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•	the potential merger, consolidation or combination of MPLX with ANDX;

•	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);

•	the regional, national and worldwide availability and pricing of refined products, crude oil, natural gas, NGLs and other feedstocks;

•	consumer demand for refined products;

•	our ability to manage disruptions in credit markets or changes to our credit rating;

•	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;

•	the reliability of processing units and other equipment;

•	expectations regarding joint venture arrangements and other acquisitions, including the dropdowns completed by Marathon Petroleum Corporation (“MPC”), or divestitures of assets;

•	business strategies, growth opportunities and expected investment;

•	the adequacy of our capital resources and liquidity, including but not limited to, availability of sufficient cash flow to execute our business plan and to pay distributions;

•	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;

•	continued or further volatility in and/or degradation of general economic, market, industry or business conditions;

•	compliance with federal and state environmental, economic, health and safety, energy and other policies and regulations;

•	our ability to successfully implement our business plans, growth strategy and self-funding model;

•	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.

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•	volatility or degradation in general economic, market, industry or business conditions;

•	risks and uncertainties associated with intangible assets, including any future goodwill or intangible assets impairment charges;

•	availability and pricing of domestic and foreign supplies of natural gas, NGLs and crude oil and other feedstocks;

•	availability and pricing of domestic and foreign supplies of 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;

•	completion of midstream infrastructure by competitors;

•	midstream and refining industry overcapacity or under capacity;

•	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;

•	the 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 to the expected construction costs and timing of projects and planned investments, and our ability to obtain regulatory and other approvals with respect thereto;

•	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, including pricing adjustments and the expansion and retirement of pipeline capacity, processing, fractionation and treating facilities 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 opportunities, including strategic initiatives and actions;

•	the ability to realize the strategic benefits of joint venture opportunities;

•	accidents or other unscheduled shutdowns affecting our machinery, pipelines, processing, fractionation and treating facilities or equipment, or those of our suppliers or customers;

•	unusual weather conditions and natural disasters;

•	disruptions due to equipment interruption or failure, including electrical shortages and power grid failures;

•	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;

•	state and federal environmental, economic, health and safety, energy and other policies and regulations, including the cost of compliance;

•	adverse changes in laws including with respect to tax and regulatory matters;

•	modifications to earnings and distribution growth objectives;

•	rulings, judgments or settlements and related expenses in litigation or other legal, tax or regulatory matters, including unexpected environmental remediation costs, in excess of any reserves or insurance coverage;

•	the suspension, reduction or termination of MPC’s obligations under MPLX’s commercial agreements;

•	political pressure and influence of environmental groups upon policies and decisions related to the production, gathering, refining, processing, fractionation, transportation and marketing of crude oil or other feedstocks, refined products, natural gas, NGLs or other hydrocarbon-based products;

•	labor and material shortages;

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•	the ability and willingness of parties with whom we have material relationships to perform their obligations to us;

•	capital market conditions, including an increase of the current yield on MPLX LP common units, adversely affecting MPLX LP’s ability to meet its distribution growth guidance;

•	changes in the credit ratings assigned to our debt securities and trade credit, changes in the availability of unsecured credit, changes affecting the credit markets generally and our ability to manage such changes; and

•	the other factors described in Item 1A. Risk Factors.

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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. Pipelines bring advantaged North American crude oil from the upper Great Plains, Louisiana, Texas and Canada to numerous refiners. Terminals provide for the receipt, storage, blending, additization, handling and redelivery of refined petroleum products.

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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, butane and propane caverns, and in tanks within MPC’s refineries. Storage facilities provide flexibility and logistics optionality, which enhances MPC’s ability to maximize returns for refined products.

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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

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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.

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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 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 also have caverns for propane storage in the northeastern United States.

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•	We transport purity ethane produced at the Majorsville Complex, Mobley Complex and Sherwood Complex to the Houston Complex on a FERC pipeline.

•	We deliver purity ethane to Sunoco Logistics Partners L.P.’s (“Sunoco”) Mariner West pipeline (“Mariner West”) from the Harmon Creek Complex, Houston Complex and Bluestone Complex.

•	We deliver purity ethane to Enterprise Products Partners L.P.’s Appalachia-to-Texas Express pipeline from the Houston Complex and the Cadiz Complex.

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Sunoco developed the Mariner East project (“Mariner East”), a pipeline and marine project that originates at our Houston Complex. 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. In May 2016, Mariner East began transporting purity ethane in addition to propane to the Marcus Hook Facility.

•	In December 2018, phase two of Mariner East, a pipeline from our Houston and Hopedale Complexes in western Pennsylvania and eastern Ohio, respectively, began transporting propane and butane to the Marcus Hook Facility where it is loaded onto marine vessels and delivered to domestic and international markets.

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(1)	We do not provide gathering services for these producer customers.

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(1)

Quarterly commitments for our transportation services agreements refer to throughput in thousands of barrels per day and, for crude oil transportation services agreements, are adjusted for crude viscosities. Commitments for our cavern storage services agreements refer to thousands of barrels. Commitments for our terminal services agreements refer to quarterly terminal throughput in thousands of barrels. Commitments for the Fuels Distribution Services Agreement refers to millions of gallons per year. Minimum commitments on some agreements are reduced by any third-party throughput volumes.

(2)	MPC has committed to utilize 100 percent of our available capacity of boats and barges.

(3)	Volume shown represents total tank farm capacity in thousands of barrels (includes Refining Logistics tanks).

(4)

Renewal terms on our agreements include multiple two to five-year terms for transportation services agreements, one additional five-year term for our terminal services agreement, various renewal terms ranging from zero to 10 years for our cavern storage services agreements, various renewal terms ranging from one to five years for our tank farm storage services agreements, two additional five-year terms for our marine transportation services agreement and one additional five-year term for our Fuels Distribution Services Agreement. These renewals are automatic, unless terminated by either party.

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•	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;

•	independent exploration and production companies;

•	interstate and intrastate pipelines; and

•	other marine and land-based transporters of natural gas and NGLs.

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We may have difficulties obtaining additional financing for working capital, capital expenditures, acquisitions, or general business 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.

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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.

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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.

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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.

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•	the fees and tariff rates we charge and the margins we realize for our services and sales;

•	the prices of, level of production of and demand for oil, natural gas, NGLs and refined products;

•	the volumes of natural gas, crude oil, NGLs and refined products we gather, process, store, transport and fractionate;

•	the level of our operating costs including repairs and maintenance;

•	the relative prices of NGLs and crude oil, which impact the effectiveness of our hedging program; and

•	prevailing economic conditions.

•	the amount of our operating expenses and general and administrative expenses, including cost reimbursements to MPC in respect of those expenses;

•	our debt service requirements and other liabilities;

•	fluctuations in our working capital needs;

•	our ability to borrow funds and access capital markets;

•	restrictions in our joint venture agreements, revolving credit facility or other agreements governing our debt;

•	the level and timing of capital expenditures we make, including capital expenditures incurred in connection with our enhancement projects;

•	the cost of acquisitions, if any; and

•	the amount of cash reserves established by our general partner in its discretion.

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•	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

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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.

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•	availability of sufficient railcar, tanker and terminalling facility capacity;

•	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.

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•	inaccurate assumptions about future synergies, revenues, capital expenditures and operating costs;

•	an inability to successfully integrate assets or businesses we acquire;

•	a decrease in our liquidity resulting from using a portion of our available cash or borrowing capacity under our revolving credit agreement to finance transactions;

•	a significant increase in our interest expense or financial leverage if we incur additional debt to finance transactions;

•	the assumption of unknown environmental and other liabilities, losses or costs for which we are not indemnified or for which our indemnity is inadequate;

•	the diversion of management’s attention from other business concerns;

•	the incurrence of other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges; and

•	the loss of customers or key employees from the acquired businesses.

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•	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.

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•	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.

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•	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;

•	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 or refining logistics and fuels distribution agreements;

•	changes to the routing of volumes shipped by MPC on our crude oil and product pipelines or the ability of MPC to utilize third-party pipeline connections to access our pipelines;

•	MPC’s ability to remain in compliance with the terms of its outstanding indebtedness;

•	changes in the cost or availability of third-party pipelines, railways, vessels, 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.

