarm conditions. These systems include real-time transient leak detection system monitors throughput and alarms if pre-established operating parameters are exceeded. These control centers operate remote pumps, motors and valves associated with the receipt and delivery of products, and provide for the remote-controlled shutdown of pump stations on the pipeline systems. These systems also include fully functional back-up operations maintained and routinely operated throughout the year to ensure safe and reliable operations.

Common Carrier Liquids Pipeline Operations. Certain of our liquids pipeline systems are common carriers subject to regulation by various federal, state and local agencies. FERC regulates interstate transportation on liquids pipeline systems under the Interstate Commerce Act (“ICA”), Energy Policy Act of 1992 (“EPAct 1992”) and the rules and regulations promulgated under those laws. The ICA and its implementing regulations require that tariff rates for interstate service on these pipelines, including interstate pipelines that transport crude oil, natural gas liquids (including purity ethane) and refined petroleum products (collectively referred to as “petroleum pipelines”), be just and reasonable and must not be unduly discriminatory or confer any undue preference upon any shipper. The ICA requires that interstate petroleum pipeline

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transportation rates and terms and conditions of service be filed with the governing agency, which is FERC, and publicly posted on the company’s website. Under the ICA, interested persons may challenge new or changed rates or services. FERC is authorized to investigate such charges and may suspend the effectiveness of a newly filed rate or service for up to seven months. A successful protest to a new rate or service could result in a petroleum pipeline paying refunds, together with interest, for the period that the rate or service was in effect. A successful complaint to an existing rate or service could result in a petroleum pipeline paying reparations, together with interest, for the period beginning two years prior to the date of the complaint until the just and reasonable rate or service was established. FERC may also investigate, upon complaint or on its own motion, existing rates and related rules and may order a pipeline to change them prospectively.

EPAct 1992 deemed certain interstate petroleum pipeline rates then in effect to be just and reasonable under the ICA. These rates are commonly referred to as “grandfathered rates.” Our rates in effect for the 365 day period ending on the date of the passage of EPAct 1992 for interstate transportation service were deemed just and reasonable and therefore are grandfathered. New rates have since been established after EPAct 1992 for certain pipeline systems, and the rates for certain of our products pipelines have subsequently been approved as market-based rates. FERC may change grandfathered rates upon complaint only after it is shown that a substantial change has occurred since enactment in either the economic circumstances or the nature of the services that were a basis for the rate.

EPAct 1992 required FERC to establish a simplified and generally applicable ratemaking methodology for interstate petroleum pipelines. As a result, FERC adopted an indexing rate methodology which, as currently in effect, allows petroleum pipelines to change their rates within prescribed ceiling levels that are tied to changes in the PPI. FERC’s indexing methodology is subject to review every five years. During the five-year period commencing July 1, 2011 and ending June 30, 2016, petroleum pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 2.65 percent. During the five-year period commencing July 1, 2016, petroleum pipelines charging indexed rates are permitted to adjust their indexed ceilings annually by PPI plus 1.23 percent. The indexing methodology is applicable to existing rates, including grandfathered rates, with the exclusion of market-based rates and settlement rates (unless permitted under the settlement). A pipeline is not required to raise its rates up to the index ceiling, but it is permitted to do so and rate increases made under the index are presumed to be just and reasonable unless a protesting party can demonstrate that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs. However, FERC is currently evaluating when and how indexed adjustments to rates can be challenged. Therefore, we cannot guarantee FERC will not make changes to its current policy regarding challenges in the future. Under the indexing rate methodology, in any year in which the index is negative, pipelines must file to lower their rates if those rates would otherwise be above the rate ceiling, unless the pipelines request and receive a waiver from FERC permitting them not to apply the negative index adjustment.

While petroleum pipelines often use the indexing methodology to change their rates, petroleum pipelines may elect to support proposed rates by using other methodologies such as cost-of-service ratemaking, market-based rates and settlement rates. A pipeline can follow a cost-of-service approach when seeking to increase its rates above the rate ceiling provided that the pipeline can establish that there is a substantial divergence between the actual costs experienced by the pipeline and the rate resulting from application of the index. A pipeline can charge market-based rates if it establishes that it lacks significant market power in the affected markets. In addition, a pipeline can establish rates under settlement if agreed upon by all current shippers. We have used index rates, settlement rates and market-based rates to change the rates for our different FERC regulated petroleum pipeline systems.

FERC issued a policy statement in May 2005 stating that it would permit interstate petroleum pipelines, among others, to include an income tax allowance in cost-of-service rates to reflect actual or potential tax liability attributable to a regulated entity’s operating income, regardless of the form of ownership. Under FERC’s policy, a tax pass-through entity seeking such an income tax allowance must establish that its partners or members have an actual or potential income tax liability on the regulated entity’s income. Whether a pipeline’s owners have such actual or potential income tax liability is subject to review by FERC on a case-by-case basis. Although this policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risk due to the case-by-case review requirement. Finally, FERC’s income tax policy continues to be the subject of various appeals by shippers, before FERC and the courts. We cannot guarantee that FERC or the courts will not make changes to the policy in the future.

Intrastate services provided by certain of our liquids pipeline systems are subject to regulation by state regulatory authorities. Much of the state regulation is complaint-based, both as to rates and priority of access. The state regulators could limit our ability to increase our rates or to set rates based on our costs or could order us to reduce our rates and could require the payment of refunds to shippers.

FERC and state regulatory agencies generally have not investigated rates on their own initiative when those rates are not the subject of a protest or a complaint by a shipper. MPC has agreed not to contest our tariff rates for the term of our transportation

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and storage services agreements with MPC, but we do not have any these types of agreements with other third parties. FERC or a state commission could investigate our rates on its own initiative or at the urging of a third party if the third party is either a current shipper or is able to show that it has a substantial economic interest in our tariff rate level.

If our rate levels were investigated, the inquiry could result in a comparison of our rates to those charged by others or to an investigation of our costs, including:

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.

If FERC or a state commission were to determine that our rates were or had become unjust and unreasonable, we could be ordered to reduce rates prospectively and pay refunds and/or reparations to shippers.

Because some of our pipelines are common carrier pipelines, we may be required to accept new shippers who wish to transport on our pipelines. It is possible that new shippers, current shippers or other interested parties may decide to challenge our tariff rates and/or the terms of service for our pipelines, including proration rules.

FERC-Regulated Natural Gas Pipelines. Our natural gas pipeline operations are subject to federal, state and local regulatory authorities. Specifically, we have FERC gas tariffs on file for MarkWest New Mexico, L.L.C. and MarkWest Pioneer with respect to our Hobbs Pipeline and the Arkoma Connector Pipeline. These pipelines are subject to regulation by FERC, and it is possible that we may have additional gas pipelines that may require such tariffs and may be subject to similar regulation in the future. FERC regulation of jurisdictional natural gas pipelines extends to various matters including:

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.

Under the Natural Gas Act (“NGA”), FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. As noted in the list above, FERC’s authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services and various other matters. Natural gas companies may not charge rates that have been determined to be unjust and unreasonable, or unduly discriminatory by FERC. In addition, FERC prohibits FERC-regulated natural gas companies from unduly preferring, or unduly discriminating against, any person with respect to pipeline rates or terms and conditions of service or other matters. The rates and terms and conditions for the Hobbs Pipeline and the Arkoma Connector Pipeline can be found in their respective FERC-approved tariffs. Pursuant to FERC’s jurisdiction, existing rates and/or other tariff provisions may be challenged (e.g., by complaint) and rate increases proposed by the pipeline or other tariff changes may be challenged (e.g., by protest). We also cannot be assured that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules, rights of access, capacity and other issues that impact natural gas facilities. Any successful complaint or protest related to our facilities could have an adverse impact on our revenues.

As noted above (under “Common Carrier Liquids Pipeline Operations”), FERC is reviewing its policies with respect to the inclusion of income tax allowances in cost-of-service rates. A Notice of Inquiry into these issues was issued by FERC on

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December 15, 2016. The outcome of this inquiry could affect the rates that interstate natural gas pipelines are permitted to charge.

Energy Policy Act of 2005. On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005 (“2005 EPAct”). Under the 2005 EPAct, FERC may impose civil penalties of up to $1 million per day for each current violation of the NGA. The 2005 EPAct also amends the NGA to add an anti-market manipulation provision, which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC. FERC issued Order No. 670 to implement the anti-market manipulation provision of the 2005 EPAct. This order makes it unlawful for gas pipelines and storage companies that provide interstate services to: (i) directly or indirectly, use or employ any device, scheme or artifice to defraud in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s enforcement authority.

Standards of Conduct. FERC has adopted affiliate standards of conduct applicable to interstate natural gas pipelines and certain other regulated entities, defined as “Transmission Providers.” Under these rules, a Transmission Provider becomes subject to the standards of conduct if it provides service to affiliates that engage in marketing functions (as defined in the standards). If a Transmission Provider is subject to the standards of conduct, the Transmission Provider’s transmission function employees (including the transmission function employees of any of its affiliates) must function independently from the Transmission Provider’s marketing function employees (including the marketing function employees of any of its affiliates). The Transmission Provider must also comply with certain posting and other requirements.

Market Transparency Rulemakings. In 2007, FERC issued Order 704, as amended and clarified in subsequent orders on rehearing, whereby wholesale buyers and sellers of more than 2.2 MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order 704.

Gas-Electric Coordination. In 2015, FERC issued Order 587-W and adopted new standards designed to improve coordination between the gas and electric industries. Among other things, the new standards revise the nomination timelines used by interstate natural gas pipelines. Interstate natural gas pipelines were required to implement the new standards in 2016. FERC continues to evaluate other measures to improve coordination between the gas and electric industries, and the adoption of any such measures may impact FERC’s regulation of jurisdictional natural gas pipelines.

Intrastate Natural Gas Pipeline Regulation. Some of our intrastate gas pipeline facilities are subject to various state laws and regulations that affect the rates we charge and terms of service. Although state regulation is typically less onerous than FERC, state regulation typically requires pipelines to charge just and reasonable rates and to provide service on a non-discriminatory basis. The rates and service of an intrastate pipeline generally are subject to challenge by complaint. Additionally, FERC has adopted certain regulations and reporting requirements applicable to intrastate natural gas pipelines (and Hinshaw natural gas pipelines) that provide certain interstate services subject to FERC’s jurisdiction. We could become subject to such regulations and reporting requirements in the future to the extent that any of our intrastate pipelines were to begin providing, or were found to provide, such interstate services.

Additional proposals and proceedings that might affect the natural gas industry periodically arise before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such action materially differently than other midstream natural gas companies with whom we compete.

Natural Gas Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC if the primary function of the facilities is gathering natural gas. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. We own a number of facilities that we believe establish the pipeline’s status as a gatherer not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so we cannot provide assurance that FERC will not at some point assert that these facilities are within its jurisdiction or that such an assertion would not adversely affect our results of operations and revenues. In such a case, we would possibly be required to file a tariff with FERC, provide a cost justification for the transportation charge and obtain certificate(s) of public convenience and necessity for the FERC-regulated pipelines, and comply with additional FERC requirements.

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In the states in which we operate, regulation of gathering facilities and intrastate pipeline facilities generally includes various safety, environmental and, in some circumstances, open access, non-discriminatory take requirement and complaint-based rate regulation. For example, some of our natural gas gathering facilities are subject to state ratable take and common purchaser statutes and regulations. Ratable take statutes and regulations generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes and regulations generally require gatherers to purchase gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. Although state regulation is typically less onerous than at FERC, these statutes and regulations have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or gather natural gas.

Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a less stringent approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services or regulated as a public utility. Our gathering operations also may be or become subject to safety and operational regulations and permitting requirements relating to the design, siting, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

Currently, PHMSA is evaluating possible changes to the scope and applicability of 49 C.F.R. Part 192, which governs construction standards and operation of natural gas gathering pipelines. The changes being considered include, but are not limited to, more stringent construction standards for remote facilities, as well as additional record-keeping requirements. Depending upon the nature of the final rule-making, those could have an impact upon MPLX LP operations.

Natural Gas Processing. Our natural gas processing operations are not presently subject to FERC or state rate regulation. There can be no assurance that our processing operations will continue to be exempt from FERC regulation in the future. In addition, although the processing facilities may not be directly related, other laws and regulations may affect the availability of natural gas for processing, such as state regulation of production rates and maximum daily production allowables from gas wells, which could impact our processing business.

NGL Pipelines. We have constructed various NGL product pipelines to transport NGL products, some of which are regulated by FERC, and we may elect to construct additional such pipelines in the future that may be subject to these same regulatory requirements. Pipelines providing transportation of NGLs in interstate commerce are subject to the same regulatory requirements as common carrier petroleum pipelines. See “Common Carrier Liquids Pipeline Operations” above. We have several NGL pipelines that carry NGLs owned by us between our processing and fractionation facilities that cross state lines. We do not have FERC tariffs on file for these pipelines because we believe they are not subject to FERC requirements or that they would otherwise meet the qualifications for a waiver from FERC’s filing and reporting requirements. We cannot, however, provide assurance that FERC will not, at some point, either at the request of other entities or on its own initiative, assert that some or all of these pipelines are subject to FERC requirements for interstate petroleum pipelines and not exempt from its filing and reporting requirements. We also cannot provide assurance that such an assertion would not adversely affect our results of operations. In the event FERC were to determine that these NGL pipelines are subject to FERC requirements for common carrier pipelines or otherwise would not qualify for a waiver from FERC’s applicable regulatory requirements, we would likely be required to file a tariff with FERC for the pipelines, provide a cost justification for their transportation rates, and provide service to all potential shippers without undue discrimination, and we may also be subject to fines, penalties or other sanctions. Our NGL pipelines are subject to safety regulation by the DOT under 49 C.F.R. Part 195 for operators of hazardous liquid pipelines. Currently, PHMSA is evaluating possible changes to the scope and applicability of 49 C.F.R. Part 195m, including, among other things, expansion of reporting obligations, additional inspection requirements, and expansion of the use of leak detection systems. Depending upon the nature of the final rule-making, those could have an impact upon MPLX LP operations. Our NGL pipelines and operations may also be or become subject to state public utility or related jurisdiction which could impose additional safety and operational regulations relating to the design, siting, installation, testing, construction, operation, replacement and management of NGL gathering facilities.

