As filed with the Securities and Exchange Commission on May 30, 2012

Registration No. 333-178457

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

AMENDMENT NO. 3

FORM S-1

REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933

Northern Tier Energy, Inc.

to be converted to a partnership to be named

Northern Tier Energy LP

(Exact name of registrant as specified in its charter)

Delaware

2911

80-0763623

(State or other jurisdiction of

incorporation or organization)

(Primary Standard Industrial

Classification Code Number)

(I.R.S. Employer Identification No.)

38C Grove Street, Suite 100

Ridgefield, Connecticut 06877

(203) 244-6550

(Address, including zip code, and telephone number, including area code, of registrant’s principal executive offices)

Peter T. Gelfman

Vice President, General Counsel and Secretary

38C Grove Street, Suite 100

Ridgefield, Connecticut 06877

(203) 244-6550

(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:

Douglas E. McWilliams

Brenda K. Lenahan

Vinson & Elkins L.L.P.

1001 Fannin, Suite 2500

Houston, Texas 77002-6760

(713) 758-2222

M. Breen Haire

Baker Botts L.L.P.

910 Louisiana Street

Houston, Texas 77002

(713) 229-1234

Michael J. Volkovitsch

Cleary Gottlieb Steen & Hamilton LLP

One Liberty Plaza

New York, New York 10006

(212) 225-2000

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933 check the following box: ¨

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer ¨		Accelerated filer ¨		Non-accelerated filer þ (Do not check if a smaller reporting company)			Smaller reporting company ¨

The registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until this Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities, and we are not soliciting offers to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion, Dated May 30, 2012

Common Units

Representing Limited Partner Interests

Northern Tier Energy LP

This is the initial public offering of our common units representing limited partner interests. Prior to this offering, there has been no public market for our common units. We anticipate that the initial public offering price of our common units will be between $ and $ per common unit.

We have applied to list our common units on the New York Stock Exchange under the symbol “NTI.”

See “Risk Factors” on page 25 to read about factors you should consider before buying our common units. These risks include the following:

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We may not have sufficient available cash to pay any quarterly distribution on our units.

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The amount of our quarterly distributions, if any, will vary significantly both quarterly and annually and will be directly dependent on the performance of our business. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time.

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Restrictions in the agreements governing our indebtedness could limit our ability to make distributions to our unitholders.

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The price volatility of crude oil, other feedstocks, refined products and fuel and utility services may have a material adverse effect on our earnings, profitability, cash flows and liquidity, and our ability to make distributions to our unitholders.

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Our results of operations are affected by crude oil differentials, which may fluctuate substantially.

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Our general partner, the indirect owners of which include ACON Refining Partners, L.L.C., TPG Refining, L.P., and certain members of our management team, has fiduciary duties to its owners, and the interests of its owners may differ significantly from, or conflict with, the interests of our public common unitholders.

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Our unitholders have limited voting rights and are not entitled to elect our general partner or our general partner’s directors.

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You will incur immediate and substantial dilution in the net tangible book value of your common units.

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Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

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You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

Neither the Securities and Exchange Commission nor any state securities regulators has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.

PRICE $ PER COMMON UNIT


	Per Common Unit	Total
Initial public offering price	$	$
Underwriting discount	$	$
Proceeds, before expenses, to Northern Tier Energy LP	$	$

To the extent that the underwriters sell more than common units, the underwriters have the option to purchase up to an additional common units at the initial public offering price less the underwriting discount.

The underwriters expect to deliver the common units against payment in New York, New York on or about , 2012.


Goldman, Sachs & Co.		Barclays		BofA Merrill Lynch

Credit Suisse

Deutsche Bank Securities

UBS Investment Bank

J.P. Morgan Macquarie Capital

Prospectus dated , 2012.

LOGO

TABLE OF CONTENTS


Prospectus Summary			1
Risk Factors			25
Cautionary Note Regarding Forward-Looking Statements			64
Use of Proceeds			67
Capitalization			68
Dilution			69
Distribution Policy and Restrictions on Distributions			70
How We Make Distributions			88
Selected Historical Condensed Consolidated Financial Data			90
Management’s Discussion and Analysis of Financial Condition and Results of Operations			92
Business			139
Management			167
Compensation Discussion and Analysis			173
Certain Relationships and Related Person Transactions			193
Security Ownership of Certain Beneficial Owners and Management			198
Conflicts of Interest and Fiduciary Duties			200
Description of Our Common Units			207
The Partnership Agreement			209
Common Units Eligible for Future Sale			223
Material Federal Income Tax Consequences			224
Investment in Northern Tier Energy LP by Employee Benefit Plans			239
Underwriting			240
Legal Matters			246
Experts			246
Where You Can Find More Information			246
Index to Financial Statements			F-1
Appendix A: Form of First Amended and Restated Agreement of Limited Partnership			A-1
Appendix B: Glossary of Industry Terms Used in this Prospectus			B-1

Through and including , 2012 (the 25th day after the date of this prospectus), all dealers effecting transactions in our common units, whether or not participating in this offering, may be required to deliver a prospectus. This requirement is in addition to the dealers’ obligation to deliver a prospectus when acting as an underwriter and with respect to an unsold allotment or subscription.

We have not authorized anyone to provide any information or to make any representations other than those contained in this prospectus or in any free writing prospectuses we have prepared. We take no responsibility for, and can provide no assurance as to the reliability of, any other information that others may give you. This prospectus is an offer to sell only the common units offered hereby, but only under circumstances and in jurisdictions where it is lawful to do so. The information contained in this prospectus is current only as of its date.

Industry and Market Data

This prospectus includes industry data and forecasts that we obtained from industry publications and surveys, public filings and internal company sources. Industry publications and surveys and forecasts generally state that the information contained therein has been obtained from sources believed to be reliable, but there can be no assurance as to the accuracy or completeness of the included information. Statements as to our ranking, market position and market estimates are based on independent industry publications, government publications, third-party forecasts and management’s estimates and assumptions about our markets and our internal research. While we are not aware of any misstatements regarding our market, industry or similar data presented herein, such data involve risks and uncertainties and are subject to change based on various factors, including those discussed under the headings “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” in this prospectus.

This prospectus contains certain information regarding refinery complexity as measured by the Nelson Complexity Index, which is calculated on an annual basis by the Oil and Gas Journal. Certain data presented in this prospectus is from the Oil and Gas Journal Report dated January 1, 2010.

Trademarks and Trade Names

We own or have rights to various trademarks, service marks and trade names that we use in connection with the operation of our business. This prospectus may also contain trademarks, service marks and trade names of third parties, which are the property of their respective owners. Our use or display of third parties’ trademarks, service marks, trade names or products in this prospectus is not intended to, and does not imply a relationship with, or endorsement or sponsorship by us. Solely for convenience, the trademarks, service marks and trade names referred to in this prospectus may appear without the ^®, TM or SM symbols, but such references are not intended to indicate, in any way, that we will not assert, to the fullest extent under applicable law, our rights or the right of the applicable licensor to these trademarks, service marks and trade names.

PROSPECTUS SUMMARY

This summary highlights selected information contained elsewhere in this prospectus and is qualified in its entirety by the more detailed information and financial statements and notes thereto included elsewhere in this prospectus. Because it is abbreviated, this summary is not complete and does not contain all of the information that you should consider before investing in our common units. You should read the entire prospectus carefully before making an investment decision, including the information presented under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and the notes thereto included elsewhere in this prospectus. Unless otherwise indicated, the information presented in this prospectus assumes (i) an initial public offering price of $ per common unit, which represents the midpoint of the price range set forth on the cover of this prospectus, and (ii) that the underwriters’ option to purchase additional common units is not exercised. We have provided definitions for certain terms used in this prospectus in the “Glossary of Industry Terms Used in this Prospectus” beginning on page B-1 of this prospectus.

Unless the context otherwise requires, the terms “we,” “us,” “our,” “Successor” and “Company,” when used in the context of the period (i) prior to the completion of the transactions described in “—IPO Transactions,” refer to Northern Tier Energy LLC and its subsidiaries, which will be contributed to Northern Tier Energy LP in connection with the closing of this offering, and (ii) after the completion of the transactions described in “—IPO Transactions,” refer to Northern Tier Energy LP and its subsidiaries. References to our “general partner” refer to Northern Tier Energy GP LLC. References to “Northern Tier Holdings” refers to Northern Tier Holdings LLC, the owner of our general partner. References to “ACON Refining” refer to ACON Refining Partners, L.L.C. and certain of its affiliates and to “TPG Refining” refer to TPG Refining, L.P. and certain of its affiliates. References to “Marathon Oil” refer to Marathon Oil Corporation, references to “Marathon Petroleum” refer to Marathon Petroleum Corporation, a wholly owned subsidiary of Marathon Oil until June 30, 2011, and references to “Marathon” refer to Marathon Petroleum Company LP, an indirect, wholly owned subsidiary of Marathon Petroleum, and certain affiliates of Marathon Petroleum Company LP. References to the “Marathon Acquisition” refer to the acquisition by us of our St. Paul Park, Minnesota refinery, a 17% interest in the Minnesota Pipe Line Company, our convenience stores and related assets from Marathon, completed in December 2010. We refer to the assets acquired in the Marathon Acquisition as the “Marathon Assets.” The Marathon Acquisition is described in greater detail, including certain related transactions in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Comparability of Historical Results—Marathon Acquisition.”

Northern Tier Energy LP

We are an independent downstream energy limited partnership with refining, retail and pipeline operations that serve the PADD II region of the United States. We operate our assets in two business segments: the refining business and the retail business. For the three months ended March 31, 2012, we had total revenues of approximately $1.0 billion, operating income of $2.7 million, a net loss of $193.6 million and Adjusted EBITDA of $81.5 million. For the year ended December 31, 2011, we had total revenues of $4.3 billion, operating income of $422.6 million, net earnings of $28.3 million and Adjusted EBITDA of $430.7 million. For a definition, and reconciliation, of Adjusted EBITDA to net earnings, see “—Summary Historical Condensed Consolidated Financial and Other Data.”

Refining Business

Our refining business primarily consists of a 74,000 barrels per calendar day (“bpd”) (84,500 barrels per stream day) refinery located in St. Paul Park, Minnesota. Our refinery has a Nelson

complexity index of 11.5, which refers to the ability of a refinery to produce finished products based on its investment intensity and cost relative to other refineries. Our refinery’s complexity allows us to process a variety of light, heavy, sweet and sour crudes into higher value refined products.

We are one of only two refineries in Minnesota and one of four refineries in the Upper Great Plains area within the Petroleum Administration for Defense District (“PADD”) II region. Our strategic location allows us direct access, primarily via the Minnesota Pipeline, to what we believe are abundant supplies of advantageously priced crude oils. Of the crude oil processed at our refinery in 2011 and in the first quarter of 2012, approximately 51% and 61%, respectively, was Canadian crude oil and the remainder was comprised of mostly light sweet crude oil from the Bakken Shale in North Dakota. Many of these crude oils have historically priced at a discount to the U.S. benchmark West Texas Intermediate crude oil (“NYMEX WTI”). Further, over the past twelve months, NYMEX WTI has traded at an additional discount relative to waterborne crude oils, such as Brent crude oil (“Brent”).

We expect to continue to benefit from our access to these growing crude oil supplies. By 2025, according to the Canadian Association of Petroleum Producers (“CAPP”), total Canadian crude oil production is expected to grow to 4.7 million bpd from 2010 production of 2.8 million bpd. Crude oil production from the Bakken Shale in North Dakota has also increased significantly, growing from approximately 98,000 bpd in 2005 to approximately 558,000 bpd as of February 2012, and is expected to continue to grow due to improvements in unconventional resource production techniques.

Our location also allows us to distribute our refined products throughout the midwestern United States. Our refinery produces a broad slate of refined products including gasoline, diesel, jet fuel and asphalt, which are then marketed to resellers and consumers primarily in the PADD II region. Approximately 83% and 79% of our total refinery production for the three months ended March 31, 2012 and the year ended December 31, 2011, respectively, was comprised of higher value, light refined products, including gasoline and distillates.

We also own various storage and transportation assets, including a light products terminal, a heavy products terminal, storage tanks, rail loading/unloading facilities and a Mississippi river dock. Approximately 73% and 83% of our gasoline and diesel volumes for the three months ended March 31, 2012 and the year ended December 31, 2011, respectively, were sold via our light products terminal to our company-operated and franchised SuperAmerica branded convenience stores, Marathon branded convenience stores and other resellers. We have a contract with Marathon to supply substantially all of the gasoline and diesel requirements for 90 independently owned and operated Marathon branded convenience stores.

Our refining business also includes our 17% interest in the Minnesota Pipe Line Company LLC (the “Minnesota Pipe Line Company”), which owns and operates the Minnesota Pipeline, a 455,000 bpd crude oil pipeline system that transports crude oil (primarily from Western Canada and North Dakota) for approximately 300 miles from the Enbridge pipeline hub at Clearbrook, Minnesota to our refinery. The Minnesota Pipeline has historically transported the majority of the crude oil used and processed in our refinery.

Retail Business

and prepackaged items. Our refinery supplied substantially all of the gasoline and diesel sold in our company-operated and franchised convenience stores for the three months ended March 31, 2012 and the year ended December 31, 2011.

We also own and operate SuperMom’s Bakery, which prepares and distributes baked goods and other prepared food items for sale in our company-operated and franchised convenience stores and other third party locations.

Refining Industry Overview

Crude oil refining is the process of separating the hydrocarbons present in crude oil for the purpose of converting them into marketable finished, or refined, petroleum products such as gasoline, diesel, jet fuel, asphalt and other products. Refining is primarily a margin-based business where both the feedstock (primarily crude oil) and the refined products are commodities with fluctuating prices. In order to increase profitability, it is important for a refinery to maximize the yields of high value finished products and to minimize the costs of feedstock and operating expenses.

According to the Energy Information Administration (the “EIA”), as of January 1, 2011, there were 137 oil refineries operating in the United States, with the 15 smallest each having a refining capacity of 14,000 bpd or less, and the 10 largest having capacities ranging from 330,000 bpd to 560,640 bpd.

High capital costs, historical excess capacity and environmental regulatory requirements have limited the construction of new refineries in the United States over the past 30 years. According to the EIA, domestic operating refining capacity has increased approximately 5% between January 1982 and January 2011 from 16.1 million bpd to 16.9 million bpd. Much of this increase in capacity is generally the result of efficiency measures and moderate expansions at various refineries, known as “capacity creep,” but some significant expansions at existing refineries have occurred as well. During this same time period, more than 110 generally smaller and less efficient refineries that had limited access to a wide variety of crude oils or were unable to profitably process feedstock into a marketable product mix were closed.

According to the EIA, total demand for refined products in PADD II, which is the region in which we operate, has represented approximately 26% of total U.S. refined products demand from 2006 to 2010. Within PADD II, refined product production capacity is currently insufficient to meet demand. For example, according to the EIA, due to product supply shortfalls within PADD II, net receipts of gasoline, distillate and jet fuel/kerosene from domestic sources outside of PADD II comprised approximately 19%, 17% and 16%, respectively, of demand for these products. Refining capacity in the PADD II region has decreased approximately 3% between January 1982 and January 2011 from approximately 3.8 million bpd to approximately 3.6 million bpd, while more than 25 refineries in the PADD II region have ceased operations. The refined product volumes that are necessary to satisfy the demand in excess of PADD II production are primarily sourced from domestic refineries located outside of PADD II, specifically from the U.S. Gulf Coast.

Our Business Strategy

The primary components of our business strategy are:

Make Distributions Equal to the Available Cash We Generate Each Quarter. The board of directors of our general partner will adopt a policy under which distributions for each quarter will equal the amount of available cash (as described in “Distribution Policy and Restrictions on

Distributions”) we generate each quarter. We do not intend to maintain excess distribution coverage in order to stablize our quarterly distributions or to otherwise reserve cash for future distributions. In addition, our general partner has a non-economic interest and no incentive distribution rights, and, accordingly, our unitholders will receive 100% of our cash distributions. See “Distribution Policy and Restrictions on Distributions.”

Focus on Growth Opportunities. We intend to pursue opportunities to grow our business both organically and through acquisitions within the refining, logistics and retail marketing industries.

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Organic Growth Projects. We plan to continue to make investments to enhance the operating flexibility of our refinery, to improve our crude oil sourcing advantage and to grow our retail business. We intend to pursue organic growth projects at the refinery to improve the yield of light products we produce and the efficiency of our operations, which we believe should improve profitability. We also plan to make investments in logistics operations, including trucking, terminal and pipeline facilities, to enhance our crude oil sourcing flexibility and to reduce related crude oil purchasing and delivery costs. We also intend to invest in the growth of our retail business with the ultimate objective of having a dedicated outlet for all of our refinery’s gasoline production. We believe that this retail strategy should allow our refinery to reduce its reliance on the wholesale market, improve the capacity utilization of our refinery and increase our profitability.

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Evaluate Accretive Acquisition Opportunities. We will selectively pursue accretive acquisitions within our refining and retail business segments, both in our existing areas of operations as well as in new geographic regions that would diversify our operating footprint. In evaluating acquisitions within the refining industry, we will consider, among other factors, sustainable performance of the targeted assets through the refining cycle, access to advantageous sources of crude oil supplies, attractive demand and supply market fundamentals, access to distribution and logistics infrastructure, and potential operating synergies.

Focus on Optimizing Crude Oil Supply. We are focused on optimizing our crude oil purchases for our refining operations and minimizing our crude oil feedstock costs. Our strategic location and the refinery’s complexity allow us to receive and process a variety of light, heavy, sweet and sour crude oils from Western Canada and the United States, many of which have historically priced at a discount to the NYMEX WTI price benchmark.

Maintain Significant Liquidity in Our Business. We benefit from a number of sources of liquidity that provide us with financial flexibility during periods of volatile commodity prices, including cash on hand, our $300 million revolving credit facility, trade credit from our crude oil supplies and other mechanisms. For example, in December 2010, we entered into a crude oil supply and logistics agreement with J.P. Morgan Commodities Canada Corporation (“JPM CCC”), which was later amended and restated in March 2012, to supply our refinery’s crude oil feedstock requirements, which helps reduce the amount of working capital required in our refinery operations. We manage our operations prudently with a focus on maintaining sufficient liquidity to meet unforeseen capital needs. On a pro forma basis for this offering, as of March 31, 2012, we estimate that we would have had approximately $ million of available liquidity comprised of cash on hand and amounts available for borrowing under our $300 million revolving credit facility. Our actual available liquidity may vary from our estimated amount depending on several factors, including fluctuations in inventory and accounts receivable values as well as cash reserves.

Selectively Engage in Hedging Activities to Ensure Sufficient Cash Flows to Service Our Fixed Obligations. We plan to systematically evaluate the merits of entering into commodity derivatives contracts to hedge our refining margins with respect to a portion of our gasoline and diesel production. We will engage in these activities with the purpose of ensuring that we have sufficient cash flows to meet our fixed cost obligations, service our outstanding debt and other liabilities, and meet our capital expenditure requirements.

Commodity derivatives contracts that we may enter into include either exchange-traded contracts in the form of futures contracts or over-the-counter contracts in the form of commodity price swaps that reference benchmark indices.

As of March 31, 2012, approximately 15 million barrels of our future gasoline and diesel production remained hedged under commodity derivatives contracts of which 10 million barrels related to 2012 production and the remainder to 2013 production. Our hedge positions for 2011 and 2012 production were established at the time of the Marathon Acquisition and our plan is to hedge a lesser amount of production than we hedged at the time of the acquisition. Consequently, we plan to increase our exposure to the gross refining margins that we would realize at our refinery on an unhedged basis over time.

In addition, during the second quarter of 2012, we reset the price of our contracts for the period of July 2012 through December 2012 and recognized a loss of approximately $92 million. We plan to use a portion of the net proceeds of this offering to settle this obligation. If we do not complete this offering, the loss from resetting the price of our derivative contracts will be paid to the counterparty on the same monthly schedule as the original contracts were scheduled to settle.

Our Competitive Strengths

We have a number of competitive strengths that we believe will help us to successfully execute our business strategy:

Strategically Located Refinery with Advantageous Access to Crude Oil Supply. Our refinery is located on approximately 170 acres along the Mississippi River in a strategically advantageous area within the PADD II region. The refinery has the ability to source a variety of crude oils, including heavy Canadian crude oils and light North Dakota crude oils, primarily via the Minnesota Pipeline. Our refinery also has access to crude oils from Cushing, Oklahoma, the U.S. Gulf Coast and other foreign markets. The ability to source and process multiple types of crude oil enables us to capitalize on changing market conditions and, we believe, increase our profitability. For the three months ended March 31, 2012, 61% of the crude oil processed at the refinery was Canadian crude oil, with the remainder comprised of locally produced U.S. crude oils, mostly from the Bakken Shale in North Dakota. Historically, we have purchased our crude oil at a discount to NYMEX WTI as a result of our close proximity to plentiful sources of crude oil in Western Canada and North Dakota. Over the five years ended March 31, 2012, we realized an average discount of $1.56 per barrel of crude oil purchased for our refinery when compared to the average NYMEX WTI price per barrel over the same period. More recently, the increase of the discount at which a barrel of NYMEX WTI traded relative to Brent has allowed refineries, such as ours, that are capable of sourcing and utilizing crude oil that is priced more in line with NYMEX WTI, to realize relatively lower feedstock costs and benefit from the higher refined product prices resulting from higher Brent prices.

Attractive Regional Refined Products Supply/Demand Dynamics. In recent years, demand for refined products in the PADD II region has exceeded regional production, resulting in a need for imports from other regions, specifically from the U.S. Gulf Coast region. Our inland location means that foreign and coastal domestic refiners seeking to access our marketing area would incur additional transportation costs. Over the five years ended March 31, 2012, our refinery has realized an average price premium of $3.45 per barrel for its gasoline and distillates production relative to the prices used in calculating the U.S. Gulf Coast 3:2:1 crack spread and an average price premium of $2.01 per barrel relative to the benchmark PADD II Group 3 3:2:1 crack spread (the “Group 3 3:2:1 crack spread”), in each case assuming a comparable rate of two barrels of gasoline and one barrel of distillate (see footnote 4 in “—Summary Historical Condensed Consolidated Financial and Other Data”).

Substantial Refinery Operating Flexibility. Since 2006, approximately $226 million (including $194 million from January 2006 through November 2010 and $32 million from our inception date of June 23, 2010 through March 2012) has been invested in upgrades and capital projects to modernize the St. Paul Park refinery, improve its operating flexibility, increase its complexity and meet U.S. environmental, health and safety requirements, including revamping the gas oil hydrotreater in 2006 to allow for the production of ultra low sulfur diesel. As a result of these capital expenditures, we believe that we will be able to comply with known prospective fuel quality requirements without incurring significant capital costs or substantially increased operating costs. In addition, we have significant redundancies in our refining assets, which include two crude oil distillation and vacuum towers, two reformers, two sulfur recovery units and five hydrotreating units. These redundancies allow us to continue to receive and process crude oil and other feedstocks in the event a unit goes out of service and allows for increased maintenance flexibility as a redundant unit may be used without having to shut down the entire refinery in the case of a major unit turnaround.

Our refinery has a Nelson complexity index of 11.5. Our refinery’s complexity means we can process lower cost crude oils into higher value light refined products, including transportation fuels, such as gasoline and distillates. Gasoline and distillates comprised approximately 83% and 79% of our total refinery production for the three months ended March 31, 2012 and the year ended December 31, 2011, respectively.

Strong Refinery Operating and Safety Track Record. Our refinery has a strong operating and safety track record as evidenced by our high mechanical availability and low recordable incidents. This performance is due to, among other things, the periodic upgrades and maintenance performed at our refinery. We measure our safety track record primarily through the use of injury frequency rates as determined by the Occupational Safety and Health Administration (“OSHA”). Our refinery had an OSHA Recordable Rate of 0.60 and 0.52 during the three months ended March 31, 2012 and the year ended December 31, 2011, respectively.

Integrated Refining and Retail Distribution Operations. Our business is an integrated refining operation with significant storage assets and a retail distribution network comprising, as of March 31, 2012, 166 company-operated and 67 franchised convenience stores, all of which are operated under the SuperAmerica brand. For the three months ended March 31, 2012 and the year ended December 31, 2011, we sold 73% and 83% of our gasoline and diesel volumes, respectively, via our eight-bay bottom-loading light products terminal located at the refinery, primarily to our retail distribution network and, to a lesser extent, other resellers. Our refinery supplied substantially all of the gasoline and diesel sold in our company-operated and franchised convenience stores during these periods. We also have a contract with Marathon to supply substantially all of the gasoline and diesel requirements of 90 independently owned and

operated Marathon branded convenience stores. In addition, we also have (i) a seven-bay heavy products terminal located on the refinery property, (ii) rail facilities for shipping liquefied petroleum gases and asphalt and for receiving butane, isobutane, crude oil and ethanol and (iii) a barge dock on the Mississippi River used primarily for shipping vacuum residuals and slurry.

Experienced, Proven and Incentivized Management Team. Our management team is led by our Chief Executive Officer, Mario E. Rodriguez, formerly a managing director in the global energy investment banking division of Citigroup Global Markets, who has approximately 20 years of experience in the energy and finance industries. Our President and Chief Operating Officer, Hank Kuchta, has over 30 years of industry experience and was formerly President and Chief Operating Officer of Premcor Inc. Premcor operated four refineries in the United States with approximately 750,000 bpd of refining capacity at the time of its sale to Valero Energy Corporation in April 2005. Prior to Premcor, Mr. Kuchta served in various management positions at Phillips 66 Company, Tosco Corporation and Exxon Corporation. Our President of refinery operations, Greg Mullins, previously worked at Marathon for over 30 years and has extensive experience in all aspects of refinery operations and management as well as major project development and project management. Several members of our management team, including our President and Chief Operating Officer; our Vice President, Marketing; our Vice President, Supply; our Vice President, Human Resources; and our Vice President, Chief Information Officer, have experience working together as a management team at Premcor.

Risk Factors

Investing in our common units involves risks that include the volatility of crude oil and other refinery feedstocks, competition, our partnership structure, the tax characteristics of our common units and other material factors. For a discussion of these risks and other considerations that could negatively affect us, see “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Our Relationship with ACON Refining and TPG Refining

Following this offering, ACON Refining and TPG Refining will indirectly control and own a substantial majority of the economic interests in Northern Tier Holdings. Following this offering, Northern Tier Holdings will own 100% of our general partner and % of our units (including 100% of our PIK units).

ACON Investments, L.L.C., an affiliate of ACON Refining, and certain other of its affiliates (“ACON Investments”) manage private equity funds and special purpose investment partnerships. ACON Investments has executed investments in upstream and midstream oil and gas companies as well as in energy infrastructure and energy services. TPG Global LLC (together with its affiliates, “TPG”), an affiliate of TPG Refining, is a leading private investment firm with $49 billion of assets under management as of December 31, 2011. TPG has extensive global experience with investments in the energy sector. We believe we will benefit from ACON Investments’ and TPG’s collective experience in the energy industry.

At the closing of this offering, ACON Funds Management L.L.C. (“ACON Management”), an affiliate of ACON Investment, and TPG VI Management, LLC, an affiliate of TPG (“TPG Management”), will receive a one time, aggregate success fee of $6.0 million pursuant to the management services agreement that will terminate in connection with the closing of this offering. The success fee will be divided equally between ACON Management and TPG Management. In addition, ACON Refining and TPG Refining will receive a distribution of $ million from the net proceeds of this offering.

Our Management

We are managed and operated by the board of directors and executive officers of our general partner, which is owned by Northern Tier Holdings. Following this offering, % of our units (including 100% of our PIK units) will be owned by Northern Tier Holdings. Northern Tier Holdings, as the owner of our general partner, will have the right to appoint all members of the board of directors of our general partner, including the independent directors. Our unitholders will not be entitled to elect our general partner or its directors or otherwise directly participate in our management or operation. For more information about the executive officers and directors of our general partner, please read “Management.”

Following the consummation of this offering, neither our general partner nor its affiliates will receive any management fee, but we will reimburse our general partner and its affiliates for all expenses they incur and payments they make on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.

Our operations will be conducted through, and our operating assets will be owned by, our wholly owned subsidiary, Northern Tier Energy LLC, and its subsidiaries. All of the employees who conduct our business will be employed by Northern Tier Energy LLC and its subsidiaries. Northern Tier Energy LP does not have any employees.

Conflicts of Interest and Fiduciary Duties

Our general partner has a legal duty to manage us in good faith. However, the officers and directors of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to its indirect owners, which include ACON Refining, TPG Refining and certain members of our management team. As a result, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its owners, on the other hand. Our partnership agreement limits the liability and reduces the duties owed by our general partner to our unitholders. Our partnership agreement also restricts the remedies available to our unitholders for actions that might otherwise constitute a breach of our general partner’s duties. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and each unitholder is treated as having consented to various actions and potential conflicts of interest contemplated in the partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law.

For a more detailed description of the conflicts of interest and the fiduciary duties of our general partner, see “Conflicts of Interest and Fiduciary Duties.” For a description of other relationships with our affiliates, see “Certain Relationships and Related Person Transactions.”

The IPO Transactions

In connection with the closing of this offering, the following transactions will occur:

The settlement agreement with Marathon with respect to the contingent consideration arrangements that we entered into in connection with the Marathon Acquisition will become effective. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Comparability of Historical Results—Marathon Acquisition and Related Transactions;”

Our management services agreement with ACON Management and TPG Management will terminate. See “Certain Relationships and Related Person Transactions—Agreements with Affiliates of Our General Partner—Management Services Agreement;”

Northern Tier Holdings LLC will contribute all of its membership interests in Northern Tier Energy LLC to Northern Tier Energy LP in exchange for PIK units and common units and the right to receive additional cash or common units as described below;

Northern Tier Energy LP will issue common units to the public, representing a % limited partner interest in us, and will use the net proceeds from this offering as described under “Use of Proceeds;”

Northern Tier Retail Holdings LLC, a wholly-owned subsidiary of Northern Tier Energy LLC that holds all of the ownership interests in Northern Tier Retail LLC and Northern Tier Bakery LLC, through which we conduct our retail business, will elect to be treated as a corporation for federal income tax purposes, subjecting that subsidiary to corporate-level tax; and

Northern Tier Energy Holdings LLC, a wholly-owned subsidiary of Northern Tier Energy LP, will elect to be treated as a corporation for federal income tax purposes, subjecting that subsidiary to corporate-level tax. Northern Tier Energy Holdings LLC will not have any independent operations.

We have granted the underwriters a 30-day option to purchase up to an aggregate of additional common units. Any net proceeds received from the exercise of this option will be distributed to Northern Tier Holdings. If the underwriters do not exercise this option in full or at all, the common units that would have been sold to the underwriters had they exercised the option in full will be issued to Northern Tier Holdings at the expiration of the option period. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding.

We refer to the above transactions as the “IPO Transactions.”

Organizational Structure

The following chart provides a simplified overview of our organizational structure after giving effect to the IPO Transactions (assuming the underwriter’s option to purchase additional common units is not exercised):

LOGO

(1)

All of the common interests in Northern Tier Holdings are owned by Northern Tier Investors, LLC, a Delaware limited liability company, the sole member of which is Northern Tier Investors LP, a Delaware limited partnership. All of the limited partnership interests in Northern Tier Investors LP are held by ACON Refining (48.75%), TPG Refining (48.75%) and certain members of our management team (2.5%). All of the limited liability company interests in the general partner of Northern Tier Investors LP, NTI GenPar LLC, a Delaware limited liability company, are held equally by ACON Refining and TPG Refining. Marathon will hold a $45 million preferred interest in Northern Tier Holdings. All of our PIK units will initially be owned by Northern Tier Holdings. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Comparability of Historical Results—Marathon Acquisition And Related Transactions.”

(2)	Northern Tier Energy Holdings LLC, which will elect to be treated as a corporation for federal income tax purposes in connection with the closing of this offering, will be a wholly-owned subsidiary of Northern Tier Energy LP and will hold a 0.01% membership interest in Northern Tier Energy LLC.

(3)	Includes 17% of the limited liability company interests of Minnesota Pipe Line Company, LLC and 17% of the stock of MPL Investments, Inc.

(4)

Northern Tier Retail Holdings LLC, a wholly-owned subsidiary of Northern Tier Energy LLC that holds all of the ownership interests in Northern Tier Bakery LLC and Northern Tier Retail LLC, will elect to be treated as a corporation for federal income tax purposes in connection with the closing of this offering.

Principal Executive Offices and Internet Address

Our principal executive offices are located at 38C Grove Street, Suite 100, Ridgefield, Connecticut 06877 and our telephone number at that address is (203) 244-6550. Our website is located at www.ntenergy.com. We expect to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission (“SEC”), available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference herein and does not constitute a part of this prospectus.