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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;

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•	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;

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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;

•	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;

•	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; and

•	our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

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provides that whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith and will not be subject to any other or different standard imposed by our Partnership Agreement, Delaware law, or any other law, rule or regulation, or at equity;

•	provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith;

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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.

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•	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

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•	the market price of our common units may decline.

•	we were conducting business in a state but had not complied with that particular state’s partnership statute; or

•	a unitholder’s right to act with other unitholders to remove or replace the general partner, to approve some amendments to our Partnership Agreement or to take other actions under our Partnership Agreement constitute “control” of our business.

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(1)	Capacity shown is 100 percent of the capacity of these pipelines and based on physical barrels.

(2)	Includes approximately 16 miles of pipeline leased from a third party.

(3)	A portion of this pipeline system is leased from a third party.

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(1)	Capacity shown is 100 percent of the capacity of these pipelines and based on physical barrels.

(2)	Consists of two separate approximately 8.5 mile pipelines.

(3)	This pipeline is bi-directional.

(4)	Capacity not shown, as the pipeline is designed to meet outgoing capacity for connecting pipelines.

(5)	This pipeline is leased from a third party.

(6)	Capacity not shown for 16 miles on this pipeline due to complexities associated with bi-directional capability.

(7)	We own a 65 percent undivided joint interest in the Louisville, KY to Lexington, KY system.

(8)	This pipeline is leased from a third party.

(9)	Includes 77 miles of pipeline leased from a third party.

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(1)	MPLX also operates one leased terminal and has partial ownership interest in two terminals, with a combined tank shell capacity of 1,068 mbbls.

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(2)	We have a 40.7 percent interest in LOOP, which includes a deep-water oil port and crude oil storage.

(4)	We own and operate 16 tank farms and operate two leased tank farms.

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(1)	Natural gas throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.

(2)	The Sherwood Complex is partially owned by Sherwood Midstream LLC (“Sherwood Midstream”). We account for Sherwood Midstream as an equity method investment. See discussion in Item 8. Financial Statements and Supplementary Data - Note 5.

(3)	The Cadiz and Seneca Complexes are owned by MarkWest Utica EMG, L.L.C. (“MarkWest Utica EMG”). We account for MarkWest Utica EMG as an equity method investment. See discussion in Item 8. Financial Statements and Supplementary Data - Note 5.

(4)	A portion of the gas processed at the Boldman plant, and all of the gas processed at the Kermit plant, is further processed at the Kenova plant to recover additional NGLs.

(5)	The Kermit processing plant is operated by a third party solely to prevent liquids from condensing in the gathering and transmission pipelines upstream of our Kenova plant. We do not receive Kermit gas volume information but do receive all

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(6)	Centrahoma Processing LLC’s processing capacity of 550 MMcf/d and actual throughput of 249 MMcf/d, that exceeded our 40 percent share of the capacity of 220 MMcf/d, are not included in this table as we own a non-operating interest.

(1)	NGL throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.

(2)

Our Houston, Hopedale and Bluestone Complexes have above-ground NGL storage with a usable capacity of 938 thousand barrels, large-scale truck and rail loading. In addition, our Houston Complex has large-scale truck unloading. We also have access to up to an additional 800 thousand barrels of propane storage capacity that can be utilized by our assets in the Marcellus Shale, Utica Shale, and Appalachia region under an agreement with a third party. Lastly, we have up to 240 thousand barrels of propane storage with third parties that can be utilized by our assets in the Marcellus Shale and Utica Shale.

(3)

The Hopedale Complex is jointly owned by MarkWest Ohio Fractionation Company, L.L.C. (“Ohio Fractionation”) and MarkWest Utica EMG. Ohio Fractionation is a joint venture between MarkWest Liberty Midstream & Resources, L.L.C. (“MarkWest Liberty Midstream”) and Sherwood Midstream (a joint venture between MarkWest Liberty and Antero Midstream LLC). MarkWest Liberty Midstream and Sherwood Midstream are entities that operate in the Marcellus region, and MarkWest Utica EMG is an entity that operates in the Utica region. The Marcellus Operations include its portion utilized of the jointly owned Hopedale Fractionation Complex. The Utica Operations includes Utica’s portion utilized of the jointly owned Hopedale Fractionation Complex. Additionally, Sherwood Midstream has the right to fractionation revenue and the obligation to pay expenses related to 20 mbpd of capacity in the Hopedale 3 fractionator.

(4)	The Ohio Condensate Complex has up to 100 thousand barrels of condensate storage. The Ohio Condensate Complex is partially-owned by MarkWest Utica EMG Condensate, L.L.C. We account for Ohio Condensate as an equity method investment. See discussion in Item 8. Financial Statements and Supplementary Data – Note 5.

(5)

Our Siloam Complex has both above-ground, pressurized NGL storage facilities, with usable capacity of 48 thousand barrels, and underground storage facilities, with usable capacity of 238 thousand barrels. Product can be received by truck, pipeline or rail and can be transported from the facility by truck, rail or barge. This facility has large-scale truck and rail loading and unloading capabilities, and a river barge facility capable of loading a 20 thousand barrel barge.

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(1)	NGL throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.

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(1)	Natural gas throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.

(2)	The Ohio Gathering System is owned by Ohio Gathering Company, L.L.C. (“Ohio Gathering”). We account for our investment in Ohio Gathering through MarkWest Utica EMG, which is accounted for as an equity method investment. See discussion in Item 8. Financial Statements and Supplementary Data – Note 5.

(3)	The Jefferson Gas System is owned by MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. (“Jefferson Dry Gas”), which is a joint venture between MarkWest Liberty Midstream and EMG MWE Dry Gas Holdings, LLC. We account for Jefferson Dry Gas as an equity method investment. See discussion in Item 8. Financial Statements and Supplementary Data – Note 5.

(4)	Excludes lateral pipelines where revenue is not based on throughput.

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(1)	This is a section of the Mariner West pipeline which is FERC-regulated and is leased to, and operated by, Sunoco.

(2)	The Utica Shale pipelines are owned by MarkWest Utica EMG. We account for MarkWest Utica EMG as an equity method investment. See discussion in Item 8. Financial Statements and Supplementary Data - Note 5

(3)	This pipeline from Seneca to Cadiz can only be used for either propane and heavier liquids or ethane and heavier liquids at one time. Both throughput capacities are listed above, respectively, with ethane included in the total.

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(4)	NGLs transported through the Langley to Ranger and Ranger to Kenova pipelines are combined with NGLs recovered at the Kenova Complex. The design capacity and volume reported for the Langley to Siloam pipeline represent the combined NGL stream.

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•	less the amount of cash reserves established by our general partner to:

•	provide for the proper conduct of our business (including reserves for our future capital expenditures and for anticipated future credit needs);

•	comply with applicable law, any of our debt instruments or other agreements or obligations; or

•	provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all common units for the current quarter);

•	plus, if our general partner so determines, all or any portion of the cash on hand resulting from working capital borrowings made subsequent to the end of such quarter.

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

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

(3)	The 2015 Adjusted EBITDA attributable to MPLX LP includes pre-merger EBITDA from MarkWest and the 2015 DCF includes undistributed DCF from MarkWest.

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

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(1)	Represents the average aggregate daily number of barrels of crude oil transported on our pipelines and at our Wood River barge dock for MPC and for third parties. Volumes shown are 100 percent of the volumes transported on the pipelines and barge dock.

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

(3)

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

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

(5)	Throughput reported for 2016 represents average volumes for the nine months beginning April 1, 2016.

(6)	Represents total at the end of the period.

(7)	G&P volumes reported for 2015 represent the average volumes after the close of the MarkWest Merger.

(8)	This table represents operating data for entities that have been consolidated into the MPLX financial statements.

(9)	This table represents operating data for entities that have been consolidated into the MPLX financial statements as well as operating data for MPLX-operated equity method investments.