Propane Regulation. National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane or comparable regulations, have been adopted as the industry standard in all of the states in which we operate. In some states these laws are administered by state agencies and in others they are administered on a municipal level. With respect to the transportation of propane by truck, we are subject to regulations promulgated under the Federal Motor Carrier Safety Act. These regulations cover the transportation of hazardous materials and are administered by the

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DOT. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations. We maintain various permits that are necessary to operate our facilities, some of which may be material to our propane operations. We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane are consistent with industry standards and are in compliance in all material respects with applicable laws and regulations.

Marine Transportation. Our marine transportation business is subject to regulation by the USCG, federal laws, including the Jones Act, state laws and certain international conventions, as well as numerous environmental regulations. The majority of our vessels are subject to inspection by the USCG and carry certificates of inspection. The crews employed aboard the vessels are licensed or certified by the USCG. We are required by various governmental agencies to obtain licenses, certificates and permits for our vessels.

Our marine transportation business competes principally in markets subject to the Jones Act, a federal cabotage law that restricts domestic marine transportation in the United States to vessels built and registered in the United States, and manned and owned by United States citizens. We presently meet all of the requirements of the Jones Act for our vessels. The loss of Jones Act status could have a significant negative effect on us. The requirements that our vessels be United States built and manned by United States citizens, the crewing requirements and material requirements of the USCG, and the application of United States labor and tax laws increases the cost of United States flag vessels when compared with comparable foreign flag vessels. Our marine transportation business could be adversely affected if the Jones Act were to be modified so as to permit foreign competition that is not subject to the same United States government imposed burdens. Since the events of September 11, 2001, the United States government has taken steps to increase security of United States ports, coastal waters and inland waterways. We believe that it is unlikely that the current cabotage provisions of the Jones Act would be modified or eliminated in the foreseeable future.

The Secretary of Homeland Security is vested with the authority and discretion to waive the Jones Act to such extent and upon such terms as the Secretary may prescribe whenever the Secretary deems that such action is necessary in the interest of national defense. In response to the effects of Hurricanes Katrina and Rita, the Secretary waived the Jones Act generally for the transportation of petroleum products from September 1 to September 19, 2005 and from September 26, 2005 to October 24, 2005. In June 2011, the Secretary waived the Jones Act for the transportation of petroleum released from the Strategic Petroleum Reserve and in November 2012 waived the Jones Act for the transportation of refined petroleum products in the Northeast following Hurricane Sandy. Waivers of the Jones Act, whether in response to natural disasters or otherwise, could result in increased competition from foreign tank vessel operators, which could negatively impact our marine transportation business.

Pipeline Interconnections. One or more of our plants include pipeline interconnections to, or incidental gathering pipelines (also known as “stub lines”) that connect the plants to, interstate pipelines. These pipeline interconnections are an integral part of our facilities and are not currently being used, nor can they be used in the future, by any third party due to their origin points at our proprietary facilities. Therefore, we believe these pipeline interconnections are part of our plant facilities and are not subject to the jurisdiction of FERC. In the event that FERC were to determine that these pipeline interconnections were subject to its jurisdiction, we believe the pipelines would qualify for a waiver from most FERC reporting and filing requirements, including the obligation to file a FERC tariff. In the event that FERC were to determine that the pipeline interconnections did not qualify for such waivers, we would likely be required to file a tariff with FERC for the pipeline interconnections, provide a cost justification for their transportation rates and provide service to all potential shippers without undue discrimination. In such event, we may experience increased operating costs and reduced revenues.

Security. Certain of our facilities have been preliminarily classified as subject to the Department of Homeland Security Chemical Facility Anti-Terrorism Standards. In addition, we have several facilities that are subject to the United States Coast Guard’s Maritime Transportation Security Act, and a number of other facilities that are subject to the Transportation Security Administration’s Pipeline Security Guidelines and are designated as “Critical Facilities.” The Transportation Security Administration Security Guidelines are subject to change without formal regulatory proposal and review. We have an internal inspection program designed to monitor and ensure compliance with all of these requirements. We believe that we are in material compliance with all applicable laws and regulations regarding the security of our facilities.

ENVIRONMENTAL REGULATION

General

Our processing and fractionation plants, storage facilities, pipelines and associated facilities are subject to multiple obligations and potential liabilities under a variety of federal, regional, state and local laws and regulations relating to environmental

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protection. Such environmental laws and regulations may affect many aspects of our present and future operations, including for example, requiring the acquisition of permits or other approvals to conduct regulated activities that may impose burdensome conditions or potentially cause delays, restricting the manner in which we handle or dispose of our wastes, limiting or prohibiting construction or other activities in environmentally sensitive areas such as wetlands or areas inhabited by endangered species, requiring us to incur capital costs to construct, maintain and/or upgrade processes, equipment and/or facilities, restricting the locations in which we may construct our compressor stations and other facilities and/or requiring the relocation of existing stations and facilities, and requiring remedial actions to mitigate any pollution that might be caused by our operations or attributable to former operations. Spills, releases or other incidents may occur in connection with our active operations or as a result of events outside of our reasonable control, which incidents may result in non-compliance with such laws and regulations. Any failure to comply with these legal requirements may expose us to the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of remedial or corrective actions and the issuance of orders enjoining or limiting some or all of our operations.

We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations and the cost of continued compliance with such laws and regulations will not have a material adverse effect on our results of operations or financial condition. We cannot assure, however, that existing environmental laws and regulations will not be reinterpreted or revised or that new environmental laws and regulations will not be adopted or become applicable to us. For instance, the EPA is currently taking a closer look at pipeline maintenance operations, and the result of this closer review may yield modified emission calculations and/or regulations relating to such activities. Generally speaking, the trend in environmental law is to place more restrictions and limitations on activities that may be perceived to adversely affect the environment, which may cause significant delays in obtaining permitting approvals for our facilities, result in the denial of our permitting applications, or cause us to become involved in time consuming and costly litigation. Thus, there can be no assurance as to the amount or timing of future expenditures for compliance with environmental laws and regulations, permits and permitting requirements or remedial actions pursuant to such laws and regulations, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional environmental requirements may result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, and could have a material adverse effect on our business, financial condition, results of operations and cash flow. We may not be able to recover some or any of these costs from insurance. Such revised or additional environmental requirements may also result in substantially increased costs and material delays in the construction of new facilities or expansion of our existing facilities, which may materially impact our ability to meet our construction obligations with our producer customers.

Under the omnibus agreement, MPC has agreed to indemnify us for all known and certain unknown environmental liabilities that are associated with the ownership or operation of our assets that we acquired from MPC and due to occurrences on or before the closing of the Initial Offering. Indemnification for any unknown environmental liabilities will be limited to liabilities due to occurrences on or before the closing of the Initial Offering and identified prior to the fifth anniversary of the closing of the Initial Offering, and will be subject to an aggregate deductible of $500,000 before we are entitled to indemnification for losses incurred. Any other liabilities for which MPC has agreed to indemnify us are not subject to a deductible before we are entitled to indemnification. There is no limit on the amount for which MPC has agreed to indemnify us under the omnibus agreement once we meet the deductible, if applicable. Neither we nor our general partner have any contractual obligation to investigate or identify any such unknown environmental liabilities. We have agreed to indemnify MPC for events and conditions associated with the ownership or operation of our assets due to occurrences after the closing of the Initial Offering and for environmental liabilities associated with or arising from our ownership or operation of the assets on or after the closing of the Initial Offering, in each case, to the extent MPC is not required to indemnify us for such liabilities. Pipe Line Holdings has agreed to indemnify MPC for events and conditions associated with the operations of the Pipe Line Holdings assets that occur after the closing of the Initial Offering. Liabilities for which we and Pipe Line Holdings have agreed to indemnify MPC pursuant to the omnibus agreement are not subject to a deductible before MPC is entitled to indemnification. There is no limit on the amount for which we or Pipe Line Holdings has agreed to indemnify MPC under the omnibus agreement.

Hazardous Substances and Wastes

A comprehensive framework of environmental laws and regulations governs our operations as they relate to the possible release of hazardous substances or non-hazardous or hazardous wastes into soils, groundwater and surface water and measures taken to mitigate pollution into the environment. The Comprehensive Environmental Response, Compensation, and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, as well as comparable state laws, impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include current and prior owners or operators of a site where a release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances released from the site. Under CERCLA, these persons may be subject to strict joint and several liability for the costs of removing or remediating hazardous substances that have been released into the environment and for restoration costs and

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damages to natural resources. Additionally, neighboring landowners and other third parties can file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. While we generate materials in the course of our operations that may be regulated as hazardous substances under CERCLA or similar state statutes, we do not believe that we have any current material liability for cleanup costs under such laws or for third-party claims. We also may incur liability under the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable or more stringent state statutes, which impose requirements relating to the handling and disposal of non-hazardous and hazardous wastes. In the course of our operations, we generate some amount of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes. While we are required to comply with RCRA requirements relating to hazardous wastes, currently our operations generate minimal quantities of such hazardous wastes. However, it is possible that some wastes generated by us that are currently classified as non-hazardous wastes may in the future be designated as hazardous wastes, resulting in the wastes being subject to more rigorous and costly transportation, storage, treatment and disposal requirements.

We currently own or lease, and have in the past owned or leased, properties that have been used over the years for natural gas gathering, processing and transportation, for NGL fractionation or for the storage, gathering and transportation of crude oil. Although waste disposal practices within the NGL industry and other oil and natural gas related industries have been enhanced and improved over the years, it is possible that petroleum hydrocarbons and other non-hazardous or hazardous wastes may have been disposed of by prior owners or operators on or under these various properties owned or leased by us during the operating history of those facilities. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination or to perform remedial operations to prevent future contamination. We do not believe that there presently exists significant surface and subsurface contamination of our properties by petroleum hydrocarbons or other wastes for which we are currently responsible.

Ongoing Remediation and Indemnification from Third Parties

The prior third-party owner or operator of our Cobb, Boldman, Kenova, Kermit and Majorsville facilities, has been, or is currently involved in, investigatory or remedial activities with respect to the real property underlying these facilities. These investigatory and remedial obligations arise out of a September 1994 “Administrative Order by Consent for Removal Actions” with EPA Regions II, III, IV and V; and with respect to the Boldman Complex, an “Agreed Order” entered into by the third-party owner/operator with the Kentucky Natural Resources and Environmental Protection Cabinet in October 1994. The third party or, in the case of the Kermit Complex, its successor in interest, has accepted sole liability and responsibility for, and indemnifies us against, any environmental liabilities associated with the EPA Administrative Order, the Kentucky Agreed Order or any other environmental condition related to the real property prior to the effective dates of our lease or purchase of the real property that are not contributed to by us. In addition, the third party, or in the case of the Kermit Complex, its successor in interest, has agreed to perform all the required response actions at its expense in a manner that minimizes interference with our use of the properties. We understand that to date, all actions required under these agreements have been or are being performed and, accordingly, we do not believe that the remediation obligation of these properties will have a material adverse impact on our financial condition or results of operations.

The prior third-party owner and/or operator of certain facilities on the real property on which our rail facility is constructed near Houston, Pennsylvania has been, or is currently involved in, investigatory or remedial activities related to acid mine drainage (“AMD”) with respect to the real property underlying these facilities. These investigatory and remedial obligations arise out of an arrangement entered into between the Pennsylvania Department of Environmental Protection and the third party, which has accepted liability and responsibility for, and indemnifies us against, any environmental liabilities associated with the AMD that are not exacerbated by us in connection with our operations. In addition, the third party has agreed to perform all of the required response actions at its expense in a manner that minimizes interference with our use of the property. We understand that to date, all actions required under these agreements have been or are being performed and, accordingly, we do not believe that the remediation obligation of these properties will have a material adverse impact on our financial condition or results of operations.

We are also entitled to indemnification from MPC for assets we acquired from MPC in our Initial Offering, as further described above under “General”. In addition, from time to time, we have acquired, and we may acquire in the future, facilities from third parties that previously have been or currently are the subject of investigatory, remedial or monitoring activities relating to environmental matters. The terms of each acquisition will vary, and in some cases we may receive contractual indemnification from the prior owner or operator for some or all of the liabilities relating to such matters, and in other cases we may agree to accept some or all of such liabilities. We do not believe that the portion of any such liabilities that the Partnership may bear with respect to any such properties previously acquired by the Partnership will have a material adverse impact on our financial condition or results of operations.

