March 3, 2016

Bank of America Merrill Lynch 2016 Refining Conference

Filed by Northern Tier Energy LP

Pursuant to Rule 425 under the Securities Act of 1933

And deemed filed pursuant to Rule 14a-12

under the Securities Exchange Act of 1934

Subject Company: Northern Tier Energy LP

Form S-4 File No.: 333-209031

On March 3, 2016, Northern Tier Energy LP made the following

presentation, which it presented later that day at the Bank of America

Merrill Lynch 2016 Refining Conference, available on its website.

Forward Looking Statements

2

Forward-Looking Statements

This presentation contains forward-looking statements. The forward-looking statements contained herein include statements about, among other things, future: integration of refining, marketing, retail and logistics assets;

entity structure; amount & type of crude oil we’ll run at our refinery and yields; location of our assets; flexibility of our refinery; advantageous access to crude oil supplies and the attractiveness of our refined product outlets;

safe operations; leverage and financial flexibility; ability to identify growth opportunities and complete accretive acquisitions; incentives of our management team; redundancy of our operations and assets, refinery utilization

and increased maintenance flexibility; ability to process a variety of light, heavy, sweet and sour crude oils and the pricing thereof; fuel quality requirements and regulations, our ability to comply therewith and capex required

for and financial impacts of such compliance; liquid volume yield; FCC capacity; increases in NDL and/or WCS crude oil production; adjusted gross margin per barrel of throughput; number of company-operated & franchised

stores, the locations thereof and the ability of such stores to sell any or all of our refinery’s gasoline; commitments for supply of third party retail networks; improved netbacks; increases in total fuel gallons sold to the

SuperAmerica Network; brand presence of SuperAmerica including its benchmark against national top tier fuel retailers; new stores and franchise growth; organic growth opportunities and our ability to identify and/or

complete high return projects successfully or at all; replacement of desalters including the costs, timing, EBITDA, IRR and payback thereof including increases in crude oil input flexibility and optionality, replacement of Syncrude

with higher valued crude oils up to 10 MPD or at all, margin benefit of $4.50/bbl or at all, improved process reliability, reduction in salt-related corrosion and diesel v. gasoline recovery flexibility; modification of our crude units

and distillate hydrotreaters and the timing, costs, IRR, payback and results thereof including increases in distillate yield, increases in crude capacity, crude margin benefits and diesel recovery incentive; installation of a solvent

deasphalting unit including costs, timing, expected product spread benefit, product yields, pitch yields and its ability to fill FCC capacity; ability to achieve IRR above 30%; improvements in higher value light product yields,

efficiency of operations and crude flexibility; optimization of first purchaser barrels in the Bakken and utilization of crude oil transport fleet; ability to source some or all Bakken crude oil from the field and associated increases

in gross margins and crude oil quality; growth of the SuperAmerica brand by building new stores, expanding our franchise network or otherwise; acquisition of refining assets, including assets that are well-maintained and/or

have access to advantaged crude oil and attractive refined product dynamics; Bakken growth; the announced merger with Western Refining, Inc. (“Western” or “WNR”), including the financing thereof, the timing and likelihood

of completion thereof and the management team of the combined company following the merger; and, support of Western Refining.  The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,”

“could,” “attempt,” “appears,” “forecast,” “outlook,” “estimate,” “project,” “potential,” “may,” “will,” “are likely” or other similar expressions are intended to identify forward-looking statements. These forward-looking

statements are based on management’s current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as

and when made, there can be no assurance that future developments affecting us will be those that we anticipate, and any and all of our forward-looking statements in this presentation may turn out to be inaccurate. Our

forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present

expectations or projections. These statements are subject to the general risks inherent in our business, and our statements about the merger are also subject to risks related to the merger generally (including the risk that is it

not completed when expected or at all) as well as general risks inherent in the business of Western.  In addition, if the merger with Western is consummated, it may impact the operation of our business, including with respect

to future growth plans and strategies. These expectations may or may not be realized, and may be based upon assumptions or judgments that prove to be incorrect. In addition, our business and operations involve numerous

risks and uncertainties, many of which are beyond our control, which could result in our expectations not being realized, or otherwise materially affect our financial condition, results of operations and cash flows. Other known,

unknown or unpredictable factors could have material adverse effects on our future results. Additional information regarding such factors and our uncertainties, risks and assumptions are contained in our filings with the

Securities and Exchange Commission. All forward-looking statements are only as of the date hereof, and we do not undertake any obligation to (and expressly disclaim any obligation to) update any forward looking statements

to reflect events or circumstances after the date such statements were made, or to reflect the occurrence of unanticipated events.