(10)

Hopedale is jointly owned by Ohio Fractionation and MarkWest Utica EMG. Ohio Fractionation is a subsidiary of MarkWest Liberty Midstream. MarkWest Liberty Midstream and MarkWest Utica EMG are entities that operate in the Marcellus and Utica regions, respectively. The Marcellus Operations includes its portion utilized of the jointly owned Hopedale Fractionation Complex. The Utica Operations includes Utica’s portion utilized of the jointly owned Hopedale Fractionation Complex. Additionally, Sherwood Midstream has the right to fractionation revenue and the obligation to pay expenses related to 20 mbpd of capacity in the Hopedale 3 fractionator.

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

(12)	Purity ethane makes up approximately 171 mbpd, 141 mbpd, 114 mbpd and 83 mbpd of MPLX LP consolidated total fractionated products for the years ended December 31, 2018, 2017, 2016 and 2015, respectively. Purity ethane makes

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

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L&S Segment Adjusted EBITDA attributable to MPLX LP increased approximately $1,282 million, or 165 percent, in 2018 compared to 2017. This increase was primarily due to $944 million of Segment Adjusted EBITDA generated by Refining Logistics and Fuels Distribution following the February 1, 2018 acquisition; an additional $159 million of Segment Adjusted EBITDA due to increased distributions and other adjustments from equity method investments including the joint venture with Enbridge Energy Partners L.P. (“MarEn Bakken”) and the Joint-Interest Acquisition; as well as increased transportation revenues due to higher rates and volumes of crude and refined products shipped.

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G&P Segment Adjusted EBITDA attributable to MPLX LP increased approximately $189 million, or 15 percent, in 2018 compared to 2017. This increase was primarily due to $140 million of Segment Adjusted EBITDA from increased gathered, processed and fractionated volumes, which drove higher utilization rates and higher fee-based revenue in the Marcellus and Southwest. These increases are a result of expansions at the Houston, Majorsville, Harmon Creek and Argo facilities. Increased prices in the Marcellus, Northeast and Southwest also resulted in higher Segment Adjusted EBITDA of approximately $45 million. Further, there was an increase in distributions from unconsolidated affiliates of $57 million and an increase in derivative gains of $12 million which was offset by increased facility and operating expenses as well as employee related costs of $65 million. Compared to full-year 2017, gathering volumes were up 26 percent, processing volumes were up nine percent and fractionated volumes were up 16 percent.

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On October 17, 2018, MPLX announced it is jointly developing with Crimson Midstream LLC (“Crimson”) a multi-diameter pipeline to provide connectivity from St. James and Raceland, Louisiana to the Louisiana Offshore Oil Port LLC terminal in Clovelly, Louisiana. The proposed pipeline would have the ability to transport up to 600 mbpd of crude oil and has an expected in-service date in the first half of 2020.

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On September 26, 2018, MPLX acquired the Mt. Airy Terminal with 4 million barrels of third-party leased storage capacity and a 120 mbpd dock from Pin Oak Holdings, LLC for $451 million. The facility has the capability to significantly expand its storage capacity to 10 million barrels and is permitted for construction of a second 120 mbpd dock. The facility is strategically located on the Mississippi River between New Orleans and Baton Rouge and is near several Gulf Coast refineries, including MPC’s Garyville refinery. The Mt. Airy Terminal can handle multiple refined products, as well as residual fuel and bunker products, to provide optionality and flexibility of feedstocks and finished products in a single location. The Mt. Airy Terminal also has significant growth opportunities as a result of multiple pipelines and rail lines crossing the property in addition to being positioned as an aggregation point for liquids growth for both ocean-going vessels and inland barges.

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On September 4, 2018, MPLX announced it is jointly developing with Energy Transfer Partners, L.P. (“Energy Transfer”), Magellan Midstream Partners, L.P. (“Magellan”) and Delek US Holdings, Inc. a new 30-inch diameter common carrier pipeline to transport crude oil from the Permian Basin to the Texas Gulf Coast region. The 600-mile pipeline system is expected to be operational in mid-2020 with multiple Texas origins and would have the strategic capability to transport crude oil to both Energy Transfer’s Nederland, Texas terminal and Magellan’s East Houston, Texas terminal. The ability to increase the diameter and capacity of the pipeline exists if additional commitments are received.

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On July 26, 2018, MPLX announced a number of steps it has taken to further expand its presence in the Permian Basin. These activities include development of a 200 MMcf/d gas processing plant in Loving County Texas, called the Torñado plant, as well as natural gas gathering infrastructure primarily in Lea County, New Mexico. These expansion activities are expected to be complete in the third quarter of 2019. MPLX also acquired a 10 percent equity interest in the Agua Blanca pipeline which is a 1,400 MMcf/d pipeline (which has the ability to be expanded to 2,000 MMcf/d) originating in Orla, Texas and ending in Waha, Texas. Agua Blanca is also constructing a lateral to connect our MarkWest Argo Plant, which commenced operations in early 2018.

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On November 15, 2018, MPLX issued $2.25 billion aggregate principal amount of senior notes in a public offering, consisting of $750 million aggregate principal amount of 4.8 percent unsecured senior notes due February 2029 and $1.5 billion aggregate principal amount of 5.5 percent unsecured senior notes due February 2049. The notes were offered at a price to the public of 99.432 percent and 98.031 percent of par, respectively. The proceeds were used to repay outstanding borrowings under the MPLX Credit Agreement and the MPC Loan Agreement, to redeem $750 million aggregate principal amount of 5.5 percent senior notes due February 2023, as well as for general business purposes.

•	On September 25, 2018, MPLX drew $1 billion under the MPLX Credit Agreement. The proceeds were used to fund the acquisition of the Mt. Airy Terminal, to pay down the MPC Loan Agreement and for general business purposes.

•	On April 27, 2018, MPLX and MPC Investment entered into an amendment to the MPC Loan Agreement to increase the borrowing capacity under the MPC Loan Agreement from $500 million to $1 billion.

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On February 8, 2018, MPLX issued $5.5 billion aggregate principal amount of senior notes in a public offering, consisting of $500 million aggregate principal amount of 3.375 percent unsecured senior notes due March 2023, $1.25 billion aggregate principal amount of 4.0 percent unsecured senior notes due March 2028, $1.75 billion aggregate principal amount of 4.5 percent unsecured senior notes due April 2038, $1.5 billion aggregate principal amount of 4.7 percent unsecured senior notes due April 2048, and $500 million aggregate principal amount of 4.9 percent unsecured senior notes due April 2058. The notes were offered at a price to the public of 99.931 percent, 99.551 percent, 98.811 percent, 99.348 percent, and 99.289 percent of par, respectively. The net proceeds were used to repay the $4.1 billion 364-day term loan facility (as described below), the outstanding borrowings under the MPLX Credit Agreement and the MPC Loan Agreement, as well as for general business purposes.

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On February 1, 2018, immediately following the completion of the dropdown acquisitions mentioned above, our general partner’s IDRs were eliminated and its two percent economic general partner interest in MPLX LP was converted into a non-economic general partner interest, all in exchange for 275 million newly issued MPLX LP common units. This exchange eliminated the general partner cash distribution requirements of MPLX.

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•	On February 1, 2018, in connection with the dropdown acquisition, MPLX drew $4.1 billion on a 364-day term loan facility with a syndicate of lenders, which was entered into on January 2, 2018. The proceeds of the term loan facility were used to fund the cash portion of the dropdown consideration for Refining Logistics and Fuels Distribution.

•	We did not make any issuances under our ATM Program during the year ended December 31, 2018.

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(1)	Includes an impairment expense of $89 million related to one of MPLX’s equity method investments for the year ended December 31, 2016.

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

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(2)

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

(3)	The Adjusted EBITDA and DCF adjustments related to Predecessor are excluded from Adjusted EBITDA attributable to MPLX LP and DCF prior to the acquisition dates.

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(1)

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

(2)	The Adjusted EBITDA and DCF adjustments related to Predecessor are excluded from Adjusted EBITDA attributable to MPLX LP and DCF prior to the acquisition dates.