The Offering

Issuer

Northern Tier Energy LP, a Delaware limited partnership.

Common units offered to the public

common units.

Option to purchase additional common units

We have granted the underwriters a 30-day option to purchase up to an aggregate of additional common units.

Units outstanding after this offering

common units and PIK units.

We have granted the underwriters a 30-day option to purchase up to an aggregate of additional common units. If the underwriters do not exercise this option in full or at all, the common units that would have been sold to the underwriters had they exercised the option in full will be issued to Northern Tier Holdings at the expiration of the option period. Accordingly, the exercise of the underwriters’ option will not affect the total number of common units outstanding.

Use of proceeds

We expect to receive approximately $ million of net proceeds from the sale of the common units offered by us, based upon the assumed initial public offering price of $ per common unit (the midpoint of the price range set forth on the cover page of this prospectus), after deducting the underwriting discount of $ million (or $ million if the underwriters exercise in full their option to purchase additional common units) and estimated offering expenses of $ million. Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $ million (assuming no exercise of the underwriters’ option to purchase additional common units).

We intend to use the net proceeds received from this offering to:

•

redeem $29 million of our senior secured notes at a redemption price of 103% of the principal amount thereof, for an estimated $30 million;

•

pay $40 million to Marathon, which represents the cash component of a settlement agreement we entered into with Marathon related to a contingent consideration agreement that was entered into at the time of the Marathon Acquisition;

•

pay $92 million to J. Aron & Company, an affiliate of Goldman, Sachs & Co., for losses incurred during the quarter ending June 30, 2012 as a result of resetting the price of certain derivative contracts; and

•

distribute approximately $ million to Northern Tier Holdings, of which $ million will be used to redeem Marathon’s existing preferred interest in Northern Tier Holdings and $ million will be distributed to ACON Refining, TPG Refining and certain members of our management team.

The remaining net proceeds of $ will be used to fund capital expenditures and for general partnership purposes. See “Use of Proceeds.”

Any net proceeds received from the exercise of the underwriters’ option to purchase additional common units will be distributed to Northern Tier Holdings.

Distribution policy

Within 60 days after the end of each quarter, beginning with the quarter ending , 2012, we expect to make distributions to unitholders of record on the applicable record date. We expect our first distribution will include available cash (as described below) for the period from the closing of this offering through , 2012.

We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or to otherwise reserve cash for distributions, and we do not intend to incur debt to pay quarterly distributions. We expect to

finance substantially all of our growth externally, either by debt issuances or additional issuances of equity.

Because our policy will be to distribute (through cash and in-kind distributions) an amount equal to all available cash we generate each quarter, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, will vary based on our operating cash flow during such quarter. As a result, our quarterly distributions, if any, will not be stable and will vary from quarter to quarter as a direct result of variations in, among other factors, (i) our operating performance, (ii) cash flows caused by, among other things, fluctuations in the prices of crude oil and other feedstocks and the prices we receive for finished products, working capital or capital expenditures and (iii) cash reserves deemed necessary or appropriate by the board of directors of our general partner. Such variations in the amount of our quarterly distributions may be significant. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The board of directors of our general partner may change our distribution policy at any time. Our partnership agreement does not require us to pay distributions to our unitholders on a quarterly or other basis.

Certain provisions of the indenture governing our senior secured notes and our revolving credit facility place restrictions on our ability to make cash distributions. Subject to certain exceptions, the restricted payment covenant under the indenture governing our senior secured notes restricts us from making cash distributions unless our fixed charge coverage ratio, as defined in the indenture, is at least 2.0 to 1.0 after giving pro forma effect to such distributions and such cash distributions do not exceed an amount equal to the aggregate net proceeds received by us (either as a result of capital contributions or from the sale of equity or certain debt securities) plus 50% of our consolidated net income (or less 100% of consolidated net loss) accrued on a cumulative basis plus certain other items. As of December 31, 2011 and March 31, 2012, our restricted payments basket under the indenture was equal to approximately $61.4 million and $59.2 million, respectively. On a pro forma basis for this offering, as of December 31, 2011 and March 31, 2012, our restricted payments basket under the indenture would have been equal to approximately $ million and $ million,

respectively. Our revolving credit facility generally restricts our ability to make cash distributions if (a) we fail to have excess availability under the facility at least equal to the greater of (1) 25% of the lesser of (x) the $300 million commitment amount and (y) the then applicable borrowing base and (2) $37.5 million or (b) we fail to maintain a fixed charge coverage ratio, as defined by the revolving credit facility, after giving pro forma effect to such distributions of at least 1.1 to 1.0.

Based upon our forecasted results, we expect that available cash for the twelve months ending June 30, 2013 will be approximately $220.4 million. The following table sets forth our forecast of available cash on a quarterly basis for the twelve months ending June 30, 2013:


Three Months Ending	Available Cash
	(in millions)
September 30, 2012	$	94.2
December 31, 2012		73.6
March 31, 2013		37.5
June 30, 2013		15.1

The forecasted available cash as of June 30, 2013 is projected to be unfavorably impacted by a planned turnaround during the second quarter of 2013. We expect that available cash for the three months ending September 30, 2013 will be approximately $56.6 million.

Distribution of the full amount in cash for each period is projected to be permitted under the restricted payments basket of the indenture. See “Distribution Policy and Restrictions on Distributions—Forecasted Available Cash.” Unanticipated events may occur which could materially adversely affect the actual results we achieve during the forecast periods.

Consequently, our actual results of operations, cash flows, financial condition and our need for cash reserves during the forecast periods may vary from the forecast, and such variations may be material. Prospective investors are cautioned not to place undue reliance on our forecast and should make their own independent assessment of our future results of operations, cash flows and financial condition. In addition, the board of directors of our general partner may be required to, or elect to, reduce or eliminate our distributions at any time during periods of high prices for refinery feedstocks, such as crude oil, and/or reduced prices or demand for our refined products, among other reasons. See “Risk Factors.”

PIK units

Northern Tier Holdings initially will own all of our PIK units. These units are called “PIK units” because as

described below distributions on such units will be “payable in kind.” Distributions on common units will be in cash, but during the PIK period described below, our general partner will cause distributions to be payable by Northern Tier Energy LP on the PIK units in additional PIK units to PIK unitholders of record on the applicable record date. The effect of paying distributions of additional PIK units on PIK units, which we refer to as distributions in kind or distributions of equity, is as if we had paid cash distributions on those PIK units, and the holders of those PIK units had in turn recontributed that cash to us in exchange for additional PIK units. In order to make distributions in kind on these securities, we will have to have sufficient available cash to have paid them in cash and must pay a simultaneous cash distribution to the holders of our common units.

The number of PIK units that will be distributed on a PIK unit in lieu of a quarterly cash distribution will equal a fraction, the numerator of which is the amount of the cash distribution paid on a common unit and the denominator of which is the volume-weighted average price of a common unit for the 10 trading days immediately preceding the ex-dividend date for the associated distribution in respect of the common unit.

This calculation is intended to provide the holders of PIK units with a number of PIK units equal in value on a per unit basis to the cash being distributed to common unitholders.

While the PIK units will not receive cash distributions during the PIK period, the distribution of additional PIK units in lieu of cash distributions may substantially increase the number of units outstanding and the amount of cash required on a quarterly and annual basis to pay distributions on all units.

The PIK period will commence on the date of the closing of the offering and end on the date that is the earlier of (i) and (ii) the date by which we redeem, repurchase, defease or retire all of the senior secured notes, or amend the indenture governing the senior secured notes in a manner that removes restrictions on our ability to distribute all available cash to unitholders.

Immediately following the end of the PIK period, each outstanding PIK unit will be automatically converted into a common unit and entitled to receive any distributions in cash. The purpose of this feature is to support the payment of cash distributions to our common unitholders during periods in which we expect that certain of the

provisions of the existing notes indenture may restrict the ability of Northern Tier Energy LLC, our operating subsidiary, to distribute cash to us and thus our ability to distribute all available cash in accordance with our distribution policy.

Incentive distribution rights

None.

Subordination period

None.

Issuance of additional units

Our partnership agreement authorizes us to issue an unlimited number of additional units, including PIK units, units with rights to distributions or in liquidation that are senior to our common units, and rights to buy units for the consideration and on the terms and conditions determined by the board of directors of our general partner, without the approval of our unitholders. See “Common Units Eligible for Future Sale” and “The Partnership Agreement—Issuance of Additional Partnership Interests.”

Limited voting rights

Our general partner manages and operates us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Unitholders will have no right to elect our general partner or our general partner’s directors on an annual or other continuing basis. Our general partner may be removed by a vote of the holders of at least two-thirds of the outstanding units (with holders of the common units and holders of the PIK units voting together as a single class), including any units owned by our general partner and its affiliates (including Northern Tier Holdings). Upon the completion of this offering, Northern Tier Holdings will own an aggregate of approximately % of our outstanding units (approximately % if the underwriters exercise their option to purchase additional common units in full). This will give Northern Tier Holdings the ability to prevent removal of our general partner. See “The Partnership Agreement—Voting Rights.”

Call right

If at any time our general partner and its affiliates (including Northern Tier Holdings) own more than 80% of the units, our general partner will have the right, but not the obligation, to purchase all, but not less than all, of the units held by unaffiliated unitholders at a price not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. See “The Partnership Agreement—Call Right.”

Estimated ratio of taxable income to distributions

We estimate that if you own the common units you purchase in this offering through the record date for

distributions for the period ending , you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be % or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $ per common unit, we estimate that your average allocable federal taxable income per year will be no more than $ per common unit. See “Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions.”

Material federal income tax consequences

For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders, see “Material Federal Income Tax Consequences.”

Exchange listing

We have applied to list our common units on the New York Stock Exchange (“NYSE”) under the symbol “NTI.”

Summary Historical Condensed Consolidated Financial and Other Data

The following tables present certain summary historical condensed consolidated financial and other data. The combined financial statements for the year ended December 31, 2009, and the eleven months ended November 30, 2010 represent a carve-out financial statement presentation of several operating units of Marathon, which we refer to as “Predecessor.” For more information on the carve-out presentation, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Predecessor Carve-Out Financial Statements” and our financial statements and the notes thereto included elsewhere in this prospectus. The historical combined financial data for periods prior to December 1, 2010 presented below do not reflect the consummation of the Marathon Acquisition and the transactions related thereto or our capital structure following the Marathon Acquisition and the transactions related thereto. Northern Tier Energy LLC was formed on June 23, 2010 and entered into certain agreements with Marathon on October 6, 2010 to acquire the Marathon Assets. At the closing of the Marathon Acquisition on December 1, 2010, Northern Tier Energy LLC acquired the Marathon Assets. Northern Tier Energy LLC had no operating activities between its inception date and the closing date of the Marathon Acquisition, although it incurred various transaction and formation costs which have been included in the period June 23, 2010 (inception date) through December 31, 2010 (the “2010 Successor Period”).

The summary historical financial data as of March 31, 2012 and for the three months ended March 31, 2011 and 2012 are derived from unaudited financial statements and the notes thereto included elsewhere in this prospectus. The summary historical financial data as of December 31, 2010 and 2011, for the year ended December 31, 2009, the eleven months ended November 30, 2010, the 2010 Successor Period and the year ended December 31, 2011 are derived from audited financial statements and the notes thereto included elsewhere in this prospectus. The summary historical combined balance sheet data as of November 30, 2010 and December 31, 2009 were derived from audited financial statements and the notes thereto and the summary historical balance sheet data as of March 31, 2011 was derived from unaudited financial statements and the notes thereto that are not included in this prospectus.

On a pro forma basis, net earnings for the year ended December 31, 2011 would have been $24.2 million, adjusted for certain items that will impact earnings following the consummation of the offering. These items include a reduction of interest expense of $3.0 million related to the redemption of a portion of our senior secured notes, increased general and administrative expenses of $3.5 million as a result of being a publicly traded partnership, a $5.7 million tax provision attributable to our retail business becoming a tax paying entity and a reduction of $2.1 million in management fees paid to ACON Management and TPG Management.

As a result of the elections by Northern Tier Retail Holdings LLC, a wholly-owned subsidiary of Northern Tier Energy LLC that holds all of the ownership interests in Northern Tier Retail LLC and Northern Tier Bakery LLC, and Northern Tier Energy Holdings LLC to be treated as corporations for federal income tax purposes, for periods following such election, our financial statements will include a tax provision on income attributable to these subsidiaries. On a pro forma basis after giving effect to such election, we would have recorded a tax benefit of approximately $0.2 million for the three months ended March 31, 2012 and a tax provision of approximately $5.7 million for the year ended December 31, 2011. In addition, we will record a tax provision related to the recognition of deferred taxes equal to the tax effect of the difference between the book and tax basis of the assets of these subsidiaries and liabilities as of the effective date of the election. Assuming we had completed the conversion as of March 31, 2012, the amount of the deferred tax provision would have been approximately $ million.

You should read the tables along with “Risk Factors,” “Use of Proceeds,” “Capitalization,” “Selected Historical Condensed Consolidated Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business” and our financial statements and the notes thereto included elsewhere in this prospectus.


	Predecessor						Successor
	Year Ended December 31, 2009			Eleven Months Ended November 30, 2010			June 23, 2010 (inception date) to December 31, 2010			Year Ended December 31, 2011			Three Months Ended March 31,
	Year Ended December 31, 2009			Eleven Months Ended November 30, 2010			June 23, 2010 (inception date) to December 31, 2010			Year Ended December 31, 2011			2011			2012
	(Dollars in millions, except per barrel/gallon data)
Consolidated and combined statements of operations data:
Total revenue	$	2,940.5		$	3,195.2		$	344.9		$	4,280.8		$	940.2		$	999.1
Costs, expenses and other:
Cost of sales		2,507.9			2,697.9			307.5			3,508.0			779.0			839.8
Direct operating expenses		238.3			227.0			21.4			260.3			61.9			60.7
Turnaround and related expenses		0.6			9.5			–			22.6			3.3			3.5
Depreciation and amortization		40.2			37.3			2.2			29.5			7.3			8.5
Selling, general and administrative expenses		64.7			59.6			6.4			90.7			18.4			20.3
Formation costs		–			–			3.6			7.4			2.5			–
Contingent consideration income		–			–			–			(55.8	)		(31.8	)		65.7
Other (income) expense, net		(1.1	)		(5.4	)		0.1			(4.5	)		(1.1	)		(2.1	)

Operating income		89.9			169.3			3.7			422.6			100.7			2.7

Realized losses from derivative activities		–			–			–			(310.3	)		(52.2	)		(52.9	)
Loss on early extinguishment of derivatives		–			–			–			–			–			(44.6	)
Unrealized losses from derivative activities		–			(40.9	)		(27.1	)		(41.9	)		(262.9	)		(88.4	)
Bargain purchase gain		–			–			51.4			–			–			–
Interest expense		(0.4	)		(0.3	)		(3.2	)		(42.1	)		(10.0	)		(10.4	)

Earnings (loss) before income taxes		89.5			128.1			24.8			28.3			(224.4	)		(193.6	)
Income tax provision		(34.8	)		(67.1	)		–			–			(0.1	)		–

Net earnings (loss)	$	54.7		$	61.0		$	24.8		$	28.3		$	(224.5	)	$	(193.6	)

Consolidated and combined statements of cash flow data:
Net cash provided by (used in):
Operating activities	$	129.4		$	145.4		$	–		$	209.3		$	94.3		$	(54.8	)
Investing activities		(25.0	)		(29.3	)		(363.3	)		(156.3	)		(117.8	)		(4.6	)
Financing activities		(103.9	)		(115.4	)		436.1			(2.3	)		–			–
Capital expenditures		(29.0	)		(29.8	)		(2.5	)		(45.9	)		(6.0	)		(5.4	)

Consolidated and combined balance sheets data (at period end):
Cash and cash equivalents	$	6.0		$	6.7		$	72.8		$	123.5		$	49.3		$	64.1
Total assets		710.1			717.8			930.6			998.8			924.1			962.7
Total long-term debt		–			–			314.5			301.9			314.5			301.9
Total liabilities		343.9			405.4			645.6			686.6			859.5			843.7
Total equity (1)		366.2			312.4			285.0			312.2			64.6			119.0


	Predecessor				Successor
	Year Ended December 31, 2009		Eleven Months Ended November 30, 2010		June 23, 2010 (inception date) to December 31, 2010		Year Ended December 31, 2011		Three Months Ended March 31,
	Year Ended December 31, 2009		Eleven Months Ended November 30, 2010		June 23, 2010 (inception date) to December 31, 2010		Year Ended December 31, 2011		2011		2012
	(Dollars in millions, except per barrel/gallon data)
Other data:
Adjusted EBITDA(2)	$	135.2	$	220.1	$	9.9	$	430.7	$	83.2	$	81.5
Refinery segment data:

Refinery feedstocks (bpd):
Light and intermediate crude		59,112		55,402		59,872		56,722		56,453		58,368
Heavy crude		15,427		18,693		14,777		20,730		21,888		14,877
Other feedstocks/ blendstocks		7,024		5,971		6,487		3,698		6,433		2,759

Total throughput		81,563		80,066		81,136		81,150		84,774		76,004

Refinery product yields (bpd):
Gasoline		42,674		41,080		42,485		40,240		41,489		38,902
Distillates		22,876		22,201		26,258		24,841		23,795		24,160
Asphalt		7,688		9,532		9,099		9,888		9,615		8,323
Other		8,888		8,145		4,011		7,110		9,805		5,052

Total production		82,126		80,958		81,853		82,079		84,704		76,437

Refinery gross product margin per barrel of throughput(3)	$	9.36	$	12.86	$	9.94	$	20.26	$	16.54	$	17.71
SPP Refinery 3:2:1 crack spread (per barrel)(4)	$	10.35	$	15.12	$	13.85	$	27.92	$	27.68	$	24.28
Group 3 3:2:1 crack spread (per barrel)(4)	$	7.94	$	9.34	$	9.88	$	25.37	$	18.98	$	22.29

Retail segment data:
Gallons sold (in millions)		335.7		316.0		29.1		324.0		78.1		74.1
Retail fuel margin per gallon (for company-operated stores)(5)	$	0.14	$	0.17	$	0.16	$	0.21	$	0.15	$	0.18

(1)

Total equity for the Predecessor represents a net balance reflecting Marathon’s investment and the effect of participation in Marathon’s centralized cash management programs. All cash receipts were remitted to, and all cash disbursements were funded by, Marathon. Other transactions affecting the net investment include general, administrative and overhead costs incurred by Marathon that were allocated to the Predecessor. There are no terms of settlement or interest charges associated with the net investment balance.

(2)

EBITDA is defined as net earnings before interest expense, income taxes and depreciation and amortization. Adjusted EBITDA is defined as EBITDA before turnaround and related expenses, stock-based compensation expense, gains (losses) from derivative activities, contingent consideration, formation costs, bargain purchase gain and adjustments to reflect proportionate EBITDA from the Minnesota Pipeline operations. We believe Adjusted EBITDA is an important measure of operating performance and provides useful information to investors because it highlights trends in our business that may not otherwise be apparent when relying solely on GAAP measures and because it eliminates items that have less bearing on our operating performance. We also believe Adjusted EBITDA may be used by some investors to assess the ability of our assets to generate sufficient cash flow to make distributions to our unitholders.

Adjusted EBITDA, as presented herein, is a supplemental measure of our performance that is not required by, or presented in accordance with, GAAP. We use non-GAAP financial measures as supplements to our GAAP results in order to provide a more complete understanding of the factors and trends affecting our business. Adjusted EBITDA is a measure of operating performance that is not defined by GAAP and should not be considered a substitute for net (loss) earnings as determined in accordance with GAAP.

Set forth below is additional detail as to how we use Adjusted EBITDA as a measure of operating performance, as well as a discussion of the limitations of Adjusted EBITDA as an analytical tool.

Operating Performance. Management uses Adjusted EBITDA in a number of ways to assess our combined financial and operating performance, and we believe this measure is helpful to management and investors in identifying trends in our performance. We use Adjusted EBITDA as a measure of our combined operating performance exclusive of income and expenses that relate to the financing, derivative activities, income taxes and capital investments of the business, adjusted to

reflect EBITDA from the Minnesota Pipeline operations. In addition, Adjusted EBITDA helps management identify controllable expenses and make decisions designed to help us meet our current financial goals and optimize our financial performance. Accordingly, we believe this metric measures our financial performance based on operational factors that management can impact in the short-term, namely the cost structure and expenses of the organization.

Limitations. Other companies, including other companies in our industry, may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure. Adjusted EBITDA also has limitations as an analytical tool and should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Some of these limitations include that Adjusted EBITDA:

•

does not reflect our cash expenditures, or future requirements, for capital expenditures or contractual commitments;

•

does not reflect changes in, or cash requirements for, our working capital needs;

•

does not reflect our interest expense, or the cash requirements necessary to service interest or principal payments, on our debt;

•

does not reflect the equity income in our Minnesota Pipe Line Company investment, but includes 17% of the calculated EBITDA of Minnesota Pipe Line Company;

•

does not reflect realized and unrealized gains and losses from hedging activities, which may have a substantial impact on our cash flow;

•

does not reflect certain other non-cash income and expenses; and

•

excludes income taxes that may represent a reduction in available cash.

The following table shows the reconciliation of net earnings, the most directly comparable GAAP measure, to EBITDA and Adjusted EBITDA for the year ended December 31, 2009, the eleven months ended November 30, 2010, the 2010 Successor Period, the year ended December 31, 2011 and the three months ended March 31, 2011 and 2012:


	Predecessor				Successor
	Year Ended December 31, 2009		Eleven Months Ended November 30, 2010		June 23, 2010 (inception date) to December 31, 2010			Year Ended December 31, 2011			Three Months Ended March 31,
	Year Ended December 31, 2009		Eleven Months Ended November 30, 2010		June 23, 2010 (inception date) to December 31, 2010			Year Ended December 31, 2011			2011			2012
	(In millions)
Net earnings	$	54.7	$	61.0	$	24.8		$	28.3		$	(224.5	)	$	(193.6	)
Adjustments:
Interest expense		0.4		0.3		3.2			42.1			10.0			10.4
Depreciation and amortization		40.2		37.3		2.2			29.5			7.3			8.5
Income tax provision		34.8		67.1		–			–			0.1			–

EBITDA subtotal		130.1		165.7		30.2			99.9			(207.1	)		(174.7	)
Minnesota Pipe Line Company proportionate EBITDA		4.2		3.7		0.3			2.8			0.9			0.7
Turnaround and related expenses		0.6		9.5		–			22.6			3.3			3.5
Stock-based compensation expense		0.3		0.3		0.1			1.6			0.3			0.4
Unrealized losses on derivative activities		–		40.9		27.1			41.9			262.9			88.4
Contingent consideration income		–		–		–			(55.8	)		(31.8	)		65.7
Formation costs		–		–		3.6			7.4			2.5			–
Loss on early extinguishment of derivatives		–		–		–			–			–			44.6
Bargain purchase gain		–		–		(51.4	)		–			–			–
Realized losses on derivative activities		–		–		–			310.3			52.2			52.9

Adjusted EBITDA	$	135.2	$	220.1	$	9.9		$	430.7		$	83.2		$	81.5

(3)

Refinery gross product margin per barrel of throughput is a per barrel measurement calculated by subtracting refinery costs of sales from total refinery revenues and dividing the difference by the total throughput for the respective periods presented. Refinery gross product margin per barrel of throughput is a non-GAAP performance measure that we believe is important to investors in evaluating our refinery performance as a general indication of the amount above our cost of products that we are able to sell refined products. Each of the components used in this calculation (revenues and cost of sales) can be reconciled directly to our statements of operations. Our calculation of refinery gross product margin per barrel of throughput may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure.

The following table shows the reconciliation of refining gross product margin per barrel of throughput for the year ended December 31, 2009, the eleven months ended November 30, 2010, the 2010 Successor Period, the year ended December 31, 2011 and the three months ended March 31, 2011 and 2012:


	Predecessor				Successor
	Year Ended December 31, 2009		Eleven Months Ended November 30, 2010		June 23, 2010 (inception date) to December 31, 2010		Year Ended December 31, 2011		Three Months Ended March 31,
	Year Ended December 31, 2009		Eleven Months Ended November 30, 2010		June 23, 2010 (inception date) to December 31, 2010		Year Ended December 31, 2011		2011		2012
	(In millions, except per barrel data)
Refinery revenue	$	2,530.7	$	2,799.8	$	312.2	$	3,804.1	$	845.2	$	894.5
Refinery costs of sales		2,252.1		2,455.9		287.2		3,204.1		719.0		772.0

Refinery gross product margin	$	278.6	$	343.9	$	25.0	$	600.0	$	126.2	$	122.5

Throughput (barrels)		29.8		26.8		2.5		29.6		7.6		6.9

Refinery gross product margin per barrel of throughput	$	9.36	$	12.86	$	9.94	$	20.26	$	16.54	$	17.71

(4)

We use the Group 3 3:2:1 crack spread as a benchmark for our refinery. The Group 3 3:2:1 crack spread is expressed in dollars per barrel and is a proxy for the per barrel margin that a sweet crude oil refinery would earn assuming it produced and sold at PADD II Group 3 prices the benchmark production of two barrels of gasoline and one barrel of ultra low sulfur diesel for every three barrels of light, sweet crude oil input. For more information about the Group 3 3:2:1 crack spread see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Major Influences on Results of Operations.”

Our SPP Refinery 3:2:1 crack spread is derived using a similar methodology as the Group 3 3:2:1 crack spread and is calculated by taking the sum of (i) two times our weighted average per barrel price received for our gasoline products plus (ii) our average per barrel price received for distillate, divided by three; then subtracting from that sum our weighted average cost of crude oil supply per barrel. The SPP Refinery 3:2:1 crack spread is not a full representation of our realized refinery gross product margin because the Group 3 3:2:1 crack spread is composed only of gasoline and distillate, whereas our refinery gross product margin is calculated using all of our refined products including asphalt and other lower margin products.

(5)

Retail fuel margin per gallon is calculated by dividing retail fuel gross margin by the fuel gallons sold at company-operated stores. Retail fuel gross margin is a non-GAAP performance measure that we believe is important to investors in evaluating our retail performance. Our calculation of retail fuel gross margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure.

The following table shows the reconciliation of retail gross margin to retail segment operating income for the year ended December 31, 2009, for the eleven months ended November 30, 2010, the 2010 Successor Period and the year ended December 31, 2011 and the three months ended March 31, 2011 and 2012:


	Predecessor				Successor
	Year Ended December 31,		Eleven Months Ended November 30,		June 23, 2010 (inception date) to December 31,		Year Ended December 31,		Three Months Ended March 31,
	2009		2010		2010		2011		2011			2012
	(In millions)
Retail gross margin:
Fuel margin	$	47.1	$	54.3	$	4.7	$	66.5	$	12.1		$	13.3
Merchandise margin		106.9		99.1		7.8		106.3		22.9			23.5

Retail gross margin		154.0		153.4		12.5		172.8		35.0			36.8
Expenses:
Direct operating expenses		100.0		94.9		10.2		131.3		29.6			29.4
Depreciation and amortization		14.2		12.4		0.5		7.2		1.9			1.8
Selling, general and administrative		20.5		19.6		1.3		20.3		5.9			6.0

Retail segment operating income (loss)	$	19.3	$	26.5	$	0.5	$	14.0	$	(2.4	)	$	(0.4	)

RISK FACTORS

Investing in our common units involves a high degree of risk. You should carefully consider the risks described below together with the other information set forth in this prospectus before making an investment decision. Any of the following risks and uncertainties could have a material adverse effect on our business, financial condition, cash flows and results of operations could be materially adversely affected. If that occurs, we might not be able to pay distributions on our common units, the trading price of our common units could decline materially, and you could lose all or part of your investment. Although many of our business risks are comparable to those faced by a corporation engaged in a similar business, limited partner interests are inherently different from the capital stock of a corporation and involve additional risks described below. The risks discussed below are not the only risks we face. We may experience additional risks and uncertainties not currently known to us, or as a result of developments occurring in the future. Conditions that we currently deem to be immaterial may also materially and adversely affect our business, financial condition, cash flows and results of operations, and our ability to pay distributions to unitholders.

Risks Related to Our Business and Industry

General Business and Industry Risks

We may not have sufficient available cash to pay any quarterly distribution on our units.

We may not have sufficient available cash each quarter to enable us to pay any distributions to our unitholders. The amount we will be able to distribute on our common units principally depends on the amount of cash we generate from our operations, which is primarily dependent upon the operating margins we generate. Our operating margins, and thus, the cash we generate from operations have been volatile, and we expect that they will fluctuate from quarter to quarter based on, among other things:

the cost of refining feedstocks, such as crude oil, that are processed and blended into refined products;

the price at which we are able to sell refined products;

the level of our direct operating expenses, including expenses such as employee and contract labor, maintenance and energy costs;

non-payment or other non-performance by our customers and suppliers; and

overall economic and local market conditions.

In addition, while the PIK units will not receive cash distributions during the PIK period, the distribution of additional PIK units in lieu of cash distributions may substantially increase the number of units outstanding and the amount of cash required on a quarterly and annual basis to pay distributions on all units. The actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

the level of capital expenditures we make;

our debt service requirements;

the amount of any accrued but unpaid expenses;

the amount of any reimbursement of expenses incurred by our general partner and its affiliates;

fluctuations in our working capital needs;

our ability to borrow funds and access capital markets;

planned and unplanned maintenance at our facility, which, based on determinations by the board of directors of our general partner to maintain reserves, may negatively impact our cash flows in the quarter in which such maintenance occurs;

restrictions on distributions and on our ability to make working capital borrowings; and

the amount of cash reserves established by our general partner.

Our partnership agreement will not require us to pay a minimum quarterly distribution. The amount of distributions that we pay, if any, and the decision to pay any distribution at all, will be determined by the board of directors of our general partner. Our quarterly distributions, if any, will be subject to significant fluctuations based on the above factors.

For a description of additional restrictions and factors that may affect our ability to pay distributions, see “Distribution Policy and Restrictions on Distributions.”

Restrictions in the agreements governing our indebtedness could limit our ability to make distributions to our unitholders.

Subject to certain exceptions, the indenture governing our senior secured notes and our revolving credit facility prohibit us from making distributions to unitholders if certain defaults exist. In addition, both the indenture and our revolving credit facility contain additional restrictions limiting our ability to pay distributions to unitholders. Subject to certain exceptions, the restricted payments covenant under the indenture governing our senior secured notes restricts us from making cash distributions unless our fixed charge coverage ratio, as defined in the indenture, is at least 2.0 to 1.0 after giving pro forma effect to such distributions and such cash distributions do not exceed an amount equal to the aggregate net proceeds received by us (either as a result of capital contributions or from the sale of equity or certain debt securities) plus 50% of our consolidated net income (or less 100% of consolidated net loss), which is defined to exclude certain non-cash charges, such as net unrealized gains or losses from hedging obligations and impairment charges, accrued on a cumulative basis, plus certain other items. Our revolving credit facility generally restricts our ability to make cash distributions if (a) we fail to have excess availability under the facility at least equal to the greater of (1) 25% of the lesser of (x) the $300 million commitment amount and (y) the then applicable borrowing base and (2) $37.5 million or (b) we fail to maintain a fixed charge coverage ratio, as defined in the revolving credit facility, after giving pro forma effect to such distributions of at least 1.1 to 1.0. Accordingly, we may be restricted by our debt agreements from distributing all of our available cash to our unitholders. See “Description of Indebtedness.”

Investors who are looking for an investment that will pay predictable quarterly distributions should not invest in our common units. We expect our business performance will be more cyclical and volatile, and our cash flows will be less stable, than the business performance and cash flows of most publicly traded partnerships. As a result, our quarterly distributions will be cyclical and volatile and are expected to vary quarterly and annually. Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The amount of our quarterly distributions will be dependent on the performance of our business, which will be volatile as a result of fluctuations in the price of crude oil and other feedstocks and the demand for our finished products. Because our quarterly distributions will be subject to significant fluctuations directly related to the available cash we generate, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero. For example, we

are forecasting available cash of $93.0 million for the three months ending September 30, 2012 as compared to $15.1 million for the three months ending June 30, 2013. See “Distribution Policy and Restrictions on Distributions.”

The amount of cash we have available for distribution to unitholders depends primarily on our cash flow and not solely on profitability.