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Water Discharges

Our operations can result in the discharge of pollutants, including crude oil and refined products. Regulations under the Water Pollution Control Act of 1972 (“Clean Water Act”), Oil Pollution Act of 1990 (“OPA-90”) and analogous state laws impose restrictions and controls on the discharge of pollutants into federal and state waters. Such discharges are prohibited, except in accord with the terms of a permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law and some state laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, oil overflow, rupture or leak. For example, the Clean Water Act requires us to maintain Spill Prevention Control and Countermeasure (“SPCC”) plans at many of our facilities. We maintain numerous discharge permits for facilities and vessels as required under the National Pollutant Discharge Elimination System program of the Clean Water Act and have implemented systems to oversee our compliance efforts. Any unpermitted release of pollutants, including oil, NGLs or condensates, could result in administrative, civil and criminal penalties as well as significant remedial obligations. In addition, the Clean Water Act and analogous state law may also require individual permits or coverage under general permits for discharges of storm water from certain types of facilities, but these requirements are subject to several exemptions specifically related to oil and natural gas operations and facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit. We conduct regular review of the applicable laws and regulations, and maintain discussions with the various federal, state and local agencies with regard to the application of those laws and regulations to our facilities, including the permitting process and categories of applicable permits for storm water or other discharges, stream crossings and wetland disturbances that may be required for the construction or operation of certain of our facilities in the various states. In June 2015, the EPA and the United States Army Corps of Engineers finalized significant changes to the definition of the term “waters of the United States” (“WOTUS”) used in numerous programs under the Clean Water Act. This final rulemaking is referred to as the “Clean Water Rule.” The Clean Water Rule has been challenged in multiple federal courts by many states, trade groups, and other interested parties, and in October 2015, a United States Court of Appeals issued a nationwide stay of the Clean Water Rule. The Clean Water Rule, as written, expands permitting, planning and reporting obligations and may extend the timing to secure permits for pipeline and fixed asset construction and maintenance activities. The Clean Water Rule does contain new language intended to address concerns that the proposed rule included storm water conveyances and storage structures as WOTUS, and we continue to review how that new language will apply under specific circumstances. Court challenges of the Clean Water Rule will continue through 2017.

In addition, the transportation and storage of crude oil and refined products over and adjacent to water involves risk and subjects us to the provisions of OPA-90 and related state requirements. Among other requirements, OPA-90 requires the owner or operator of a tank vessel, a facility or a pipeline to maintain an emergency plan to respond to releases of oil or hazardous substances. Also, in case of any such release, OPA-90 requires the responsible company to pay resulting removal costs and damages. OPA-90 also provides for civil penalties and imposes criminal sanctions for violations of its provisions. We operate facilities at which releases of oil and hazardous substances could occur. We have implemented emergency oil response plans for all of our components and facilities covered by OPA-90 and we have established SPCC plans for facilities subject to Clean Water Act SPCC requirements.

Construction or maintenance of our plants, compressor stations, pipelines, barge dock and storage facilities may impact wetlands, which are also regulated under the Clean Water Act by the EPA, the United States Army Corps of Engineers and state water quality agencies. Regulatory requirements governing wetlands (including associated mitigation projects) may result in the delay of our projects while we obtain necessary permits and may increase the cost of new projects and maintenance activities. We believe that we are in substantial compliance with the Clean Water Act and analogous state laws. However, there is no assurance that we will not incur material increases in our operating costs or delays in the construction or expansion of our facilities because of future developments, the implementation of new laws and regulations, the reinterpretation of existing laws and regulations, or otherwise, including, for example, increased construction activities, potential inadvertent releases arising from pursuing borings for pipelines, and earth slips due to heavy rain and/or other cause.

Hydraulic Fracturing

We do not conduct hydraulic fracturing operations, but we do provide gathering, processing and fractionation services with respect to natural gas and NGLs produced by our producer customers as a result of such operations. Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final Clean Air Act regulations governing performance standards, including standards

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for the capture of air emissions released during hydraulic fracturing, and issued in May 2014 its Advance Notice of Proposed Rulemaking to solicit input on the possible Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in March 2015, the Bureau of Land Management (“BLM”) published its final rule setting new standards for hydraulic fracturing on onshore federal and Indian lands. The final rules have been challenged and, in June 2016, the United States District Court for Wyoming set aside these BLM rules, holding that the BLM lacked the statutory authority to regulate the hydraulic fracturing process. In addition, Congress has from time to time considered legislation to provide for additional regulation of hydraulic fracturing, and some states have adopted, and other states are considering adopting, laws and/or regulations that could impose more stringent permitting, disclosure and well construction requirements on natural gas drilling activities or prohibit hydraulic fracturing altogether, similar to the State of New York. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. In the event that new or more stringent federal, state or local legal restrictions relating to natural gas drilling activities or to the hydraulic fracturing process are adopted in areas where our producer customers operate, those customers could incur potentially significant added costs to comply with such hydraulic fracturing-related requirements and experience delays or curtailment in the pursuit of production or development activities, which could reduce demand for our gathering, transportation and processing services and/or our NGL fractionation services.

In addition, certain governmental reviews are underway that focus on potential environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Most notably, in December 2016, the EPA released its final assessment of the impacts of hydraulic fracturing on drinking water. These studies could spur initiatives to further regulate hydraulic fracturing that could delay or curtail production of natural gas, and thus reduce demand for our midstream services.

Air Emissions

The Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, including processing plants and compressor stations, and also impose various monitoring and reporting requirements. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, utilize specific equipment or technologies to control emissions, or aggregate two or more of our facilities into one application for permitting purposes. We may be required to incur capital expenditures in the future for installation of air pollution control equipment and encounter construction or operational delays while applying for, or awaiting the review, processing and issuance of new or amended permits, and we may be required to modify certain of our operations which could increase our operating costs. For example, the EPA issued final regulations in October 2015 to revise the National Ambient Air Quality Standard for ozone to 70 parts per billion, or ppb, for both the eight-hour primary and secondary standards protective of public health and public welfare. These standards, which are currently again under review, could require states to implement new more stringent regulations, which could apply to our operations and those of our producer customers. Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business. Federal and state regulators and agencies are also currently taking a closer look at pipeline maintenance operations and any emissions and permits that may be related to such activities. The result of this closer review may yield modified emission calculations and/or regulations relating to such activities or potentially enforcement actions by the agencies for unaccounted for or unpermitted emissions. EPA has finalized revisions to regulations or interpretations of regulations regarding aggregation of facilities for permitting purposes and performance standards for methane emissions from new and modified oil and gas production and natural gas processing and transmission facilities, any of which could require additional capital expenditures, increase our operating costs or otherwise restrict our operations. Additionally, in 2015, EPA finalized regulations to revise existing refinery air emissions standards, which require additional controls, lower emission standards and require ambient air monitoring. These revised refinery standards affect MPC’s refineries from which we receive significant revenues. MPC has been required in the past, and will be required in the future, to incur significant capital expenditures to comply with new legislative and regulatory requirements relating to its operations. To the extent these capital expenditures have a material effect on MPC, they could have a material effect on our business and results of operations. We have been in discussions with various state agencies in the areas in which we operate with respect to their guidance, policies, rules and regulations regarding the permitting process, source determination, categories of applicable permits and control technology that may be required for the construction or operation of certain of our facilities. We believe that our operations are in substantial compliance with applicable air permitting and control technology requirements.


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Climate Change

As a consequence of an EPA administrative conclusion that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) into the ambient air endangers public health and welfare, the EPA adopted regulations establishing the Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit programs for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. In addition, the EPA is gathering information regarding existing facilities in various industries, including information collection requests (“ICRs”) issued in December 2016 to various oil and gas production and midstream facilities, which may be used to support potential future regulation of GHGs. Although the EPA’s PSD and Title V permit programs are limited to large stationary sources of criteria pollutant emissions, states may seek to adopt their own permitting programs under state laws that require permit reviews of large stationary sources emitting only GHGs. If we were to become subject to Title V and PSD permitting requirements due to non-GHG criteria pollutants, or if the EPA implemented more stringent permitting requirements relating to GHG emissions without regard to non-GHG criteria pollutants, or if states adopt their own permitting programs that require permit reviews based on GHG emissions, we may be required to install “best available control technology,” to the extent such technology is available, to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future. In addition, we may experience substantial delays or possible curtailment of construction or projects in connection with applying for, obtaining or maintaining preconstruction and operating permits, we may encounter limitations on the design capacities or size of facilities, and we may incur material increases in our construction and operating costs. The EPA has also adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas sources in the United States, including, among others, certain onshore and offshore oil and natural gas production and onshore oil and natural gas processing, fractionation, transmission, storage and distribution facilities, which includes certain of our operations. In addition, in 2015, the EPA issued rules expanding the petroleum and natural gas system sources for which annual GHG emissions reporting is required to include GHG emissions reporting beginning in the 2016 reporting year for certain onshore gathering and boosting systems consisting primarily of gathering pipelines, compressors and process equipment used to perform natural gas compression, dehydration and acid gas removal. We are monitoring GHG emissions from certain of our facilities in accordance with current GHG emissions reporting requirements in a manner that we believe is in substantial compliance with applicable reporting obligations. Additionally, in 2015 the EPA finalized rules to limit GHG emissions from new and existing power plants, although the United States Supreme Court issued a stay of these rules in February 2016 while the rules are under review by the United States Court of Appeals for the District of Columbia Circuit. The requirements could increase the cost of electricity and natural gas for our operations and ultimately states could impose additional GHG emission reduction requirements. In sum, requiring reductions in GHG emissions at our facilities could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls at our facilities and (iii) administer and manage any GHG emissions programs, including acquiring emission credits or allotments. These requirements may also significantly affect MPC’s refinery operations and may have an indirect effect on our business, financial condition and results of operations.

Also, Congress has from time to time considered legislation to reduce emissions of GHGs, and while there has not been federal climate legislation adopted in the United States in recent years, it is possible that such legislation could be enacted in the future. In the absence of federal climate legislation in the United States, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress were to undertake comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for oil, natural gas, NGLs and products derived therefrom. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emission allowances or comply with new regulatory or reporting requirements including the imposition of a carbon tax. The EPA issued final rules in May 2016 aimed at minimizing fugitive emissions and establishing methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025. This rule is currently being challenged in court by various affected states. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil and natural gas produced by our exploration and production customers that, in turn, could reduce the demand for our services and thus adversely affect our cash available for distribution to our unitholders.

Endangered Species Act and Migratory Bird Treaty Act Considerations

The federal Endangered Species Act (“ESA”) and analogous laws regulate activities that may affect endangered or threatened species, including their habitats. If endangered species are located in areas where we propose to construct new gathering or transportation pipelines or processing or fractionation facilities, such work could be prohibited or delayed in certain of those locations or during certain times, when our operations could result in a taking of the species. We also may be obligated to

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develop plans to avoid potential takings of protected species, the implementation of which could materially increase our operating and capital costs. Existing laws, regulations, policies and guidance relating to protected species may also be revised or reinterpreted in a manner that further increase our construction and mitigation costs or restricts our construction activities. Additionally, construction and operational activities could result in inadvertent impact to a listed species and could result in alleged takings under the ESA, exposing the Partnership to civil or criminal enforcement actions and fines or penalties. Moreover, as a result of a settlement approved by the United States District Court for the District of Columbia in September 2011, the United States Fish and Wildlife Service (“FWS”) is required to make a determination on listing numerous species as endangered or threatened under the ESA by completion of the agency’s 2017 fiscal year. For example, in April 2015, the FWS published a final rule listing the Northern Long Eared Bat as threatened under the ESA. In another example, in March 2014, the FWS announced the listing of the lesser prairie chicken as a threatened species under the ESA. In addition, in January 2017, FWS announced that it will list the rusty patched bumblebee as an endangered species effective in February 2017. All of these species, along with the other endangered species such as the Indiana Bat and American Burying Beetle, are in areas in which we operate. The listing of these or other species as threatened or endangered in areas where we conduct operations or plan to construct pipelines or facilities may cause us to incur increased costs arising from species protection measures or could result in delays in, or prohibit, the construction of our facilities or limit our customer’s exploration and production activities, which could have an adverse impact on demand for our midstream operations.

The Migratory Bird Treaty Act implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds. In accordance with this law, the taking, killing or possessing of migratory birds covered under this act is unlawful without a permit. If there is the potential to adversely affect migratory birds as a result of our operations or construction activities, we may be required to obtain necessary permits to conduct those operations or construction activities, which may result in specified operating or construction restrictions on a temporary, seasonal, or permanent basis in affected areas and thus have an adverse impact on our ability to provide timely gathering, processing or fractionation services to our exploration and production customers.

Pipeline Safety Matters

Our assets are subject to increasingly strict safety laws and regulations. The transportation and storage of natural gas and crude oil and refined products involve a risk that hazardous liquids may be released into the environment, potentially causing harm to the public or the environment. In turn, such incidents may result in substantial expenditures for response actions, significant government penalties, liability to government agencies for natural resources damages and significant business interruption. The DOT has adopted safety regulations with respect to the design, construction, operation, maintenance, inspection and management of our pipeline assets. These regulations contain requirements for the development and implementation of pipeline integrity management programs, which include the inspection and testing of pipelines and the correction of anomalies. These regulations also require that pipeline operation and maintenance personnel meet certain qualifications and that pipeline operators develop comprehensive spill response plans.

We are subject to regulation by the DOT under the Hazardous Liquid Pipeline Safety Act of 1979, also known as the HLPSA. The HLPSA delegated to the DOT the authority to develop, prescribe and enforce minimum federal safety standards for the transportation of hazardous liquids by pipeline. Congress also enacted the Pipeline Safety Act of 1992, also known as the PSA, which added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, required regulations be issued to define the term “gathering line” and establish safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in High Consequence Areas (“HCAs”), defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. In 1996, Congress enacted the Accountable Pipeline Safety and Partnership Act, also known as the APSPA, which limited the operator identification requirement mandate to pipelines that cross a waterway where a substantial likelihood of commercial navigation exists, required that certain areas where a pipeline rupture would likely cause permanent or long-term environmental damage be considered in determining whether an area is unusually sensitive to environmental damage, and mandated that regulations be issued for the qualification and testing of certain pipeline personnel. In the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, also known as the PIPES Act, Congress required mandatory inspections for certain U.S. crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquid pipelines and pipeline control room management. We are also subject to the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, which reauthorized funding for federal pipeline safety programs through 2015, increased penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of certain safety issues that could result in the adoption of new regulatory requirements for existing pipelines.