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(1)	See the Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net income table for the reconciliation to the most directly comparable GAAP measure.

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(1)

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

(2)	See the Reconciliation of Adjusted EBITDA attributable to MPLX LP and DCF attributable to GP and LP unitholders from Net income table for the reconciliation to the most directly comparable GAAP measure.

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(1)	Includes percent-of-proceeds, keep-whole and other types of arrangements tied to NGL, condensate and natural gas prices.

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(1)

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

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(1)	Outstanding borrowings include $3 million in letters of credit outstanding under this facility.

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(1)	Amounts represent outstanding borrowings at December 31, 2018, plus any commitment and administrative fees and interest.

(2)	Amounts relate primarily to leases associated with Refining Logistics as well as to our office, railcar, and vehicle leases.

(3)

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

(4)

Natural gas purchase obligations consist primarily of a purchase agreement with a producer in our Southern Appalachia Operations. The contract provides for the purchase of keep-whole volumes at a specific price and is a component of a broader regional arrangement. The contract price is designed to share a portion of the frac spread with the producer and as a result, the amounts reflected for the obligation exceed the cost of purchasing the keep-whole volumes at a market price. The contract is considered an embedded derivative (see Item 8. Financial Statements and Supplementary Data – Note 17 for the fair value of the frac spread sharing component). We use the estimated future frac spreads as of December 31, 2018 for calculating this obligation. The counterparty to the contract has the option to renew the gas purchase agreement and the related keep-whole processing agreement for two successive five-year terms after 2022, which is not included in the natural gas purchase obligations line item.

(5)	Represents amounts due under a product supply agreement (see Item 8. Financial Statements and Supplementary Data – Note 25 for further discussion of the product supply agreement).

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

(7)	Excludes estimated accretion expense of $31 million. The total amount to be paid is approximately $61 million.

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

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•	Level 1 - Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

•	Level 2 - Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the measurement date.

•	Level 3 - Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

•	assessment of impairment of long-lived assets;

•	assessment of impairment of intangible assets:

•	assessment of impairment of goodwill;

•	assessment of impairment of equity method investments;

•	recorded values for assets acquired and liabilities assumed in connection with acquisitions; and

•	recorded values of derivative instruments.

•

Future Net operating margins. Our estimates of future Net operating margins are based on our analysis of various supply and demand factors, which include, among other things, industry-wide capacity, our planned utilization rate, end-user demand, capital expenditures and economic conditions as well as commodity prices. Such estimates are consistent with those used in our planning and capital investment reviews.

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Future volumes. Our estimates of future throughput of crude oil, natural gas, NGL and refined product volumes are based on internal forecasts. These throughput assumptions depend, in part, on expected commodity prices. Assumptions about our customers’ drilling activity and future commodity prices are inherently subjective and contingent upon a number of variable factors, many of which are difficult to forecast. Management considers the sustained reduction of commodity prices in forecasted cash flows.

•	Discount rate commensurate with the risks involved. We apply a discount rate to our cash flows based on a variety of factors, including market and economic conditions, operational risk, regulatory risk and political risk. This discount rate is also compared to recent observable market transactions, if possible. A higher discount rate decreases the net present value of cash flows.

•	Future capital requirements. These are based on authorized spending and internal forecasts.

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•	Probability of Renewal. As of December 31, 2018, we believe there is a 90 percent and 80 percent probability that the customer will exercise its first and second term extending options, respectively. The customer must exercise the first term extending option in order for the second term extending option to become available.

•	Commodity Prices. Third-party forward price curves are not available after 2020, which requires us to extrapolate NGL and natural gas prices.

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

(2)	Assumes a 100-basis-point decrease in the weighted average yield-to-maturity at December 31, 2018.

(3)	Assumes a 100-basis-point change in interest rates. The change to net income was based on the weighted average balance of all outstanding variable-rate debt for the year ended December 31, 2018.

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

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Percent-of-proceeds arrangements – Under percent-of-proceeds arrangements, MPLX: gathers and processes natural gas on behalf of producers; sells the resulting residue gas, condensate and NGLs at market prices; and remits to producers an agreed-upon percentage of the proceeds. In other cases, instead of remitting cash payments to the producer, MPLX delivers an agreed-upon percentage of the residue gas and NGLs to the producer (take-in-kind arrangements) and sells the volumes MPLX retains to third parties. Revenue is recognized on a net basis when MPLX acts as an agent and does not have control of the gross amount of gas and/or NGLs prior to it being sold. Percent-of-proceeds revenue is reported as “Service revenue - product related” on the Consolidated Statements of Income.

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Keep-whole arrangements – Under keep-whole arrangements, MPLX gathers natural gas from the producer, processes the natural gas and sells the resulting condensate and NGLs to third parties at market prices. Because the extraction of the condensate and NGLs from the natural gas during processing reduces the Btu content of the natural gas, MPLX must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the value of the energy content of this natural gas. Certain keep-whole arrangements also have provisions that require MPLX 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. “Service revenue - product related” is recorded based on the value of the NGLs received on the date the services are performed. Natural gas purchased to return to the producer and shared NGL profits are recorded as a reduction of “Service revenue - product related” on the Consolidated Statements of Income on the date the services are performed. 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 MPLX is the principal in the arrangement and controls the product prior to sale. The sale of the NGLs may occur shortly after services are performed at the tailgate of the plant, or after a period of time as determined by MPLX.

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Purchase arrangements – Under purchase arrangements, MPLX purchases natural gas at either the wellhead or the tailgate of a plant. MPLX then gathers and delivers the natural gas to pipelines where MPLX may resell the natural gas. Wellhead purchase arrangements represent an arrangement with a supplier and are recorded in “Purchased product costs.” Often, MPLX earns fees for services performed prior to taking control of the product in these arrangements and “Service revenue” is recorded for these fees. Revenue generated from the sale of product obtained in tailgate purchase arrangements is reported as “Product sales” on the Consolidated Statements of Income and is recognized on a gross basis as MPLX purchases and takes control of the product prior to sale and is the principal in the transaction.

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(1)	“Income/(loss) from equity method investments” includes the impact of any basis differential amortization or accretion.

(2)	Includes an impairment charge of $89 million for the year ended December 31, 2016 related to MPLX’s investment in Ohio Condensate Company, L.L.C., which does not appear separately in this table.

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(1)	MarkWest Utica EMG, L.L.C (“MarkWest Utica EMG”), noncurrent assets include its investment in its subsidiary Ohio Gathering Company, L.L.C. (“Ohio Gathering”), which does not appear elsewhere in this table. The investment was $750 million and $790 million as of December 31, 2018 and 2017, respectively.

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

•	MarkWest Utica EMG, in which MPLX LP has a 56 percent interest as of December 31, 2018. MarkWest Utica EMG is engaged in natural gas processing and NGL fractionation, transportation and marketing in Ohio.

•	Ohio Gathering, in which MPLX LP has a 34 percent indirect interest as of December 31, 2018. Ohio Gathering is a subsidiary of MarkWest Utica EMG providing natural gas gathering service in the Utica Shale region of eastern Ohio.

•	Sherwood Midstream, in which MPLX LP has a 50 percent interest as of December 31, 2018. Sherwood Midstream supports the development of Antero Resources’ Marcellus Shale acreage in the rich-gas corridor of West Virginia.

•	Sherwood Midstream Holdings, in which MPLX LP has an 80 percent total direct and indirect interest as of December 31, 2018. Sherwood Midstream Holdings owns certain infrastructure at the Sherwood Complex that is shared by and supports the operation of both the Sherwood Midstream and MPLX gas processing plants and de-ethanization facilities.

•	MarkWest EMG Jefferson Dry Gas Gathering Company, L.L.C. (“Jefferson Dry Gas”), in which MPLX LP has a 67 percent interest as of December 31, 2018. Jefferson Dry Gas provides natural dry gas gathering and related services in the Utica Shale region of Ohio.

