Bank of America Merrill Lynch 2017 Refining Conference Tim Griffith, Senior Vice President and CFO

March 2, 2017

Forward‐Looking Statements

2

This presentation contains forward-looking statements within the meaning of federal securities laws regarding Marathon Petroleum Corporation ("MPC") and MPLX LP ("MPLX"). These forward-looking statements relate to, among other things, expectations, estimates and projections concerning the business and operations of MPC and MPLX, including proposed strategic initiatives. You can identify forward-looking statements by words such as "anticipate," "believe," "design," "estimate," "expect," "forecast," "goal," "guidance," "imply," "intend," "objective," "opportunity," "outlook," "plan," "position," "pursue," "prospective," "predict," "project," "potential," "seek," "strategy," "target," "could," "may," "should," "would," "will" or other similar expressions that convey the uncertainty of future events or outcomes. Such forward-looking statements are not guarantees of future performance and are subject to risks, uncertainties and other factors, some of which are beyond the companies' control and are difficult to predict. Factors that could cause MPC's actual results to differ materially from those implied in the forward-looking statements include: the time, costs and ability to obtain regulatory or other approvals and consents and otherwise consummate the strategic initiatives discussed herein; the satisfaction or waiver of conditions in the agreements governing the strategic initiatives discussed herein; our ability to achieve the strategic and other objectives related to the strategic initiatives discussed herein; adverse changes in laws including with respect to tax and regulatory matters; inability to agree with the MPLX conflicts committee with respect to the timing of and value attributed to assets identified for dropdown; changes to the expected construction costs and timing of projects; continued/further volatility in and/or degradation of market and industry conditions; the availability and pricing of crude oil and other feedstocks; slower growth in domestic and Canadian crude supply; completion of pipeline capacity to areas outside the U.S. Midwest; consumer demand for refined products; transportation logistics; the reliability of processing units and other equipment; MPC's ability to successfully implement growth opportunities; modifications to MPLX earnings and distribution growth objectives, and other risks described below with respect to MPLX; compliance with federal and state environmental, economic, health and safety, energy and other policies and regulations, including the cost of compliance with the Renewable Fuel Standard, and/or enforcement actions initiated thereunder; changes to MPC's capital budget; other risk factors inherent to MPC's industry; and the factors set forth under the heading "Risk Factors" in MPC's Annual Report on Form 10-K for the year ended Dec. 31, 2016, filed with Securities and Exchange Commission (SEC). Factors that could cause MPLX's actual results to differ materially from those implied in the forward-looking statements include: negative capital market conditions, including a persistence or increase of the current yield on common units, which is higher than historical yields, adversely affecting MPLX's ability to meet its distribution growth guidance; the time, costs and ability to obtain regulatory or other approvals and consents and otherwise consummate the strategic initiatives discussed herein and other proposed transactions; the satisfaction or waiver of conditions in the agreements governing the strategic initiatives discussed herein and other proposed transactions; our ability to achieve the strategic and other objectives related to the strategic initiatives discussed herein and other proposed transactions; adverse changes in laws including with respect to tax and regulatory matters; inability to agree with respect to the timing of and value attributed to assets identified for dropdown; the adequacy of MPLX's capital resources and liquidity, including, but not limited to, availability of sufficient cash flow to pay distributions, and the ability to successfully execute its business plans and growth strategy; the timing and extent of changes in commodity prices and demand for crude oil, refined products, feedstocks or other hydrocarbon-based products; continued/further volatility in and/or degradation of market and industry conditions; changes to the expected construction costs and timing of projects; completion of midstream infrastructure by competitors; disruptions due to equipment interruption or failure, including electrical shortages and power grid failures; the suspension, reduction or termination of MPC's obligations under MPLX's commercial agreements; modifications to earnings and distribution growth objectives; the level of support from MPC, including dropdowns, alternative financing arrangements, taking equity units, and other methods of sponsor support, as a result of the capital allocation needs of the enterprise as a whole and its ability to provide support on commercially reasonable terms; compliance with federal and state environmental, economic, health and safety, energy and other policies and regulations and/or enforcement actions initiated thereunder; changes to MPLX's capital budget; other risk factors inherent to MPLX's industry; and the factors set forth under the heading "Risk Factors" in MPLX's Annual Report on Form 10-K for the year ended Dec. 31, 2016, filed with the SEC. In addition, the forward-looking statements included herein could be affected by general domestic and international economic and political conditions. Unpredictable or unknown factors not discussed here, in MPC's Form 10-K or in MPLX's Form 10-K could also have material adverse effects on forward-looking statements. Copies of MPC's Form 10-K are available on the SEC website, MPC's website at http://ir.marathonpetroleum.com or by contacting MPC's Investor Relations office. Copies of MPLX's Form 10-K are available on the SEC website, MPLX's website at http://ir.mplx.com or by contacting MPLX's Investor Relations office.

Non-GAAP Financial Measures EBITDA, Adjusted EBITDA and distributable cash flow are non-GAAP financial measures provided in this presentation. EBITDA, Adjusted EBITDA and distributable cash flow reconciliations to the nearest GAAP financial measure are included in the Appendix to this presentation. EBITDA, Adjusted EBITDA and distributable cash flow are not defined by GAAP and should not be considered in isolation or as an alternative to net income attributable to MPC or MPLX, net cash provided by operating activities or other financial measures prepared in accordance with GAAP. The EBITDA forecasts related to certain projects were determined on an EBITDA-only basis. Accordingly, information related to the elements of net income, including tax and interest, are not available and, therefore, reconciliations of these non-GAAP financial measures to the nearest GAAP financial measures have not been provided.

Our Priorities for Value Creation

3

Execute Strategic Actions to Enhance Value for Investors

Maintain Top-Tier Safety and Environmental performance

Increase Capital Return to Shareholders

Grow Higher Valued and Stable Cash-flow businesses

Enhance Margins for our Refining operations

Strong Operational Performance and Responsible Corporate Leadership

4

5

Delivering Significant Returns for Our Shareholders

2016 Refining Margin-Enhancing Accomplishment

6

Increased production capacity of high-value alkylate and light

products

30,000 BPD dock expansion increasing optionality for refined

product placement

Increased light crude processing and overall crude

capacity

Expanded Galveston Bay resid hydrocracker capacity and improved oil gas recovery

~$90 MM EBITDA/yr. ~$50 MM EBITDA/yr. ~$120 MM EBITDA/yr. (2016-2020E Avg.)

Commissioned Light Crude Upgrade

Export Capacity Expansion

FCC/Alky Revamp Completed

Completed First Phase

Speedway Sets Multiple All-time Highs in 2016

7

EBITDA Light Product Sales Merchandise Margin

Merchandise Margin

gallons

2016 MPLX Accomplishments

8

Start-up of 3rd

Distribution growth of

Commenced Operations

at Hopedale

Entered Delaware Basin

Complex

Increased natural gas processed volumes by in Marcellus & Utica and Southwest

Strengthened Balance Sheet Available Liquidity

Reduced Leverage to target Debt to LTM EBITDA

One-year anniversary of

MarkWest with

Increased fractionated volumes by in Marcellus & Utica

Executing Strategic Plan to Enhance Value

9

Asset Dropdowns

MLP-Qualifying EBITDA

Exchange for

Expected ~$4.5 B after-tax cash proceeds from dropdowns and ~$1.2 B - $1.4 B annual distributions after IDR exchange

Expected to fund substantial ongoing return of capital to shareholders consistent with maintaining an investment grade credit profile

Tangible valuation marker for MPC’s ownership interest in MPLX

Simplifies structure Expected to lower cost of capital Increased visibility to distribution growth Additional ~$1.4 B of annual EBITDA adds

substantial stable cash flow

Benefits

Evaluation Underway

Completed First Quarter Dropdown to MPLX

10

Terminal, pipeline and storage assets – 62 light product terminals with ~24 million barrels of

storage capacity – 11 pipeline systems consisting of 604 pipeline miles – 73 tanks with ~7.8 million barrels of storage capacity – Crude oil truck unloading facility at MPC’s refinery in

Canton, Ohio – Natural gas liquids storage cavern in Woodhaven,

Michigan, with ~1.8 million barrels of capacity

Total consideration of $2.015 B – $1.511 B in cash and $504 MM in MPLX equity – Represents ~8 times EBITDA multiple – ~$250 MM estimated annual EBITDA – Expected to be immediately accretive to MPLX’s

distributable cash flow

2018E LP & GP distributions MPC receives from MPLX(1)(2)

(1)Assumes ~$1.4 B of EBITDA dropped to MPLX over 2017 at ~7.0x - 9.0x; financed 50% with debt (~5.0% interest rate) and 50% equity issued to MPC at an average assumed MPLX unit price of ~$35 (2)Assumes MPLX acquires MPC’s GP/IDR interests valued between $9 B and $12 B. GP/IDR Buy-In transaction 100% financed via an exchange of MPLX equity at a unit price of ~$37 (3)Based on approximately 528 MM MPC shares outstanding as of December 31, 2016; includes after-tax cash dropdown proceeds received from MPLX (assumes 20% tax leakage) (4)Equal to MPLX LP yield grossed-up for percentage of cash distributions paid to GP

