MPLX LP - Annual Report: 2019 (Form 10-K)

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•	future levels of revenues and other income, income from operations, net income attributable to MPLX LP, earnings per unit, Adjusted EBITDA or DCF (see the Non-GAAP Financial Information section below for the definitions of Adjusted EBITDA and DCF);

•	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 amount and timing of future distributions; and

•	the anticipated effects of actions of third parties such as competitors, activist investors or federal, foreign, state or local regulatory authorities or plaintiffs in litigation.

•	Marathon Petroleum Corporation’s (“MPC”) ability to achieve its strategic objectives and the effects of those strategic decisions on us;

•	the risk that anticipated opportunities and any other synergies from or anticipated benefits of the Andeavor Logistics LP (“ANDX”) acquisition may not be fully realized or may take longer to realize than expected, including whether the transaction will be accretive within the expected timeframe or at all;

•	disruption from the ANDX acquisition making it more difficult to maintain relationships with customers, employees or suppliers;

•	risks relating to any unforeseen liabilities of ANDX;

•	further impairments;

•	negative capital market conditions, including an increase of the current yield on common units;

•	the ability to achieve strategic and financial objectives, including with respect to distribution coverage, future distribution levels, proposed projects and completed transactions;

•	the success of MPC’s portfolio optimization, including the ability to complete any divestitures on commercially reasonable terms and/or within the expected timeframe, and the effects of any such divestitures on the business, financial condition, results of operations and cash flows;

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

•	the adequacy of capital resources and liquidity, including the availability of sufficient cash flow to pay distributions and access to debt on commercially reasonable terms, and the ability to successfully execute business plans, growth strategies and self-funding models; and

•	the timing and extent of changes in commodity prices and demand for crude oil, refined products, feedstocks or other hydrocarbon-based products;

•	volatility in or degradation of market and industry conditions;

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

•	completion of midstream infrastructure by competitors;

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

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

•	modifications to financial policies, capital budgets, and earnings and distributions;

•	the ability to manage disruptions in credit markets or changes to credit ratings;

•	compliance with federal and state environmental, economic, health and safety, energy and other policies and regulations or enforcement actions initiated thereunder;

•	adverse results in litigation;

•	the reliability of processing units and other equipment;

•	the effect of restructuring or reorganization of business components;

•	the potential effects of changes in tariff rates on our business, financial condition, results of operations and cash flows;

•	foreign imports and exports of crude oil, refined products, natural gas and NGLs;

•	changes in producer customers’ drilling plans or in volumes of throughput of crude oil, natural gas, NGLs, refined products or other hydrocarbon-based products;

•	changes in 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;

•	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;

•	expectations regarding joint venture arrangements and other acquisitions, including the dropdowns completed by MPC, or divestitures of assets;

•	midstream and refining industry overcapacity or under capacity;

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

•	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;

•	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; and

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

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(1)	Includes goodwill impairment of $1.2 billion within our G&P operating segment.

(2)	Includes segment adjusted EBITDA attributable to predecessor.

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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 then transport raw, or untreated, natural gas to a central location for treating and processing.

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Processing. Natural gas has a widely varying composition depending on the field, formation reservoir or facility from which it is produced. Processing removes the heavier and more valuable hydrocarbon components, which are extracted as a mixed NGL stream that includes ethane, propane, butanes and natural gasoline (also referred to as “y-grade”). Processing aids in allowing the residue gas remaining after extraction of NGLs to meet the quality specifications for long-haul pipeline transportation and commercial use.

•	Fractionation. Fractionation is the separation of the mixture of extracted NGLs into individual components for end-use sale. Fractionation systems typically exist either as an integral part of a gas processing plant or as a central fractionator.

•	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.

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(1)	This is a Sherwood Midstream LLC (“Sherwood Midstream”) investment. The first of six processing plants within this complex is scheduled to be in-service during 2020 with a processing capacity of 200 MMcf/d. The estimated completion dates for the five remaining plants are to be determined.

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

(2)	Region includes some contracts which contain acreage dedications.