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Fuels distribution services agreement – Fuels Distribution is a party to a services agreement with MPC in connection with the dropdown of the fuels distribution services. Under this agreement, Fuels Distribution provides services related to the scheduling and marketing of certain petroleum products to MPC. Fuels Distribution does not provide the same services to third parties without the prior written consent of MPC. This agreement has an initial term of 10 years, subject to a five-year renewal period under terms to be renegotiated at that time.

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Transportation services agreements – MPLX has various separate transportation services agreements with terms ranging from five to 15 years, under which MPC pays MPLX fees for transporting crude oil and refined products on various of MPLX’s crude oil and refined product pipelines. MPLX also has a five-year agreement under which MPC pays MPLX fees for handling crude oil and products at MPLX’s Wood River, Illinois barge dock, and a six-year transportation services agreement under which MPC pays MPLX fees for providing marine transportation of crude oil, feedstocks and refined petroleum products, and related services.

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Storage services agreements – MPLX has three storage services agreements, with 10-year, 10-year, and 17-year terms, under which MPC pays MPLX fees for providing storage services at MPLX’s Neal, West Virginia butane cavern; Robinson, Illinois butane cavern; and Woodhaven, Michigan butane and propane caverns, respectively. MPLX has various separate three-year storage services agreements under which MPC pays MPLX fees for providing storage services at MPLX’s tank farms, and various separate three-year storage services agreements under which MPC pays MPLX fees for providing storage services at MPLX’s storage tanks associated with MPLX’s crude oil and refined product pipelines. MPLX also has various separate storage services agreements with each of MPC’s refineries under which MPLX provides certain services exclusively to MPC related to the receipt, storage, throughput, custody and delivery of petroleum products in and through certain storage and logistical facilities and assets associated with MPC’s refineries. These agreements have initial terms of 10 years.

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•	Terminal services agreement – MPLX has a 10-year terminal services agreement under which MPC pays MPLX fees for terminal storage for refined petroleum products.

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(1)	There were additional product sales to MPC that net to zero within the consolidated financial statements as the transactions are recorded net due to the terms of the agreements under which such product was sold. For 2018, 2017, and 2016, these sales totaled $440 million, $254 million and $46 million, respectively.

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(1)	Balance includes $386 million related to the MPC Loan Agreement as of December 31, 2017. There was no outstanding balance on the MPC Loan Agreement as of December 31, 2018.

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(1)	See Note 8 for distribution information.

(2)	Distributions declared on January 25, 2018 on general partner common units issued on February 1, 2018 in exchange for the economic general partner interest, including IDRs, are shown as general partner distributions declared.

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

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(1)	Changes to the number of general partner units outstanding, other than changes due to contributions made to MPC for the acquisitions of HSM, HST, WHC, MPLXT, the Joint-Interest Acquisition and Refining Logistics and Fuels Distribution, are the result of cash contributions made by the general partner in order to maintain its two percent GP Interest.

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(1)	Includes distributions of fourth quarter 2017 income declared on general partner common units issued February 1, 2018 in exchange for the economic general partner interest.

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•	L&S – transports, stores, distributes and markets crude oil and refined petroleum products.

•	G&P – gathers, processes and transports natural gas; gathers, transports, fractionates, stores and markets NGLs.

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(2)	See below for the reconciliation from Segment Adjusted EBITDA to “Net income.”

(3)	Includes an impairment expense of $89 million related to one of MPLX’s equity method investments for the year ended December 31, 2016.

(1)	Equity method investments included in L&S assets were $1.12 billion at December 31, 2018 and $1.15 billion at December 31, 2017. Equity method investments included in G&P assets were $3.05 billion at December 31, 2018 and $2.86 billion at December 31, 2017.

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(1)	Depreciation and amortization attributable to L&S was $240 million, $163 million and $128 million for the years ended 2018, 2017 and 2016, respectively. Depreciation and amortization attributable to G&P was $526 million, $520 million and $463 million for 2018, 2017 and 2016, respectively.

(2)	Includes an impairment expense of $89 million related to one of MPLX’s equity method investments for the year ended December 31, 2016.

(3)

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

(4)	The Adjusted EBITDA adjustments related to Predecessor are excluded from Adjusted EBITDA attributable to MPLX LP prior to the acquisition date.

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

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(1)	Amortization expense attributable to the G&P segment for the years ended December 31, 2018 and 2017 was $38 million in both years.

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(1)	Gains and losses on commodity derivatives classified as Level 3 are recorded in “Product sales” on the Consolidated Statements of Income. Gains and losses on derivatives embedded in commodity contracts are recorded in “Purchased product costs” and “Cost of revenues” on the Consolidated Statements of Income.

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

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•	Third-party reimbursements – Third-party reimbursements, such as electricity costs, are presented gross on the income statement rather than net within cost of revenues. The gross-up for third-party reimbursements (e.g., increase in “Service revenue”; increase in “Cost of revenues”) was $369 million for the year ended December 31, 2018.

•

Noncash consideration – Under certain processing agreements, MPLX is entitled to retain NGLs or other liquids from the customer. We obtain control of these NGLs and are able to direct the use of the goods. Service revenues are recorded based on the value of the NGLs received on the date the services are performed. Historically, revenue was not recorded on these arrangements until the product was sold. The impact to this change was an increase of $52 million to “Service revenue - product related” for the year ended December 31, 2018. NGL inventory related to keep-whole volumes was also revalued as a result of this change, with a cumulative effect adjustment of $1 million and an increase to inventory of $2 million as of December 31, 2018. The increase in the inventory basis increased “Purchased product costs” by $50 million for the year ended December 31, 2018.

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Percent-of-proceeds revenues – MPLX’s percentage of proceeds revenue received was historically recorded in product revenues. Upon adoption of ASC 606, these revenues have been classified in service revenue, as the performance obligation related to these contracts is to provide gathering and processing services. Revenues will continue to be recorded net under these arrangements as MPLX does not control the product prior to sale. For the year ended December 31, 2018, $146 million was recorded in “Service revenue - product related” as opposed to “Product sales.”

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Imbalances – Historically, all imbalances were recorded net. In certain instances, MPLX’s arrangements are structured such that imbalances are cashed-out each period end which results in the transfer of control of a commodity and creates a purchase and/or sale of a commodity under ASC 606. Thus, certain imbalances will be grossed up as a result of adoption. The impact of this change was an increase of $55 million to “Product sales” and “Purchased product costs” for the year ended December 31, 2018.

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Aid in construction – Historically, all aid in construction amounts received were deferred and recognized into revenue. Payments received from non-customers will no longer be deferred as the accounting will not be subject to ASC 606. Such payments will be recorded as a reduction to “Property, plant and equipment, net.” The cumulative adjustment wrote down $3 million of “Property, plant and equipment, net.”

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Oil Allowances – Historically, oil allowances were recorded when received as consideration for services performed. Under ASC 606, MPLX does not believe such amounts represent consideration from a customer. Any excess product obtained and sold as a result of these allowances is recorded as product sales. This change decreased “Service revenues” and “Service revenues - related party” by $7 million, and increased “Product sales” and “Product sales related party” by $7 million for the year ended December 31, 2018.

(1)	G&P “Product sales” for the year ended December 31, 2018 excludes approximately $5 million of impact related to derivative gains and mark-to-market adjustments.

(2)	Excludes “Purchased product costs,” “Rental cost of sales,” “Purchases,” “Depreciation and amortization,” “General and administrative expenses,” and “Other taxes.”

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(1)	G&P “Product sales” for the year ended December 31, 2018 excludes approximately $5 million of impact related to derivative gains and mark-to-market adjustments.

(2)	Non-ASC 606 Revenue includes rental income, income from equity method investments, derivative gains and losses, mark-to-market adjustments, and other income.

(1)	Balance represents ASC 606 portion of each respective line item.

(2)	$1 million revenue was recognized related to past performance obligations in the current year.

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(1)	All fixed consideration from contracts with customers is included in the amounts presented above. Variable consideration that is constrained or not required to be estimated as it reflects our efforts to perform is excluded.

(2)	Arrangements deemed implicit leases are included in “Rental income” and are excluded from this table.