The amount of cash we have available for distribution depends primarily upon our cash flow and not solely on profitability, which may be affected by non-cash items. For example, we may have working capital changes as well as extraordinary capital expenditures and major maintenance expenses in the future. See “Management’s Discussion and Analysis of Financial Condition and Results of Operation—Liquidity and Capital Resources—Capital Spending.” While these items may not affect our profitability in a quarter, they would reduce the amount of cash available for distribution with respect to such quarter. As a result, we may make cash distributions during periods when we report losses and may not make cash distributions during periods when we report net income.

For the year ended December 31, 2011 and the three months ended March 31, 2012, in each case on a pro forma basis, we would not have generated sufficient available cash to have paid the quarterly distributions that we project that we will be able to pay for the twelve months ending June 30, 2013 and for the three months ending September 30, 2013.

We project that we will be able to pay aggregate distributions of $ per unit for the twelve months ending June 30, 2013 and a distribution of $ per unit for the three months ending September 30, 2013. In order to pay these projected distributions, we must generate approximately $ million of available cash in the twelve months ending June 30, 2013 and $ million of available cash in the three months ending September 30, 2013. However, for the years ended December 31, 2011 and March 31, 2012, on a pro forma basis, we would have generated $11.7 million and $9.1 million, respectively, of available cash. The increases in projected available cash compared to the forecasted available cash for the twelve months ending June 30, 2013 is primarily driven by the lower projected realized losses from derivative activities. There can therefore be no assurance that we will generate enough available cash to pay distributions of $ per unit or $ per unit, respectively, or any distribution at all, with respect to the twelve months ending June 30, 2013 and the three months ending September 30, 2013, or any future period. We have a limited operating history upon which to rely in evaluating whether we will have sufficient cash to allow us to pay distributions on our common units. For a description of the price assumptions upon which we have based our projected per unit distribution for the twelve months ending June 30, 2013 and the three months ending September 30, 2013, see “Distribution Policy and Restrictions on Distributions—Assumptions and Considerations.”

The board of directors of our general partner may modify or revoke our distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all.

The board of directors of our general partner will adopt a distribution policy pursuant to which we will distribute an amount equal to the available cash we generate each quarter. However, the board may change such policy at any time at its discretion and could elect not to pay distributions for one or more quarters. See “Distribution Policy and Restrictions on Distributions.”

Our partnership agreement does not require us to pay any distributions at all. Accordingly, investors are cautioned not to place undue reliance on the permanence of such a policy in making an investment decision. Any modification or revocation of our distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders. The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner, whose interests may differ from those of our public unitholders. Our general partner

has limited fiduciary and contractual duties, which may permit it to favor its own interests or the interests of its owners, including ACON Refining and TPG Refining, to the detriment of our public unitholders.

The assumptions underlying the forecast of available cash that we include in “Distribution Policy and Restrictions on Distributions—Forecasted Available Cash” are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

Our forecast of available cash set forth in “Distribution Policy and Restrictions on Distributions—Forecasted Available Cash” includes our forecast of our results of operations and available cash for the twelve months ending June 30, 2013 and the three months ending September 30, 2013. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, regulatory and competitive risks and uncertainties, including those discussed in this section, which could cause actual results to differ materially from those forecasted. Such forward-looking statements are based on assumptions and beliefs that we believe to be reasonable; however, assumed facts almost always vary from actual results, and the differences between assumed facts and actual results can be material, depending upon the circumstances. Where we express an expectation or belief as to future results, that expectation or belief is expressed in good faith and based on assumptions believed to have a reasonable basis. It cannot be assured, however, that the stated expectation or belief will occur or be achieved or accomplished. If the forecasted results are not achieved, we would not be able to pay the forecasted annual distribution or any distribution at all, in which event the market price of the common units may decline materially. The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Neither PricewaterhouseCoopers LLP nor any other independent accountants, have examined, compiled, or performed any procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The PricewaterhouseCoopers LLP reports included herein relate to our successor’s and predecessor’s historical financial information. Those reports do not extend to the prospective financial information and should not be read to do so. A net loss in any period in which we forecasted net income would disproportionately affect our ability to pay cash distributions under the covenants in our indenture, because 100% of any consolidated net loss decreases the restricted payment basket while only 50% of any consolidated net income increases the basket. The forecasted results relate to the twelve months ending June 30, 2013 and the three months ending September 30, 2013 and are not indicative of the results we may achieve for any other period or of our future performance more generally. Investors should review the forecast of our results of operations for the twelve months ending June 30, 2013 and the three months ending September 30, 2013 together with the other information included elsewhere in this prospectus, including “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Our arrangements with Marathon expose us to Marathon related credit and performance risk.

We have a contract with Marathon under which we supply substantially all of the gasoline and diesel requirements for the 90 independently owned and operated Marathon branded stores in our marketing area. Marathon has indemnification obligations to us pursuant to the agreements entered into in connection with the Marathon Acquisition. Marathon’s indemnification obligation resulting from any breach of representations and warranties generally are limited by an indemnification deductible of $25 million and an indemnification ceiling of $100 million and are guaranteed by Marathon Petroleum.

Marathon Petroleum has guaranteed the performance of all of Marathon’s obligations under all of the acquisition agreements entered into in connection with the Marathon Acquisition obligations

discussed above. Nevertheless, relying on Marathon’s ability to honor its fuel requirements purchase obligations and indemnity obligations, and on Marathon Petroleum’s ability to honor its guaranty obligations, exposes us to Marathon’s and Marathon Petroleum’s respective credit and business risks. There can be no assurance that claims resulting from any breach of Marathon’s representations and warranties under the acquisition agreements entered into in connection with the Marathon Acquisition will not exceed the $100 million indemnification ceiling. Moreover, selling products to Marathon under the supply contract can expose us to Marathon’s credit and general business risks. An adverse change in Marathon’s or Marathon Petroleum’s business, results of operations or financial condition could adversely affect their respective ability to perform each of these obligations, which could consequently have a material adverse effect on our business, results of operations or liquidity and, as a result, our ability to make distributions.

Our historical financial statements may not be indicative of future performance.

The historical financial statements for periods prior to December 1, 2010 presented in this prospectus reflect carve-out financial statements of several operating units of Marathon, which, except for certain assets that were not acquired (e.g., cash other than in-store cash at our convenience stores and receivables and assets sold to third parties) and certain liabilities (e.g., accounts payable, payroll and benefits payable and deferred taxes) that were not assumed in connection with the Marathon Acquisition, represent the assets and liabilities that were transferred to us upon the closing of the Marathon Acquisition. We now own the assets and operate them as a standalone business. Prior to the closing of the Marathon Acquisition, we had no history of operating these assets, and they were never operated as a standalone business, thus the historical results presented in the financial statements for the periods prior to the Marathon Acquisition are not necessarily comparable to our financial statements following the Marathon Acquisition or indicative of the results for any future period. Additionally, we entered into certain arrangements at the closing of the Marathon Acquisition, including our crude oil supply and logistics agreement with JPM CCC and a lease arrangement with Realty Income Properties 3 LLC (“Realty Income”), that resulted in our working capital needs and operating costs varying from those affecting the assets that we acquired from Marathon. The pre-Marathon Acquisition historical financial information reflects intercompany allocations of expenses which may not be indicative of the actual expenses that would have been incurred had the combined businesses been operating as a company independent from Marathon for the periods presented. In addition, our results of operations for periods subsequent to the closing of this offering may not be comparable to our results of operations for periods prior to the closing of this offering as a result of certain transactions undertaken in connection with this offering described in “Prospectus Summary—IPO Transactions.” See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Comparability of Historical Results” for a discussion of factors that affect comparability. As a result, it is difficult to evaluate our historical results of operations to assess our future prospects and viability.

Our liquidity may be adversely affected by a reduction in third party credit.

We rely on third party credit for approximately 50% of our crude oil and other feedstock purchases. We purchase the remaining crude oil and other feedstocks via a crude oil supply and logistics agreement with JPM CCC, which provides logistical and administrative support to us for both the crude oil we source from them as well as the crude oil we source from our suppliers. We pay for both domestic crude oil purchases and Canadian crude oil purchases during the month following delivery. If our suppliers who sell crude oil and other feedstocks to us on trade credit were to reduce or eliminate our credit lines, we would be required to fund our purchases through our revolving credit facility or our crude oil supply and logistics agreement with JPM CCC, which would have a negative impact on liquidity and, as a result, our ability to make distributions.

We may have capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.

If we cannot generate sufficient cash flows or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may not be able to meet our payment obligations, comply with certain deadlines related to environmental regulations and standards or pursue our business strategies, any of which could have a material adverse effect on our results of operations or liquidity. We have substantial short-term capital needs and may have substantial long-term capital needs. Our short-term working capital needs are primarily related to financing our refined product inventory and accounts receivable. Our long-term needs for cash include those to support ongoing capital expenditures for equipment maintenance and upgrades during turnarounds at our refinery and to complete our routine and normally scheduled maintenance, regulatory and security expenditures. Our next major turnaround is scheduled for April 2013 for which we have budgeted approximately $50 million. The refinery is expected to be shut down during the month of April 2013 to complete the turnaround. In addition, from time to time, we are required to spend significant amounts for repairs when one or more processing units experiences temporary shutdowns. We continue to utilize significant capital to upgrade equipment, improve facilities, and reduce operational, safety and environmental risks. We may incur substantial compliance costs in connection with any new environmental, health and safety regulations. In addition, the board of directors of our general partner will adopt a distribution policy pursuant to which we will distribute an amount equal to the available cash we generate each quarter to unitholders. As a result, we will need to rely on external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our growth. Our liquidity will affect our ability to satisfy any of these needs.

Competition from companies having greater financial and other resources than we do could materially and adversely affect our business and results of operations.

Our refining operations compete with domestic refiners and marketers in the PADD II region of the United States, as well as with domestic refiners in other PADD regions and foreign refiners that import products into the United States. In addition, we compete with producers and marketers in other industries that supply alternative forms of energy and fuels to satisfy the requirements of our industrial, commercial and individual customers. Certain of our competitors have larger, more complex refineries, and may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or international oil companies that are larger and have substantially greater resources than we do and have access to proprietary sources of controlled crude oil production. Unlike these competitors, we obtain substantially all of our feedstocks from unaffiliated sources. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of crude oil supply and other feedstocks or intense price fluctuations.

Newer or upgraded refineries will often be more efficient than our refinery, which may put us at a competitive disadvantage. While we have taken significant measures to maintain and upgrade units in our refinery by installing new equipment and repairing equipment to improve our operations, these actions involve significant uncertainties, since upgraded equipment may not perform at expected throughput levels, the yield and product quality of new equipment may differ from design specifications and modifications may be needed to correct equipment that does not perform as expected. Any of these risks associated with new equipment, redesigned older equipment or repaired equipment could lead to lower revenues or higher costs or otherwise have an adverse effect on future results of operations and financial condition and our ability to make distributions. Over time, our refinery may become obsolete, or be unable to compete, because of the construction of new, more efficient facilities by our competitors.

Our retail operations compete with numerous convenience stores, gasoline service stations, supermarket chains, drug stores, fast food operations and other retail outlets. Increasingly, national high-volume grocery and dry-goods retailers are entering the gasoline retailing business. Many of these competitors are substantially larger than we are. Because of their diversity, integration of operations and greater resources, these companies may be better able to withstand volatile market conditions or levels of low or no profitability. In addition, these retailers may use promotional pricing or discounts, both at the pump and in the store, to encourage in-store merchandise sales. These activities by our competitors could adversely affect our profit margins. Additionally, our convenience stores could lose market share, relating to both gasoline and merchandise, to these and other retailers, which could adversely affect our business, results of operations and cash flows. Our convenience stores compete in large part based on their ability to offer convenience to customers. Consequently, changes in traffic patterns and the type, number and location of competing stores could result in the loss of customers and reduced sales and profitability at affected stores, and adversely affect our ability to make distributions.

Difficult conditions resulting from the ongoing U.S. and worldwide financial and credit crisis, and potential further deteriorating conditions in the United States and globally, may materially adversely affect our business, results of operations, financial condition and our ability to make distributions.

Continued volatility and disruption in worldwide capital and credit markets and potential further deteriorating conditions in the United States and globally could affect our revenues and earnings negatively and could have a material adverse effect on our business, results of operations, financial condition and our ability to make distributions. We are indirectly exposed to risks faced by our suppliers, customers and other business partners. The impact on these constituencies of the risks posed by continued economic turmoil have included, or can include, interruptions or delays in the performance by counterparties to our contracts, reductions and delays in customer purchases, delays in or the inability of customers to obtain financing to purchase our products and the inability of customers to pay for our products. All of these events may significantly adversely impact our business, results of operations and financial condition and, as a result, our ability to make distributions.

The geographic concentration of our refinery and retail assets creates a significant exposure to the risks of the local economy and other local adverse conditions. The location of our refinery also creates the risk of significantly increased transportation costs should the supply/demand balance change in our region such that regional supply exceeds regional demand for refined products.

As our refinery and a significant number of our stores are located in Minnesota, Wisconsin and South Dakota, we primarily market our refined and retail products in a single, relatively limited geographic area. As a result, we are more susceptible to regional economic conditions than the operations of more geographically diversified competitors, and any unforeseen events or circumstances that affect our operating area could also materially adversely affect our revenues and our ability to make distributions. These factors include, among other things, changes in the economy, weather conditions, demographics and population.

Should the supply/demand balance shift in our region as a result of changes in the local economy discussed above, an increase in refining capacity or other reasons, resulting in supply in the PADD II region exceeding demand, we would have to deliver refined products to customers outside of the region and thus incur considerably higher transportation costs, resulting in lower refining margins, if any. Changes in market conditions could have a material adverse effect on our business, financial condition and results of operations and, as a result, our ability to make distributions.

Our operating results are seasonal and generally lower in the first and fourth quarters of the year for our refining business and in the first quarter of the year for our retail business. We depend on favorable weather conditions in the spring and summer months.

Demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. Decreased demand during the winter months can lead to lower gasoline prices. As a result, the operating results of our refining business for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year.

Seasonal fluctuations in traffic also affect sales of motor fuels and merchandise in our retail fuel and convenience stores. As a result, the operating results of our retail business are generally lower for the first quarter of the year. Weather conditions in our operating area also have a significant effect on our retail operating results. Customers are more likely to purchase higher profit margin items at our retail fuel and convenience stores, such as fast foods, fountain drinks and other beverages and more gasoline during the spring and summer months, thereby typically generating higher revenues and gross margins for us in these periods. Unfavorable weather conditions during these months and a resulting lack of the expected seasonal upswings in traffic and sales could have a material adverse effect on our business, financial condition and results of operations.

As the amount of cash we will be able to distribute with respect to a quarter principally depends on the amount of cash we generate from operations and because we do not intend to reserve or borrow cash to pay distributions in subsequent quarters, distributions with respect to the first and fourth quarters of the year may be significantly lower than with respect to the second and third quarters.

Weather conditions and natural disasters could materially and adversely affect our business and operating results.

The effects of weather conditions and natural disasters can lead to volatility in the costs and availability of energy and raw materials or negatively impact our operations or those of our customers and suppliers, which could have a significant adverse effect on our business and results of operations and, as a result, our ability to make cash distributions.

We may not be able to successfully execute our strategy of growth within the refining and retail industry through acquisitions.

A component of our growth strategy is to selectively consider strategic acquisitions within the refining industry and retail market based on sustainable financial performance through the refining cycle, advantageous access to crude oil supplies, attractive refined products market fundamentals and access to distribution and logistics infrastructure. Our ability to do so will be dependent upon a number of factors, including our ability to identify acceptable acquisition candidates, consummate acquisitions on favorable terms, successfully integrate acquired assets and obtain financing to fund acquisitions and to support our growth and many other factors beyond our control. Risks associated with acquisitions include those relating to:

diversion of management time and attention from our existing business;

challenges in managing the increased scope, geographic diversity and complexity of operations;

difficulties in integrating the financial, technological and management standards, processes, procedures and controls of an acquired business with those of our existing operations;

liability for known or unknown environmental conditions or other contingent liabilities not covered by indemnification or insurance;

greater than anticipated expenditures required for compliance with environmental, safety or other regulatory standards or for investments to improve operating results;

our inability to offer competitive terms to our franchisees to grow our franchise business;

difficulties in achieving anticipated operational improvements; and

incurrence of additional indebtedness to finance acquisitions or capital expenditures relating to acquired assets.

We may not be successful in acquiring additional assets, and any acquisitions that we do consummate may not produce the anticipated benefits or may have adverse effects on our business and operating results.

Our business may suffer if any of the executive officers of our general partner or other key employees discontinues employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity.

Our future success depends to a large extent on the services of the executive officers of our general partner and other key employees and on our continuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including accounting, business operations, finance and other key back-office and mid-office personnel. Furthermore, our operations require skilled and experienced employees with proficiency in multiple tasks. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business could be materially adversely affected. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.

Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.

Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. If a key system were to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. Our systems could also be damaged or interrupted by a security breach, fire, flood, power loss, telecommunications failure or similar event. Our formal disaster recovery plan may not prevent delays or other complications that could arise from an information systems failure. Further, our business interruption insurance may not compensate us adequately for losses that may occur.

We may incur significant liability under, or costs and capital expenditures to comply with, environmental, health and safety regulations, which are complex and change frequently.

Our refinery, pipelines and retail operations are subject to federal, state and local laws regulating, among other things, the generation, storage, handling, use and transportation of petroleum and hazardous substances, the emission and discharge of materials into the environment, waste management, characteristics and composition of gasoline and diesel and other matters otherwise relating to the protection of the environment. Our operations are also subject to various laws and regulations relating to occupational health and safety. Compliance with the complex array of federal, state and local laws relating to the protection of the environment, health and safety is difficult and likely will require us to make significant expenditures. Moreover, our business is inherently subject to accidental spills, discharges or other releases of petroleum or hazardous substances into the environment including at neighboring areas or third party storage, treatment or disposal facilities. For example, we have performed

remediation of known soil and groundwater contamination beneath certain of our retail locations primarily as a result of leaking underground storage tanks, and we will continue to perform remediation of this known contamination until the appropriate regulatory standards have been achieved. Certain environmental laws impose joint and several liability without regard to fault or the legality of the original conduct in connection with the investigation and cleanup of such spills, discharges or releases. As such, we may be required to pay more than our fair share of such investigation or cleanup. We may not be able to operate in compliance with all applicable environmental, health and safety laws, regulations and permits at all times. Violations of applicable legal or regulatory requirements could result in substantial fines, criminal sanctions, permit revocations, injunctions and/or facility shutdowns. We may also be required to make significant capital expenditures or incur increased operating costs or change operations to achieve compliance with applicable standards.

We cannot predict what additional environmental, health and safety legislation or regulations will be enacted or become effective in the future or how existing or future laws or regulations will be administered or interpreted with respect to our operations. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. For example, the United States Environmental Protection Agency (“EPA”) has announced that it plans to propose new “Tier 3” motor vehicle emission and fuel standards sometime in the second half of 2012. It has been reported that these new Tier 3 regulations may, among other things, lower the maximum average sulfur content of gasoline from 30 parts per million to 10 parts per million. If the Tier 3 regulations are eventually implemented and lower the maximum allowable content of sulfur or other constituents in fuels that we produce, we may at some point in the future be required to make significant capital expenditures and/or incur materially increased operating costs to comply with the new standards. Expenditures or costs for environmental, health and safety compliance could have a material adverse effect on our results of operations, financial condition and profitability and, as a result, our ability to make distributions.

We could incur significant costs in cleaning up contamination at our refinery, terminal and convenience stores.

Our refinery site has been used for refining activities for many years. Petroleum hydrocarbons and various substances have been released on or under our refinery site. Marathon performed remediation of known soil and groundwater contamination beneath the refinery for many years, and we will continue to perform remediation of this known contamination until the appropriate regulatory standards have been achieved. These remediation efforts are being overseen by the Minnesota Pollution Control Agency (“MPCA”) pursuant to a remediation settlement agreement entered into by Marathon and MPCA in 2007. Releases of petroleum hydrocarbons have also occurred at several of our convenience stores, and we have performed and will continue to perform remediation of this known contamination until the applicable regulatory standards are met. Costs for such remediation activities are often unpredictable, and there can be no assurance that the future costs will not be material. It is possible that we may identify additional contamination in the future, which could result in additional remediation obligations and expenses, including fines and penalties.

We are subject to strict laws and regulations regarding employee and business process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations and financial condition.

We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, process safety standards and control of

occupational exposure to regulated substances, could subject us to significant fines or cause us to spend significant amounts on compliance, which could have a material adverse effect on our results of operations, financial condition and the cash flows of the business and, as a result, our ability to make distributions.

Compliance with and changes in tax laws could adversely affect our performance.

We are subject to extensive tax liabilities, including federal, state and transactional taxes such as excise, sales/use, payroll, franchise, withholding and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. Certain of these liabilities are subject to periodic audits by the respective taxing authority, which could increase our tax liabilities. Subsequent changes to our tax liabilities as a result of these audits may also subject us to interest and penalties. Any such changes in our tax liabilities could adversely affect our ability to make distributions to our unitholders.

Our insurance policies may be inadequate or expensive.

Our insurance coverage does not cover all potential losses, costs or liabilities. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be affected by conditions in the insurance market over which we have no control. In addition, if we experience insurable events, our annual premiums could increase further or insurance may not be available at all or if it is available, on restrictive coverage items. The occurrence of an event that is not fully covered by insurance or the loss of insurance coverage could have a material adverse effect on our business, financial condition, and results of operations and, as a result, our ability to make distributions.

Our level of indebtedness may increase and reduce our financial flexibility.

In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties. Our level of indebtedness could affect our operations in several ways, including the following:

a significant portion of our cash flows could be used to service our indebtedness;

a high level of debt would increase our vulnerability to general adverse economic and industry conditions;

the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay distributions and make certain investments;

a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged, and therefore may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;

our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and

a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.

A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our units or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.

In addition, our bank borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial condition and, as a result, our ability to make distributions.

Increased costs of capital could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations.

Additionally, as with other yield-oriented securities, we expect that our unit price will be impacted by the level of our quarterly cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have a material adverse impact on our unit price and our ability to issue additional equity to fund our operations or to make acquisitions or to incur debt as well as increasing our interest costs.

We require continued access to capital. In particular, the board of directors of our general partner will adopt a distribution policy pursuant to which we will distribute an amount equal to the available cash we generate each quarter to unitholders. As a result, we will need to rely on external financing sources to fund our growth. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.

The indenture governing our senior secured notes, our revolving credit facility and our hedge agreements contain certain covenants that may inhibit our ability to make certain investments, incur certain additional indebtedness and engage in certain other transactions, which could adversely affect our ability to pursue our business strategies.

The indenture governing our senior secured notes and our revolving credit facility contain a number of restrictive covenants that impose significant operating and financial restrictions on us and may limit our ability to engage in acts that may be in our long-term best interest, including restrictions on our ability, among other things, to:

incur, assume or guarantee additional debt or issue redeemable stock or preferred stock;

make distributions or prepay, redeem, or repurchase certain debt;

enter into agreements that restrict distributions from restricted subsidiaries;

incur liens;

sell or otherwise dispose of assets, including capital stock of subsidiaries;

enter into new lines of business;

enter into transactions with affiliates; and

merge, consolidate or sell substantially all of our assets.

A breach of the covenants under the indenture governing the senior secured notes or under the credit agreement governing the revolving credit facility could result in an event of default under the applicable indebtedness. Such default may allow the creditors to accelerate the related debt and may result in the acceleration of any other debt to which a cross-acceleration or cross-default provision applies. In addition, an event of default under our revolving credit facility would permit the lenders under our revolving credit facility to terminate all commitments to extend further credit under that facility. Furthermore, if we were unable to repay the amounts due and payable under our revolving credit facility or indenture, those creditors could proceed against the collateral granted to them to secure that indebtedness. In the event our lenders or noteholders accelerate the repayment of our borrowings, we may not have sufficient assets to repay that indebtedness. As a result of these restrictions, we may be:

limited in how we conduct our business;

unable to raise additional debt or equity financing to operate during general economic or business downturns; or

unable to compete effectively or to take advantage of new business opportunities.

In addition, our hedge agreements with J. Aron & Company and Macquarie Bank Limited contain a number of restrictive covenants that limit our ability to, among other things, incur, assume or guarantee funded debt that is secured by a priority lien or sell all or any portion of the refinery. A breach of any of the covenants under these hedge agreements could result in an event of default. Such default allows the counterparties to terminate all outstanding transactions governed by the hedge agreements. If we are unable to find a replacement counterparty for our crack spread hedge agreements, such a termination will limit our capacity to hedge our crack spread risk with respect to any portion of the refinery’s projected monthly production of some or all of its refined products.

These restrictions may affect our ability to grow in accordance with our plans.

We are a holding company and depend upon our subsidiaries for our cash flow.

We are a holding company. All of our operations are conducted and all of our assets are owned by our subsidiaries. Consequently, our cash flow and our ability to meet our obligations or to make distributions to our unitholders in the future will depend upon the cash flow of our subsidiaries and the payment of funds by our subsidiaries to us in the form of dividends or otherwise. The ability of our subsidiaries to make any payments to us will depend on their respective earnings, the terms of their indebtedness, including the terms of any credit facilities and indentures, and legal restrictions.

Risks Primarily Related to Our Refining Business

The price volatility of crude oil, other feedstocks, refined products and fuel and utility services may have a material adverse effect on our earnings, cash flows and liquidity and our ability to make distributions to our unitholders.

Our refining and retail earnings, cash flows and liquidity from operations depend primarily on the margin above operating expenses (including the cost of refinery feedstocks, such as crude oil and natural gas liquids that are processed and blended into refined products) at which we are able to sell refined products. Refining is primarily a margin-based business and, to increase earnings, it is important to maximize the yields of high value finished products while minimizing the costs of feedstock and operating expenses. When the margin between refined product prices and crude oil and other feedstock costs contracts, our earnings, and cash flows are negatively affected. Refining margins historically have been volatile, and are likely to continue to be volatile, as a result of a variety of factors, including fluctuations in the prices of crude oil, other feedstocks, refined products and fuel and utility services. For example, from January 2005 to March 2012, the price for NYMEX WTI crude oil fluctuated between $33.87 and $145.29 per barrel, while the price for U.S. Gulf Coast conventional gasoline fluctuated between $33.52 per barrel and $204.67 per barrel. While an increase or decrease in the price of crude oil may result in a similar increase or decrease in prices for refined products, there may be a time lag in the realization of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on our refining margins therefore depends in part on how quickly and how fully refined product prices adjust to reflect these changes.

In addition, the nature of our business requires us to maintain substantial refined product inventories. Because refined products are commodities, we have no control over the changing market value of these inventories. Our refined product inventory is valued at the lower of cost or market value under the last-in, first-out (“LIFO”), inventory valuation methodology. If the market value of our refined product inventory were to decline to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash charge to cost of sales.

Prices of crude oil, other feedstocks and refined products depend on numerous factors beyond our control, including the supply of and demand for crude oil, other feedstocks, gasoline, diesel, asphalt and other refined products. Such supply and demand are affected by, among other things:

changes in global and local economic conditions;

domestic and foreign demand for fuel products, especially in the United States, China and India;

worldwide political conditions, particularly in significant oil producing regions such as the Middle East, West Africa and Latin America;

the level of foreign and domestic production of crude oil and refined products and the volume of crude oil, feedstock and refined products imported into the United States;

availability of and access to transportation infrastructure;

utilization rates of United States refineries;

the ability of the members of the Organization of Petroleum Exporting Countries (“OPEC”) to affect oil prices and maintain production controls;

development and marketing of alternative and competing fuels;

commodities speculation;

natural disasters (such as hurricanes and tornadoes), accidents, interruptions in transportation, inclement weather or other events that can cause unscheduled shutdowns or otherwise adversely affect our refineries;

federal and state government regulations and taxes; and

local factors, including market conditions, weather conditions and the level of operations of other refineries and pipelines in our markets.

Our direct operating expense structure also impacts our earnings. Our major direct operating expenses include employee and contract labor, maintenance and energy costs. Our predominant variable direct operating cost is energy, which is comprised primarily of fuel and other utility services. The volatility in costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refinery and other operations affect our operating costs. Fuel and utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for fuel and utility services in both local and regional markets. Natural gas prices have historically been volatile and, typically, electricity prices fluctuate with natural gas prices. Future increases in fuel and utility prices may have a negative effect on our earnings and cash flows. Fuel and other utility services costs constituted approximately 14.2% and 13.3% of our total direct operating expenses for the three months ended March 31, 2012 and the year ended December 31, 2011, respectively.

Volatility in refined product prices also affects our borrowing base under our revolving credit facility. A decline in prices of our refined products reduces the value of our refined product inventory collateral, which, in turn, may reduce the amount available for us to borrow under our revolving credit facility.

Our results of operations are affected by crude oil differentials, which may fluctuate substantially.

Our results of operations are affected by crude oil differentials, which may fluctuate substantially. Since 2010, refined product prices have been more correlated to prices of Brent than to NYMEX WTI, the traditional U.S. crude oil benchmark, as the discount to which a barrel of NYMEX WTI traded relative to a barrel of Brent has widened significantly relative to historical levels. This differential has also been very volatile as a result of various continuing geopolitical events as well as logistical and infrastructure constraints to move crude oil from Cushing, Oklahoma into the U.S. Gulf Coast. Between December 1, 2010 and March 31, 2012, the discount at which a barrel of NYMEX WTI traded relative to a barrel of Brent increased from $2.12 to $19.86. The widening of this price differential benefited refineries, such as ours, that are capable of sourcing and utilizing crude oil that is priced more in line with NYMEX WTI. The refinery not only realized relatively lower feedstock costs but also was able to sell refined products at prices that had been pushed upward by higher Brent prices. The announcement during the fourth quarter of 2011 of the reversal of the Seaway Pipeline, which would carry crude oil from Cushing, Oklahoma to Freeport, Louisiana, caused a temporary reduction in the discount. The initial phase of the Seaway Pipeline reversal came onstream on May 17, 2012. Narrowing of the differential may have a material adverse effect on our business and results from operations and our ability to pay distributions.

The dangers inherent in our operations could cause disruptions and could expose us to potentially significant losses, costs or liabilities and reduce our liquidity. We are particularly vulnerable to disruptions in our operations because all of our refining operations are conducted at a single facility.

Our operations are subject to significant hazards and risks inherent in refining operations and in transporting and storing crude oil, intermediate products and refined products. These hazards and risks include, but are not limited to, natural disasters, fires, explosions, pipeline ruptures and spills, third party interference and mechanical failure of equipment at our facilities, any of which could result in production and distribution difficulties and disruptions, pollution (such as oil spills, etc.), personal injury

or wrongful death claims and other damage to our properties and the property of others. For example, in December 2007, a fuel oil tank roof caught on fire at our refinery when an operator was attempting to thaw a level gauge. The tank’s roof was destroyed and the operator was fatally injured during the fire.

There is also risk of mechanical failure and equipment shutdowns both in the normal course of operations and following unforeseen events. In such situations, undamaged refinery processing units may be dependent on, or interact with, damaged process units and, accordingly, are also subject to being shut down. For example, on May 6, 2012, our refinery experienced a temporary shutdown due to a power outage that appears to have originated from outside the plant as a result of high winds and thunderstorms. In the case of such a shutdown, the refinery must initiate a standard start-up process, and such process typically lasts several days. We were able to resume normal operations on May 13, 2012. Because all of our refining operations are conducted at a single refinery, any of such events at our refinery could significantly disrupt our production and distribution of refined products, including the supply of our refined products to our convenience stores, which receive substantially all of their supply of gasoline and diesel from the refinery. Any disruption in our ability to supply our convenience stores would increase the cost of purchasing refined products for our retail business. Any sustained disruption would have a material adverse effect on our business, financial condition, results of operations and cash flows and, as a result, our ability to make distributions.

We are subject to interruptions of supply and distribution as a result of our reliance on pipelines for transportation of crude oil, blendstocks and refined products.

Our refinery receives most of its crude oil and delivers a portion of its refined products through pipelines. The Minnesota Pipeline system is our primary supply route for crude oil and has transported substantially all of the crude oil used at our refinery. We also distribute a portion of our transportation fuels through pipelines owned and operated by Magellan Pipeline Company, L.P. (“Magellan”), including the Aranco Pipeline, which Magellan leases from us. We could experience an interruption of supply or delivery, or an increased cost of receiving crude oil and delivering refined products to market, if the ability of these pipelines to transport crude oil, blendstocks or refined products is disrupted because of accidents, weather interruptions, governmental regulation, terrorism, other third party action or any of the types of events described in the preceding risk factor. For example, there was a leak in 2006 prior to the completion of the expansion of the Minnesota Pipeline, and the refinery was temporarily shut off from any receipts from the Minnesota Pipeline other than crude oil that was already in the tanks at Cottage Grove, Minnesota. At that time, the only alternative to receive crude oil was the Wood River Pipeline, a pipeline extending from Wood River, Illinois to a connection with the Minnesota Pipeline near Pine Bend, Minnesota, which had limited capacity to meet the refinery’s needs. While the refinery can receive crude oil deliveries from the Wood River Pipeline if the Minnesota Pipeline system experiences another disruption, this would result in an increase in the cost of crude oil and therefore lower refining margins.