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(1)

Renewal terms on our agreements include multiple two to five-year terms for transportation services agreements, one to two additional five-year terms for our terminal services agreements, 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 one of our two Fuels Distribution Services Agreements. These renewals are automatic, unless terminated by either party.

(2)

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 or stipulated volumes in thousands of barrels. Commitments for the fuels distribution services agreements refers to millions of gallons per year. Minimum commitments on some agreements are reduced by any third-party throughput volumes.

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

(4)	Volume shown represents total capacity in thousands of barrels (includes refining logistics tanks).

(5)	Some terminal services agreements also contain minimum commitments for activities such as blending, additives, on-loading and off-loading, and storage.

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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.

•	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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•	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, or a delay in the successful integration of, 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 loss of customers or key employees from the acquired businesses; and

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•	the emission or discharge of materials into the environment,

•	solid and hazardous waste management,

•	the regulatory classification of materials presently used in our business,

•	pollution prevention,

•	greenhouse gas emissions,

•	climate change,

•	public and employee safety and health,

•	inherently safer technology, and

•	facility security.

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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 refined 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 refined 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;

•	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;

•	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

•	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)	Includes approximately 21 miles of crude pipeline and approximately 158 miles of refined product pipeline leased from third parties.

(2)

Includes approximately 1,921 miles of crude pipeline in which we have a 9.2 percent ownership interest, 168 miles of crude pipeline in which we have a 35.0 percent ownership interest, 48 miles of crude pipeline in which we have a 40.7 percent ownership interest, 57 miles of crude pipeline in which we have a 58.5 percent ownership interest, 118 miles of crude pipeline in which we have a 67.0 percent ownership interest and 975 miles of crude pipeline in which we have a 17.0 percent ownership interest. Also includes approximately 1,830 miles of refined product pipeline in which we have a 24.5 percent ownership interest and 87 miles of refined product pipeline in which we have a 65.16 percent ownership interest.

(3)	Includes approximately 399 miles of inactive crude pipeline and 232 miles of inactive refined product pipeline.

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(1)	MPLX also operates one leased terminal and has partial ownership interest in one terminal, with a combined tank shell capacity of 1,045 mbbls.

(2)	This terminal is accounted for as an equity method investment.

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(1)	Capacity for Tank Farms is shown as 100 percent of the available storage capacity. Capacity for the Barge Dock is shown as 100 percent of the throughput capacity. Capacity for caverns is shown as the storage commitment.

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

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(3)	The Mt. Airy Terminal includes 37 tanks, 2-bay ethanol loading rack, 3-vessel barge/ship dock and 7 dock loading lines.

(4)	We own and operate 28 tank farms and operate two leased tank farms.

(5)	All capacities reflect 100 percent of the pipeline systems’ capacity in thousands of barrels per day.

(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)	Centrahoma Processing LLC’s processing capacity of 550 MMcf/d and actual throughput of 272 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)

Certain complexes have above-ground NGL storage with a usable capacity of 938 thousand barrels, large-scale truck and rail loading. 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 capacity, throughput and utilization of design capacity at the Hopedale fractionation complex is presented in the Marcellus Shale totals, however, the Hopedale fractionation complex is jointly owned by MarkWest Ohio Fractionation Company, L.L.C. (“Ohio Fractionation”) and MarkWest Utica EMG, L.L.C. (“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 Midstream 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. During the year ended December 31, 2019, the Marcellus Operations and Utica Operations utilized an average of 83

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(4)	We have access to 100 thousand barrels of condensate storage in this region.

(5)

This region includes complexes with 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. We also have large-scale truck and rail loading and unloading capabilities, and a river barge facility capable of loading a 20 thousand barrel barge.

(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.

(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)	This region does not include our operated joint venture, Rendezvous Gas Services, L.L.C. (“RGS”), which has a gathering capacity of 1,032 MMcf/d; this system supports other systems which are included in the Rockies region and that throughput is presented in the table above. The third party volumes gathered for RGS during the year ended December 31, 2019 were 127 MMcf/d.

