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As filed with the Securities and Exchange Commission on January 16, 2013

Registration No. 333-185124

 

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Amendment No. 4

To

FORM S-1

REGISTRATION STATEMENT

UNDER

THE SECURITIES ACT OF 1933

 

 

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 Number)

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 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

 

 

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

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, 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		x  (Do not check if a smaller reporting company)		Smaller reporting company		¨

CALCULATION OF REGISTRATION FEE

 

Title of Each Class of Securities to Be Registered		Amount to be Registered (1)		Proposed Maximum Offering Price Per Unit (2)		Proposed Maximum Aggregate Offering Price (2)		Amount of Registration Fee (2)
Common units representing limited partner interests		10,350,000		$24.30		$251,505,000		$34,305.28(3)

 

(1)	Includes common units issuable upon exercise of the underwriters’ option to purchase additional common units.

(2)	Calculated in accordance with Rule 457(c) on the basis of high and low sales prices January 11, 2013.

(3)	A registration fee of $34,100 was previously paid based on a prior estimate of the aggregate maximum offering price.

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 the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

 

 

 

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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 January 16, 2013

PROSPECTUS

 

 

 

Northern Tier Energy LP

9,000,000 Common Units

Representing Limited Partner Interests

 

 

The securities to be offered and sold using this prospectus are currently issued and outstanding common units representing limited partner interests in us. All of the 9,000,000 common units offered by this prospectus are being sold by Northern Tier Holdings LLC, as the selling unitholder. Northern Tier Holdings LLC owns 100% of our general partner and, giving effect to this offering, 69.9% of our common units (or 68.4% if the underwriters exercise in full their option to purchase additional common units). We will not receive any proceeds from the sale of the common units by the selling unitholder in this offering.

Our common units are listed on the New York Stock Exchange under the symbol “NTI.” On January 15, 2013, the last reported sales price of our common units on the New York Stock Exchange was $25.46 per common unit.

Investing in our common units involves risks. See “Risk Factors” on page 22 to read about factors you should consider before buying our common units.

 

		Per Common Unit				Total
Public offering price		$				$
Underwriting discount		$				$
Proceeds to the selling unitholder		$				$

To the extent that the underwriters sell more than 9,000,000 common units, the underwriters have the option to purchase up to an additional 1,350,000 common units at the initial public offering price less the underwriting discount.

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.

The underwriters expect to deliver the common units on or about                 , 2013.

 

 

 

Barclays		BofA Merrill Lynch		Goldman, Sachs & Co.		Citigroup		UBS Investment Bank

 

Credit Suisse		Deutsche Bank Securities		J.P. Morgan

 

 

 

		Macquarie Capital

 

Prospectus dated             , 2013.

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Prospectus Summary			1
Risk Factors			22
Cautionary Note Regarding Forward-Looking Statements			55
Use of Proceeds			57
Capitalization			58
Price Range of Common Units and Distributions			59
Selected Historical Condensed Consolidated Financial Data			60
Management’s Discussion and Analysis of Financial Condition and Results of Operations			62
Business			107
Management			134
Compensation Discussion and Analysis			139
Certain Relationships and Related Person Transactions			156
Security Ownership of Certain Beneficial Owners and Management			161
Selling Unitholder			162
Conflicts of Interest and Fiduciary Duties			163
Description of our Common Units			169
The Partnership Agreement			170
Common Units Eligible for Future Sale			182
Material Federal Income Tax Consequences			183
Investment in Northern Tier Energy LP by Employee Benefit Plans			197
Underwriting			199
Legal Matters			205
Experts			205
Where You Can Find More Information			205
Index to Financial Statements			F-1
Glossary of Terms Used in This Prospectus			A-1

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.

 

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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.

 

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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, 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.

 

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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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Distribution Policy.”

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

Subject to certain exceptions, the indenture governing the 2020 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 restricts us from making cash distributions unless our fixed charge coverage ratio, as defined in the indenture, is at least 1.75 to 1.0 after giving pro forma effect to such distributions. Our revolving credit facility generally restricts our ability to make cash distributions if 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. Accordingly, we may be restricted by our debt agreements from distributing all of our available cash to our unitholders. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Description of Our Indebtedness.”

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.

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. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Distribution Policy.”

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.

 

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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 adopted 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Distribution Policy.”

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.

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. We currently expect our next major turnaround to occur in 2013, for which we have budgeted approximately $50 million. The refinery is currently expected to have reduced throughputs during the months of April and October 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 has adopted 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.

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 daily on terms 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. For crude oil purchased on third party credit terms, 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.

 

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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 our initial public offering may not be comparable to our results of operations for periods prior to the closing of our initial public offering as a result of certain transactions undertaken in connection with our initial public offering. 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.

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

 

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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 in the U.S. and worldwide economies, and potential further deteriorating conditions in the United States and globally, may materially adversely affect our business, results of operations and financial condition.

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.

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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 significantly 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 significantly 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 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 accretive acquisitions within the refining industry and retail market based on sustainable performance of the targeted assets through the refining cycle, access to advantageous crude oil supplies, attractive demand and supply market fundamentals, access to distribution and logistics infrastructure and potential operating synergies. 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

 

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and to support our growth and many other factors beyond our control. Risks associated with acquisitions include those relating to:

 

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diversion of management time and attention from our existing business;

 

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

 

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

 

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

 

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

 

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

 

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difficulties in achieving anticipated operational improvements; and

 

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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

 

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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 the extent to which 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, on September 12, 2012, the U.S. Environmental Protection Agency (“EPA”) published final amendments to the New Source Performance Standards (“NSPS”) for petroleum refineries to be effective November 13, 2012. These amendments include standards for emissions of nitrogen oxides from process heaters and work practice standards and monitoring requirements for flares. To comply with the amendments, we plan to install and operate a continuous emissions monitoring system for nitrogen oxides on a process heater. We have already installed and will operate additional instrumentation on our flare. We anticipate the total cost for these two projects will be approximately $700,000 to be spent in 2012 and 2013. We continue to evaluate the regulation and amended standards, as may be applicable to the operations at our refinery. We cannot currently predict what additional costs that we may have to incur, if any, to comply with the amended NSPS, but the costs could be material. In addition, the 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 the former owner 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

 

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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:

 

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

 

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

 

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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;

 

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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;

 

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

 

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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

 

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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.

As of September 30, 2012, after giving effect to the 2020 Notes offering and the use of proceeds therefrom, as described in “—Recent Developments—2020 Notes Offering and Tender Offer”:

 

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we would have had $275 million of secured indebtedness, representing the 2020 Notes, and $118 million of obligations under our hedging arrangements (of which $77 million represents the fair market value of contracts outstanding at September 30, 2012); and

 

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we would have had commitments under the ABL Facility of $300 million (less approximately $24 million in outstanding letters of credit).

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 has adopted 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.

 

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We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.

Unlike a corporation, our policy is to distribute all available cash generated each quarter. Accordingly, if we experience a liquidity problem in the future, we may have difficulty satisfying our debt obligations.

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 September 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 $39.16 per barrel and $140.08 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:

 

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changes in global and local economic conditions;

 

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

 

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

 

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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;

 

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availability of and access to transportation infrastructure;

 

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utilization rates of U.S. refineries;

 

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the ability of the members of the Organization of Petroleum Exporting Countries to affect oil prices and maintain production controls;

 

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development and marketing of alternative and competing fuels;

 

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commodities speculation;

 

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•

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;

 

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federal and state government regulations and taxes; and

 

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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 13.0% and 13.3% of our total direct operating expenses for the nine months ended September 30, 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 September 30, 2012, the discount at which a barrel of NYMEX WTI traded relative to a barrel of Brent increased from $2.12 to $19.34. 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 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

 

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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 the 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:

 

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

 

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unplanned increases in the cost of construction materials or labor;

 

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

 

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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;

 

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

 

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

 

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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 $21 million was spent from 2006 through September 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 2013 for which we have budgeted approximately $50 million. While we are still finalizing our planning for this turnaround, we currently expect the refinery to have reduced throughputs during the months of April and October 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 180 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, 23 of our employees associated with the operations of our retail business are covered by a collective bargaining agreement that expires in August 2014. 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.

 

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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 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. Additionally, in December 2010, the EPA reached a settlement agreement with numerous parties pursuant to which it agreed to promulgate NSPS for GHG emissions from petroleum refineries by November 2012. To date, the EPA has not proposed the NSPS for GHG emissions from petroleum refineries, and we cannot predict the requirements of these rules. We may be required to make significant capital expenditures and/or incur materially increased operating costs to comply with the GHG NSPS once it is finalized by the EPA.

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, 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

 

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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 granted a partial waiver raising 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. EPA required that fuel and fuel additive manufacturers take certain steps before introducing gasoline containing 15% ethanol (“E15”) into the market, including developing and obtaining EPA approval of a plan to minimize the potential for E15 to be used in vehicles and engines not covered by the partial waiver. EPA has taken several recent actions to authorize the introduction of E15 into the market, including approving, on June 15, 2012, the first plans to minimize the potential for E15 to be used in vehicles and engines not covered by the partial waiver. 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 pipeline 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, 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.

 

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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 below the indexed level. 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.

 

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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 may enter into commodity derivatives contracts to mitigate our crack spread risk with respect to a portion of our expected gasoline and diesel production. We enter into these arrangements with the intent to

 

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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;

 

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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;

 

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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 risk mitigation 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 risk mitigation 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

 

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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 nine months ended September 30, 2012 and the year ended December 31, 2011, our retail business purchased approximately 75% 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.

 

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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:

 

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competition in targeted market areas;

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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

 

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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.

 

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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.

 

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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 adopted 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 adopted a policy to distribute an amount equal to the available cash we generate each quarter to our unitholders. 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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Distribution Policy.”

Our general partner, the indirect owners of which include ACON Refining, TPG Refining and entities in which our President and Chief Executive Officer holds an interest, has fiduciary duties to its owners, and the interests of ACON Refining, TPG Refining and entities in which our President and Chief Executive Officer holds an interest 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 Mr. Kuchta. The interests of ACON Refining, TPG Refining and Mr. Kuchta 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.

 

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

 

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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.

 

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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.

 

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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.

 

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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.

 

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Our general partner may exercise its rights to call and purchase all of our common units if at any time it and its affiliates own more than 90% of the units.

 

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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.

 

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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 it may own and its determination whether or not to consent to any merger or consolidation or amendment to our partnership agreement.

 

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•

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.

 

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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.

 

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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:

 

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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

 

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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.”

Our partnership agreement provides that a conflicts committee may be comprised of one or more directors. If we establish a conflicts committee with only one director, your interests may not be as well served as if we had a conflicts committee comprised of at least two independent directors.

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.

Northern Tier Holdings has 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 are subject to our general partner’s call right.

If at any time our general partner and its affiliates own more than 90% of our outstanding common 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.”

 

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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.

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 69.9% of our common units (or approximately 68.4% of our common 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 without the consent of Northern Tier Holdings.

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 “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Distribution Policy,” “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

 

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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 17-804 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 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.

If our unit price fluctuates after this offering, you could lose a significant part of your investment.

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 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.

 

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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 we are unable to satisfy the requirements of Section 404 of the Sarbanes-Oxley Act, or our internal control over financial reporting is 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.

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. 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.

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.

 

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As of January 9, 2013, there were 91,921,112 units outstanding. 18,687,500 common units were sold to the public in our initial public offering and an aggregate of 73,227,500 common units are owned by Northern Tier Holdings. The common units sold in our initial public offering, as well as the units to be 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 LLC 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.

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 our initial public 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 our initial public offering, we have not filed reports with the SEC. Following our initial public offering, we became 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. 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.”

 

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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.

 

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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.

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 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.

 

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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.

 

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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 elected to be treated as corporations for federal income tax purposes and became subject to corporate-level income taxes.

As part of the IPO Transactions, as described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Comparability of Historical Results—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, elected to be treated as corporations for federal income tax purposes, which subjected 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 prior to our initial public offering 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.

 

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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. 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 “Summary,” “Risk Factors,” “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;

 

•

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

 

•

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 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 or disruptions affecting our refinery, machinery, or equipment, or those of our suppliers or customers;

 

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•

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;

 

•

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;

 

•

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.

 

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Use of Proceeds

The common units to be offered and sold using this prospectus will be offered and sold by the selling unitholder named in this prospectus. We will not receive any proceeds from the sale of such common units.

 

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Capitalization

The following table shows our cash and capitalization as of September 30, 2012:

 

•

on a historical basis; and

 

•

on a pro forma basis to reflect the issuance and sale of $275 million of the 2020 Notes and the application of the net proceeds therefrom, together with cash on hand of $31 million, and the conversion of our PIK units into common units.

This offering will not affect our capitalization. You should read our financial statements and notes that are contained in this prospectus for additional information.

 

		As of September 30, 2012
		Actual				Pro Forma
		(In millions)
Cash and cash equivalents		$	323.5			$	292.6
Long-term debt, including current maturities:
2017 Notes(1)		$	261.0			$	—
2020 Notes			—				275.0
Revolving credit facility			—				—
Lease financing obligation(2)			7.5				7.5
Total long-term debt, including current maturities			268.5				282.5
Equity:
Comprehensive loss		$	(0.4	)		$	(0.4	)
Common units: 73,532,000 issued and outstanding, actual; 91,915,000 issued and outstanding, pro forma			430.7				490.1
PIK units:18,383,000 issued and outstanding, actual; none issued and outstanding, pro forma(3)			107.6				—
Total partners’ interest(4)			537.9				489.7
Total capitalization		$	806.4			$	772.2

 

(1)	Approximately $258 million of the 2017 Notes have been repurchased and the remainder has been satisfied and discharged pursuant to the terms of the indenture governing the 2017 Notes. See “Summary—Recent Developments—2020 Notes Offering and Tender Offer.”

(2)	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.

(3)

The repurchase and satisfaction and discharge of the 2017 Notes resulted in a termination of the PIK Period, as such term is defined in our First Amended and Restated Limited Partnership Agreement. Upon termination of the PIK Period, all of the PIK units automatically converted into common units and thereafter were entitled to receive cash distributions when and as decided by the board of directors of our general partner, instead of distributions “payable in kind” in additional PIK units.