Total Midstream Value to MPC after Strategic Plan(1)(3)

MPLX Cost of Equity (4)

2016E: 8.3% 2018E Pro Forma: 6.5%

Illustrative $9 B

GP/IDR Buy-In

~$21 B

2018E Pro Forma LP distributions to MPC

b

Illustrative $12 B

GP/IDR Buy-In

~$26 B

~$3 B

(2)

~$5 - $6 B

Illustrative gross value per MPC share

~$6 + ~$17 - $21 + ~$17 - $23 = ~$40 - $50

Strategic Plan to Enhance Shareholder Value

11

~$9 - $12 B

Accelerated dropdowns

~$4 - $5 B

2017 Macro Outlook

U.S. macro picture remains solid – Expect good underlying demand for refined products despite a difficult January – Distillate demand expected to benefit from increased commercial activity

OPEC’s resolve to reduce production levels – Balanced supply and demand environment supportive of higher crude prices

Regulatory environment appears more favorable – Encouraged by early tone around energy policy

U.S. refining remains globally competitive – Sustained export advantage due to low cost natural gas and high complexity

refineries

NGL prices expected to strengthen with the broader oil complex

– Increased ethane demand as ethane cracker projects come online – Opportunity for MPLX midstream infrastructure projects

12

2017 Capital Outlook

13

Excluding Acquisitions and Dropdowns

MPC excluding MPLX ~$1.7 B Refining & Marketing (R&M) – $1,165 MM Midstream – $90 MM Speedway – $380 MM Corporate & Other – $100 MM

MPLX ~$1.7 B Growth – $1,550 MM* Maintenance – $100 MM

Midstream

MPLX

R&M Margin Enhancement

Corporate & Other

R&M Sustaining

Capital

*Represents midpoint of MPLX organic growth capital expenditure guidance

25%

9%

3% Speedway 11%

49%

3%

2017 Refining and Marketing Capital Investment Plan

14

~$325 MM Growth and Margin Enhancing Investments

STAR Program – $1.5 B multi-year staged investment – ~$85 MM investment in 2017 – Full integration of Galveston Bay and Texas City refineries – Project scope substantially preserved with attractive return

profile of nearly 30% IRR

Garyville ULSD projects – ~$120 MM total investment, ~$95 MM investment in 2017 – Additional 10 MBPD ULSD production capacity – ~75% IRR, 2018 est. completion

Galveston Bay export capacity expansion – ~$70 MM total investment, ~$9 MM investment in 2017 – Additional 115 MBPD refined product export capacity – ~20% IRR, 2019 est. completion

Galveston Bay Refinery Performance Improvements

15

Environmental Incident

Reduction

Unplanned Downtime Reduction

Reduced OPEX To Date

Unit Processing

Rate Records OSHA Recordable Injury Rate

Period of 2013-2016

Top-tier Refining Turnaround Execution

16

2014

Lower Turnaround Costs(1)

MPC Merchant Group U.S. Avg.

MPC approx. 25% below Merchant Group and 5% below U.S. Avg.

(1)Results from benchmarking studies performed by HSB Solomon Associates LLC (Solomon). Solomon performs an industry benchmarking study biennially which reports refinery results on a consistent basis for each refinery regardless of the varied company financial reporting practices. (2)Galveston Bay Refinery excluded from MPC results – purchased in 2013 and not owned during all intervals included in study

Crude

FCC

Reformer

Alky

NHT

DHT

Longer Turnaround Intervals (1,2)

MPC

U.S. Avg.

MPC approx. 15% longer than U.S. Avg.

Low

er C

ost

($/u

nit o

f cap

acity

)

Longer Span between Outages

3

7

11

15

19

23

27

31

35

55

59

63

67

71

75

79

83

87

Dec-09 Dec-10 Dec-11 Dec-12 Dec-13 Dec-14 Dec-15 Dec-16 Dec-17 Dec-18 Dec-19 Dec-20 Dec-21 Dec-22

The Marcellus/Utica Resource Play is the Leading U.S. Natural Gas Growth Play

17

Res

t of U

.S. –

Billi

on C

ubic

Fee

t per

Day

(Bcf

/d)

Note: Wellhead gas production (before flaring and NGL extraction) Sources: As of December 29, 2016. Bloomberg (PointLogic Energy/LCI Energy Insight Estimates) and Platts Bentek Oil & Gas Production Monitor

Marcellus & U

tica – Billion Cubic Feet per D

ay (Bcf/d)

Marcellus & Utica account for over 25% of total U.S. Gas Supply today and is expected

to grow to 32% by 2022

Marcellus & Utica

Rest of U.S.

Forecast Actual

2017 MPLX Organic Growth Capital Investment

18

Forecast range of $1.4 B to $1.7 B* ~$1 B to $1.3 B - natural gas and gas liquids infrastructure

– 3rd fractionation train at Hopedale completed in January – Numerous projects supporting producer customers’ growth

primarily in the prolific Marcellus Shale; 2017 expected completions include: • 400 MMcf/d of processing capacity at Sherwood • 60 MBPD of fractionation capacity at Keystone and Majorsville • Additional rich and dry-gas gathering as well as NGL pipeline

expansions in Marcellus, Utica and Southwest regions

~$400 MM - crude and refined products infrastructure – Utica build-out in connection with the recently completed

Cornerstone Pipeline – Butane cavern in Robinson, Illinois – Tank farm expansion in Texas City, Texas

*Excludes acquisitions and dropdowns

MPLX Recent Strategic Acquisitions

19

– ~$220 MM investment

– 433 mile, 22″ crude pipeline running from Cushing, Oklahoma to Wood River, Illinois, with capacity of ~230 MBPD

– Planned expansion to ~345 MBPD expected to be completed by 2Q 2018

Ozark Pipeline

Ozark Pipeline Acquisition Bakken Pipeline – $500 MM investment – ~9.2% equity interest in the Dakota Access Pipeline

(DAPL) and the Energy Transfer Crude Oil Pipeline (ETCOP) projects

– Expected to deliver ~470 MBPD from the Bakken/Three Forks production area to the Midwest and Gulf Coast with capacity up to ~570 MBPD

MPLX Strengthens Leading Position in Northeast

20

Recently Announced 50/50 Joint Venture with Antero Midstream

WEST VIRGINIA

PENNSYLVANIA

OHIO

SHERWOOD JV EXPANSION (site location TBD)

HOPEDALE

C3+ Fractionation Complex NGL Pipeline

Gas Processing Complex Processing and Fractionation Complex

Supports Antero Resources’ significant production growth profile in the Marcellus Shale

– Long-term, fee-based agreement and significant acreage dedication

Includes three 200 MMcf/d gas processing plants currently under construction at Sherwood complex

– Potential to develop up to eight additional processing facilities at Sherwood and a future expansion site

Includes 20 MBPD of existing fractionation capacity at Hopedale complex

– Option to invest in future fractionation expansions

2017 Speedway Capital Investment Plan

Planned investments of ~$380 MM – Build new stores and remodel and

rebuild existing retail locations in core markets

Delivered on goals for acquired locations

– Expect to complete remodel plan in 2017

– Planned investments achieved under budget and ahead of schedule

– ~80% of acquired stores upgraded under remodel plan

– Foundation for sales uplift, merchandise margin enhancements and synergy capture

21

Speedway Exceeding Expected Acquisition-Related Synergies

22

20

75 120

180 190 225

0

50

100

150

200

250

2014E 2014 2015E 2015 2016E 2016 2017E 2017E

$MM

Synergies and Marketing Enhancements

Guidance** Speedway Synergies R&M Synergies

47

149

*Light Product Breakeven = (Total Expense - Merchandise Margin) / Light Product Volume **Based on original announcement guidance in May 2014

Continuing to focus on marketing enhancements opportunities

2016 actual synergies exceeded revised projection of $155 MM

Reduced overall light product breakeven by ~30% in 4Q 2016 compared to 4Q 2015*

Strong Liquidity and Capitalization

Committed to maintaining investment grade credit profiles at MPC and MPLX

Substantial available liquidity at MPC and MPLX

Provides financial flexibility to fund growth projects and pursue business strategies

MPC excluding MPLX metrics provided as consolidated metrics are less useful given both the size of the partnership and its capital structure

23

As of December 31, 2016 MPC Consolidated

MPLX Adjustments(a)

MPC Excluding

MPLX ($MM except ratio data)

Debt 10,572 4,423 6,149

Mezzanine equity (MPLX conv. preferred) 1,000 1,000 -

Equity 20,203 8,219 11,984

Total capitalization 31,775 13,642 18,133

Debt-to-capital ratio (book) 33% 34%

Cash and cash equivalents 887 234 653

Debt to LTM Adjusted EBITDA(b) 2.5x 1.9x

(a)Adjustments made to exclude MPLX non-recourse debt and the public portion of MPLX equity (b)Calculated using face value of total debt and LTM adjusted EBITDA. Refer to appendix for reconciliation (c)Availability under MPC’s $750 MM trade receivables securitization facility is a function of eligible accounts receivable, which is affected by the refined products price environment