The DOT has delegated its authority under these statutes to the PHMSA, which administers compliance with these statutes and has promulgated comprehensive safety standards and regulations for the transportation of natural gas by pipeline (49 Code of

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Federal Regulations (“CFR”) Part 192), as well as hazardous liquids by pipeline (49 CFR Part 195), including regulations for the design and construction of new pipeline systems or those that have been relocated, replaced or otherwise changed (Subparts C and D of 49 CFR, Part 195); pressure testing of new pipelines (Subpart E of 49 CFR Part 195); operation and maintenance of pipeline systems, including inspecting and reburying pipelines in the Gulf of Mexico and its inlets, establishing programs for public awareness and damage prevention, managing the integrity of pipelines in HCAs and managing the operation of pipeline control rooms (Subpart F of 49 CFR Part 195); protecting steel pipelines from the adverse effects of internal and external corrosion (Subpart H of 49 CFR Part 195); and integrity management requirements for pipelines in HCAs (49 CFR 195.452). In addition, on October 18, 2010, PHMSA issued an advance notice of proposed rulemaking on a range of topics relating to the safety of natural gas, crude oil and other hazardous liquids pipelines. On October 13, 2015, PHMSA issued a notice of proposed rulemaking which purposes changes to 49 CFR Part 195, followed shortly by proposed changes to 49 CFR Part 192, and is currently evaluating recommendations regarding potential changes to both Parts 192 and 195. We do not anticipate that we would be impacted by these regulatory initiatives to any greater degree than other similarly situated competitors.

We monitor the structural integrity of our pipelines through a program of periodic internal assessments using high resolution internal inspection tools, as well as hydrostatic testing and direct assessment, that conforms to federal standards. We accompany these assessments with a review of the data and repair anomalies, as required, to ensure the integrity of the pipeline. We then utilize sophisticated risk algorithms and a comprehensive data integration effort to ensure that the highest risk pipelines receive the highest priority for scheduling subsequent integrity assessments. We use external coatings and impressed current cathodic protection systems to protect against external corrosion. We conduct all cathodic protection work in accordance with National Association of Corrosion Engineers standards. We continually monitor, test and record the effectiveness of these corrosion inhibiting systems.

Pipeline Permitting

Pipeline construction and expansion is subject to government permitting and involves numerous regulatory environmental, political and legal uncertainties, most of which are beyond our control. We believe our operations are in substantial compliance with our permits.

Facility Safety

At manned facilities, the workplaces associated with the processing and storage facilities and the pipelines we operate are also subject to oversight pursuant to the federal Occupational Safety and Health Act, as amended, (“OSHA”), as well as comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard-communication standard requires that we maintain information about hazardous materials used or produced in operations, and that this information be provided to employees, state and local government authorities and citizens. We believe that we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record-keeping requirements and monitoring of occupational exposure to regulated substances.

At unmanned facilities, the EPA’s Risk Management Planning requirements at regulated facilities are intended to protect the safety of the surrounding public. The application of these regulations, which are often unclear, can result in increased compliance expenditures.

In general, we expect industry and regulatory safety standards to become stricter over time, resulting in increased compliance expenditures. While these expenditures cannot be accurately estimated at this time, we do not expect such expenditures will have a material adverse effect on our results of operations.

Notwithstanding the foregoing, PHMSA and one or more state regulators, including the Texas Railroad Commission, have recently sought to expand the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities in order to assess compliance with hazardous liquids pipeline safety requirements. These recent actions by PHMSA are currently subject to judicial and administrative challenges by one or more midstream operators; however, to the extent that such challenges are unsuccessful, midstream operators of NGL fractionation facilities and associated storage facilities may be required to make operational changes or modifications at their facilities to meet standards beyond current requirements. These changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation.

Product Quality Standards

Refined products and other hydrocarbon-based products that we transport are generally sold by us or our customers for consumption by the public. Various federal, state and local agencies have the authority to prescribe product quality

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specifications for products. The EPA has established sulfur specifications for natural gasoline sold as certified ethanol denaturant effective January 1, 2017. The EPA has also proposed product quality specification for natural gasoline used for blendstock in ethanol flex fuel. Changes in product quality specifications or blending requirements could reduce our throughput volumes, require us to incur additional handling costs or require capital expenditures. For example, different product specifications for different markets affect the fungibility of the products in our system and could require the construction of additional storage. In addition, changes in the product quality of the products we receive on our product pipeline systems could reduce or eliminate our ability to blend products.

EMPLOYEES

We are managed and operated by the board of directors and executive officers of MPLX GP, our general partner. Our general partner has the sole responsibility for providing the employees and other personnel necessary to conduct our operations. All of the employees that conduct our business are employed by affiliates of our general partner. Our general partner and its affiliates have approximately 2,800 full-time employees that provide services to us under our employee services agreements. We believe that our general partner and its affiliates have a satisfactory relationship with those employees.

AVAILABLE INFORMATION

General information about MPLX LP and our general partner, MPLX GP, including Governance Principles, Audit Committee Charter, Conflicts Committee Charter and Certificate of Limited Partnership, can be found at http://www.mplx.com. In addition, our Code of Business Conduct and Code of Ethics for Senior Financial Officers are available in this same location.

MPLX LP uses its website, www.mplx.com, as a channel for routine distribution of important information, including news releases, analyst presentations and financial information. Our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after the reports are filed or furnished with the SEC. These documents are also available in hard copy, free of charge, by contacting our Investor Relations office. In addition, our website allows investors and other interested persons to sign up to automatically receive email alerts when we post news releases and financial information on our website. Information contained on our website is not incorporated into this Annual Report on Form 10-K or other securities filings.


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Item 1A. Risk Factors

You should carefully consider each of the following risks and all the other information set forth elsewhere in this Annual Report on Form 10-K in evaluating us and our common units. Some of these risks relate principally to our business, the business and operations of MPC and the industry in which we operate, while others relate principally to tax matters, and ownership of our common units and the securities markets generally.

Our business, financial condition, results of operations or cash flows could be materially and adversely affected by these risks, and, as a result, the trading price of our common units could decline.

Risks Relating to Our Business

Our substantial debt and other financial obligations could impair our financial condition, results of operations and cash flow, and our ability to fulfill our debt obligations.

We have significant debt obligations, which totaled $4.9 billion as of December 31, 2016, and we may incur significant additional debt obligations in the future. For example, in February 2017, we issued an additional $2.25 billion aggregate principal amount of senior notes. Our existing and future indebtedness may impose various restrictions and covenants on us that could have, or the incurrence of such debt could otherwise result in, material adverse consequences, including:

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.

Global economic conditions may have adverse impacts on our business and financial condition and adversely impact our ability to access capital markets on acceptable terms.

Changes in economic conditions could adversely affect our financial condition and results of operations. A number of economic factors, including, but not limited to, gross domestic product, consumer interest rates, government spending sequestration, strength of U.S. currency versus other international currencies, consumer confidence and debt levels, retail trends, inflation and foreign currency exchange rates, may generally affect our business. Recessionary economic cycles, higher unemployment rates, higher fuel and other energy costs and higher tax rates may adversely affect demand for natural gas, NGLs and crude oil. Also, any tightening of the capital markets could adversely impact our ability to execute our long-term organic growth projects and meet our obligations to our customers and limit our ability to raise capital and, therefore, have an adverse impact on our ability to otherwise take advantage of business opportunities or react to changing economic and business conditions. These factors could have a material adverse effect on our revenues, income from operations, cash flows and our quarterly distribution on our common units.


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A significant decrease or delay in oil and natural gas production in our areas of operation, whether due to sustained declines in oil, natural gas and NGL prices, and natural declines in well production, or otherwise, may adversely affect our revenues, financial condition, and cash available for distribution.

A significant portion of our operations are dependent upon production from oil and natural gas reserves and wells, which will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels and the utilization rate of our facilities, we must continually obtain new oil, natural gas, NGL and refined product supplies, which depends in part on the level of successful drilling activity near our facilities.

We have no control over the level of drilling activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, drilling costs per Mcf or barrel, demand for hydrocarbons, operational challenges, access to downstream markets, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital. Because of these factors, even if new oil or natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. If we are not able to obtain new supplies of oil or natural gas to replace the natural decline in volumes from existing wells, throughput on our pipelines and the utilization rates of our facilities would decline, which could have a material adverse effect on our business, results of operations and financial condition and could reduce our ability to make distributions to our unitholders.

Decreases in energy prices can decrease drilling activity, production rates and investments by third parties in the development of new oil and natural gas reserves. The prices for oil, natural gas and NGLs depend upon factors beyond our control, including global and local demand, production levels, changes in interstate pipeline gas quality specifications, imports and exports, seasonality and weather conditions, economic and political conditions domestically and internationally and governmental regulations. Sustained periods of low prices could result in producers also significantly curtailing or limiting their oil and gas drilling operations which could substantially delay the production and delivery of volumes of oil, gas and NGLs to our facilities and adversely affect our revenues and cash available for distribution. This impact may also be exacerbated due to the extent of our commodity-based contracts, which are more directly impacted by changes in gas and NGL prices than our fee-based contracts due to frac spread exposure and may result in operating losses when natural gas becomes more expensive on a Btu equivalent basis than NGL products. In addition, our purchase and resale of gas and NGLs in the ordinary course exposes us to significant risk of volatility in gas or NGL prices due to the potential difference in the time of the purchases and sales and the potential difference in the price associated with each transaction, and direct exposure may also occur naturally as a result of our production processes. The significant fluctuation and decline in natural gas, NGL and oil prices currently occurring has adversely impacted our unit price, thereby increasing our distribution yield and cost of capital. Such impacts could adversely impact our ability to execute our long-term organic growth projects, satisfy our obligations to our customers, and make distributions to unitholders at intended levels, and may also result in non-cash impairments of long-lived assets or goodwill or other-than-temporary non-cash impairments of our equity method investments.

Our business plan and growth strategy requires, among other matters, access to new capital. An increased cost of capital could impair our ability to grow, our ability to make distributions to unitholders at our intended levels and trigger us to impair our goodwill and intangible assets.

Our ability to successfully operate our business, generate sufficient cash to pay the quarterly cash distributions to our unitholders and to allow for growth of our business and the growth of our distributions is subject to a number of risks and uncertainties, including economic and competitive factors beyond our control, which may impair our access to new capital. If the cost of capital becomes too expensive, we may not be able to raise the necessary funds from the equity market on satisfactory terms, if at all. We may be required to consider alternative financing strategies such as the formation of joint ventures or the sale of non-strategic assets, which may not provide the necessary capital, and our ability to develop or acquire strategic and accretive assets and finance growth projects will be limited. Factors that influence our cost of capital include market conditions, including our common unit price and the resultant distribution yield. When the price of our common units decreases, the resultant distribution yield increases, and our cost of capital increases accordingly. A significant drop in our unit price could also trigger an impairment of our goodwill and intangible assets. The significant decline in oil prices that occurred in 2015 and continued into 2016 has impacted our common unit price, as it has others in the energy industry. Although oil prices have begun to recover late in 2016, there is no assurance that this recovery will continue. The high and the low market price of our common units in 2016 ranged from a high of $39.46 to a low of $16.34. Given the significant change in MLP valuations and the resultant higher distribution yield environment the sector has experienced in 2015 and 2016, our cost of capital has increased, which could impair our ability to grow our business and make distributions to unitholders at intended levels.


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We may not have sufficient cash from operations after the establishment of cash reserves and payment of our expenses, including cost reimbursements to MPC and its affiliates, to enable us to pay the minimum quarterly distribution to our unitholders.

We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distributions to our unitholders. The amount of cash we can distribute on our common units depends principally on the amount of cash we generate from our operations, which may fluctuate from quarter to quarter based on, among other things:

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.

In addition, the actual amount of cash available for distribution may depend on other factors, some of which are beyond our control, including:

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.

Our inability, or limited ability, to control certain aspects of management of joint venture legal entities in which we have a partial ownership interest may mean that we will not receive the amount of cash we expect to be distributed to us. In addition, for entities where we have a noncontrolling ownership interest, or for entities that we operate but in which the noncontrolling interest owners have participative rights, we will be unable to control ongoing operational or other decisions, including the incurrence of capital expenditures that we may be required to fund, the incurrence of debt, or the pursuit of certain projects that we may want to pursue. Certain of our joint venture partners have the option to not make, or may otherwise cease making, capital contributions, so we may be required to fully fund capital or operating expenditures for the joint venture. For joint ventures we operate, we may not receive adequate reimbursement for all of the expenditures we incur to operate the joint venture. In addition, we may be unable to control the amount of cash we receive from the operation of these entities, which could adversely affect our ability to pay the minimum quarterly distribution to our unitholders.

Furthermore, the amount of cash we have available for distribution depends primarily on our cash flow and not solely on profitability, which is affected by non-cash items. As a result, we may make distributions during periods when we record net losses and may not make distributions during periods when we record net income.

We may not always be able to accurately estimate hydrocarbon reserves and expected production volumes; therefore, volumes we service in the future could be less than we anticipate.

We work closely with our producer customers in an effort to understand hydrocarbon reserves and expected production volumes. We periodically review or have outside consultants review hydrocarbon reserve information and expected production data that is publicly available or that is provided to us by our producer customers. However, we may not be able to accurately estimate hydrocarbon reserves and production volumes expected to be delivered to us for a variety of reasons, including the unavailability of sufficiently detailed information and unanticipated changes in producers’ expected drilling schedules. Significant declines in oil, natural gas or NGL prices could also cause producers to curtail or limit drilling operations, which

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may result in the volumes delivered to us being less than anticipated. Accordingly, we may not have accurate estimates of total reserves serviced by our assets, the anticipated life of such reserves, or the expected volumes to be produced from those reserves. In such event, if we are unable to secure additional sources, then the volumes that we gather or process in the future could be less than anticipated. A decline in such volumes could have a material adverse effect on our results of operations and financial condition.