(4)	Pro forma reflects the pro forma after-tax charge from repurchase of the 2017 Notes of approximately $48 million.

 

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Price Range of Common Units and Distributions

Our common units are listed on the New York Stock Exchange under the symbol “NTI.” The last reported sales price of the common units on January 15, 2013 was $25.46. As of January 15, 2013, we had issued and outstanding 91,921,112 common units, which were held of record by 6 unitholders. The following table sets forth the range of high and low sales prices of the common units on the New York Stock Exchange, as well as the amount of cash distributions paid per common unit for the periods indicated.

 

		Common Unit Price Ranges								Cash Distributions per Common Unit(1)
Quarter Ended		High				Low
March 31, 2013 (through January 15, 2013)(2)		$	26.50			$	24.61
December 31, 2012(3)		$	27.11			$	19.97
September 30, 2012(4) (from July 26, 2012)		$	21.27			$	13.00			$	1.48

 

(1)	Distributions are shown for the quarter with respect to which they were declared.

(2)	The distribution attributable to the quarter ending March 31, 2013 has not yet been declared or paid.

(3)	The distribution attributable to the quarter ending December 31, 2012 has not yet been declared or paid.

(4)	The distribution attributable to the quarter ended September 30, 2012 represents a prorated distribution for the period from the closing of our initial public offering through September 30, 2012 and was paid on November 29, 2012 to unitholders of record as of November 21, 2012.

 

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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. Upon the closing of our initial public offering, the historical consolidated financial statements of Northern Tier Energy LLC became the historical consolidated financial statements of Northern Tier Energy LP.

The selected historical financial data as of September 30, 2012 and for the nine months ended September 30, 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, 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 June 30, 2011 is derived from unaudited financial statements and the notes thereto that are not included in this prospectus.

On a pro forma basis and adjusted for certain items to give effect to our initial public offering, the tendering of our 2017 Notes and the private placement of our 2020 Notes, net earnings for the year ended December 31, 2011 would have been $33.1 million.

The items related to our initial public offering include a reduction of interest expense of $3.0 million related to the redemption of a portion of the 2017 Notes, increased selling, general and administrative expenses of $3.5 million as a result of being a publicly traded partnership (resulting in pro forma selling, general and administrative expense of $94.2 million for the year ended December 31, 2011) and a reduction of $2.1 million in management fees paid to ACON Management and TPG Management (resulting in pro forma other income of $6.6 million for the year ended December 31, 2011).

On November 8, 2012, we completed a private placement of $275 million in aggregate principal amount of the 2020 Notes. We used the net proceeds of the offering and cash on hand of $31 million (i) to repurchase our outstanding 2017 Notes that were tendered pursuant to our previously announced tender offer and (ii) to satisfy and discharge any remaining 2017 Notes outstanding (which notes were called for redemption after the closing of the tender offer) and to pay related fees and expenses. The repurchase of the 2017 Notes resulted in an after-tax charge of approximately $48 million in the fourth quarter of 2012. On a pro forma basis after giving effect to such private placement and tender offer, we would have recorded a reduction of approximately $8.9 million of interest expense for the year ended December 31, 2011. The pro forma impacts of the private placement and tender offer and the pro forma impacts of the partial redemption of the 2017 Notes as part of our initial public offering would have resulted in a pro forma interest expense of $30.2 million for the year ended December 31, 2011.

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

 

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You should read these tables along with “Risk Factors,” “Use of Proceeds,” “Capitalization,” “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,												Eleven Months Ended November 30, 2010				June 23, 2010 (inception date) to December 31, 2010				Year Ended December 31, 2011				Nine Months Ended September 30,
		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			$	3,192.0			$	3,417.8
Costs and expenses:
Costs of sales			2,820.0				3,659.0				2,507.9				2,697.9				307.5				3,508.0				2,578.2				2,594.0
Direct operating expenses			249.0				252.7				238.3				227.0				21.4				260.3				192.5				189.1
Turnaround and related expenses			32.6				3.7				0.6				9.5				—				22.6				22.5				17.1
Depreciation and amortization			33.7				39.2				40.2				37.3				2.2				29.5				22.3				24.6
Selling, general and administrative expenses			61.7				67.7				64.7				59.6				6.4				90.7				63.3				67.1
Formation costs			—				—				—				—				3.6				7.4				6.1				1.0
Contingent consideration (income) expense			—				—				—				—				—				(55.8	)			(37.6	)			104.3
Other (income) expense, net			0.7				1.2				(1.1	)			(5.4	)			0.1				(4.5	)			(2.4	)			(6.2	)
Operating income			325.1				98.9				89.9				169.3				3.7				422.6				347.1				426.8
Realized losses from derivative activities			—				—				—				—				—				(310.3	)			(246.4	)			(165.0	)
Unrealized (losses) gains from derivative activities			—				—				—				(40.9	)			(27.1	)			(41.9	)			(334.5	)			32.6
Loss on early extinguishment of derivatives			—				—				—				—				—				—				—				(136.8	)
Bargain purchase gain			—				—				—				—				51.4				—				—				—
Interest expense			0.2				(0.5	)			(0.4	)			(0.3	)			(3.2	)			(42.1	)			(30.6	)			(36.7	)
Earnings (loss) before income taxes			325.3				98.4				89.5				128.1				24.8				28.3				(264.4	)			120.9
Income tax provision			(129.9	)			(39.8	)			(34.8	)			(67.1	)			—				—				—				(7.8	)
Net earnings (loss)		$	195.4			$	58.6			$	54.7			$	61.0			$	24.8			$	28.3			$	(264.4	)		$	113.1
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			$	194.9			$	174.8
Investing activities			(111.0	)			(84.6	)			(25.0	)			(29.3	)			(363.3	)			(156.3	)			(138.5	)			(12.0	)
Financing activities			(171.7	)			34.5				(103.9	)			(115.4	)			436.1				(2.3	)			(2.5	)			37.2
Capital expenditures			(75.8	)			(45.0	)			(29.0	)			(29.8	)			(2.5	)			(45.9	)			(27.4	)			(13.3	)

 

		Predecessor																Successor
		December 31,												November 30, 2010				December 31, 2010				December 31, 2011				September 30, 2012
		2007				2008				2009
														(in millions)
Consolidated and combined balance sheets data:
Cash and cash equivalents		$	8.5			$	5.5			$	6.0			$	6.7			$	72.8			$	123.5			$	323.5
Total assets			737.3				708.2				710.1				717.8				930.6				998.8				1,177.4
Total long-term debt			—				—				—				—				314.5				301.9				268.5
Total liabilities			415.1				292.7				343.9				405.4				645.6				686.6				639.5
Total equity			322.2				415.5				366.2				312.4				285.0				312.2				537.9

 

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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 limited partnership with refining, retail and pipeline operations that serves 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 nine months ended September 30, 2012, we had total revenues of approximately $3.4 billion, operating income of $426.8 million, net earnings of $113.1 million and Adjusted EBITDA of $577.3 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 “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 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 80% and 79% of our total refinery production for the nine months ended September 30, 2012 and the year ended December 31, 2011, respectively, was comprised of higher value, light refined products, including gasoline and distillates. Our refinery utilization rates, using standard industry methodologies for utilization measurement, have been 72%, 75% and 78% for the period from inception to December 31, 2010, for the year ended December 31, 2011 and for the nine months ended September 30, 2012, respectively.

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 82% and 83% of our gasoline and diesel volumes for the nine months ended September 30, 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.

 

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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 September 30, 2012, our retail business operated 166 convenience stores under the SuperAmerica brand and also supported 68 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 nine months ended September 30, 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.

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 continued strong overall product demand in our geographic area of operations.

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 nine months ended September 30, 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. 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,

 

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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 Northern Tier Holdings LLC.

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 and margin support arrangements with Marathon under which we could have received margin support payments of up to $60 million from MPC or could have paid MPC net earn-out payments of up to $125 million over the term of the arrangements, depending on our Adjusted EBITDA as defined in the arrangements. On May 4, 2012, we entered into a settlement agreement with Marathon under which Marathon received $40 million of the net proceeds from our initial public offering, and Northern Tier Holdings LLC redeemed Marathon’s existing preferred interest with a portion of the net proceeds from our initial public offering and issued Marathon a new $45 million preferred interest in Northern Tier Holdings LLC in consideration for relinquishing all claims with respect to earn-out payments under the contingent consideration agreement. We also agreed, pursuant to the settlement agreement, to relinquish all claims to margin support payments under the contingent consideration agreement.

 

•

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:

 

•

2017 Notes.  We issued $290 million of the 10.5% senior secured notes due December 1, 2017. The net proceeds from the sale of the 2017 Notes were used to fund part of the Marathon Acquisition. On November 14, 2012, we completed a tender offer for the 2017 Notes. See “Summary—Recent Developments—2020 Notes Offering and Tender Offer.”

 

•

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, as subsequently amended, is available through July 17, 2017. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Description of Our Indebtedness—Senior Secured Asset-Based Revolving Credit Facility.”

 

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•

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.

 

•

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 $301.8 million and $310.3 million of realized losses and $32.6 million of unrealized gains and $41.9 million of unrealized losses for the nine months ended September 30, 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 our initial public offering may not be comparable to our results of operations for periods prior to the closing of our initial public offering as a result of certain aspects of our initial public offering, including the following:

 

•

We expect that our general and administrative expenses will increase as a result of our initial public 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 our initial public offering, Northern Tier Retail

 

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Holdings LLC, the subsidiary of Northern Tier Energy LLC through which we conduct our retail business, and Northern Tier Energy Holdings LLC elected to be treated as corporations for federal income tax purposes, subjecting these subsidiaries to corporate-level tax. As a result of the elections 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 elections, our financial statements will include a tax provision on income attributable to these subsidiaries. Giving effect to such elections, we recorded a tax provision of $7.8 million for the nine months ended September 30, 2012, including an $8.0 million tax charge to recognize the net deferred tax asset and liability position as of the date of the elections. On a pro forma basis after giving effect to such elections and our initial public offering, we would have recorded a tax provision of approximately $5.7 million for the year ended December 31, 2011.

 

•

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 terminated in connection with the closing of our initial public offering.

2020 Notes Offering and Tender Offer

Our results of operations for periods subsequent to the completion of our 2020 Notes offering and tender offer may not be comparable to our results of operations for periods prior to the refinancing.

On November 8, 2012, we completed a private placement of $275 million in aggregate principal amount of the 2020 Notes. We used the net proceeds of the offering and cash on hand of $31 million (i) to repurchase our outstanding 2017 Notes that were tendered pursuant to our previously announced tender offer and (ii) to satisfy and discharge any remaining 2017 Notes outstanding (which notes were called for redemption after the closing of the tender offer) and to pay related fees and expenses. The repurchase of the 2017 Notes resulted in an after-tax charge of approximately $48 million in the fourth quarter of 2012. On a pro forma basis after giving effect to such private placement and tender offer, we would have recorded a reduction of approximately $8.9 million of interest expense for the year ended December 31, 2011. The pro forma impacts of the private placement and tender offer and the pro forma impacts of the partial redemption of the 2017 Notes as part of our initial public offering would have resulted in a pro forma interest expense of $30.2 million for the year ended December 31, 2011.

In connection with the transactions described in the preceding paragraph, our PIK units converted into common units representing limited partner interests with the same rights and limitations as our existing common units, effective November 9, 2012.

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.

 

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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

 

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$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 nine months ended September 30, 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 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 these refined products. Consistent with that policy, as of September 30, 2012, we had hedged approximately nine million barrels of future gasoline and diesel production, of which four million barrels are 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 nine months ended September 30, 2012, we settled contracts covering approximately three million barrels of our remaining 2012 gasoline and diesel production and recognized a loss of approximately $44.6 million. 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 used $92 million of the net proceeds from our initial public offering to settle the majority of these obligations. The remainder of these deferred losses of approximately $45 million will be paid through the end of 2013.

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.

 

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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 September 30, 2012, 33 of the 68 existing franchise stores are 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.

 

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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.

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 Minnesota Pipe Line and dividend income from our cost method investment in Minnesota Pipe Line Company, LLC.

Gain (loss) from derivative activities.  Gain (loss) from derivative activities primarily includes impacts from our crack spread risk mitigation 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. 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 Marathon 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 our senior secured notes as well as commitment fees and interest on the revolving credit facility and the amortization of deferred financing costs.

 

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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.”

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				Nine Months Ended September 30,
																		2011				2012
										(in millions)
Revenue		$	2,940.5			$	3,195.2			$	344.9			$	4,280.8			$	3,192.0			$	3,417.8
Costs, expenses and other:
Costs of sales			2,507.9				2,697.9				307.5				3,508.0				2,578.2				2,594.0
Direct operating expenses			238.3				227.0				21.4				260.3				192.5				189.1
Turnaround and related expenses			0.6				9.5				—				22.6				22.5				17.1
Depreciation and amortization			40.2				37.3				2.2				29.5				22.3				24.6
Selling, general and administrative			64.7				59.6				6.4				90.7				63.3				67.1
Formation costs			—				—				3.6				7.4				6.1				1.0
Contingent consideration (income) expense			—				—				—				(55.8	)			(37.6	)			104.3
Other (income) expense, net			(1.1	)			(5.4	)			0.1				(4.5	)			(2.4	)			(6.2	)
Operating income			89.9				169.3				3.7				422.6				347.1				426.8
Realized losses from derivative activities			—				—				—				(310.3	)			(246.4	)			(165.0	)
Loss on early extinguishment of derivatives			—				—				—				—				—				(136.8	)
Unrealized (losses) gains from derivative activities			—				(40.9	)			(27.1	)			(41.9	)			(334.5	)			32.6
Bargain purchase gain			—				—				51.4				—				—				—
Interest expense, net			(0.4	)			(0.3	)			(3.2	)			(42.1	)			(30.6	)			(36.7	)
Earnings (loss) before income taxes			89.5				128.1				24.8				28.3				(264.4	)			120.9
Income tax provision			(34.8	)			(67.1	)			—				—				—				(7.8	)
Net earnings (loss)		$	54.7			$	61.0			$	24.8			$	28.3			$	(264.4	)		$	113.1

Nine Months Ended September 30, 2012 Compared to the Nine Months Ended September 30, 2011

Revenue.  Revenue for the nine months ended September 30, 2012 was $3,417.8 million compared to $3,192.0 million for the nine months ended September 30, 2011, an increase of 7.1%. Refining segment revenue increased 7.9% and retail segment revenue decreased 3.8% compared to the nine months ended September 30, 2011. The refining segment benefited from higher average market prices for refined products and higher sales volumes. Retail revenue decreased primarily due to lower fuel sales volumes caused by reduced market demand and road construction projects impacting our retail stores. Excise taxes included in revenue totaled $215.0 million and $181.5 million for the nine months ended September 30, 2012 and 2011, respectively.