Liquidity Summary MPLX MPC

Cash and cash equivalents 234 653

Revolvers(c) 2,000 3,500

Accounts receivable facility(c) 684

Credit Agreement with MPC 500

Outstanding letters of credit (3) (65)

Total liquidity 2,731 4,772

EPA Proposed Denial of Request to Change the RVO Point of Obligation

24

Comment Period Ended February 22, 2017

Summary of MPC’s comments – Renewable volume obligation (RVO) is embedded in the refinery gate price of the regulated

transportation fuel (gasoline and diesel) – Moving the point of obligation to the distribution rack simply shifts the RVO cost from the refinery

gate to the rack – Price at the pump will remain unchanged because the cost of compliance has been, and will

continue to be, borne by the consumer – Moving the point of obligation will have no effect on refining segment profitability – Moving the point of obligation will not alter the viability of a single U.S. refinery

Others supporting no change to the point of obligation: the American Petroleum Institute, Shell, BP, ExxonMobil, Chevron, Tesoro and Murphy USA

Refining and Marketing - Market Data Update

25

Effective March 1, 2017

RIN/CBOB crack adjustment included in R&M Gross Margin Indicator – Previously part of Other Gross Margin – Adjusts the LLS 6-3-2-1 crack spread to an ex-RIN basis – Adjusts the LLS 6-3-2-1 crack spread to an 84 octane CBOB basis (i.e., the product

produced and blended with ethanol)

Other Gross Margin now categorized into crude, products and volumetric gain

Note: The information presented in MPC’s Market Data is for informational purposes only. This information is not intended to be an indicator of MPC’s past or future financial results. Some of the information is compiled from sources outside MPC. MPC does not make any representation as to the accuracy of the data and does not undertake any obligation to update, revise or continue to provide the data. MPC, its information providers, and other third parties involved in or related to the making or compiling of any of the information listed above make no representations or warranties of any kind, either express or implied, with respect to the information (or the results to be obtained by the use thereof) and expressly disclaim all warranties and representations as to the information or use thereof.

1,230

1,900

(651)

581 36 (4)

87

621

(1,319) (362)

219 0

5001,0001,5002,0002,500

*LLS6-3-2-1Crack

*RIN/CBOBAdjustment

*Sweet/Sour Diff.

*LLS/WTIDiff.

*LLSPrompt vs.Delivered

*MarketStructure

OtherGrossMargin

R&MGrossMargin

DirectOperating

Costs

Other R&MSegmentIncome

$MM

Market Data Update

26

Refining and Marketing Indicative Gross Margin Reporting

*Based on 4Q 2016 market indicators using actual volumes

Crude (278) Product 759 Volumetric 140

1,230

1,900 581 36 (4)

87 (30)

(1,319) (362)

219 0

5001,0001,5002,0002,500

*LLS6-3-2-1Crack

*Sweet/Sour Diff.

*LLS/WTIDiff.

*LLSPrompt vs.Delivered

*MarketStructure

OtherGrossMargin

R&MGrossMargin

DirectOperating

Costs

Other R&MSegmentIncome

$MM

Appendix

27

Update on Strategic Actions to Enhance Shareholder Value

1) Significantly accelerated dropdowns, to be done as soon as practicable (expected in 2017), subject to requisite approvals and regulatory clearances, including tax

• MPC expects to dropdown assets generating ~$1.4 B of EBITDA to MPLX in 2017; expect valuation multiples consistent with recent industry precedents ranging from ~7.0x to ~9.0x EBITDA

2) Completed initial evaluation of strategic alternatives for general partner (GP) interests in MPLX

MPC expects to pursue an exchange of its economic interests in the GP (GP interests and IDRs) for MPLX LP units in conjunction with completion of dropdowns, with details of transaction to be announced following receipt of requisite approvals and tax clearance for all dropdowns (expected in 2017)

MPC would continue to retain control of the GP following this exchange

3) MPC’s Board to conduct a full and thorough review of Speedway, with update to be provided in mid-2017

Review by special committee to include a tax-free separation of Speedway and other strategic and financial alternatives

4) Given the significantly accelerated dropdown schedule, MPC does not plan to change its segment reporting in advance of the dropdowns

Note: All transactions subject to requisite approvals, market and other conditions, including tax and other regulatory clearances

1

2

3

4

28

Strategic Actions to Enhance Shareholder Value

29

Significant Cash to MPC for Return to Shareholders and Debt Paydown 1 2

Dropdown transactions will result in a substantial amount of cash to MPC at close; additional cash would be generated through ongoing distributions from MPLX

– Dropdowns are expected to produce ~$4.5 B of after-tax cash proceeds(1)(2)

– ~$1.2 B - $1.4 B in initial annual distributions expected from MPLX to MPC after IDR exchange(3)

Cash proceeds from dropdowns and ongoing LP distributions expected to fund substantial ongoing return of capital to MPC shareholders in a manner consistent with maintaining investment grade credit profiles at MPC and MPLX

– The dropdown and IDR exchange transactions are achievable with pro forma MPLX net leverage ≤4.0x

Note: All transactions subject to requisite approvals, market and other conditions, including tax and other regulatory clearances (1)Assumes ~$1.4 B of EBITDA dropped to MPLX at 8.0x; financed 50% with debt (~5.0% interest rate) and 50% equity issued to MPC at MPLX market price as of December 30, 2016 (2)Assumes 20% tax leakage on cash proceeds from dropdowns (3)Assumes MPLX acquires MPC’s GP/IDR interests valued between ~$9 B and ~$12 B based on a 15.0x - 20.0x multiple of PF GP/IDR distributions of ~$600 million with near-term DCF coverage expected to be above 1.1x. Also assumes GP/IDR Buy-In transaction 100% financed via an exchange of MPLX LP units at December 30, 2016 MPLX market price

Assets acquired in 1Q17

MPC Assets Expected to be Acquired by MPLX

30

~$1.4 B of Estimated Annual EBITDA

● ~55 MMBBL storage

● Multiple rail and truck loading racks and docks

● Fixed service fee per gallon

● No fuel inventory risk or working capital cost

Fuels Distribution

Refinery Logistics

● Private carrier crude oil and refined product pipelines and associated storage

● Joint interest pipelines

● Equity in 50/50 blue water JVs with Crowley

● ~60 light product; ~20 MMBBL storage; loading racks and docks

Pipelines Terminals Marine

Fuels Distribution Business Model

Services Model Marketing Model (Wholesale Distribution)

Marketing Model (Rack-to-Retail)

Business Description

– MPC outsources fuels marketing services to MPLX for those same services currently performed by MPC; generates revenue at MPLX

– Services performed for current MPC sales volumes

– Purchase MPC’s marketing businesses

– Marketing costs incurred to generate revenues

– Exposure to daily margin volatility, credit risk and bankruptcy of marketing customers

– Precedents models purchase, market, and transport fuel from independent sellers to third party and related party entities

– Services performed for Speedway volumes

Revenue Generation

– MPLX receives service fee (fixed) per gallon on fuels sold by MPC; not exposed to daily margin volatility

– Variable margin per gallon on fuels sold

– Fixed fee and/or margin (variable) per gallon

Inventory – MPLX has no fuel inventory risk or

working capital cost – Fuel inventory risk and working

capital cost – High volatility (requires

leased/owned storage capacity)

– Precedent models may have fuel inventory risk and working capital costs

MLP Qualifying

Income

– No precedent models; reviewing recently issued qualifying income regulations; likely involves a private letter ruling

– Precedent models include portions of: Susser/Sunoco LP, Global Partners, Delek Logistics

– Precedent models include portions of: Susser/Sunoco LP, CrossAmerica Partners

31

Strategic Actions to Enhance Shareholder Value

32

Significant Value to MPLX 1 2

The combination of dropdowns and GP/IDR buy-in is anticipated to lower MPLX’s cost of capital going forward

– Dropdowns enhance distribution growth

– GP/IDR buy-in removes IDR burden and lowers equity cost of capital

The strategic actions are projected to provide DCF accretion and allow MPLX to achieve its double-digit distribution growth targets with near-term DCF coverage expected to be above 1.1x

– MPLX will have the ability to further increase distributions if market conditions support such actions

The strategic actions will simplify the MPLX structure and fully align incentives with MPC

– MPC will own the general partner and a majority of MPLX LP units, completely aligning interests towards continuing MPLX distribution growth and managing MPLX to be competitive and attractively valued

Addition of ~$1.4 B of EBITDA adds substantial stable cash flow to MPLX and greater visibility to distribution growth

Consistent with Its Demonstrated Track Record, MPC Continues Its Focus on Long-Term Value Creation MPC and its Board of Directors continually analyze opportunities to enhance value and are confident that the MPC plan is the right course