Important Notice to Investors

This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval in any jurisdiction where such an offer or solicitation is unlawful.  Any such offer

will be made only by means of a prospectus meeting the requirements of Section 10 of the Securities Act of 1933, pursuant to a registration statement filed with the SEC. The proposed transaction between Western Refining,

Inc. (“Western”) and Northern Tier Energy LP (“NTI”) will be submitted to the unitholders of NTI for their consideration. On January 19, 2016, Western filed a registration statement on Form S-4 with the SEC that included a

preliminary prospectus of Western and a preliminary proxy statement of NTI.  Western and NTI will also file other documents with the SEC regarding the proposed transaction, including a definitive prospectus and proxy

statement. INVESTORS AND SECURITY HOLDERS OF NTI ARE URGED TO READ THE DEFINITIVE PROXY STATEMENT/PROSPECTUS AND ANY OTHER RELEVANT DOCUMENTS THAT WILL BE FILED WITH THE SEC CAREFULLY AND IN

THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION. Investors and security holders may obtain free copies of the definitive proxy

statement/prospectus and other documents containing important information about Western and NTI once such documents are filed with the SEC through the website maintained by the SEC at www.sec.gov. Copies of the

documents filed with the SEC by Western will be available free of charge on Western’s website at www.wnr.com under the “Investor Relations” section or by contacting Western’s Investor Relations Department at (602) 286-

1530.  Copies of the documents filed with the SEC by NTI will be available free of charge on NTI’s website at www.northerntier.com under the “Investors” section or by contacting NTI’s Investor Relations Department at (651)

769-6700. 

Participants in Solicitation Relating to the Merger

Western, NTI and certain of their respective directors and executive officers may be deemed to be participants in the solicitation of proxies from the unitholders of NTI in connection with the proposed transaction. Information

about the directors and executive officers of Western is set forth in the Proxy Statement on Schedule 14A for Western’s 2015 annual meeting of shareholders, which was filed with the SEC on April 22, 2015. Information about

the directors and executive officers of the general partner of NTI is set forth in the 2015 Annual Report on Form 10-K for NTI, which was filed with the SEC on February 26, 2016. These documents can be obtained free of charge

from the sources indicated above. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the proxy

statement/prospectus and other relevant materials to be filed with the SEC when they become available.

Key Business Highlights

3

•

Strategically-Located Refinery with Advantaged Access to Crude Oil Supplies and

Attractive Refined Product Outlets

•

Integrated Refining, Marketing, Retail, and Logistics Operations

•

Flexible Refinery with Operational Redundancies

•

Refinery Track Record of Safe Operations

•

Low Leverage with Financial Flexibility

•

Focused on Organic Growth Opportunities and Potential for Accretive Acquisitions

•

Experienced, Proven and Incentivized Management Team

Northern Tier Overview

Integrated

refining, marketing, retail, and

logistics assets operating as a variable

distribution publicly traded partnership.

St. Paul Park Refinery Product Yields

St. Paul Park Refinery Feedstocks

Total Input: 96,515 bpd

Total Yield: 96,506 bpd

1

Full Year Ended December 31, 2015.

4

Gasoline

48%

Distillates

35%

Asphalt

11%

Other 6%

Canadian

Crude 40%

Domestic

Crude 57%

Other 3%

1

1

5

•

Redundant refining assets, allowing for higher refinery utilization and increased

maintenance flexibility

•

Refinery configuration allows it to process a variety of light, heavy, sweet and sour

crude oils, most of which have historically priced on average below WTI

•

Compliance with currently known prospective Group 3 fuel quality requirements

without requiring significant additional capital expenditure, including upcoming     

Tier 3 gasoline sulfur regulations

•

High liquid volume yield –

typically greater than 100% on crude oil input

•

Available

FCC capacity

Flexible Refinery with Crude Oil Advantage

Operational Redundancy

Crude Distillation

/

Vacuum Towers

2

Reformers

2

Sulfur Recovery Units

2

Hydrotreating

Units

6

North Dakota Crude Oil Production

Western Canadian Crude Oil Production

Source:  PIRA Long Range Crude Production Forecast (December 2015)

Source: Canadian Association of Petroleum Producers (June 2015)

Refinery Benchmarking

6

Source:  Company filings.