In addition, due to the common carrier regulatory obligation applicable to interstate oil pipelines, capacity must be prorated among shippers in an equitable manner in accordance with the tariff then in effect in the event there are nominations in excess of capacity. Therefore, nominations by new shippers or increased nominations by existing shippers may reduce the capacity available to us. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that we rely upon for transportation of crude oil and refined products could have a material adverse effect on our business, financial condition, results of operations and cash flows and, as a result, our ability to make distributions.

We must make substantial capital expenditures on our operating facilities to maintain their reliability and efficiency. If we are unable to complete capital projects at their expected costs and/or in a timely manner, or if the market conditions assumed in our project economics deteriorate, our financial condition, results of operations or cash flows, and our ability to make distributions to unitholders, could be materially and adversely affected.

Delays or cost increases related to the engineering, procurement and construction of new facilities (or improvements and repairs to our existing facilities and equipment) could have a material adverse effect on our business, financial condition or results of operations, and our ability to make distributions to our unitholders. Such delays or cost increases may arise as a result of unpredictable factors in the marketplace, many of which are beyond our control, including:

denial or delay in issuing regulatory approvals and/or permits;

unplanned increases in the cost of construction materials or labor;

disruptions in transportation of modular components and/or construction materials;

severe adverse weather conditions, natural disasters or other events (such as equipment malfunctions, explosions, fires or spills) affecting our facilities, or those of our vendors and suppliers;

shortages of sufficiently skilled labor, or labor disagreements resulting in unplanned work stoppages;

market-related increases in a project’s debt or equity financing costs; and/or

nonperformance or force majeure by, or disputes with, our vendors, suppliers, contractors or sub-contractors.

Our refinery consists of many processing units, a number of which have been in operation for many years. Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep it operating at optimum efficiency. For example, as part of installing safety instrumentation systems throughout the refinery to improve operational and safety performance, approximately $17 million was spent from 2006 through March 2012, and we have budgeted for additional related expenditures through 2013 to complete the instrumentation project. One or more of the units may require unscheduled downtime for unanticipated maintenance or repairs that may be more frequent than our scheduled turnarounds for such units. Scheduled and unscheduled maintenance could reduce our revenues during the period of time that the units are not operating. Our next major turnaround is scheduled for April 2013 for which we have budgeted approximately $50 million. The refinery is expected to be shut down during the month of April 2013 to complete the turnaround. We do not intend to reserve cash to pay distributions during periods of scheduled or unscheduled maintenance, though we do intend to reserve for turnaround expenses.

Any one or more of these occurrences could have a significant impact on our business. If we were unable to make up the delays or to recover the related costs, or if market conditions change, it could materially and adversely affect our financial position, results of operations or cash flows and, as a result, our ability to make distributions.

A portion of our workforce is unionized, and we may face labor disruptions that would interfere with our operations.

Approximately 179 of our employees associated with the operations of our refining business are covered by a collective bargaining agreement that expires in December 2013. In addition, 20 of our employees associated with the operations of our retail business are covered by a collective bargaining agreement that expires in August 2012. We may not be able to renegotiate our collective bargaining

agreements on satisfactory terms or at all when such agreements expire. A failure to do so may increase our costs associated with our workforce. Other employees of ours who are not presently represented by a union may become so represented in the future as well. In 2006, the unionized refinery employees conducted a strike when Marathon sought to revise certain working terms and conditions. Another work stoppage resulting from, among other things, a dispute over a term or condition of a collective bargaining agreement that covers employees who work at our refinery or in our retail business, could cause disruptions in our business and negatively impact our results of operations and ability to make distributions.

Product liability claims and litigation could adversely affect our business and results of operations.

Product liability is a significant commercial risk. Substantial damage awards have been made in certain jurisdictions against manufacturers and resellers based upon claims for injuries caused by the use of or exposure to various products. Failure of our products to meet required specifications could result in product liability claims from our shippers and customers arising from contaminated or off-specification commingled pipelines and storage tanks and/or defective quality fuels. There can be no assurance that product liability claims against us would not have a material adverse effect on our business or results of operations and on our ability to make distributions.

Laws and regulations restricting emissions of greenhouse gases could force us to incur increased capital and operating costs and could have a material adverse effect on our results of operations and financial condition.

In December 2009, the U.S. Environmental Protection Agency (“EPA”) determined that emissions of carbon dioxide, methane and other “greenhouse gases” (“GHGs”) endanger public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. Based on these findings, the EPA has begun adopting and implementing regulations to restrict emissions of GHGs under existing provisions of the federal Clean Air Act, as amended (“CAA”). The EPA adopted two sets of rules effective January 2, 2011 regulating GHG emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which regulates emissions of GHGs from certain large stationary sources. While the EPA’s rules relating to emissions of GHGs from large stationary sources of emissions are currently subject to a number of legal challenges, the federal courts have thus far declined to issue any injunctions to prevent the EPA from implementing or requiring state environmental agencies to implement the rules. The EPA has also implemented rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including petroleum refineries, on an annual basis, for emissions occurring after January 1, 2010.

In addition, the U.S. Congress has from time to time considered adopting legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. These cap and trade programs generally work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and gas processing plants, to acquire and on an annual basis surrender emission allowances. The number of allowances available for purchase is reduced over time in an effort to achieve the overall GHG emission reduction goal. Minnesota is a participant in the Midwest Regional GHG Reduction Accord, a non-binding resolution that could lead to the creation of a regional GHG cap-and-trade program if the Minnesota legislature and the legislatures of other participating states enact implementing legislation.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the refined products that we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations and, as a result, our ability to make distributions.

In addition, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such events were to occur, they could have an adverse effect on our business, financial condition and results of operations and and, as a result, our ability to make distributions.

Renewable fuels mandates may reduce demand for the petroleum fuels we produce, which could have a material adverse effect on our results of operations and financial condition, and our ability to make distributions to our unitholders.

Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Security Act of 2007, the EPA has issued Renewable Fuels Standards (“RFS”) implementing mandates to blend renewable fuels into the petroleum fuels produced and sold in the United States. Under RFS, the volume of renewable fuels that obligated refineries like us must blend into their finished petroleum fuels increases annually over time until 2022. We currently purchase renewable identification number credits (“RINS”) for some fuel categories on the open market, as well as waiver credits for cellulosic biofuels from the EPA, in order to comply with the RFS. In the future, we may be required to purchase additional RINS on the open market and waiver credits from the EPA to comply with the RFS. We cannot currently predict the future prices of RINS or waiver credits, but the costs to obtain the necessary number of RINS and waiver credits could be material. Additionally, Minnesota law currently requires that all diesel sold in the state for use in internal combustion engines must contain at least 5% biodiesel. Under this statute, if certain preconditions are met, the minimum biodiesel content in diesel sold in the state will increase to 10% beginning on May 1, 2012, and to 20% beginning on May 1, 2015. The increase to 10% did not occur on May 1, 2012, because the Minnesota commissioners of agriculture, commerce, and pollution control did not certify that all statutory pre-conditions were satisfied by the statutory deadline, but instead jointly recommended delaying the increase to 10% by one year, to May 1, 2013. Minnesota law also currently requires, with limited exceptions, that all gasoline sold or offered for sale in the state must contain the maximum amount of ethanol allowed under federal law for use in all gasoline-powered motor vehicles. On October 13, 2010, the EPA raised the maximum amount of ethanol allowed under federal law from 10% to 15% for cars and light trucks manufactured since 2007, and on January 21, 2011, EPA extended the maximum allowable ethanol content of 15% to apply to cars and light trucks manufactured since 2001. The maximum amount allowed under federal law currently remains at 10% ethanol for all other vehicles. Existing laws and regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum fuels may increase. Because we do not produce renewable fuels, increasing the volume of renewable fuels that must be blended into our products displaces an increasing volume of our refinery’s product pool, potentially resulting in lower earnings and materially adversely affecting our ability to make distributions.

Our pipeline interests are subject to federal and/or state rate regulation, which could reduce

our profitability.

Our transportation activities are subject to regulation by multiple governmental agencies, and compliance with such regulation increases our cost of doing business and affects our profitability. Additional proposals and proceedings that affect the oil industry are regularly considered by Congress,

the states, the Federal Energy Regulatory Commission (“FERC”) and the courts. We cannot predict when or whether any such proposals may become effective or what impact such proposals may have. Projected expenditures related to the Minnesota Pipeline reflect the recurring costs resulting from compliance with these regulations, and these costs may increase due to future acquisitions, changes in regulation, changes in use, ongoing expenditures to maintain reliability and efficiency or discovery of existing but unknown compliance issues. In addition, if the current lease with Magellan of the Aranco Pipeline were terminated and we were to operate the Aranco Pipeline or, if the Cottage Grove pipelines were required to comply with these regulations, we would incur similar costs.

The Minnesota Pipeline is a common carrier pipeline providing interstate transportation service, which is subject to regulation by FERC under the Interstate Commerce Act (“ICA”). The ICA requires that tariff rates for interstate petroleum pipelines transportation service be just and reasonable and that the rates and terms of service of such pipelines not be unduly discriminatory or unduly preferential. The tariff rates are generally set by the board of managers of the Minnesota Pipe Line Company, which we do not control. Because we currently do not operate the Minnesota Pipeline or control the board of managers of the Minnesota Pipe Line Company, we do not control how the Minnesota Pipeline’s tariff is applied, including the tariff provisions governing the allocation of capacity, or control of decision-making with respect to tariff changes for the pipeline.

FERC can investigate the pipeline’s rates and certain terms of service on its own initiative. In addition, shippers may file with FERC protests against new tariff rates and/or terms and conditions of service or complaints against existing tariff rates and/or terms and conditions of services. Under certain circumstances, FERC could limit the Minnesota Pipe Line Company’s ability to set rates based on its costs, or could order the Minnesota Pipe Line Company to reduce its rates and could require the payment of reparations to complaining shippers for up to two years prior to the complaint or refunds to all shippers in the context of a protest proceeding. If it found the Minnesota Pipeline’s rates or terms of service to be contrary to statutory requirements, FERC could impose conditions it considers appropriate and/or impose penalties. Further, FERC could declare pipeline-related facilities to be common carrier facilities and require that common carrier access be provided or otherwise alter the terms of service and/or rates of such facilities, to the extent applicable. Rate regulation or a successful challenge to the rates the Minnesota Pipeline charges could adversely affect its financial position, cash flows, or results of operations and, thus, our financial position, cash flows or results of operations. Conversely, reduced rates on the Minnesota Pipeline would reduce the rates for transportation of crude oil into our refinery.

FERC currently allows petroleum pipelines to change their rates within prescribed ceiling levels tied to an inflation index. The Minnesota Pipeline currently bases its rates on the indexing methodology. If the Minnesota Pipeline were to attempt to increase rates beyond the maximum allowed by the indexing methodology, it would be required to file a cost-of-service justification, obtain approval from an unaffiliated party that intends to ship on the pipeline (with respect to initial rates for any new service), obtain approval from all current shippers (i.e., settlement), or obtain prior approval to file market-based rates. FERC’s indexing methodology is subject to review every five years. In an order issued in December 2010, FERC announced that, effective July 1, 2011, the index would equal the change in the producer price index for finished goods plus 2.65% (previously, the index was equal to the change in the producer price index for finished goods plus 1.3%). This index is to be in effect through July 2016. If the increases in the index are not sufficient to fully reflect actual increases to our costs, our financial condition could be adversely affected. If the index results in a rate increase that is substantially in excess of the pipeline’s actual cost increases, or it results in a rate decrease that is substantially less than the pipeline’s actual cost decrease, the rates may be protested, and, if such protests are successful, result in the lowering of the pipeline’s rates. FERC’s rate-making methodologies may limit the pipeline’s ability to set rates based on our true costs and may delay or limit the use of rates that reflect increased costs of providing transportation service.

If we were to operate the Aranco Pipeline to provide transportation of crude oil or petroleum products in interstate commerce, we would expect to also be regulated by FERC as an interstate oil pipeline and the Aranco Pipeline would be subject to the same regulatory risks discussed above.

Terrorist attacks and other acts of violence or war may affect the market for our units, the industry in which we conduct our operations and our results of operations and our ability to make distributions to our unitholders.

Terrorist attacks may harm our business results of operations. We cannot provide assurance that there will not be further terrorist attacks against the United States or U.S. businesses. Such attacks or armed conflicts may directly impact our refinery, properties or the securities markets in general. More generally, any of these events could cause consumer confidence and spending to decrease or result in increased volatility in the United States and worldwide financial markets and economy. Adverse economic conditions could harm the demand for our products or the securities markets in general, which could harm our operating results and ability to make distributions.

While we have insurance that provides some coverage against terrorist attacks, such insurance has become increasingly expensive and difficult to obtain. As a result, insurance providers may not continue to offer this coverage to us on terms that we consider affordable, or at all.

Some of our operations are conducted with partners, which may decrease our ability to manage risks associated with those operations.

We sometimes enter into arrangements to conduct certain business operations, such as pipeline transportation, with partners in order to share risks associated with those operations. However, these arrangements may also decrease our ability to manage risks and costs associated with those operations, particularly where we are not the operator. We could have limited influence over and control of the behaviors and performance of these operations. This could affect our operational performance, financial position and reputation.

We own 17% of the outstanding common interests of the Minnesota Pipe Line Company and 17% of the outstanding preferred shares of MPL Investments, Inc. which owns 100% of the preferred units of the Minnesota Pipe Line Company. The Minnesota Pipe Line Company owns the Minnesota Pipeline, a crude oil pipeline system in Minnesota that transports crude oil to the Twin Cities area and which consistently transports most of our crude oil input. The remaining interests in the Minnesota Pipe Line Company are held by a subsidiary of Koch Industries, Inc., which operates the system and is an affiliate of the only other refinery owner in Minnesota, with a 74.16% interest, and TROF Inc. with an 8.84% interest. For more information about the economic effect of our investments in the Minnesota Pipe Line Company and MPL Investments, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” and “—Results of Operations.” Because our investments in the Minnesota Pipe Line Company and MPL Investments are limited, we do not have significant influence over or control of the performance of the Minnesota Pipe Line Company’s operations, which could impact our operational performance, financial position and reputation.

If we are unable to obtain our crude oil supply without the benefit of the crude oil supply and logistics agreement with JPM CCC or similar agreement, our exposure to the risks associated with volatile crude oil prices may increase.

Our supply and logistics agreement with JPM CCC allows us to price all crude oil processed at the refinery one day after it is received at the plant. This arrangement minimizes the amount of in-transit inventory and reduces our exposure to fluctuations in crude oil prices. In excess of 90% of the crude oil delivered at the refinery is handled through our agreement with JPM CCC independent of

whether crude oil is sourced from our suppliers or from JPM CCC directly. If we are unable to obtain our crude oil supply through the crude oil supply and logistics agreement or similar agreement, our exposure to crude oil pricing risks may increase as the number of days between when we pay for the crude oil and when the crude oil is delivered to us increases. Such increased exposure could negatively impact our liquidity position due to our increased working capital needs as a result of the increase in the value of crude oil inventory we would have to carry on our balance sheet and, therefore, could adversely affect our ability to make distributions.

Our suppliers source a substantial amount of our crude oil from the Bakken Shale of North Dakota and may experience interruptions of supply from that region.

Our suppliers source a substantial amount of our crude oil from the Bakken Shale of North Dakota. As a result, we may be disproportionately exposed to the impact of delays or interruptions of supply from that region caused by transportation capacity constraints, curtailment of production, unavailability of equipment, facilities, personnel or services, significant governmental regulation, natural disasters, adverse weather conditions, plant closures for scheduled maintenance or interruption of transportation of oil or natural gas produced from the wells in that area.

Our commodity derivative contracts may limit our potential gains, exacerbate potential losses and involve other risks.

We enter into commodity derivatives contracts to hedge our crack spread risk with respect to a portion of our expected gasoline and diesel production. We enter into these hedging arrangements with the intent to secure a minimum fixed cash flow stream on the volume of products hedged during the hedge term. However, our hedging arrangements may fail to fully achieve these objectives for a variety of reasons, including our failure to have adequate hedging contracts, if any, in effect at any particular time and the failure of our hedging arrangements to produce the anticipated results. We may not be able to procure adequate hedging arrangements due to a variety of factors. Moreover, while intended to reduce the adverse effects of fluctuations in crude oil and refined product prices, such transactions may limit our ability to benefit from favorable changes in margins. In addition, our hedging activities may expose us to the risk of financial loss in certain circumstances, including instances in which:

the volumes of our actual use of crude oil or production of the applicable refined products is less than the volumes subject to the hedging arrangement;

accidents, interruptions in feedstock transportation, inclement weather or other events cause unscheduled shutdowns or otherwise adversely affect our refinery, or those of our suppliers or customers;

the counterparties to our futures contracts fail to perform under the contracts; or

a sudden, unexpected event materially impacts the commodity or crack spread subject to the hedging arrangement.

As a result, the effectiveness of our hedging strategy could have a material adverse impact on our financial results and our ability to make distributions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure About Market Risk.”

In addition, these hedging activities involve basis risk. Basis risk in a hedging arrangement occurs when the price of the commodity we hedge is more or less variable than the index upon which the hedged commodity is based, thereby making the hedge less effective. For example, a NYMEX index used for hedging certain volumes of crude oil or refined products may have more or less variability than the cost or price for such crude oil or refined products. We do not expect to hedge the basis risk inherent in our derivatives contracts.

Our commodity derivative activities could result in period-to-period earnings volatility.

We do not apply hedge accounting to our commodity derivative contracts and, as a result, unrealized gains and losses are charged to our earnings based on the increase or decrease in the market value of the unsettled position. These gains and losses are reflected in our income statement in periods that differ from when the underlying hedged items (i.e., gross margins) are reflected in our income statement. Such derivative gains or losses in earnings may produce significant period-to-period earnings volatility that is not necessarily reflective of our underlying operational performance.

Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices.

The U.S. Congress adopted the Dodd-Frank Wall Street Reform and Consumer Protection Act in 2010 (the “Dodd-Frank Act”). This comprehensive financial reform legislation establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The legislation was signed into law by the President on July 21, 2010 and requires the Commodity Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. In December 2011, the CFTC extended temporary exemptive relief from the deadline for certain regulations applicable to swaps until no later than July 16, 2012. The CFTC has since adopted regulations to set position limits for certain futures and option contracts in the major energy markets. The CFTC has also proposed to establish minimum capital requirements, although it is not possible at this time to predict whether or when the CFTC will adopt these rules as proposed or include comparable provisions in its rulemaking under the Dodd-Frank Act. The Dodd-Frank Act may also require compliance with margin requirements and with certain clearing and trade-execution requirements in connection with certain derivative activities, although the application of those provisions is uncertain at this time. The legislation may also require the counterparties to our commodity derivative contracts to spinoff some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty, or cause the entity to comply with the capital requirements, which could result in increased costs to counterparties such as us.

The Dodd-Frank Act and any new regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, reduce the availability of some derivatives to protect against risks we encounter, reduce our ability to monetize or restructure our existing commodity derivative contracts and potentially increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and any new regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to make distributions or plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the Dodd-Frank Act and any new regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations and therefore could have an adverse effect on our ability to make distributions.

Risks Primarily Related to Our Retail Business

Our retail business depends on one principal supplier for a substantial portion of its merchandise inventory. A change of merchandise suppliers, a disruption in merchandise supply, a significant change in our relationship with our principal merchandise supplier or material changes in the payment terms or availability of trade credit provided by our merchandise suppliers could have a material adverse effect on our retail business and results of operations or liquidity.

Eby-Brown Company (“Eby-Brown”) is a wholesale grocer that has been the primary supplier of general merchandise, including most tobacco and grocery items, for all our retail stores since 1993. For the three months ended March 31, 2012 and the year ended December 31, 2011, our retail business purchased approximately 80% of its convenience store inside merchandise requirements from Eby-Brown. Our retail business also purchases a variety of merchandise, including soda, beer, bread, dairy products, ice cream and snack foods, directly from a number of manufacturers and their wholesalers. A change of merchandise suppliers, a disruption in merchandise supply or a significant change in our relationship with Eby-Brown could have a material adverse effect on our retail business and results of operations. In addition, our retail business is impacted by the availability of trade credit to fund merchandise purchases. Any material changes in the payments terms, including payment discounts, or availability of trade credit provided by our merchandise suppliers could adversely affect our liquidity or results of operations and, as a result, our ability to make distributions.

If the locations of our current convenience stores become unattractive to customers and attractive alternative locations are not available for a reasonable price, then our ability to maintain and grow our retail business will be adversely affected.

We believe that the success of any retail store depends in substantial part on its location. There can be no assurance that the locations of our retail stores will continue to be attractive to customers as demographic patterns change. Neighborhood or economic conditions where retail stores are located could decline in the future, resulting in potentially reduced sales in these locations. If we cannot obtain desirable locations at reasonable prices, our ability to maintain and grow our retail business could be adversely affected, which could have an adverse effect on our business, financial condition or results of operations and, as a result, our ability to make distributions.

The growth of our retail business depends in part on our ability to open and profitably operate new convenience stores and to successfully integrate acquired sites and businesses in the future.

We may not be able to open new convenience stores and any new stores we open may be unprofitable. Additionally, acquiring sites and businesses in the future involves risks that could cause our actual growth or operating results to be lower than expected. If these events were to occur, each would have a material adverse impact on our financial results. There are several factors that could affect our ability to open and profitably operate new stores or to successfully integrate acquired sites and businesses. These factors include:

competition in targeted market areas;

difficulties during the acquisition process in discovering certain liabilities of the businesses that we acquire;

the inability to identify and acquire suitable sites or to negotiate acceptable leases for such sites;

difficulties associated with the growth of our financial controls, information systems, management resources and human resources needed to support our future growth;

difficulties with hiring, training and retaining skilled personnel, including store managers;

difficulties in adapting distribution and other operational and management systems to an expanded network of stores;

the potential inability to obtain adequate financing to fund our expansion;

limitations on investments contained in our revolving credit facility and other debt instruments;

difficulties in obtaining governmental and other third-party consents, permits and licenses needed to operate additional stores;

difficulties in obtaining any cost savings, accretion and financial improvements anticipated from future acquired stores or their integration; and

challenges associated with the consummation and integration of any future acquisition.

Our retail store franchisees are independent business operators that could take actions that harm our brand, reputation or goodwill, which could adversely affect our business, results of operations, financial condition or cash flows.

Our retail store franchisees are independent business operators, not employees, and, as such, we cannot control their operations. These franchisees could hire and fail to train unqualified sales associates and other employees, or operate the franchised retail stores in a manner inconsistent with our operating standards. If our retail store franchisees provide diminished quality of service to customers, or if they engage or are accused of engaging in unlawful or tortious acts, such as sexual harassment or discriminatory practices in violation of applicable laws, then our brand, reputation or goodwill could be harmed, which could have an adverse effect on our business, results of operations, financial condition or cash flows and, as a result, our ability to make distributions.

Additionally, as independent business operators, our retail store franchisees could occasionally disagree with us or with our strategies regarding our retail business or with our interpretation of the rights and obligations set forth under our retail franchise agreement. This could lead to disputes with our retail store franchisees, which we expect to occur from time to time in the future as we continue to offer and sell retail store franchises. To the extent we have such disputes, the attention of our management and our retail store franchisees could be diverted, which could have an adverse effect on our business, results of operations, financial condition or cash flows and, as a result, our ability to make distributions.

Credit and debit card data loss, litigation and/or liability could significantly harm our reputation and adversely impact our business.

In connection with credit and debit card sales at our retail stores, we transmit confidential credit and debit card information securely over public networks. Third parties may have the technology or know-how to breach the security of this customer information, and our security measures may not effectively prohibit others from obtaining improper access to this information. If a person is able to circumvent our security measures, he or she could destroy or steal valuable information or disrupt our operations. Any security breach could expose us to risks of data loss, litigation and liability and could seriously disrupt our operations and any resulting negative publicity could significantly harm our reputation.

Our failure or inability to enforce our current and future trademarks and trade names could adversely affect our efforts to establish brand equity and expand our retail franchising business.

Our ability to successfully expand our retail franchising business will depend on our ability to establish brand equity through the use of our current and future trademarks, service marks, trade dress and other proprietary intellectual property, including our name and logos. Some or all of these intellectual property rights may not be enforceable, even if registered, against any prior users of similar intellectual property or our competitors who seek to use similar intellectual property in areas where we operate or intend to conduct operations. If we fail to enforce any of our intellectual property rights, then we may be unable to capitalize on our efforts to establish brand equity.

We could encounter claims from prior users of similar intellectual property in areas where we operate or intend to conduct operations, which could result in additional expenditures and divert our management’s time and attention from our operations. Conversely, competing businesses, including any of our former retail store franchisees, could infringe on our intellectual property, which would necessarily require us to defend our intellectual property possibly at a significant cost to us.

Our retail business is vulnerable to changes in consumer preferences, economic conditions and other trends and factors that could harm our business, results of operations, financial condition or cash flows.

Our retail business is affected by consumer preferences, national, regional and local economic conditions, demographic trends and consumer confidence in the economy. Factors such as traffic patterns, weather conditions, local demographics and the number and locations of competing retail service stations and convenience stores also affect the performance of our retail stores. In addition, we cannot ensure that our retail customers will continue to frequent our retail stores or that we will be able to find new retail store franchisees or encourage our existing retail store franchisees to grow their franchised business or renew their franchise rights. Adverse changes in any of these trends or factors could reduce our retail customer traffic or sales, or impose limits on our pricing, which could adversely affect our business, results of operations, financial condition or cash flows and, as a result, our ability to make distributions.

We face the risk of litigation in connection with our retail operations.

We are from time to time the subject of complaints or litigation from our consumers alleging illness, injury or other health or operational concerns. Adverse publicity resulting from these allegations may materially adversely affect us and our brand, regardless of whether the allegations are valid or whether we are liable. In addition, employee claims against us based on, among other things, discrimination, harassment or wrongful termination, or labor code violations may divert financial and management resources that would otherwise be used to benefit our future performance. There is also a risk of litigation from our franchisees. We have been subject to a variety of these and other claims from time to time and a significant increase in the number of these claims or the number that are successful could materially adversely affect our business, prospects, financial condition, operating results or cash flows and, as a result, our ability to make distributions.

Failure of our retail business to comply with state and local laws regulating the sale of alcohol and tobacco products could result in the loss of necessary licenses and the imposition of fines and penalties on us, which could have a material adverse effect on our business, liquidity and results of operations.

State and local laws regulate the sale of alcohol and tobacco products. In certain areas where our stores are located, state or local laws limit the hours of operation for the sale of alcohol, or prohibit the

sale of alcohol, and permit the sale of alcohol and tobacco products only to persons older than a certain age. State and local regulatory agencies have the authority to approve, revoke, suspend or deny applications for, and renewals of, permits and licenses relating to the sale of alcohol and tobacco products and to issue fines to stores for the improper sale of alcohol and tobacco products. Most jurisdictions, in their permit and license applications, require an applicant to disclose past denials, suspensions, or revocations of permits or licenses relating to the sale of alcohol and tobacco products in any jurisdiction. Thus, if we experience a denial, suspension, or revocation in one jurisdiction, then it could have an adverse effect on our ability to obtain permits and licenses relating to the sale of alcohol and tobacco products in other jurisdictions. In addition, the failure of our retail business to comply with state and local laws regulating the sale of alcohol and tobacco products could result in the loss of necessary licenses and the imposition of fines and penalties on us. Such a loss or imposition could have a material adverse effect on our business, liquidity and results of operations and, as a result, our ability to make distributions.

Risks Related to an Investment in Us

The board of directors of our general partner will adopt a policy to distribute an amount equal to the available cash we generate each quarter, which could limit our ability to grow and make acquisitions.

The board of directors of our general partner will adopt a policy to distribute an amount equal to the available cash we generate each quarter to our unitholders, beginning with the quarter ending , 2012. As a result, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As such, to the extent we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.

In addition, because of our distribution policy, our growth, if any, may not be as robust as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures or as in-kind distributions, current unitholders will experience dilution and the payment of distributions on those additional units will decrease the amount we distribute on each outstanding unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the available cash that we have to distribute to our unitholders. See “Distribution Policy and Restrictions on Distributions.”

Our general partner, the indirect owners of which include ACON Refining, TPG Refining and certain members of our management team, has fiduciary duties to its owners, and the interests of ACON Refining, TPG Refining and certain members of our management team may differ significantly from, or conflict with, the interests of our public unitholders.

Our general partner is responsible for managing us. Although our general partner has fiduciary duties to manage us in a manner that it believes is in our best interests, the fiduciary duties are specifically limited by the express terms of our partnership agreement, and the directors and officers of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to its owners, which include ACON Refining, TPG Refining and certain members of our management team. The interests of ACON Refining, TPG Refining and these management team members may differ from, or conflict with, the interests of our unitholders. In resolving these conflicts, our general partner may favor its own interests or the interests of its owners over our interests and those of our unitholders.

The potential conflicts of interest include, among others, the following:

Neither our partnership agreement nor any other agreement will require the owners of our general partner to pursue a business strategy that favors us. The affiliates of our general partner have fiduciary duties to make decisions in their own best interests and in the best interest of their owners, which may be contrary to our interests. In addition, our general partner is allowed to take into account the interests of parties other than us or our unitholders, such as its owners, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders.

Our general partner has limited its liability and reduced its fiduciary duties under our partnership agreement and has also restricted the remedies available to our unitholders for actions that, without those limitations and reductions, might constitute breaches of fiduciary duty. As a result of purchasing common units, unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.

The board of directors of our general partner will determine the amount and timing of asset purchases and sales, capital expenditures, borrowings, repayment of indebtedness and issuances of additional partnership interests, each of which can affect the amount of cash that is available for distribution to our unitholders.

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf. There is no limitation in our partnership agreement on the amounts our general partner can cause us to pay it or its affiliates.

Our general partner may exercise its rights to call and purchase all of our common units and PIK units if at any time it and its affiliates own more than 80% of the units.

Our general partner will control the enforcement of obligations owed to us by it and its affiliates. In addition, our general partner will decide whether to retain separate counsel or others to perform services for us.

Our general partner determines which costs incurred by it and its affiliates are reimbursable by us.

See “Conflicts of Interest and Fiduciary Duties.”

Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner and restricts the remedies available to us and our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our common unitholders for actions that, without these limitations and reductions, might constitute breaches of fiduciary duty. Delaware partnership law permits such contractual reductions of fiduciary duty. By purchasing common units, common unitholders consent to some actions that might otherwise constitute a breach of fiduciary or other duties applicable under state law. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example:

Our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to its capacity as general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, our common unitholders. Decisions made by our general partner in its individual capacity will be made by its owners and

not by the board of directors of our general partner. Examples include the exercise of the general partner’s call right, its voting rights with respect to any common units or PIK units it may own and its determination whether or not to consent to any merger or consolidation or amendment to our partnership agreement.

Our partnership agreement provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decisions were not adverse to the interests of our partnership.

Our partnership agreement provides that our general partner and the officers and directors of our general partner will not be liable for monetary damages to us for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those persons acted in bad faith or, in the case of a criminal matter, acted with knowledge that such person’s conduct was unlawful.

Our partnership agreement provides that our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is:

•

Approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or

•

Approved by the vote of a majority of the outstanding units, excluding any units owned by our general partner and its affiliates.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. See “Conflicts of Interest and Fiduciary Duties.”

By purchasing a common unit, a unitholder will become bound by the provisions of our partnership agreement, including the provisions described above. See “Description of Our Common Units—Transfer of Common Units.”

Northern Tier Holdings has the power to appoint and remove our general partner’s directors.

Upon the consummation of this offering, Northern Tier Holdings will have the power to elect all of the members of the board of directors of our general partner. Our general partner has control over all decisions related to our operations. See “Management—Our Management.” Our public unitholders do not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. Furthermore, the goals and objectives of the owners of our general partner may not be consistent with those of our public unitholders.

Common units and PIK units are subject to our general partner’s call right.

If at any time our general partner and its affiliates own more than 80% of the units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the units held by unaffiliated unitholders at a price not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. Our general

partner is not obligated to obtain a fairness opinion regarding the value of the units to be repurchased by it upon exercise of the call right. There is no restriction in our partnership agreement that prevents our general partner from issuing additional units and then exercising its call right. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. See “The Partnership Agreement—Call Right.”