(1)	Includes 38 miles of inactive pipeline.

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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)

On July 30, 2019, MPLX completed the acquisition of ANDX. ANDX’s assets, liabilities and results of operations prior to the Merger are collectively included in what we refer to as the “Predecessor” from October 1, 2018, which was the date that MPC acquired Andeavor. MPLX’s acquisition of ANDX is considered a transfer between entities under common control due to MPC’s prior relationship with ANDX. As an entity under common control with MPC, MPLX recorded the assets acquired and liabilities assumed on its consolidated balance sheets at MPC’s historical carrying value. Transfers of businesses between entities under common control require prior periods to be retrospectively adjusted for those dates that the entity was under common control. Accordingly, the table above includes the historical results of ANDX beginning October 1, 2018.

(2)

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. In connection with the Merger, MPLX LP assumed ANDX senior notes with an aggregate principal amount of $3.75 billion as of October 1, 2018.

(3)	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.

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

(5)	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

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

(12)

Purity ethane makes up approximately 179 mbpd, 171 mbpd, 141 mbpd, 114 mbpd and 83 mbpd of MPLX LP consolidated total fractionated products for the years ended December 31, 2019, 2018, 2017, 2016 and 2015, respectively. Purity ethane makes up approximately 189 mbpd, 185 mbpd, 146 mbpd, 118 mbpd and 89 mbpd of MPLX operated total fractionated products for the years ended December 31, 2019, 2018, 2017, 2016 and 2015, respectively.

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

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MPLX completed the acquisition of ANDX via Merger on July 30, 2019. The historical results of ANDX have been incorporated into the MPLX results from October 1, 2018, which is the date that MPC acquired Andeavor. At the effective time of the Merger, each common unit held by ANDX’s public unitholders was converted into the right to receive 1.135 MPLX common units. ANDX common units held by certain affiliates of MPC were converted into the right to receive 1.0328 MPLX common units. The assets of ANDX complement and enhance MPLX’s existing asset base and further expand MPLX’s existing footprint.

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MPLX entered into a joint venture agreement related to the Wink-to-Webster crude oil pipeline, which remains on schedule to be completed in the first half of 2021 and has 100 percent of the contractible capacity committed with minimum volume commitments. This is a 36-inch diameter pipeline with a capacity of 1.5 million barrels per day which will originate in the Permian Basin and have destination points in the Houston market, including MPC’s Galveston Bay refinery.

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We also entered into a joint venture agreement related to the design and construction of the Whistler Pipeline. The Whistler Pipeline is designed to be a 42-inch diameter pipeline, which will transport approximately 2 Bcf/d of natural gas from Waha, Texas, to the Agua Dulce area in South Texas. The majority of available capacity on the planned pipeline has been committed with minimum volume commitments. The pipeline is expected to be in service in the second half of 2021.

•	Additionally, we continue to execute on our organic growth plan through terminal and marine fleet expansions, the expansion of processing and fractionating capacity at numerous plants, as well as having a continued focus on the optimization of our portfolio of assets, which could include asset divestitures.

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During the year, MPLX: entered into a Term Loan Agreement, which provides for a committed term loan facility for up to an aggregate of $1.0 billion; issued $2.0 billion aggregate principal amount of floating rate senior notes in a public offering; increased its borrowing capacity on the MPLX Credit Agreement to $3.5 billion; extended the maturity of the MPLX Credit Agreement to July 30, 2024; and paid off $500 million aggregate principal amount of the outstanding ANDX 5.5 percent senior notes due 2019 at maturity.

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In connection with the Merger, MPLX also assumed all outstanding ANDX senior notes, which had an aggregate principal amount of $3.75 billion with interest rates ranging from 3.5 percent to 6.375 percent and maturity dates ranging from 2019 to 2047. On September 23, 2019, $3.06 billion aggregate principal amount of ANDX’s outstanding senior notes were exchanged for an aggregate principal amount of $3.06 billion new senior notes issued by MPLX in an exchange offer and consent solicitation undertaken by MPLX, leaving $690 million aggregate principal of outstanding senior notes issued by ANDX, of which $500 million aggregate principal amount of outstanding ANDX 5.5 percent senior notes due 2019 were paid off on October 15, 2019 at maturity as described above.