$0

$5

$10

$15

$20

US Independent Refiners

Full Year 2015 Adjusted Gross Margin per Barrel of Throughput

Integrated Marketing Channel

7

•

Northern Tier’s integrated marketing network included 168

company-operated and 109 franchised SuperAmerica

convenience stores as of December 31, 2015

Approximately 264 stores are located in Minnesota with a

majority clustered in the Twin Cities metropolitan area

40% -

50% of St. Paul Park Refinery gasoline is sold

through the SuperAmerica

network

•

Northern Tier has additional committed fuel supply contracts

for 3

party retail networks

•

Integrated refining and marketing operations provide for

improved netback

•

Total fuel gallons sold to the SuperAmerica network increased

9% in 2015 versus 2014

•

Opened three new company-operated stores in the fourth

quarter 2015 and another one in January 2016

•

Added 20 franchise locations in 2015

Total Retail Fuel Sold (000 gal/store/month)

(company-operated  stores)

Retail Fuel Margin ($/gallon)

(company-operated stores)

Inside Sales ($000/store/month)

(company-operated stores)

Source:  Full Year Ended December 31, 2015.  SA Source is Internal

Reporting.  Central and US reporting source is CSX LLC

153

141

140

-

50

100

150

200

SA

Central

US

$0.234

$0.218

$0.203

-

$0.05

$0.10

$0.15

$0.20

$0.25

$0.30

SA

Central

US

$175

$152

$152

$-

$50

$100

$150

$200

$250

SA

Central

US

Inside Sales ($$$)

rd

Growth Strategy

Organic

•

Slate of high return projects (IRR in excess of 30%) which should

improve yields of higher value light products, efficiency of

operations, and/or crude oil slate flexibility:

Projects underway intended to:

replace

the

desalters

to

increase

crude

oil

input

flexibility

modify

the

No.

2

crude

unit

and

diesel

hydrotreater

to

increase

distillate yield and

crude oil throughput capacity

install

a

solvent

deasphalting

unit

to

utilize

available

FCC

capacity

•

Optimize first purchaser crude oil barrels in the Bakken with flexible

utilization of

crude oil transport fleet

•

Grow the SuperAmerica brand by opening new stores and expanding

franchise network

Acquisitions

•

Evaluate well-maintained

refining assets with access to advantaged

crude oil and attractive refined product dynamics

•

Grow the SuperAmerica

brand by acquiring existing retail assets

8

Crude Unit Desalter Project

Replace Existing Single Stage Desalters

with State of the Art Two Stage Desalters, intended to:

Gain

optionality

to

replace

up

to

10

MBPSD

of

Canadian

Syncrude

with

higher

valued

crude

oils

Expected

$4.50/bbl

margin

benefit

based

on

5-year

average

(2011

–

2015)

historical

crude

oil

differentials

Improve process reliability through reduction in salt related corrosion

Gain diesel versus gasoline recovery flexibility

Expect

to

complete

No.

1

Crude

Unit

Desalter

with

commissioning

starting

in

the

second

quarter

2016

Expect

to

complete

No.

2

Crude

Unit

Desalter

installation

in

connection

with

our

fall

2016

turnaround

9

Advantaged Crude Mix Opportunity

(not including quality adjustment)

Project Economics

1

Based primarily on average crude oil differentials and other assumptions for

the full five fiscal years of 2011 through 2015.  Actual results may differ.

