---

---

---

•	future levels of revenues and other income, income from operations, net income attributable to MPLX LP, earnings per unit, Adjusted EBITDA or DCF (please read Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Non-GAAP Financial Information for the definitions of Adjusted EBITDA and DCF);

•	anticipated levels of regional, national and worldwide prices of crude oil, natural gas, NGLs and refined products;

•	anticipated levels of drilling activity, production rates and volumes of throughput of crude oil, natural gas, NGLs, refined products or other hydrocarbon-based products;

•	future levels of capital, environmental or maintenance expenditures, general and administrative and other expenses;

•	the success or timing of completion of ongoing or anticipated capital or maintenance projects;

•	expectations regarding the MarkWest Merger (as defined below) and other acquisitions or divestitures of assets;

•	business strategies, growth opportunities and expected investments;

•	the effect of restructuring or reorganization of business components;

•	the potential effects of judicial or other proceedings on our business, financial condition, results of operations and cash flows;

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

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

•	our ability to successfully implement our growth strategy, whether through organic growth or acquisitions;

•	capital market conditions, including the cost of capital, and our ability to raise adequate capital to execute our business plan and implement our growth strategy; and

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

---

•	changes in general economic, market or business conditions;

•	changes in the economic and financial condition of MPLX LP;

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

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

•	changes in regional, national and worldwide prices of crude oil, natural gas, NGLs and refined products;

•	domestic and foreign supplies of crude oil and other feedstocks, natural gas, NGLs and refined products such as gasoline, diesel fuel, jet fuel, home heating oil and petrochemicals;

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

•	midstream and refining industry overcapacity or undercapacity;

•	changes in the cost or availability of third-party vessels, pipelines, railcars and other means of transportation for crude oil, natural gas, NGLs, feedstocks and refined products;

•	price, availability and acceptance of alternative fuels and alternative-fuel vehicles and laws mandating such fuels or vehicles;

•	fluctuations in consumer demand for refined products, natural gas and NGLs, including seasonal fluctuations;

•	changes in maintenance capital expenditure requirements or changes in costs of planned capital projects;

•	political and economic conditions in nations that consume refined products, natural gas and NGLs, including the United States, and in crude oil producing regions, including the Middle East, Africa, Canada and South America;

•	actions taken by our competitors and the expansion and retirement of pipeline, processing, fractionation and treating capacity in response to market conditions;

•	changes in fuel and utility costs for our facilities;

•	failure to realize the benefits projected for capital projects, or cost overruns associated with such projects;

•	the ability to successfully implement growth strategies, whether through organic growth or acquisitions;

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

•	unusual weather conditions and natural disasters;

•	disruptions due to equipment interruption or failure;

•	acts of war, terrorism or civil unrest that could impair our ability to gather, process, fractionate or transport crude oil, natural gas, NGLs or refined products;

•	legislative or regulatory action, which may adversely affect our business or operations;

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

---

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

•	labor and material shortages;

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

•	capital market conditions, increases in and availability of equity capital, changes in the availability of unsecured credit and changes affecting the credit markets generally; and

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

---

---

---

•

Our L&S segment’s assets are located in regions that collectively comprised approximately 73 percent of total U.S. crude distillation capacity and approximately 53 percent of total U.S. finished products demand for the year ended December 31, 2015, according to the EIA. MPC owns and operates seven refineries in the Midwest and Gulf Coast regions of the United States, which have an aggregate crude oil refining capacity of approximately 1.8 million barrels per calendar day. Our L&S assets are integral to the success of MPC’s operations.

•	Our G&P segment is focused on regions of natural gas supply growth. We are one of the largest processors and fractionators in the United States.

◦

We are the largest processor and fractionator in the Marcellus and Utica Shale plays. As of February 12, 2016, our assets in the northeastern United States have combined processing capacity of approximately 5.9 bcf/d and combined fractionation capacity of approximately 483 mbpd as well as an integrated NGL pipeline network and extensive logistics and marketing infrastructure. We believe our significant asset base and full-service midstream model provides us with strategic competitive advantages in capturing and contracting for gathering and processing of new supplies of natural gas as production in the Northeast continues to increase.

◦	We also have a significant presence in the southwestern portion of the United States with an existing strong competitive position; access to a significant reserve or customer base with a stable or growing production profile; ample opportunities for long-term continued organic growth; ready access to markets; and close

---

---

---

•	Our common units are publicly traded on the NYSE under the symbol “MPLX.”

•

All of our Class A units are owned by MarkWest Hydrocarbon, which is our wholly-owned subsidiary. The Class A units generally share in our income or losses on a pro rata basis with our common units and our Class B units, however the Class A units do not share in any income or losses that are attributable to our ownership interest (or disposition of such interest) in MarkWest Hydrocarbon. The only impact of the Class A units on our consolidated results of operations and financial position is that MarkWest Hydrocarbon pays income tax on its pro rata share of our income or losses. The Class A units are not treated as outstanding common units in the accompanying Consolidated Balance Sheets as they are all held by our wholly-owned subsidiaries and therefore eliminated in consolidation.

•

All of the Class B units were issued to and are held by M&R MWE Liberty LLC and certain of its affiliates (“M&R”), an affiliate of The Energy & Minerals Group (“EMG”). The 8.0 million Class B units will convert into common units at a rate of 1.09 common units per Class B unit and will receive $6.20 in cash per Class B unit, which will be funded by MPC in two equal installments on July 1, 2016 and July 1, 2017. Class B units (i) share in our taxable income and losses, (ii) are not entitled to participate in any distributions of available cash prior to their conversion and (iii) do not have the right to vote on, approve or disapprove, or otherwise consent to or not consent to any matter (including mergers, unit exchanges and similar statutory authorizations) other than those matters that disproportionately and adversely affect the rights and preferences of the Class B units. Upon conversion of the Class B units, the right of M&R and certain of its affiliates to vote as a common unitholder of the Partnership will be limited to a maximum of five percent of the Partnership’s outstanding common units. Upon the conversion of each tranche of Class B units, M&R will have the right with respect to such converted units to participate in the Partnership’s underwritten offerings of our common units including continuous equity or similar programs in an amount up to 20 percent of the total number of common units offered by the Partnership. In addition, M&R may freely transfer such converted units, and M&R will have the right to demand that we conduct up to three underwritten offerings beginning in 2017, but restricted to no more than one offering in any twelve-month period. M&R is not permitted to transfer its Class B units without the prior written consent of our general partner’s board of directors.

•

Logistics. Crude oil is the basis for many products including plastics and petrochemicals in addition to fuel for trucks and heating oil for homes once it is refined and prepared for use. While many forms of transportation are used to move this product to storage hubs and refineries, we believe pipelines are one of the safest, most efficient and cost-effective ways to move this resource to refineries and to market. Pipelines bring advantaged North American crude oil from the upper Great Plains, Texas and Canada to numerous refiners. Pipelines are also used to effectively move refined products from refineries to customers and end markets.

•	Storage. The hydrocarbon market is often volatile and the ability to take advantage of fast moving market conditions is enhanced by our ability to store crude oil and other hydrocarbon-based products at our tank farms and butane cavern. Storage facilities provide flexibility and logistics optionality, which enhances MPC’s ability to maximize returns for refined products.