Our unitholders have limited voting rights and are not entitled to elect our general partner or our general partner’s directors.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right to elect our general partner or our general partner’s board of directors on an annual or other continuing basis. The board of directors of our general partner, including the independent directors, will be chosen entirely by Northern Tier Holdings as the direct owner of the general partner and not by our common unitholders. Unlike publicly traded corporations, we will not hold annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders. Furthermore, even if our unitholders are dissatisfied with the performance of our general partner, they will have no practical ability to remove our general partner. These limitations could adversely affect the price at which the common units will trade.

Our public unitholders will not have sufficient voting power to remove our general partner without Northern Tier Holdings’ consent.

Our general partner may only be removed by a vote of the holders of at least two-thirds of the outstanding units, including any units owned by our general partner and its affiliates (including Northern Tier Holdings). Following the closing of this offering, Northern Tier Holdings will own approximately % of our units (or approximately % of our units if the underwriters exercise their option to purchase additional common units in full), which means holders of common units purchased in this offering will not be able to remove the general partner, under any circumstances, unless Northern Tier Holdings sells some of the units that it owns or we sell additional units to the public.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units (other than our general partner and its affiliates and permitted transferees).

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, may not vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common unitholders to influence the manner or direction of management.

Cost reimbursements due to our general partner and its affiliates will reduce cash available for distribution to you.

Prior to making any distribution on our outstanding units, we will reimburse our general partner for all expenses it incurs on our behalf including, without limitation, salary, bonus, incentive compensation and other amounts paid to its employees and executive officers who perform services for us. There are no limits contained in our partnership agreement on the amounts or types of expenses for which our general partner and its affiliates may be reimbursed. The payment of these amounts, including allocated overhead, to our general partner and its affiliates could adversely affect our ability to make

distributions to our unitholders. See “Distribution Policy and Restrictions on Distributions,” “Certain Relationships and Related Person Transactions” and “Conflicts of Interest and Fiduciary Duties—Conflicts of Interest.”

Unitholders may have liability to repay distributions.

In the event that: (1) we make distributions to our unitholders when our nonrecourse liabilities exceed the sum of (a) the fair market value of our assets not subject to recourse liability and (b) the excess of the fair market value of our assets subject to recourse liability over such liability, or a distribution causes such a result, and (2) a unitholder knows at the time of the distribution of such circumstances, such unitholder will be liable for a period of three years from the time of the impermissible distribution to repay the distribution under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”).

Likewise, upon the winding up of the partnership, in the event that (1) we do not distribute assets in the following order: (a) to creditors in satisfaction of their liabilities; (b) to partners and former partners in satisfaction of liabilities for distributions owed under our partnership agreement; (c) to partners for the return of their contribution; and finally (d) to the partners in the proportions in which the partners share in distributions and (2) a unitholder knows at the time of such circumstances, then such unitholder will be liable for a period of three years from the impermissible distribution to repay the distribution under Section 17-807 of the Delaware Act.

A purchaser of common units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to us that are known by the purchaser at the time it became a limited partner and for unknown obligations if the liabilities could be determined from our partnership agreement.

Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the owners of our general partner to transfer their equity interests in our general partner to a third party. The new equity owner of our general partner would then be in a position to replace the board of directors and the officers of our general partner with its own choices and to influence the decisions taken by the board of directors and officers of our general partner.

There is no existing market for our common units, and we do not know if one will develop to provide you with adequate liquidity. If our unit price fluctuates after this offering, you could lose a significant part of your investment.

Prior to this offering, there has not been a public market for our common units. If an active trading market does not develop, you may have difficulty selling any of our common units that you buy. The initial public offering price for the common units will be determined by negotiations between us and the underwriters and may not be indicative of prices that will prevail in the open market following this offering. Consequently, you may not be able to sell our common units at prices equal to or greater than the price paid by you in this offering. The market price of our common units may be influenced by many factors including:

our operating and financial performance;

quarterly variations in our financial indicators, such as net (loss) earnings per unit, net earnings (loss) and revenues;

the amount of distributions we make and our earnings or those of other companies in our industry or other publicly traded partnerships;

strategic actions by our competitors;

changes in revenue or earnings estimates, or changes in recommendations or withdrawal of research coverage, by equity research analysts;

speculation in the press or investment community;

sales of our common units by us or other unitholders, or the perception that such sales may occur;

changes in accounting principles;

additions or departures of key management personnel;

actions by our unitholders;

general market conditions, including fluctuations in commodity prices; and

domestic and international economic, legal and regulatory factors unrelated to our performance.

As a result of these factors, investors in our common units may not be able to resell their common units at or above the initial offering price. In addition, the stock market in general has experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of companies like us. These broad market and industry factors may materially reduce the market price of our common units, regardless of our operating performance.

Our new standalone finance and accounting information systems may fail to operate effectively or as intended, which could adversely affect the reliability of our financial statements.

Pursuant to a transition services agreement, Marathon agreed to provide us with, among other things, administrative and support services, including finance, accounting and information system services, for up to 18 months following the closing of the Marathon Acquisition to allow us time to build the infrastructure required to operate these functions independently. During the fourth quarter of 2011, we transitioned the finance, accounting information system services and functions from Marathon to our own standalone information systems and processes. It is possible that we will discover material shortcomings in our new standalone finance accounting information systems and processes, including those that may represent material weaknesses in our internal control over financial reporting, that are not currently known to us. Any such defects could adversely affect the reliability of our financial statements.

If, after this offering, we are unable to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act, or our internal control over financial reporting are not effective, the reliability of our financial statements may be questioned, and our unit price may suffer.

Section 404 of the Sarbanes-Oxley Act requires any company subject to the reporting requirements of the U.S. securities laws to perform a comprehensive evaluation of its and its subsidiaries’ internal controls. To comply with these requirements, we will be required to document and test our internal control procedures, our management will be required to assess and issue a report concerning our internal control over financial reporting, and, under the Sarbanes-Oxley Act, our independent auditors will be required to issue an opinion on management’s assessment and the effectiveness of our internal control over financial reporting. Our compliance with Section 404 of the Sarbanes-Oxley Act will first be reported on in connection with the filing of our second Annual Report on Form 10-K. The rules governing the standards that must be met for management to assess our

internal control over financial reporting are complex and require significant documentation, testing and possible remediation. During the course of its testing, our management may identify material weaknesses, which may not be remedied in time to meet the deadline imposed by the SEC rules implementing Section 404. If our management cannot favorably assess the effectiveness of our internal control over financial reporting, or our auditors identify material weaknesses in our internal control, investor confidence in our financial results may weaken, and the price of our common units may suffer.

You will incur immediate and substantial dilution in net tangible book value per common unit.

The initial public offering price of our common units is substantially higher than the pro forma net tangible book value of our outstanding units. As a result, if you purchase common units in this offering, you will incur immediate and substantial dilution in the amount of $ per common unit. See “Dilution.”

We may issue additional common units and other equity interests without your approval, which would dilute your existing ownership interests.

Under our partnership agreement, we are authorized to issue an unlimited number of additional interests without a vote of the unitholders. For example, we will issue additional PIK units, in lieu of making cash distributions, to the holders of the PIK units during the PIK period. In addition, at the end of the PIK period, the PIK units will convert into common units. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:

the proportionate ownership interest of unitholders immediately prior to the issuance will decrease;

the amount of cash distributions on each unit will decrease;

the ratio of our taxable income to distributions may increase;

the relative voting strength of each previously outstanding unit will be diminished; and

the market price of the common units may decline.

In addition, our partnership agreement does not prohibit the issuance of equity interests by our subsidiary, which may effectively rank senior to the common units.

Our general partner may redeem, retire, repurchase or otherwise refinance the senior secured notes or otherwise amend the indenture in a manner that terminates the PIK period. Any such action may require us to incur substantial costs.

At any time, our general partner may, in its sole discretion and on terms determined in its sole discretion, redeem, retire, repurchase or otherwise refinance the senior secured notes or otherwise amend the indenture in a manner that terminates the PIK period. Following the termination of the PIK period, distributions in respect of any outstanding PIK units will be paid in cash (and any PIK units will automatically convert into an equal number of common units). Under our partnership agreement, such a decision will explicitly be deemed not to be a violation of the fiduciary duties that might otherwise be owed by our general partner to our unitholders. The redemption, retirement, repurchase or refinancing of the senior secured notes or any amendment to the indenture may be at a substantial expense to us. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Description of Our Indebtedness—Senior Secured Notes” for a discussion of our ability to redeem the senior secured notes and the redemption price related thereto.

Units eligible for future sale may cause the price of our common units to decline.

Sales of substantial amounts of our common units in the public market, or the perception that these sales may occur, could cause the market price of our common units to decline. This could also impair our ability to raise additional capital through the sale of our equity interests.

There will be units outstanding following this offering. common units are being sold to the public in this offering (or common units if the underwriters exercise their option to purchase additional common units in full) and an aggregate of common units and PIK units will be owned by Northern Tier Holdings (or common units and PIK units if the underwriters exercise their option to purchase additional common units in full). The common units sold in this offering will be freely transferable without restriction or further registration under the Securities Act of 1933, as amended (the “Securities Act”), by persons other than “affiliates,” as that term is defined in Rule 144 under the Securities Act.

In addition, we are party to a registration rights agreement with Northern Tier Holdings and certain of its indirect owners pursuant to which we may be required to register the sale of the units they hold under the Securities Act and applicable state securities laws.

In connection with this offering, we, Northern Tier Holdings, our general partner and our general partner’s directors and executive officers will enter into lock-up agreements, pursuant to which they will agree, subject to certain exceptions, not to sell or transfer, directly or indirectly, any of our units until 180 days from the date of this prospectus, subject to extension in certain circumstances. Following termination of these lockup agreements, all units held by Northern Tier Holdings, our general partner and our general partner’s directors and executive officers will be freely tradable under Rule 144, subject to the volume and other limitations of Rule 144. See “Common Units Eligible for Future Sale.”

We will incur increased costs as a result of being a publicly traded partnership.

As a publicly traded partnership, we will incur significant legal, accounting and other expenses that we did not incur prior to this offering. In addition, the Sarbanes-Oxley Act and the Dodd-Frank Act, as well as rules implemented by the SEC and the NYSE, require, or will require, publicly traded entities to adopt various corporate governance practices that will further increase our costs. Before we are able to pay distributions to our unitholders, we must first pay our expenses, including the costs of being a public company and other operating expenses. As a result, the amount of cash we have available for distribution to our unitholders will be affected by our expenses, including the costs associated with being a publicly traded partnership. We estimate that we will incur approximately $3.5 million of estimated incremental costs per year, some of which will be direct charges associated with being a publicly traded partnership and some of which will be allocated to us by our general partner and its affiliates; however, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.

Prior to this offering, we have not filed reports with the SEC. Following this offering, we will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). We expect these requirements will increase our legal and financial compliance costs and make compliance activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal control over financial reporting. In addition, we will incur additional costs associated with our publicly traded company reporting requirements.

As a publicly traded limited partnership we qualify for, and will rely on, certain exemptions from the New York Stock Exchange’s corporate governance requirements.

As a publicly traded partnership, we qualify for, and will rely on, certain exemptions from the NYSE’s corporate governance requirements, including:

the requirement that a majority of the board of directors of our general partner consist of independent directors;

the requirement that the board of directors of our general partner have a nominating/corporate governance committee that is composed entirely of independent directors; and

the requirement that the board of directors of our general partner have a compensation committee that is composed entirely of independent directors.

As a result of these exemptions, our general partner’s board of directors will not be comprised of a majority of independent directors, our general partner’s compensation committee may not be comprised entirely of independent directors and our general partner’s board of directors does not currently intend to establish a nominating/corporate governance committee. Accordingly, unitholders will not have the same protections afforded to equityholders of companies that are subject to all of the corporate governance requirements of the NYSE. See “Management.”

Tax Risks

In addition to reading the following risk factors, you should read “Material Federal Income Tax Consequences” for a more complete discussion of the expected material federal income tax consequences of owning and disposing of common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation for federal income tax purposes, or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to you could be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service (the “IRS”) on this or any other tax matter affecting us. To maintain our status as a partnership for federal income tax purposes, current law requires that 90% or more of our gross income for every taxable year consist of “qualifying income,” as defined in Section 7704 of the Internal Revenue Code of 1986, as amended (the “Code”). “Qualifying income” includes (i) income and gains derived from the refining, transportation, processing and marketing of crude oil, natural gas and products thereof, (ii) interest (other than from a financial business), (iii) dividends, (iv) gains from the sale of real property and (v) gains from the sale or other disposition of capital assets held for the production of qualifying income.

Despite the fact that we are organized as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe, based upon our current operations, that we will be so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35% and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as

corporate distributions, and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes at any time. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may be applied retroactively and could impose additional administrative requirements on us or make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes. We are unable to predict whether any of these changes, or other proposals will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. Following this offering, Northern Tier Holdings will own more than 50% of the total interests in our capital and profits. If transfers within a twelve-month period of common units and PIK units by Northern Tier Holdings, by itself or in combination with other transfers of common units, represent 50% or more of the total interests in our capital and profits, we will be considered to have terminated our partnership for federal income tax purposes. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in its taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. See “Material Federal Income Tax Consequences—Disposition of Units—Constructive Termination” for a discussion of the consequences of our termination for federal income tax purposes.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our net taxable income decrease your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those units, even if the price you receive is less than your original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale. See “Material Federal Income Tax Consequences—Disposition of Units—Recognition of Gain or Loss” for a further discussion of the foregoing.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (“IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to you.

The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. Our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that may not conform to all aspects of existing and proposed U.S. Treasury regulations (the “Treasury Regulations”). A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. See “Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election” for a further discussion of the effect of the depreciation and amortization positions we will adopt.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We will prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and although the U.S. Treasury Department issued proposed Treasury Regulations allowing a similar monthly simplifying convention, such regulations are not final and do not specifically authorize the use of the proration method we have adopted. Accordingly, our counsel is unable to opine as to the validity of this method. If the IRS were to successfully challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because there is no tax concept of loaning a partnership interest, a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units. See “Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Treatment of Short Sales” for a further discussion of the foregoing.

Unitholders may be subject to state and local taxes and return filing requirements in jurisdictions where they do not live as a result of investing in our common units.

In addition to federal income taxes, unitholders may become subject to other taxes, including state, local and non-U.S. taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by jurisdictions in which we conduct business or own property in the future, even if they do not live in any of those jurisdictions. We currently conduct business or own property in several states, each of which imposes an income tax on corporations and other entities and a personal income tax. We may own property or conduct business in other states or non-U.S. countries in the future. Unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of those various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. It is the unitholder’s responsibility to file all federal, state, local and non-U.S. tax returns.

As part of the IPO Transactions, some of our subsidiaries will elect to be treated as corporations for federal income tax purposes and will become subject to corporate-level income taxes.

As part of the IPO Transactions, certain of our subsidiaries, including Northern Tier Retail Holdings LLC, which holds all of the ownership interests in Northern Tier Retail LLC and Northern Tier Bakery LLC, and Northern Tier Energy Holdings LLC, will elect to be treated as corporations for federal income tax purposes, which will subject them to corporate-level income taxes and may reduce the cash available for distribution to us and, in turn, to unitholders. In the future, we may conduct additional operations through these subsidiaries or additional subsidiaries that are subject to corporate-level income taxes. Our historical financial statements do not reflect the corporate-level taxes that these subsidiaries would be required to pay in the future, which may affect the financial statements’ usefulness in predicting our future earnings and ability to distribute cash. Additionally, any losses in these subsidiaries will not be available to offset income generated by our other business operations, and may necessitate additional cash contributions that would reduce the cash available for distribution to unitholders.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus includes “forward-looking statements.” 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, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. All statements herein about our forecast of available cash and our forecasted results for the twelve months ending June 30, 2013 and the three months ending September 30, 2013 constitute forward-looking statements. 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 prospectus may turn out to be inaccurate.

Forward-looking statements appear in a number of places in this prospectus, including “Prospectus Summary,” “Risk Factors,” “Distribution Policy and Restrictions on Distributions,” “Management’s Discussion and Analysis of Financial Conditions and Results of Operations” and “Business,” and include statements with respect to, among other things:

our ability to make distributions on the common units;

the volatile nature of our business and the variable nature of our distributions;

the ability of our general partner to modify or revoke our distribution policy at any time;

our ability to forecast our future financial condition, results of operations, future compliance with covenants in our debt instruments and our future sales and expenses;

our forecast of available cash and our forecasted results for the twelve months ending June 30, 2013 and the three months ending September 30, 2013;

the estimated ratio of taxable income to distributions;

our business strategy and prospects;

technology;

our cash flows and liquidity;

our financial strategy, budget, projections and operating results;

the amount, nature and timing of capital expenditures;

the availability and terms of capital;

competition and government regulations;

general economic conditions and trends in the refining industry;

effectiveness of our risk management activities;

our environmental liabilities;

our counterparty credit risk;

governmental regulation and taxation of the refining industry; and

developments in oil-producing and natural gas-producing countries.

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. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:

the overall demand for specialty hydrocarbon products, fuels and other refined products;

our ability to produce products and fuels that meet our customers’ unique and precise specifications;

the impact of fluctuations and rapid increases or decreases in crude oil, refined products, fuel and utility services prices and crack spreads, including the impact of these factors on our liquidity;

fluctuations in refinery capacity;

accidents or other unscheduled shutdowns affecting our refineries, machinery, or equipment, or those of our suppliers or customers;

changes in the cost or availability of transportation for feedstocks and refined products;

the results of our hedging and other risk management activities;

our ability to comply with covenants contained in our debt instruments;

labor relations;

relationships with our partners and franchisees;

successful integration and future performance of acquired assets, businesses or third-party product supply and processing relationships;

our access to capital to fund expansions, acquisitions and our working capital needs and our ability to obtain debt or equity financing on satisfactory terms;

currently unknown liabilities in connection with the Marathon Acquisition;

environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;

dependence on one principal supplier for merchandise;

maintenance of our credit ratings and ability to receive open credit lines from our suppliers;

the effects of competition;

continued creditworthiness of, and performance by, counterparties;

the impact of current and future laws, rulings and governmental regulations, including guidance related to the Dodd-Frank Act;

shortages or cost increases of power supplies, natural gas, materials or labor;

weather interference with business operations;

seasonal trends in the industries in which we operate;

fluctuations in the debt markets;

potential product liability claims and other litigation;

accidents or other unscheduled shutdowns or disruptions;

changes in economic conditions, generally, and in the markets we serve, consumer behavior, and travel and tourism trends; and

changes in our treatment as a partnership for U.S. income or state tax purposes.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other unknown or unpredictable factors also could have material adverse effects on our future results. Our future results will depend upon various other risks and uncertainties, including those described elsewhere in this prospectus under the heading, “Risk Factors.” Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise. All forward-looking statements attributable to us are qualified in their entirety by this cautionary statement.

USE OF PROCEEDS

We expect to receive approximately $ million of net proceeds from the sale of the common units offered by us, based upon the assumed initial public offering price of $ per unit (the midpoint of the price range set forth on the cover page of this prospectus), after deducting the underwriting discount of approximately $ million (or approximately $ million if the underwriters exercise in full their option to purchase additional common units) and estimated offering expenses of $ million (including a $6.0 million fee payable to ACON Management and TPG Management pursuant to a management services agreement entered into at the time of the Marathon Acquisition). Each $1.00 increase (decrease) in the public offering price would increase (decrease) our net proceeds by approximately $ million (assuming no exercise of the underwriters’ option to purchase additional common units).

We intend to use the net proceeds to:

redeem $29 million of our senior secured notes at a redemption price of 103% of the principal amount thereof, for an estimated $30 million;

The remaining net proceeds of $ million will be used to fund capital expenditures and general partnership purposes.

The senior secured notes were issued in December 2010 in connection with the consummation of the Marathon Acquisition. The senior secured notes mature in December 2017 and bear an annual interest rate of 10.5%. $261 million of our senior secured notes will remain outstanding after the application of proceeds from this offering. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Description of Our Indebtedness—Senior Secured Notes.”

We have granted the underwriters a 30-day option to purchase up to an aggregate of additional common units. If the underwriters do not exercise this option in full or at all, the common units that would have been sold to the underwriters had they exercised the option in full will be issued to Northern Tier Holdings at the expiration of the option period. Any net proceeds received from the exercise of the underwriters’ option to purchase additional common units will be distributed to Northern Tier Holdings.

CAPITALIZATION

The following table sets forth cash and cash equivalents and capitalization as of March 31, 2012:

on an actual basis for Northern Tier Energy LLC; and

on an as adjusted basis for Northern Tier Energy LP, after giving effect to this offering, the use of proceeds and the other transactions described in “Prospectus Summary—The IPO Transactions.”

You should read the following table in conjunction with “Prospectus Summary—The IPO Transactions,” “Use of Proceeds,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our financial statements and related notes thereto appearing elsewhere in this prospectus.


	As of March 31, 2012
	Northern Tier Energy LLC		Northern Tier Energy LP
	Actual		As adjusted
	(in millions)
Cash and cash equivalents(1)	$	64.1	$

Long-term debt, including current maturities:
Senior secured notes	$	290.0	$
Revolving credit facility(2)		—
Lease financing obligation(3)		11.9

Total long-term debt, including current maturities		301.9

Member’s/Partners’ interest:
Member’s/partners’ interest(4)		116.0		—
Common units: none issued and outstanding; issued and outstanding, pro forma		—
PIK units: none issued and outstanding; issued and outstanding, pro forma		—
General partner interest		—
Additional paid-in capital		—

Total member’s/partners’ interest		116.0

Total capitalization	$	417.9	$

(1)	As of April 30, 2012, cash and cash equivalents were $142 million.

(2)	As of April 30, 2012, we had no borrowings outstanding under our revolving credit facility and had $62 million in outstanding letters of credit.

(3)	Relates to specific properties that did not qualify for operating lease treatment under the sale leaseback of 135 SuperAmerica convenience stores with Realty Income, a third party equity real estate investment trust.

(4)	On May 18, 2012, the Company declared a dividend and on May 22, 2012 the Company paid the dividend to Northern Tier Holdings in the amount of $40 million.

DILUTION

Dilution is the amount by which the offering price paid by the purchasers of units sold in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of March 31, 2012, after giving effect to the offering of common units and the application of the related net proceeds, and assuming the underwriters’ option to purchase additional common units is not exercised, our net tangible book value was $ million, or $ per unit. Net tangible book value excludes $ million of net intangible assets. Purchasers of common units in this offering will experience immediate and substantial dilution in net tangible book value per unit for financial accounting purposes, as illustrated in the following table:


Assumed initial public offering price per unit		$	—
Pro forma net tangible book value per unit before the offering	$
Increase in net tangible book value per unit attributable to purchasers in the offering

Less: Pro forma net tangible book value per unit after the offering(1)		$	—

Immediate dilution in net tangible book value per unit to purchasers in the offering(2)(3)		$	—

(1)	Determined by dividing the net tangible book value of the contributed assets and liabilities by the number of units ( common units and PIK units to be issued to Northern Tier Holdings).

(2)	Determined by dividing our pro forma net tangible book value, after giving effect to the application of the expected net proceeds of the offering by the total number of units ( common units and PIK units to be issued to Northern Tier Holdings) to be outstanding after the offering.

(3)	If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per unit would equal $ and $ , respectively.

The following table sets forth the number of units that we will issue and the total consideration contributed to us by Northern Tier Holdings and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus:

Units Acquired

Total Consideration

Number

Percent

Amount

Percent

Northern Tier Holdings(1)

Purchasers in this offering(2)

Total

(1)	The assets contributed by Northern Tier Holdings were recorded at historical cost in accordance with GAAP. Book value of the consideration provided by Northern Tier Holdings, as of March 31, 2012, equals parent net investment, which was $ million and is not affected by this offering.

(2)	Assumes the underwriters’ option to purchase additional common units is not exercised.

DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

You should read the following discussion of our distribution policy and restrictions on distributions in conjunction with the specific assumptions upon which our distribution policy is based. See “—Assumptions and Considerations” below. For additional information regarding our historical and our pro forma operating results, you should refer to “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and our audited financial statements included elsewhere in this prospectus. In addition, you should read “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements” for information regarding statements that do not relate strictly to historical or current facts and certain risks inherent in our business.

General

Our Distribution Policy

The board of directors of our general partner will adopt a policy pursuant to which distributions for each quarter (including the distributions of additional PIK units on outstanding PIK units) will equal the amount of available cash we generate in such quarter. Distributions on our units will be in cash, but during the PIK period described below, the board of directors of our general partner will cause distributions on the PIK units to be payable by Northern Tier Energy LP in the form of additional PIK units to the PIK unitholders of record on the applicable record date as described below. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We expect that available cash for each quarter will generally equal our cash flow from operations for the quarter, less cash needed for maintenance capital expenditures, accrued but unpaid expenses, reimbursement of expenses incurred by our general partner and its affiliates, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, including reserves for our turnaround and related expenses. In advance of scheduled turnarounds at our refinery, the board of directors of our general partner currently intends to reserve amounts to fund expenditures associated with such scheduled turnarounds. Such a decision by the board of directors may have an adverse impact on the available cash in the quarter(s) in which the reserves are withheld and a corresponding mitigating impact on the future quarter(s) in which the reserves are utilized. Actual turnaround and related expenses will be funded with cash reserves or borrowings under our revolving credit facility. We do not intend to maintain excess distribution coverage or reserve cash for the purpose of maintaining stability or growth in our quarterly distribution. We do not intend to incur debt to pay quarterly distributions. We expect to finance substantially all of our growth externally, either by debt issuances or additional issuances of equity.

Because our policy will be to distribute (through cash and in-kind distributions) an amount equal to all available cash we generate each quarter, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, will vary based on our operating cash flow during each quarter. Our quarterly distributions, if any, will not be stable and will vary from quarter to quarter and year to year as a direct result of variations in, among other factors, (i) our operating performance, (ii) cash flows caused by, among other things, fluctuations in the prices of crude oil and other feedstocks and the price we receive for refined products, working capital or capital expenditures and (iii) any cash reserves deemed necessary and appropriate by the board of directors of our general partner. Such variations in the amount of our quarterly distributions may be significant. Unlike most publicly traded partnerships, we

will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The board of directors of our general partner may change the foregoing distribution policy at any time. Our partnership agreement does not require us to pay distributions to our unitholders on a quarterly or other basis.

Notwithstanding our distribution policy, certain provisions of the indenture governing the senior secured notes and our revolving credit facility will restrict the ability of Northern Tier Energy LLC, our operating subsidiary, to distribute cash to us. The PIK units described below are designed to support the payment of cash distributions to our common unitholders during any period in which the provisions of our indenture may restrict our ability to distribute available cash to all unitholders in accordance with our distribution policy.

As discussed above, during the PIK period described below, the board of directors of our general partner will cause distributions on our PIK units to be payable in additional PIK units. The number of PIK units that will be distributed on a PIK unit in lieu of a quarterly cash distribution will equal a fraction, the numerator of which is the amount of the cash distribution paid on a common units and the denominator of which is the volume-weighted average price of a common unit for the 10 trading days immediately preceding the ex-dividend date for the associated distribution in respect of a common unit. This calculation is intended to provide the holders of PIK units with a number of PIK units equal in value on a per unit basis to the cash being simultaneously distributed to common unitholders. While the PIK units will not receive cash distributions during the PIK period, the distribution of additional PIK units in lieu of cash distributions may substantially increase the number of units outstanding and the amount of cash required on a quarterly and annual basis to pay distributions on all units. The effect of paying distributions of additional PIK units on PIK units is as if we had paid cash distributions on those PIK units, and the holders of those PIK units had in turn recontributed that cash to us in exchange for additional PIK units. The PIK period will commence on the date of the closing of the offering and end on the date that is the earlier of (i) and (ii) the date by which we redeem, repurchase, defease or retire all of the senior secured notes, or amend the indenture governing the senior secured notes in a manner that removes restrictions on our ability to distribute all available cash to unitholders. Immediately following the end of the PIK period, each outstanding PIK unit will be automatically converted into a common unit and entitled to receive any distributions in cash. See “How We Make Distributions—Partnership Interests” for a further description of the features of our equity capital structure. Northern Tier Holdings will initially hold all of our PIK units.

Limitations on Cash Distributions; Our Ability to Change Our Distribution Policy

There is no guarantee that unitholders will receive quarterly cash distributions from us. Our distribution policy may be changed at any time and is subject to certain restrictions, including:

Our unitholders have no contractual or other legal right to receive distributions from us on a quarterly or other basis. The board of directors of our general partner will adopt a policy at or prior to the closing of this offering pursuant to which distributions for each quarter (including the distributions of additional PIK units on outstanding PIK units) will equal the amount of the available cash we generate in such quarter, as determined quarterly by the board of directors of our general partner, but it may change this policy at any time.

Subject to certain exceptions, the indenture governing our senior secured notes and our revolving credit facility place restrictions on our ability to make cash distributions. Subject to certain exceptions, the restricted payment covenant under the indenture governing our senior secured notes restricts us from making cash distributions unless our fixed charge coverage ratio, as defined in the indenture, is at least 2.0 to 1.0 after giving pro forma effect to such distributions and such cash distributions do not exceed an amount equal to the aggregate net proceeds received by us (either as a result of capital contributions or from the sale of equity or

certain debt securities) plus 50% of our consolidated net income (or less 100% of consolidated net loss), which is defined to exclude certain non-cash charges, such as net unrealized gains or losses from hedging obligations and impairment charges, accrued on a cumulative basis, plus certain other items. Our revolving credit facility generally restricts our ability to make cash distributions if (a) we fail to have excess availability under the facility at least equal to the greater of (1) 25% of the lesser of (x) the $300 million commitment amount and (y) the then applicable borrowing base and (2) $37.5 million or (b) we fail to maintain a fixed charge coverage ratio, as defined in the revolving credit facility, after giving pro forma effect to such distributions of at least 1.1 to 1.0.

As of December 31, 2011 and March 31, 2012, our restricted payments basket under the indenture was equal to approximately $61.4 million and $59.2 million, respectively. On a pro forma basis for this offering, the contribution of a portion of the proceeds of this offering to Northern Tier Energy LLC and the use of the proceeds from this offering, as of December 31, 2011 and March 31, 2012, our restricted payments basket under the indenture would have been equal to approximately $ million and $ million, respectively. These financial tests and covenants are described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Description of Our Indebtedness.” Should we be unable to satisfy the restrictions described above or if we are otherwise in default under our revolving credit facility or the indenture, we may be required to reduce or eliminate cash distributions to you notwithstanding our distribution policy.

Unlike most publicly traded partnerships, we will not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase quarterly distributions over time. Furthermore, none of our limited partner interests will be subordinate in right of distributions to the common units sold in this offering.

Our general partner will have the authority to establish cash reserves for the prudent conduct of our business, and the establishment of or increase in those reserves could result in a reduction in cash distributions to our unitholders. Our partnership agreement does not set a limit on the amount of cash reserves that our general partner may establish. Any decision to establish cash reserves made by our general partner in good faith will be binding on our unitholders.

Prior to making any distributions on our units, we will reimburse our general partner and its affiliates for all direct and indirect expenses they incur on our behalf. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us, but does not limit the amount of expenses for which our general partner and its affiliates may be reimbursed. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of cash to pay distributions to our unitholders.

We may lack sufficient cash to make distributions to our unitholders due to a number of factors that would adversely affect us, including but not limited to decreases in sales or increases in operating expenses, principal and interest payments on debt, working capital requirements, capital expenditures, disruptions in the operations of our refinery or anticipated cash needs. See “Risk Factors” for information regarding these factors.

Under Section 17-607 of the Delaware Act, we may not make a distribution to our limited partners if the distribution would cause our liabilities to exceed the fair value of our assets.

We have a limited operating history upon which to rely in evaluating our ability to make distributions on our common units. While we believe, based on our financial forecast and related assumptions, that we should have sufficient cash to enable us to pay the forecasted aggregate distribution in cash on all of our units for the twelve months ending June 30, 2013 and for the three months ending September 30, 2013, we may be unable to pay the forecasted distribution or any amount on our units.

We expect to generally distribute a significant percentage of our cash from operations to our unitholders on a quarterly basis, after, among other things, the establishment of cash reserves and payment of our expenses. Therefore, our growth, if any, may not be comparable to those businesses that reinvest most or all of their cash to expand ongoing operations. Moreover, any future growth may be slower than our historical growth. We expect that we will rely upon external financing sources in large part, including bank borrowings and issuances of debt and equity interests, to fund our expansion capital expenditures. To the extent we are unable to finance growth externally, our distribution policy could significantly impair our ability to grow.