2

From operational start-up

Capital Expenditure, $MM

$30

Expected Annual EBITDA, $MM

$21

Simple Payback, Months

2

17

Source:  Argus Month 1 Crude Prices

0

2

4

6

8

10

12

14

16

Jan-11

Jul-11

Jan-12

Jul-12

Jan-13

Jul-13

Jan-14

Jul-14

Jan-15

Jul-15

Jan-16

$/bbl

Month Average Syncrude

minus North Dakota Light Price

Delivered to St. Paul Park Refinery

January 2011 through December 2015 delivered average of $6.5 0/bbl

1

No. 2 Crude Unit and Diesel Hydrotreater

Revamp Projects

Increase crude oil throughput capability by up to

4 MBPSD while increasing diesel recovery by 2%

Expected $11/bbl Syncrude

or similar crude oil

margin benefit to overhead processing limits based

on

5-year

average

(2011

–

2015)

historical

margins

1

Expected $6.50/bbl diesel recovery incentive based

on

5-year

average

(2011

–

2015)

historical

spreads

1

Expect to complete the project in connection with

our fall 2016 turnaround

10

Project Economics

1

Based primarily on average crude prices, product netbacks, and other

assumptions for the five full fiscal years of 2011 through 2015.  Actual results

may differ.

2

From operational start-up

Upgrade Key Charge Rate & Distillate Recovery Limiting Equipment in the No. 2 Crude Unit,

intended to:

Sources:

Assumptions:

Argus Month 1 Crude Prices

1) Asphalt Price Equals FOB Hardisty WCS

OPIS Group 3 Midpoint Product Prices

2) Incremental Gasoline sold at Group 3 Midpoint minus 6 cpg

3) Incremental Distillate sold at Group 3 Midpoint minus 2 cpg

-10

-5

0

5

10

15

20

25

Jan-10

Jul-10

Jan-11

Jul-11

Jan-12

Jul-12

Jan-13

Jul-13

Jan-14

Jul-14

Jan-15

Jul-15

Jan-16

$/bbl

ULSD Recovery Incentive

Incentive

Average

1 Year Worst (2015)

1 Year Best (2014)

-5

0

5

10

15

20

25

30

35

Jan-10

Jul-10

Jan-11

Jul-11

Jan-12

Jul-12

Jan-13

Jul-13

Jan-14

Jul-14

Jan-15

Jul-15

Jan-16

$/bbl

Historic Incremental Crude Margins

Syncrude & North Dakota Light

Syncrude

North Dakota Light

Avg Syncrude

Avg

North Dakota Light

Capital Expenditure, $MM

$19

Expected Annual EBITDA, $MM

$10

Simple Payback, Months

2

23

Solvent Deasphalting Project

Upgrade residual oil for conversion to gasoline and diesel by utilizing excess FCC capacity

Expected $31.50/bbl project light to heavy product spread benefit based on 5-year (2011-2015) average

historical prices

1

Expected 60% light product yield from unit

Pitch yield from unit is expected to be blended into asphalt

Expect to complete the project by the middle of 2017

11

Project Economics

1

Based primarily on average crude prices, product netbacks, and other

assumptions for the five full fiscal years of 2011 through 2015.  Actual results

may differ.

2

From operational start-up

Install a 5,000 BPSD Solvent Deasphalting

Unit, intended to:

Capital Expenditure, $MM

$63

Expected Annual EBITDA, $MM

$27

Simple Payback, Months

2

28

Sources:

Assumptions:

OPIS Group 3 Midpoint Product Prices

1) Solvent Deasphalting Unit feed is 50% residual fuel oil and

Historic Asphalt sales netbacks

     50% asphalt

Argus Gulf Coast 3% No. 6 Fuel Oil

2) Residual fuel oil is priced at 80% 3% No. 6 Fuel Oil minus $10/bbl

     and 20% local roofing flux sales (asphalt plus $75/ton)

3) Asphalt is priced at average sales netback

4) Incremental Gasoline sold at Group 3 Midpoint minus 6 cpg

5) Incremental Distillate sold at Group 3 Midpoint minus 2 cpg

6) Pitch is sold at average asphalt sales netback

Month Average

6 Year Average

1 Year Best (2011)

1 Year Worst (2015)

0

10

20

30

40

50

60

Jan-10

Jul-10

Jan-11

Jul-11

Jan-12

Jul-12

Jan-13

Jul-13

Jan-14

Jul-14

Jan-15

Jul-15

Jan-16

$/bbl

Historic Project Light to Heavy Product Spread

Bakken First Purchase Strategy

12

Source:  Company Information

We Strive to Optimize Our First Purchases in the Bakken Field

Goal: Optionality to Source all Bakken Crude Oil from the Field

Goal: Increase Gross Margin by Acquiring the Best Quality Crude Oil for our Process Configuration

-

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

50,000

barrels per day

Bakken Crude Oil Purchases

Leases & Gathering System Pipelines

Lease Purchases

Enbridge Gathering Pipeline Purchases

Merger of Western Refining and Northern Tier

Summary of Transaction

13

•

As announced on December 21, 2015, Western Refining , Inc. (WNR) will acquire all of the

outstanding common units of Northern Tier Energy LP (NTI) not already owned by WNR.