---

•

Gathering. The natural gas production process begins with the drilling of wells into gas-bearing rock formations. At the initial stages of the midstream value chain, a network of typically smaller diameter pipelines known as gathering systems directly connect to wellheads in the production area. These gathering systems transport raw, or untreated, natural gas to a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow gathering of additional production without significant incremental capital expenditures.

•

Compression. Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which allows the natural gas to be gathered more efficiently and delivered into a higher pressure system, processing plant or pipeline. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure system. Since wells produce at progressively lower field pressures as they deplete, field compression is needed to maintain throughput across the gathering system.

•	Treating and dehydration. To the extent that gathered natural gas contains contaminants, such as water vapor, carbon dioxide and/or hydrogen sulfide, such natural gas is dehydrated to remove the saturated water and treated to separate the carbon dioxide and hydrogen sulfide from the gas stream.

•

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

•

Fractionation. Fractionation is the separation of the mixture of extracted NGLs into individual components for end-use sale. It is accomplished by controlling the temperature and pressure of the stream of mixed NGLs in order to take advantage of the different boiling points and vapor pressures of separate products. Fractionation systems typically exist either as an integral part of a gas processing plant or as a central fractionator, often located many miles from the primary production and processing complex. A central fractionator may receive mixed streams of NGLs from many processing plants. A fractionator can fractionate one product or a central fractionator, multiple products. We operate fractionation facilities at certain processing systems 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.

---

•	Ethane is used primarily as feedstock in the production of ethylene, one of the basic building blocks for a wide range of plastics and other chemical products.

•	Propane is used for heating, engine and industrial fuels, agricultural burning and drying and as a petrochemical feedstock for the production of ethylene and propylene.

•	Normal butane is mainly used for gasoline blending, as a fuel gas, either alone or in a mixture with propane, and as a feedstock for the manufacture of ethylene and butadiene, a key ingredient of synthetic rubber.

•	Isobutane is primarily used by refiners to enhance the octane content of motor gasoline.

•	Natural gasoline is principally used as a motor gasoline blend stock or petrochemical feedstock.

•	Ethylene is primarily used in the production of a wide range of plastics and other chemical products.

•	Propylene is primarily used in manufacturing plastics, synthetic fibers and foams. It is also used in the manufacture of polypropylene, which has a variety of end-uses including packaging film, carpet and upholstery fibers and plastic parts for appliances, automobiles, housewares and medical products.

---

(1)	All capacity shown is for 100 percent of the available storage capacity of our butane cavern and tank farms and 100 percent of the barge dock’s average capacity.

---

(1)	We have the operational flexibility to process gas for producer customers at either complex.

(2)	We do not provide gathering services.

---

(1)	The Hopedale Complex is jointly owned by MarkWest Liberty Midstream & Resources, L.L.C (“MarkWest Liberty Midstream”) and MarkWest Utica EMG, which are entities that operate in the Marcellus and Utica regions, respectively. We account for MarkWest Utica EMG as an equity method investment. See discussion in Item 8. Financial Statements and Supplementary Data - Note 5.

---

•	We transport purity ethane produced at the Majorsville Complex and the Sherwood Complex to the Houston Complex on a FERC pipeline. Once operational, purity ethane produced at the Mobley Complex will also be transported on this same FERC pipeline to the Houston Complex.

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

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

•

Sunoco developed the Mariner East project (“Mariner East”), a pipeline and marine project that originates at our Houston Complex. Beginning in December 2014, Mariner East began transporting propane to Sunoco’s terminal near Philadelphia, Pennsylvania (“Marcus Hook Facility”) where it is loaded onto marine vessels and delivered to international markets. By the first quarter of 2016, Mariner East is expected to transport purity ethane in addition to propane to the Marcus Hook Facility.

•

Sunoco has announced phase two of Mariner East (“Mariner East II”) with plans to construct a pipeline from our Houston and Hopedale Complexes in western Pennsylvania and eastern Ohio, respectively, to transport propane and butane to the Marcus Hook Facility where it will be loaded onto marine vessels and delivered to domestic and international markets. The Mariner East II pipeline is expected to be operational in the first half of 2017.

---

(1)	Quarterly commitment for our transportation services agreements in thousands of barrels per day and committed storage capacity for our storage services agreements in thousands of barrels. Volumes shown for crude oil transportation services agreements are adjusted for crude viscosities.

---

•

Omnibus Agreement. As of October 31, 2012, we entered into an omnibus agreement with MPC that addresses our payment of a fixed annual fee to MPC for the provision of executive management services by certain executive officers of our general partner and our reimbursement to MPC for the provision of certain general and administrative services to us, as well as MPC’s indemnification of us for certain matters, including certain environmental, title and tax matters. In addition, we will indemnify MPC for certain matters under this agreement.

•

Employee Services Agreements. We entered into two employee services agreements with MPC, effective October 1, 2012, under which we agreed to reimburse MPC for the provision of certain operational and management services to us in support of our pipelines, barge dock, butane cavern and tank farms. Effective December 28, 2015, we entered into an employee services agreement with MW Logistics Services LLC (“MWLS”), a wholly-owned subsidiary of MPC, under which we agreed to reimburse MWLS for the certain operational and management services to us in support of our G&P segment and certain of our other operations.

•	approximately 5,400 miles of crude oil and product pipelines that MPC owns, leases or in which it has an ownership interest;

•	ownership interest in Southern Access Extension pipeline;

•	19 owned or leased inland towboats and 219 owned or leased inland barges;

•	ownership interest in a blue water joint venture with Crowley Maritime Corporation;

---

•	61 owned and operated light product terminals with approximately 20 million barrels of storage capacity and 187 loading lanes;

•	18 owned and operated asphalt terminals with approximately 4 million barrels of storage capacity and 68 loading lanes;

•	one leased and two non-operated, partially-owned light product terminals;

•	2,210 owned or leased railcars;

•	59 million barrels of tank and cavern storage capacity at its refineries;

•	25 rail and 26 truck loading racks at its refineries;

•	seven owned and 11 non-owned docks at its refineries;

•	condensate splitters at its Canton, Ohio and Catlettsburg, Kentucky refineries; and

•	approximately 20 billion gallons of fuel distribution based on 2015 volumes.

•

Fee-based arrangements - Under fee-based arrangements, we receive a fee or fees for one or more of the following services: transportation and storage of crude oil; gathering, processing and transmission of natural gas; gathering, transportation, fractionation, exchange and storage of NGLs; and gathering and transportation of crude oil. The revenue we earn from these arrangements is generally directly related to the volume of natural gas, NGLs or crude oil that flows through our systems and facilities and is not normally directly dependent on commodity prices. In certain cases, our arrangements provide for minimum annual payments or fixed demand charges.

•

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

•

Keep-whole arrangements - Under keep-whole arrangements, we gather natural gas from the producer, process the natural gas and sell the resulting condensate and NGLs to third parties at market prices. Because the extraction of the condensate and NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the energy content of this natural gas. Certain keep-whole arrangements also have provisions that require us to share a percentage of the keep-whole profits with the producers based on the oil to gas ratio or the NGL to

---

•

Percent-of-index arrangements - Under percent-of-index arrangements, we purchase natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount. We then gather and deliver the natural gas to pipelines where we resell the natural gas at the index price or at a different percentage discount to the index price. Revenue generated from percent-of-index arrangements are reported as Product sales on the Consolidated Statements of Income and are recognized on a gross basis as we purchase and take title to the product prior to sale and are the principal in the transaction.