Proven Commitment to

Enhancing Shareholder Value

– 2011 spinoff from Marathon Oil – Creation of MPLX – Tripled stable cash flow(1)

– Over $10 B returned to shareholders – 179% Total Shareholder Return since 2011(2)

MPC’s Strategic Plan Will Continue

to Deliver Shareholder Value

– Significantly accelerated dropdowns: MPC expects to dropdown assets generating ~$1.4 B of EBITDA to MPLX as soon as practicable (expected in 2017) subject to regulatory clearances, including tax

– Completed initial evaluation of strategic alternatives for general partner (GP) interests in MPLX: MPC expects to pursue an exchange of its economic interests in the GP (GP interests and IDRs) for MPLX LP units in conjunction with completion of dropdowns, with details of transaction to be announced following receipt of requisite approvals and tax clearance for all dropdowns (expected in 2017)

– MPC’s Board will conduct a full and thorough review of Speedway, including a tax-free separation and other strategic and financial alternatives. Review to be led by a special committee of the Board with the assistance of an independent financial advisor. Update on review expected to be provided by mid-2017

MPC and MPLX Interests are

Aligned

– Increased and substantial MPLX LP holdings by MPC – greater than 50% pro forma for dropdowns and GP/IDR buy-in – Growing stable cash flows through continued investment in midstream infrastructure, driven by a steady stream of MPLX

organic capex of $1.4 B - $1.7 B in 2017 – Increasing distributions to MPLX LP unit holders with forecasted growth of 12% - 15% in 2017 and double-digit growth in

2018 driven by organic growth capital and MPC dropdowns – Optimizing MPLX’s cost of capital enhances the partnership’s organic and M&A opportunities

(1)Based on 3Q 2016 LTM EBITDA as compared to 2011 EBITDA (2)FACTSET as of December 30, 2016

33

Refining and Marketing - Market Data Update

34

Effective March 1, 2017

RIN/CBOB crack adjustment included in R&M Gross Margin Indicator – Previously part of Other Gross Margin – Adjusts the LLS 6-3-2-1 crack spread to an ex-RIN basis – Adjusts the LLS 6-3-2-1 crack spread to an 84 octane CBOB basis (i.e., the product

produced and blended with ethanol)

Other Gross Margin now categorized into crude, products and volumetric gain Report enhancements

– Hypothetical gross margin indicator calculated based on guidance – Historical data shown in new format including other gross margin breakout between

crude, products and volumetric gain

Note: The information presented in MPC’s Market Data is for informational purposes only. This information is not intended to be an indicator of MPC’s past or future financial results. Some of the information is compiled from sources outside MPC. MPC does not make any representation as to the accuracy of the data and does not undertake any obligation to update, revise or continue to provide the data. MPC, its information providers, and other third parties involved in or related to the making or compiling of any of the information listed above make no representations or warranties of any kind, either express or implied, with respect to the information (or the results to be obtained by the use thereof) and expressly disclaim all warranties and representations as to the information or use thereof.

1,230

1,900

(651)

581 36 (4)

87

621

(1,319) (362)

219 0

5001,0001,5002,0002,500

*LLS6-3-2-1Crack

*RIN/CBOBAdjustment

*Sweet/Sour Diff.

*LLS/WTIDiff.

*LLSPrompt vs.Delivered

*MarketStructure

OtherGrossMargin

R&MGrossMargin

DirectOperating

Costs

Other R&MSegmentIncome

$MM

Market Data Update

35

Refining and Marketing Indicative Gross Margin Reporting

*Based on 4Q 2016 market indicators using actual volumes

Crude (278) Product 759 Volumetric 140

1,230

1,900 581 36 (4)

87 (30)

(1,319) (362)

219 0

5001,0001,5002,0002,500

*LLS6-3-2-1Crack

*Sweet/Sour Diff.

*LLS/WTIDiff.

*LLSPrompt vs.Delivered

*MarketStructure

OtherGrossMargin

R&MGrossMargin

DirectOperating

Costs

Other R&MSegmentIncome

$MM

Refining and Marketing - Other Gross Margin

36

Crude, Product and Volumetric Gain Examples*

Crude – Actual crude and other feedstocks versus the seven crudes included in market data – Hedging gains and losses – Crude transportation to refinery, historically ~$2 per barrel of crude throughput

Products – Product realizations versus spot market metric price – Variances due to actual yield versus 6-3-2-1 proxy – Variances due to actual distribution versus 60% USGC and 40% Chicago proxy – Variance due to actual sales volumes versus throughput volumes

Volumetric gain – Volume gain inherent in refining process – Volume varies based on units in turnaround and capital improvements – Historically ~1.5% – 2.0% of total throughput – Value varies with refined product prices

*illustrative subset of items included in crude, products and volumetric gain

Other Components of R&M Segment Income

37

Direct Operating Costs – Guidance provided at earnings call for upcoming quarter – Comprised of three expense classes

• Major maintenance and turnaround • Depreciation and amortization • Other Manufacturing

Other – Guidance not provided – Includes terminaling and transportation costs from refinery gate forward and associated marketing

and supply, distribution and planning expenses – Equity method income for ethanol and biofuel investments

Marathon Petroleum Corporation Market Data - Current Quarter Price information through 12/31/20161 2 3 4 5 6 7 8 9 10 11 12 13 14

(1) - (6) (6) + (8) (1) - (9) (6) + (11) (1) - (12)2016 LLS Prompt Chicago USGC Blended RIN/CBOB Crack WTI Prompt LLS Prompt vs. LLS Delivered LLS Delivered LLS Prompt vs. Sour Delivered Sour Delivered LLS Prompt Market Structure

Price (a) 6-3-2-1 Crack (b) 6-3-2-1 Crack (b) 6-3-2-1 Crack (c) Adjustment (d) Price (a) WTI Prompt Diff. (e) Cost (g) LLS Delivered Diff. (f) Cost (g) Sweet/Sour Diff. (h)Oct 51.35 6.56 8.03 7.44 (3.79) 49.94 1.41 1.65 51.59 (0.24) (5.01) 44.93 6.42 (0.84) Nov 46.72 5.08 6.91 6.18 (3.83) 45.76 0.95 1.50 47.26 (0.54) (4.92) 40.85 5.87 (0.66) Dec 53.53 7.25 9.30 8.48 (4.10) 52.17 1.36 1.12 53.29 0.24 (4.87) 47.29 6.23 (0.84) 4th Qtr 50.59 6.32 8.10 7.39 (3.91) 49.29 1.30 1.42 50.71 (0.12) (4.93) 44.36 6.24 (0.78)

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N)Crude Non-Crude Total LLS 6-3-2-1 RIN/CBOB Sweet/Sour LLS Prompt LLS Prompt Market Gross Margin Crude Other Charge/ Sour Crude Oil WTI- Priced Crude

Throughput Throughput Throughput Crack Spread Crack Adjustment Differential vs WTI Prompt vs Delivered Structure Indicator Throughput Feedstocks Throughput Oil Throughput(mmbbls) (mmbbls) (mmbbls) ($MM) ($MM) ($MM) ($MM) ($MM) ($MM) ($MM) (MBD) (MBD) Percentage Percentage

(K) x Days in Qtr (L) x Days in Qtr (A) + (B) (C) x Col 4 (C) x Col 5 (A) x Col 13 x (M) (A) x Col 7 x (N) (A) x Col 10 x [1-(M)-(N)] (A) x Col 14 x 65% Sum of (D) thru (I)

4Q16 Est. 154 14 168 1,240 (656) 557 50 (3) 78 1,266 1,675 150 58% 25%

(a) Prompt Price represents calendar workday average of prices quoted that month for crude delivered in immediately following month(s). All prices and differentials listed are in Dollars per Barrel(b) Crack Spread Calculation: Chicago = ((Chicago 87 Octane Gasoline x 3 + Chicago Ultra Low Sulfur Distillate x 2+ USGC 3% Residual Fuel Oil)/6) - LLS Prompt Price Data Sources: NYMEX, Argus, and MPC Estimate

USGC = ((U.S. Gulf Coast (USGC) 87 Octane Gasoline x 3 + USGC Ultra Low Sulfur Distillate x 2+ USGC 3% Residual Fuel Oil)/6) - LLS Prompt Price(c) Blended Chicago/USGC crack spread was 38%/62% for 2015, and is 40%/60% in 2016 based on MPC's refining capacity by PADD in each period.(d) Represents the market cost of Renewable Identification Numbers (RINs)(credits needed to meet an EPA-specific Renewable Volume Obligation) for attributable products and the difference between 87 Octane Gasoline and 84 Octane CBOB Gasoline.(e) Represents differential (versus Prompt WTI) for the trade month period beginning with the 26th calendar day two months prior to the prompt month through the 25th day one month prior to the prompt month (see next page for Prompt LLS versus LLS Delivered Cost calculation).(f) Delivered differentials per footnote (e), with the exception of the Maya delivered differential which is calculated on a prompt calendar month basis. MPC's typical sour crude oil basket consists of the following crudes: Arab Light, Kuwait, Maya, Western Canadian Select, Mars. (g) Delivered Cost is based on WTI Prompt Price plus each respective grade's delivered differential and does NOT include market structure or other expenses such as transportation, demurrage, etc. Market structure effects are calculated as a separate adjustment (see column 14 and (I) above).(h) Delivered month market structure (roll). Negative values represent contango and positive values represent backwardation. For 2017 approximately 65% of MPC's crude oil acquisition volume uses market structure in its acquisition price formula.