Cost of sales.  Cost of sales totaled $2,594.0 million for the nine months ended September 30, 2012 compared to $2,578.2 million for the nine months ended September 30, 2011, an increase of 0.6%, due to the impact of increased refining throughput, partially offset by lower priced crude oil as a result of favorable crude differentials in the second and third quarters of 2012. Excise taxes included in cost of sales were $215.0 million and $181.5 million for the nine months ended September 30, 2012 and 2011, respectively.

Direct operating expenses.  Direct operating expenses totaled $189.1 million for the nine months ended September 30, 2012 compared to $192.5 million for the nine months ended September 30, 2011, a decrease of

 

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1.8%, due primarily to lower operating expenses at our retail stores and reduced 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, offset by costs recognized in the 2012 period related to environmental compliance projects at our refinery’s wastewater treatment plant.

Turnaround and related expenses.  Turnaround and related expenses totaled $17.1 million for the nine months ended September 30, 2012 compared to $22.5 million for the nine months ended September 30, 2011. Both periods include costs related to planned, partial turnarounds. The 2012 turnarounds include the alkylation unit, which was completed according to schedule in mid-May, and the No. 1 reformer unit, which was completed in early November. The 2011 turnaround was principally to replace 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 $24.6 million for the nine months ended September 30, 2012 compared to $22.3 million for the nine months ended September 30, 2011, an increase of 10.3%. This increase was primarily due to depreciation of assets placed in service since September 30, 2011 primarily related to our refinery and our systems implementation project.

Selling, general and administrative expenses.  Selling, general and administrative expenses were $67.1 million for the nine months ended September 30, 2012 compared to $63.3 million for the nine months ended September 30, 2011. This increase of 6.0% from the prior year period relates primarily to higher administrative costs incurred during the first six months of 2012 related to post go-live systems support during the process optimization phase of our standalone systems implementation and higher compensation costs and risk management expenses in the 2012 period.

Formation costs.  Formation costs for the nine months ended September 30, 2012 and 2011 were $1.0 million and $6.1 million, respectively. The formation costs in the 2012 period relate to offering costs for our initial public offering that did not meet the accounting requirements for deferral. This second quarter 2012 charge was incurred by Northern Tier Energy LP but was not an expense of Northern Tier Energy LLC. All of the costs from the 2011 period are attributable to the Marathon Acquisition.

Contingent consideration loss (income).  Contingent consideration loss was $104.3 million for the nine months ended September 30, 2012 compared to contingent consideration income of $37.6 million for the nine months ended September 30, 2011. The contingent consideration losses relate to the margin support and earn-out agreements entered into with Marathon at acquisition. The 2012 charge of $104.3 million includes the impact of the final valuation adjustment to arrive at the agreed settlement amount which was contingent upon our initial public offering. The contingent consideration income in the 2011 period relates to changes in the financial performance estimates as of September 30, 2011 for the then remaining period of performance.

Other income, net.  Other income, net was $6.2 million for the nine months ended September 30, 2012 compared to $2.4 million for the nine months ended September 30, 2011. This change is driven primarily by increases in equity income from our investment in Minnesota Pipe Line Company, LLC.

Gains (losses) from derivative activities.  For the nine months ended September 30, 2012, we had realized losses of $165.0 million related to settled contracts compared to $246.4 million in the prior-year period. Offsetting benefits related to these losses were recognized through improved operating margins. We incurred unrealized gains on outstanding derivatives of $32.6 million for the nine months ended September 30, 2012 compared to unrealized losses of $334.5 million during the nine months ended September 30, 2011. These derivatives were entered into to partially hedge the crack spreads for our refining business. In addition to these impacts, during the nine months ended September 30, 2012, we entered into arrangements to settle or re-price a portion of our existing derivative instruments ahead of their respective expiration dates and incurred $136.8 million of realized losses related to these early extinguishments. We settled $92 million of this early extinguishment obligation out of the net proceeds of our initial public offering.

 

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Interest expense, net.  Interest expense, net was $36.7 million for the nine months ended September 30, 2012 and $30.6 million for the nine months ended September 30, 2011. These interest charges relate primarily to the 2017 Notes as well as commitment fees and interest on the ABL facility and the amortization of deferred financing costs. The increase from the prior-year period is primarily due to the write-off of $4.6 million of deferred financing costs caused by the partial redemption of the 2017 Notes and the refinancing of our ABL facility. Additionally, the 2012 period includes approximately $0.9 million of incremental interest charges related to the 3% premium paid upon the partial redemption of the 2017 Notes.

Income tax provision.  The income tax provision for the nine months ended September 30, 2012 was $7.8 million compared to less than $0.1 million for the nine months ended September 30, 2011. Prior to July 31, 2012, we operated as a pass-through entity for federal tax purposes and, as such, only state taxes were recognized. Effective on July 31, 2012 our retail business became a tax paying entity for federal and state income taxes. The charge in the third quarter of 2012, relates primarily to the recognition of an $8.0 million net deferred tax liability on the effective date of the conversion of our retail business to a tax paying entity.

Net income (loss).  Our net income was $113.1 million for the nine months ended September 30, 2012 compared to a net loss of $264.4 million for the nine months ended September 30, 2011. This improvement of $377.5 million was primarily attributable to a $233.6 million increase in operating income for our refining segment due to refining gross margins in the second and third quarters of 2012 and a reduction in losses related to derivative activities of $311.7 million. These improvements were partially offset by a $141.9 million unfavorable impact in contingent consideration adjustments.

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

 

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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, 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 2017 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 decrease of 57.5% from the

 

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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 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

 

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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 the 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
		Nine Months Ended September 30, 2012
		Refining				Retail				Other/Elim				Consolidated
		(in millions)
Revenue:
Sales and other revenue		$	2,296.5			$	1,121.3			$	—			$	3,417.8
Intersegment sales			788.3				—				(788.3	)			—
Segment revenue		$	3,084.8			$	1,121.3			$	(788.3	)		$	3,417.8
Cost of sales:
Cost of sales		$	2,379.3			$	214.7			$	—			$	2,594.0
Intersegment purchases			—				788.3				(788.3	)			—
Segment cost of sales		$	2,379.3			$	1,003.0			$	(788.3	)		$	2,594.0

 

		Successor
		Nine Months Ended September 30, 2011
		Refining				Retail				Other/Elim				Combined
		(in millions)
Revenue:
Sales and other revenue		$	2,026.4			$	1,165.6			$	—			$	3,192.0
Intersegment sales			831.3				—				(831.3	)			—
Segment revenue		$	2,857.7			$	1,165.6			$	(831.3	)		$	3,192.0
Cost of sales:
Cost of sales		$	2,370.7			$	207.5			$	—			$	2,578.2
Intersegment purchases			—				831.3				(831.3	)			—
Segment cost of sales		$	2,370.7			$	1,038.8			$	(831.3	)		$	2,578.2

 

		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
Cost of sales:
Cost of sales		$	3,204.1			$	303.9			$	—			$	3,508.0
Intersegment purchases			—				1,043.1				(1,043.1	)			—
Segment cost of sales		$	3,204.1			$	1,347.0			$	(1,043.1	)		$	3,508.0

 

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		Successor
		June 23, 2010 (inception date) to December 31, 2010
		Refining				Retail				Other/Elim				Consolidated
		(in millions)
Revenue:
Sales and other revenue		$	242.0			$	102.9			$	—			$	344.9
Intersegment sales			70.2				—				(70.2	)			—
Segment revenue		$	312.2			$	102.9			$	(70.2	)		$	344.9
Cost of sales:
Cost of sales		$	287.2			$	20.2			$	0.1			$	307.5
Intersegment purchases			—				70.2				(70.2	)			—
Segment cost of sales		$	287.2			$	90.4			$	(70.1	)		$	307.5

 

		Predecessor
		Eleven Months Ended November 30, 2010
		Refining				Retail				Other				Combined
		(in millions)
Revenue:
Sales and other revenue		$	1,988.4			$	1,206.8			$	—			$	3,195.2
Intersegment sales			811.4				—				(811.4	)			—
Segment revenue		$	2,799.8			$	1,206.8			$	(811.4	)		$	3,195.2
Cost of sales:
Cost of sales		$	2,455.9			$	242.0			$	—			$	2,697.9
Intersegment purchases			—				811.4				(811.4	)			—
Segment cost of sales		$	2,455.9			$	1,053.4			$	(811.4	)		$	2,697.9

 

		Predecessor
		Year Ended December 31, 2009
		Refining				Retail				Other				Combined
		(in millions)
Revenue:
Sales and other revenue		$	1,811.3			$	1,129.2			$	—			$	2,940.5
Intersegment sales			719.4				—				(719.4	)			—
Segment revenue		$	2,530.7			$	1,129.2			$	(719.4	)		$	2,940.5
Cost of sales:
Cost of sales		$	2,252.1			$	255.8			$	—			$	2,507.9
Intersegment purchases			—				719.4				(719.4	)			—
Segment cost of sales		$	2,252.1			$	975.2			$	(719.4	)		$	2,507.9

 

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Refining Segment

 

		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				Nine Months Ended September 30,
																		2011				2012
		(Dollars in in millions, except per barrel data))
Revenue		$	2,530.7			$	2,799.8			$	312.2			$	3,804.1			$	2,857.7			$	3,084.8
Costs, expenses and other:
Cost of sales			2,252.1				2,455.9				287.2				3,204.1				2,370.7				2,379.3
Direct operating expenses			138.3				132.2				11.2				129.0				98.7				99.5
Turnaround and related expenses			0.6				9.5				—				22.6				22.5				17.1
Depreciation and amortization			26.0				24.9				1.7				21.5				16.0				18.5
Selling, general and administrative			44.2				40.0				3.1				45.3				27.0				19.0
Other income, net			(1.1	)			(5.5	)			(0.1	)			(6.6	)			(3.9	)			(8.9	)
Operating income		$	70.6			$	142.8			$	9.1			$	388.2			$	326.7			$	560.3
Key Operating Statistics:
Total refinery production (bpd)(1)			82,126				80,958				81,853				82,079				81,173				82,330
Total refinery throughput (bpd)			81,563				80,066				81,136				81,150				80,694				81,697
Refined products sold (bpd)(2)			87,572				86,682				95,122				86,038				85,170				86,960
Per barrel of throughput:
Refining gross margin(3)		$	9.36			$	12.86			$	9.94			$	20.26			$	22.11			$	31.52
Direct operating expenses(4)		$	4.65			$	4.94			$	4.45			$	4.36			$	4.48			$	4.45
Per barrel of refined products sold:
Refining gross margin(3)		$	8.72			$	11.88			$	8.48			$	19.11			$	20.95			$	29.61
Direct operating expenses(4)		$	4.33			$	4.56			$	3.80			$	4.11			$	4.24			$	4.18
Refinery product yields (bpd):
Gasoline			42,674				41,080				42,485				40,240				40,238				39,578
Distillate(5)			22,876				22,201				26,258				24,841				23,851				26,464
Asphalt			7,688				9,532				9,099				9,888				11,169				11,011
Other(6)			8,888				8,145				4,011				7,110				5,915				5,277
Total			82,126				80,958				81,853				82,079				81,173				82,330
Refinery throughput (bpd):
Crude oil			74,539				74,095				74,649				77,452				76,829				80,158
Other feedstocks(7)			7,024				5,971				6,487				3,698				3,865				1,539
Total			81,563				80,066				81,136				81,150				80,694				81,697
Market Statistics:
Crude Oil Average Pricing:
West Texas Intermediate ($/barrel)		$	62.09			$	78.69			$	89.23			$	95.11			$	95.47			$	95.84
PADD II / Group 3 Average Pricing:
Unleaded 87 Gasoline ($/barrel)		$	69.95			$	86.86			$	96.97			$	117.60			$	120.38			$	122.10
Ultra Low Sulfur Diesel ($/barrel)		$	70.20			$	90.38			$	103.38			$	126.26			$	126.35			$	128.51

 

(1)	Excludes fuel and coke on catalyst, which are used in our refining process. Also excludes purchased refined products.

 

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(2)	Includes produced and purchased refined products, including ethanol and biodiesel.

(3)

Refinery gross product margin per barrel is a per barrel measurement calculated by subtracting refinery costs of sales from total refinery revenues and dividing the difference by the total throughput or total refined products sold for the respective periods presented. Refinery gross product margin per barrel 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 may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. For a reconciliation of refinery gross product margin per barrel to refining segment revenue, the most directly comparable GAAP measure, see “Summary—Summary Historical Condensed Consolidated Financial and Other Data.”

(4)	Direct operating expenses per barrel is calculated by dividing direct operating expenses by the total barrels of throughput or total barrels of refined products sold for the respective periods presented.

(5)	Distillate includes diesel, jet fuel and kerosene.

(6)	Other refinery products include propane, propylene, liquid sulfur, light cycle oil and No. 6 fuel oil, among others. None of these products, by itself, contributes significantly to overall refinery product yields.

(7)	Other feedstocks include gas oil, natural gasoline, normal butane and isobutane, among others. None of these feedstocks, by itself, contributes significantly to overall refinery throughput.

Nine Months Ended September 30, 2012 Compared to the Nine Months Ended September 30, 2011

Revenue.  Revenue for the nine months ended September 30, 2012 was $3,084.8 million compared to $2,857.7 million for the nine months ended September 30, 2011, an increase of 8.0%. This increase was primarily due to a 2.4% increase in sales volumes for refined products and higher market prices for gasoline, distillate and asphalt in the nine months ended September 30, 2012. The higher refined product volumes came in the second and third quarters of 2012 and are primarily attributable to higher refining throughput. Excise taxes included in revenue were $207.9 million and $173.6 million for the nine months ended September 30, 2012 and 2011, respectively.