(1)	Includes condensate sales and other types of arrangements tied to NGL prices.

(2)	Includes condensate sales and other types of arrangements tied to both NGL and natural gas prices.

(3)	Detail on contract types above.

(4)	Includes unconsolidated affiliates (See Item 8. Financial Statements and Supplementary Data - Note 5).

---

•	natural gas midstream providers, of varying financial resources and experience, that gather, transport, process, fractionate, store and market natural gas and NGLs;

•	major integrated oil companies and refineries;

•	medium and large sized independent exploration and production companies; and

•	major interstate and intrastate pipelines.

---

•	a substantial change has occurred since enactment in either the economic circumstances or the nature of the services that were a basis for the rate;

---

•	the complainant was contractually barred from challenging the rate prior to enactment of EPAct 1992 and filed the complaint within 30 days of the expiration of the contractual bar; or

•	a provision of the tariff is unduly discriminatory or preferential.

•	the overall cost of service, including operating costs and overhead;

•	the allocation of overhead and other administrative and general expenses to the regulated entity;

•	the appropriate capital structure to be utilized in calculating rates;

•	the appropriate rate of return on equity and interest rates on debt;

•	the rate base, including the proper starting rate base;

---

•	the throughput underlying the rate; and

•	the proper allowance for federal and state income taxes.

•	rates and rate structures;

•	return on equity;

•	recovery of costs;

•	the services that our regulated assets are permitted to perform;

•	the acquisition, construction, expansion, operation and disposition of assets;

•	affiliate interactions; and

•	to an extent, the level of competition in that regulated industry.

---

---

---

---

---

---

---

---

---

---

---

•

We may have difficulties obtaining additional financing for working capital, capital expenditures, acquisitions or general partnership purposes on favorable terms, if at all, or our cost of borrowing may increase. Our funds available for operations, business opportunities and distributions to unitholders will also be reduced by that portion of our cash flow required to make interest payments on our debt.

•	We may be at a competitive disadvantage compared to our competitors who have proportionately less debt, or we may be more vulnerable to, and have limited flexibility to respond to, competitive pressures or a downturn in our business or the economy generally.

•

If our operating results are not sufficient to service our indebtedness, we may be required to reduce our distributions, reduce or delay our business activities, investments or capital expenditures, sell assets or issue equity, which could materially and adversely affect our financial condition, results of operations, cash flows and ability to make distributions to unitholders, as well as the trading price of our common units.

•

The operating and financial restrictions and covenants in our revolving credit facility and any future financing agreements could restrict our ability to finance our operations or capital needs or to expand or pursue our business activities, which may, in turn, limit our ability to make distributions to our unitholders. Our ability to comply with these covenants may be impaired from time to time if the fluctuations in our working capital needs are not consistent with the timing for our receipt of funds from our operations.

•

If we fail to comply with our debt obligations and an event of default occurs, our lenders could declare the outstanding principal of that debt, together with accrued interest, to be immediately due and payable, which may trigger defaults under our other debt instruments or other contracts. Our assets may be insufficient to repay such debt in full, and the holders of our units could experience a partial or total loss of their investment.

---

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

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

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

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

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

•	prevailing economic conditions.

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

•	our debt service requirements and other liabilities;

•	fluctuations in our working capital needs;

•	our ability to borrow funds and access capital markets;

---

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

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

•	the cost of acquisitions, if any; and

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

---

•	more stringent permitting and other regulatory requirements;

•	a limited supply of qualified fabrication and construction contractors, which could delay or increase the cost of the construction and installation of our facilities or increase the cost of operating our existing facilities;

•	unexpected increases in the volume of oil, natural gas, NGLs and refined products being delivered to our facilities, which could adversely affect our ability to expand our facilities in a manner that is consistent with our customers’ production or delivery schedules;

•	changes in, or inability to meet, downstream gas, NGL, crude oil or refined product pipeline quality specifications, which could reduce the volumes of gas, NGLs, crude oil and refined products that we receive;

•	scheduled maintenance, unexpected outages or downtime at our facilities or at upstream or downstream third‑party facilities, which could reduce the volumes of oil, gas, NGLs and refined products that we receive; and

•

market and capacity constraints affecting downstream oil, natural gas, NGL and refined products facilities, including limited gas and NGL capacity downstream of our facilities, limited railcar and NGL pipeline facilities and reduced demand or limited markets for certain NGL or refined products, which could reduce the volumes of oil, gas, NGLs and refined products that we receive and adversely affect the pricing received for NGLs.

---

---

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

•	currency fluctuations, particularly to the extent sales are denominated in foreign currencies as we do not currently hedge against currency fluctuations;

•	compliance with additional governmental regulations and maritime requirements, including U.S. export controls and foreign laws, sanctions regulations and the Foreign Corrupt Practices Act;

•	risks of loss resulting from non-payment or non-performance by international purchasers; and

•	political and economic disturbances in the countries to which NGLs are being exported.

---

•	operating a significantly larger combined organization and integrating additional operations into ours;

•	difficulties in the assimilation of the assets and operations of the acquired businesses, especially if the assets acquired are in a new business segment or geographical area;

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

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

•	the failure to realize expected synergies and cost savings;

•	coordinating geographically disparate organizations, systems and facilities;

•	integrating personnel from diverse business backgrounds and organizational cultures; and

•	consolidating corporate and administrative functions.

---

---

---

---

•	damage to pipelines, plants, storage facilities, related equipment and surrounding properties caused by floods, hurricanes and other natural disasters and acts of terrorism;

•	inadvertent damage from vehicles and construction and farm equipment;

•	leakage of crude oil, natural gas, NGLs, refined products and other hydrocarbons into the environment, including groundwater;

•	fires and explosions; and

•	other hazards and conditions, including those associated with various hazardous pollutant emissions, high‑sulfur content, or sour gas, and proximity to businesses, homes, or other populated areas, that could also result in personal injury and loss of life, pollution and suspension of operations.

---

•	perform ongoing assessments of pipeline integrity;

•	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

•	improve data collection, integration and analysis;

•	repair and remediate the pipeline as necessary; and

•	implement preventive and mitigating actions.

•	unscheduled turnarounds or catastrophic events, including damages to pipelines and facilities, related equipment and surrounding properties caused by earthquakes, tornadoes, hurricanes, floods, fires, severe weather, explosions and other natural disasters;

•	restrictions imposed by governmental authorities or court proceedings;

•	labor difficulties that result in a work stoppage or slowdown;

•	a disruption in the supply of natural gas, NGLs, crude oil or refined products to our pipelines, processing and fractionation plants and associated facilities;

•	disruption in our supply of power, water and other resources necessary to operate our facilities;

•	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, trucks and pipeline capacity, or market constraints, including reduced demand or limited markets for certain NGL products.