Unaudited Pro Forma Available Cash

The following table illustrates, on a pro forma basis for the year ended December 31, 2011 and for the year ended March 31, 2012, our available cash assuming that the IPO Transactions had occurred as of January 1, 2011.

If we had completed the IPO Transactions on January 1, 2011, our unaudited pro forma available cash for the year ended December 31, 2011 and the year ended March 31, 2012 would have been $11.7 million and $9.1 million, respectively. This amount would have enabled us to make an annualized distribution of $ and $ per unit on all of our outstanding units for the year ended December 31, 2011 and the year ended March 31, 2012, respectively (assuming that distributions on the PIK units are made in cash and not in additional PIK units). Our pro forma available cash for the year ended December 31, 2011 and the year ended March 31, 2012 includes a realized loss from derivative activities of $310.3 million and $311.0 million, respectively. The hedge positions resulting in this realized loss were established at the time of the Marathon Acquisition. Our plan going forward is to hedge a lesser amount of production than we hedged at the time of the acquisition. Consequently, we plan to increase our exposure to the gross refining margins that we would realize at our refinery on an unhedged basis.

Available cash is a cash accounting concept, while our consolidated financial statements have been prepared on an accrual basis. The amount of pro forma available cash should only be viewed as a general indication of the amount of available cash that we might have generated had we been formed and completed the IPO Transactions in earlier periods.


	Year Ended December 31, 2011			Twelve Months Ended March 31, 2012
	(in millions except per unit data)
Revenue	$	4,280.8		$	4,339.7
Costs, expenses and other:
Cost of sales		3,508.0			3,568.8
Direct operating expenses		260.3			259.1
Turnaround and related expenses		22.6			22.8
Depreciation and amortization		29.5			30.7
Selling, general and administrative		90.7			92.6
Formation costs		7.4			4.9
Contingent consideration income (loss)		(55.8	)		41.7
Other (income) expense, net		(4.5	)		(5.5	)

Operating income		422.6			324.6
Realized losses from derivative activities		(310.3	)		(311.0	)
Loss on early extinguishment of derivatives		—			(44.6	)
Unrealized losses from derivative activities		(41.9	)		132.6
Interest expense, net		(42.1	)		(42.5	)

Earnings before income taxes		28.3			59.1

Income tax provision		—			—

Net earnings	$	28.3		$	59.1

Adjustments to reconcile net earnings to Adjusted EBITDA:
Interest expense	$	42.1		$	42.5
Depreciation and amortization		29.5			30.7

EBITDA		99.9			132.3
Minnesota Pipeline proportionate EBITDA		2.8			2.6
Turnaround and related expenses		22.6			22.8
Stock-based compensation expense		1.6			1.7
Unrealized losses from derivative activities		41.9			(132.6	)
Loss on early extinguishment of derivatives		—			44.6
Realized losses on derivative activities		310.3			311.0
Contingent consideration income		(55.8	)		41.7
Formation costs		7.4			4.9

Adjusted EBITDA(a)	$	430.7		$	429.0


	Year Ended December 31, 2011		Twelve Months Ended March 31, 2012
	(in millions except per unit data)
Adjusted EBITDA(a)	$	430.7	$	429.0
Adjustments to reconcile Adjusted EBITDA to pro forma available cash:
Less:
Pro forma incremental general and administrative expenses(b)		3.5		3.5
Pro forma income tax paid(c)		5.7		6.6
Cash interest expense		37.9		38.0
Minnesota Pipeline proportionate EBITDA		2.8		2.6
Actual turnaround and related expenses		22.6		22.8
Maintenance capital expenditures		45.9		45.3
Turnaround and related expenses reserve(d)		18.0		18.0
Realized losses on derivative activities		310.3		311.0
Plus:
Pro forma interest expense(e)		3.0		3.0
Pro forma management fee(f)		2.1		2.1
Use of cash reserves or borrowings to fund actual turnaround and related expenses		22.6		22.8

Pro forma available cash	$	11.7	$	9.1


Actual and implied cash distributions based on pro forma available cash(g):
Aggregate pro forma available cash per unit
Cash distributions to common unitholders
Available cash attributable to PIK units(h)

Indenture(i):
Restricted payments basket(j)	$		$
Fixed charge coverage ratio		2.8x		2.8x
Revolving credit facility:
Fixed charge coverage ratio(k)		1.2x		1.1x

(a)	For a definition of Adjusted EBITDA, see “Prospectus Summary—Summary Historical Condensed Consolidated Financial and Other Data.”

(b)

Represents an adjustment for estimated incremental general and administrative expenses that we expect we will incur as a publicly traded partnership, including costs associated with SEC reporting requirements, annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation.

(c)	Represents the estimated income tax provision resulting from Northern Tier Retail Holdings LLC, our subsidiary that conducts our retail business, and Northern Tier Energy Holdings LLC electing to be treated as corporations for federal income tax purposes.

(d)

Represents a reserve of cash to fund expenditures associated with scheduled turnarounds of our refinery. We estimate total turnaround and related expenses at our St. Paul Park refinery of approximately $110 million over a six-year turnaround cycle. Therefore, we estimate reserving approximately $18 million of available cash per year for turnaround and related expenses.

(e)	Reflects the reduction in interest expense related to the redemption of $29 million of our senior secured notes with a portion of the proceeds of this offering.

(f)

Represents the reduction in management fees paid to ACON Management and TPG Management pursuant to the management services agreement which will terminate in connection with the closing of this offering. At the closing of this offering, ACON Management and TPG Management will receive a success fee of $6.0 million pursuant to the management services agreement. See “Certain Relationships and Related Person Transactions—Agreements with Affiliates of Our General Partner—Management Services Agreement.”

(g)	Based on common units and PIK units outstanding and assumes no dilution with respect to distributions of additional PIK units on outstanding PIK units for each quarter in the period presented.

(h)	Available cash represented by distributions of additional PIK units on outstanding PIK units for any quarter is to be retained for general partnership purposes.

(i)

Subject to certain exceptions, the restricted payment covenant under the indenture governing our senior secured notes restricts us from making cash distributions unless our fixed charge coverage ratio, as defined in the indenture, is at least 2.0 to 1.0 and such cash distributions do not exceed an amount equal to the aggregate net proceeds received by us (either as a result of capital contributions or from the sale of equity or certain debt securities) plus 50% of our consolidated net income (or less 100% of consolidated net loss) accrued on a cumulative basis plus certain other items.

(j)	Represents the amount of the restricted payments basket before giving effect to the reduction in the basket as a result of the distributions assumed to be paid in respect of the common units as contemplated above.

(k)

Our revolving credit facility generally restricts our ability to make cash distributions if (a) we fail to have excess availability under the facility at least equal to the greater of (1) 25% of the lesser of (x) the $300 million commitment amount and (y) the then applicable borrowing base and (2) $37.5 million or (b) we fail to maintain a fixed charge coverage ratio, as defined in the revolving credit facility, after giving pro forma effect to such distributions of at least 1.1 to 1.0.

Forecasted Available Cash

We do not as a matter of course make projections as to future sales, earnings or other results. However, we have prepared the prospective financial information set forth below for the twelve months ending June 30, 2013 and the three months ending September 30, 2013 to supplement the historical consolidated financial information included elsewhere in this prospectus. The table presents our expectations regarding our ability to generate $220.4 million of available cash for the twelve months ending June 30, 2013 and $56.6 million for the three months ending September 30, 2013. The accompanying prospective financial information was not prepared with a view toward complying with the guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management’s knowledge and belief, the expected course of action and our expected future financial performance. However, this information is not fact and should not be relied upon as being indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information. The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Neither PricewaterhouseCoopers LLP nor any other independent accountants, has examined, compiled, or performed any procedures with respect to the accompanying prospective financial information and, accordingly, PricewaterhouseCoopers LLP does not express an opinion or any other form of assurance with respect thereto. The PricewaterhouseCoopers LLP reports included in the registration statement relate to our successor’s and predecessor’s historical financial information. Those reports do not extend to the prospective financial information and should not be read to do so.

In “—Assumptions and Considerations” below, we discuss the major assumptions underlying this estimate. We can give you no assurance that our assumptions will be realized or that we will generate any available cash, in which event we will not be able to pay quarterly cash distributions on our common units.

When considering our ability to generate available cash and how we calculate forecasted available cash, investors should keep in mind all of the risk factors and other cautionary statements under the headings “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements,” which describe factors that could cause our results of operations and available cash to vary significantly from our estimates.

The assumptions and estimates underlying the prospective financial information are inherently uncertain. Although such assumptions and estimates are considered, as of the date of this prospectus, to be reasonable by our management team, such assumptions and estimates are subject to a wide variety of significant business, economic and competitive risks and uncertainties that could cause actual results to differ materially from those contained in the prospective financial information. Such forward-looking statements are based on assumptions and views that we believe to be reasonable; however, assumed facts almost always vary from actual results, and the differences between assumed facts and actual results can be material, depending upon the circumstances. Where we express an expectation or belief as to future results, that expectation or belief is expressed in good faith and based on assumptions believed to have a reasonable basis. It cannot be assured, however, that the stated expectation or belief will occur or be achieved or accomplished. Accordingly, there can be no assurance that the prospective results are indicative of our future performance or that actual results will not differ materially from those presented in the prospective financial information. Inclusion of the prospective financial information in this prospectus should not be regarded as a representation by any person that the results contained in the prospective financial information will be achieved.

We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of the above, the statement that we believe that we will have sufficient available cash to allow us to pay the forecasted quarterly distributions on all of our outstanding common units for the twelve months ending June 30, 2013 and the three months ending September 30, 2013 should not be regarded as a representation by us or the underwriters or any other person that we will make such distributions. Therefore, you are cautioned not to place undue reliance on this information.

The following table shows how we calculate estimated available cash for the twelve months ending June 30, 2013 and for the three months ending September 30, 2013. The assumptions that we believe are relevant to particular line items in the table below are explained in the corresponding footnotes and in “—Assumptions and Considerations.”


	For the Three Months Ending												For the Twelve Months Ending June 30, 2013			For the Three Months Ending September 30, 2013
	September 30, 2012			December 31, 2012			March 31, 2013			June 30, 2013			For the Twelve Months Ending June 30, 2013			For the Three Months Ending September 30, 2013
	(dollars in millions except per barrel/gallon data)
Operating Data:
Refinery segment data:
Refinery feedstocks (bpd):
Light and intermediate crude oil		59,000			59,000			59,000			39,550			54,151			59,000
Heavy crude oil		15,000			15,000			15,000			10,055			13,767			15,000
Other feedstocks / blendstocks		716			3,034			4,383			593			2,174			885

Total throughput		74,716			77,034			78,383			50,198			70,092			74,885
Refinery product yields (bpd):
Gasoline		37,543			40,162			41,493			25,166			36,091			37,543
Distillates		26,880			26,850			26,834			18,018			24,652			26,880
Asphalt		7,970			7,831			7,760			5,343			7,228			7,970
Other		3,047			3,007			2,989			2,184			2,808			3,047

Total production		75,440			77,850			79,076			50,711			70,779			75,440

Refinery gross product margin per barrel of throughput	$	22.64		$	19.14		$	17.21		$	18.55		$	19.44		$	19.17
Forecasted SPP Refinery 3:2:1 crack spread (per barrel)	$	22.01		$	18.18		$	16.45		$	17.41		$	18.51		$	17.78
Forecasted Group 3 3:2:1 crack spread (per barrel)	$	20.13		$	16.29		$	14.56		$	15.52		$	16.63		$	15.90
Forecasted WTI (per barrel)	$	108.75		$	110.25		$	113.25		$	114.75		$	111.75		$	115.75
Retail segment data:
Company operated stores:
Gallons sold (in millions)		85			82			76			82			325			85
Retail fuel margin ($/gallon)	$	0.17		$	0.17		$	0.18		$	0.17		$	0.17		$	0.17
Statement of operations data:
Total revenue	$	1,151.2		$	1,161.3		$	1,167.0		$	830.3		$	4,309.8		$	1,193.9
Cost, expenses and other:
Cost of sales		949.0			982.1			1,007.1			701.7			3,639.9			1,015.3
Direct operating expenses		67.0			66.9			66.8			60.6			261.3			67.0
Turnaround and related expenses		5.4			2.7			33.8			16.3			58.2			–
Depreciation & amortization		8.0			8.0			8.8			8.8			33.6			8.8
Selling, general & administrative expenses		19.9			19.8			19.6			19.8			79.1			19.8
Other income, net		(3.0	)		(3.0	)		(3.1	)		(3.0	)		(12.1	)		(3.0	)

Operating income		104.9			84.8			34.0			26.1			249.8			86.0
Realized (loss) gain from derivative activities		1.2			0.9			(3.3	)		(4.6	)		(5.8	)		(3.4	)
Unrealized gain (loss) from derivative activities		(1.2	)		(0.9	)		3.3			4.6			5.8			3.4
Interest expense		(9.0	)		(8.9	)		(9.0	)		(8.9	)		(35.8	)		(8.9	)

Earnings before income taxes		95.9			75.9			25.0			17.2			214.0			77.1
Income tax provision		(1.7	)		(0.9	)		(0.6	)		(1.6	)		(4.8	)		(1.7	)

Net earnings	$	94.2		$	75.0		$	24.4		$	15.6		$	209.2		$	75.4


	For the Three Months Ending												For the Twelve Months Ending June 30, 2013			For the Three Months Ending September 30, 2013
	September 30, 2012			December 31, 2012			March 31, 2013			June 30, 2013			For the Twelve Months Ending June 30, 2013			For the Three Months Ending September 30, 2013
	(dollars in millions except per unit data)
Net earnings	$	94.2		$	75.0		$	24.4		$	15.6		$	209.2		$	75.4

Adjustments to reconcile net earnings to Adjusted EBITDA:
Interest expense		9.0			8.9			9.0			8.9			35.8			8.9
Depreciation & amortization		8.0			8.0			8.8			8.8			33.6			8.8
Income tax provision		1.7			0.9			0.6			1.6			4.8			1.7

EBITDA subtotal	$	112.9		$	92.8		$	42.8		$	34.9		$	283.4		$	94.8

Minnesota Pipeline proportionate EBITDA		2.8			2.8			2.8			2.9			11.3			2.8
Turnaround and related expenses		5.4			2.7			33.8			16.3			58.2			–
Stock based compensation		0.6			0.6			0.6			0.6			2.4			0.6
Unrealized gains from derivative activities		1.2			0.9			(3.3	)		(4.6	)		(5.8	)		(3.4	)
Realized losses from derivative activities		(1.2	)		(0.9	)		3.3			4.6			5.8			3.4

Adjusted EBITDA(a)	$	121.7		$	98.9		$	80.0		$	54.7		$	355.3		$	98.2

Adjustments to reconcile Adjusted EBITDA to available cash:
Less:
Cash interest expense		8.0			7.8			7.8			7.8			31.4			7.9
Income tax provision		1.7			0.9			0.6			1.6			4.8			1.7
Debt service related to early retirement of derivatives(b)		–			2.3			19.1			9.6			31.0			9.6
Minnesota Pipeline proportionate EBITDA		2.8			2.8			2.8			2.9			11.3			2.8
Actual turnaround and related expenses		5.4			2.7			33.8			16.3			58.2			–
Maintenance capital expenditures		11.7			7.9			4.4			8.6			32.6			11.7
Turnaround and related expenses reserve		4.5			4.5			4.5			4.5			18.0			4.5
Realized losses from derivative activities		(1.2	)		(0.9	)		3.3			4.6			5.8			3.4
Plus:
Use of cash reserves or borrowings to fund actual turnaround and related expenses		5.4			2.7			33.8			16.3			58.2			–

Available cash	$	94.2		$	73.6		$	37.5		$	15.1		$	220.4		$	56.6

Actual and implied cash distributions based on available cash(c):
Available cash per unit
Cash distributions to common unitholders
Available cash attributable to PIK units(d)
Common units outstanding as of the distribution record date for the period presented
PIK units outstanding as of the distribution record date for period presented

Sensitivity Analysis:
Changes in available cash if:
$1/bbl increase in Group 3 3:2:1 crack spread	$	5.9		$	6.1		$	6.1		$	3.9		$	22.0		$	5.9
$1/bbl increase in crude oil differential		6.8			6.8			6.7			4.5			24.8			6.8
1,000 bpd increase in throughput		2.0			2.2			2.1			1.1			7.4			1.7
Indenture:
Restricted payments basket	$			$			$			$			$			$
Fixed charge coverage ratio		6.5x			7.1x			6.7x			6.7x			6.7x			5.7x
Revolving credit facility:
Fixed charge coverage ratio		6.6x			7.6x			8.9x			9.5x			9.5x			8.7x

(a)	For a definition of Adjusted EBITDA, see “Prospectus Summary—Summary Historical Condensed Consolidated Financial and Other Data.”

(b)	Represents payments for realized losses on early extinguishment of derivative contracts. These realized losses were incurred during the first quarter of 2012 and we entered into deferred payment terms with the counterparty.

(c)

Based on common units and PIK units outstanding as of July 1, 2012. For each distribution, the number of outstanding units is increased to reflect the additional PIK units issued to the holders of PIK units in respect of the prior quarter’s distribution, assuming a constant price per common unit of $ (the mid-point of the range set forth on the cover page of this prospectus).

(d)	Available cash attributable to PIK units represents the amount of cash that would have been distributed to holders of PIK units if such units were entitled to receive their distributions in cash during the forecast period.

Assumptions and Considerations

General

The accompanying financial forecast and specific significant forecast assumptions assume that the IPO Transactions had occurred as of July 1, 2012.

Our next major turnaround is scheduled for April 2013. The refinery is expected to be shut down during the month of April 2013 to complete the turnaround. Therefore, we have included a financial forecast for the three months ending September 30, 2013 to provide an additional quarterly estimate of available cash following completion of the planned turnaround. Our assumptions and considerations for the three months ending September 30, 2013 are materially consistent with our assumptions and considerations described below with respect to the twelve months ending June 30, 2013.

Utilization

For the twelve months ending June 30, 2013, we estimate that our refinery will operate at an average throughput of 67,900 barrels per day of crude oil on an annual basis after making an allowance for downtime associated with the major turnaround on the refinery anticipated in 2013. We have assumed that the refinery is shut down for the month of April 2013. For more information on our planned turnaround, see “—Turnaround and Related Expenses” and “—Turnaround and Related Expenses Reserve.” Our refinery has a capacity of approximately 74,000 barrels per calendar day and 84,500 barrels per stream day of crude oil. For the year ended December 31, 2011 and the year ended March 31, 2012 the St. Paul Park refinery operated at an average throughput of 77,452 barrels per day and 76,188 barrels per day, respectively.

Revenue

We project revenue of $4.3 billion over the twelve months ending June 30, 2013. During each of the year ended March 31, 2012 and the year ended December 31, 2011, we generated revenue of $4.3 billion.

Refining Segment

We forecast revenue from our refining segment of approximately $3.7 billion, of which approximately $992 million relates to intercompany sales to our SuperAmerica owned and operated convenience stores. Revenue from our refining segment for the year ended December 31, 2011 and the year ended March 31, 2012 was approximately $3.8 billion and $3.9 billion, respectively, of which approximately $1.0 billion and $1.0 billion, respectively, related to intercompany sales to our SuperAmerica owned and operated convenience stores.

Group 3 3:2:1 Crack Spread. Our estimates for gasoline and distillate prices are based on the PADD II Group 3 3:2:1 crack spread, which in turn is derived from Group 3 benchmark pricing for gasoline and distillate and WTI benchmark pricing for crude oil. The Group 3 3:2:1 crack spread is a proxy for the per barrel margin that a sweet crude oil refinery would earn assuming it produced and sold at Group 3 prices the benchmark production of two barrels of gasoline and one barrel of ultra low sulfur diesel for every three barrels of WTI crude oil input. We forecast a Group 3 3:2:1 crack spread of $16.63 per barrel for the twelve months ending June 30, 2013. The NYMEX 3:2:1 forward crack spread over the same period, as of April 30, 2012, was $19.94 per barrel.

Gasoline. We estimate revenue from gasoline sales based on forecast future product prices multiplied by the number of barrels of gasoline we estimate that we will produce and sell during the twelve months ending June 30, 2013. We forecast that we will sell approximately 14.8 million barrels of gasoline at a weighted average price of $127.32 per barrel during the twelve months ending June 30, 2013. Forecast future product prices are estimated assuming that the purchaser will pay all shipping costs. We project the weighted average selling price of gasoline based on projected estimates of WTI and the projected Group 3 gasoline benchmark price differential to WTI. We assumed a weighted

average gasoline price premium to WTI of $15.83 per barrel. As an element of this price premium, we have assumed a favorable basis differential of $1.95 per barrel at the St. Paul Park refinery as compared to the Group 3 benchmark pricing. This is comparable to the average Group 3 gasoline benchmark basis differential the refinery has realized based on historical data going back further than five years. The NYMEX RBOB forward price differential to WTI over the twelve months ending June 30, 2013, as of April 30, 2012, was $16.04 per barrel. Based on these assumptions, we forecast our net gasoline revenues for the twelve months ending June 30, 2013 to be approximately $1.9 billion, of which approximately $913 million relates to intercompany sales to our SuperAmerica owned and operated convenience stores. For the year ended December 31, 2011, we sold approximately 16.0 million barrels of gasoline at a weighted average price of $119.36 per barrel and realized net gasoline revenues of approximately $1.9 billion, of which approximately $965 million was to SuperAmerica. For the year ended March 31, 2012, we sold approximately 16.0 million barrels of gasoline at a weighted average price of $120.63 per barrel and realized net gasoline revenues of approximately $1.9 billion, of which approximately $960 million was to SuperAmerica.

Distillate. We estimate revenue from distillate sales based on forecast future product prices multiplied by the number of barrels of distillate we estimate that we will produce and sell during the twelve months ending June 30, 2013. Forecast future product prices are estimated assuming that the purchaser will pay all shipping costs. We forecast that we will sell approximately 9.2 million barrels of distillate at a weighted average price of $135.49 per barrel during the twelve months ending June 30, 2013. We project the weighted average selling price of distillate based on projected estimates of WTI and the projected Group 3 distillate benchmark price differential to WTI. We assumed a weighted average distillate price premium to WTI of $24.02 per barrel. As an element of this price premium, we have assumed a favorable basis differential of $1.76 per barrel at the St. Paul Park refinery as compared to the Group 3 benchmark pricing. This is comparable to the average Group 3 distillate benchmark basis differential the refinery has realized based on historical data going back further than five years. The NYMEX U.S. Gulf Coast ultra low sulfur diesel forward price differential to WTI over the twelve months ending June 30, 2013, as of April 30, 2012, was $27.75. Based on these assumptions, we forecast our net distillate revenues for the twelve months ending June 30, 2013 to be approximately $1.2 billion, of which approximately $79 million relates to intercompany sales to our SuperAmerica owned and operated convenience stores. For the year ended December 31, 2011, we sold approximately 9.1 million barrels of distillate at a weighted average price of $129.91 per barrel and realized net distillate revenues of approximately $1.2 billion. For the year ended March 31, 2012, we sold approximately 9.2 million barrels of distillate at a weighted average price of $132.44 per barrel and realized net distillate revenues of approximately $1.2 billion.

Asphalt. We estimate asphalt revenue based on forecast future product prices multiplied by the number of barrels of asphalt we estimate that we will produce and sell during the twelve months ending June 30, 2013. Forecast future product prices are estimated assuming that the purchaser will pay all shipping costs. We forecast that we will sell approximately 2.6 million barrels of asphalt at a weighted average price of $75.56 per barrel during the twelve months ending June 30, 2013. We have assumed sales to our customers at a weighted average discount of $35.89 per barrel to the applicable WTI price over the twelve months ending June 30, 2013. The $35.89 per barrel discount to WTI is calculated from a regression formula derived from monthly Western Canadian Select crude oil prices and St. Paul Park refinery realized asphalt prices based on historical data going back further than five years. The WTI benchmark price per barrel is forecast based on our view of future prices. Based on these assumptions, we forecast our net asphalt revenues for the twelve months ending June 30, 2013 to be approximately $200 million. For the year ended December 31, 2011, we sold approximately 3.9 million barrels of asphalt at a weighted average price of $66.90 per barrel and realized net asphalt revenues of approximately $259 million. For the year ended March 31, 2012, we sold approximately 3.8 million barrels of asphalt at a weighted average price of $70.72 per barrel and realized net asphalt revenues of approximately $267 million. The reduction in forecasted asphalt production from the year ended

December 31, 2011 and the year ended March 31, 2012 is due to our assumption that our refinery will run a lighter slate of crude oil to take advantage of favorable North Dakota light crude oil differentials and we will maximize production of distillate in the forecast period.

Other Products. The St. Paul Park refinery produces and sells propane, propylene, liquid sulfur and No. 6 fuel oil in addition to the products described above. We forecast that we will sell approximately 1.0 million barrels of these products at a weighted average price of $89.99 per barrel during the twelve months ending June 30, 2013. Based on these forecasted prices and the volumes, we forecast net revenues of other products to be approximately $91 million during the twelve months ending June 30, 2013. For the year ended December 31, 2011, we sold approximately 2.4 million barrels of other products at a weighted average price of $86.93 per barrel and realized net revenues of approximately $211 million. For the year ended March 31, 2012, we sold approximately 2.2 million barrels of other products at a weighted average price of $85.63 per barrel and realized net revenues of approximately $184 million. The reduction in forecasted production of other products from the year ended December 31, 2011 and the year ended March 31, 2012 is due to our assumption that our refinery will run a lighter slate of crude oil to take advantage of favorable North Dakota light crude oil differentials and we will maximize production of distillate in the forecast period.

Other Revenue. Other revenue consists of excise taxes, renewable identification number (RIN) credit sales and other miscellaneous revenues not specifically identified above. We forecast other revenue of approximately $270 million over the twelve months ending June 30, 2013, of which approximately $266 million are excise taxes. For the year ended December 31, 2011, we recognized other revenue of approximately $241 million, of which approximately $233 million were excise taxes. For the year ended March 31, 2012, we recognized other revenue of approximately $251 million, of which approximately $242 million were excise taxes.

Retail Segment

Revenue from our retail segment includes the sale of gasoline and diesel (“light products”) and merchandise, supplied to us both from our SuperMom’s Bakery and third party vendors, from our company owned and operated SuperAmerica stores, royalty fees from our franchised SuperAmerica stores, sales to third parties from our SuperMom’s Bakery and excise and sales taxes. We project revenue from our retail segment of approximately $1.6 billion for the twelve months ending June 30, 2013. We project that we will sell approximately 325 million barrels of light products in the retail segment at an average margin of $0.17 per gallon. We project approximately $346 million of merchandise revenue for the twelve months ending June 30, 2013. For the year ended December 31, 2011, we sold approximately 324 million barrels of light products at a weighted average margin of $0.21 per gallon. In addition, we sold approximately $340 million of merchandise revenue and realized total revenue from our retail segment of approximately $1.5 billion. For the year ended March 31, 2012, we sold approximately 320 million barrels of light products at a weighted average margin of $0.20 per gallon. In addition, we sold approximately $344 million of merchandise revenue and realized total revenue from our retail segment of approximately $1.5 billion.

Cost of Sales

We estimate that our cost of sales for the twelve months ending June 30, 2013 will be approximately $3.6 billion, or approximately 84% of sales. Cost of sales for the year ended December 31, 2011 was approximately $3.5 billion, or approximately 82% of sales. Cost of sales for the year ended March 31, 2012 was approximately $3.6 billion, or approximately 82% of sales.

Refining Segment

Cost of sales for our refining segment includes the purchased raw material costs for crude oil, natural gasoline, normal butane, isobutane, ethanol, biodiesel and other costs. Our feedstock and raw material costs consist of blending components for the finished products production process, which are driven primarily by commodity prices and volumes. We assume that our product yield will be approximately 101.0% over the twelve months ending June 30, 2013. For the year ended December 31, 2011, our product yield was 101.1%. For the year ended March 31, 2012, our product yield was 101.3%.

Crude Oil. We estimate that we will purchase approximately 24.8 million barrels of crude oil for the twelve months ending June 30, 2013. We estimate crude oil costs of approximately $2.7 billion and that our realized crude oil cost will be $107.86 per barrel for the twelve months ending June 30, 2013. We forecast that the St. Paul Park refinery will realize an average crude oil price discount of $3.61 per barrel to the benchmark WTI price. Our crude oil discount is based on our projection of the weighted average price of our benchmark crude oils’ discount to WTI. We believe the St. Paul Park refinery will continue to realize favorable crude differentials to WTI. We believe these favorable differentials will continue due to the continued logistical bottlenecks in the U.S. Gulf Coast for sweet crude, and north of Cushing, Oklahoma, for Canadian heavy crude oil. We believe these bottlenecks will cause the favorable crude oil price differentials off WTI for the crude oils processed at our refinery to continue. Our average crude oil price discount relative to WTI realized for the seven years ended December 31, 2011 was $2.25 per barrel. For the year ended December 31, 2011, we purchased approximately 28.3 million barrels of crude oil at a weighted average price of $94.69 per barrel for a total crude oil cost of approximately $2.7 billion. For the year ended March 31, 2012, we purchased approximately 27.9 million barrels of crude oil at a weighted average price of $97.22 per barrel for a total crude oil cost of approximately $2.7 billion.

Feedstocks and Blendstocks. Cost of sales also includes the cost of natural gasoline, normal butane, isobutane, ethanol and biodiesel, among others, that we blend into our gasoline and distillate finished products, excise taxes and transportation/terminal charges. We forecast these elements of cost of sales to be approximately $529 million over the twelve months ending June 30, 2013, of which approximately $266 million is excise taxes. For the year ended December 31, 2011, these elements of cost of sales were approximately $527 million, of which approximately $233 million was excise taxes. For the year March 31, 2012, these elements of cost of sales were approximately $546 million, of which approximately $242 million was excise taxes.

Retail Segment

Cost of sales from our retail segment includes the cost of gasoline and diesel products purchased from our refining segment sold at our company owned and operated SuperAmerica stores, the cost of merchandise sold to third parties by our SuperMom’s Bakery and at our company owned and operated SuperAmerica stores and excise and sales taxes. We forecast cost of sales from our retail segment of approximately $1.4 billion for the twelve months ending June 30, 2013. For the year ended December 31, 2011, cost of sales from our retail segment was approximately $1.3 billion. For the year ended March 31, 2012, cost of sales from our retail segment was approximately $1.3 billion.

Direct Operating Expenses

Refining Segment

Direct operating expenses include all direct and indirect labor at the facility, materials, supplies, and other expenses associated with the operation and maintenance of the facility. We estimate that our

direct operating expenses for the twelve months ending June 30, 2013 will be approximately $129 million. Refining segment direct operating expenses for the year ended December 31, 2011 were $129 million. Refining segment direct operating expenses for the year ended March 31, 2012 were $128 million.

Retail Segment

Direct operating expenses include all direct and indirect labor at our retail stores and our SuperMom’s Bakery, rent expense, credit card fees and other costs of operating our SuperAmerica stores. We estimate that our direct operating expenses for the twelve months ending June 30, 2013 will be approximately $132 million. Retail segment direct operating expenses for the year ended December 31, 2011 were $131 million. Retail segment direct operating expenses for the year ended March 31, 2012 were $131 million.

Turnaround and Related Expenses

Turnaround and related expenses represent the costs of required major maintenance projects on the refinery processing units. We expect to perform our major turnaround during 2013. We plan to shut down the refinery during the month of April to complete the turnaround. Expected turnaround expense for the twelve months ending June 30, 2013 is approximately $58 million, of which approximately $50 million is attributed to the major turnaround in 2013. Turnaround and related expenses for the year ended December 31, 2011 were $23 million. Turnaround and related expenses for the year ended March 31, 2012 were $23 million. We intend to use cash reserves or borrowings under our revolving credit facility to fund actual turnaround and related expenses. See “—Turnaround and Related Expenses Reserve.”

Depreciation and Amortization Expense

We estimate the depreciation and amortization expense for the twelve months ending June 30, 2013 to be approximately $34 million, of which approximately $8 million is the depreciation of assets in our retail segment. Depreciation and amortization expense for the year ended December 31, 2011 was approximately $30 million. Depreciation and amortization expense for the twelve months ended March 31, 2012 was approximately $31 million. The increase in forecasted depreciation expense from the year ended December 31, 2011 and the year ended March 31, 2012 is due to the incremental depreciation expense on capital expenditures made during the six months ending June 30, 2012 and during the forecast period.