Cost of sales.  Cost of sales totaled $2,379.3 million for the nine months ended September 30, 2012 compared to $2,370.7 million for the nine months ended September 30, 2011, a 0.4% increase. This increase was primarily due to the impact of increased sales volumes, partially offset by lower raw material costs, driven principally by favorable crude differentials in the nine months ended September 30, 2012 compared to the 2011 period. Excise taxes included in cost of sales were $207.9 million and $173.6 million for the nine months ended September 30, 2012 and 2011, respectively. Refining gross product margin per barrel of throughput was $31.52 for the nine months ended September 30, 2012 compared to $22.11 for the nine months ended September 30, 2011, an increase of $9.41, or 42.6%, which is mostly attributable to improved crack spreads and improved differentials to market for both crude cost and refined products sold primarily in the second and third quarters of 2012.

Direct operating expenses.  Direct operating expenses totaled $99.5 million for the nine months ended September 30, 2012 compared to $98.7 million for the nine months ended September 30, 2011, a 0.8% increase. This increase was due primarily to costs recognized in the third quarter of 2012 quarter related to environmental compliance projects at our refinery’s wastewater treatment plant offset by lower utility expenses at the refinery, which resulted from decreases in natural gas prices across the nine months ended September 30, 2012 and reduced overall usage primarily during the first quarter of 2012.

Turnaround and related expenses.  Turnaround and related expenses totaled $17.1 million for the nine months ended September 30, 2012 compared to $22.5 million for the nine months ended September 30, 2011. Both periods include costs related to planned, partial turnarounds. The 2012 turnarounds include the alkylation unit, which was completed according to schedule in mid-May, and the No. 1 reformer unit, which was completed

 

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in early November. The 2011 turnaround was principally to replace 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 $18.5 million for the nine months ended September 30, 2012 compared to $16.0 million for the nine months ended September 30, 2011, an increase of 15.6%. This increase was primarily due to increased assets placed in service as a result of our capital expenditures since September 30, 2011, the most significant of which was our boiler replacement project which was placed in service in the fourth quarter of 2011.

Selling, general and administrative expenses.  Selling, general and administrative expenses were $19.0 million and $27.0 million for the nine months ended September 30, 2012 and 2011, respectively, a decrease of 29.6%. This decrease was due to the termination of our transition services agreement with Marathon in the fourth quarter of 2011, as a result of which we did not incur expenses related to the agreement in the nine months ended September 30, 2012. We are no longer using Marathon’s systems infrastructure.

Other income, net.  Other income, net was $8.9 million for the nine months ended September 30, 2012 compared to $3.9 million for the nine months ended September 30, 2011. This increase is driven primarily by an increase in equity income from our investment in Minnesota Pipe Line Company, LLC, which increased its tariff rates in the third quarter of 2011.

Operating income.  Income from operations was $560.3 million for the nine months ended September 30, 2012 compared to $326.7 million for the nine months ended September 30, 2011. This increase from the prior-year period of $233.6 million is primarily due to favorable crack spreads, crude differentials and higher throughput rates during the 2012 period.

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 $3,804.1 million compared to $2,799.8 million for the eleven months ended November 30, 2010, an increase of 24.5% from the average monthly run rate for the 2010 period. This increase was primarily due to an increase in third -party sales driven by higher average prices across our principal refined products sold and an increase in intersegment sales driven by a similar increase in average prices across our principal refined products sold. Excise taxes included in revenue were $232.8 million and $263.0 million for the year ended December 31, 2011 and the eleven months ended November 30, 2010, respectively.

Cost of sales.  Cost of sales totaled $3,204.1 million for the year ended December 31, 2011 compared to $2,455.9 million for the eleven months ended November 30, 2010, a 19.6% increase from the average monthly run rate for the 2010 period. This increase was primarily due to an increase in raw material costs driven principally by higher prices of crude oil and other feedstocks. Cost of sales as a percentage of revenue was 84.2% and 87.7% for the year ended December 31, 2011 and the eleven months ended November 30, 2010, respectively. This improvement is the result of higher revenue driven by market prices relative to the increased cost of crude. Excise taxes included in cost of sales were $232.8 million and $263.0 million for the year ended December 31, 2011 and the eleven months ended November 30, 2010, respectively.

Refinery gross product margin per barrel of throughput was $20.26 for the year ended December 31, 2011 compared to $12.86 for the eleven months ended November 30, 2010, an increase of $7.40, or 57.5%, which is primarily due to improved market conditions and favorable crude pricing.

Direct operating expenses.  Direct operating expenses totaled $129.0 million for the year ended December 31, 2011 compared to $132.2 million for the eleven months ended November 30, 2010, a 10.6% decrease from the average monthly run rate for the 2010 period. This variance was due to a decrease in normal

 

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maintenance costs for the year ended December 31, 2011. These resources were directed towards turnaround and related activities in 2011 as a result of the refinery turnaround in April 2011.

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 2011. 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 $21.5 million for the year ended December 31, 2011 compared to $24.9 million for the eleven months ended November 30, 2010, a decrease of 20.9% compared to the average monthly run rate for the 2010 period. This decrease was primarily due to the impact of an adjustment to the book value of our refinery as a result of the Marathon Acquisition as well as a change in the estimated useful life of the refinery assets.

Selling, general and administrative expenses.  Selling, general and administrative expenses were $45.3 million and $40.0 million for the year ended December 31, 2011 and the eleven months ended November 30, 2010, respectively. This 3.8% increase compared to the average monthly run rate for the 2010 period reflects higher administrative costs as we developed in 2011 our standalone infrastructure while continuing to pay transition services fees in 2011 to utilize Marathon systems.

Other income, net.  Other income, net was $6.6 million for the year ended December 31, 2011 compared to $5.5 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.

Operating income.  Income from operations was $388.2 million for the year ended December 31, 2011 compared to $142.8 million for the eleven months ended November 30, 2010. This increase was primarily due to higher crack spreads across our principal refined products sold which helped to increase our refinery gross product margin.

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

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 $312.2 million. The revenue for the period represents a 48.1% increase over the average monthly run rate for 2009. The increase relates primarily to an 8.6% increase in sales volumes per day and market pricing increases for refined products when compared to the average for 2009. Cost of sales totaled $287.2 million for the 2010 Successor Period. Cost of sales as a percentage of revenue was 92.0% and excise taxes included in both revenue and cost of sales were $24.3 million for the 2010 Successor Period. Refinery gross product margin per barrel of throughput was $9.94 for the 2010 Successor Period compared to $9.36 per barrel average monthly run rate for 2009.

Operating income for the 2010 Successor Period totaled $9.1 million, an improvement of $3.2 million versus the average monthly run rate of fiscal 2009. The improvement in operating income is due to the increased volumes of refined products sold and improved Group 3 3:2:1 crack spreads.

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

Revenue.  Revenue for the eleven months ended November 30, 2010 was $2,799.8 million compared to $2,530.7 million for the year ended December 31, 2009. The increase of 20.7% versus the 2009 average monthly

 

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run rate is due to an increase in the market prices for refined products which more than offset a 1.0% decline in sales volume per day. Included in revenue were excise taxes of $263.0 million and $280.3 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 $2,455.9 million compared to $2,252.1 million for the year ended December 31, 2009. The cost of sales for the eleven months represents a 19.0% increase over the average monthly run rate for fiscal 2009. The increase relates primarily to market increases in crude oil costs in the 2010 period compared to the average for 2009. Cost of sales as a percentage of revenue was 87.7% and 89.0% for the eleven months ended November 30, 2010 and year ended December 31, 2009, respectively. Excise taxes included in cost of sales were $263.0 million and $280.3 million for the eleven months ended November 30, 2010 and year ended December 31, 2009, respectively.

Refinery gross product margin per barrel of throughput was $12.86 for the eleven months ended November 30, 2010 and $9.36 for the year ended December 31, 2009. The increase was primarily due to improved market crack spreads in the 2010 period.

Direct operating expenses.  Direct operating expenses for the eleven months ended November 30, 2010 totaled $132.2 million compared to $138.3 million for the year ended December 31, 2009, a 4.4% increase compared to the 2009 average run monthly rate. The increase in direct operating expenses compared to the 2009 run rate is primarily due to higher utility costs during the 2010 period.

Turnaround and related expenses.  Turnaround and related expenses totaled $9.5 million and $0.6 million for the eleven months ended November 30, 2010 and year ended December 31, 2009, respectively. The increase in turnaround costs versus the prior year is due to the timing, nature and extent of turnaround activities completed in the two periods. The 2010 period included a scheduled partial turnaround at the refinery during September and October 2010. The units involved in this turnaround were the No. 2 crude unit, No. 2 vacuum unit and No. 2 sulfur recovery/Shell Claus Off-Gas Treating unit.

Depreciation and amortization.  Depreciation and amortization for the eleven months ended November 30, 2010 totaled $24.9 million compared to $26.0 million for the year ended December 31, 2009. The 4.4% increase versus average 2009 monthly run rate levels relates to the ongoing investment in the refinery infrastructure.

Selling, general and administrative expenses.  Selling, general and administrative expenses totaled $40.0 million and $44.2 million for the eleven months ended November 30, 2010 and year ended December 31, 2009, respectively, representing a reduction of 1.3% compared to the average monthly run rate levels of 2009. This reduction was primarily due to reduced shared service allocations from Marathon in the 2010 period.

Other income, net.  Other income, net for the eleven months ended November 30, 2010 totaled $5.5 million compared to $1.1 million for the year ended December 31, 2009. This increase is due to higher equity income from our investment in the Minnesota Pipe Line Company.

Operating income.  Income from operations for the eleven months ended November 30, 2010 totaled $142.8 million compared to $70.6 million for the year ended December 31, 2009. The increase is due to the higher crack spreads and refinery gross product margin and an increase in equity income from our investment in the Minnesota Pipe Line Company.

 

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Retail Segment

 

		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				Nine Months Ended September 30,
																		2011				2012
		(Dollars in in millions, except per gallon data))
Revenue		$	1,129.2			$	1,206.8			$	102.9			$	1,519.8			$	1,165.6			$	1,121.3
Costs, expenses and other:
Cost of sales			975.2				1,053.4				90.4				1,347.0				1,038.8				1,003.0
Direct operating expenses			100.0				94.9				10.2				131.3				93.8				89.6
Depreciation and amortization			14.2				12.4				0.5				7.2				6.0				5.6
Selling, general and administrative			20.5				19.6				1.3				20.3				19.8				17.9
Operating income		$	19.3			$	26.5			$	0.5			$	14.0			$	7.2			$	5.2
Operating data:
Company owned stores:
Fuel gallons sold (in millions)			335.7				316.0				29.1				324.0				245.8				231.6
Fuel margin per gallon(1)		$	0.14			$	0.17			$	0.16			$	0.21			$	0.20			$	0.17
Merchandise sales (in millions)		$	328.4			$	309.8			$	26.8			$	340.3			$	253.9			$	269.3
Merchandise margin %(2)			26.8	%			26.3	%			24.1	%			25.4	%			25.5	%			25.4	%
Number of stores at period end			166				166				166				166				166				166
Franchisee stores:
Fuel gallons sold			51.3				48.3				4.1				51.5				37.5				33.1
Royalty income		$	1.6			$	1.5			$	0.1			$	1.7			$	1.2			$	1.5
Number of stores at period end			68				67				67				67				67				68
Market Statistics:
PADD II gasoline prices ($/gallon)		$	2.34			$	2.76			$	3.00			$	3.53			$	3.60			$	3.67

 

(1)

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. For a reconciliation of retail fuel gross margin to retail segment operating income, the most directly comparable GAAP measure, see “Summary—Summary Historical Condensed Consolidated Financial and Other Data.”

(2)

Merchandise margin is expressed as a percentage of merchandise sales and is calculated by subtracting costs of merchandise from merchandise sales for company-operated stores, and then dividing by merchandise sales. Merchandise margin is a non-GAAP performance measure that we believe is important to investors in evaluating our retail performance. Our calculation of merchandise margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. For a reconciliation of merchandise margin to retail segment operating income, the most directly comparable GAAP measure, see “Summary—Summary Historical Condensed Consolidated Financial and Other Data.”

 

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Nine Months Ended September 30, 2012 Compared to the Nine Months Ended September 30, 2011

Revenue.  Revenue for the nine months ended September 30, 2012 was $1,121.3 million compared to $1,165.6 million for the nine months ended September 30, 2011, a decrease of 3.8%. This decrease was primarily due to a reduction in fuel sales driven primarily by lower sales volumes. We experienced a 5.8% decrease in fuel gallons sold in our retail segment compared to the prior year. The volume reduction in the 2012 period is primarily due to lower retail market demand for gasoline and road construction projects impacting our retail stores. Excise taxes included in revenue were $7.1 million for the nine months ended September 30, 2012 and $7.9 million for the nine months ended September 30, 2011.

Cost of sales.  Cost of sales totaled $1,003.0 million for the nine months ended September 30, 2012 and $1,038.8 million for the nine months ended September 30, 2011, a decrease of 3.4%. Excise taxes included in cost of sales were $7.1 million for the nine months ended September 30, 2012 and $7.9 million for the nine months ended September 30, 2011. For company-operated stores, retail fuel margin per gallon was $0.17 for the nine months ended September 30, 2012 compared to $0.20 per gallon for the nine months ended September 30, 2011. This reduction in fuel margin per gallon relates to a spike in competitive pricing actions in the local market that occurred during the middle of the third quarter of 2012 in response to reduced volume levels across the local market.

Direct operating expenses.  Direct operating expenses totaled $89.6 million for the nine months ended September 30, 2012 compared to $93.8 million for the nine months ended September 30, 2011, a decrease of 4.5% from the 2011 period due to reductions in convenience store operating costs as a result of cost reduction efforts.

Depreciation and amortization.  Depreciation and amortization was $5.6 million for the nine months ended September 30, 2012 compared to $6.0 million for the nine months ended September 30, 2011, a decrease of 6.7%. During 2011, our continuing involvement ended for a subset of our retail stores which did not meet the criteria for sales-leaseback treatment at the time of the Marathon Acquisition. As such, the related fair value of the assets for these stores was removed from the consolidated balance sheet and was no longer depreciated. This reduction in depreciation was partially offset by increases related to our capital expenditures since September 30, 2011.