(3)	Only minimum volume commitments that are deemed fixed are included in the table above. MPLX has various minimum volume commitments in processing arrangements that vary based on the actual Btu content of the gas received. These amounts are deemed variable consideration and are excluded from the table above.

(2)	As a result of the adoption of ASU 2016-18, Statement of Cash Flows - Restricted Cash, the Consolidated Statements of Cash Flows now explain the change during the period of both “Cash and cash equivalents” and “Restricted cash.”

(1)	Contribution of assets to Sherwood Midstream and Sherwood Midstream Holdings. See Note 5.

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(2)

For 2016, includes limited partner units issued to MPC as consideration in the acquisition of HSM. For 2017, includes limited and general partner units issued to MPC as consideration in the acquisitions of the joint-interests, HST, WHC and MPLXT. For 2018, includes limited and general partner units issued to MPC as consideration in the acquisition of Refining Logistics and Fuels Distribution. See Note 4.

(1)	These components of “Accumulated other comprehensive loss” are included in the computation of net periodic benefit cost by LOOP and Explorer and are therefore included on the Consolidated Statements of Income under the caption “Income/(loss) from equity method investments.”

(2)	Components of other comprehensive loss - remeasurements relate to actuarial gains and losses as well as amortization of prior service costs. MPLX records an adjustment to “Comprehensive income” in accordance with its ownership interest in LOOP and Explorer.

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(1)	Represents a subset of phantom units held by our non-employee directors and certain of our officers and non-officer employees that are generally non-forfeitable and that would be paid out as common units upon the holder’s separation from service.

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(a)	Corporate officer

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(a)	As noted above in “Compensation Decisions and Allocation,” certain elements of Mr. Swearingen’s compensation, including his base salary, were allocated to us 75% for 2018 and are reflected as such in this table and in the “Salary” column of the “2018 Summary Compensation Table” below.

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(a)	Measures MPC’s operating income per barrel of crude oil throughput, adjusted for unusual business items and accounting changes, compared to a group of peer companies, which for 2018 were: BP p.l.c.; Chevron Corporation; ExxonMobil Corporation; HollyFrontier Corporation; PBF Energy; Phillips 66; and Valero Energy Corporation.

(b)	Costs generally not subject to change based on production volume, purchases of commodities, sales, throughputs or changes in commodity prices. These costs are adjusted to exclude costs related to acquisitions and divestitures, capital projects in excess of $500 million, and employee bonus accruals.

(c)	Represents the cash flow available to be paid to our common unitholders, as disclosed in our consolidated financial statements.

(d)

Derived from MPC's consolidated financial statements and adjusted for certain items. This non-GAAP performance metric is calculated as earnings before interest and financing costs, interest income, income taxes, depreciation and amortization expense adjusted to exclude the effects of impairment expenses, pension settlement gains/losses, inventory market valuation adjustments, certain non-cash charges and credits and the effects of acquisitions and divestitures.

(e)	Measures the mechanical availability of the processing equipment in MPC's refineries and the critical equipment in MPC's midstream assets.

(f)	Measures MPC's success and commitment to employee safety. Goals are set annually at best-in-class industry performance, focusing on continual improvement and include common industry metrics.

(g)	Measures MPC's ability to identify, understand and control certain process hazards.

(h)	Measures certain internal environmental performance metrics.

(i)	Shown in absolute dollars. Measures the impact of product quality incidents and cumulative costs to MPC.

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•	Reported record full-year net income of $1.8 billion, an increase of $1.0 billion compared to 2017;

•	Executed on our strategic vision by significantly growing our business, enhancing the stability of our cash flow profile, and simplifying our financial structure; and

•	Returned nearly $2.1 billion to our unitholders.

(a)	As noted above in “Compensation Decisions and Allocation,” certain elements of Mr. Swearingen’s compensation, including his 2018 bonus payment, were allocated to us 75% for 2018 and are reflected as such in this table and in the “Non-Equity Incentive Plan Compensation” column of the “2018 Summary Compensation Table” below.

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(a)	Payout for performance between quartiles will be determined using linear interpolation.

(b)	Increased to the 30th percentile for awards granted in 2018 and thereafter.

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(a)	Payout will be based on achievement of DCF in each year of the performance cycle as compared with the threshold, target and maximum levels. Payout for performance between these levels will be determined using linear interpolation.

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(a)	Payout for performance between quartiles will be determined using linear interpolation.

(b)	Increased to the 30th percentile for awards granted in 2018 and thereafter.

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•	providing and preserving an economic motivation for participating executives to consider a business combination that might result in an executive’s job loss, and

•	competing effectively in attracting and retaining executives in an industry that features frequent mergers, acquisitions and divestitures.

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(a)

With respect to Mr. Heminger, amounts reflect the annualized fixed fee we pay MPC for Mr. Heminger’s services under the Omnibus Agreement. With respect to Mr. Swearingen, amounts reflect the portion of his compensation that was allocated to us for 2018 (75%). With respect to the other NEOs, amounts reflect actual salary earned during the fiscal year covered. Compensation is reviewed after the end of each year, and salary increases, if any, are generally effective April 1 of the following year. See “Executive Compensation Discussion and Analysis—Elements of Compensation—Base Salary” for additional information on base salaries for 2018.

(b)	The amount shown for Mr. Hennigan reflects a cash sign-on bonus.

(c)

The amounts shown in these columns reflect the aggregate grant date fair value of LTI awarded in the applicable year calculated in accordance with Financial Accounting Standards Board Accounting Standards Codification 718, Compensation-Stock Compensation (“FASB ASC Topic 718”). See Item 8. Financial Statements and Supplementary Data, Note 22 for assumptions used in the calculation of the amounts related to MPLX equity for the year ended December 31, 2018 and Note 23 to MPC’s financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2018 for valuation assumptions used to determine the value of these awards.

(d)	The maximum value of the performance units granted in 2018, assuming the highest level of performance is achieved, is: Mr. Heminger, MPLX - $2,700,000; Ms. Beall, MPLX - $500,000 and MPC - $500,000; Mr. Hennigan, MPLX - $1,750,000 and MPC - $1,750,000; Mr. Floerke, MPLX - $500,000 and MPC - $500,000; and Mr. Swearingen, MPLX - $500,000 and MPC - $500,000.

(e)	For Mr. Swearingen, reflects 75% of the total value of his ACB award. For the other NEOs, reflects the total value of ACB awards earned for the year indicated. ACB awards are generally paid in the year following the year in which they are earned.

(f)

The amounts shown in this column reflect the annual change in actuarial present value of accumulated benefits under the MPC retirement plans. See “Post-Employment Benefits for 2018” in this Item 11 for more information regarding the defined benefit plans and the assumptions used in the calculation of these amounts. There are no deferred compensation earnings reported in this column as the nonqualified deferred compensation plans do not provide above-market or preferential earnings.

(g)	MPC offers limited perquisites to our NEOs which, together with contributions to defined contribution plans, comprise the amounts reported in this column. See “Executive Compensation Discussion and Analysis—Other Benefits—Perquisites” for a description of each of these items.

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(h)

The amounts shown in this column reflect MPC’s aggregate incremental cost of personal use of corporate aircraft by our NEOs, their spouses or other guests for 2018, estimated using the average costs of operating the aircraft, such as fuel costs, trip-related maintenance, crew travel expenses, trip-related fees, storage costs, communications charges and other miscellaneous variable costs. Fixed costs, such as pilot compensation, the purchase and lease of aircraft and maintenance not related to travel are excluded from this calculation. We believe this method provides a reasonable estimate of MPC’s incremental cost; however, it overstates the actual incremental cost when a flight has a primary business purpose, space is available to transport an officer or his or her guest not traveling for business purposes and no incremental cost is realized by MPC. No income tax assistance or gross-ups are provided for personal use of corporate aircraft.

(i)	The amounts shown in this column reflect MPC’s contributions under our tax-qualified retirement plans and related nonqualified deferred compensation plans. For Mr. Swearingen, these amounts reflect the portion of his compensation that was allocated to us for 2018 (75%). See “Post-Employment Benefits for 2018” for more information.