Hypothetical Gross Margin Indicator Calculation Based on Guidance Provided Outlook

Revised Market Data Sheet – Current Quarter

38

RIN/CBOB CrackAdjustment (d)

(3.79) (3.83) (4.10) (3.91)

Hypothetical Gross Margin Indicator Calculation Based on Guidance

Marathon Petroleum Corporation Market Data - Historical Price information through 12/31/20161 2 3 4 5 6 7 8 9 10 11 12 13 14

(1) - (6) (6) + (8) (1) - (9) (6) + (11) (1) - (12)2016 LLS Prompt Chicago USGC Blended RIN/CBOB Crack WTI Prompt LLS Prompt vs. LLS Delivered LLS Delivered LLS Prompt vs. Sour Delivered Sour Delivered LLS Prompt Market Structure

Price (a) 6-3-2-1 Crack (b) 6-3-2-1 Crack (b) 6-3-2-1 Crack (c) Adjustment (d) Price (a) WTI Prompt Diff. (e) Cost (g) LLS Delivered Diff. (f) Cost (g) Sweet/Sour Diff. (h)Jan 32.83 2.91 5.16 4.26 (2.80) 31.78 1.05 1.69 33.47 (0.64) (4.98) 26.80 6.03 (1.81) Feb 32.37 2.72 4.56 3.82 (3.23) 30.62 1.75 1.30 31.92 0.45 (4.84) 25.78 6.59 (1.35) Mar 40.06 6.42 5.17 5.67 (2.97) 37.96 2.10 1.80 39.76 0.30 (5.46) 32.50 7.56 (2.33) 1st Qtr 35.29 4.11 4.97 4.62 (3.00) 33.63 1.66 1.60 35.23 0.06 (5.11) 28.52 6.77 (1.84) Apr 42.69 8.58 6.45 7.30 (3.09) 41.12 1.57 2.40 43.52 (0.83) (5.00) 36.12 6.57 (2.08) May 48.69 9.32 5.92 7.28 (3.03) 46.80 1.89 1.70 48.50 0.19 (5.94) 40.86 7.83 (1.52) Jun 50.60 10.47 6.94 8.35 (3.75) 48.85 1.75 2.01 50.86 (0.26) (4.61) 44.24 6.36 (0.87) 2nd Qtr 47.38 9.47 6.44 7.66 (3.30) 45.64 1.74 2.04 47.68 (0.30) (5.17) 40.47 6.91 (1.49) Jul 46.42 6.15 6.20 6.18 (4.03) 44.80 1.62 1.84 46.64 (0.22) (4.55) 40.25 6.17 (0.70) Aug 46.33 10.33 8.58 9.28 (3.67) 44.80 1.53 1.76 46.56 (0.23) (4.65) 40.15 6.18 (0.89) Sep 46.83 9.35 8.04 8.57 (3.65) 45.23 1.60 1.59 46.81 0.01 (4.89) 40.34 6.49 (0.98) 3rd Qtr 46.52 8.70 7.66 8.08 (3.78) 44.94 1.58 1.73 46.67 (0.15) (4.70) 40.24 6.28 (0.86) Oct 51.35 6.56 8.03 7.44 (3.79) 49.94 1.41 1.65 51.59 (0.24) (5.01) 44.93 6.42 (0.84) Nov 46.72 5.08 6.91 6.18 (3.83) 45.76 0.95 1.50 47.26 (0.54) (4.92) 40.85 5.87 (0.66) Dec 53.53 7.25 9.30 8.48 (4.10) 52.17 1.36 1.12 53.29 0.24 (4.87) 47.29 6.23 (0.84) 4th Qtr 50.59 6.32 8.10 7.39 (3.91) 49.29 1.30 1.42 50.71 (0.12) (4.93) 44.36 6.24 (0.78) YTD 45.01 7.19 6.80 6.96 (3.50) 43.47 1.55 1.70 45.17 (0.15) (4.98) 38.49 6.52 (1.24)

(A) (B) (C) (D) (E) (F) (G) (H) (I) (J) (K) (L) (M) (N)Crude Non-Crude Total LLS 6-3-2-1 RIN/CBOB Sweet/Sour LLS Prompt LLS Prompt Market Gross Margin Reported Reported vs. Sour Crude Oil WTI- Priced Crude

Throughput Throughput Throughput Crack Spread Crack Adjustment Differential vs WTI Prompt vs Delivered Structure Indicator Gross Margin* Indicator Throughput Oil Throughput(mmbbls) (mmbbls) (mmbbls) ($MM) ($MM) ($MM) ($MM) ($MM) ($MM) ($MM) ($MM) Other Gross Margin Percentage Percentage

(A) + (B) (C) x Col 4 (C) x Col 5 (A) x Col 13 x (M) (A) x Col 7 x (N) (A) x Col 10 x [1-(M)-(N)] (A) x Col 14 x 75% Sum of (D) thru (I) ($MM) (K) - (J)(Detail Below)

1Q15 150 16 167 1,615 (439) 596 126 58 82 2,038 2,691 653 56% 20%2Q15 163 15 178 1,819 (453) 438 158 (54) 255 2,163 2,635 472 55% 19%3Q15 160 15 176 2,142 (423) 527 122 (6) 76 2,438 3,037 599 56% 20%4Q15 151 18 169 1,124 (336) 534 40 (30) 112 1,444 2,148 704 55% 20%1Q16 146 16 161 747 (485) 604 44 2 199 1,111 1,611 500 61% 18%2Q16 157 15 172 1,316 (567) 665 58 (8) 177 1,641 2,204 563 61% 21%3Q16 165 12 177 1,431 (669) 607 52 (5) 108 1,524 1,906 382 59% 20%4Q16 154 13 167 1,230 (651) 581 36 (4) 87 1,279 1,900 621 61% 18%

Reported vs. Crude Related Product Related Volumetric GainsIndicator ($MM) ($MM) ($MM)

($MM)

1Q15 653 (303) 813 143 2Q15 472 (371) 640 203 3Q15 599 (391) 798 192 4Q15 704 (266) 822 148 1Q16 500 (493) 864 129 2Q16 563 (320) 697 186 3Q16 382 (403) 624 161 4Q16 621 (278) 759 140

Gross Margin Indicator Calculation Based on Actuals

Reported vs. Indicator Variance Explanation | Other Gross Margin

Historical Data Tab

39

RIN/CBOB CrackAdjustment (d)

(2.80) (3.23) (2.97) (3.00) (3.09) (3.03) (3.75) (3.30) (4.03) (3.67) (3.65) (3.78) (3.79) (3.83) (4.10) (3.91) (3.50) Reported vs. Crude Related Product Related Volumetric Gains

Indicator ($MM) ($MM) ($MM)($MM)

1Q15 653 (303) 813 143 2Q15 472 (371) 640 203 3Q15 599 (391) 798 192 4Q15 704 (266) 822 148 1Q16 500 (493) 864 129 2Q16 563 (320) 697 186 3Q16 382 (403) 624 161 4Q16 621 (278) 759 140

Reported vs. Indicator Variance Explanation | Other Gross Margin

0

20

40

60

80

100

120

MM

BD

Distillate Leading World Liquids Demand

Average product demand growth of 1.6 MMBD in 2016-2017

Distillate remains the growth leader through 2025

Heavy fuel oil continues its structural decline

40

Sources: BP Statistical Review of World Energy (Actual), MPC Economics (Forecast)

Middle Distillate

Gasoline

Resid

Other

Average Annual Volumetric

Growth (MBD) 2015 vs. 2025

+445

-19

+623

+157

Forecast Actual

Distillate Leads U.S. Domestic Petroleum Fuels Demand

41

0

1

2

3

4

5

6

7

8

9

10

MM

BD

Compounded Annual

Growth Rates 2015 vs. 2030

Sources: U.S. Energy Information Administration (EIA), MPC

Gasoline

Gasoline ex ethanol

Distillate

Jet Fuel

Resid

-1.1% -1.1%

+1.4%

+0.5%

-2.8%

Forecast Actual Gasoline demand

declines due to corporate average fuel economy (CAFE) standards despite increased travel

Region 2015

Utilization Rate

North America 88%

MPC 99%

Europe 86%

Former Soviet Union 82%

Asia 81%

Middle East 79%

Latin America 74%

Africa 71%

U.S. Refiners Have Sustained Export Advantages

42

Lower-cost natural gas Large, complex refineries Access to lower-cost feedstocks High-utilization rates Sophisticated workforce