•	the timing and extent of changes in commodity prices and demand for MPC’s products, and the availability and costs of crude oil and other refinery feedstocks;

•	a material decrease in the refining margins at MPC’s refineries;

---

•	the risk of contract cancellation, non-renewal or failure to perform by MPC’s customers, and MPC’s inability to replace such contracts and/or customers;

•	disruptions due to equipment interruption or failure at MPC’s facilities or at third-party facilities on which MPC’s business is dependent;

•	any decision by MPC to temporarily or permanently alter, curtail or shut down operations at one or more of its refineries or other facilities and reduce or terminate its obligations under our transportation and storage services agreements;

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

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

•	changes in the cost or availability of third-party pipelines, terminals and other means of delivering and transporting crude oil, feedstocks, refined products and other hydrocarbon-based products;

•	state and federal environmental, economic, health and safety, energy and other policies and regulations, and any changes in those policies and regulations;

•	environmental incidents and violations and related remediation costs, fines and other liabilities;

•	operational hazards and other incidents at MPC’s refineries and other facilities, such as explosions and fires, that result in temporary or permanent shut downs of those refineries and facilities;

•	changes in crude oil and product inventory levels and carrying costs; and

•	disruptions due to hurricanes, tornadoes or other forces of nature.

---

---

---

---

---

•

neither our partnership agreement nor any other agreement requires MPC to pursue a business strategy that favors us or utilizes our assets, which could involve decisions by MPC to increase or decrease refinery production, shut down or reconfigure a refinery, or pursue and grow particular markets. MPC’s directors and officers have a fiduciary duty to make these decisions in the best interests of the stockholders of MPC;

•	MPC, as a significant customer, has an economic incentive to cause us to not seek higher tariff rates, even if such higher rates or fees would reflect rates and fees that could be obtained in arm’s-length, third-party transactions;

•	MPC may be constrained by the terms of its debt instruments from taking actions, or refraining from taking actions, that may be in our best interests;

•	our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner’s liabilities and restricting the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty;

•	except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

•	our general partner will determine the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of cash reserves, each of which can affect the amount of cash that is distributed to our unitholders;

•

our general partner will determine the amount and timing of many of our cash expenditures and whether a cash expenditure is classified as an expansion capital expenditure, which would not reduce operating surplus, or a maintenance capital expenditure, which would reduce our operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the amount of adjusted operating surplus generated in any given period;

•	our general partner will determine which costs incurred by it are reimbursable by us and may cause us to pay it or its affiliates for any services rendered to us;

•	our general partner may cause us to borrow funds in order to permit the payment of distributions, even if the borrowing is to allow us to pay the general partner’s incentive distribution rights;

•	our partnership agreement permits us to classify up to $60.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of the general partner interest or the incentive distribution rights;

•	our partnership agreement does not restrict our general partner from entering into additional contractual arrangements with it or its affiliates on our behalf;

•	our general partner intends to limit its liability regarding our contractual and other obligations;

•	our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if it and its affiliates own more than 85 percent of the common units;

•	our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including our transportation and storage services agreements with MPC;

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

•

our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner, which we refer to as our conflicts committee, or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

---

•

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

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

•

provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

---

•	provides that our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.

---

•	our unitholders’ proportionate ownership interest in us will decrease;

•	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.

---

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

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

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

---

(1)	Capacity shown is 100 percent of the capacity of these pipeline systems.

(2)	Capacity not shown, as the pipeline is designed to meet outgoing capacity for connecting third-party pipelines.

(3)	Consists of two separate approximately 8.5-mile pipelines.

(4)	This pipeline is bi-directional.

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

---

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

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

(1)	All capacity shown is for 100 percent of the available storage capacity of our butane cavern and tank farms and 100 percent of the barge dock’s average capacity.

---

(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)	Natural gas throughput includes volumes from December 4, 2015 to December 31, 2015.

(3)	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.

(4)	The Kermit processing plant is operated by a third party solely to prevent liquids from condensing in the gathering and transmission pipelines upstream of our Kenova plant. We do not receive Kermit gas volume information but do receive all of the liquids produced at the Kermit Complex. As such, the design capacity has been excluded from the subtotal.

(5)	Centrahoma processing capacity of 300,000 mmcf/d is 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)	NGL throughput includes volumes from December 4, 2015 to December 31, 2015.

(3)

Our Houston, Hopedale and Keystone Complexes have above ground NGL storage with a usable capacity of 26 million gallons, large-scale truck and rail loading. In addition, our Houston Complex has large-scale truck unloading. We also have access to up to an additional 50 million gallons of propane storage capacity that can be utilized by our assets in the Marcellus Shale, Utica Shale, and Appalachia region under an agreement with a third party that expires in 2018. Lastly, we have up to nine million gallons of butane storage and 11 million gallons of propane storage with third parties that can be utilized by our assets in the Marcellus Shale and Utica Shale.

(4)	Includes 33 mbpd of de-propanization only capacity.

(5)	Our Hopedale System is jointly owned by MarkWest Liberty Midstream and MarkWest Utica EMG, respectively. We account for MarkWest Utica EMG as an equity method investment. See discussion in Item 8. Financial Statements and Supplementary Data - Note 5.

(6)	The Ohio Condensate Complex has up to seven million gallons of condensate storage. The Ohio Condensate Complex is partially owned by MarkWest Utica EMG Condensate. We account for Ohio Condensate as an equity method investment. See discussion in Item 8. Financial Statements and Supplementary Data - Note 5.

(7)

Our Siloam Complex has both above ground, pressurized NGL storage facilities, with usable capacity of two million gallons, and underground storage facilities, with usable capacity of 10 million gallons. Product can be received by truck, pipeline or rail and can be transported from the facility by truck, rail or barge. This facility has large-scale truck and rail loading and unloading capabilities, and a river barge facility capable of loading barges up to 840,000 gallons.

---

(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)	NGL throughput includes volumes from December 4, 2015 to December 31, 2015.

(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)	Natural gas throughput includes volumes from December 4, 2015 to December 31, 2015.

---

(3)	The Ohio Gathering System is owned by Ohio Gathering. We account for Ohio Gathering as an equity method investment. See discussion in Item 8. Financial Statements and Supplementary Data - Note 5.

(4)	The Jefferson Gas System is owned by 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.

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

(1)	NGL throughput includes volumes from December 4, 2015 to December 31, 2015.

(2)	This pipeline is FERC-regulated.

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

(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.

---

---

---

---

(1)	Represents cash distributions attributable to the quarter and declared and paid in accordance with our partnership agreement.

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

•	provide for the proper conduct of our business (including reserves for our future capital expenditures, anticipated future debt service requirements and refunds of collected rates reasonably likely to be refunded as a result of a settlement or hearing related to FERC rate proceedings or rate proceedings under applicable law subsequent to that quarter);

---

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

•

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

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

(1)	The unitholders’ percentage of distributions is paid to common unitholders, subordinated unitholders, if any, and Class A unitholders on a pro rata basis except that Class A units will not be entitled to participate in any distributions of available cash derived from or attributable to MPLX LP’s ownership interest of MarkWest Hydrocarbon or the disposition of such interest.

---

---

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

(2)

For a discussion of the non-GAAP financial measures of Adjusted EBITDA and DCF and a reconciliation of Adjusted EBITDA and DCF to our most directly comparable measures calculated and presented in accordance with GAAP, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Non-GAAP Financial Information and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations.

(3)	The 2012 Adjusted EBITDA attributable to MPLX LP is subsequent to the Initial Offering. The 2015 Adjusted EBITDA attributable to MPLX LP includes pre-merger EBITDA from MarkWest and the 2015 DCF attributable to MPLX LP includes undistributed DCF from MarkWest. See Item 7. Management’s Discussion and Analysis - Results of Operations for a reconciliation of non-GAAP measures.