Consideration

20-day

18-Dec

Undisturbed VWAP

Closing Price

WNR Shares per NTI Unit

0.2986

0.2986

WNR Price

44.68

$                    

37.04

$                    

Equity Value per NTI Unit

13.34

$                    

11.06

$                    

Cash per NTI Unit

15.00

$                    

15.00

$                    

Implied Consideration

28.34

$                    

26.06

$                    

Premium to NTI Closing Price (12/18)

18%

9%

Premium to NTI 20-day Undisturbed VWAP Price

18%

8%

WNR Price

•

The cash portion of consideration ($858 million) expected to be funded by cash-on-hand and

bank or capital markets debt

•

WNR will issue 17.1 million shares as part of the transaction consideration

•

Paul Foster to remain Executive Chairman; Jeff Stevens to remain Chief Executive Officer; Dave

Lamp to be appointed President and Chief Operating Officer

•

Transaction expected to close during 1H 2016, subject to NTI unitholder approval and

customary closing conditions

Key Business Highlights

14

•

Strategically-Located Refinery with Advantaged Access to Crude Oil Supplies and

Attractive Refined Product Outlets

•

Integrated Refining, Marketing, Retail, and Logistics Operations

•

Flexible Refinery with Operational Redundancies

•

Refinery Track Record of Safe Operations

•

Low Leverage with Financial Flexibility

•

Focused on Organic Growth Opportunities and Potential for Accretive Acquisitions

•

Experienced, Proven and Incentivized Management Team

APPENDIX

Q4 and Full Year 2015 Financial Summary

16

Gross Margin

1

($ per throughput barrel)

Direct Operating Expenses

4

($ per throughput barrel)

Total Refinery Throughput

3

(thousands of barrels per day)

2015

2014

Adjusted EBITDA

2

and

Cash Available for Distribution

$86.0

$499.2

$35.7

$345.2

$123.2

$430.7

$45.6

$258.9

Q4 Adjusted

EBITDA

Full Year Adjusted

EBITDA

Q4 Cash Available

for Distribution

Full Year Cash

Available for

Distribution

1

Gross margin data includes the impact of the lower of cost or market inventory adjustment which is depicted by dotted lines.  See page 18 for the components used in this calculation (revenue,

cost of sales, and lower of cost or market inventory adjustment).

2

See page 19 for reconciliations of Net Income to Adjusted EBITDA and Adjusted EBITDA to Cash Available for Distribution.

3

Total refinery throughput includes crude oil and other feedstocks.

4

Direct operating expenses per barrel is calculated by dividing direct operating expenses by the total barrels of throughput for the respective periods presented.

Key Refining Performance Metrics

17

1

Gross margin data for 2014 and 2015 excludes the impact of a lower of cost or market inventory adjustment.  See page 18 for the components used in this calculation (revenue, cost of sales, and lower of

cost or market inventory adjustment).

2

Typically, 80% of our products are comparable to a 3-2-1 crack spread, while 95% of our products are comparable to a 6-3-2-1 crack spread.

3

See page 16 for components used in this calculation (refinery operating expenses and refinery barrels of throughput).

Gross Margin

1

($ per throughput barrel)

Group 3 Benchmark Crack Spread

2

($ per barrel)

Direct Operating Expenses

3

($ per throughput barrel)

Total Refinery Throughput

(thousands of barrels per day)

$19.15

$18.04

$18.87

$0.00

$5.00

$10.00

$15.00

$20.00

2013

2014

2015

75.5

93.5

96.5

0.0

20.0

40.0

60.0

80.0

100.0

2013

2014

2015

$20.37

$16.25

$17.99

$13.45

$10.97

$13.08

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

2013

2014

2015

Group 3 3:2:1

Group 3 6:3:2:1

$5.23

$4.77

$4.71

$4.40

$4.60

$4.80

$5.00

$5.20

$5.40

2013

2014

2015

Refining Operating Information Per Barrel of

Throughput Reconciliation

18

($ in millions, unless otherwise indicated)