•	During the year ended December 31, 2019, we did not issue any common units under our ATM Program. As of December 31, 2019, $1.7 billion of common units remain available for issuance through the ATM Program.

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(1)	Includes impairment expense of $42 million related to two equity method investments in 2019.

(2)	Non-GAAP measure. See reconciliation below for the most directly comparable GAAP measures. Excludes adjusted EBITDA and DCF adjustments attributable to Predecessor.

(3)	Non-GAAP measure. See reconciliation below for the most directly comparable GAAP measures. Includes adjusted EBITDA and DCF adjustments attributable to Predecessor.

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(1)	Includes impairment expense of $42 million related to two equity method investments in 2019.

(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 attributable to GP and LP unitholders prior to the acquisition dates.

(4)

Includes MPLX distributions declared on the Series A and Series B preferred units as well as cash distributions earned by the Series B preferred (as the Series B preferred units are declared and payable semi-annually) assuming a distribution is declared by the Board of Directors. Cash distributions declared/to be paid to holders of the Series A and Series B preferred units are not available to common unitholders.

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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 attributable to GP and LP unitholders prior to the acquisition dates.

(3)

Includes MPLX distributions declared on the Series A and Series B preferred units as well as cash distributions earned by the Series B preferred (as the Series B preferred units are declared and payable semi-annually) assuming a distribution is declared by the Board of Directors. Cash distributions declared/to be paid to holders of the Series A and Series B preferred units are not available to common unitholders.

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(1)	Includes results of Predecessor.

(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)	Includes results of Predecessor.

(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 capital expenditures of the Predecessor for all periods presented.

(2)	This amount is represented in the Consolidated Statements of Cash Flows as Additions to property, plant and equipment after excluding growth and maintenance reimbursements. Reimbursements are shown as Contributions from MPC within the Financing activities section of the Consolidated Statements of Cash Flows.

(3)	Amount excludes contributions from noncontrolling interests of $95 million, $11 million and $129 million for the years ended December 31, 2019, 2018 and 2017, respectively, as reflected in the financing section of our Consolidated Statements of Cash Flows.

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(1)	Amounts represent outstanding borrowings at December 31, 2019, plus any commitment and administrative fees and interest.

(2)	Amounts relate primarily to facilities and equipment under leases, including ground leases, building space, office and field equipment, storage facilities and transportation equipment. See Item 8. Financial Statements and Supplementary Data – Note 22 for further discussion about our lease obligations.

(3)	Represents purchase orders and contracts related to the purchase or build out of property, plant and equipment.

(4)

Natural gas purchase obligations consist primarily of a purchase agreement with a producer in our Southern Appalachia Operations. The contract provides for the purchase of keep-whole volumes at a specific price and is a component of a broader regional arrangement. The contract price is designed to share a portion of the frac spread with the producer and as a result, the amounts reflected for the obligation exceed the cost of purchasing the keep-whole volumes at a market price. The contract is considered an embedded derivative (see Item 8. Financial Statements and Supplementary Data – Note 16 for the fair value of the frac spread sharing component). We use the estimated future frac spreads as of December 31, 2019 for calculating this obligation. The counterparty to the contract has the option to renew the gas purchase agreement and the related keep-whole processing agreement for two successive five-year terms after 2022, which is not included in the natural gas purchase obligations line item.

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

(6)	Represents transportation and terminalling agreements that obligate us to minimum volume, throughput or payment commitments over the terms of the agreements, which will range from four to 20 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 $24 million. The total amount to be paid is approximately $51 million.

(8)	Other contracts include various service agreements and easements including right of way obligations.

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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, intangible assets, goodwill and equity method investments;

•	assessment of values for assets in implicit leases;

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

•	recorded values of derivative instruments.

•

Future Operating Performance. Our estimates of future operating performance 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.