(1)

Represents the average aggregate daily number of barrels of crude oil transported on our pipeline systems and at our Wood River barge dock for MPC and for third parties. Volumes shown are 100 percent of the volumes transported on the pipeline systems and barge dock. Volumes shown for all periods exclude volumes transported on two undivided joint interest crude oil pipeline systems not contributed to MPLX LP at the Initial Offering.

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

(3)

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

(4)	G&P volumes represent the volumes after the close of the MarkWest Merger. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for full year pro-forma information.

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

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

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

(8)	The Sherwood de-ethanization complex came online in December 2015. The volumes reported for 2015 are the average daily rate for the days of operation.

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

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

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

(12)	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.

---

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

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

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

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

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

•

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

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

•

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

•

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

---

---

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

---

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

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

(1)	These amounts relate to Partnership operated unconsolidated affiliates. The chief operating decision maker and management include these to evaluate the segment performance as we continue to operate and manage the operations. Therefore, the impact of the revenue is included for segment reporting purposes, but removed for GAAP purposes.

---

---

---

---

---

---

---

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

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

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

(4)

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

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

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

(7)	C2 + NGL pricing based on Mont Belvieu prices assuming an NGL barrel of approximately 35 percent ethane, 35 percent propane, 6 percent Iso-Butane, 12 percent normal butane and 12 percent natural gasoline.

---

---

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

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

---

---

(1)	Outstanding borrowings includes $8 million in letters of credit outstanding under this facility.

---

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

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

---

(1)	Amounts represent outstanding borrowings at December 31, 2015 plus any commitment and administrative fees and interest.

(2)	Amounts relate primarily to a long-term propane storage agreement and our office and vehicle leases.

(3)

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

(4)

Natural gas purchase obligations consist primarily of a purchase agreement with a producer in our Southern Appalachia operations. The contract provides for the purchase of keep-whole volumes at a specific price and is a component of a broader regional arrangement. The contract price is designed to share a portion of the frac spread with the producer and as a result, the amounts reflected for the obligation exceed the cost of purchasing the keep-whole volumes at a market price. The contract is considered an embedded derivative (see Item 8. Financial Statements and Supplementary Data - Note 15 for the fair value of the frac spread sharing component). We use the estimated future frac spreads as of December 31, 2015 for calculating this obligation. The counterparty to the contract has the option to renew the gas purchase agreement and the related keep-whole processing agreement for two successive five-year terms after 2022, which is not included in the natural gas purchase obligations line item.

---

(5)	Represents amounts due under a product supply agreement (see Item 8. Financial Statements and Supplementary Data -Note 22 for further discussion of the product supply agreement).

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

(7)	Represents the payable for Class B units recorded in connection with the MarkWest Merger (see Item 8. Financial Statements and Supplementary Data - Note 4 for further discussion).

(8)	Excludes estimated accretion expense of $20 million. The total amount to be paid is approximately $37 million.

---

---

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

---

---

---

---

---

---

---

---

(1)	Fair value of the variable-rate debt approximates carrying value since the debt was recorded at fair value as of December 4, 2015, the date of the MarkWest Merger.

---

(2)	Assumes a 100-basis-point change in interest rates. The change to income before income taxes was based on the weighted average balance of debt outstanding for the year ended December 31, 2015.

---

---

---

---

---

---

---

---

---

•	Product sales – Product sales represent the sale of NGLs, condensate and natural gas. The product is primarily obtained as consideration for or related to providing midstream services.

•	Service revenue – Service revenue represents all other revenue generated as the result of performing the services listed above.

•

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

◦

Fee-based arrangements are reported as Service revenue on the Consolidated Statements of Income. In certain instances when specifically stated in the contract terms, the Partnership purchases product after fee-based services have been provided. Revenue from the sale of products purchased after services are provided is reported as Product sales and recognized on a gross basis as the Partnership is the principal in the transaction.

•

Percent-of-proceeds arrangements – Under percent-of-proceeds arrangements, the Partnership gathers and processes natural gas on behalf of producers, sells the resulting residue gas, condensate and NGLs at market prices and remits to producers an agreed-upon percentage of the proceeds. In other cases, instead of remitting cash payments to the producer, the Partnership delivers an agreed-upon percentage of the residue gas and NGLs to the producer (take-in-kind arrangements) and sells the volumes the Partnership retains to third parties. Revenue from these arrangements is reported on a gross basis where the Partnership acts as the principal, as the Partnership has physical inventory risk and does not earn a fixed dollar amount. The agreed-upon percentage paid to the producer is reported as Purchased product costs on the Consolidated Statements of Income. Revenue is recognized on a net basis when the Partnership acts as an agent and earns a fixed dollar amount of physical product and does not have risk of loss of the gross amount of gas and/or NGLs. Percent-of-proceeds revenue is reported as Product sales on the Consolidated Statements of Income.

•

Keep-whole arrangements – Under keep-whole arrangements, the Partnership gathers natural gas from the producer, processes the natural gas and sells the resulting condensate and NGLs to third parties at market prices. Because the extraction of the condensate and NGLs from the natural gas during processing reduces the Btu content of the natural gas, the Partnership must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the energy content of this natural gas. Certain keep-whole arrangements also have provisions that require the Partnership to share a percentage of the keep-whole profits with the producers based on the oil to gas ratio or the NGL to gas ratio. Sales of NGLs under these arrangements are reported as Product sales on the

---

•

Percent-of-index arrangements – Under percent-of-index arrangements, the Partnership purchases natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount. The Partnership then gathers and delivers the natural gas to pipelines where the Partnership resells the natural gas at the index price or at a different percentage discount to the index price. Revenue generated from percent-of-index arrangements are reported as Product sales on the Consolidated Statements of Income and are recognized on a gross basis as the Partnership purchases and takes title to the product prior to sale and is the principal in the transaction.

---

---

---

•	Level 1-inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

•	Level 2-inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

•	Level 3-inputs to the valuation methodology are unobservable and significant to the fair value measurement.

---

---

---

---

---

---

---

---

(1)	MarkWest Utica EMG’s noncurrent assets includes its investment in its subsidiary Ohio Gathering, which does not appear elsewhere in this table. The investment was $781 million as of December 31, 2015.

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

•	Centennial Pipeline LLC (“Centennial”), in which MPC has a 50 percent interest. Centennial owns a products pipeline and storage facility.

•	Muskegon Pipeline LLC (“Muskegon”), in which MPC has a 60 percent interest. Muskegon owns a common carrier products pipeline.

---

•	MarkWest Utica EMG, in which MPLX has a 60 percent interest. MarkWest Utica EMG is engaged in significant natural gas processing and NGL fractionation, transportation and marketing in eastern Ohio.

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

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

•	Ohio Condensate, in which MPLX has a 60 percent interest. Ohio Condensate is engaged in wellhead condensate gathering, stabilization, terminalling, transportation and storage within certain defined areas of Ohio.