Selling, general and administrative expenses.  Selling, general and administrative expenses were $17.9 million and $19.8 million for the nine months ended September 30, 2012 and 2011, respectively, which represents a decrease of 9.6% from the 2011 period. This reduction primarily relates to lower back office costs in 2012 period. In the 2011 period our back office costs were higher as we developed our stand-alone infrastructure while continuing to pay transition services fees to utilize the Speedway back office infrastructure.

Operating income.  Operating income was $5.2 million for the nine months ended September 30, 2012 compared to $7.2 million for the nine months ended September 30, 2011, a reduction of $2.0 million. The reduction is primarily attributable to lower fuel margins per gallon and lower fuel volumes partially offset by higher merchandise gross margin and lower operating expenses during the nine months ended September 30, 2012.

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 $1,519.8 million compared to $1,206.8 million for the eleven months ended November 30, 2010, an increase of 15.4% from the average monthly run rate for the 2010 period. This increase was primarily due to an increase in fuel sales driven by higher average prices of the fuels sold. Partially offsetting this increase was the impact of lower fuel volumes sold and lower merchandise sales. Poor weather conditions early in the year and higher priced gasoline resulted in 6.0% less fuel gallons sold in our retail segment compared to the average monthly run rate for the 2010 period. Excise taxes included in revenue were $10.1 million for the year ended December 31, 2011 and $8.8 million for the eleven months ended November 30, 2010.

 

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Cost of sales.  Cost of sales totaled $1,347.0 million for the year ended December 31, 2011 compared to $1,053.4 million for the eleven months ended November 30, 2010, an increase of 17.2% from the average monthly run rate for the 2010 period. This increase was primarily due to higher prices for purchased fuel. Cost of sales as a percentage of revenue was 88.6% and 87.3% for the year ended December 30, 2011 and the eleven months ended November 30, 2010, respectively. Excise taxes included in cost of sales were $10.1 million for the year ended December 31, 2011 and $8.8 million for the eleven months ended November 30, 2010. For company-operated stores, retail fuel margin per gallon was $0.21 for the year ended December 31, 2011 and $0.17 per gallon for the eleven months ended November 30, 2010. The increased fuel margin per gallon in 2011 is due to generally stronger local market conditions.

Direct operating expenses.  Direct operating expenses totaled $131.3 million for the year ended December 31, 2011 compared to $94.9 million for the eleven months ended November 30, 2010, an increase of 26.8% from the average monthly run rate for the 2010 period. This increase was primarily due to higher rent expense as well as increased credit card fees due to higher fuel prices. Concurrent with the Marathon Acquisition, we entered into a sale-leaseback arrangement for the majority of our convenience stores. We therefore have operating leases for the majority of our convenience stores, which results in higher rent expense.

Depreciation and amortization.  Depreciation and amortization was $7.2 million for the year ended December 31, 2011 compared to $12.4 million for the eleven months ended November 30, 2010, a decrease of 46.8% from the average monthly run rate for the 2010 period. Due to the sale-leaseback arrangement noted above, we have operating leases for the majority of our convenience stores, which results in lower depreciation costs.

Selling, general and administrative expenses.  Selling, general and administrative expenses were $20.3 million and $19.6 million for the year ended December 31, 2011 and the eleven months ended November 30, 2010, respectively, which represents a decrease of 5.1% from the average monthly run rate for the 2010 period. This decrease is primarily the result of timing differences for certain services incurred such as advertising expenses and other administrative expenses.

Operating income.  Income from operations was $14.0 million for the year ended December 31, 2011 compared to $26.5 million for the eleven months ended November 30, 2010, a decrease of 51.6% from the average monthly run rate for the 2010 period. The decrease in operating income is attributable to increased direct operating expenses caused by higher rents, lower merchandise volumes and increased credit card fees, which more than offset improved fuel margins and lower depreciation and selling, general and administrative expenses.

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

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 $102.9 million, an increase of 9.4% compared to the monthly average run rate for fiscal 2009. The increase in the 2010 Successor Period as compared to the 2009 average monthly run rate is due to higher average market prices for fuel and a 4.0% increase in fuel volumes, which more than offset a 2.1% decline in merchandise revenue in the period. Cost of sales for the 2010 Successor Period was $90.4 million, an 11.2% increase from the 2009 average monthly run rate. Cost of sales as a percentage of revenue was 87.9% for the 2010 Successor Period compared to 86.4% for 2009. Excise taxes included in revenue and cost of sales were $0.8 million for the 2010 Successor Period. For company-operated stores, retail fuel margin per gallon was $0.16 for the 2010 Successor Period compared to $0.14 during 2009.

Income from operations for the 2010 Successor Period totaled $0.5 million compared to average monthly run rate operating income of $1.6 million for 2009.

 

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

Revenue.  Revenue for the eleven months ended November 30, 2010 was $1,206.8 million compared to $1,129.2 million for the year ended December 31, 2009, an increase of 16.6% compared to the average monthly run rate for 2009. The increase in the 2010 period as compared to the 2009 average monthly run rate levels is due to higher average market prices for fuel, a 2.7% increase in fuel volumes and a 2.9% increase in merchandise revenue in the period. Excise taxes included in revenue totaled $8.8 million and $9.3 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 $1,053.4 million compared to $975.2 million for the year ended December 31, 2009, an increase of 17.8% from the 2009 average monthly run rate due to higher average fuel costs in the 2010 period. Cost of sales as a percentage of revenue was 87.3% and 86.4% for the eleven months ended November 30, 2010 and year ended December 31, 2009, respectively. Excise taxes included in cost of sales were $8.8 million and $9.3 million for the eleven months ended November 30, 2010 and year ended December 31, 2009, respectively. For company-operated stores, retail fuel margin per gallon was $0.17 for the eleven months ended November 30, 2010 and $0.14 per gallon for the year ended December 31, 2009.

Direct operating expenses.  Direct operating expenses totaled $94.9 million and $100.0 million for the eleven months ended November 30, 2010 and year ended December 31, 2009, respectively, a 3.5% increase compared to the 2009 average monthly run rate levels. This increase in the period is primarily due to higher credit card fees associated with the higher average selling prices for fuel.

Depreciation and amortization.  Depreciation and amortization was $12.4 million for the eleven months ended November 30, 2010 compared to $14.2 million for the year ended December 31, 2009, a 4.7% decrease from the average monthly run rate for 2009.

Selling, general and administrative expenses.  Selling, general and administrative expenses for the eleven months ended November 30, 2010 were $19.6 million compared to $20.5 million for the year ended December 31, 2009, a 4.3% increase from the average monthly run rate levels for 2009.

Operating income.  Income from operations the eleven months ended November 30, 2010 totaled $26.5 million compared to $19.3 million for the year ended December 31, 2009, an increase of 49.8% from the 2009 average monthly run rate levels. The improvement in operating income for the 2010 period is primarily due to higher fuel margins per gallon and higher fuel volumes compared to the 2009 average monthly run rate levels.

Adjusted EBITDA

Our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with the board of directors of our general partner, creditors, analysts and investors concerning our financial 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. The revolving credit facility and other contractual obligations also include similar measures as a basis for certain covenants under those agreements which may differ from the Adjusted EBITDA definition described below.

Adjusted EBITDA is not a presentation made in accordance with GAAP and our computation of Adjusted EBITDA may vary from others in our industry. In addition, Adjusted EBITDA contains some, but not all, adjustments that are taken into account in the calculation of the components of various covenants in the agreements governing the notes, the revolving credit facility, earn-out, margin support and management services. Adjusted EBITDA should not be considered as an alternative to operating earnings or net (loss) earnings as

 

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measures of operating performance. In addition, Adjusted EBITDA is not presented as and should not be considered an alternative to cash flows from operations as a measure of liquidity. 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. Other companies, including 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 investment, but includes 17% of the calculated EBITDA of Minnesota Pipe Line;

 

•

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 tables reconcile net (loss) earnings as reflected in the results of operations tables and segment footnote disclosures to Adjusted EBITDA for the periods presented:

 

		Successor
		Nine Months Ended September 30, 2012
		Refining				Retail				Other				Total
		(in millions)
Net income (loss)		$	560.3			$	5.2			$	(452.4	)		$	113.1
Adjustments:
Interest expense			—				—				36.7				36.7
Income tax provision			—				—				7.8				7.8
Depreciation and amortization			18.5				5.6				0.5				24.6
EBITDA subtotal			578.8				10.8				(407.4	)			182.2
Minnesota Pipe Line proportionate EBITDA			2.1				—				—				2.1
Turnaround and related expenses			17.1				—				—				17.1
Equity-based compensation expense			—				—				1.4				1.4
Unrealized gains on derivative activities			—				—				(32.6	)			(32.6	)
Contingent consideration loss			—				—				104.3				104.3
Loss on early extinguishment of derivatives			—				—				136.8				136.8
Formation costs			—				—				1.0				1.0
Realized losses on derivative activities			—				—				165.0				165.0
Adjusted EBITDA		$	598.0			$	10.8			$	(31.5	)		$	577.3

 

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		Successor
		Nine Months Ended September 30, 2011
		Refining				Retail				Other				Total
		(in millions)
Net income (loss)		$	326.7			$	7.2			$	(598.3	)		$	(264.4	)
Adjustments:
Interest expense			—				—				30.6				30.6
Depreciation and amortization			16.0				6.0				0.3				22.3
EBITDA subtotal			342.7				13.2				(567.4	)			(211.5	)
Minnesota Pipe Line proportionate EBITDA			2.7				—				—				2.7
Turnaround and related expenses			22.5				—				—				22.5
Equity-based compensation expense			—				—				1.1				1.1
Unrealized losses on derivative activities			—				—				334.5				334.5
Contingent consideration income			—				—				(37.6	)			(37.6	)
Formation costs			—				—				6.1				6.1
Realized losses on derivative activities			—				—				246.4				246.4
Adjusted EBITDA		$	367.9			$	13.2			$	(16.9	)		$	364.2

 

		Successor
		Year Ended December 31, 2011
		Refining				Retail				Other				Total
		(in millions)
Net income (loss)		$	388.2			$	14.0			$	(373.9	)		$	28.3
Adjustments:
Interest expense			—				—				42.1				42.1
Depreciation and amortization			21.5				7.2				0.8				29.5
EBITDA subtotal			409.7				21.2				(331.0	)			99.9
Minnesota Pipe Line proportionate EBITDA			2.8				—				—				2.8
Turnaround and related expenses			22.6				—				—				22.6
Equity-based compensation expense			—				—				1.6				1.6
Unrealized losses on derivative activities			—				—				41.9				41.9
Contingent consideration income			—				—				(55.8	)			(55.8	)
Formation costs			—				—				7.4				7.4
Realized losses on derivative activities			—				—				310.3				310.3
Adjusted EBITDA		$	435.1			$	21.2			$	(25.6	)		$	430.7

 

		Successor
		June 23, 2010 (inception date) to December 31, 2010
		Refining				Retail				Other				Total
		(in millions)
Net income (loss)		$	9.1			$	0.5			$	15.2			$	24.8
Adjustments:
Interest expense			—				—				3.2				3.2
Depreciation and amortization			1.7				0.5				—				2.2
EBITDA subtotal			10.8				1.0				18.4				30.2
Minnesota Pipeline proportionate EBITDA			0.3				—				—				0.3
Stock-based compensation expense			—				—				0.1				0.1
Unrealized losses on derivative activities			—				—				27.1				27.1
Formation costs			—				—				3.6				3.6
Bargain purchase gain			—				—				(51.4	)			(51.4	)
Adjusted EBITDA		$	11.1			$	1.0			$	(2.2	)		$	9.9

 

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		Predecessor
		Eleven Months Ended November 30, 2010
		Refining				Retail				Other				Total
		(in millions)
Net income (loss)		$	142.8			$	26.5			$	(108.3	)		$	61.0
Adjustments:
Interest expense			—				—				0.3				0.3
Income tax provision			—				—				67.1				67.1
Depreciation and amortization			24.9				12.4				—				37.3
EBITDA subtotal			167.7				38.9				(40.9	)			165.7
Minnesota Pipeline proportionate EBITDA			3.7				—				—				3.7
Turnaround and related expenses			9.5				—				—				9.5
Stock-based compensation expense			0.3				—				—				0.3
Unrealized losses on derivative activities			—				—				40.9				40.9
Adjusted EBITDA		$	181.2			$	38.9			$	—			$	220.1

 

		Predecessor
		Year Ended December 31, 2009
		Refining				Retail				Other				Total
		(in millions)
Net income (loss)		$	70.6			$	19.3			$	(35.2	)		$	54.7
Adjustments:
Interest expense			—				—				0.4				0.4
Income tax provision			—				—				34.8				34.8
Depreciation and amortization			26.0				14.2				—				40.2
EBITDA subtotal			96.6				33.5				—				130.1
Minnesota Pipeline proportionate EBITDA			4.2				—				—				4.2
Turnaround and related expenses			0.6				—				—				0.6
Stock-based compensation expense			0.3				—				—				0.3
Adjusted EBITDA		$	101.7			$	33.5			$	—			$	135.2

Liquidity and Capital Resources

Our primary sources of liquidity have traditionally been cash generated from our operating activities and borrowings under our revolving credit facility. Our ability to generate sufficient cash flows from our operating activities will continue to be primarily dependent on producing or purchasing and selling sufficient quantities of refined products and merchandise at margins sufficient to cover fixed and variable expenses. Part of our long-term strategy is to increase cash available for distribution to our unitholders by making strategic acquisitions. Our ability to make these acquisitions in the future will depend largely on the availability of debt financing and on our ability to periodically use equity financing through the issuance of new common units. Future financing will depend on various factors, including prevailing market conditions, interest rates and our financial condition and credit rating. For discussions on our refinery gross product margin per barrel and retail fuel margin per gallon and merchandise margin for company-operated stores, see “—Results of Operations—Refining Segment” and “—Results of Operations—Retail Segment,” and for discussions on factors that affect our results of operations, see “—Major Influences on Results of Operations.” For more information on our revolving credit facility, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Description of Our Indebtedness—Senior Secured Asset-Based Revolving Credit Facility.”