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(a)	The approval date for MPLX phantom unit and performance unit awards was February 28, 2018. The approval date for MPC stock options, restricted stock and performance unit awards was February 27, 2018. The approval date for Mr. Heminger’s 12/20/2018 award was December 20, 2018.

(b)	Target amounts reflect the target annual incentive opportunity. No threshold amount is disclosed as MPC’s Compensation Committee has discretion to award no annual incentive under the ACB program. Each NEO may generally earn a maximum of 200% of the target.

(c)

Target amounts reflect the number of performance units granted. Each performance unit has a target value of $1.00. The threshold for the award is the minimum possible payout of the award, which is 12.5%. The threshold is achieved when the payout percentage is 50% for one measurement period and 0% for the other three measurement periods, thus an average payout percentage of 12.5% for the performance cycle. The maximum payout for this award is 200% of target.

(d)

Amounts reflect the total grant date fair value calculated in accordance with FASB ASC Topic 718. The Black-Scholes value used for the stock options was $17.37 per share. The restricted stock value was based on the closing price of $64.79 per share of MPC common stock on the grant date. The MPC performance units have a grant date fair value of $0.83 per unit as calculated using a Monte Carlo valuation model. Assumptions used in the calculation of these amounts are included in Note 23 to MPC’s financial statements included in its Annual Report on Form 10-K for the year ended December 31, 2018. The phantom unit value was based on the closing price of $34.89 per unit of MPLX common units on the grant date. See Item 8. Financial Statements and Supplementary Data, Note 22 for assumptions used in the calculation of these amounts. No total grant date fair value for the MPLX performance units has been determined under FASB ASC Topic 718 because the MPLX Committee sets the DCF levels for these awards at the beginning of each performance year; thus, the DCF levels for the second and third performance years have not yet been set.

(e)

This award was granted to Mr. Heminger as part of the correction of an erroneous 2018 payment of his outstanding MPLX phantom unit awards, which was fully corrected in 2018 pursuant to applicable Internal Revenue Service guidance. Mr. Heminger took no part in the decision to make the erroneous payment. The correction restored him to the same economic position that he would have been in had the payment not occurred.

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(a)	MPC stock options have a maximum term for exercise of ten years from the grant date. They generally become exercisable in one-third increments on the first, second and third anniversaries of the grant date.

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(c)	Amounts reflect the aggregate value of all unvested MPLX LP phantom units and MPC restricted stock held on December 31, 2018, using the MPLX closing unit price of $30.30 and the MPC closing stock price of $59.01 on that date.

(d)

Amounts reflect the number of unvested MPC and MPLX performance units held on December 31, 2018. The MPLX performance unit grants awarded in 2017 and 2018 have a 36-month performance cycle and are designed to settle 25% in MPLX common units and 75% in cash. Each performance unit is dollar denominated with a target value of $1.00. Payout may vary from $0.00 to $2.00 per unit and will be determined (i) 50% based on MPLX’s TUR as compared to the applicable peer group, which for 2017 and 2018 were: Andeavor Logistics LP, Buckeye Partners, L.P., Enbridge Energy Partners, L.P., Energy Transfer Partners, L.P., Enterprise Products Partners L.P., Magellan Midstream Partners, L.P., Phillips 66 Partners LP, Plains All American Pipeline, L.P., Valero Energy Partners LP, Western Gas Partners, LP and Williams Partners L.P., (due to industry consolidations, Enbridge Energy Partners, L.P., Energy Transfer Partners, L.P. and Williams Partners L.P. were removed from the group effective January 1, 2018) and (ii) 50% based on a DCF-per-MPLX-common-unit metric which measures the growth of MPLX’s full-year DCF over the three-year performance cycle.

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(e)

Amounts for MPC reflect the aggregate value of all performance units held on December 31, 2018, assuming a payout of $1.5238 per unit for the March 1, 2017 award and $1.3333 per unit for the March 1, 2018 award, which is the next higher performance achievement that exceeds the performance for these grants’ performance period that ended December 31, 2018. Amounts shown for MPLX reflect the aggregate value of all performance units held on December 31, 2018, assuming a payout of $1.5000 per unit for the March 1, 2017 award and $1.0000 per unit for the March 1, 2018 award, which is the next higher performance achievement that exceeds the performance for these grants’ performance period that ended December 31, 2018.

(a)	As discussed in footnote (b) to the “Outstanding Equity at 2018 Fiscal Year-End” table, during 2018, certain awards held by

(b)	Amounts reflect the actual pre-tax gain realized upon vesting of MPLX phantom units and MPC restricted stock, which is the fair market value of the units or stock on the vesting date.

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(a)	Represents the number of years the NEO has participated in the plan. However, plan participation service used for the purpose of calculating each participant’s benefit under the Marathon Petroleum Retirement Plan legacy final average pay formula was frozen as of December 31, 2009.

(b)

The present value of accumulated benefit for the Marathon Petroleum Retirement Plan was calculated assuming a discount rate of 4.20%, the RP2000 mortality table for lump sums, a 96% lump sum election rate and retirement at age 62 (or current age, if later). In accordance with the Marathon Petroleum Retirement Plan provisions and actuarial assumptions, the discount rate for lump sum calculations varied between 0.75% to 1.50% based on anticipated year of retirement.

(c)	Dollar values for Mr. Swearingen reflect the portion of his compensation that was allocated to us for 2018 (75%).

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•	Participants with less than 50 points receive a 7% pay credit;

•	Participants with at least 50 but less than 70 points receive a 9% pay credit; and

•	Participants with 70 or more points receive an 11% pay credit.

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(a)	Amounts shown are also included in the “Salary” and “Non-Equity Incentive Plan Compensation” columns of the “2018 Summary Compensation Table.”

(b)	Amounts shown are also included in the “All Other Compensation” column of the “2018 Summary Compensation Table.”

(c)	As discussed in footnote (b) to the “Outstanding Equity Awards at 2018 Fiscal Year-End” table, during 2018, certain awards held by

(d)

Amounts represent the value of Mr. Heminger’s MPLX phantom units and accrued distribution equivalents. The Company Contributions amount is calculated using the average of the high and low MPLX common unit prices on his October 1, 2018 ($35.24) and December 20, 2018 ($31.26) vesting dates. The Aggregate Balance amount is calculated using the December 31, 2018 closing price of MPLX common units ($30.30).

(e)	Amounts for Mr. Swearingen reflect the portion of his compensation that was allocated to us for 2018 (75%).

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(a)

Under the MPLX LP Executive Change in Control Severance Benefits Plan, as further described below, cash severance will only be paid upon a change in control if the NEO experiences a Qualified Termination. If the Qualified Termination occurs within three years prior to the date the officer reaches age 65, the NEO’s benefit will be limited to a pro rata portion of the benefit. The NEO’s benefit is calculated using a fraction equal to the number of full and partial months existing between the Qualifying Termination and the 65th birthday divided by 36 months. As Mr. Heminger attained age 65 in September 2018, his cash severance benefits have been reduced to zero.

(b)

Pension benefits for our NEOs are reflected in the “2018 Pension Benefits Table” above. Amounts in this column represent additional pension benefits attributable solely to the final average pay formula in the Executive Change in Control Severance Benefits Plan. The incremental retirement benefits included in these amounts were calculated using the following assumptions: individual life expectancies using the RP2000 Combined Healthy Table weighted 75% male and 25% female; a discount rate of 1.00% for NEOs who are retirement eligible (taking into account the additional three years of age and service credit) and 1.00% for our NEOs who are not retirement eligible; the current lump-sum interest rate for the relevant plans; and a lump-sum form of benefit. Health and welfare plans reflect the incremental cost of coverage under the policy using the assumptions used for financial reporting purposes under generally accepted accounting principles in the U.S. Only Mr. Swearingen and Ms. Beall are eligible for this enhanced benefit.

(c)	Vesting of stock options is accelerated upon retirement or a change in control with a Qualified Termination. Amounts shown reflect the value that would be realized if accelerated stock options were exercised on December 31, 2018, taking into account the spread (if any) between the options’ exercise prices and the closing price of MPC common stock on December 31, 2018 ($59.01).