•	three separate 10-year transportation services agreements and one five-year transportation services agreement under which MPC pays the Partnership fees for transporting crude oil on various of our crude oil pipeline systems;

•	four separate 10-year transportation services agreements under which MPC pays the Partnership fees for transporting products on each of our refined product pipeline systems;

•	a five-year transportation services agreement under which MPC pays the Partnership fees for handling crude oil and products at our Wood River, Illinois barge dock;

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

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

---

---

---

---

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

---

---

---

---

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

•	G&P - gathers, processes and transports natural gas; gathers, transports, fractionates, stores and markets NGLs. This segment is the result of the MarkWest Merger on December 4, 2015 discussed in more detail in Note 4. Segment information for periods prior to the MarkWest Merger does not include amounts for these operations.

---

---

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

---

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

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

---

---

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

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

(3)

The producer counterparty to the embedded derivative has the option to renew the gas purchase agreement and the related keep-whole processing agreement for two successive five-year terms after 2022. The embedded gas purchase agreement cannot be renewed without the renewal of the related keep-whole processing agreement. Due to the significant number of years until the renewal options are exercisable and the high level of uncertainty regarding the counterparty’s future business strategy, the future commodity price environment, and the future competitive environment for midstream services in the Southern Appalachian region, management determined that a 50 percent probability of renewal for the first five-year term and 75 percent for the second five-year term are appropriate assumptions. Included in this assumption is a further extension of management’s estimates of future frac spreads through 2032.

---

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

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

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

(1)	Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in Product sales in the accompanying Consolidated Statements of Income. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in Costs of revenue and Purchased product costs.

---

---

---

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

---

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

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

---

---

---

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

(1)	See Note 4.

---

---

---

---

---

---

---

---

(1)	These amounts include results from the MarkWest Merger which closed on December 4, 2015. See Note 4 for more information on the MarkWest Merger.

---

---

---

---

(1)	Corporate officer.

---

---

---

---

---

---

---

•	act with honesty and integrity, including the ethical handling of actual or apparent conflicts of interest between personal and professional relationships;

•	provide full, fair, accurate, timely and understandable disclosure in reports and documents filed with, or submitted to, the SEC, and in other public communications;

•	comply with applicable laws, governmental rules and regulations, including insider trading laws; and

•	promote the prompt internal reporting of potential violations or other concerns related to this code of ethics to the chair of the audit committee and to the appropriate person or persons identified in the code of business conduct.

---

---

---

•	Nancy K. Buese - Executive Vice President and Chief Financial Officer

•	C. Corwin Bromley - Executive Vice President, General Counsel (Chief Legal Officer) and Secretary

•	Gregory S. Floerke - Executive Vice President and Chief Commercial Officer, MarkWest Assets; and

•	John C. Mollenkopf - Executive Vice President and Chief Operating Officer, MarkWest Operations

•	Retention Award - The values of the Retention Awards are set out below:

•	Nancy K. Buese - $1,808,900

•	C. Corwin Bromley - $1,746,800

•	Gregory S. Floerke - $1,268,234

•	John C. Mollenkopf - $1,992,160

•	Nancy K. Buese - $79,574.73

•	C. Corwin Bromley - $76,843.80

•	Gregory S. Floerke - $55,790.72

•	John C. Mollenkopf - $87,637.92

•	2016 Long-Term Incentive Award - We agreed to accelerate the MW NEOs’ 2016 long-term incentive award to December 2015, and, as such, they will not receive long-term incentive awards in calendar year 2016. These awards have intended values as listed below:

---

•	Nancy K. Buese - $1,462,500

•	C. Corwin Bromley - $855,000

•	Gregory S. Floerke - $880,000

•	John C. Mollenkopf - $2,040,000

•

Retention Bonus Award - To further incentivize the MW NEOs to continue to provide services to us, MPC or one of its subsidiaries for at least three years after the MarkWest Merger, additional grants of equity were made to the MW NEOs in the form of MPC restricted stock with a grant date value of $1,000,000. These awards will vest on the third anniversary of the grant, subject to earlier vesting in full upon resignation following a Relocation Event or upon such other events for which MPC typically provides in its award agreements. Dividends associated with this grant are accrued and paid upon vesting.

•	MarkWest Distributable Cash Flow(1) for 2015 (50%);

•	MarkWest Distributable Cash Flow per unit for 2015 (25%);

---

•	MarkWest Discretionary Factors (25%) which included:

◦	Customer satisfaction;

◦	Leadership development;

◦	Volumes relative to MarkWest 2015 annual plan;

◦	Capex management relative to the MarkWest 2015 annual plan;

◦	Debt/EBITDA(2) metric relative to the MarkWest 2015 annual plan; and

◦	Environmental and safety performance.

(1)

This is a non-GAAP performance metric. MarkWest calculated Distributable Cash Flow as net income (loss) adjusted for (i) depreciation, amortization, and other non-cash expenses; (ii) amortization of deferred financing costs and debt discount; (iii) loss on redemption of debt, net of tax benefit; (iv) impairment expense; (v) non-cash (earnings) loss from unconsolidated affiliates; (vi) distributions from (contributions to) unconsolidated affiliates (net of affiliates growth capital expenditures); (vii) non-cash compensation expense; (viii) non-cash derivative activity; (ix) loss (gain) on the sale or disposal of property, plant and equipment (PP&E); (x) provision for deferred income taxes; (xi) cash adjustments for noncontrolling interest in consolidated subsidiaries; (xii) revenue deferral adjustment; (xiii) losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the period; and (xiv) maintenance capital.

(2)

This is a non-GAAP performance metric. MarkWest calculated Adjusted EBITDA as net income (loss) adjusted for (i) depreciation, amortization and other non-cash operating expenses; (ii) interest expense; (iii) amortization of deferred financing costs and debt discount; (iv) loss on redemption of debt; (v) loss (gain) on the sale or disposal of PP&E; (vi) impairment of unconsolidated affiliates; (vii) gain on sale of unconsolidated affiliate; (viii) impairment expense; (ix) non-cash derivative activity; (x) non-cash compensation expense; (xi) provision for income tax (benefit); (xii) adjustments for cash flow from unconsolidated affiliates; (xiii) cash adjustment for noncontrolling interest of consolidated subsidiaries; and (xiv) losses (gains) relating to other miscellaneous non-cash amounts affecting net income for the period.

(1)	The final award is rounded to the next $1,000.

---

*	Payout for performance between quartiles will be determined using linear interpolation.

---

---

•	based on the executive’s position and responsibilities, and

•	expected to be reached within five years of the executive officer’s assumption of the position.

•	Chairman of the Board and Chief Executive Officer – 25,000 units;

•	President – 20,000 units;

•	Executive Vice President – 15,000 units;

•	Senior Vice President – 10,000 units; and

•	Vice President - 5,000 units.

---

•	knowingly engaged in misconduct;

•	was grossly negligent with respect to misconduct;

•	knowingly failed or was grossly negligent in failing to prevent misconduct; or

•	engaged in fraud, embezzlement or other similar misconduct materially detrimental to us.

---

(1)	The amounts shown in this column reflect the annualized fixed fee for Messrs. Heminger and Templin for 2015, 2014 and 2013 and for Mr. Griffith for 2015. The amounts listed for the MW NEOs are salaries paid by MPLX LP while they were employed by MarkWest Hydrocarbon.