On July 31, 2012, we closed our initial public offering of 18,687,500 common units. We used the net proceeds from our initial public offering of approximately $245 million and cash on hand of approximately

 

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$56 million to: (i) distribute approximately $124 million to Northern Tier Holdings LLC, of which approximately $92 million was used to redeem Marathon’s existing preferred interest in Northern Tier Holdings LLC and $32 million was distributed to ACON Refining, TPG Refining and entities in which our President and Chief Executive Officer holds an ownership interest, (ii) pay $92 million to J. Aron & Company, an affiliate of Goldman, Sachs & Co., related to deferred payment obligations from the early extinguishment of derivatives, (iii) pay $40 million to Marathon, which represents the cash component of a settlement agreement Northern Tier Energy LLC entered into with Marathon in satisfaction of a contingent consideration arrangement that was part of the Marathon Acquisition, (iv) redeem $29 million of the 2017 Notes at a redemption price of 103% of the principal amount thereof, plus accrued interest, for an estimated $31 million, and (v) pay other offering costs of approximately $15 million. Subsequent to our initial public offering, we may increase future liquidity via the sale of additional common units.

On November 8, 2012, we completed a private placement of the 2020 Notes. We used the net proceeds of the offering and cash on hand of $31 million (i) to repurchase our outstanding 2017 Notes that were tendered pursuant to our previously announced tender offer and (ii) to satisfy and discharge any remaining 2017 Notes outstanding (which notes were called for redemption after the closing of the tender offer) and to pay related fees and expenses. The 2020 Indenture has substantially the same covenants as the 2017 Indenture, except that under the 2020 Indenture we may distribute all of our available cash (as defined in the 2020 Indenture) to our unitholders if we maintain a fixed charge coverage ratio of 1.75 to 1.

In connection with the transactions described in the preceding paragraph, our PIK units converted into common units representing limited partner interests with the same rights and limitations as our existing common units, effective November 9, 2012.

The repurchase of the 2017 Notes resulted in an after-tax charge of approximately $48 million.

Based on current and anticipated levels of operations and conditions in our industry and markets, we believe that cash on hand, together with cash flows from operations and borrowings available to us under our revolving credit facility, will be adequate to meet our ordinary course working capital, capital expenditures, debt service and other cash requirements for at least the next twelve months.

We may use a variety of derivative instruments to enhance the stability of our cash flows. In general, we may attempt to mitigate risks related to the variability of our future cash flow and profitability resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures and similar requirements. See “—Quantitative and Qualitative Disclosures About Market Risk.” During the nine months ended September 30, 2012, we settled contracts covering approximately three million barrels of our remaining 2012 gasoline and diesel production and recognized a loss of approximately $44.6 million. 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 used $92 million of the net proceeds from our initial public offering to settle the majority of these obligations. The remainder of these deferred losses of approximately $45 million will be paid through the end of 2013. As of September 30, 2012, $35.9 million of this liability is included in current liabilities and $5.2 million is included in non-current liabilities with the final amount to be paid in December 2013.

 

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Cash Flows

The following table sets forth our cash flows for the periods indicated:

 

		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				Nine Months Ended September 30,
																		2011				2012
		(In millions)
Net cash provided by operating activities		$	129.4			$	145.4			$	—			$	209.3			$	194.9			$	174.8
Net cash used in investing activities			(25.0	)			(29.3	)			(363.3	)			(156.3	)			(138.5	)			(12.0	)
Net cash provided by (used in) financing activities			(103.9	)			(115.4	)			436.1				(2.3	)			(2.5	)			37.2
Net increase in cash and cash equivalents			0.5				0.7				72.8				50.7				53.9				200.0
Cash and cash equivalents at beginning of period			5.5				6.0				—				72.8				72.8				123.5
Cash and cash equivalents at end of period		$	6.0			$	6.7			$	72.8			$	123.5			$	126.7			$	323.5

Net Cash Provided By Operating Activities.  Net cash provided by operating activities for the nine months ended September 30, 2012 was $174.8 million. The most significant providers of cash were our operating income ($426.8 million) adjusted for non-cash adjustments, such as depreciation and amortization expense ($24.6 million) and contingent consideration loss ($104.3 million). Offsetting these impacts were realized losses from derivative activities ($165.0 million) and increases in accounts receivable ($52.7 million).

Net cash provided by operating activities for the nine months ended September 30, 2011 was $194.9 million. The most significant providers of cash were operating income ($347.1 million) adjusted for non-cash adjustments, such as depreciation and amortization ($22.3 million) and contingent consideration income ($37.6 million). Additionally, cash was provided by reduced other current assets ($15.9 million) and increased accounts payable and accrued expenses ($119.2 million). Offsetting these sources of cash were realized losses from derivative activities ($246.4 million).

Net cash provided by operating activities for the year ended December 31, 2011 was $209.3 million. The most significant providers of cash were our net earnings ($28.3 million) adjusted for non-cash adjustments, such as depreciation and amortization expense ($29.5 million), unrealized losses from derivative activities ($41.9 million) and non-cash contingent consideration income ($55.8 million). Additionally, cash was provided by decreases in accounts receivable ($18.3 million) and increases in accounts payable and accrued expenses ($146.4 million).

Net cash used in operating activities for the 2010 Successor Period was less than $0.1 million. The most significant providers of cash were net earnings ($24.8 million) and adjustments to reconcile net earnings to net cash provided from operating activities, such as depreciation and amortization ($2.2 million), unrealized losses from derivative activities ($27.1 million), changes in inventories ($38.6 million) and changes in accounts payable and accrued expenses ($86.4 million). These increases in cash were offset by a net cash outflow from changes in current receivables ($100.2 million), changes in other current assets ($27.7 million) and an adjustment for non-cash bargain purchase gain ($51.4 million).

Net cash provided by operating for the eleven months ended November 30, 2010 was $145.4 million. The most significant providers of cash were net earnings ($61.0 million) and adjustments to reconcile net earnings to

 

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net cash provided from operating activities, such as depreciation and amortization ($37.3 million), unrealized losses from derivative activities ($40.9 million) and changes in accounts payable and accrued expenses ($23.8 million). These increases in cash were partially offset by a net cash outflow from changes in current receivables ($17.5 million).

Net cash provided by operating activities for the fiscal year ended December 31, 2009 was $129.4 million. The most significant providers of cash were our net earnings ($54.7 million) and adjustments to reconcile net earnings to net cash provided from operating activities, such as depreciation and amortization ($40.2 million) and changes in current accounts payable and accrued expenses ($31.2 million) and receivables from/payables to related parties ($23.8 million). These increases in cash were partially offset by a net cash outflow from changes in accounts receivables ($14.7 million) and inventories ($6.8 million).

Changes in accounts payable and receivable and accrued expenses described above primarily relate to the changes in our total revenue, costs and expenses for such period discussed above under “Results of Operations.” Other factors affecting these changes were not material.

Net Cash Used In Investing Activities.  Net cash used in investing activities for the nine months ended September 30, 2012 was $12.0 million, relating primarily to capital expenditures of $13.3 million.

Net cash used in investing activities for the nine months ended September 30, 2011 was $138.5 million, relating primarily to capital expenditures ($27.4 million) and cash paid to Marathon as part of the Marathon Acquisition ($112.8 million).

Net cash used in investing activities for the year ended December 31, 2011 was $156.3 million, relating primarily to capital expenditures ($45.9 million) and cash paid to Marathon Oil with respect to a payable related to crude oil inventory purchased as part of Marathon Acquisition ($112.8 million). Capital spending for the year ended December 31, 2011 primarily included a multi-year boiler replacement project at the refinery, safety related enhancements and facility improvements at the refinery and the implementation of our new information and accounting systems.

Net cash used in investing activities for the 2010 Successor Period was $363.3 million, primarily relating to net cash paid for the Marathon Acquisition ($360.8 million).

Net cash used in investing activities for the eleven months ended November 30, 2010 was $29.3 million, primarily relating to capital expenditures ($29.8 million). Capital spending for the eleven months ended November 30, 2010 primarily included ongoing expenditures related to the revamp of the No. 2 crude unit, the multi-year boiler replacement project at the refinery, safety related enhancements and facility improvements at the refinery.

Net cash used in investing activities for the year ended December 31, 2009 was $25.0 million, primarily relating to capital expenditures ($29.0 million), partially offset by the return of capital on our cost method investment ($3.3 million). Capital spending for 2009 included ongoing expenditures related to the revamp of the No. 2 crude unit, the multi-year boiler replacement project at the refinery, safety related enhancements and facility improvements.

Net Cash Provided By (Used In) Financing Activities.  Net cash provided by financing activities for the nine months ended September 30, 2012 was $37.2 million. The net proceeds from our initial public offering of $245 million were the primary source of cash from financing activities. Out of those proceeds, we repaid $29.0 million of the 2017 Notes, distributed $124.2 million to Northern Tier Holdings LLC and paid $15 million of offering costs. Additionally, during the second quarter of 2012 we made an equity distribution in the amount of $40 million to Northern Tier Holdings LLC. Net cash used in financing activities was $2.3 million for the year ended December 31, 2011, representing tax distributions to Northern Tier Holdings LLC. Net cash from financing activities for the 2010 Successor Period were $436.1 million representing borrowing from the 2017

 

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Notes ($290.0 million) and investments from members ($180.2 million) offset by financing costs related to the establishment of our credit facilities ($34.1 million). Net cash used in financing activities for the eleven months ended November 30, 2010 and the year ended December 31, 2009 were $115.4 million and $103.9 million, respectively, each representing net distributions to Marathon.

Working Capital

Working capital at September 30, 2012 was $298.6 million, consisting of $642.8 million in total current assets and $344.2 million in total current liabilities.

Working capital at December 31, 2011 was $77.4 million, consisting of $425.0 million in total current assets and $347.6 million in total current liabilities. The working capital at December 31, 2011 was impacted by the short-term derivative liability for unrealized losses of $109.9 million related to our crack spread risk management program. The offsetting benefits related to these unrealized losses should be realized over future periods as improved crack spread margins are realized. Working capital at December 31, 2010 was $108.6 million, consisting of $358.1 million in total current assets and $249.5 million in total current liabilities.

At the closing of the Marathon Acquisition, we entered into a crude oil and 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 at Cottage Grove, Minnesota, which are approximately two miles from our refinery. In March 2012, we amended and restated the crude oil supply and logistics agreement with JPM CCC. Upon delivery of the crude oil to us 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.

Our Distribution Policy

We expect within 60 days after the end of each quarter to make distributions to unitholders of record on the applicable record date. The board of directors of our general partner adopted a policy pursuant to which distributions for each quarter will equal the amount of available cash we generate in such quarter. Distributions on our units will be in cash. 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 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

 

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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 2020 Notes and our revolving credit facility may restrict the ability of Northern Tier Energy LLC, our operating subsidiary, to distribute cash to us. See “—Description of Our Indebtedness.”

Acquisition Financing

We financed the Marathon Acquisition through a combination of capital contributions from ACON Refining, TPG Refining, and certain members of our senior management, the issuance of an $80 million noncontrolling preferred membership interest to Marathon, the issuance of $290 million in the 2017 Notes and through certain third-party transactions. See “—Comparability of Historical Results.”

Capital Spending

Capital spending was $13.3 million for the nine months ended September 30, 2012, which primarily included safety related enhancements and facility improvements at the refinery and the implementation of our new information and accounting systems. We currently expect to spend an aggregate of approximately $20 to $25 million in capital expenditures during 2012.

Capital spending for the year ended December 31, 2011 primarily included a multi-year boiler replacement project at the refinery, safety related enhancements and facility improvements at the refinery and the implementation of our new information and accounting systems. We completed a multi-year boiler replacement project, which entailed $19.9 million of capital expenditures over the project life, $12.7 million during the period from 2008 through November 30, 2010 and $7.2 million during the period from December 1, 2010 through December 31, 2011.

Contractual Obligations and Commitments

We have the following contractual obligations and commitments as of December 31, 2011:

 

		Payments Due by Period
		Less than 1 year				1-3 Years				3-5 Years				More than 5 Years				Total
		(In millions)
Long-term debt(1)		$	32.3			$	64.7			$	62.8			$	320.5			$	480.3
Lease obligations(2)			22.2				43.6				42.1				180.3				288.2
Capital expenditures(3)			1.4				—				—				—				1.4
Environmental remediation costs			4.2				1.5				1.0				1.9				8.6

 

(1)

Long-term debt represents (i) the repayment of the $290 million of the 2017 Notes at their 2017 maturity date, (ii) cash interest payments for the 2017 Notes through the 2017 maturity date and (iii) commitment fees of 0.625% on an assumed $300 million undrawn balance under our revolving credit facility (prior to the July 17, 2012 amendment) with a maturity date of 2015.

(2)

Lease obligations represent payments for a variety of facilities and equipment under lease, including existing real property leases and payments pursuant to our lease arrangement with Realty Income, office equipment and vehicles, as well as rail tracks for storage of rail tank cars near the refinery and numerous rail tank cars.

(3)	Capital expenditures represent our contractual commitments to acquire property, plant and equipment.

 

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Off-Balance Sheet Arrangements

Historically we have not had any off-balance sheet arrangements. In connection with the closing of the Marathon Acquisition, we entered into a lease arrangement with Realty Income, pursuant to which we leased 135 SuperAmerica convenience stores and one support facility over a 15-year initial term at an aggregate annual rent fixed for five years at an annual rate of $20.3 million, with consumer price index-based rent increases thereafter. For more information on the sale-leaseback arrangement, see “—Comparability of Historical Results.”

Description of Our Indebtedness

Senior Secured Asset-Based Revolving Credit Facility

At the closing of the Marathon Acquisition, we and certain of our subsidiaries (the “ABL Borrowers”) entered into an asset-backed lending facility with JP Morgan Chase Bank, N.A. as administrative agent and collateral agent (the “ABL Agent”), Bank of America, N.A., as syndication agent, and lenders party thereto. On July 17, 2012, we entered into an amendment of this asset-backed lending facility. Our revolving credit facility provides for revolving credit financing through July 17, 2017 in an aggregate principal amount of up to $300 million (of which $150 million may be utilized for the issuance of letters of credit and up to $30 million may be short-term borrowings upon same-day notice, referred to as swingline loans) and may be increased up to a maximum aggregate principal amount of $450 million, subject to borrowing base availability and lender approval. Availability under our revolving credit facility at any time will be the lesser of (a) the aggregate commitments under our revolving credit facility and (b) the borrowing base, less any outstanding borrowings and letters of credit. The borrowing base is calculated based on a percentage of eligible accounts receivable, petroleum inventory and other assets.