*Average import border price 02468

1012141618

2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025

$/M

MB

tu

Natural Gas Price Comparison

Japanese Liquefied Natural Gas (World Bank)*European Natural Gas (World Bank)*HH Spot Price (World Bank)

Forecast Actual

Sources: World Bank, IEA, PIRA

ENERGY STAR Program

ENERGY STAR labels for refining industry began in 2006

47 labels awarded during 11 labeling years

9 labels to Phillips 66/ConocoPhillips

1 label to ExxonMobil

1 label to former MPC site in St. Paul Park, Minnesota

Remaining 36 labels to MPC refineries 43

43

Operating Year ---> 2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015EPA Certification Year ---> 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

Canton 1 1 1 1 1 1 1 1 1 1 1

Detroit 1 1 1 1 1 1

Garyville 1 1 1 1 1 1 1 1 1 1 1

Robinson 1 1 1

Texas City 1 1 1 1 1

Conoco Phillips, Billings 1 1 1

Conoco Phillips, Lake Charles 1

Former Marathon, St Paul Park 1

Exxon/Mobil, Baton Rouge 1

Conoco Phillips, Bayway 1

Phillips 66 Company, Bayway 1

Phillips 66 Company, Ferndale 1 1 1

EPA ENERGY STAR History as of 6-15-16

Source: EPA ENERGY STAR Website

Balance in Refining Network

Midwest Capacity 729,000 BPCD

Louisiana Capacity 543,000 BPCD

Texas Capacity 545,000 BPCD

44

*Weighted Average NCI

The Nelson Complexity Index is a construction cost-based measurement used to describe the investment cost of a refinery in terms of the process operations being conducted. It is basically the ratio of the process investment downstream of the crude unit to the investment of the crude unit itself. This index has many limitations as an indicator of value and is not necessarily a useful tool in predicting profitability. There is no consideration for operating, maintenance or energy efficiencies and no consideration of non-process assets such as tanks, docks, etc. Likewise it does not consider the ability to take advantage of market related feedstock opportunities. Source: MPC data as reported in the Oil & Gas Journal effective Dec. 31, 2016

BPCD NCI

Canton (Ohio) 93,000 7.8

Catlettsburg (Ky.) 273,000 9.3

Detroit (Mich.) 132,000 9.9

Robinson (Ill.) 231,000 9.8

Galveston Bay (Texas) 459,000 13.0

Texas City (Texas) 86,000 7.8

Garyville (La.) 543,000 11.2

Total 1,817,000 10.7*

Key Strengths

45

Balanced Operations

40% 60%

Crude Oil Refining Capacity

PADD IIPADD III

61%

39%

Crude Slate

Sour CrudeSweet Crude

As of December 31, 2016 4Q 2016

~70% ~30% Assured Sales

Wholesale andOther Sales

Assured Sales of Gasoline Production (Speedway + Brand + Wholesale Contract Sales)

4Q 2016

Galveston Bay-Texas City World-Class Refining Complex

46

*MPC estimates post-STAR program completion in 2021

Galveston Bay and Texas City refineries consolidating operations in mid-2017

Galveston Bay-Texas City BPCD*

Crude 585,000

Resid Processing 142,100

Catalytic Cracking/Hydrocracking 258,400

Alkylation 52,800

Aromatics 33,800

Speedway – Top-tier Performer

47

- 25 50 75

100

Sunoco Speedway Casey's CST Couche-Tard MurphyUSA

WesternRefining

Alon USA

Total Margin*

Light Product Merchandise

-

10

20

30

Speedway Murphy USA Casey's Couche-Tard Sunoco CST Alon USA Western Refining

EBITDA*

Sources: 2015/2016 Company Reports, excludes asset gains/losses *Represents 3Q 2016 LTM information

Speedway Light Product Speedway Merchandise

$M/s

tore

/mon

th

Generates predictable, stable cash flows #1 in EBITDA/store/month vs. public peers

Speedway Strong and Consistent Growth

48

3,027 3,146 3,942

6,038 6,094

0

2,000

4,000

6,000

8,000

2012 2013 2014 2015 2016

MM

Gal

lons

Gasoline and Distillate Sales Volume

13.18 14.41 17.75 18.23

16.56

0.00

5.00

10.00

15.00

20.00

2012 2013 2014 2015 2016

¢/G

allo

n

Gasoline and Distillate Gross Margin(a)

795 825 975 1,368 1,435

3,058 3,135 3,611

4,879 5,007

24

25

26

27

28

29

30

0

2,000

4,000

6,000

2012 2013 2014 2015 2016

Percent $M

M

Merchandise Sales/Gross Margin

Merchandise Sales $

Merchandise Gross Margin $

Merchandise Gross Margin Percent

(a)The price paid by consumers less the cost of refined products, including transportation, consumer excise taxes and bankcard processing fees, divided by gasoline and distillate sales volume. Excludes LCM inventory valuation adjustments.

Following Through on Goals for Acquired Locations

Invest ~$570 MM in conversions, remodels and maintenance

Converted stores to Speedway brand and technology platforms

Remodel approximately 700 locations to drive marketing enhancements

Generate $365 MM of annual EBITDA in 2017

Achieve $190 MM in annual synergies in 2017

49

20 30 35 10 20 40 45 45

45 25

70

0

50

100

150

200

2014E** 2015E 2016E 2017E

$MM

Synergies and Marketing Enhancements (Original Guidance)

WilcoHess Synergies Operating and G&A Expense SynergiesLight Product Supply and Logistics Marketing Enhancements

175

365 35 40

45 70

0

100

200

300

400

2013Pro Forma Hess

EBITDA*

Form 10WilcoHessSynergies

Operating andG&A Expense

Synergies

Light ProductSupply and

Logistics

MarketingEnhancements

2017E HessEBITDA

$MM

Earnings Opportunities (Original Guidance)

**Based on Oct. 1, 2014 closing

Sources: Company reports, MPC internal estimates *Sept. 30, 2013 Form 10 Pro Forma annualized

190

20

75

120

Focus on Improving Light Product Breakeven

Measure of operating efficiency and merchandise contribution to total expense

Potential to drive substantial value in the business over time

7.13

0

2

4

6

8

10

12

14

2005 2013

Ligh

t Pro

duct

Bre

akev

en (c

pg)

2.56

12.39 Each 1.00 cent per

gallon improvement = ~$30 MM annual pretax earnings

Speedway Hess Sept. 30, 2013 Form 10 Estimate

LPBE = Total Expenses –

Merchandise Margin Light Product

Volume

50

Speedway and Hess Side-by-Side Comparison

Speedway generates an incremental $17,300 of merchandise margin per store per month

~$250 MM of additional annual merchandise margin potential across Hess retail

Hess(a) Speedway(b)

Company-operated Sites 1,255 1,478

Fuel Sales (gallons/store/month) 198,500 177,400

Fuel Margin ($/gallon) $0.137 $0.144

Merchandise Sales ($/store/month) $111,000 $176,800

Merchandise Margin ($/store/month) $29,200 $46,500

(a)2013 Pro-Forma data provided in Hess Retail Corporation Form 10 SEC filing (b)2013 data provided in Marathon Petroleum Corporation 10K SEC filing

51

About MPLX

Growth-oriented, diversified MLP with high-quality, strategically located assets with leading midstream position

Two primary businesses – Logistics & Storage includes transportation and storage

of crude oil, refined products and other hydrocarbon-based products

– Gathering & Processing includes gathering, processing, and transportation of natural gas and the gathering, transportation, fractionation, storage and marketing of NGLs

Investment grade credit profile with strong financial flexibility

MPC as sponsor has interests aligned with MPLX – MPLX assets are integral to MPC – Growing stable cash flows through continued investment in

midstream infrastructure

52

As of December 31, 2016 See appendix for legend

2% GP interest

MPLX and MPC are Aligned

MPC views MPLX as integral to its operations and is aligned with its success and incentivized to grow MPLX

MPC owns 23.5% LP interest and 100% of MPLX’s GP interest and IDRs

100% interest

r

100% interest Public Preferred Common

Class B

74.5% LP interest

100% interest

MPLX GP LLC (our General Partner)

23.5% LP interest

MPLX LP* (NYSE: MPLX)

(the “Partnership”)

Marathon Petroleum Corporation and Affiliates

(NYSE: MPC)

MPLX Organizational Structure

53

As of December 31, 2016 * All Class B units are owned by M&R MWE Liberty, LLC and included with the public ownership percentage and depicted on an as-converted basis.

MPLX Terminal and Storage LLC

MarkWest Energy Partners, L.P.

100% interest

MarkWest Hydrocarbon, L.L.C.