(2)

The amounts shown in this column reflect the aggregate grant date fair value in accordance with provisions of the Financial Accounting Standards Board Accounting Standards Codification 718, Compensation - Stock Compensation (FASB ASC Topic 718.) See Item 8. Financial Statements and Supplementary Data - Note 19 for assumptions used in the calculation of the amounts related to MPLX equity. Assumptions used in the calculation of the MPC equity value are included in footnote 23 to the Company’s financial statements as reported on Form 10-K for the fiscal year ended December 31, 2015. The maximum value of the performance units reported in the “Unit Awards” column assuming the highest level of performance is achieved for Messrs. Heminger, Griffith and Templin for 2015 is $2,200,000, $360,000 and $500,000, respectively; for Messrs. Heminger and Templin for 2014 is $2,000,000 and $440,000, respectively and for Messrs. Heminger and Templin for 2013 is $1,800,000 and $420,000, respectively.

---

(1)	The target amounts shown in this column reflect the number of performance units granted to each of our NEOs, and each unit has a target value of $1.00.

(2)

The amounts shown in this column reflect the total grant date fair value of performance units and phantom units granted in 2015 in accordance with FASB ASC Topic 718. Performance units are designed to settle 25 percent in MPLX common units and 75 percent in cash. The performance unit awards with a grant date of March 1, 2015 have a grant date fair value of $1.0355 per unit as calculated using a Monte Carlo valuation model. See Item 8. Financial Statements and Supplementary Data - Note 19 for assumptions used in the calculation of these amounts. The phantom unit value is based on the MPLX closing unit price on the grant date, or the next business day if the grant date is not a business day. The prices used for the March 1, 2015 and December 18, 2015 grants of phantom unit awards, were $82.22 per unit and $33.24 per unit, respectively. The restricted stock value was based on the MPC closing stock price on the grant date listed, or the next business day if the grant date is not a business day. The price used for the December 18, 2015 grants of restricted stock awards was $50.35 per share.

---

(1)

The amounts shown in this column reflect the number of unvested MPLX phantom units held by each of our NEOs on December 31, 2015. Phantom unit grants generally are scheduled to vest in one-third increments on the first, second and third anniversaries of the grant date. It also includes unvested shares of MPC restricted stock granted to MW NEOs as part of their retention grants as previously discussed in the “Retention Agreements with Former MarkWest Executives” section. MPC restricted stock grants are scheduled to vest in full on the third anniversary of the grant date.

---

(2)

The amounts shown in this column reflect the aggregate value of all unvested MPLX phantom units held by each of our NEOs on December 31, 2015, using the MPLX common unit closing price of $39.33 per unit. It also includes the value of unvested shares of MPC restricted stock granted to MW NEOs as part of their retention grants as previously discussed in the “Retention Agreements with Former MarkWest Executives” section. These are valued using the MPC closing price on December 31, 2015 of $51.84 per share.

(3)

The amounts shown in this column reflect the number of unvested performance units held by Messrs. Heminger, Griffith and Templin on December 31, 2015. Performance unit grants awarded in 2015 have a 36-month performance cycle and are designed to settle 25 percent in MPLX common units and 75 percent in cash. Each of these performance unit grants has a target value of $1.00 and payout may vary from $0.00 to $2.00 per unit. Payout is tied to our TUR as compared to specified peer groups.

---

(4)	The amounts shown in this column reflect the aggregate value of all performance units held by Messrs. Heminger, Griffith and Templin on December 31, 2015 assuming a payout of $1.20 per unit for the 2014 grant and $0.50 per unit for the 2015 grant, which is the next higher performance achievement that exceeds the performance for these grants' performance period ended December 31, 2015.

(1)	This column reflects the actual pre-tax gain realized by Messrs. Heminger, Griffith and Templin upon vesting of phantom units, which is the fair market value of the units on the date of vesting.

---

•	50 percent in the form of a cash retainer, payable in equal quarterly installments of $18,750 (at the commencement of each calendar quarter); and

•

50 percent in the form of a phantom unit award (granted at the commencement of each calendar quarter) representing a number of units having a value (based on the closing price of our common units on the date of grant) equal to $18,750. The phantom unit awards are not subject to any risk of forfeiture once granted and are automatically deferred until and settled in common units at the time the non-management director separates from service on the board or upon his or her death, if earlier.

•	Audit Committee Chair – $15,000;

•	Conflicts Committee Chair – $15,000;

•	Lead Director & Executive Committee Member - $15,000; and

•	Other Committee Chair – $7,500.

(1)	The amounts shown in this column reflect the director cash retainers and committee chair and lead director fees paid for service from January 1, 2015, through December 31, 2015.

(2)

The amounts shown in this column reflect the aggregate grant date fair value, as computed in accordance with provisions of Financial Accounting Standards Board Accounting Standards Codification 718, Compensation - Stock Compensation (“FASB ASC Topic 718”), for phantom unit awards granted to the non-management directors in 2015. All phantom unit awards are deferred until departure from the board and distribution equivalents in the form of additional phantom unit awards are credited to non-management director deferred accounts as and when distributions are paid on our common units. The aggregate number of MPLX phantom unit awards credited for board service and outstanding as of December 31, 2015, for each non-employee director is as follows: Messrs. Daberko, Helms, Sandman, Surma, and Wilson, 4,804; Mr. Peiffer, 2,506; Mr. Beatty, 172.

(3)	The amounts shown in this column reflect contributions made on behalf of Messrs. Helms and Sandman to educational institutions under our matching gifts program.

---

(1)

The 56,932,134 common units representing limited partner interests (“Common Units”) are directly held by MPLX Logistics Holdings LLC. The 6,800,475 general partner units are directly held by MPLX GP LLC and represent its two percent general partner interest in MPLX LP. Marathon Petroleum Corporation is the ultimate parent company of MPLX GP LLC and MPLX Logistics Holdings LLC and may be deemed to beneficially own the Common Units directly held by MPLX Logistics Holdings LLC, and the general partner units directly owned by MPLX GP LLC. MPC Investment owns all of the membership interests in both MPLX GP LLC and MPLX Logistics Holdings, and MPC owns all of the membership interest in MPC Investment.

(2)

Percentages in this column were calculated excluding the Class A units and including the Class B units on an as-converted basis. All of the Class A units are owned by MarkWest Hydrocarbon, a wholly-owned subsidiary of the Partnership. All of the 7,981,756 Class B units currently outstanding are owned by M&R MWE Liberty LLC and will convert into approximately 8.7 million Common Units in two equal installments on July 1, 2016, and July 1, 2017.