Our expansion of existing assets and the construction of new assets, if completed, may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks that could adversely impact our business, financial condition, results of operations and cash flows.

One of the ways we intend to grow our business is through the construction of, or additions to, our existing gathering, transportation, treating, processing, storage and fractionation facilities, which requires the expenditure of significant amounts of capital which may exceed our expectations. Construction involves many factors beyond our control including delays caused by third-party landowners, unavailability of materials, labor disruptions, environmental constraints, financing, accidents, weather and other factors. Additionally, we are subject to numerous regulatory, environmental, political, legal and inflationary uncertainties, including societal sentiment regarding the development and use of carbon based fuels, political pressures and the influence of environmental or other special interest groups, as well as stringent, lengthy and occasionally unreasonable or impractical federal, state and local permitting, zoning, consent, or authorizations requirements, or new laws, regulations, requirements or enforcement actions, which may cause us to incur additional capital expenditures, delay, interfere with or impair our construction activities, including by requiring the redesign of facilities, the acquisition of additional equipment, and relocations or rerouting of facilities, subject us to additional expenses or penalties and adversely affect our operations and cash flows available for distribution to unitholders. If we undertake these projects, we may not be able to complete them on schedule, or at all, or at the budgeted cost. We also may be required to incur additional costs and expenses in connection with the design and installation of our facilities due to their location and the surrounding terrain. We may be required to install additional facilities, incur additional capital and operating expenditures, or experience interruptions in or impairments of our operations to the extent that the facilities are not designed or installed correctly. For example, certain of our processing, fractionation and pipeline facilities are located in mountainous areas such as our Utica, Marcellus and southern Appalachian operations, which may require specially designed foundations, retaining walls and other structures or facilities. If such foundations, retaining walls or other facilities are not designed or installed correctly, do not perform as intended, or fail, we may be required to incur significant capital expenditures to correct or repair the deficiencies, or may incur significant damage to or loss of facilities, and our operations may be interrupted as a result of deficiencies or failures. In addition, such deficiencies may cause damages to the surrounding environment, including slope failures, stream impacts and other natural resource damages, and we may as a result also be subject to increased operating expenses or environmental penalties and fines. In addition, certain agreements with our customers contain substantial financial penalties and/or give the producer the right to repurchase certain assets and terminate their contracts with us if construction deadlines are not achieved. Any such penalty or contract termination could have a material adverse effect on our income from operations and cash available for distribution. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction may occur over an extended period of time, and we may not receive any material increases in revenues until after completion of the project, if at all.

Furthermore, we may have only limited oil, natural gas, NGL or refined product supplies committed to these facilities prior to their construction. We may construct facilities to capture anticipated future growth in production or satisfy anticipated market demand which does not materialize, the facilities may not operate as planned or may not be used at all. In order to attract additional oil, natural gas, NGL or refined product supplies from a customer, we may be required to order equipment and facilities, obtain rights of way or other land rights or otherwise commence construction activities for facilities that will be required to serve such customer’s additional supplies prior to executing agreements with the customer. If such agreements are not executed, we may be unable to recover such costs and expenses. We may also rely on estimates of proved reserves in our decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough oil, natural gas, NGLs or refined products to achieve our expected investment return or result in immediate revenue increases, which could adversely affect our operations and cash available for distribution. Alternatively, oil, natural gas, NGL or refined product supplies committed to facilities under construction may be delivered prior to completion of such facilities, or we may otherwise have unexpected increase in volumes that could adversely affect our ability to expand our facilities. In such event, we may be required to temporarily utilize third-party facilities for such oil, natural gas, NGLs or refined products, which may increase our operating costs and reduce our cash available for distribution.


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Due to capacity, market and other constraints relating to the growth of our business, we may experience difficulties in the execution of our business plan, which may increase our costs and reduce our revenues and cash available for distribution.

The successful execution of our business strategy is impacted by a variety of factors, including our ability to grow our business and satisfy our customers’ requirements for gathering, processing, fractionation, marketing, transportation and storage services. Our ability to grow our business and satisfy our customers’ requirements may be adversely affected by a variety of factors, including the following:

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.

If we are unable to successfully execute our business strategy, then our operating and capital expenditures may materially increase and our revenues and cash available for distribution may be adversely affected.

We engage in commodity derivative activities to mitigate the impact of commodity price volatility on our cash flows, but these activities may reduce our earnings, profitability and cash flows. In addition, we may not accurately predict future commodity price fluctuations, our risk management activities may impair our ability to benefit from price increases, and additional regulation of commodity derivative activities could adversely impact our ability to manage these risks.

Our operations expose us to fluctuations in commodity prices. We utilize derivative financial instruments related to the future price of crude oil, natural gas and certain NGLs with the intent of reducing volatility in our cash flows due to fluctuations in commodity prices.

The extent of our commodity price exposure is related largely to our contract mix and the effectiveness and scope of our derivative activities. We have a policy to enter into derivative transactions related to only a portion of the volume of our expected production or fuel requirements that are subject to commodity price volatility and, as a result, we expect to continue to have some direct commodity price exposure. Our actual future production or fuel requirements may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to settle all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, which could result in a substantial diminution of our liquidity. Alternatively, we may seek to amend the terms of our derivative financial instruments, including the extension of the settlement date of such instruments. Additionally, because we may use derivative financial instruments relating to the future price of crude oil to mitigate our exposure to NGL price risk, the volatility of our future cash flows and net income may increase if there is a change in the pricing relationship between crude oil and NGLs. As a result of these factors, our risk management activities may not be as effective as we intend in reducing the downside volatility of our cash flows and, in certain circumstances, may actually increase the volatility of our cash flows. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect and our risk management policies and procedures are not properly followed. For further information about our risk management policies and procedures, please read Item 8. Financial Statements and Supplementary Data – Note 16. Derivative Financial Instruments.

To the extent that we do not manage the commodity price risk relating to a position that is subject to commodity price risk and commodity prices move adversely, we could suffer losses. Such losses could be substantial and could adversely affect our

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operations and cash flows available for distribution. In addition, managing the commodity risk may actually reduce our opportunity to benefit from increases in the market or spot prices.

As a result of the Dodd-Frank Act, over-the-counter derivatives markets and entities are subject to regulation by the Commodities Futures Trading Commission (the “CFTC”), the SEC and other regulators. The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and exchange trading. To the extent we engage in such transactions that are or become subject to such rules in the future, we will be required to comply or to take steps to qualify for an exemption to such requirements. Although we believe that we qualify for the end-user exception to the mandatory clearing requirements for swaps to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants may change the cost and availability of the swaps that we use for hedging. Additional mandatory clearing requirements could be imposed that may impair our ability to maintain over-the-counter hedging positions or require us to post collateral. The Dodd-Frank Act and its implementing regulations, including those not yet finalized, could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, increase the administrative burden and regulatory risk associated with entering into certain derivative contracts, and increase our exposure to less credit-worthy counterparties. As a result, if we reduce our use of derivatives, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material adverse effect on our income from operations and cash flows available for distribution.

Due to an increased domestic supply of NGLs, we may be required to find alternative NGL market outlets and to rely more heavily on the export of NGLs, which may increase our operating costs or reduce the price received for NGLs and thereby reduce our cash available for distribution.

Due to increased production of natural gas, particularly in shale plays, there is an increased domestic supply of NGLs, which is currently outpacing, and could continue to outpace, domestic demand. As a result, we and our producer customers may need to continue to find alternate NGL market outlets and to rely more heavily on the export of NGLs. Our ability to find alternative NGL market outlets is dependent upon a variety of factors, including the construction and installation of additional NGL transportation infrastructure necessary to transport NGLs to other markets. In order to obtain committed transportation capacity, it may be necessary to make significant minimum volume commitments, with take or pay payments or deficiency fees if the minimum volume is not delivered. In other instances, we may enter into long-term sales arrangements, and we may incur shortfall or deficiency fees or be subject to other liabilities, including breach of contract claims, if we do not deliver the contracted quantity. We market NGLs on behalf of various of our producer customers, and as a result, we may make such commitments on behalf of those producer customers. We expect to be able to pass such commitments through to our producer customers, but if we were unable to do so, our operating costs may increase significantly, which could have a material adverse effect on our results of operations and our ability to make cash distributions. Similarly, our ability to export NGLs on a competitive basis is impacted by various factors, including:

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 above factors could increase our operating costs or adversely affect the price that we and our producer customers receive for NGLs, which in turn may have a material adverse effect on our volumes, revenues, income and cash available for distribution.

We depend on third parties for the oil, natural gas and refined products we gather, transport and store, the natural gas and refinery off-gas we process, and the NGLs we fractionate and stabilize at our facilities, and a reduction in these quantities could reduce our revenues and cash flow.

Although we obtain our supply of oil, natural gas, refinery off-gas, NGLs and refined products from numerous third-party producers and suppliers, a significant portion comes from a limited number of key producers/suppliers, who are usually under no obligation to deliver a specific volume to our facilities. If these key suppliers, or a significant number of other producers,

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were to decrease the supply of oil, natural gas, refinery off-gas, NGLs or refined products to our systems and facilities for any reason, we could experience difficulty in replacing those lost volumes. In some cases, the producers or suppliers are responsible for gathering or delivering oil, natural gas, refinery off-gas, NGLs or refined products to our facilities or we rely on other third parties to deliver volumes to us on behalf of the producers or suppliers. If such producers, suppliers or other third parties are unable, or otherwise fail to, deliver the volumes to our facilities, or if our agreements with any of these third parties terminate or expire such that our facilities are no longer connected to their gathering or transportation systems or the third parties modify the flow of natural gas, refinery off-gas or NGLs on those systems away from our facilities, the throughput on and utilization of our facilities may be reduced, or we may be required to incur significant capital expenditures to construct and install gathering pipelines or other facilities to be able to receive such volumes. Because our operating costs are primarily fixed, a reduction in the volumes delivered to us would result not only in a reduction of revenues, but also a decline in net income and cash flow.

We may not be able to retain existing customers, or acquire new customers, which would reduce our revenues and limit our future profitability.

A significant portion of our business comes from a limited number of key customers. The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including competition from other gatherers, processors, pipelines, and fractionators, and the price of, and demand for, natural gas, NGLs, crude oil and refined products in the markets we serve. Our competitors include large oil, natural gas, refining and petrochemical companies, some of which have greater financial resources, more numerous or greater capacity pipelines, processing and other facilities, greater access to natural gas, crude oil and NGL supplies than we do or other synergies with existing or new customers that we cannot provide. Our competitors may also include our joint venture partners, who in some cases are permitted to compete with us and may have a competitive advantage due to their familiarity with our business arising from our joint venture arrangements, as well as third parties on whom we rely to deliver natural gas, NGLs, crude oil and refined products to our facilities, who may have a competitive advantage due to their ability to modify the flow of natural gas, NGLs, crude oil and refined products on their systems away from our facilities. Additionally, our customers that gather gas through facilities that are not otherwise dedicated to us may develop their own processing and fractionation facilities in lieu of using our services.

As a consequence of the increase in competition in the industry, and the volatility of natural gas prices, end-users and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternative fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could affect our profitability.

The fees charged to third parties under our gathering, processing, transmission, transportation, fractionation, stabilization and storage agreements may not escalate sufficiently to cover increases in costs, or the agreements may not be renewed or may be suspended in some circumstances.

Our costs may increase at a rate greater than the fees we charge to third parties. Furthermore, third parties may not renew their contracts with us. Additionally, some third parties’ obligations under their agreements with us may be permanently or temporarily reduced due to certain events, some of which are beyond our control, including force majeure events wherein the supply of natural gas, NGLs, crude oil or refined products are curtailed or cut-off due to events outside our control. If the escalation of fees is insufficient to cover increased costs, or if third parties do not renew or extend their contracts with us, or if third parties suspend or terminate their contracts with us, our financial results would suffer.

We are exposed to the credit risks of our key customers and derivative counterparties, and any material non-payment or non-performance by our key customers or derivative counterparties could reduce our ability to make distributions to our unitholders.

We are subject to risks of loss resulting from non-payment or non-performance by our customers, which risks may increase during periods of economic uncertainty. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. This risk is further heightened due to the sustained decline of natural gas, NGL and oil prices that has occurred. With respect to our producer customers who have made acreage dedications to us, we may be exposed to additional risks to the extent that those customers become bankrupt and the acreage dedications are challenged and not upheld in bankruptcy. In addition, our risk management activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument,

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the terms of the derivative instruments are imperfect, and our risk management policies and procedures are not properly followed. Any such material non-payment or non-performance could reduce our ability to make distributions to our unitholders.

Any strategic acquisitions, including the dropdowns proposed by MPC, are subject to substantial risks that could adversely affect our financial condition and results of operations and reduce our ability to make distributions to unitholders.

In addition to organic growth, a component of our business strategy can include the expansion of our operations through strategic acquisitions, including the dropdowns proposed by MPC. Any acquisitions, including the dropdowns proposed by MPC, involve potential risks, including, amongst others:

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.

In addition, if we are unable to make accretive strategic acquisitions from MPC or third parties that increase the cash generated from operations per unit, whether due to an inability to identify attractive acquisition candidates, to negotiate acceptable purchase contracts, or to obtain financing for these acquisitions on economically acceptable terms, then our ability to successfully implement our business strategy may be impaired.