MarkWest Operating Subsidiaries

MPLX Operations LLC

Hardin Street Marine LLC

MPLX Pipe Line Holdings LLC

MPLX’s Forecast

12-15% distribution growth in 2017; double-digit distribution growth in 2018 Forecast, excluding acquisitions and dropdowns:

54

Financial Measure 2017 Forecast

Net Income $500 MM - $650 MM

Adjusted EBITDA(a) $1.5 B - $1.65 B

Net cash provided by operating activities $1.25 B - $1.4 B

Distributable Cash Flow (DCF)(a) $1.15 B - $1.3 B

Organic Growth Capital Expenditures(b) $1.4 B - $1.7 B

Distribution Growth Rate 12% - 15%

(a)Non-GAAP measure calculated before the distribution to preferred units. See reconciliation in appendix. (b)Guidance excludes expenditures incurred related to acquisitions and non-affiliated JV members’ share of capital expenditures

MPLX Organic Growth Capital Investments

55

2017 forecast $1.4 B - $1.7 B

(a)Utica Rich-Gas Gathering is a joint venture between MarkWest Utica EMG’s and Summit Midstream LLC. Dry-Gas Gathering in the Utica Shale is completed through a joint venture with MarkWest and EMG. (b)MarkWest and MarkWest Utica EMG shared fractionation capacity (c)Replacement of existing Houston 35 MMcf/d plant (d)MarkWest Utica EMG Joint Venture (e)MarkWest Antero Midstream Joint Venture

Gathering & Processing Projects Shale Resource Capacity Est. Completion Date

Rich- & Dry-Gas Gathering(a) Marcellus & Utica N/A Ongoing

Western OK - STACK Rich-Gas & Oil Gathering Cana Woodford N/A Ongoing

Hopedale III C3+ Fractionation & NGL logistics(b) Marcellus & Utica 60,000 Bbl/d Completed

Sherwood VII Processing Plant(e) Marcellus 200 MMcf/d 1Q17

Keystone C2 Fractionation Marcellus 20,000 Bbl/d 3Q17

Sherwood VIII Processing Plant(e) Marcellus 200 MMcf/d 3Q17

Majorsville II C2 Fractionation Marcellus 40,000 Bbl/d 4Q17

NGL Pipeline Expansions Marcellus N/A 2017 and 2018

Houston 1 Processing Plant(c) Marcellus 200 MMcf/d 1Q18

Sherwood IX Processing Plant(e) Marcellus 200 MMcf/d 1Q18

Majorsville VII Processing Plant Marcellus 200 MMcf/d 2018

Harmon Creek Processing Plant Marcellus 200 MMcf/d 2018

Harmon Creek C2 Fractionation Marcellus 20,000 Bbl/d 2018

Cadiz IV Processing Plant(d) Utica 200 MMcf/d 2018

Logistics & Storage Projects Est.

Completion Date

Utica Infrastructure Build-out Mid-2017

Robinson Butane Cavern 2018

Texas City Tank Farm 2018

Executing a Comprehensive Utica Strategy Phased infrastructure investment

56

Cornerstone Pipeline commenced operations on time and under budget

Hopedale pipeline connection completed December 2016

Utica build-out mid-2017 estimated completion

– Links Marcellus and Utica condensate and natural gasoline with Midwest refiners

– Allows diluent movements to Canada

– Leverages existing MPC/MPLX pipelines and right of way

– Budgeted investments ~$255 MM

• ~$40 MM annual EBITDA

MPLX - Attractive Portfolio of Organic Growth Capital Logistics & Storage Segment

Utica Infrastructure Build-out Industry solution for Marcellus and Utica liquids Mid-2017 estimated completion Texas City Tank Farm MPC and third-party logistics solutions 2018 estimated completion Robinson Butane Cavern MPC shifting third-party services to MPLX and

optimizing Robinson butane handling 2018 estimated completion Other projects in development

57

74%

20%

6%

MPC Commited MPC Additional Third Party

MPLX - Logistics & Storage Contract Structure

Fee-based assets with minimal commodity exposure(c)

MPC has historically accounted for – over 85% of the volumes shipped on MPLX’s

crude and product pipelines – 100% of the volumes transported via MPLX’s

inland marine vessels MPC has entered into multiple

long-term transportation and storage agreements with MPLX

– Terms of up to 10 years, beginning in 2012 – Pipeline tariffs linked to FERC-based rates – Indexed storage fees – Fee-for-capacity inland marine business

58

2016 Revenue – Customer Mix

MPC = 94%

$633 MM

$171 MM

$51 MM

(a,b)

Notes: (a)Includes revenues generated under Transportation and Storage agreements with MPC (excludes marine agreements) (b)Volumes shipped under joint tariff agreements are accounted for as third party for GAAP purposes, but represent MPC barrels shipped (c)Commodity exposure only to the extent of volume gains and losses

MPLX Gathering & Processing

59

One of the largest NGL and natural gas midstream service providers – Gathering capacity of 5.4 Bcf/d

• ~50% Marcellus/Utica; ~50% Southwest

– Processing capacity of 7.6 Bcf/d* • ~70% Marcellus/Utica; ~20% Southwest

– C2 + Fractionation capacity of 550 MBPD** • ~90% Marcellus/Utica

Primarily fee-based business with highly diverse customer base and established long-term contracts

Raw Natural Gas Production

Processing Plants

Mixed NGLs

Fractionation Facilities

NGL Products

• Ethane • Propane • Normal Butane • Isobutane • Natural Gasoline

Gathering and

Compression

*Includes processing capacity of non-operated joint venture **Includes condensate stabilization capacity

MPLX Northeast Operations Well-Positioned in Ethane Market

Ethane demand growing as exports and steam cracker development continues in Gulf Coast and Northeast

MPLX well-positioned to support producer customers’ rich-gas development with extensive distributed de-ethanization system

Based on current utilization, MPLX can support the production of an additional ~60 MBPD of purity ethane with existing assets

Opportunity to invest $500 MM to $1 B to support Northeast ethane recovery over the next five years

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West Virginia

Pennsylvania Ohio

Sherwood

Mobley

Majorsville

Cadiz Houston

Keystone

Harmon Creek

Seneca

MPLX De-ethanization Facility

MPLX Processing Complex

MPLX Planned De-ethanization Facility

Steam Cracker Planned

Steam Cracker Proposed

MPLX Ethane Pipeline

ATEX Pipeline

Mariner West Pipeline

Mariner East 1 Pipeline

MPLX - Gathering & Processing Contract Structure

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Durable long-term partnerships across leading basins

Marcellus Utica Southwest Resource Play

Marcellus, Upper Devonian

Utica Haynesville, Cotton Valley, Woodford, Anadarko Basin, Granite Wash, Cana-Woodford, Permian, Eagle Ford

Producers 14 – including Range, Antero, EQT, CNX, Noble, Southwestern, Rex and others

7 – including Antero, Gulfport, Ascent, Rice, PDC and others

140 – including Newfield, Devon, BP, Chevron, PetroQuest and others

Contract Structure Long-term agreements initially 10-15 years, which contain renewal provisions

Long-term agreements initially 10-15 years, which contain renewal provisions

Long-term agreements initially 10-15 years, which contain renewal provisions

Volume Protection (MVCs)

65% of 2017 capacity contains minimum volume commitments

25% of 2017 capacity contains minimum volume commitments

15% of 2017 capacity contains minimum volume commitments

Area Dedications 4.3 MM acres 3.9 MM acres 1.4 MM acres

Inflation Protection Yes Yes Yes

MPLX - Gathering & Processing

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Marcellus & Utica Operations

0 2.9Bcf/d Gathering capacity

5.5Bcf/d Processing capacity

471MBPD C2+ Fractionation capacity

25MBPD Cond. Stabilization capacity

Houston Complex Sherwood Complex Hopedale Complex

MPLX - Gathering & Processing

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Marcellus & Utica Operations

2016: Processed volumes increased

~14% over full-year 2015 Gathered volumes increased

~20% over full-year 2015

2017: Processed volumes expected to

increase ~10% to ~15% over 2016 Gathered volumes expected to

increase ~3% to ~6% over 2016

(a)Based on weighted average number of days plant(s) in service. Excludes periods of maintenance

Processed Volumes

Area Available Capacity

(MMcf/d)(a)

Average Volume

(MMcf/d)

Utilization (%)

Marcellus 4,155 3,341 80% Houston 555 456 82%

Majorsville 1,070 758 71%

Mobley 920 721 78%

Sherwood 1,200 1,138 95%

Keystone 410 268 65%

Utica 1,325 1,084 82% Cadiz 525 517 98%

Seneca 800 567 71%

4Q 2016 Total 5,480 4,425 81% 3Q 2016 Total 5,480 4,323 79%

MPLX - Gathering & Processing

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Marcellus & Utica Fractionation

2016 fractionated volumes increased ~29% over full-year 2015

2017 fractionated volumes expected to increase ~15% to ~20% over 2016

Commenced third fractionation train at Hopedale Complex, increasing total propane-plus capacity to 180 MBPD

Fractionated Volumes

Area Available Capacity

(MBPD)(a)(b)

Average Volume (MBPD)