($ in millions unless otherwise indicated)

2013

2014

Q1 2015

Q2 2015

Q3 2015

Q4 2015

2015

Refinery gross margin per barrel:

Refinery revenue

$4,536.0

$5,097.7

$689.6

$839.8

$762.3

$645.1

$2,936.8

Refinery costs of sales

$4,008.4

$4,554.7

$513.7

$641.9

$590.2

$586.4

$2,332.2

Refinery gross margin

$527.6

$543.0

$175.9

$197.9

$172.1

$58.7

$604.6

Lower of cost or market inventory adjustment

-

72.2

(10.5)

(37.2)

36.0

71.8

60.1

Refinery gross margin excluding lower of cost or market inventory

adjustment

$527.6

$615.2

$165.4

$160.7

$208.1

$130.5

$664.7

Total refinery throughput (mmbbls)

27.5

34.1

8.5

9.0

8.3

9.4

35.2

Refinery gross margin per total throughput barrel ($/bbl)

$19.15

$15.91

$20.77

$21.98

$20.65

$6.23

$17.16

Refinery gross margin excluding lower of cost or market inventory

adjustment per total throughput barrel ($/bbl)

$19.15

$18.04

$19.53

$17.85

$24.97

$13.86

$18.87

Operating expense per barrel:

Direct operating expense

$144.1

$163.0

$38.9

$43.2

$40.3

$43.6

$166.0

Total refinery throughput (mmbbls)

27.5

34.1

8.5

9.0

8.3

9.4

35.2

Direct operating expense per total throughput barrel ($/bbl)

$5.23

$4.77

$4.59

$4.80

$4.84

$4.63

$4.71

Adjusted EBITDA & Cash Available for

Distribution Reconciliation

19

Q1

Q2

Q3

Q4

Q1

Q2

Q3

Q4

Net Income (Loss)

$71.5

$57.9

$96.2

$16.0

$111.2

$128.9

$103.5

($12.6)

Adjustments:

Interest expense

6.2

6.2

6.7

7.5

7.5

7.5

7.5

6.2

Income tax provision

0.1

1.5

1.9

3.6

0.8

2.9

3.6

1.1

Depreciation and amortization

9.9

10.2

10.7

11.1

10.8

10.8

11.0

11.4

EBITDA Subtotal

$87.7

$75.8

$115.5

$38.2

$130.3

$150.1

$125.6

$6.1

MPL proportionate depreciation expense

0.7

0.7

0.7

0.8

0.7

0.7

0.7

0.8

Turnaround and related expenses

0.5

0.9

4.6

8.9

0.4

1.2

7.8

1.2

Equity-based compensation impacts

7.4

2.9

2.0

1.7

2.6

2.9

2.4

2.4

Lower of cost or market inventory adjustment

     -

    -

-

73.6

(10.8)

(38.2)

36.8

73.0

Reorganization and related costs

6.3

1.8

-

-

-

-

-

-

Merger-related expenses

-

-

-

-

-

-

-

2.5

Adjusted EBITDA

$102.6

$82.1

$122.8

$123.2

$123.2

$116.7

$173.3

$86.0

Adjustments:

Cash interest expense

(5.6)

(5.6)

(5.7)

(6.9)

(7.0)

(6.9)

(7.1)

(7.1)

Cash income tax paid

(0.1)

(1.5)

(1.9)

(1.0)

(1.0)

(1.0)

(0.7)

(3.4)

MPL proportionate depreciation expense

(0.7)

(0.7)

(0.7)

(0.8)

(0.7)

(0.7)

(0.7)

(0.8)

Capital expenditures

(10.0)

(10.1)

(9.1)

(6.2)

(6.2)

(14.3)

(12.4)

(16.0)

Cash reserve for turnaround and related expenses

(7.5)

(7.5)

(7.5)

(7.5)

(7.5)

(7.5)

(7.5)

(7.5)

Cash reserve for discretionary capital expenditures

(7.5)

(7.5)

(5.0)

-

-

-

(7.5)

(7.5)

Working capital reserve (increase)/decrease

-

-

-

(55.2)

-

25.0

(40.0)

(8.0)

Cash available for distribution

$71.2

$49.2

$92.9

$45.6

$100.8

$111.3

$97.4

$35.7

2014

2015

Organic Growth Projects: Reconciliation of Annual

Forecasted Net Income to Annual Forecasted EBITDA

20

Annual Forecasted Net Income

1

$24.0

Add: Estimated Depreciation and Amortization

3.0

Annual Forecasted EBITDA

$27.0

($ in millions)

1

Based primarily on average crude prices, product netbacks, and other assumptions for the five full fiscal years of 2011 through 2015.  Actual results may differ.