If we are unable to timely and successfully integrate the MarkWest Merger or our future acquisitions, including the dropdowns proposed to MPC, our future financial performance may suffer, and we may fail to realize all of the anticipated benefits of the transactions.

Our future growth may depend in part on our ability to integrate our future acquisitions. We cannot guarantee that we will successfully integrate the MarkWest Merger, the assets we may acquire in the dropdowns proposed by MPC, or any other acquisitions into our existing operations, or that we will achieve the desired profitability and anticipated results from such acquisitions. Failure to achieve such planned results could adversely affect our operations and cash available for distribution.

Significant acquisitions, including the MarkWest Merger and dropdowns proposed by MPC, present potential risks including:

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.

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Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition, if at all. Following an acquisition, we may discover previously unknown liabilities, including environmental liabilities, which could cause us to incur increased costs to address these liabilities or to attain or maintain compliance with applicable law. Our capitalization and results of operation may also change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we may consider in determining the application of these funds and other resources.

We are indemnified for liabilities arising from an ongoing remediation of property on which certain of our facilities are located and our results of operations and our ability to make distributions to our unitholders could be adversely affected if an indemnifying party fails to perform its indemnification obligations.

The prior third-party owner or operator of our Kenova, Boldman, Cobb, Kermit and Majorsville facilities has been or is currently involved in investigatory or remedial activities with respect to the real property underlying those facilities pursuant to regulatory orders with the EPA and various state regulatory agencies. The third party or its successor in interest has agreed to retain sole liability and responsibility for, and to indemnify us against, any environmental liabilities associated with these regulatory orders or the real property underlying these facilities to the extent such liabilities arose prior to the effective date of the agreements pursuant to which such properties were acquired or leased and to the extent not contributed to by us. In addition, the previous owner and/or operator of certain facilities on the real property on which our rail facility is constructed near Houston, Pennsylvania has been or is currently involved in investigatory or remedial activities related to AMD with respect to that real property. The third party has accepted liability and responsibility for, and has agreed to indemnify us against, any environmental liabilities associated with the AMD that are not exacerbated by us in connection with our operations. MPC has also agreed to indemnify us for certain environmental liabilities related to assets contributed to us by MPC in our Initial Offering or sold to us subsequently. Our results of operation and our ability to make cash distributions to our unitholders could be adversely affected if in the future any of these third parties fail to perform their indemnification obligations. In addition, from time to time, we have acquired, and may acquire in the future, facilities from third parties which previously have been or currently are the subject of investigatory, remedial or monitoring activities relating to environmental matters. In some cases, we may receive indemnification from the prior owner or operator for some or all of such liabilities, and in other cases we may accept some or all of such liabilities. There is no assurance that any such third parties will perform any such indemnification obligations, or that the obligations and liabilities that we may accept in connection with any such acquisition will not be larger than anticipated, and in such event, our results of operations and cash available for distribution could be adversely affected.

If foreign investment in us or our general partner exceeds certain levels, we could be prohibited from operating inland river vessels, which could materially and adversely affect our business, financial condition, results of operations and cash flows.

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

Risks Relating to our Industry

Certain of our pipelines may be subject to federal or state rate and service regulation, and the imposition and/or cost of compliance with such regulation could adversely affect our operations and cash flows available for distribution to our unitholders.

Some of our natural gas and NGL pipelines, and various of our crude oil and refined product pipelines are, or may in the future be, subject to siting, public necessity and/or service regulations by FERC and/or various state or other regulatory bodies, depending upon jurisdiction. FERC generally regulates the transportation of natural gas, NGLs, crude oil and refined products in interstate commerce and FERC’s regulatory authority includes: facilities construction, acquisition, extension or abandonment of services or facilities (for natural gas pipelines only); rates; operations; accounts and records; and depreciation and amortization policies. FERC’s action in any of these areas or modifications of its current regulations can adversely impact our ability to compete for business, the costs we incur in our operations, the construction of new facilities or our ability to recover the full cost of operating our pipelines. FERC also may conduct audits of these facilities, and if FERC determines that we are not in compliance with our tariff or applicable regulations, we may incur additional costs, expenses or penalties. For certain NGL product pipelines and for the crude oil and refined product common carrier pipelines, we have a FERC tariff on file and we may have additional common carrier pipelines in the future that may be subject to these requirements. We also own and are constructing pipelines that are carrying or are expected to carry NGLs owned by us across state lines between our processing

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and fractionation facilities that we believe are either not subject to FERC’s requirements for common carrier NGL pipelines or would otherwise meet the qualifications for a waiver from many of FERC’s reporting and filing requirements. However, we cannot provide assurance that FERC will not at some point find that some or all of these pipelines are subject to FERC’s requirements for common carrier pipelines and/or are otherwise not exempt from its reporting and filing requirements. Such a finding could subject us to potentially burdensome and expensive operational, reporting and other requirements as well as fines, penalties or other sanctions.

Most of our natural gas and NGL pipelines are generally not subject to regulation by FERC. The NGA specifically exempts natural gas gathering systems from FERC’s jurisdiction. Yet, such operations may still be subject to regulation by various state agencies. The applicable statutes and regulations generally require that our rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render services and that we offer service to our shippers on a not unduly discriminatory basis. We cannot assure unitholders that FERC will not at some point determine that some or all of such pipelines are within its jurisdiction, and regulate such services, which could limit the rates that we may charge, increase our costs of operation, and subject us to fines, penalties or other sanctions. FERC rate cases can involve complex and expensive proceedings. For more information regarding regulatory matters that could affect our business, please read Item 1. Business –Rate and Other Regulation as set forth in this Annual Report on Form 10-K.

Some of our natural gas and NGL pipelines, and various of our crude oil and refined product pipelines, are subject to FERC’s rate-making policies that could have an adverse impact on our ability to establish rates that would allow us to recover the full cost of operating our pipelines including a reasonable return.

A number of our pipelines provide interstate service that is subject to regulation by the FERC. The FERC prescribes rate methodologies for developing regulated tariff rates for these natural gas, interstate oil and products pipelines. The FERC’s regulated tariff may not allow us to recover all of our costs of providing services. Changes in the FERC’s approved rate methodologies, or challenges to our application of an approved methodology, could also adversely affect our rates. Additionally, shippers may protest (and the FERC may investigate) the lawfulness of tariff rates. The FERC can require refunds of amounts collected pursuant to rates that are ultimately found to be unlawful and prescribe new rates prospectively.

MPC has agreed not to challenge, or to cause others to challenge or assist others in challenging, our tariff rates in effect during the term of our transportation services agreements with MPC. However, this agreement does not prevent other shippers or interested persons from challenging our tariff rates or proration rules; nor does it prevent regulators from reviewing our rates and tariffs on their own initiative. At the end of the term of each of our transportation services agreements with MPC, if the agreement is not renewed, MPC will be free to challenge, or to cause other parties to challenge or assist others in challenging, our tariffs in effect at that time.

Action by FERC could adversely affect our ability to establish reasonable rates that cover operating costs and allow for a reasonable return. An adverse determination in any future rate proceeding brought by or against us could have a material adverse effect on our business, financial condition and results of operations.

If we are unable to obtain new rights-of-way or other property rights, or the cost of renewing existing rights-of-way or property rights increases, then we may be unable to fully execute our growth strategy, which may adversely affect our operations and cash flows available for distribution to unitholders.

The construction of additions to, or expansions of, our facilities may require us to obtain new rights-of-way or other property rights prior to constructing new plants, pipelines and other transportation and storage facilities. We may be unable to obtain such rights-of-way or other property rights to connect new natural gas supplies to our existing gathering lines, to connect our existing or future facilities to new natural gas, NGL, crude oil or refined product markets, or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new or renew existing rights-of-way or other property rights, including the renewal of leases for land on which our processing facilities are located. If the cost of obtaining new or renewing existing rights-of-way or other property rights increases, it may adversely affect our operations and cash flows available for distribution to unitholders. If we are unable to renew a lease for land on which any of our processing facilities are located, we may be required to remove our facilities from that site, which could require us to incur significant costs and expenses, disrupt our operations, and adversely affect our cash available for distribution.

Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make distributions at our intended levels.

Our revolving credit facility and our loan agreement with MPC Investment have variable interest rates. Although interest rates have been low during the past several years, the United States Federal Reserve raised interest rates in December 2015 and

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December 2016, and have indicated that additional interest rate increases may occur in 2017. As a result, interest rates on our debt could be higher than current levels, causing our financing costs to increase accordingly. In addition, we may in the future refinance outstanding borrowings under our revolving credit facility with fixed-rate indebtedness. Interest rates payable on fixed-rate indebtedness typically are higher than the short-term variable interest rates that we pay on borrowings under our revolving credit facility. We also have other fixed-rate indebtedness that we may need or desire to refinance in the future prior to the applicable stated maturity. Furthermore, as with other yield-oriented securities, our unit price will be impacted by our cash distributions and the implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make distributions at our intended levels.

Our business is subject to laws and regulations with respect to environmental, occupational safety and health, nuisance, zoning, land use and other regulatory matters, and the violation of, or the cost of compliance with, such laws and regulations could adversely affect our operations and cash flows available for distribution to our unitholders.

Numerous governmental agencies enforce federal, regional, state and local laws and regulations on a wide range of environmental, occupational safety and health, nuisance, zoning, land use, endangered species and other regulatory matters. We could be adversely affected by increased costs due to stricter pollution-control requirements or liabilities resulting from non-compliance with operating or other regulatory permits. Strict joint and several liability may be incurred without regard to fault, or the legality of the original conduct, under certain of the environmental laws for remediation of contaminated areas, including CERCLA, RCRA and analogous state laws. Private parties, including the owners of properties located near our storage, fractionation and processing facilities or through which our pipeline systems pass, also may have the right to pursue legal actions to enforce compliance, as well as seek damages for non-compliance, with environmental laws and regulations or for personal injury or property damage. New, more stringent environmental laws, regulations and enforcement policies, the listing of additional species as endangered or threatened, and new, amended or re-interpreted permitting requirements, policies and processes, might adversely affect our operations and activities, and existing laws, regulations and policies could be reinterpreted or modified to impose additional requirements, delays or constraints on our construction of facilities or on our operations, increase our operating costs, or require our facilities to be aggregated into one air emissions permit or permit application. Federal, state and local agencies also could impose additional health and safety requirements, any of which could increase our operating costs. Local governments may adopt more stringent local permitting and zoning ordinances that impose additional time, place and manner restrictions, delays or constraints on our activities to construct and operate our facilities, require the relocation of our facilities, prevent or restrict the expansion of our facilities, or increase our costs to construct and operate our facilities, including the construction of sound mitigation devices.

In addition, we face the risk of accidental releases or spills associated with our operations, which could result in material costs and liabilities, including those relating to claims for damages to property, natural resources and persons, environmental remediation and restoration costs and governmental fines and penalties. Our failure to comply with or alleged non-compliance with environmental or safety-related laws and regulations could result in administrative, civil and criminal penalties, the imposition of investigatory and remedial obligations and even injunctions that restrict or prohibit some or all of our operations. For more information regarding the environmental, safety and other regulatory matters that could affect our business, please read Item 1. Business – Rate and Other Regulation, Item 1. Business – Environmental Regulation, and Item 1. Business – Pipeline Safety, each as set forth in this Annual Report on Form 10-K.

Climate change legislation or regulations restricting emissions of GHGs or methane could result in increased operating costs, reduced demand for our services and adversely affect the cash flows available for distribution to our unitholders.

As a consequence to an EPA administrative conclusion that GHGs present an endangerment to public health and the environment, the EPA adopted regulations establishing PSD construction and Title V operating permit requirements for GHG emissions from certain large stationary sources that are potential major sources of certain principal, or criteria, pollutant emissions. In addition, the EPA and states are gathering information on existing facilities in various industries, which may be used to support potential future regulation of carbon emissions, and states may seek to adopt their own permitting programs under state laws that require permit reviews of large stationary sources emitting only GHGs. If we were to become subject to Title V and PSD permitting requirements due to non-GHG criteria pollutants, or if EPA or states implemented more stringent permitting requirements relating to GHG emissions without regard to non-GHG criteria pollutants, we may be required to install “best available control technology” to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future. In addition, we may experience substantial delays or possible curtailment of construction or projects in connection with applying for, obtaining or maintaining preconstruction and operating permits, we may encounter limitations on the design capacities or size of facilities, and our construction and operating costs may materially increase.

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Congress has from time to time considered legislation to reduce emissions of GHGs, but, in the absence of federal climate legislation in the United States in recent years, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. If Congress were to undertake comprehensive tax reform, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for oil, natural gas, NGLs and products derived therefrom.

These requirements or enforcement thereof, or the adoption of any new legislation or regulations that requires additional reporting, monitoring or recordkeeping of GHGs, limits emissions of GHGs from our equipment and operations, or imposes a carbon tax, could adversely affect our operations and materially restrict or delay our ability to obtain air permits for new or modified facilities, could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we process or fractionate. In May 2016, EPA finalized new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration’s efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025. This rule is currently being challenged in court by various affected states. Concurrently, the Commonwealth of Pennsylvania has also proposed similar regulations that have not yet been finalized. We may experience delays in the construction and installation of new facilities due to more stringent permitting requirements, incur additional costs to reduce methane emissions associated with our operations or be required to aggregate the emissions from separate facilities for permitting purposes or to relocate one or more of our facilities due to more stringent emissions standards. To the extent that we incur additional costs or delays, our cash available for distribution may be adversely affected.

Our producer customers or suppliers may also experience similar issues, which may adversely impact their drilling schedules and production volumes and reduce the volumes delivered to us. For more information regarding greenhouse gas and methane emission and regulation, please read Item 1. Business – Environmental Matters – Climate Change.