Selling, General and Administrative Expenses

Selling, general and administrative expenses include salary and benefits costs for executive management, stock based compensation, accounting and information technology personnel, legal, audit, tax and other professional service costs. We estimate that our selling, general and administrative expense will be approximately $77 million for the twelve months ending June 30, 2013, of which approximately $14 million is attributed to our retail segment and approximately $48 million is related to our corporate infrastructure. Our selling, general and administrative expense estimate includes approximately $3.5 million of incremental expenses that we expect to incur as a public traded partnership. Selling, general and administrative expenses for the year ended December 31, 2011 were approximately $91 million. Selling, general and administrative expenses for the year ended March 31, 2012 were approximately $93 million. The forecasted net reduction in selling, general and administrative expense is due to incremental costs incurred during the year ended December 31, 2011 as we developed our standalone infrastructure while we also paid Marathon for transition services.

Realized Losses from Derivative Activities

As of the time of this offering, approximately 50% of our remaining 2012 production is hedged and 20% of our 2013 production is hedged. For the twelve months ending June 30, 2013, we estimate losses of approximately $6 million will be realized on these derivative instruments.

In addition, during the first quarter of 2012, we selectively bought back some of our 2012 hedges, for which we realized losses of approximately $45 million. Payment of these realized losses was deferred and will be paid to our counterparties throughout 2012 and 2013. These payments will decrease our available cash for the twelve months ending June 30, 2013.

During the second quarter of 2012, we reset the price of our remaining derivative contracts for the period of July 2012 through December 2012 and recognized a loss of $92 million. We plan to use a portion of the net proceeds of this offering to settle this obligation. If this offering is not completed the loss from resetting the price of our derivative contracts will be paid to the counterparty on the same monthly schedule as the original contracts were scheduled to settle.

Interest Expense

Interest expense relates primarily to interest incurred on our senior secured notes as well as commitment fees and interest on our revolving credit facility and the amortization of deferred financing costs. We expect to use a portion of the net proceeds from this offering to redeem 10% of our senior secured notes at 103% of par value, or $30 million. We do not expect to draw on our revolving credit facility during the twelve months ending June 30, 2013. We expect to incur approximately $36 million in net interest expense during the twelve months ending June 30, 2013, of which approximately $4 million is non-cash interest expense attributable to the amortization of financing costs on our senior secured debt. Interest expense for the year ended December 31, 2011 was approximately $42 million. Interest expense for the twelve months ended March 31, 2012 was approximately $43 million.

Other (Income) Expense, Net

Included in other income are the dividends and equity income related to our 17% interests in the Minnesota Pipe Line Company, LLC and MPL Investments, Inc. For the twelve months ending June 30, 2013, we estimate distributions of net income to us from these investments of approximately $12 million. For the year ended December 31, 2011 and the twelve months ended March 31, 2012, we received income distributions from these interests of approximately $9 million and $10 million, respectively.

Income Tax Expense

We estimate that we will pay approximately $5 million in federal and state income tax during the twelve months ending June 30, 2013, all of which is attributable to our retail segment. We estimate that we will pay no federal income tax for our refining segment during the twelve months ending June 30, 2013.

Maintenance Capital Expenditures

We estimate maintenance capital expenditures over the forecast period of approximately $33 million, of which approximately $4 million is attributed to the retail segment. Capital expenditures for the year ended December 31, 2011 were approximately $46 million, of which approximately $9 million is attributed to the retail segment and $3 million were corporate related. Capital expenditures for the twelve months ended March 31, 2012 were approximately $45 million, of which approximately $9 million is attributed to the retail segment and $2 million were corporate related.

Turnaround and Related Expenses Reserve

In advance of scheduled turnarounds at our refinery, the board of directors of our general partner intends to elect to reserve amounts to fund expenditures associated with such scheduled turnarounds. Such a decision by the board of directors may have an adverse impact on the available cash in the quarter(s) in which the reserves are withheld and a corresponding mitigating impact on the future quarter(s) in which the reserves are utilized.

We estimate total turnaround expense at St. Paul Park refinery of approximately $110 million over a six year turnaround cycle. Therefore, we estimate reserving approximately $18 million of available cash for turnaround expense over the forecast period. Expected turnaround expense for the twelve months ending June 30, 2013 is approximately $58 million, of which approximately $50 million is attributed to the major turnaround scheduled for April 2013.

Regulatory, Industry and Economic Factors

Our forecast for the twelve months ending June 30, 2013, is based on the following assumptions related to regulatory, industry and economic factors:

No material nonperformance or credit-related defaults by suppliers, customer or vendors;

No new regulation or interpretation of existing regulations that, in either case, would be materially adverse to our business;

No material accidents, weather-related incidents, floods, unplanned turnarounds or other downtime or similar unanticipated events that would reduce our capacity utilization below 91.8%;

No material adverse change in the market in which we operate resulting from reduced demand for gasoline, distillate, asphalt or our other products;

No material decreases in the prices we receive for our products; and

No material changes to market or overall economic conditions.

Actual conditions may differ materially from those anticipated in this section as a result of a number of factors, including, but not limited to, those set forth under “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.”

Compliance with Debt Covenants

Our ability to make distributions could be affected if we do not remain in compliance with the covenants in the indenture governing our senior secured notes and our revolving credit facility. We have assumed we will remain in compliance with such covenants.

Subject to certain exceptions, the restricted payments covenant under the indenture governing our senior secured notes restricts us from making cash distributions unless our fixed charge coverage ratio, as defined in the senior secured notes agreement, is at least 2.0 to 1.0 after giving pro forma effect to such distributions and such cash distributions do not exceed an amount equal to the aggregate net proceeds received by us (either as a result of capital contributions or from the sale of equity or certain debt securities) plus 50% of our consolidated net income (or less 100% of consolidated net loss), which is defined to exclude certain non-cash charges, such as net unrealized gains or losses from hedging obligations and impairment charges, accrued on a cumulative basis, plus certain other items.

The restricted payments covenant in our indenture could limit our ability to distribute all available cash in quarters in which our net earnings significantly exceed our forecast because only 50% of those

earnings will increase the restricted payment basket. Additionally, a net loss in any period in which we forecasted net earnings would disproportionately affect our ability to pay cash distributions because 100% of any consolidated net loss decreases the restricted payment basket while only 50% of any consolidated net income increases the basket.

Sensitivity Analysis

Our available cash is significantly impacted by volatility in prevailing crack spreads, crude oil prices and throughput at our refinery. In the paragraphs below, we discuss the impact of changes in these variables, while holding all other variables constant, on our ability to generate our estimated available cash for the twelve months ending June 30, 2013.

Crack Spread Volatility

Crack spreads measure the difference between the price received from the sale of light products and the price paid for crude oil. Holding all other variables constant, and excluding the impact of our current hedges, we expect a $1.00 change in the Group 3 3:2:1 crack spread per barrel would change our forecasted available cash by $22 million for the twelve months ending June 30, 2013.

Crude Oil Price Volatility

We are exposed to significant fluctuations in the price of crude oil. Holding all other variables constant, and excluding the impact of our current hedges, we expect a $1.00 change in the per barrel price of WTI would change our forecasted available cash by $25 million for the twelve months ending June 30, 2013.

Refinery Throughput

Holding all other variables constant, and excluding the impact of our current hedges, we expect a 1,000 bpd change in our refinery feedstock would change our forecasted available cash by $7.4 million for the twelve months ending June 30, 2013.

HOW WE MAKE DISTRIBUTIONS

General

Within 60 days after the end of each quarter, beginning with the quarter ending , 2012, we expect to make distributions, as determined by the board of directors of our general partner, to unitholders of record on the applicable record date.

Method of Distributions

The board of directors of our general partner will adopt a policy pursuant to which distributions for each quarter will be in an amount equal to the available cash we generate in such quarter. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. We do not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distributions or to otherwise reserve cash for distributions, and we do not intend to incur debt to pay quarterly distributions. Accordingly, there is no guarantee that we will pay any distribution on our units in any quarter. We do not have a legal obligation to pay distributions, and the amount of distributions paid under our policy and the decision to make any distribution will be determined by the board of directors of our general partner.

Partnership Interests

At the closing of this offering, we will have outstanding a non-economic general partner interest, common units and PIK units.

Common Units

At the closing of this offering, we will have common units outstanding. Each common unit will be entitled to receive cash distributions. Common units will not accrue arrearages.

PIK Units

At the closing of this offering, we will have PIK units outstanding. Northern Tier Holdings will initially own all of our PIK units. During the PIK period, the board of directors of our general partner will cause distributions in respect of our PIK units to be payable by Northern Tier Energy LP in additional PIK units to PIK unitholders of record on the applicable record date. The number of PIK units that will be distributed on a PIK unit in lieu of a quarterly cash distribution will equal a fraction, the numerator of which is the amount of the cash distribution paid on a common units and the denominator of which is the volume-weighted average price of a common unit for the 10 trading days immediately preceding the ex-dividend date for the associated distribution in respect of a common unit. This calculation is intended to provide the holders of PIK units with a number of PIK units equal in value on a per unit basis to the cash being simultaneously distributed to common unitholders. While the PIK units will not receive cash distributions during the PIK period, the distribution of additional PIK units in lieu of cash distributions may substantially increase the number of units outstanding and the amount of cash required on a quarterly and annual basis to pay distributions on all units. The effect of paying distributions of additional PIK units on PIK units, which we refer to as distributions in kind or distributions of equity, is as if we had paid cash distributions on those PIK units, and the holders of those PIK units had in turn recontributed that cash to us in exchange for additional PIK units. In order to make distributions in kind on these securities, we will have to have sufficient available cash to have paid them in cash and must pay a simultaneous cash distribution to the holders of our common units.

The PIK period will commence on the date of the closing of the offering and end on the date that is the earlier of (i) and (ii) the date by which we redeem, repurchase, defease or retire all of the

senior secured notes, or amend the indenture governing the senior secured notes in a manner that removes restrictions on our ability to to distribute all available cash to all unitholders. Immediately following the end of the PIK period, each outstanding PIK unit will be automatically converted into a common unit and entitled to receive any distributions in cash. The purpose of this feature is to support the payment of cash distributions to our common unitholders during periods in which we expect that certain of the provisions of the indenture may restrict the ability of Northern Tier Energy LLC, our operating subsidiary, to distribute cash to us and thus our ability to distribute all available cash in accordance with our distribution policy. The PIK units will not accrue arrearages.

The number of PIK units that may be distributed on PIK units in lieu of a quarterly cash distribution will equal a fraction, the numerator of which is the amount of the cash distribution paid on a common unit and the denominator of which is the volume-weighted average price of a common unit for the 10 trading days immediately preceding the ex-dividend date for the associated distribution in respect of the common units.

General Partner Interest

Our general partner owns a non-economic general partner interest in us and thus will not be entitled to distributions that we make prior to any liquidation in respect of such interest. However, it may acquire common units and other equity interests in the future and would be entitled to receive pro rata distributions therefrom.

Adjustments to Capital Accounts upon Issuance of Additional Common Units

We will make adjustments to capital accounts upon the issuance of additional common units (including additional PIK units). In doing so, we will generally allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to our unitholders prior to such issuance on a pro rata basis so that after such issuance the capital account balances attributable to all common units are equal.

SELECTED HISTORICAL CONDENSED CONSOLIDATED FINANCIAL DATA

The following tables present certain selected historical condensed consolidated financial data. The combined financial statements as of and for the years ended December 31, 2007, 2008 and 2009 and the eleven months ended November 30, 2010 represent a carve-out financial statement presentation of several operating units of Marathon, which we refer to as “Predecessor.” For more information on the carve-out presentation, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Predecessor Carve-Out Financial Statements” and our financial statements and the notes thereto included elsewhere in this prospectus. The historical financial data for periods prior to December 1, 2010 presented below do not reflect the consummation of the Marathon Acquisition and the transactions related thereto or our capital structure following the Marathon Acquisition and the transactions related thereto. Northern Tier Energy LLC was formed on June 23, 2010 and entered into certain agreements with Marathon on October 6, 2010 to acquire the Marathon Assets. At the closing of the Marathon Acquisition on December 1, 2010, Northern Tier Energy LLC acquired the Marathon Assets. Northern Tier Energy LLC had no operating activities between its June 23, 2010 inception date and the closing date of the Marathon Acquisition, although it incurred various transaction and formation costs which have been included in the 2010 Successor Period.

The selected historical financial data as of March 31, 2012 and for the three months ended March 31, 2011 and 2012 are derived from unaudited financial statements and the notes thereto included elsewhere in this prospectus. The selected historical financial data as of December 31, 2010 and 2011, and for the year ended December 31, 2009, the eleven months ended November 30, 2010, the 2010 Successor Period and the year ended December 31, 2011 are derived from audited financial statements and the notes thereto included elsewhere in this prospectus. The selected historical combined financial data as of December 31, 2007, 2008, 2009 and November 30, 2010 and for the years ended December 31, 2007 and 2008 are derived from audited financial statements and the notes thereto and the summary historical balance sheet data as of March 31, 2011 was derived from unaudited financial statements and the notes thereto not included in this prospectus.

The historical financial and other data presented below are not necessarily indicative of the results expected for any future period.

You should read these tables along with “Prospectus Summary—The IPO Transactions,” “Risk Factors,” “Use of Proceeds,” “Capitalization,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Predecessor Carve-Out Financial Statements,” “Business” and financial statements and the notes thereto, included elsewhere in this prospectus.


	Predecessor												Successor
	Year Ended December 31,									Eleven Months Ended November 30, 2010			June 23, 2010 (inception date) to December 31, 2010			Year Ended December 31, 2011			Three Months Ended March 31,
	Year Ended December 31,																		Three Months Ended March 31,
	2007			2008			2009												2011			2012
	(In millions)
Consolidated and Combined statements of operations data:
Total revenue	$	3,522.8		$	4,122.4		$	2,940.5		$	3,195.2		$	344.9		$	4,280.8		$	940.2		$	999.1
Costs and expenses:
Costs of sales		2,820.0			3,659.0			2,507.9			2,697.9			307.5			3,508.0			779.0			839.8
Direct operating expenses		249.0			252.7			238.3			227.0			21.4			260.3			61.9			60.7
Turnaround and related expenses		32.6			3.7			0.6			9.5			—			22.6			3.3			3.5
Depreciation and amortization		33.7			39.2			40.2			37.3			2.2			29.5			7.3			8.5
Selling, general and administrative expenses		61.7			67.7			64.7			59.6			6.4			90.7			18.4			20.3
Formation costs		—			—			—			—			3.6			7.4			2.5			—
Contingent consideration income		—			—			—			—			—			(55.8	)		(31.8	)		65.7
Other (income) expense, net		0.7			1.2			(1.1	)		(5.4	)		0.1			(4.5	)		(1.1	)		(2.1	)

Operating income		325.1			98.9			89.9			169.3			3.7			422.6			100.7			2.7
Realized losses from derivative activities		—			—			—			—			—			(310.3	)		(52.2	)		(52.9	)
Unrealized losses from derivative activities		—			—			—			(40.9	)		(27.1	)		(41.9	)		(262.9	)		(88.4	)
Loss on early extinguishment of derivatives		—			—			—			—			—			—			—			(44.6	)
Bargain purchase gain		—			—			—			—			51.4			—			—			—
Interest expense		0.2			(0.5	)		(0.4	)		(0.3	)		(3.2	)		(42.1	)		(10.0	)		(10.4	)

Earnings (loss) before income taxes		325.3			98.4			89.5			128.1			24.8			28.3			(224.4	)		(193.6	)
Income tax provision		(129.9	)		(39.8	)		(34.8	)		(67.1	)		—			—			(0.1	)		–

Net earnings (loss)	$	195.4		$	58.6		$	54.7		$	61.0		$	24.8		$	28.3		$	(224.5	)	$	(193.6	)

Consolidated and combined statements of cash flow data:
Net cash provided by (used in):
Operating activities	$	282.7		$	47.1		$	129.4		$	145.4		$	—		$	209.3		$	94.3		$	(54.8	)
Investing activities		(111.0	)		(84.6	)		(25.0	)		(29.3	)		(363.3	)		(156.3	)		(117.8	)		(4.6	)
Financing activities		(171.7	)		34.5			(103.9	)		(115.4	)		436.1			(2.3	)		—			—
Capital expenditures		(75.8	)		(45.0	)		(29.0	)		(29.8	)		(2.5	)		(45.9	)		(6.0	)		(5.4	)
Consolidated and combined balance sheets data (at period end):
Cash and cash equivalents	$	8.5		$	5.5		$	6.0		$	6.7		$	72.8		$	123.5		$	49.3		$	64.1
Total assets		737.3			708.2			710.1			717.8			930.6			998.8			924.1			962.7
Total long-term debt		—			—			—			—			314.5			301.9			314.5			301.9
Total liabilities		415.1			292.7			343.9			405.4			645.6			686.6			859.5			843.7
Total equity		322.2			415.5			366.2			312.4			285.0			312.2			64.6			119.0

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and related notes included elsewhere in this prospectus. The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of a number of factors, including those we discuss under “Risk Factors” elsewhere in this prospectus. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. See “Cautionary Note Regarding Forward-Looking Statements.”

Overview

We are an independent downstream energy company with refining, retail and pipeline operations that serve the PADD II region of the United States. We operate our assets in two business segments: the refining business and the retail business. For the three months ended March 31, 2012, we had total revenues of $1.0 billion, operating income of $2.7 million, a net loss of $193.6 million and Adjusted EBITDA of $81.5 million. For the year ended December 31, 2011, we had total revenues of $4.3 billion, operating income of $422.6 million, net earnings of $28.3 million and Adjusted EBITDA of $430.7 million. For a definition, and reconciliation, of Adjusted EBITDA to net (loss) earnings, see “Prospectus Summary—Summary Historical Condensed Consolidated Financial and Other Data.”

Refining Business

Our refining business primarily consists of a 74,000 bpd (84,500 barrels per stream day) refinery located in St. Paul Park, Minnesota. Our refinery has a Nelson complexity index of 11.5, which refers to the number, type and capacity of processing units at the refinery. We are one of only two refineries in Minnesota and one of four refineries in the Upper Great Plains area within the PADD II region. Our refinery’s complexity allows us to process a variety of light, heavy, sweet and sour crudes, many of which have historically priced at a discount to the NYMEX WTI price benchmark, meaning we can process lower cost crude oils into higher value refined products. The PADD II region covers the following states: Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, South Dakota, Ohio, Oklahoma, Tennessee and Wisconsin. Our strategic location allows us direct access, primarily via the Minnesota Pipeline, to sources of crude oil from Western Canada and North Dakota, as well as the ability to distribute our refined products throughout the midwestern United States. Our refinery produces a broad slate of refined products including gasoline, diesel, jet fuel and asphalt, which are then marketed to resellers and consumers primarily in the PADD II region. Approximately 83% and 79% of our total refinery production for the three months ended March 31, 2012 and the year ended December 31, 2011, respectively, comprised higher value, light refined products, including gasoline and distillates. Our refinery crude capacity utilization rates have ranged from approximately 80% to approximately 88% over the last five years.

We also own various storage and transportation assets, including a light products terminal, a heavy products terminal, storage tanks, rail loading/unloading facilities and a Mississippi river dock. Approximately 73% and 83% of our gasoline and diesel volumes for three months ended March 31, 2012 and the year ended December 31, 2011, respectively, were sold via our light products terminal located at the refinery to our company-operated and franchised SuperAmerica branded convenience stores, Marathon branded convenience stores and other resellers. We have a contract with Marathon to supply substantially all of the gasoline and diesel requirements for 90 independently owned and operated Marathon branded convenience stores.

Our refining business also includes our 17% interest in the Minnesota Pipe Line Company and MPL Investments, which owns and operates the Minnesota Pipeline, a 455,000 bpd crude oil pipeline system that transports crude oil (primarily from Western Canada and North Dakota) for approximately 300 miles from the Enbridge pipeline hub at Clearbrook, Minnesota to our refinery. The Minnesota Pipeline has historically transported the majority of the crude oil used and processed in our refinery.

Retail Business

As of March 31, 2012, our retail business operated 166 convenience stores under the SuperAmerica brand and also supported 67 franchised convenience stores, which are also operated under the SuperAmerica brand. These convenience stores are located primarily in Minnesota and Wisconsin and sell various grades of gasoline and diesel, tobacco products and immediately consumable items such as non-alcoholic beverages, beer, prepared food and a large variety of snacks and prepackaged items. Our refinery supplied substantially all of the gasoline and diesel sold in our company-operated and franchised convenience stores for the three months ended March 31, 2012 and the year ended December 31, 2011.

Outlook

Transportation fuels demand in the Upper Great Plains of the PADD II region currently exceeds supply from local refineries. Therefore, demand is fulfilled by products that are imported into the region mostly via pipeline from other parts of the Midwest, the Rocky Mountains and the U.S. Gulf Coast. Overall refined product demand declined in 2008 as a result of prevailing economic conditions and began to improve in the first quarter of 2010. While there continues to be a significant global macroeconomic risk that may affect the pace of growth in the United States, we have experienced improved overall product demand in our geographic area of operations relative to prior years.

Our operating performance has benefited from the widening of the price relationship between the traditional crude oil pricing benchmark, NYMEX WTI, and the international waterborne crude oil pricing benchmark, Brent. We purchase crude oil which is priced based off NYMEX WTI. Refined products prices are set by global markets and are typically priced off Brent. Therefore, we have enjoyed a benefit during the year ended December 31, 2011 and the first quarter of 2012 from the overall widening of the price differential between our cost of crude oil and the price of the products we sell. The widening differential may have been attributable to several factors, including geopolitical events in the Middle East, the suspension of crude oil exports from Libya, new U.N. sanctions on Iran’s oil exports, and limited pipeline and other infrastructure to transport crude oil from Cushing, Oklahoma, where NYMEX WTI is settled, to alternative markets. More recently, during the beginning of the second quarter of 2012, the discount to which NYMEX WTI trades relative to Brent has narrowed due to a number of factors, including recently announced changes in the pipeline infrastructure serving Cushing, Oklahoma. The narrowing of this margin will affect the prices at which we sell our refined products relative to our cost of crude oil and can therefore cause a reduction in our refining margins. Please see “Risk Factors—Risks Primarily Related to Our Refining Business—Our results of operations are affected by crude oil differentials, which may fluctuate substantially.”

Predecessor Carve-Out Financial Statements

As described in the financial statements and notes thereto included elsewhere in this prospectus, this prospectus includes financial statements for the year ended December 31, 2009, and the eleven months ended November 30, 2010 for the St. Paul Park Refinery and Retail Marketing Business,

representing a carve-out financial statement presentation of several operating units of Marathon (the “Predecessor Financial Statements”). All significant intercompany accounts and transactions have been eliminated in the Predecessor Financial Statements.

The Predecessor Financial Statements were prepared to reflect the way we have operated our business subsequent to the Marathon Acquisition, which is in two segments: the refining segment and the retail segment. Except for certain assets that were not acquired (e.g., cash other than in-store cash at our convenience stores, receivables and assets sold to third parties pursuant to a sale-leaseback arrangement between us, Speedway SuperAmerica LLC, an affiliate of Marathon, and Realty Income, a third party equity real estate investment trust, and a crude oil supply and logistics purchase agreement with JPM CCC) and certain liabilities (e.g., accounts payable, payroll and benefits payable and deferred taxes) that were not assumed in connection with the Marathon Acquisition, the Predecessor Financial Statements represent the Marathon Assets. In addition, the Predecessor Financial Statements include allocations of selling, general and administrative costs and other overhead costs of Marathon Oil and its affiliates that are attributable to the operations of the Marathon Assets. We believe the assumptions, allocations and methodologies underlying the Predecessor Financial Statements are reasonable. However, the Predecessor Financial Statements do not include all of the actual expenses that would have been incurred had the Marathon Assets been operated on a standalone basis during the periods presented and do not reflect the Marathon Assets’ combined results of operations, financial position and cash flows had it been operated on a standalone basis during the periods presented.

Comparability of Historical Results

Marathon Acquisition and Related Transactions

We commenced operations in December 2010 through the acquisition of our St. Paul Park, Minnesota refinery, a 17% interest in the Minnesota Pipe Line Company and in MPL Investments, our convenience stores and related assets from Marathon for $554 million, which included cash and the issuance to Marathon of $80 million of a noncontrolling preferred membership interest in our parent, Northern Tier Holdings.

Prior to the Marathon Acquisition, the business was operated as several operating units of Marathon, and participated in Marathon’s centralized cash management programs. All cash receipts were remitted to and all cash disbursements were funded by Marathon. Following the Marathon Acquisition, we operate as a standalone company, and our results of operations may not be comparable to the historical results of operations for the periods presented, primarily for the reasons described below:

In connection with the Marathon Acquisition, we entered into a contingent consideration arrangement with Marathon. This arrangement would have required earn-out payments if our annual consolidated EBITDA, adjusted for certain agreed items (the “Agreement Adjusted EBITDA”), exceeded $165 million during any year in each of the eight years following the Marathon Acquisition. Specifically, we would have been required to pay Marathon 40% of the amount by which the Agreement Adjusted EBITDA exceeded $165 million, subject to certain reductions, in any year in the eight years following the Marathon Acquisition. Total payments to Marathon under this agreement could not have exceeded $125 million over the eight years following the Marathon Acquisition.

Conversely, Marathon would have been required to make margin support payments to us of up to $30 million per year if the Agreement Adjusted EBITDA was less than $145 million, subject to certain reductions, in either of the twelve-month periods ending November 30, 2011 and 2012. Any such payments made by Marathon would have increased the maximum amount that

we would have been required to pay Marathon over the earn-out period as described above. For the year ended December 31, 2011, we were not required to make any earn-out payments under the agreements. As of December 31, 2011, we recorded a receivable of $30 million relating to the margin support component of the contingent consideration arrangement for the twelve months ended November 30, 2011. Marathon has disputed approximately $12 million of this amount. In connection with the resolution of this dispute, we entered into a settlement agreement with Marathon on May 4, 2012. Under the terms of this settlement agreement, Marathon will receive $40 million of the net proceeds from this offering, and Northern Tier Holdings will redeem Marathon’s existing preferred interest with a portion of the net proceeds from this offering and issue Marathon a new $45 million preferred interest in Northern Tier Holdings in consideration for relinquishing all claims with respect to earn-out payments under the contingent consideration agreement. We have also agreed, pursuant to the settlement agreement, to relinquish all claims to margin support payments under the contingent consideration agreement. The settlement agreement is contingent upon the consummation of this offering.

At March 31, 2012, in addition to the $30 million receivable discussed above, we had recorded at fair value, an asset of $2.8 million related to the margin support component for the twelve months ended November 30, 2012 and a liability of $79.2 million related to the earn-out component. Upon the consummation of this offering, we will reverse any amounts recorded for the margin support and earn-out arrangements and record a liability of $85 million.

In connection with the Marathon Acquisition, certain additional transactions were consummated, and we entered into certain agreements with respect to our operations, including the following:

•

Senior Secured Notes. We issued $290 million of the 10.5% senior secured notes due December 1, 2017. We pay interest on the senior secured notes on June 1 and December 1 of each year. The net proceeds from the sale of the senior secured notes were used to fund part of the Marathon Acquisition. See “Liquidity and Capital Resources—Description of Our Indebtedness—Senior Secured Notes.”

•

Asset-Based Revolving Credit Facility. We entered into a $300 million senior secured asset-based revolving credit facility, which is subject to a borrowing base. We did not draw on the revolving credit facility to fund the Marathon Acquisition, other than to the extent utilized through the issuance of letters of credit. The revolving credit facility is available through December 1, 2015. See “Liquidity and Capital Resources—Description of Our Indebtedness—Senior Secured Asset-Based Revolving Credit Facility.”

•

Sale-Leaseback Arrangement. Marathon sold certain real property interests, including the land underlying 135 of the SuperAmerica convenience stores associated with our retail business and SuperMom’s Bakery, to Realty Income, a third party equity real estate investment trust. In connection with the closing of the Marathon Acquisition, Realty Income leased those properties to us on a long-term basis.

•

Crude Oil Inventory Purchase Agreement. JPM CCC purchased substantially all of the crude oil inventory associated with operations of the refinery directly from Marathon pursuant to an inventory purchase agreement with Marathon.

•

Crude Oil Supply and Logistics Agreement. In December 2010, we entered into a crude oil supply and logistics agreement with JPM CCC, which agreement was amended and restated in March 2012. JPM CCC assists us in the purchase of the crude oil requirements of our refinery and provides transportation and other logistical services for delivery of the crude oil to our storage tanks at Cottage Grove, Minnesota, which are approximately two miles from our refinery. We pay the price of the crude oil plus certain

agreed fees and expenses. We believe this crude oil supply and logistics agreement significantly reduces our need to maintain crude oil inventories and allows us to take title to and price our crude oil at the refinery, as opposed to the crude oil origination point, reducing the time we are exposed to market fluctuations before the finished product output is sold. For more information, see “Business—Crude Oil Supply.”

•

Transition Services Agreement. Marathon agreed to provide us with administrative and support services pursuant to a transition services agreement, including finance and accounting, human resources and information systems services, as well as support services in connection with our transition from being a part of Marathon’s systems and infrastructure to having our own systems and infrastructure. Marathon is no longer providing any transition services under the agreement. For more information, see “Certain Relationships and Related Person Transactions—Transactions with Marathon.”

The Marathon Acquisition has been accounted for under the purchase method of accounting for business combinations which requires that the assets acquired and liabilities assumed be adjusted to their estimated fair value at the date of the acquisition. This treatment changed the accounting basis for the assets acquired and liabilities assumed from Marathon as of December 1, 2010.

In October 2010, at our request, Marathon initiated a crack spread derivative strategy to mitigate refining margin risk on a portion of the business’s 2011 and 2012 projected refinery production. In connection with the Marathon Acquisition, we assumed all corresponding rights and obligations for derivative instruments executed pursuant to this strategy. We incurred $97.5 million and $310.3 million of realized losses and $88.4 million and $41.9 million of unrealized losses for the three months ended March 31, 2012 and the year ended December 31, 2011, respectively, related to these derivative activities.

The IPO Transactions

Our results of operations for periods subsequent to the closing of this offering may not be comparable to our results of operations for periods prior to the closing of this offering as a result of certain aspects of this offering and the other IPO Transactions described in “Prospectus Summary—The IPO Transactions,” including the following:

We expect that our general and administrative expenses will increase as a result of this offering. Specifically, we will incur certain expenses relating to being a publicly traded partnership, including the Exchange Act reporting expenses; expenses associated with Sarbanes-Oxley Act compliance; expenses associated with the listing of the NYSE; independent auditors fees expenses associated with tax return and Schedule K-1 preparation and distribution; legal fees, investor relations expenses; transfer agent fees; director and officer liability insurance costs; and director compensation.

Northern Tier Energy LLC and its subsidiaries have historically not been subject to federal income and certain state income taxes. After consummation of this offering, Northern Tier Retail Holdings LLC, the subsidiary of Northern Tier Energy LLC through which we conduct our retail business, and Northern Tier Energy Holdings LLC will elect to be treated as corporations for federal income tax purposes, subjecting these subsidiaries to corporate-level tax. As a result of the election by Northern Tier Retail Holdings LLC and Northern Tier Energy Holdings LLC to be treated as corporations for federal income tax purposes, for periods following such election, our financial statements will include a tax provision on income attributable to these subsidiaries. On a pro forma basis after giving effect to such election, we would have recorded a tax benefit of approximately $0.2 million for the three months ended March 31, 2012 and a tax provision of approximately $5.7 million for the year ended December 31, 2011. In addition, we will record a

tax provision related to the recognition of deferred taxes equal to the tax effect of the difference between the book and tax basis of the assets of these subsidiaries and liabilities as of the effective date of the election. Assuming we had completed the conversion as of March 31, 2012, the amount of the deferred tax provision would have been approximately $ million.

In 2010, we entered into a management services agreement with ACON Management and TPG Management pursuant to which they provided us with ongoing management, advisory and consulting services in exchange for management fees. This management services agreement will terminate in connection with the closing of this offering. See “Certain Relationships and Related Person Transactions—Agreements with Affiliates of Our General Partner—Management Services Agreement.”

Major Influences on Results of Operations

Refining

Our earnings and cash flows from our refining business segment are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. Refining is primarily a margin-based business, and in order to increase profitability, it is important for the refinery to maximize the yields of high value finished products and to minimize the costs of feedstock and operating expenses. Feedstocks are petroleum products, such as crude oil and natural gas liquids that are processed and blended into refined products. The cost to acquire feedstocks and the price for which refined products are ultimately sold depend on several factors, many of which are beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined products, which depend on changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, availability of and access to transportation infrastructure, the availability of imports, the marketing of competitive fuel, and the extent of government regulation, among other factors.