Borrowings under our revolving credit facility bear interest, at our option, at either (a) an alternative base rate, plus an applicable margin (ranging between 1.00% and 1.50%) or (b) a LIBOR rate plus an applicable margin (ranging between 2.00% and 2.50%). The alternative base rate is the greater of (a) the prime rate, (b) the Federal Funds Effective Rate plus 50 basis points, or (c) the one-month LIBOR rate plus 100 basis points and a spread of up to 150 basis points based upon percentage utilization of this facility. In addition to paying interest on outstanding borrowings, we are also required to pay an annual commitment fee ranging from 0.375% to 0.500% and letter of credit fees.

As of December 31, 2011 and the nine months ended September 30, 2012, the availability under our revolving credit facility was $108.0 million and $168.0 million, respectively. This availability is net of $61.6 million and $24.0 million in outstanding letters of credit as of December 31, 2011 and the nine months ended September 30, 2012, respectively. We had no borrowings under our revolving credit facility at either December 31, 2011 or September 30, 2012.

In order to borrow under our revolving credit facility, if the amount available under our revolving credit facility is less than the greater of (i) 12.5% of the lesser of (x) the $300 million commitment amount and (y) the then-applicable borrowing base and (ii) $22.5 million, the ABL Borrowers must comply with a minimum fixed charge coverage ratio of at least 1.0 to 1.0. As of September 30, 2012, the most recent determination date, the fixed charge coverage ratio was 7.0 to 1.0.

Our revolving credit facility contains a negative covenant restricting the ABL Borrowers’ ability to incur additional debt, subject to certain exceptions, including, but not limited to, the following:

 

•

indebtedness existing under our revolving credit facility or that was existing as of December 1, 2010, as set forth in our revolving credit facility;

 

•

intercompany indebtedness, provided that such indebtedness would be permitted as an investment under our revolving credit facility, such indebtedness is evidenced by an intercompany note in the specified form or such indebtedness was in existence as of December 1, 2010 and such indebtedness is evidenced by an intercompany note;

 

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•

certain guarantees by the ABL Borrowers and their affiliates;

 

•

indebtedness incurred exclusively to finance the acquisition, lease, construction, repair, renovations, replacement, expansion or improvement of any fixed or capital assets or otherwise incurred in respect of capital expenditures, not to exceed the greater of (i) $20 million and (ii) 2.5% of the ABL Borrowers’ total assets (in each case determined as of the date of incurrence);

 

•

the extension, refinancing, refunding, replacement or renewal of any permitted indebtedness, subject to certain exceptions, as described in our revolving credit facility;

 

•

indebtedness incurred by us, or any of our subsidiaries, with respect to letters of credit, bank guarantees, bankers’ acceptances, warehouse receipts, or similar instruments issued or created in the ordinary course of business, provided that upon the drawing of such letters of credit or the incurrence of such indebtedness, such obligations are reimbursed within 30 days following such drawing or incurrence;

 

•

indebtedness of an entity that becomes a subsidiary after December 1, 2010 and indebtedness acquired or assumed in connection with acquisitions permitted under our revolving credit facility, so long as (i) such indebtedness exists at the time such entity becomes a subsidiary or at the time of such permitted acquisition and is not created in contemplation of or in connection with a permitted acquisition and (ii) such indebtedness is not guaranteed by us or our subsidiaries;

 

•

indebtedness of any of our subsidiaries issued or incurred to finance acquisitions permitted under our revolving credit facility, subject to certain exceptions as described in our revolving credit facility;

 

•

indebtedness and guarantees with respect to the 2020 Notes in an aggregate principal amount that is not in excess of $275 million;

 

•

other indebtedness in an aggregate principal amount not exceeding $50 million; and

 

•

unsecured subordinated indebtedness of ours or any subsidiary and any other unsecured indebtedness so long as at the time of any such incurrence and after giving pro forma effect to such incurrence, there is excess availability under our revolving credit facility equal to or in excess of the greater of (a) 17.5% of the lesser of (x) the revolving credit commitment under our revolving credit facility and (y) the borrowing base under our revolving credit facility and (B) $26.25 million.

In addition, our revolving credit facility contains negative covenants that restrict the ABL Borrowers ability to, among other things, incur certain additional debt, grant certain liens, enter into certain guarantees, enter into certain mergers, make certain loans and investments, dispose of certain assets, prepay certain debt, make cash distributions, modify certain material agreements or organizational documents, or change the business we conduct.

Our revolving credit facility also contains certain customary representations and warranties, affirmative covenants and events of default. Events of default include, among other things, payment defaults, breach of representations and warranties, covenant defaults, cross-defaults and cross-acceleration to certain indebtedness, certain events of bankruptcy, certain events under ERISA, material judgments, actual or asserted failure of any guaranty or security document supporting our revolving credit facility to be in full force and effect, and change of control. If such an event of default occurs, the lenders under our revolving credit facility would be entitled to take various actions, including the acceleration of amounts due under our revolving credit facility and all actions permitted to be taken by a secured creditor.

2020 Notes

On November 8, 2012, Northern Tier Energy LLC, our wholly owned subsidiary (“NTE LLC”), and Northern Tier Finance Corporation (together with NTE LLC, the “Notes Issuers”), privately placed $275 million in aggregate principal amount of 7.125% senior secured notes due 2020. The proceeds from the offering of the 2020 Notes and

 

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cash on hand of $31 million were used to repurchase the 2017 Notes tendered pursuant to the tender offer for the 2017 Notes described in “Summary—Recent Developments—2020 Notes Offering and Tender Offer” and to satisfy and discharge any remaining 2017 Notes outstanding after completion of the tender offer and to pay related fees and expenses. Deutsche Bank Trust Company Americas acts as trustee for the 2020 Notes.

The Notes Issuers’ obligations under the 2020 Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Northern Tier Energy LP and on a senior secured basis by (i) all of NTE LLC’s restricted subsidiaries that borrow, or guarantee obligations, under our senior secured asset-backed revolving credit facility or any other indebtedness of NTE LLC or another subsidiary of NTE LLC that guarantees the 2020 Notes and (ii) all other material wholly owned domestic subsidiaries of NTE LLC. The 2020 Notes and the subsidiary note guarantees are secured, subject to permitted liens, on a pari passu basis with certain hedging agreements by (a) a first-priority security interest in substantially all present and hereinafter acquired tangible and intangible assets of the Notes Issuers and each of the subsidiary guarantors in which liens have been granted in relation to the 2020 Notes (other than those items described in clause (b) below) (the “Notes Priority Collateral”), and (b) a second-priority security interest in the (i) inventory, (ii) accounts receivable, (iii) investment property, general intangibles, deposit accounts, cash and cash equivalents and other assets to the extent related to the assets described in clauses (i) and (ii), (iv) books and records relating to the foregoing and (v) all proceeds of and supporting obligations, including letter of credit rights, with respect to the foregoing, and all collateral security and guarantees of any person with respect to the foregoing (the “ABL Priority Collateral”), in each case owned or hereinafter acquired by the Notes Issuers and each of the subsidiary guarantors.

The 2020 Notes are the Notes Issuers’ general senior secured obligations that are effectively subordinated to the Notes Issuers’ obligations under our revolving credit facility to the extent of the value of the ABL Priority Collateral that secures such obligations on a first-priority basis, effectively senior to the Notes Issuers’ obligations under our revolving credit facility to the extent of the Notes Priority Collateral that secures the 2020 Notes on a first-priority basis, structurally subordinated to any existing and future indebtedness and claims of holders of preferred stock and other liabilities of the Notes Issuers’ direct or indirect subsidiaries that are not guarantors of the 2020 Notes (other than Northern Tier Finance Corporation), and pari passu in right of payment with all of the Notes Issuers’ existing and future indebtedness that is not subordinated. The 2020 Notes rank effectively senior to all of the Notes Issuers’ existing and future unsecured indebtedness to the extent of the value of the collateral, effectively equal to the obligations under certain hedge agreements and any future indebtedness which is permitted to be secured on a pari passu basis with the 2020 Notes to the extent of the value of the collateral and senior in right of payment to any future subordinated indebtedness of the Notes Issuers.

At any time prior to November 15, 2015, the Notes Issuers may, on any one or more occasions, upon not less than 30 nor more than 60 days’ notice, redeem up to 35% of the aggregate principal amount of 2020 Notes issued under the indenture (together with any additional notes) at a redemption price of 107.125% of the principal amount thereof, plus accrued and unpaid interest thereon to, but excluding, the applicable redemption date, with all or a portion of the net cash proceeds of one or more qualified equity offerings; provided that (1) at least 65% of the aggregate principal amount of the 2020 Notes issued under the indenture (including any additional notes) remains outstanding immediately after the occurrence of such redemption (excluding notes held by the Notes Issuers and their subsidiaries); and (2) the redemption must occur within 90 days of the date of the closing of such qualified equity offering.

At any time prior to November 15, 2015, the Notes Issuers may, on any one or more occasions, redeem all or a part of the 2020 Notes, upon not less than 30 nor more than 60 days’ notice, at a redemption price equal to 100% of the principal amount of the 2020 Notes redeemed, plus an applicable make-whole premium as of, and accrued and unpaid interest to, but excluding, the date of redemption, subject to the rights of holders of the 2020 Notes on the relevant record date to receive interest due on the relevant interest payment date.

Except pursuant to the preceding paragraphs, the 2020 Notes will not be redeemable at the Notes Issuers’ option prior to November 15, 2015.

 

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On or after November 15, 2015, the Notes Issuers may redeem all or a part of the 2020 Notes, upon not less than 30 nor more than 60 days’ notice, at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest thereon to, but excluding, the applicable redemption date, if redeemed during the 12-month period beginning on November 15 of the years indicated below, subject to the rights of holders of the 2020 Notes on the relevant record date to receive interest on the relevant interest payment date:

 

Year		Percentage
2015			105.344	%
2016			103.563	%
2017			101.781	%
2018 and thereafter			100.000	%

The indenture governing the 2020 Notes contains certain covenants that, among other things, limit the ability of NTE LLC and NTE LLC’s restricted subsidiaries to, subject to certain exceptions:

 

•

incur, assume or guarantee additional debt or issue redeemable stock and preferred stock if our fixed charge coverage ratio, after giving effect to the issuance, assumption or guarantee of such additional debt or the issuance of such redeemable stock or preferred stock, for the most recently ended four full fiscal quarters would have been less than 2.0 to 1.0;

 

•

declare or pay dividends on or make any other payment or distribution on account of our or any of our restricted subsidiaries’ equity interests;

 

•

make any payment with respect to, or purchase, repurchase, redeem, defease or otherwise acquire or retire for value our equity interests;

 

•

purchase, repurchase, redeem, defease or otherwise acquire or retire for value or give any irrevocable notice of redemption with respect to certain subordinated debt;

 

•

make certain investments, loans and advances;

 

•

sell, lease or transfer any of our property or assets;

 

•

merge, consolidate, lease or sell substantially all of our assets;

 

•

create, incur, assume or otherwise cause or suffer to exist or become effective any lien;

 

•

conduct any business or enter into or permit to exist any contract or transaction with any affiliate involving aggregate payments or consideration in excess of $5.0 million;

 

•

suffer a change of control;

 

•

enter into new lines of business; and

 

•

enter into agreements that restrict distributions from certain subsidiaries.

The 2020 Notes also provide for events of default which, if any of them occurs, would permit or require the principal of and accrued interest on such notes to become or to be declared to be due and payable.

Inflation

Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations 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. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy.

 

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Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Note 2 to our audited financial statements for a discussion of additional accounting policies and estimates made by management.

Contingent Consideration and Margin Support Arrangements

We entered into a contingent consideration agreement with Marathon as part of the Marathon Acquisition. This agreement would have required us to make earn-out payments to Marathon if the Agreement Adjusted EBITDA exceeded $165 million, less, among other things, any rental expense accrued pursuant to the sale-leaseback arrangement with Realty Income, during any year in each of the eight years following the Marathon Acquisition. Agreement Adjusted EBITDA adjusts for, among other items, (i) any unrealized gains or losses relating to derivative activities, (ii) any gains or losses generated by the liquidation of any LIFO inventory layers, (iii) any losses related to lower of cost or market inventory adjustments, and (iv) any gains on the sale of property, plant or equipment and certain other assets. Specifically, we would have been required to pay Marathon 40% of the amount by which Agreement Adjusted EBITDA exceeded the specified threshold, not to exceed $125 million over the eight years following the Marathon Acquisition. For the year ended December 31, 2011, we were not required to make any earn-out payment under the agreement. The Marathon Acquisition agreements also include a margin support component that would have required Marathon to pay us up to $30 million per year to the extent the Agreement Adjusted EBITDA had been $145 million, less, among other things, any rental expense accrued pursuant to the sale-leaseback arrangement with Realty Income, in either of the twelve-month periods ending November 30, 2011 or 2012 up to a maximum of $60 million. Any such payments made by Marathon would have increased the amount that we would have been required to pay Marathon over the earn-out period. Subsequent fair value adjustments to these collective contingent consideration arrangements (earn-out arrangement and margin support arrangement) would have been recorded in the statement of operations based on quarterly remeasurements. These subsequent fair value adjustments would have been made based on our estimates of the Agreement Adjusted EBITDA expected over the earn-out period. As such, there were inherent risks related to the accuracy of such estimates. See Note 13 to our audited financial statements for further information on our fair value measurements.

On May 4, 2012, we entered into a settlement agreement with Marathon under the terms of which Marathon received $40 million of the net proceeds from our initial public offering, and Northern Tier Holdings LLC redeemed Marathon’s existing preferred interest with a portion of the net proceeds from our initial public offering and issued Marathon a new $45 million preferred interest in Northern Tier Holdings LLC, in consideration for relinquishing all claims with respect to earn-out payments under the contingent consideration agreement. We also agreed, pursuant to the settlement agreement, to relinquish all claims to margin support payments under the contingent consideration agreement.