•

Future volumes. Our estimates of future throughput of crude oil, natural gas, NGL and refined product volumes are based on internal forecasts and depend, in part, on assumptions about our customers’ drilling activity which is inherently subjective and contingent upon a number of variable factors (including future or expected pricing considerations), many of which are difficult to forecast. Management considers these volume forecasts and other factors when developing our forecasted cash flows.

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•	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, 2019, we believe there is a 94 percent and 83 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 2023, 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, 2019.

(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, 2019.

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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.

•

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 or related 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.

•

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.

•

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

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(1)	Inclusive of activity recorded subsequent to the acquisition of ANDX on July 30, 2019, a portion of which was recorded as a non-cash contribution from MPC.

(2)	Includes both related party and third party other current assets.

(3)	Includes approximately $4 million of favorable lease assets. In connection with the implementation of ASC 842, this balance was reclassed to “Right of use assets” on the Consolidated Balance Sheets during 2019.

(4)	Includes both related party and third party other noncurrent assets as well as right of use assets associated with leases.

(5)	Includes accrued liabilities, operating lease liabilities, long-term debt due within one year, as well as related party and third party other current liabilities.

(6)	Includes deferred revenue and deferred income taxes, as well as related party and third party other noncurrent liabilities.

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(1)	These investments as well as certain investments included within “Other” for both L&S and G&P are investments acquired as part of the Merger. The December 31, 2019 balance reflects all purchase accounting adjustments identified by MPC as part of its acquisition of Andeavor.

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(1)

The financial information for equity method investments for 2019 includes financial information of equity method investments acquired as part of the Merger. The financial information for equity method investments for 2018 includes financial information of equity method investments acquired as part of the Merger for the last three months of 2018. The financial information for equity method investments for 2017 does not include financial information of equity method investments acquired as part of the Merger. See Note 1 for additional information.

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

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•	MPLX has fuels distribution agreements with MPC under which MPC pays MPLX for marketing and selling MPC’s products. This can include MPC paying MPLX a tiered monthly fee based on the volume of products sold or thought margin support under a related product supply agreement. Agreements are subject to minimum volume commitments and are subject various terms and renewal periods.

•

MPLX has various pipeline transportation agreements under which MPC pays MPLX fees for transporting crude and refined products on MPLX’s pipeline systems. These agreements are subject to minimum throughput volumes under which MPC will pay MPLX deficiency payments for any period in which they do not ship the minimum committed volume. These deficiency payments can be applied as credits to future periods in which MPC ships volumes in excess of the minimum volume, subject to a limited period of time. These agreements are subject to various terms and renewal periods.

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

•

MPLX has various trucking transportation services agreements with terms ranging from month-to-month to 10 years, under which MPC pays MPLX fees for gathering barrels and providing trucking, dispatch, delivery and data services. Most of these agreements are subject to minimum volume commitments and have various terms regarding carry-forward of deficiency payments as credits towards excess volumes shipped in future periods. These agreements are subject to various terms and renewal periods.

•

MPLX has numerous storage services agreements governing storage services at various types of facilities including terminals, pipeline tank farms, caverns and refineries, under which MPC pays MPLX per-barrel fees for providing storage services. Some of these agreements provide MPC with exclusive access to storage at certain locations, such as storage located at MPC’s refineries or storage in certain caverns. Under these agreements, MPC pays MPLX a per-barrel fee for such storage capacity, regardless of whether MPC fully utilizes the available capacity. Many of the refinery storage agreements also contain provisions for logistical services to be provided by MPLX, for which MPC pays monthly fees. These agreements are subject to terms ranging from three to 17 years and are subject to various renewal periods.