Finally, for a variety of reasons, natural and/or anthropogenic, some members of the scientific community believe that climate changes could occur which could have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations, which in turn could adversely affect our cash available for distribution to our unitholders.

Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could delay or impede oil or gas production or result in reduced volumes available for us to gather, transport, store, process and fractionate.

We do not conduct hydraulic fracturing operations, but we do provide gathering, processing, transportation, storage and fractionation services with respect to natural gas, oil, NGLs and refined products produced by our customers as a result of such operations. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations such as shales. The process involves the injection of water, sand and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions but several federal agencies have asserted regulatory authority over certain aspects of the process, including the EPA and BLM. In addition, Congress has from time to time considered legislation to provide for additional regulation of hydraulic fracturing. Also, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new federal, state or local laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could make it more difficult to complete natural gas and oil wells in shale formations and increase our producers’ costs of compliance. This could significantly reduce the volumes delivered to us, which could adversely impact our earnings, profitability and cash flows.

We are subject to operating and litigation risks that may not be covered by insurance.

Our industry is subject to numerous operating hazards and risks incidental to gathering, processing, transporting, fractionating and storing natural gas and NGLs and to transporting and storing crude oil and refined products. These include:

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;

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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.

As a result, we may be a defendant in various legal proceedings and litigation arising from our operations. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates or at all, and, even if we are able to obtain such insurance, we may not be able to recover amounts from the insurance carrier for events that we believe are covered. In addition, insurance carriers now require broad exclusions for losses due to war risk and terrorist acts. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our operations and cash available for distribution.

We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs, and the expansion of pipeline safety laws and regulations could require us to use more comprehensive and stringent safety controls and subject us to increased capital and operating costs.

The DOT through the PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs for gas transmission and hazardous liquids pipelines located where a leak or rupture could do the most harm. The regulations require the following of operators of covered pipelines to:

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.

In addition, the maximum civil penalty for federal pipeline safety violations has increased from $100,000 to $200,000 per violation per day of violation and also from $1 million to $2 million for a related series of violations. Over the past several years, PHMSA has published new regulations, and issued notices for additional proposed regulations, to expand pipeline safety requirements.

In addition, PHMSA and other state regulators have recently expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities to assess compliance with hazardous liquids pipeline safety requirements, which actions by PHMSA are currently subject to judicial and administrative challenges by one or more midstream operators. The adoption of these and other laws or regulations that apply more comprehensive or stringent safety standards to gas, NGL, crude oil and refined product lines or other facilities, or the expansion of regulatory inspections by PHMSA and other state regulators described above, could require us to install new or modified safety controls, pursue added capital projects, make modifications or operational changes, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased capital and operational costs or operational delays that could be significant and have a material adverse effect on our financial position or results of operations and ability to make distributions to our unitholders.

Some states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. These regulations have raised operating costs for the industry, and compliance with such laws and regulations may cause us to incur potentially material capital expenditures associated with the construction, maintenance, and upgrading of equipment and facilities.

The United States inland waterway infrastructure is aging and planned and unplanned maintenance may adversely affect our operations.

Maintenance of the United States inland waterway system is vital to our marine transportation operations. The system is composed of over 12,000 miles of commercially navigable waterway, supported by over 240 locks and dams designed to provide flood control, maintain pool levels of water in certain areas of the country and facilitate navigation on the inland river system. The United States inland waterway infrastructure is aging, with more than half of the locks over 50 years old. As a

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result, due to the age of the locks, planned and unplanned maintenance may create more frequent outages, resulting in delays and additional operating expenses. Part of the costs for new construction and major rehabilitation of locks and dams is funded by marine transportation companies through taxes and the other portion is funded by general federal tax revenues. Failure of the federal government to adequately fund infrastructure maintenance and improvements in the future would have a negative impact on our ability to deliver products to our customers on a timely basis. Furthermore, any additional user taxes that may be imposed in the future to fund infrastructure improvements would increase our operating expenses.

Interruptions in operations at any of our facilities or MPC’s refining operations may adversely affect our operations and cash flows available for distribution to our unitholders.

Our operations depend upon the infrastructure that we have developed, including processing and fractionation plants, storage facilities, gathering and transportation facilities, various other means of transportation and marketing services. Any significant interruption at these facilities or pipelines, MPC’s refining operations or in our ability to gather, transport, or store natural gas, NGLs, crude oil or other refined products to or from these facilities or pipelines for any reason, or to market or transport the natural gas, crude oil, NGLs or refined products, would adversely affect our operations and cash flows available for distribution to our unitholders. In some cases, these events may also adversely affect the pricing received for NGLs, and may reduce the volumes of oil, gas, NGLs and refined products that we receive.

Operations at our facilities or MPC’s refining operations could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within our control, such as:

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.

Our NGL fractionation, storage and marketing operations in the Marcellus and Utica regions are integrated, and as a result, it is possible that an interruption of these operations may impact operations in the other regions, which may exacerbate the impacts of such interruption.

The construction and operation of certain of our facilities in our G&P segment may be impacted by surface or subsurface mining operations by one or more third parties, which could adversely impact our construction activities or cause subsidence or other damage to our facilities. In such event, our construction may be prevented or delayed, or the costs and time increased, or our operations at such facilities may be impaired or interrupted, and we may not be able to recover the costs incurred for delays or to relocate or repair our facilities, from such third parties.

In addition, our marine transportation business is subject to weather conditions on a daily basis. Adverse weather conditions such as high or low water on the inland waterway systems, fog and ice, tropical storms, hurricanes and tsunamis on both the inland waterway systems and throughout the United States coastal waters can impair the operating efficiencies of the marine fleet. Such adverse weather conditions can cause a delay, diversion or postponement of shipments of products and are beyond our control. In addition, adverse water and weather conditions can negatively affect a towing vessel’s performance, tow size, loading drafts, fleet efficiency, place limitations on night passages and dictate horsepower requirements.


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Our operations depend on the use of information technology systems that could be the target of industrial espionage or cyber-attack.

Our business has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications for the gathering and processing of natural gas, the gathering, fractionation, transportation and marketing of NGLs, and the gathering, storage and transportation of crude oil and refined products. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our systems and networks, as well as those of our customers, vendors and counterparties, may become the target of cyber-attacks or information security breaches, which in turn could result in the unauthorized release and misuse of confidential or proprietary information as well as disrupt our operations or damage our facilities or those of third parties, which could have a material adverse effect on our revenues and increase our operating and capital costs, which could reduce the amount of cash otherwise available for distribution. Additionally, as cyber incidents continue to evolve we may be required to incur additional costs to modify or enhance our systems or in order to try to prevent or remediate any such attacks. To protect against such attempts of unauthorized access or attack, we have implemented infrastructure protection technologies and disaster recovery plans. There can be no guarantee such plans, to extent they are in place, will be effective.

Terrorist attacks aimed at our facilities or that impact our customers or the markets we serve could adversely affect our business.

The U.S. government has issued warnings that energy assets in general, and the nation’s pipeline and terminal infrastructure in particular, may be future targets of terrorist organizations. The threat of terrorist attacks has subjected our operations to increased risks. Any future terrorist attack on our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business. Similarly, any future terrorist attacks that severely disrupt the markets we serve could materially and adversely affect our results of operations, financial position and cash flows.

Risks Relating to the Business and Operations of MPC

MPC accounted for a large portion of our revenues in 2016 and will continue to do so on a go-forward basis. If MPC changes its business strategy, is unable to satisfy its obligations to us or significantly reduces the volumes transported through our facilities or stored at our storage assets, our revenues would decline and our financial condition, results of operations, cash flows, and ability to make distributions to our unitholders would be materially and adversely affected.

For the year ended December 31, 2016, excluding revenues attributable to volumes shipped by MPC under joint tariffs with third parties that were treated as third-party revenues for accounting purposes, MPC accounted for approximately 30 percent of our revenues and other income, including 92 percent of the revenues and other income within our L&S segment, and we believe MPC will continue to account for a large portion of our revenues on a go forward basis. As we expect to continue to derive a portion of our revenues from MPC for the foreseeable future, any event that materially and adversely affects MPC’s financial condition, results of operations or cash flows may adversely affect our ability to sustain or increase distributions to our unitholders. Accordingly, we are indirectly subject to the operational and business decisions and risks of MPC, the most significant of which include the following:

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;

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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.

We have no control over MPC’s business decisions and operations, and MPC may elect to pursue a business strategy that does not favor us and our business. In addition, significant stockholders of MPC may attempt to affect changes at MPC or acquire control of the company, which could impact the pursuit of MPC’s business strategies. Campaigns by stockholders to affect changes at publicly traded companies are sometimes led by investors seeking to increase short-term stockholder value through actions such as financial restructuring, increased debt, special dividends, stock repurchases or sales of assets or the entire company. As a result, stockholder campaigns at MPC could directly or indirectly adversely affect our results of operations and financial condition and our ability to sustain or increase distributions to our unitholders.

MPC may suspend, reduce or terminate its obligations under our transportation and storage services agreements in some circumstances, which would have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

Our transportation and storage services agreements with MPC include provisions that permit MPC to suspend, reduce or terminate its obligations under the applicable agreement if certain events occur. These events include a material breach of the applicable agreement by us, MPC being prevented from transporting its full minimum volume commitment because of capacity constraints on our pipelines, certain force majeure events that would prevent us from performing some or all of the required services under the applicable agreement and MPC’s determination to suspend refining operations at one of its refineries. MPC has the discretion to make such decisions notwithstanding the fact that they may significantly and adversely affect us. These actions could result in a suspension, reduction or termination of MPC’s obligations under one or more transportation and storage services agreements.

Any such reduction, suspension or termination of MPC’s obligations would have a material adverse effect on our financial condition, results of operations, cash flows and ability to make distributions to our unitholders.

If MPC satisfies only its minimum obligations under, or if we are unable to renew or extend, the transportation and storage services agreements we have with MPC, or if MPC elects to use credits upon the expiration or termination of a transportation services agreement, our cash available for distribution will be materially and adversely affected.

MPC is not obligated to use our services with respect to volumes of crude oil or products in excess of the minimum volume commitments under the transportation services agreements with us. Our cash available for distribution will be materially and adversely affected to the extent that we do not transport volumes in excess of the minimum volume commitments under our transportation services agreements or if MPC’s obligations under our transportation and storage services agreements are suspended, reduced or terminated. In addition, the initial terms of MPC’s obligations under those agreements range from three to 10 years. If MPC fails to use our assets and services after expiration of those agreements and we are unable to generate additional revenues from third parties, our ability to make distributions to unitholders may be materially and adversely affected.

In addition, under our transportation services agreements, MPC must pay us a deficiency payment if it fails to transport its minimum throughput commitment. MPC may then apply the amount of any such deficiency payments as a credit for volumes transported on the applicable pipeline system in excess of its minimum volume commitment during the following four quarters or eight quarters under the terms of the applicable transportation services agreement. Upon the expiration or termination of a transportation services agreement, MPC may use any remaining credits against any volumes shipped by MPC on the applicable pipeline system for the succeeding four or eight quarters, as applicable, without regard to any minimum volume commitment that may have been in place during the term of the agreement. If that were to occur, we would not receive any cash payments for volumes shipped on the applicable pipeline system until any such remaining credits were fully used or until the expiration of the applicable four or eight quarter period.


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MPC’s level of indebtedness, the terms of its borrowings and its credit ratings could adversely affect our ability to grow our business and our ability to make distributions to our unitholders. Our ability to obtain credit in the future may also be adversely affected by MPC’s credit rating.

MPC must devote a portion of its cash flows from operating activities to service its indebtedness, and therefore, cash flows may not be available for use in pursuing its growth strategy. Furthermore, a higher level of indebtedness at MPC in the future increases the risk that it may default on its obligations to us under our transportation and storage services agreements. As of December 31, 2016, MPC had consolidated long-term indebtedness of approximately $11 billion, of which $6 billion was a direct obligation of MPC. The covenants contained in the agreements governing MPC’s outstanding and future indebtedness may limit its ability to borrow additional funds for development and make certain investments and may directly or indirectly impact our operations in a similar manner.

Furthermore, if MPC were to default under certain of its debt obligations, there is a risk that MPC’s creditors would attempt to assert claims against our assets during the litigation of their claims against MPC. The defense of any such claims could be costly and could materially impact our financial condition, even absent any adverse determination. If these claims were successful, our ability to meet our obligations to our creditors, make distributions and finance our operations could be materially and adversely affected.

MPC’s long-term credit ratings are currently investment grade. If these ratings are lowered in the future, the interest rate and fees MPC pays on its credit facilities may increase. Credit rating agencies will likely consider MPC’s debt ratings when assigning ours because of MPC’s ownership interest in us, the significant commercial relationships between MPC and us, and our reliance on MPC for a portion of our revenues. If one or more credit rating agencies were to downgrade the outstanding indebtedness of MPC, we could experience an increase in our borrowing costs or difficulty accessing the capital markets. Such a development could adversely affect our ability to grow our business and to make distributions to our unitholders.

Risks Relating to Tax Matters

Our tax treatment depends on our status as a partnership for federal income tax purposes as well as our not being subject to a material amount of entity level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes, or we become subject to a material amount of entity level taxation for state tax purposes, it would substantially reduce the amount of cash available for distribution to our unitholders.

The anticipated after-tax economic benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this.