(d)	Vesting of restricted stock is accelerated upon a change in control with a Qualified Termination. Amounts shown reflect the value that would be realized if MPC restricted stock and MPLX phantom unit awards vested on December 31, 2018, taking into account the closing price of MPC common stock ($59.01) and MPLX LP common units ($30.30) on December 31, 2018. In the event of

(e)

In the event of a change in control and a Qualified Termination, unvested performance units will vest and be paid out based on actual performance for the period from the grant date to the change in control date, and target performance for the period from the change in control date to the end of the performance cycle. Amounts shown reflect the MPC and MPLX performance unit target vesting amounts that would be payable in the event of a change in control with each performance unit having a target value of $1.00.

(f)	Includes 36 months of continued health, dental and life insurance coverage. In the event of death, life insurance would be paid out to the estates of certain of our NEOs in the following amounts: Ms. Beall, $1.05 million; Mr. Hennigan, $1.6 million; Mr. Floerke, $0.9 million; Mr. Swearingen, $1 million.

(g)	Messrs. Heminger and Swearingen and Ms. Beall are currently eligible to retire under MPC’s retirement plan; thus, amounts shown for them reflect retirement rather than resignation. Messrs. Hennigan and Floerke were not eligible to retire as of December 31, 2018; thus, amounts shown for them reflect the compensation they would receive upon their voluntary resignation.

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•	due to death or disability;

•	for cause;

•	voluntary, unless the NEO has good reason (defined as a reduction in the NEO’s roles, responsibilities, pay or benefits, or the NEO being required to relocate more than 50 miles from his or her current location); or

•	on or after the date the NEO attains age 65.

•	a cash payment of up to three times the sum of the NEO’s current annualized base salary plus three times the highest bonus paid in the three years before the termination or change in control;

•	life and health insurance benefits for up to 36 months after termination at the lesser of the current cost or the active employee cost;

•	an additional three years of service credit and three years of age credit for purposes of retiree health and life insurance benefits;

•

a cash payment equal to the actuarial equivalent of the difference between amounts receivable by the NEO under the final average pay formula in our pension plans and those that would be payable if: (i) the NEO had an additional three years of participation service credit; (ii) the NEO’s final average pay were the higher of the NEO’s salary at the time of the change in control event or Qualified Termination plus the NEO’s highest annual bonus from the preceding three years (for purposes of determining early retirement commencement factors, the NEO is credited with three additional years of vesting service and three additional years of age);

•	a cash payment equal to the difference between amounts receivable under our tax-qualified and nonqualified defined contribution type retirement and deferred compensation plans and amounts that would have been received if the NEO’s defined contribution plan account had been fully vested; and

•	accelerated vesting of all outstanding MPC LTI awards.

•	a cash payment of up to three times the sum of the NEO’s current annualized base salary plus three times the highest bonus paid in the three years before the termination or change in control;

•	life and health insurance benefits for up to 36 months after termination at the active employee cost;

•	an additional three years of service credit and three years of age credit for purposes of retiree health and life insurance benefits;

•

a cash payment equal to the actuarial equivalent of the difference between amounts receivable by the NEO under the final average pay formula in our pension plans and those that would be payable if: (i) the NEO had an additional three years of participation service credit; (ii) the NEO’s final average pay were the higher of the NEO’s salary at the time of the change-in-control event or Qualified Termination plus the NEO’s highest annual bonus from the preceding three years (for purposes of determining early retirement commencement factors, the NEO is credited with three additional years of vesting service and three additional years of age); and (iii) the NEO’s pension had been fully vested; and

•	a cash payment equal to the difference between amounts receivable under our tax-qualified and nonqualified defined contribution type retirement and deferred compensation plans and amounts that would have been received if the NEO’s defined contribution plan account had been fully vested.

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(a)

Amounts reflect the aggregate grant date fair value of phantom units, calculated in accordance FASB ASC Topic 718. Non-employee directors generally received quarterly grants of phantom units with a grant date fair value of $21,875. Mr. Daberko’s quarterly grant was prorated for the second quarter due to his retirement, resulting in a grant date fair value for that award of $6,010. Mr. Stice joined our board during the second quarter and received a prorated award of phantom units with a grant date fair value of $16,106. All phantom units are deferred until departure from the Board, and distribution equivalents in the form of additional phantom unit awards are credited to each director’s deferred account as and when distributions are paid. The aggregate number of phantom units in respect of Board service outstanding for each non-employee director as of December 31, 2018 is: Messrs. Helms, Sandman, and Surma, 14,048;

(b)	Reflects contributions made to educational institutions under MPC’s matching gifts program.

(c)	Mr. Daberko retired from the Board effective April 25, 2018. Following his retirement, in July 2018, Mr. Daberko received a distribution of MPLX common units related to his Board service from his deferred equity account valued at $399,868, and cash in lieu of a fractional MPLX common unit in the amount of $5.

(d)	Mr. Semple was appointed as our Representative Observer to attend certain MPC Board and committee meetings, a role in which he acts as a liaison between the MPC Board and us, effective October 1, 2018; accordingly, his fees reflect the prorated retainer he received for his service during that period.

(e)	Mr. Stice was elected to the Board effective April 25, 2018.

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(1)	Includes the following:

(a)	1,154,336 phantom unit awards granted pursuant to the MPLX 2012 Plan and the MPLX 2018 Plan for common units unissued and not forfeited, cancelled or expired as of December 31, 2018.

(b)

218,103 units as the maximum potential number of common units that could be issued in settlement of performance units outstanding as of December 31, 2018, pursuant to the MPLX 2012 Plan and the MPLX 2018 Plan based on the closing price of our common units on December 31, 2018, of $30.30 per unit. The number of units reported for this award vehicle may overstate dilution. See Item 8. Financial Statements and Supplementary Data – Note 22 for more information on performance unit awards granted under the MPLX 2012 Plan and the MPLX 2018 Plan.

(2)	There is no exercise price associated with phantom unit awards.

(3)

Reflects the common units available for issuance pursuant to the MPLX 2018 Plan. The number of units reported in this column assumes 2,393 as the maximum potential number of common units that could be issued in settlement of performance units outstanding as of December 31, 2018, pursuant to the MPLX 2018 Plan based on the closing price of our common units on December 31, 2018, of $30.30 per unit. The number of units assumed for this award vehicle may understate the number of common units available for issuance pursuant to the MPLX 2018 Plan. See Item 8. Financial Statements and Supplementary Data – Note 22 for more information on performance unit awards issued pursuant to the MPLX 2018 Plan.

•	Payment of compensation to an executive officer or director of our general partner if the compensation is otherwise required to be disclosed in our filings with the SEC;

•	Any transaction where the related person’s interest arises solely from the ownership of securities;

•	Any ongoing employment relationship provided that such employment relationship will be subject to initial review and approval; and

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•	Any transaction between any of our subsidiaries and us, on the one hand, and our general partner or any of its affiliates, on the other hand; provided, however, that such transaction is approved consistent with our Partnership Agreement.

•	the benefits to us, including the business justification;

•	if the related person is a director or an immediate family member of a director, the impact on the director’s independence;

•	the availability of other sources for comparable products or services;

•	the terms of the transaction and the terms available to unrelated third parties or to employees generally; and

•	whether the transaction is consistent with our Code of Business Conduct.

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†	The exhibits and schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K and will be provided to the Securities and Exchange Commission upon request.

*	Indicates management contract or compensatory plan, contract or arrangement in which one or more directors or executive officers of the Registrant may be participants.

+	Application has been made to the Securities and Exchange Commission for confidential treatment of certain provisions of these exhibits. Omitted material for which confidential treatment has been requested and has been filed separately with the Securities and Exchange Commission.

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*	The undersigned, by signing his name hereto, does sign and execute this report pursuant to the Power of Attorney executed by the above-named directors and officers of the general partner of the registrant, which is being filed herewith on behalf of such directors and officers.