Utilization (%)

4Q16 Total C3+ 227 187 82%

4Q16 Total C2 184 127 69%

3Q16 Total C3+ 227 189 84%

3Q16 Total C2 190 126 66% (a)Based on weighted average number of days plant(s) in service. Excludes periods of maintenance (b)Excludes Cibus Ranch condensate facility

MPLX - Gathering & Processing

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Southwest Operations

0 Gathering capacity

1.5Bcf/d* Processing capacity

29MBPD C2+ Fractionation capacity

2.6Bcf/d

Javelina Complex Carthage Complex Buffalo Creek Complex

Transmission capacity 1.4Bcf/d

*Includes 40% of processing capacity through the Partnership’s Centrahoma Joint Venture

Hidalgo Complex

MPLX - Gathering & Processing Southwest Operations

2016: Processed volumes increased

~14% over full-year 2015 Gathered volumes increased

~1% over full-year 2015

2017: Processed volumes expected to

increase ~3% to ~8% over 2016 – West Texas (Delaware Basin) and

Western Oklahoma (STACK) to support majority of increase

Gathered volumes expected to be flat over 2016

(a)Based on weighted average number of days plant(s) in service. Excludes periods of maintenance (b)West Texas is comprised of the Hidalgo plant in the Delaware Basin (c)Processing capacity includes Partnership’s portion of Centrahoma JV and excludes volumes sent to third parties

Processed Volumes

Area Available Capacity

(MMcf/d)(a)

Average Volume

(MMcf/d)

Utilization (%)

West Texas(b) 200 179 90%

East Texas 600 455 76%

Western OK 425 342 81%

Southeast OK(c) 120 120 100%

Gulf Coast 142 104 73%

4Q 2016 Total 1,487 1,200 81%

3Q 2016 Total 1,487 1,253 84%

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MPLX - Strong Financial Flexibility to Manage and Grow Asset Base

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Committed to maintaining investment grade credit profile

Completed a $1 B private placement of convertible preferred securities with third-party investors in 2Q 2016

Completed ~$780 MM of opportunistic ATM issuances in 2016

$2.25 B senior notes issued 1Q 2017

($MM except ratio data) As of 12/31/16

Cash and cash equivalents 234

Total assets 16,646

Total debt 4,423

Redeemable preferred units 1,000

Total equity 10,319

Consolidated total debt to LTM pro forma adjusted EBITDA ratio(a) 3.4x

Remaining capacity available under $2.0 B revolving credit agreement 1,997

Remaining capacity available under $500 MM credit agreement with MPC 500

(a)Calculated using face value total debt and last twelve month adjusted EBITDA, which is pro forma for acquisitions and includes NCI. Face value total debt includes approximately $435 MM of unamortized discount and debt issuance costs as of December 31, 2016.

MPLX’s Commodity Price Sensitivities

92% fee-based net operating margin, 8% commodity exposure for 2017 Maintain active hedging program with ~35% of our 2017 commodity exposure

currently hedged Annual 2017 sensitivities to commodity price changes (assumes no hedges):

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NOTE: Net operating margin is calculated as segment revenue less segment purchased product costs less realized derivative gains (losses). (a)The composition is based on MPLX’s average projected barrel of approximately: Ethane: 35%, Propane: 35%, Iso-Butane: 6%, Normal Butane: 12%, Natural Gasoline: 12%.

Product Commodity Price Change Annual DCF Impact

Natural Gas Liquids (Mont Belvieu) $.05 per weighted average gallon(a) ~$18 MM

Crude Oil (WTI) $1 per BBL ~$1 MM

Natural Gas (Henry Hub) $.50 per MMbtu <$1 MM

MPLX’s 2017 Forecast - Reconciliation

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($MM) Low High Net income 500 650 Depreciation and amortization 595 595 Net interest and other financial costs 265 265 Adjustment for equity investment earnings & distributions 90 90 Unrealized derivative losses(a) 13 13 Other 40 40 Adjusted EBITDA 1,503 1,653 Adjusted EBITDA attributable to noncontrolling interests (3) (3) Adjusted EBITDA attributable to MPLX LP 1,500 1,650 Deferred revenue impacts 5 5 Net interest and other financial costs (220) (220) Maintenance capital expenditures (100) (100) Other (35) (35) Distributable cash flow attributable to MPLX LP 1,150 1,300 Preferred unit distributions (65) (65) Distributable cash flow available to GP and LP unitholders 1,085 1,235

(a)The Partnership makes a distinction between realized or unrealized gains and losses on derivatives. During the period when a derivative contract is outstanding, we record changes in the fair value of the derivative as an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously recorded unrealized gain or loss and record the realized gain or loss of the contract.

Adjusted EBITDA and Distributable Cash Flow from Net Income

Reconciliations - Speedway

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*Based on Hess Sept. 30, 2013 Form 10 data annualized **Based on original announcement guidance in May 2014

EBITDA to Net Income for Acquired Locations ($MM) 2013* 2017E**

Net Income 47 138 Less: Net interest and other financial income (costs) (12) - Plus: Provision for income taxes 22 78 Plus: Depreciation and Amortization 94 149 Acquired Locations EBITDA 175 365

Speedway Segment EBITDA to Segment Income from Operations ($MM) 2016

Speedway Segment Income from Operations 734 Plus: Depreciation and Amortization 273 Speedway Segment EBITDA 1,007

Reconciliation

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Adjusted EBITDA to Net Income Attributable to MPC

($MM) 2016 LTM

1Q 2Q 3Q 4Q

Net Income attributable to MPC 1 801 145 227 1,174

Less: Net interest and other financial income (costs) (142) (137) (141) (136) (556)

Add: Net income (loss) attributable to inco noncontrolling interests (79) (18) 74 62 39

Provision for income taxes 11 395 75 128 609

Depreciation and amortization 490 500 507 504 2,001

Impairment expense 129 90 267 - 486

Inventory market valuation adjustment 15 (385) - - (370)

Adjusted EBITDA 709 1,520 1,209 1,057 4,495

Less: Adjusted EBITDA related to MPLX 1,272

Adjusted EBITDA excluding MPLX 3,223

Reconciliation

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MPC Adjusted EBITDA Related to MPLX to MPLX Net Income

($MM) 2016 LTM

1Q 2Q 3Q 4Q

MPLX Net Income (37) 20 143 132 258

Less: Net interest and other financial income (costs) (68) (64) (64) (65) (261)

Add: Provision for income taxes (4) (8) - - (12)

Depreciation and amortization 132 137 138 139 546

Impairment expense 129 90 - - 219

Adjusted EBITDA related to MPLX 288 303 345 336 1,272

MPC Annual Price and Margin Sensitivities Refining and Marketing Segment $MM (After Tax)

LLS 6-3-2-1 Crack Spread* Sensitivity ~$450 (per $1.00/barrel change) Sweet/Sour Differential** Sensitivity ~$225 (per $1.00/barrel change) LLS-WTI Spread*** Sensitivity ~$80 (per $1.00/barrel change) Natural Gas Price Sensitivity ~$130 (per $1.00/MMbtu change in Henry Hub)

*Weighted 40% Chicago and 60% USGC LLS 6-3-2-1 crack spreads and assumes all other differentials and pricing relationships remain unchanged **Light Louisiana Sweet (prompt) - [Delivered cost of sour crudes: Arab Light + Kuwait + Maya + Western Canadian Select + Mars] ***Assumes approximately 20% of crude throughput volumes are WTI-based domestic crudes

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MPC’s Fully Integrated Downstream System

Refining and Marketing Seven-plant refining system with ~1.8 MMBPCD capacity One biodiesel facility and interest in three ethanol facilities One of the largest wholesale suppliers in our market area One of the largest producers of asphalt in the U.S. ~5,500 Marathon Brand retail outlets across 19 states Owns/operates 61 light product terminals and 18 asphalt terminals, while utilizing

third-party terminals at 121 light product and two asphalt locations 2,074 owned/leased railcars, 163 owned transport trucks

Speedway ~2,730 locations in 21 states Second largest U.S. owned/operated c-store chain

Midstream (including MPLX) Owns, leases or has interest in ~8,400 miles of crude and refined product pipelines 18 owned inland waterway towboats with 204 owned barges and 18 leased barges Owns/operates over 5,600 miles of gas gathering and NGL pipelines Owns/operates 54 gas processing plants, 14 NGL fractionation facilities and two

condensate stabilization facilities

MPC Refineries

Light Product Terminals MPC owned and Part-owned Third Party

Asphalt/Heavy Oil Terminals MPC Owned Third Party

Water Supplied Terminals Coastal Inland

Pipelines MPC Owned and Operated MPC Interest: Operated by MPC MPC Interest: Operated by Others Pipelines Used by MPC

Marketing Area Ethanol Facility Biodiesel Facility

Renewable Fuels

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MarkWest Facility

Tank Farms

Butane Cavern

Pipelines

Barge Dock

Marine Repair Facility

As of December 31, 2016