Feedstock and refined product prices are also affected by other factors, such as product pipeline capacity, local market conditions and the operating levels of competing refineries. Crude oil costs and the prices of refined products have historically been subject to wide fluctuations. An expansion or upgrade of our competitors’ facilities, price volatility, international political and economic developments and other factors beyond our control are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a negative impact on product margins. Moreover, the refining industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving season and for home heating oil during the winter, primarily in the Northeast. In addition to current market conditions, there are long-term factors that may impact the demand for refined products. These factors include mandated renewable fuels standards, proposed climate change laws and regulations, and increased mileage standards for vehicles.

In order to assess our operating performance, we compare our refinery gross product margin against an industry refining margin benchmark. The industry refining margin benchmark we use is referred to as Group 3 3:2:1 crack spread, which is calculated by assuming that three barrels of benchmark light sweet crude oil is converted into two barrels of reformulated gasoline and one barrel of ultra low sulfur diesel. Because we calculate the benchmark refining margin using the market value of PADD II Group 3 conventional gasoline and ultra low -sulfur diesel against the market value of NYMEX WTI, we refer to the benchmark as the Group 3 3:2:1 crack spread. The Group 3 3:2:1 crack spread is expressed in dollars per barrel and is a proxy for the per barrel margin that a sweet crude oil refinery would earn assuming it produced and sold at PADD II Group 3 prices the benchmark production of gasoline and ultra low sulfur diesel.

Our direct operating expense structure is also important to our profitability. Major direct operating expenses include employee and contract labor, maintenance and energy. Our predominant variable direct operating cost is energy, which is comprised primarily of fuel and other utility services. The costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refinery and other operations have historically been volatile.

Consistent, safe and reliable operations at our refinery are key to our financial performance and results of operations. Unplanned downtime at our refinery may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. We seek to mitigate the financial impact of planned downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform needed maintenance, contractual commitments, feedstock logistics and other factors. Periodically, we have planned maintenance turnarounds at our refinery, which are expensed as incurred. The refinery generally undergoes a major facility turnaround every five to six years, and the last full plant turnaround was completed in 2007. The length of the turnaround is contingent upon the scope of work to be completed. A major turnaround of either of the two main refinery units (fluid catalytic cracking unit and alkylation unit) generally takes two to four weeks to complete, and is planned and accomplished in a manner that allows for reduced production during maintenance instead of a complete shutdown. We completed a partial turnaround in April 2011, principally to replace a catalyst in the distillate and gas oil hydrotreaters, and to conduct basic maintenance on the No. 1 crude unit. At the end of March 2012, we started a planned turnaround of the alkylation unit that was completed according to schedule in mid May 2012. The next major turnaround is scheduled for 2013.

Because petroleum feedstocks and products are essentially commodities, we have no control over the changing market. Therefore, the lower the target inventory we are able to maintain, the lesser is the impact of commodity price volatility on our petroleum product inventory position. Our inventory of crude oil and refined products is valued at the lower of cost or market value under the LIFO cost flow assumption. For periods in which the market price declines below our LIFO cost basis, we are subject to significant fluctuations in the recorded value of our inventory and related cost of products sold. Since 2009, we have experienced LIFO liquidations based upon permanent decreased levels in our inventories. These LIFO liquidations resulted in decreased cost of sales and increased income from operations of $1.7 million, $2.1 million, $2.1 million and $4.1 million for the year ended December 31, 2009, the eleven months ended November 30, 2010, the Successor Period ended December 31, 2010 and the year ended December 31, 2011, respectively. There were no such liquidations in the three months ended March 31, 2011 and 2012.

At the closing of the Marathon Acquisition, we entered into a crude oil supply and logistics agreement with JPM CCC pursuant to which JPM CCC assists us in the purchase of the crude oil requirements of our refinery and provides transportation and other logistical services for delivery of the crude oil to our storage tanks in Cottage Grove, Minnesota. In March 2012, we amended and restated the crude oil supply and logistics agreement with JPM CCC. We pay JPM CCC the price of the crude oil plus certain agreed fees and expenses. We believe this crude oil supply and logistics agreement significantly reduces our crude inventories and allows us to take title to and price our crude oil at the refinery, as opposed to the crude oil origination point, reducing the time we are exposed to market fluctuations before the finished product output is sold.

In addition, we may hedge a portion of our gasoline and distillate production with the purpose of ensuring we can meet our fixed cost obligations, service our outstanding debt and other liabilities and meet our capital expenditure obligations. We have entered into hedge agreements that govern all cash-settled commodity transactions that we enter into with J. Aron & Company and Macquarie Bank Limited for the purpose of managing our risk with respect to the crack spread created by the purchase of crude oil for future delivery and the sale of refined products, including gasoline, diesel, jet fuel and heating fuel,

for future delivery. As market conditions permit, we have the capacity to hedge our crack spread risk with respect to a portion of the refinery’s projected monthly production of some or all of these refined products. Consistent with that policy, as of March 31, 2012, we had hedged approximately 15 million barrels of future gasoline and diesel production, of which 10 million barrels related to 2012 production and the remainder to 2013 production. We intend to hedge significantly less than what we hedged at the time of the Marathon Acquisition on an ongoing basis. Consequently, we plan to increase our exposure to the gross refining margins that we would realize at our refinery on an unhedged basis over time.

During the first quarter of 2012, we settled contracts covering approximately 3 million barrels of our remaining 2012 gasoline and diesel production and recognized a loss of approximately $45 million. Our required payment of the majority of the loss from these settled contracts has been deferred until 2013. In addition, during the second quarter of 2012, we reset the price of our contracts for the period of July 2012 through December 2012 and recognized a loss of approximately $92 million. We plan to use a portion of the net proceeds of this offering to settle this obligation. If we do not complete this offering, the loss from resetting the price of our derivative contracts will be paid to the counterparty on the same monthly schedule as the original contracts were scheduled to settle.

Our refining business experiences seasonal effects. Demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. Decreased demand during the winter months can lower gasoline prices. As a result, our operating results of our refining business for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year.

Retail

Our earnings and cash flows from our retail business segment are primarily affected by the volumes and margins of gasoline and diesel sold, and by the sales and margins of merchandise sold at our convenience stores. Seasonal fluctuations in traffic also affect sales of motor fuels and merchandise in our convenience stores. As a result, the operating results of our retail segment are generally lower for the first quarter of the year. Weather conditions in our operating area also have a significant effect on our retail operating results. Customers are more likely to purchase higher profit margin items at our convenience stores, such as fast foods, fountain drinks and other beverages and more gasoline during the spring and summer months, thereby typically generating higher revenues and gross margins for us in these periods. Margins for transportation fuel sales are equal to the sales price (which includes the motor fuel taxes) less the delivered cost of the fuel and motor fuel taxes, and are measured on a cents per gallon basis. Fuel margins are impacted by local supply, demand and competition. Margins for retail merchandise sold are equal to retail merchandise sales less the delivered cost of the merchandise, net of any supplier discounts and inventory shrinkage, and are measured as a percentage of merchandise sales. Merchandise sales are impacted by convenience or location, branding and competition. Franchisees are required to pay us an initial license fee (generally, $10,000 for licensees located in Minnesota and Wisconsin and $2,000 for licensees located in South Dakota) and a royalty fee for all products and merchandise sold at the convenience store, including motor fuel and diesel. The initial term of the license is generally 10 years, which is renewable by the licensee for a renewal term of 10 years, subject to the licensee satisfying certain conditions. The license agreements also require that, if a franchise store is located within our distribution area, then the franchise store must purchase a high minimum percentage (often 85% to 100%) of its motor fuel supply, including gasoline and distillate, from us. However, if a franchise store is not located within our distribution area, then the franchise store is not required to purchase any portion of its motor fuel supply from us. As of March 31, 2012, 31 of the 67 existing franchise stores located within our distribution area and, thus, required to purchase a high minimum percentage of their motor fuel supply from us.

Results of Operations

We operate our business in two segments: the refining segment and the retail segment. Each of these segments is organized and managed based upon the nature of the products and services they offer. Through the refining segment, we operate the St. Paul Park, Minnesota, refinery, terminal and related assets, and through the retail segment, we operate 166 convenience stores primarily in Minnesota. The retail segment also includes the operations of SuperMom’s Bakery and SuperAmerica Franchising LLC, our wholly owned subsidiary (“SAF”), through which we conduct our franchising operations.

In this “Results of Operations” section, we first review our business on a combined and consolidated basis, and then separately review the results of operations of each of the refining segment and the retail segment. Detailed explanations of the period over period changes in our results of operations are contained in the discussion of individual segments. For partial year periods that do not have a corresponding period of the same duration, comparisons are made on a run rate basis comparing the partial period results with the prior year’s average monthly results for the corresponding period of time.

We refer to our financial statement line items in the explanation of our period over period changes in results of operations. Below are general definitions of what those line items include and represent.

Revenue. Revenue primarily includes the sale of refined products in our refining segment and sales of fuel and merchandise to retail consumers in our retail segment. All sales are recorded net of customer discounts and rebates and inclusive of federal and state excise taxes. Refining revenue includes intersegment sales of refined products to the retail segment. For purposes of presenting sales on a combined basis, such intersegment transactions are eliminated. Retail revenue primarily includes sales of fuel and merchandise to customers inclusive of related excise taxes and net of any applicable discounts. Also included in retail revenue is royalty income, revenues from car wash operations and SuperMom’s Bakery sales to third parties.

Cost of sales. Refining cost of sales primarily include costs of crude and refinery feedstocks purchased, ethanol and other refined products purchased and excise taxes paid to various government authorities. Retail cost of sales consists of cost of fuel, merchandise and other products, costs of sales for SuperMom’s Bakery merchandise sales to third parties and excise taxes paid to various government authorities. Retail cost of sales includes intersegment purchases of refined products from the refining segment. For purposes of presenting cost of sales on a combined and consolidated basis, such intersegment transactions are eliminated.

Direct operating expenses. Direct operating expenses include the operating expenses of the refinery and costs of operating the convenience stores and the bakery. Refining direct operating expenses primarily include direct costs of labor, maintenance materials and services, chemicals and catalysts, utilities and other direct operating expenses of the refinery. Retail direct operating expenses consist primarily of salaries, labor and benefits, bankcard processing fees, contracted services, repair and maintenance, utilities and rent expense.

Turnaround and related expenses. Turnaround and related expenses represent the costs of required major maintenance projects on refinery processing units. A turnaround is a standard industry operation to refurbish and maintain a refinery and usually requires the shutdown and inspection of major processing units. Processing units require major maintenance every five to six years.

Depreciation and amortization. Depreciation and amortization represents an allocation to expense within the statement of operations of the carrying value of capital and intangible assets. The value is allocated based on the straight-line method over the estimated useful life of the related asset.

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Selling, general and administrative. Selling, general and administrative expenses primarily include corporate costs, administrative expenses, shared service costs and marketing expenses.

Formation costs. Formation costs represent costs incurred in the creation of Northern Tier Energy LLC and its subsidiaries. No such costs existed for periods prior to the Marathon Acquisition.

Contingent consideration (income) expense. Contingent consideration income (expense) relates to changes in the estimated fair value of our margin support and earn-out arrangements with Marathon. No such arrangement existed for periods prior to December 1, 2010.

Other income (expense), net. Other income (expense), net primarily represents income (expense) from our equity method investment in the Minnesota Pipe Line Company and dividend income from our cost method investment in MPL Investments.

Gain (loss) from derivative activities. Gain (loss) from derivative activities primarily includes losses incurred on our crack spread derivative strategy initiated in October 2010 in anticipation of the Marathon Acquisition to mitigate market price risk. Included in gain (loss) from derivative activities are realized gains or losses related to settled contracts during the period and unrealized gains or losses on outstanding derivatives to partially hedge the crack spread margins for our refining business through 2012. The offsetting benefits related to these unrealized losses should be realized over future periods as improved crack spreads are realized. Going forward, we plan to hedge a lesser amount of our production than we hedged at the time of the acquisition.

Bargain purchase gain. Bargain purchase gain represents the excess of the estimated fair value of the net assets acquired in the Marathon Acquisition over the total purchase consideration.

Interest expense, net. Interest expense, net subsequent to December 1, 2010 relates primarily to interest incurred on the notes as well as commitment fees and interest on the revolving credit facility and the amortization of deferred financing costs.

The historical financial data presented below are not necessarily indicative of the results to be expected for any future period. The historical financial data for the year ended December 31, 2009 and for the eleven months ended November 30, 2010, do not reflect the consummation of the Marathon Acquisition or our capital structure following the Marathon Acquisition. See “—Predecessor Carve-out Financial Statements.”

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Consolidated and Combined Financial Data


	Predecessor						Successor
	Year Ended December 31, 2009			Eleven Months Ended November 30, 2010			June 23, 2010 (inception date) to December 31, 2010			Year Ended December 31, 2011			Three Months Ended March 31,
	Year Ended December 31, 2009			Eleven Months Ended November 30, 2010			June 23, 2010 (inception date) to December 31, 2010			Year Ended December 31, 2011			2011			2012
	(in millions)
Revenue	$	2,940.5		$	3,195.2		$	344.9		$	4,280.8		$	940.2		$	999.1
Costs, expenses and other:
Costs of sales		2,507.9			2,697.9			307.5			3,508.0			779.0			839.8
Direct operating expenses		238.3			227.0			21.4			260.3			61.9			60.7
Turnaround and related expenses		0.6			9.5			—			22.6			3.3			3.5
Depreciation and amortization		40.2			37.3			2.2			29.5			7.3			8.5
Selling, general and administrative		64.7			59.6			6.4			90.7			18.4			20.3
Formation costs		—			—			3.6			7.4			2.5			–
Contingent consideration (income)		—			—			—			(55.8	)		(31.8	)		65.7
Other (income) expense, net		(1.1	)		(5.4	)		0.1			(4.5	)		(1.1	)		(2.1	)

Operating income		89.9			169.3			3.7			422.6			100.7			2.7
Realized losses from derivative activities		—			—			—			(310.3	)		(52.2	)		(52.9	)
Loss on early extinguishment of derivatives		—			—			—			—			—			(44.6	)
Unrealized losses from derivative activities		—			(40.9	)		(27.1	)		(41.9	)		(262.9	)		(88.4	)
Bargain purchase gain		—			—			51.4			—			–			–
Interest expense, net		(0.4	)		(0.3	)		(3.2	)		(42.1	)		(10.0	)		(10.4	)

Earnings (loss) before income taxes		89.5			128.1			24.8			28.3			(224.4	)		(193.6	)
Income tax provision		(34.8	)		(67.1	)		—			—			(0.1	)		–

Net earnings (loss)	$	54.7		$	61.0		$	24.8		$	28.3		$	(224.5	)	$	(193.6	)

Three Months Ended March 31, 2012 (Successor) Compared to the Three Months Ended March 31, 2011 (Successor)

Revenue. Revenue for the three months ended March 31, 2012 was $999.1 million compared to $940.2 million for the three months ended March 31, 2011, an increase of 6.3%. Refining segment revenue increased 5.8% and retail segment revenue increased 1.1% compared to the three months ended March 31, 2011. The refining segment benefited from higher average prices across our principal products driven primarily by increased market prices for refined products offset by lower volumes. Retail revenue also benefited from higher average fuel prices and higher merchandise sales that were partially offset by lower fuel sales volumes. Excise taxes included in revenue totaled $65.6 million and $56.7 million for the three months ended March 31, 2012 and 2011, respectively.

Cost of sales. Cost of sales totaled $839.8 million for the three months ended March 31, 2012 compared to $779.0 million for the three months ended March 31, 2011, an increase of 7.8%, due primarily to higher priced crude oil and other feedstock costs. Cost of sales as a percentage of revenue increased from 82.9% for the three months ended March 31, 2011 to 84.1% for the three months ended March 31, 2012. The increase relates primarily to our refining segment where costs of crude oil and other feedstocks have increased at a higher rate than the increases in average selling

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prices of our refined products compared to the prior year period. Excise taxes included in cost of sales were $65.6 million and $56.7 million for the three months ended March 31, 2012 and 2011, respectively.

Direct operating expenses. Direct operating expenses totaled $60.7 million for the three months ended March 31, 2012 compared to $61.9 million for the three months ended March 31, 2011, a decrease of 1.9%, due primarily to lower utility expenses at the refinery, which were driven by lower utility rates and reduced usage due to favorable weather conditions in the first quarter of 2012.

Turnaround and related expenses. Turnaround and related expenses totaled $3.5 million for the three months ended March 31, 2012 compared to $3.3 million for the three months ended March 31, 2011. Both periods include costs related to preparation for partial turnarounds planned for the second quarter of each year.

Depreciation and amortization. Depreciation and amortization was $8.5 million for the three months ended March 31, 2012 compared to $7.3 million for the three months ended March 31, 2011, an increase of 16.4%. This increase was primarily due to depreciation of assets placed in service since March 31, 2011 at our refinery and related to our systems implementation project.

Selling, general and administrative expenses. Selling, general and administrative expenses were $20.3 million for the three months ended March 31, 2012 compared to $18.4 million for the three months ended March 31, 2011. This increase of 10.3% from the prior year period relates primarily to higher administrative costs as we continue to incur a significant level of third party systems support during the process optimization portion of our standalone systems implementation.

Formation costs. Formation costs for the three months ended March 31, 2011 were $2.5 million, all attributable to the Marathon Acquisition. We did not incur any such costs in the three months ended March 31, 2012.

Contingent consideration loss (income). Contingent consideration loss was $65.7 million for the three months ended March 31, 2012 compared to contingent consideration income of $31.8 million for the three months ended March 31, 2011. Both the contingent consideration income and loss relate to updated financial performance estimates for the period of performance under the margin support and earn-out agreements with Marathon related primarily to changes in the forward markets for our refined products.

Other income, net. Other income, net was $2.1 million for the three months ended March 31, 2012 compared to $1.1 million for the three months ended March 31, 2011. This change is driven primarily by increases in equity income from our investment in the Minnesota Pipe Line Company.

Loss from derivative activities. For the three months ended March 31, 2012, we had realized losses of $52.9 million related to settled contracts compared to $52.2 million in the prior year period. Offsetting benefits related to these losses were recognized through improved operating margins. We incurred unrealized losses on outstanding derivatives of $88.4 million for the three months ended March 31, 2012 compared to $262.9 million during the three months ended March 31, 2011. These derivatives were entered into to partially hedge the crack spread margins for our refining business. The offsetting benefits related to these unrealized losses should be realized over future periods as improved operating margins are realized. In addition to these losses, during the three months ended March 31, 2012, we entered into arrangements to settle a portion of our existing derivative instruments ahead of their respective expiration dates and incurred $44.6 million of realized losses related to these early extinguishments. The cash payments for these early extinguishments have been deferred and will come due between December 2012 and December 2013.

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Interest expense, net. Interest expense, net was $10.4 million for the three months ended March 31, 2012 and $10.0 million for the three months ended March 31, 2011. These interest charges relate primarily to the issuance of our senior secured notes as well as commitment fees and interest on the ABL Facility and the amortization of deferred financing costs.

Income tax provision. Income tax expense was less than $0.1 million for the three months ended March 31, 2012 and for the three months ended March 31, 2011. We operate as a pass-through entity for federal tax purposes and, as such, only state taxes have been recognized.

Net loss. Our net loss was $193.6 million for the three months ended March 31, 2012 compared to a net loss of $224.5 million for the three months ended March 31, 2011. This reduction in the loss of 13.8% was primarily attributable to the decrease of $129.2 million related to derivatives activities, which were partially offset by losses from our contingent consideration arrangement with Marathon in the 2012 quarter compared to income in the 2011 quarter.

Year Ended December 31, 2011 (Successor) Compared to the Eleven Months Ended November 30, 2010 (Predecessor)

Revenue. Revenue for the year ended December 31, 2011 was $4,280.8 million compared to $3,195.2 million for the eleven months ended November 30, 2010, an increase of 22.8% from the average monthly run rate for the 2010 period. Refining segment revenue increased 24.5% and retail segment revenue increased 7.3% compared to the average monthly run rate for the eleven months ended November 30, 2010. The refining segment benefited from higher average prices across our principal products driven primarily by increased market prices for refined products. Retail revenue also benefited from higher average fuel prices that were partially offset by lower sales volumes and lower merchandise sales. Excise taxes included in revenue totaled $242.9 million and $271.8 million for the year ended December 31, 2011 and the eleven months ended November 30, 2010, respectively.

Cost of sales. Cost of sales totaled $3,508.0 million for the year ended December 31, 2011 compared to $2,697.9 million for the eleven months ended November 30, 2010, an increase of 19.2% from the average monthly run rate for the 2010 period, due primarily to higher priced crude oil and other feedstock costs. Cost of sales as a percentage of revenue decreased from 84.4% for the eleven months ended November 30, 2010 to 81.9% for the year ended December 31, 2011 due to the increased revenues resulting from higher refined product average prices. Excise taxes included in cost of sales were $242.9 million and $271.8 million for the year ended December 31, 2011 and the eleven months ended November 30, 2010, respectively.

Direct operating expenses. Direct operating expenses totaled $260.3 million for the year ended December 31, 2011 compared to $227.0 million for the eleven months ended November 30, 2010, an increase of 5.1% from the average monthly run rate for the 2010 period, due to higher rent costs in our retail segment as a result of the sale-leaseback arrangement entered into in connection with the Marathon Acquisition and higher credit card processing fees in our retail segment as a result of the higher revenues.

Turnaround and related expenses. Turnaround and related expenses totaled $22.6 million for the year ended December 31, 2011 compared to $9.5 million for the eleven months ended November 30, 2010. The increase from the 2010 period is primarily due to the timing and scope of the scheduled turnaround projects undertaken in the respective periods. The 2011 period included a scheduled partial turnaround at the refinery in April principally to replace a catalyst in the distillate and gas oil hydrotreaters and to conduct basic maintenance on the No. 1 crude unit.

Depreciation and amortization. Depreciation and amortization was $29.5 million for the year ended December 31, 2011 compared to $37.3 million for the eleven months ended November 30,

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2010, a decrease of 27.5% from the average monthly run rate for the 2010 period. As part of the Marathon Acquisition, the real estate for the majority of our convenience stores was sold and as a result we are no longer depreciating these convenience store buildings. Additionally, as a result of purchase accounting, the book value of our refinery was increased and its estimated useful life was extended. The impact of these purchase accounting adjustments is a net decrease in overall refinery depreciation.

Selling, general and administrative expenses. Selling, general and administrative expenses were $90.7 million for the year ended December 31, 2011 compared to $59.6 million for the eleven months ended November 30, 2010. This increase of 39.5% from the average monthly run rate for the 2010 period reflects higher administrative costs as we developed our standalone infrastructure throughout the year while continuing to pay transition services fees of $21.1 million in 2011 to utilize Marathon systems. As a result, there was a period of overlap and redundant cost structures during this infrastructure development.

Formation costs. Formation costs for the year ended December 31, 2011 were $7.4 million, all attributable to the Marathon Acquisition. We did not incur any such costs in the eleven months ended November 30, 2010.

Contingent consideration income. Contingent consideration income was $55.8 million for the year ended December 31, 2011, which is due to updated financial performance estimates for the period of performance under the margin support and earn-out provisions included in the Marathon Acquisition agreements.

Other income, net. Other income, net was $4.5 million for the year ended December 31, 2011 compared to $5.4 million for the eleven months ended November 30, 2010. This change is driven primarily by changes in equity income from our investment in the Minnesota Pipe Line Company.

Loss from derivative activities. For the year ended December 31, 2011, we had realized losses of $310.3 million related to settled contracts. Offsetting benefits related to these losses were recognized through improved operating margins. We incurred unrealized losses of $41.9 million for the year ended December 31, 2011 on outstanding derivatives entered into to partially hedge the crack spread margins for our refining business through 2012. We incurred unrealized losses on these outstanding derivatives of $40.9 million for the eleven months ended November 30, 2010. The offsetting benefits related to these unrealized losses should be realized over future periods as improved operating margins are realized.

Interest expense, net. Interest expense, net was $42.1 million for the year ended December 31, 2011 compared to $0.3 million for the eleven months ended November 30, 2010. This increase was primarily attributable to the issuance of the notes as well as commitment fees and interest on our revolving credit facility and the amortization of deferred financing costs.

Income tax provision. Income tax expense was less than $0.1 million for the year ended December 31, 2011 compared to $67.1 million for the eleven months ended November 30, 2010. The effective tax rate was 52.4% for the eleven months ended November 30, 2010. The effective rate was impacted primarily by the establishment of a valuation allowance against capital losses incurred on derivative activities. The effective tax rate is not comparable to the year ended December 31, 2011. From the date of the Marathon Acquisition, only state taxes have been recognized and no federal provision was recognized. We operated as a pass-through entity for federal income tax purposes for the year ended December 31, 2011.

Net earnings. Our net earnings were $28.3 million for the year ended December 31, 2011 compared to net earnings of $61.0 million for the eleven months ended November 30, 2010. This

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decrease of 57.5% from the average monthly run rate for the 2010 period was primarily attributable to the realized loss on derivative activities of $310.3 million and an increase in interest expense, partially offset by increased operating income and lower income taxes.

2010 Successor Period from June 23, 2010 (inception date) through December 31, 2010

Northern Tier Energy LLC was formed on June 23, 2010 and entered into certain agreements with Marathon on October 6, 2010 to acquire the Marathon Assets. At the closing of the Marathon Acquisition on December 1, 2010, Northern Tier Energy LLC acquired the Marathon Assets. Northern Tier Energy LLC had no operating activities between its June 23, 2010 inception date and the closing date of the Marathon Acquisition, although it incurred various transaction and formation costs which have been included in the 2010 Successor Period.

The discussion below presents a comparison of the 2010 Successor Period and 2009 monthly average run rates, and does not seek to compare the 2010 Successor Period to the equivalent period in the prior year.

Revenue for the 2010 Successor Period was $344.9 million. Revenue for the 2010 Successor Period was favorably impacted by price increases across both the refining and retail segments. Refining and retail segment revenues increased 48.1% and 9.4% compared to 2009 average monthly run rate revenues. Cost of sales for the 2010 Successor Period was $307.5 million. Excise taxes included in both revenue and cost of sales were $25.1 million for the 2010 Successor Period. Cost of sales as a percentage of revenue was 89.2% for the 2010 Successor Period compared to 85.3% for 2009.

The 2010 Successor Period included two significant non-recurring items: formation costs of $3.6 million and a bargain purchase gain of $51.4 million, both related to the Marathon Acquisition. Additionally, during the 2010 Successor Period, we incurred unrealized losses of $27.1 million on outstanding derivatives entered into in 2010 to partially hedge the crack spread margins for our refining business for 2011 through 2012. The offsetting benefits related to these unrealized losses will be realized over future periods as the improved crack spread margins are realized.

Our net earnings were $24.8 million for the 2010 Successor Period, compared to 2009 average monthly run rate net earnings of $4.6 million. The net earnings in the 2010 Successor Period include $3.6 million of formation costs, $27.1 million of unrealized derivative losses and a $51.4 million bargain purchase gain, all of which were related to the Marathon Acquisition and did not occur in the 2009 period.

Eleven Months Ended November 30, 2010 Compared to Year Ended December 31, 2009

Revenue. Revenue for the eleven months ended November 30, 2010 was $3,195.2 million compared to $2,940.5 million for the year ended December 31, 2009, an 18.5% increase versus the average monthly run rate for 2009. Refining and retail segment revenue increased to $2,799.8 million and $1,206.8 million, respectively, which represent increases of 20.7% and 16.6%, respectively, versus the 2009 average monthly run rate levels. These increases were primarily due to increases in the market prices for refined products across the periods. Federal and state excise taxes included in revenue totaled $271.8 million and $289.6 million for the eleven months ended November 30, 2010 and year ended December 31, 2009, respectively.

Cost of sales. Cost of sales for the eleven months ended November 30, 2010 was $2,697.9 million compared to $2,507.9 million for the year ended December 31, 2009, a 17.3% increase versus the average monthly run rate for 2009. This increase is primarily due to increased market prices for

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crude oil in the 2010 period. Cost of sales as a percentage of revenue was 84.4% and 85.3% for the eleven months ended November 30, 2010 and year ended December 31, 2009, respectively. Excise taxes included in cost of sales were $271.8 million and $289.6 million for the eleven months ended November 30, 2010 and year ended December 31, 2009, respectively.

Direct operating expenses. Direct operating expenses for the eleven months ended November 30, 2010 were $227.0 million compared to $238.3 million for the year ended December 31, 2009, a 3.9% increase versus the 2009 average monthly run rate. The increase was primarily due to higher utility costs in the refining segment and higher credit card fees in retail segment.

Turnaround and related expenses. Turnaround and related expenses totaled $9.5 million for the eleven months ended November 30, 2010 compared to $0.6 million for the year ended December 31, 2009. This increase is primarily due to a scheduled partial turnaround at the refinery during September and October 2010.

Depreciation and amortization. Depreciation and amortization was $37.3 million for the eleven months ended November 30, 2010 and $40.2 million for the year ended December 31, 2009, a 1.2% increase versus the 2009 average monthly run rate. The increase versus the prior year relates primarily to the on-going investment in our refinery infrastructure.

Selling, general and administrative expenses. Selling, general and administrative expenses for the eleven months ended November 30, 2010 were $59.6 million compared to $64.7 million for the year ended December 31, 2009, a 0.5% increase versus the 2009 average monthly run rate.

Other income, net. Other income, net was $5.4 million for the eleven months ended November 30, 2010 compared to other income, net of $1.1 million for the year ended December 31, 2009. This improvement is due to higher equity income from our investment in the Minnesota Pipe Line Company.

Loss from derivative activities. We incurred unrealized losses of $40.9 million for the eleven months ended November 30, 2010 on outstanding derivatives entered into during 2010. The offsetting benefits relating to these unrealized losses should be realized over future periods as improved operating margins are realized. No such derivative activity existed for the year ended December 31, 2009.

Interest expense, net. Interest expense, net was $0.3 million for the eleven months ended November 30, 2010 and $0.4 million for the year ended December 31, 2009.

Income tax provision. Income tax expense was $67.1 million for the eleven months ended November 30, 2010 and $34.8 million for the year ended December 31, 2009. The effective tax rate was 52.4% for the eleven months ended November 30, 2010 and 38.9% for the year ended December 31, 2009. The effective rate for the eleven months ended November 30, 2010 was impacted primarily by the establishment of a valuation allowance against capital losses incurred on derivative activities.

Net earnings. Our net earnings were $61.0 million for the eleven months ended November 30, 2010 and $54.7 million for the year ended December 31, 2009. The increase in net earnings is primarily due to the improved gross product margin in our refining business in the 2010 period. Refinery gross product margin per barrel of throughput were $12.86 for the eleven months ended November 30, 2010 and $9.36 for the year ended December 31, 2009.

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Segment Financial Data

The segment financial data for the refining segment discussed below under “—Refining Segment” include intersegment sales of refined products to the retail segment. Similarly, the segment financial data for the retail segment discussed below under “—Retail Segment” contain intersegment purchases of refined products from the refining segment. For purposes of presenting our combined and consolidated results, such intersegment transactions are eliminated, as shown in the following tables.


	Successor
	Three Months Ended March 31, 2012
	Refining		Retail		Other/Elim			Consolidated
	(in millions)
Revenue:
Sales and other revenue	$	654.5	$	344.6	$	—		$	999.1
Intersegment sales		240.0		—		(240.0	)		—

Segment revenue	$	894.5	$	344.6	$	(240.0	)	$	999.1

Cost of sales:
Cost of sales	$	772.0	$	67.8	$	—		$	839.8
Intersegment purchases		—		240.0		(240.0	)		—

Segment cost of sales	$	772.0	$	307.8	$	(240.0	)	$	839.8


	Successor
	Three Months Ended March 31, 2011
	Refining		Retail		Other/Elim			Combined
	(in millions)
Revenue:
Sales and other revenue	$	599.5	$	340.7	$	—		$	940.2
Intersegment sales		245.7		—		(245.7	)		—

Segment revenue	$	845.2	$	340.7	$	(245.7	)	$	940.2

Cost of sales:
Cost of sales	$	719.0	$	60.0	$	—		$	779.0
Intersegment purchases		—		245.7		(245.7	)		—

Segment cost of sales	$	719.0	$	305.7	$	(245.7	)	$	779.0


	Successor
	Year Ended December 31, 2011
	Refining		Retail		Other/Elim			Consolidated
	(in millions)
Revenue:
Sales and other revenue	$	2,761.0	$	1,519.8	$	—		$	4,280.8
Intersegment sales		1,043.1		—		(1,043.1	)		—

Segment revenue	$	3,804.1	$	1,519.8	$	(1,043.1	)	$	4,280.8

Northern Tier Energy LLC 8-K