•

MPLX has a 10-year terminal services agreement governing certain terminals under which MPC pays MPLX fees for terminal storage for refined petroleum products. Under this agreement MPC pays MPLX agreed upon fees relating to MPC product deliveries as well as any viscosity surcharges, loading, handling, transfers or other related charges. This agreement is subject to minimum volume throughput commitments under which MPC pays a deficiency payment for any period in which they do not meet the minimum committed volume. The terminal services agreement with MPC includes automatic renewal terms ranging from one to five years. MPLX also has numerous additional terminal services agreements governing terminals acquired through the Merger. Under these agreements, MPC pays MPLX agreed upon fees relating to various terminal activities including throughput, blending, on and offloading and additives. Many of these agreements contain various minimum commitments for some or all of these activities. Some of these agreements allow for deficiency payments to be applied as credits to future periods with excess throughput volumes. These agreements have terms ranging from one to 10 years with varying renewal terms.

•	MPLX has a year to year keep-whole commodity agreement with MPC under which MPC pays us a processing fee for NGL’s related to keep-whole agreements and delivers shrink gas to the producers on our behalf. We pay MPC a marketing fee in exchange for assuming the commodity

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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 2019, 2018 and 2017, these sales totaled $1,120 million, $607 million and $254 million, respectively.

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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 had been distributed based on the distribution priorities applicable to the period.

(2)	The Series B preferred units and the MPLX common units issued in connection with the Merger were not outstanding during the entire year. See Notes 4 and 8 for additional information about the treatment of these units.

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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, asphalt, refined petroleum products and water. Also includes an inland marine business, terminals, rail facilities, storage caverns and refining logistics.

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

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(1)	Within the total segment revenues and other income amounts presented above, third party revenues for the L&S segment were $660 million, $371 million and $160 million for 2019, 2018 and 2017, respectively. Third party revenues for the G&P segment were $3,474 million, $3,198 million and $2,246 million for 2019, 2018 and 2017, respectively.

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

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(1)	Depreciation and amortization attributable to L&S was $503 million, $308 million and $163 million for the years ended 2019, 2018 and 2017, respectively. Depreciation and amortization attributable to G&P was $751 million, $559 million and $520 million for 2019, 2018 and 2017, respectively.

(2)

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.

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

(1)	The percent calculations exclude revenues attributable to volumes shipped by MPC under joint tariffs with third parties, which are treated as third-party revenue for accounting purposes.

(2)	Operating revenues consist of service revenue, service revenue - product related, rental income and product sales.

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(1)	Acquisitions in 2018 are inclusive of the Mt. Airy Terminal acquisition as well as the Merger while acquisitions in 2019 are inclusive of measurement period adjustments related to the previously mentioned transactions.

(1)	Amortization expense attributable to the G&P segment for the years ended December 31, 2019 and 2018 was $127 million and $49 million, respectively. Amortization expense attributable to the L&S segment for the year ended December 31, 2019 and 2018 was $31 million and $14 million, respectively.

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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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(1)	See Note 22 for lease information.

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(1)	G&P “Product sales” for the year ended December 31, 2018 was adjusted in the table above by $5 million related to derivative gains and mark-to-market adjustments. There were no adjustments for the year ended December 31, 2019.

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

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

(2)	No significant revenue was recognized related to past performance obligations for the years ended December 31, 2019 and 2018.

(3)	Includes opening balances related to the Merger.

(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.

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

(2)

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. For 2019, includes limited partner units issued to MPC and public unitholders as consideration in the Merger. See Note 4.

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(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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(1)	These amounts are presented net of executory costs.

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(1)

As discussed in Note 1, MPLX’s acquisition of ANDX is considered a transfer between entities under common control due to MPC’s prior relationship with ANDX. Transfers of businesses between entities under common control require prior periods to be retrospectively adjusted for those dates that the entity was under common control. Accordingly, the tables above include the historical results of ANDX beginning October 1, 2018. Amounts shown for the fourth quarter of 2018 as well as the first and second quarters of 2019 are different than amounts previously reported for Total revenues and other income, Income from operations and Net income as a results of this retrospective adjustment for ANDX. Total revenues and other income originally reported for the fourth quarter of 2018 and the first and second quarters of 2019 was $1,715 million, $1,646 million and $1,629 million, respectively. Income from operations originally reported for the fourth quarter of 2018 and the first and second quarters of 2019 was $666 million, $678 million and $659 million, respectively. Net income originally reported for the fourth quarter of 2018 and the first and second quarters of 2019 was $439 million, $509 million and $488 million, respectively.