(3)

According to a Schedule 13G/A filed with the SEC on February 9, 2016, by Tortoise Capital Advisors, L.L.C. (“TCA”). According to such Schedule 13G/A, TCA acts as an investment adviser to certain investment companies registered under the Investment Company Act of 1940. TCA, by virtue of investment advisory agreements with these investment companies, has all investment and voting power over securities owned of record by these investment companies. However, despite their delegation of investment and voting power to TCA, these investment companies may be deemed to be the beneficial owners under Rule 13d-3 of the Act, of the securities they own of record because they have the right to acquire investment and voting power through termination of their investment advisory agreement with TCA. Thus, TCA has reported that it shares voting power and dispositive power over the securities owned of record by these investment companies. TCA also acts as an investment adviser to certain managed accounts. Under contractual agreements with managed account clients, TCA, with respect to the securities held in the client managed accounts, has investment and voting power with respect to certain client accounts, and has investment power but no voting power with respect to certain other client accounts. TCA has reported that it shares voting and/or investment power over the securities held by these client managed accounts despite a delegation of voting and/or investment power to TCA because the clients have the right to acquire investment and voting power through termination of their agreements with TCA. TCA may be deemed the beneficial owner of the securities covered by this statement under Rule 13d-3 of the Act that are held by its clients. Subject to the above, TCA reported that it has sole voting power over 297,106 of our Common Units, shared voting power over

---

(4)

According to a Schedule 13G filed with the SEC on February 3, 2016, by ALPS Advisors, Inc. (“AAI”) and Alerian MLP ETF. According to such Schedule 13G, AAI, an investment adviser registered under Section 203 of the Investment Advisors Act of 1940, furnishes investment advice to investment companies registered under the Investment Company Act of 1940 (collectively referred to as the “Funds”). In its role as investment advisor, AAI has voting and/or investment power over our Common Units that are owned by the Funds, and may be deemed to be the beneficial owner of our Common Units held by the Funds. However, all of our Common Units are owned by the Funds. AAI disclaims beneficial ownership of such securities. In addition, the filing of such Schedule 13G shall not be construed as an admission that the reporting person or any of its affiliates is the beneficial owner of any securities covered by such Schedule 13G for any other purposes than Section 13(d) of the Securities Exchange Act of 1934. Alerian MLP ETF is an investment company registered under the Investment Company Act of 1940 and is one of the Funds to which AAI provides investment advice. Subject to the above, AAI reported that it has sole voting power over none of our Common Units, shared voting power over 16,813,973 of our Common Units, sole dispositive power over none of our Common Units and shared dispositive power over 16,813,973 of our Common Units. Subject to the above, and according to the Schedule 13G, Alerian MLP ETF reported that it beneficially owns 16,677,671 of our Common Units, has sole voting power over none of our Common Units, shared voting power over 16,677,671 of our Common Units, sole dispositive power over none of our Common Units and shared dispositive power over 16,677,671 of our Common Units.

(1)	None of the common units reported in this column are pledged as security.

(2)	Includes common units directly or indirectly held in beneficial form.

(3)	Includes phantom unit awards granted pursuant to the MPLX LP 2012 Incentive Compensation Plan and credited within a deferred account pursuant to the Marathon Petroleum Corporation Deferred Compensation Plan for Non-Employee Directors. The aggregate number of phantom unit awards credited as of January 31, 2016, for each of Messrs. Daberko and Surma is 1,105.

---

(4)

Includes phantom unit awards granted pursuant to the MPLX LP 2012 Incentive Compensation Plan and credited within a deferred account pursuant to the MPLX GP LLC Non-Management Director Compensation Policy and Director Equity Award Terms. The aggregate number of phantom unit awards credited as of January 31, 2016, for the non-management directors of our general partner is as follows: Messrs. Daberko, Helms, Sandman, Surma and Wilson, 5,282 each; Mr. Peiffer, 2,983; and Mr. Beatty, 649.

(5)	Includes phantom unit awards granted pursuant to the MPLX LP 2012 Incentive Compensation Plan, which may be forfeited under certain conditions.

(6)	Includes common units indirectly beneficially owned in trust. The number of common units held in trust as of January 31, 2016, by each applicable director or named executive officer of our general partner is as follows: Mr. Heminger, 26,750; Mr. Semple, 377,952; and Mr. Peiffer, 31,697.

(7)	Includes common units issued in settlement of performance units within sixty days of January 31, 2016.

*	The percentage of common units beneficially owned by each director or each executive officer of our general partner does not exceed one percent of the common units outstanding, and the percentage of common units beneficially owned by all directors and executive officers of our general partner as a group does not exceed one percent of the common units outstanding.

(1)	None of the shares of common stock reported in this column are pledged as security.

(2)	Includes shares of common stock directly or indirectly held in registered or beneficial form.

(3)

Includes restricted stock unit awards granted pursuant to the Second Amended and Restated Marathon Petroleum Corporation 2011 Incentive Compensation Plan and/or the Marathon Petroleum Corporation 2012 Incentive Compensation Plan, and credited within a deferred account pursuant to the Marathon Petroleum Corporation Deferred Compensation Plan for Non-Employee Directors. The aggregate number of restricted stock unit awards credited as of January 31, 2016, for each of Messrs. Daberko and Surma are 133,224 and 23,300, respectively.

(4)	Includes shares of restricted stock issued pursuant to the Marathon Petroleum Corporation 2012 Incentive Compensation Plan, which are subject to limits on sale and transfer, and may be forfeited under certain conditions.

(5)	Includes shares of common stock held within the Marathon Petroleum Thrift Plan.

(6)	Includes shares of common stock held within the Marathon Petroleum Corporation Dividend Reinvestment and Direct Stock Purchase Plan.

---

(7)	Includes shares of common stock indirectly beneficially owned in trust. The number of shares held in trust as of January 31, 2016, by each applicable director or named executive officer of our general partner is as follows: Mr. Heminger, 21,228; Mr. Peiffer, 63,394; and Mr. Surma, 10,000.

(8)	Includes stock options exercisable within sixty days of January 31, 2016, including 127,604 stock options exercisable by the applicable directors and named executive officers but not in the money as of January 31, 2016.

(9)	Includes shares of common stock issued in settlement of performance units within sixty days of January 31, 2016.

*	The percentage of shares beneficially owned by each director or each executive officer of our general partner does not exceed one percent of the MPC common shares outstanding, and the percentage of shares beneficially owned by all directors and executive officers of our general partner as a group does not exceed one percent of the MPC common shares outstanding.

(1)	Includes the following:

(a)	1,031,219 phantom unit awards granted pursuant to the MPLX 2012 Plan for common units unissued and not forfeited, cancelled or expired as of December 31, 2015.

(b)

77,366 units as the maximum potential number of common units that could be issued in settlement of performance units outstanding as of December 31, 2015, pursuant to the MPLX 2012 Plan based on the closing price of our common units on December 31, 2015, of $39.33 per unit. The number of units reported for this award vehicle may overstate dilution. See Item 8. Financial Statements and Supplementary Data - Note 19 for more information on performance unit awards granted under the MPLX 2012 Plan.

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

(3)

Reflects the common units available for issuance pursuant to the MPLX 2012 Plan. The number of units reported in this column assumes 77,366 as the maximum potential number of common units that could be issued in settlement of performance units outstanding as of December 31, 2015 pursuant to the MPLX 2012 Plan based on the closing price of our common units on December 31, 2015, of $39.33 per unit. The number of units assumed for this award vehicle may understate the number of common units available for issuance pursuant to the MPLX 2012 Plan. See Item 8. Financial Statements and Supplementary Data - Note 19 for more information on performance unit awards issued pursuant to the MPLX 2012 Plan.

---

---

---

---

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

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

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

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

(1)

The Partnership’s Pre-Approval of Audit, Audit-Related, Tax and Permissible Non-Audit Services Policy is summarized in this Annual Report on Form 10-K. See “Audit Committee Policy for Pre-Approval of Audit, Audit-Related, Tax and Permissible Non-Audit Services.” In 2015 and 2014, all of these services were pre-approved by the Audit Committee of our general partner in accordance with its pre-approval policy. Our Audit Committee did not utilize the Policy’s de minimis exception in 2015 or 2014.

---

---

---

---

---

---

---

---

---

†	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.

---

---

*	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.