Annual Forecasted Net Income

1

$9.3

Add: Estimated Depreciation and Amortization

0.7

Annual Forecasted EBITDA

$10.0

Annual Forecasted Net Income

1

$19.5

Add: Estimated Depreciation and Amortization

1.5

Annual Forecasted EBITDA

$21.0

Desalter

Project

No. 2 Crude and Diesel Hydrotreater

Project

Solvent Deasphalting

Project

Non-GAAP Measures

This presentation includes Non-GAAP financial and performance measures, including:

EBITDA and Adjusted EBITDA

Adjusted EBITDA is defined as net income (loss) before interest expense, income taxes and depreciation and amortization, adjusted for depreciation from the

Minnesota Pipe Line operations, lower of cost or market inventory adjustments, turnaround and related expenses, equity-based compensation expense, and merger-

related  expenses.  Adjusted EBITDA is not a presentation made in accordance with GAAP and our computation of Adjusted EBITDA may vary from others in our

industry.  In addition, Adjusted EBITDA contains some, but not all, adjustments that are taken into account in calculating the components of various covenants in the

agreements governing our 2020 Secured Notes and the ABL Facility.  We believe the presentation of Adjusted EBITDA is useful to investors because it is frequently used

by securities analysts, investors and other interested parties in the evaluation of companies in our industry.  The calculation of Adjusted EBITDA generally eliminates the

effects of financings, income taxes and the accounting effects of significant turnaround activities which many of our peers capitalize and therefore exclude from

Adjusted

EBITDA.

Adjusted

EBITDA

should

not

be

considered

as

an

alternative

to

operating

income

or

net

income

as

measures

of

operating

performance.

In

addition,

Adjusted

EBITDA

is

not

presented

as,

and

should

not

be

considered,

an

alternative

to

cash

flow

from

operations

as

a

measure

of

liquidity.

Adjusted

EBITDA

has

limitations as an analytical tool and should not be considered in isolation, or as a substitute for analysis of the results as reported under GAAP.

Cash Available for Distribution

Cash available for distribution is a non-GAAP performance measure that we believe is important to investors in evaluating our overall cash generation performance.

Cash

available

for

distribution

should

not

be

considered

as

an

alternative

to

operating

income

or

net

income

as

measures

of

operating

performance.

In

addition,

cash

available

for

distribution

is

not

presented

as,

and

should

not

be

considered,

an

alternative

to

cash

flow

from

operations

as

a

measure

of

liquidity.

As

shown

in

the

tables

in this

Appendix,

we

have

reconciled

cash

available

for

distribution

to

Adjusted

EBITDA

and

in

addition

reconciled

Adjusted

EBITDA

to

net

income.

Cash

available for

distribution

has

limitations

as

an

analytical

tool

and

should

not

be

considered

in

isolation,

or

as

a

substitute

for

analysis

of

the

results

as

reported

under

GAAP.

Our

calculation of cash available for distribution may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative

measure.

Cash

available

for

distribution

for

each

quarter

will

be

determined

by

the

board

of

directors

of

our

general

partner

following

the

end

of

such

quarter.

Refining Gross Margin

Refining gross margin is calculated by subtracting refining costs of sales from total refining revenues.  Refining gross margin excluding lower of cost or market (“LCM”)

inventory adjustment is calculated by adding back the non-cash LCM inventory adjustment to refining gross margin.  Refining gross margin and refining gross margin

excluding

LCM

are

non-GAAP

measures

that

we

believe

are

important

to

investors

in

evaluating

our

refining

segment

performance

as

a

general

indication

of

the

amount above its cost of products that is able to sell refined products.  NTI’s calculation of refining gross margin and refining gross margin excluding LCM may differ

from similar calculations by other companies in our industry, thereby limiting its usefulness as a comparative measure.

21