A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. Based on our current operations, we believe that we are treated as a partnership rather than as a corporation for such purposes; however, a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes. We have requested and received a favorable ruling from the IRS on the treatment of a portion of our “qualifying income.” The IRS may adopt positions that differ from the ones we take. A successful IRS contest of the federal income tax positions we take may adversely impact the market for our common units, and the costs of any IRS contest will reduce our cash available for distribution to unitholders.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35 percent, and likely would pay state and local income tax at varying rates. Distributions to unitholders generally would be taxed again as corporate dividends, and no income, gains, losses, deductions, or credits would flow through to our unitholders. Treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units. Changes in current state law may subject us to additional entity-level taxation by individual states. Imposition of any such additional taxes on us will substantially reduce the cash available for distribution to unitholders.

Our partnership agreement provides that, if a law is enacted or an existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.


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The sale or exchange of 50 percent or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50 percent or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50 percent threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one calendar year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but it would result in our being treated as a new partnership for tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution.

The IRS has made no determination as to our status as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Our unitholders will be required to pay taxes on their share of income even if they do not receive any distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no distributions from us. Our unitholders may not receive distributions from us equal to their share of our taxable income or even equal to the actual tax liability that result from that income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If our unitholders sell their common units, they will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of a unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in their common units, the amount, if any, of such prior excess distributions with respect to their units will, in effect, become taxable income to the unitholder if the common units are sold at a price greater than the unitholder’s tax basis in those common units, even if the price the unitholder receives is less than the unitholder’s original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our non-recourse liabilities, if a unitholder sells units, the unitholder may incur a tax liability in excess of the amount of cash received from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income. Non-U.S. persons will also potentially have tax filings and payment obligations in additional jurisdictions. Tax-exempt entities and non-U.S. persons should consult their tax advisor before investing in our common units.


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We treat each purchaser of common units as having the same tax benefits without regard to the actual units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

To maintain the uniformity of the economic and tax characteristics of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to our unitholders’ tax returns.

Our unitholders will likely be subject to state and local taxes and return filing requirements in states where they do not live as a result of investing in our units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if our unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently conduct business in approximately 16 states. Many of these states currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is our unitholders’ responsibility to file all U.S. federal, state and local tax returns.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of the common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, or our allocations of income, gain, loss and deduction between our general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

A unitholder who loans his common units to a “short seller” to cover a short sale of common units (i) may be considered as having disposed of the loaned common units, (ii) may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and (iii) may recognize gain or loss from such disposition.

Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.


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The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time.

From time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded limited partnerships, including as a result of any fundamental tax reform. Any modification to the U.S. federal income tax laws and interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes or increase the amount of taxes payable by unitholders in publicly traded partnerships. Any reductions to the U.S. federal income tax rates applicable to individuals and corporations could cause the rate of return on investments in our common units to be relatively less attractive as compared to investments in shares of corporations, which in turn could adversely affect our unit price and increase our cost of capital. In addition, as to possible additional legislation, including any fundamental tax reform, we cannot predict whether any proposals will be introduced, reintroduced or ultimately enacted. Any such changes could affect us and negatively impact the value of an investment in our units.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between existing unitholders and unitholders who purchase our units based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.

Pursuant to the Bipartisan Budget Act of 2015, if the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. We will generally have the ability to shift any such tax liability to our general partner and our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so (or choose to do so) under all circumstances. If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders might be reduced.

Risks Relating to Ownership of our Common Units

Our general partner and its affiliates, including MPC, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders. Additionally, we have no control over MPC’s business decisions and operations, and MPC is under no obligation to adopt a business strategy that favors us.

MPC owns our general partner and an approximate 23.5 percent limited partner interest (including the Class B units on an as-converted basis) in us as of February 13, 2017. Although our general partner has a duty to manage us in a manner that is not adverse to the best interests of our partnership and our unitholders, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is not adverse to the best interests of its owner, MPC.


57


Conflicts of interest may arise between MPC and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, the general partner may favor its own interests and the interests of its affiliates, including MPC, over the interests of our common unitholders, which may occur under our partnership agreement without being independently reviewed by the conflicts committee. These conflicts include, among others, the following situations:

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.

Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will

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not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may reduce the amount of cash available to distribute to our unitholders.

Our general partner has certain incentive distribution rights that reduce the amount of our cash available for distribution to our common unitholders.

Our general partner currently holds a general partner interest in us that entitles it to receive two percent of all distributions paid to our common unitholders and incentive distribution rights that entitle it to receive an increasing percentage (13 percent, 23 percent and 48 percent) of the cash that we distribute to our common unitholders from available cash after the minimum quarterly distribution and certain target distribution levels have been achieved. The maximum distribution right for our general partner to receive 48 percent of any distributions paid to our common unitholders does not include any distributions that our general partner or its affiliates may receive on common or general partner units that they own. Throughout 2016, our general partner was at the top tier of the incentive distribution rights scale. Because a higher percentage of our cash is allocated to our general partner due to these incentive distribution rights, it will be more difficult for us to increase the amount of distributions to our unitholders and our cost of capital will be higher, making investments, capital expenditures and acquisitions, and therefore, future growth, by us more costly. In January 2017, MPC announced that it expects to exchange the general partner's incentive distribution rights for common units in conjunction with the completion of the expected dropdowns of midstream assets. However, there is no assurance that this transaction will occur in 2017, or at all. If such a transaction does occur, it would likely result in a substantial increase in the number of common units outstanding. As a result, our unitholders' proportionate ownership in us will decrease, it may be more difficult for us to maintain or increase our distributions to unitholders and the amount of cash available for distribution for each unit may decrease, the relative voting strength of each previously outstanding unit may be diminished and the market price of our common units may decline.

Our partnership agreement replaces our general partner’s fiduciary duties to holders of our common units with contractual standards governing its duties and restricts the remedies available to unitholders for actions taken by our general partner.

Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing. Our general partner is entitled to consider only the interests and factors that it desires and is relieved of any duty or obligation to give consideration to any interest of, or factors affecting, us, our affiliates or our limited partners.

Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement:

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;

59


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.

In connection with a transaction with an affiliate or a conflict of interest, our partnership agreement provides that any determination by our general partner must be made in good faith, and that our conflicts committee and the board of directors of our general partner are entitled to a presumption that they acted in good faith. In any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. By purchasing a common unit, a unitholder is treated as having consented to the provisions in our partnership agreement, including the provisions discussed above.

Unitholders have very limited voting rights and, even if they are dissatisfied, they have limited ability to remove our general partner without its consent.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner, which are wholly-owned subsidiaries of MPC. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The vote of the holders of at least 66 2/3 percent of all outstanding common units voting together as a single class is required to remove our general partner. As of February 13, 2017, our general partner and its affiliates owned approximately 24.2 percent of the common units (excluding common units held by officers and directors of our general partner and MPC). As a result of these limitations, the price at which our common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20 percent or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

If unitholders are not both citizenship-eligible holders and rate-eligible holders, their common units may be subject to redemption.

In order to avoid (1) any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on assets that are subject to rate regulation by the FERC or analogous regulatory body, and (2) any substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest, we have adopted certain requirements regarding those investors who may own our common units. Citizenship eligible holders are individuals or entities whose nationality, citizenship or other related status does not create a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or authorization, in which we have an interest, and will generally include individuals and entities who are U.S. citizens. Rate eligible holders are individuals or entities subject to U.S. federal income taxation on the income generated by us or entities not subject to U.S. federal income taxation on the income generated by us, so long as all of the entity’s owners are subject to such taxation. If unitholders are not persons who meet the requirements to be citizenship eligible holders and rate eligible holders, they run the risk of having their units redeemed by us at the market price as of the date three days before the date the notice of redemption is mailed. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. In

60


addition, if unitholders are not persons who meet the requirements to be citizenship eligible holders, they will not be entitled to voting rights.

Cost reimbursements, which will be determined in our general partner’s sole discretion, and fees due our general partner and its affiliates for services provided will be substantial and will reduce our cash available for distribution.

Under our partnership agreement, we are required to reimburse our general partner and its affiliates for all costs and expenses that they incur on our behalf for managing and controlling our business and operations. Except to the extent specified under our omnibus agreement or our employee services agreements, our general partner determines the amount of these expenses. Under the terms of the omnibus agreement, we will be required to reimburse MPC for the provision of certain general and administrative services to us. Under the terms of our employee services agreements, we have agreed to reimburse MPC or its affiliates for the provision of certain operational and management services to us in support of our facilities. Our general partner and its affiliates also may provide us other services for which we will be charged fees as determined by our general partner. Payments to our general partner and its affiliates will be substantial and will reduce the amount of cash available for distribution to unitholders.

Our general partner interest, the control of our general partner and the incentive distribution rights of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of MPC to transfer its membership interest in our general partner to a third party. The new partners of our general partner would then be in a position to replace the board of directors and officers of our general partner with their own choices and to control the decisions taken by the board of directors and officers.

Additionally, our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of MPC selling or contributing additional midstream assets to us, as MPC would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

We may issue additional units without unitholder approval, which will dilute limited unitholder interests.

At any time, including in connection with the dropdowns proposed by MPC, we may issue an unlimited number of limited partner interests of any type, including limited partner interests that are convertible into our common units, without the approval of our unitholders and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such limited partner interests. Further, neither our partnership agreement nor our bank revolving credit facility prohibits the issuance of additional preferred units, Class B units, or other equity securities that may effectively rank senior to our common units as to distributions or liquidations. The issuance by us of additional common units, preferred units or other equity securities of equal or senior rank will have the following effects:

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.

MPC may sell units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

As of December 31, 2016, MPC held 86,619,313 common units. Additionally, we have agreed to provide MPC with certain registration rights. The sale of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market that may develop.


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Affiliates of our general partner, including MPC, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Neither our partnership agreement nor our omnibus agreement will prohibit MPC or any other affiliates of our general partner from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, MPC and other affiliates of our general partner may acquire, construct or dispose of additional midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets. As a result, competition from MPC and other affiliates of our general partner could materially and adversely impact our results of operations and cash available for distribution to unitholders.

Our general partner has a limited call right that may require unitholders to sell common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 85 percent of our common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then current market price. As a result, unitholders may be required to sell their common units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of such units.

A unitholder’s liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made non-recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some jurisdictions. A unitholder could be liable for our obligations as if they were a general partner if a court or government agency were to determine that:

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.

Unitholders may have to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

Our general partner, or any transferee holding incentive distribution rights, may elect to cause us to issue common units and general partner units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights, without the approval of our conflicts committee or the holders of our common units. This could result in lower distributions to holders of our common units.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received distributions on its incentive distribution rights at the highest level to which it is entitled (48 percent, in addition to distributions paid on its two percent general partner interest, each as of December 31, 2016) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.


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If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units and general partner units. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. Our general partner will also be issued the number of general partner units necessary to maintain our general partner’s interest in us at the level that existed immediately prior to the reset election. We anticipate that our general partner would exercise this reset right to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of distributions that they would have otherwise received had we not issued new common units and general partner units in connection with resetting the target distribution levels. Additionally, our general partner has the right to transfer all or any portion of our incentive distribution rights at any time, and such transferee shall have the same rights as the general partner relative to resetting target distributions if our general partner concurs that the tests for resetting target distributions have been fulfilled.

The NYSE does not require a publicly traded limited partnership like us to comply with certain of its corporate governance requirements.

We list our common units on the NYSE. Because we are a publicly traded limited partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements.

Item 1B. Unresolved Staff Comments

None


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Item 2. Properties

LOGISTICS AND STORAGE

Crude Oil Pipeline Systems

The following table sets forth certain information regarding our crude oil pipeline systems as of December 31, 2016, each of which has an associated transportation services agreement with MPC (other than the inactive pipelines):
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.

Our crude oil pipeline systems and related assets are strategically positioned to support diverse and flexible crude oil supply options for MPC’s Midwest refineries, which receive imported and domestic crude oil through a variety of sources. Imported and domestic crude oil is transported to supply hubs in Wood River and Patoka, Illinois from a variety of regions, including: Cushing, Oklahoma on the Ozark pipeline system; Western Canada, Wyoming and North Dakota on the Keystone, Platte, Mustang and Enbridge pipeline systems; and the Gulf Coast on the Capline crude oil pipeline system. Our major crude oil pipeline systems are connected to these supply hubs and transport crude oil to refineries owned by MPC and third parties.

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Product Pipeline Systems

The following table sets forth certain information regarding our product pipeline systems as of December 31, 2016, each of which has an associated transportation services agreement with MPC (other than our Louisville airport products system, which currently transports only third-party volumes, and the inactive pipelines):
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.

65


(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.

Our product pipeline systems are strategically positioned to transport products from six of MPC’s refineries to MPC’s marketing operations, as well as those of third parties. These pipeline systems also supply feedstocks to MPC’s Midwest refineries. These product pipeline systems are integrated with MPC’s expansive network of refined product marketing terminals, which support MPC’s integrated midstream business.

Marine Assets

The following table sets forth certain information regarding our marine assets as of December 31, 2016. The marine business currently has an associated transportation service agreement with MPC.
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

Our fleet of boats and barges transport light products, heavy oils, crude oil, renewable fuels, chemicals and feedstocks to and from refineries and terminals owned by MPC in the Midwest and U.S. Gulf Coast regions. The MRF is a full-service marine shipyard located on the Ohio River, adjacent to MPC’s Catlettsburg, Kentucky refinery. The MRF is responsible for the preventive routine and unplanned maintenance of towing vessels, barges and local terminal facilities.

Other L&S Assets

The following table sets forth certain information regarding our other midstream assets as of December 31, 2016, each of which currently has an associated transportation services agreement or storage services agreement with MPC:
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.

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GATHERING AND PROCESSING

The following tables set forth certain information relating to our gas processing facilities, fractionation facilities, natural gas gathering systems, NGL pipelines, natural gas pipeline and crude oil and refined product pipelines as of and for the year ended December 31, 2016. All throughputs and utilizations included are weighted-averages for days in operation.

Gas Processing Complexes
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