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*	Corporate officer

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•	Independent Directors (individually or as a group): non-managedirectors@mplx.com

•	Audit Committee Chair: auditchair@mplx.com

•	Conflicts Committee Chair: conflictschair@mplx.com

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•	MPC achieved full-year earnings for 2019 of $2.6 billion.

•	MPC’s sustained focus on shareholder returns, with $3.3 billion returned to shareholders through dividends and share repurchases.

•	Successful integration of Andeavor into MPC, with the synergies realized well over first-year target.

•	Successful merger of ANDX into MPLX.

•	Enhancement of MPC shareholder and MPLX unitholder value through return of capital and unlocking midstream asset value.

•	Successful integration of Andeavor and ANDX into MPC and MPLX operations.

•	Excellence in environmental, personal safety and process safety improvement.

•	Talent development, retention, succession and acquisition.

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•	System integration, optimization and removing bottlenecks.

•	Growth through organic expansion and acquisition opportunities.

•	Growth of market share for gasoline and diesel.

•	Progress on diversity and inclusion initiatives.

*	Mr. Hennigan’s Target Bonus amount was adjusted to reflect his change in base salary and bonus target as he transitioned from his role as our President to service as our President and CEO.

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•	Phantom unit awards, which settle in common units upon a director’s retirement from service on the Board, as follows: Mr. Beatty, 14,004; Mr. Helms, 20,253; Mr. Peiffer, 17,153; Mr. Sandman, 20,253; Mr. Semple, 12,246; Mr. Stice, 8,497; Mr. Surma, 24,002.

•	Phantom unit awards, which may be forfeited under certain conditions, as follows: Ms. Beall, 10,773; Mr. Floerke, 47,074; Ms. Gagle, 14,122; Mr. Hennigan, 113,543; Mr. Swearingen, 9,984; Mr. Templin, 30,221; all other executives, 4,613.

•	For Mr. Heminger, 77,852 phantom unit awards, which are no longer subject to forfeiture because Mr. Heminger has reached mandatory retirement age.

•	Common units indirectly beneficially held in trust as follows: Ms. Beall, 10,000; Mr. Heminger, 174,515; Mr. Peiffer, 68,497; Mr. Semple, 527,517; Mr. Stice, 700.

•	For Messrs. Semple and Templin, common units held by or with spouse, with spouse as co-trustee or by trust for the benefit of spouse.

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•	All stock options exercisable within 60 days of January 31, 2020 as follows: Ms. Beall, 75,188; Mr. Floerke, 15,831; Ms. Gagle, 94,994; Mr. Heminger, 2,541,680; Mr. Hennigan, 40,791; Mr. Swearingen, 185,974; Mr. Templin, 541,751; all other executive officers, 4,106. Includes 359,773 stock options exercisable by the applicable executive officers but not in the money as of January 31, 2020.

•	Shares of common stock indirectly beneficially held in trust as follows: Ms. Beall, 32,208; Mr. Heminger, 206,202; Mr. Peiffer, 63,394; Mr. Surma, 10,000.

•	For Messrs. Surma and Templin, shares of common stock held by or with spouse, with spouse as co-trustee or by trust for the benefit of spouse.

•	Restricted stock unit awards, which vest upon the director’s retirement from service on the MPC Board or observer status, as follows: Mr. Semple, 4,892; Mr. Stice, 7,713; Mr. Surma, 37,412.

•	1,109,598 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, 2019.

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•

315,248 units as the maximum potential number of common units that could be issued in settlement of performance units outstanding as of December 31, 2019, pursuant to the MPLX 2012 Plan and the MPLX 2018 Plan based on the closing price of our common units on December 31, 2019, of $25.46 per unit. The number of units reported for this award vehicle may overstate dilution. See Item 8. Financial Statements and Supplementary Data – Note 21 for more information on performance unit awards granted under the MPLX 2012 Plan and 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

•	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;

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•	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.

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

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*	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.