 

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Investment in the Minnesota Pipe Line Company and MPL Investments

Our 17% common interest in the Minnesota Pipe Line Company is accounted for using the equity method of accounting and carried at our share of net assets in accordance with the Financial Accounting Standards Board, or the FASB, Accounting Standards Codification paragraph 323-30-35-3. Income from equity method investment represents our proportionate share of net (loss) earnings attributed to common owners generated by the Minnesota Pipe Line Company.

The equity method investment is assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net (loss) earnings.

The investment in MPL Investments, over which we do not have significant influence and whose stock does not have a readily determinable fair value, is carried at cost. MPL Investments owns all of the preferred membership units of the Minnesota Pipe Line Company. Dividends received from MPL Investments are recorded as return of capital from cost method investment and in other income.

Inventories

Inventories are carried at the lower of cost or net realizable value. Cost of inventories is determined primarily under the LIFO method. However, we maintain other inventories in the retail segment whose cost is primarily determined using the first-in, first-out (“FIFO”) method. The refining segment has a LIFO pool for crude oil and refinery feedstocks and a separate LIFO pool for refined products. The retail segment has a LIFO pool for refined products for inventory held by the retail stores.

Intangible Assets

Intangible assets primarily include a retail marketing trade name, franchise agreements, refinery licensed technology agreements and refinery permits and plans. The marketing trade name has an indefinite life and therefore is not amortized, but rather is tested for impairment annually and when events or changes in circumstances indicate that the fair value of the intangible asset has been reduced below carrying value. The other intangibles are amortized on a straight-line basis over the expected remaining lives of the related contracts, as applicable, which range from 8 to 15 years. Amortized intangible assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset.

Major Maintenance Activities

We incur costs for planned major refinery maintenance, referred to as “turnarounds.” These types of costs include contractor repair services, materials and supplies, equipment rentals and labor costs. Such costs are expensed in the period incurred.

Environmental Costs

Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. We provide for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed and determinable. If recoveries of

 

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remediation costs from third parties are probable, a receivable is recorded and is discounted when the estimated amount is reasonably fixed and determinable.

Asset Retirement Obligations

The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Conditional asset retirement obligations for removal and disposal of fire-retardant material from certain refining assets and asset retirement obligations for the removal of underground storage tanks from leased convenient stores have been recognized. The amounts recorded for such obligations are based on the most probable current cost projections. Asset retirement obligations have not been recognized for the removal of materials and equipment from or the closure of certain refinery, pipeline, terminal and retail marketing assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminable.

Current inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is determined on a straight-line basis, while accretion escalates over the lives of the assets.

Derivative Financial Instruments

We are exposed to earnings and cash flow volatility based on the timing and change in refined product prices versus crude oil prices. To manage these risks, we use derivative instruments associated with the purchase or sale of crude oil and refined products. Crack spread option contracts are used to hedge the volatility of refining margins. We also may use futures contracts to manage price risks associated with inventory quantities above or below target levels. We have not designated any derivative instruments as hedges for accounting purposes and we do not enter into derivative contracts for speculative purposes. All derivative instruments are recorded in the consolidated balance sheet at fair value and are classified depending on the maturity date of the underlying contracts. Changes in the fair value of its contracts are accounted for by marking them to market and recognizing any resulting gains or losses in its statements of operations. These gains or losses are reported within operating activities on the consolidated statement of cash flows.

Income Taxes

Effective August 1, 2012, Northern Tier Retail Holdings LLC elected to be treated as a corporation for income tax purposes in order to preserve the master limited partnership tax status of Northern Tier Energy LP. As such, we recorded deferred tax assets and deferred tax liabilities as of the election date. Additionally, we recorded current period income taxes for the period from August 1, 2012 through September 30, 2012 (see Note 6) at the Northern Tier Retail Holdings LLC level. Prior to August 1, 2012, all of our income was derived from subsidiaries which were limited liability companies and were therefore pass-through entities for federal income tax purposes. As a result, we did not incur federal income taxes prior to this date. Prior to the Marathon Acquisition, our taxable income was historically included in the consolidated U.S. federal income tax returns of Marathon and also in a number of state income tax returns, which were filed as consolidated returns.

Prior to the Marathon Acquisition, the provision for income taxes was computed as if we were a standalone tax-paying entity and as if we paid the amount of our current federal and state tax liabilities to Marathon in each period. As such, the accrual and payment of the current federal and state tax liabilities is recorded within the net investment in the combined financial statements in the period incurred.

Prior to the Marathon Acquisition, deferred tax assets and liabilities were recognized based on temporary differences between the financial statement carrying amounts of our assets and liabilities and their tax bases as reported in Marathon’s tax filings with the respective taxing authorities. The realization of deferred tax assets

 

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was assessed periodically based on several interrelated factors. These factors included the expectation to generate sufficient future taxable income in order to utilize tax credits and operating loss carry-forwards.

For more information, see Note 5 to our audited historical financial statements included elsewhere in this prospectus.

Recent Accounting Pronouncements

In July 2012, the FASB issued Accounting Standards Update (“ASU”) No. 2012-02, “Intangibles—Goodwill and other” (“ASU 2012-02”). ASU 2012-02 provides guidance on annual impairment testing of indefinite-lived intangible assets. The standards update allows an entity to first assess qualitative factors to determine if it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount. If based on its qualitative assessment an entity concludes it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount, quantitative impairment testing is required. However, if an entity concludes otherwise, quantitative impairment testing is not required. The standards update is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted. We believe that the adoption of ASU 2012-02 will not have a material impact on our consolidated financial statements.

In May 2011, the FASB issued ASU No. 2011-04, “Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS” (“ASU 2011-04”). ASU 2011-04 changes the terminology used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between U.S. GAAP and International Financial Reporting Standards (“IFRS”). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is to be applied prospectively. ASU 2011-04 will be effective for our quarterly and annual financial statements beginning with the first quarter of 2012. We believe that the adoption of this standard will not materially impact our consolidated financial statements because the guidance only provides for enhanced disclosure requirements.

On January 1, 2012, we adopted ASU No. 2011-05, “Comprehensive Income (ASC Topic 220): Presentation of Comprehensive Income” (“ASU 2011-05”), which amends current comprehensive income guidance. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, we must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. Also effective January 1, 2012, we adopted ASU No. 2011-12, “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” (“ASU 2011-12”). ASU 2011-12 defers the effectiveness for the requirement to present on the face of our financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income.

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”). ASU 2011-11 retains the existing offsetting requirements and enhances the disclosure requirements to allow investors to better compare financial statements prepared under U.S. GAAP with those prepared under IFRS. This new guidance is to be applied retrospectively. ASU 2011-11 will be effective for our quarterly and annual financial statements beginning with the first quarter of 2013. We believe that the adoption of ASU 2011-11 will not have a material impact on our consolidated financial statements.

Quantitative and Qualitative Disclosures About Market Risk

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mitigate the effects of the identified risks. In general, we may attempt to mitigate risks related to the variability of our future cash flow and profitability resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures and similar requirements.

Commodity Price Risk

As a refiner of petroleum products, we have exposure to market pricing for products sold in the future. In order to realize value from our processing capacity, we must achieve a positive spread between the cost of raw materials and the value of finished products (i.e., refinery gross product margin or crack spread). The physical commodities that comprise our raw materials and finished goods are typically bought and sold at a spot or index price that can be highly variable. The timing, direction and overall change in refined product prices versus crude oil prices will impact profit margins and could have a significant impact on our earnings and cash flows. Assuming all other factors remained constant, a $1 per barrel change in our average refinery gross product margin, based on our average refinery throughput for the nine months ended September 30, 2012 of 81,697 bpd, would result in a change of $29.9 million in our overall gross margin.

The prices of crude oil, refined products and other commodities are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors that are beyond our control. We monitor these risks and, where appropriate under our risk mitigation policy, we will seek to reduce the volatility of our cash flows by hedging an operationally reasonable volume of our gasoline and diesel production. We enter into derivative transactions designed to mitigate the impact of commodity price fluctuations on our business by locking in or fixing a percentage of the anticipated or planned gross margin in future periods. We will not enter into financial instruments for purposes of speculating on commodity prices. However, we may execute derivative financial instruments pursuant to our hedging policy that are not considered to be hedges within the applicable accounting guidelines.

In addition, the crude oil supply and logistics agreement with JPM CCC 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 refined products are sold. Furthermore, this agreement enables us to mitigate potential working capital fluctuations relating to crude oil price volatility.

Basis Risk

The effectiveness of our risk mitigation strategies is dependent upon the correlation of the price index utilized for the hedging activity and the cash or spot price of the physical commodity for which price risk is being mitigated. Basis risk is a term we use to define that relationship. Basis risk can exist due to several factors, for example the location differences between the derivative instrument and the underlying physical commodity. Our selection of the appropriate index to utilize in a hedging strategy is a prime consideration in our basis risk exposure. In hedging NYMEX or U.S. Gulf Coast (or any other relevant benchmark) crack spreads, we experience location basis as the settlement price of NYMEX refined products (related more to New York Harbor cash markets) or U.S. Gulf Coast refined products (related more to U.S. Gulf Coast cash markets) may be different than the prices of refined products in our Upper Great Plains pricing area. The risk associated with not hedging the basis when using NYMEX or U.S. Gulf Coast forward contracts to fix future margins is if the crack spread increases based on prices traded on NYMEX or U.S. Gulf Coast while pricing in our market remains flat or decreases, then we would be in a position to lose money on the derivative position while not earning an offsetting additional margin on the physical position based on the pricing in our market.

Commodities Price and Basis Risk Management Activities

We have entered into 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

 

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spread created by the purchase of crude oil for future delivery and the sale of refined petroleum products, including gasoline, diesel, jet fuel and heating fuel, for future delivery. Under the agreements, as market conditions permit, we have the capacity to mitigate our crack spread risk with respect to reasonable percentages of the refinery’s projected monthly production of some or all of these refined products. As of September 30, 2012, we have hedged approximately nine million barrels of future gasoline and diesel production under commodity derivatives contracts that are 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 such as NYMEX or U.S. Gulf Coast. 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 the 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.

During the nine months ended September 30, 2012, we settled contracts covering approximately three million barrels of our remaining 2012 gasoline and diesel production and recognized a loss of approximately $44.6 million. 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 used $92 million of the net proceeds from our initial public offering to settle the majority of these obligations. The remainder of these deferred losses of approximately $45 million will be paid through the end of 2013.

Our open positions at September 30, 2012 will expire at various times during the remainder of 2012 and 2013. We prepared a sensitivity analysis to estimate our exposure to market risk associated with our derivative instruments. This analysis may differ from actual results. Based on our open positions of nine million barrels, a $1.00 per barrel change in quoted market prices of our derivative instruments, assuming all other factors remain constant, could change the fair value of our derivative instruments and our net (loss) earnings by approximately $9 million.

We may enter into additional futures derivatives contracts at times when we believe market conditions or other circumstances suggest that it is prudent to do so. Although we have historically been hedged at higher rates, we intend to hedge significantly less than what we hedged at the time of the Marathon Acquisition on an ongoing basis. We may use commodity derivatives contracts such as puts, calls, swaps, forward agreements and other financial instruments to mitigate the effects of the identified risks; however, it is our plan to hedge a lesser amount of production than we historically have, which will increase our exposure to the gross refining margins that we would realize at our refinery on an unhedged basis. Additionally, we may take advantage of opportunities to modify our derivative portfolio to change the percentage of our hedged refined product volumes when circumstances suggest that it is prudent to do so.

Interest Rate Risk

As of December 31, 2011 and September 30, 2012, the availability under our revolving credit facility was $108.0 million and $168.0 million, respectively. This availability is net of $61.6 million and $24.0 million in outstanding letters of credit as of December 31, 2011 and the nine months ended September 30, 2012, respectively. We had no borrowings under our revolving credit facility at December 31, 2011 or at September 30, 2012. Borrowings under our revolving credit facility bear interest, at our election, at either an alternative base rate, plus an applicable margin (which ranges between 1.00% and 1.50% pursuant to a grid based on average excess availability) or a LIBOR rate, plus an applicable margin (which ranges between 2.00% and 2.50% pursuant to a grid based on average excess availability). See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Description of Our Indebtedness—Senior Secured Asset-Based Revolving Credit Facility.”

We have interest rate exposure on a portion of the cost of crude oil payable to JPM CCC for the crude oil inventory that they purchase for delivery to our refinery under the crude oil supply and logistics agreement. This

 

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exposure is offset with the credits we receive from JPM CCC for the trade terms granted by suppliers to them on crude oil purchases intended for our refinery. Our interest rate exposure is the spread between 3-months and 1-month LIBOR. A widening of the spread between these two rates may result in a higher cost of crude oil to us.

Credit Risk

We are subject to risk of losses resulting from nonpayment or nonperformance by our customers. We will continue to closely monitor the creditworthiness of customers to whom we grant credit and establish credit limits in accordance with our credit policy.

 

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Business

Overview

We are an independent downstream energy limited partnership with refining, retail and pipeline operations that serves 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 nine months ended September 30, 2012, we had total revenues of approximately $3.4 billion, operating income of $426.8 million, net earnings of $113.1 million and Adjusted EBITDA of $577.3 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—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 PADD II region. The PADD II region covers 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 what we believe are abundant supplies of advantageously priced crude oils. Of the crude oil processed at our refinery in the nine months ended September 30, 2012 and in the year ended December 31, 2011, approximately 44% and 51%, 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 NYMEX WTI. Further, over the past twelve months, NYMEX WTI has traded at an additional discount relative to waterborne crude oils.

We expect to continue to benefit from our access to these growing crude oil supplies. By 2030, according to CAPP, total Canadian crude oil production is expected to grow to 6.2 million bpd from 2011 production of 3.0 million bpd. Crude oil production from the Bakken Shale in North Dakota has also increased significantly, helping to grow crude oil production in North Dakota from approximately 98,000 bpd in 2005 to approximately 674,000 bpd as of July 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 80% and 79% of our total refinery production for the nine months ended September 30, 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 82% and 83% of our gasoline and diesel volumes for the nine months ended September 30, 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.

 

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Our refining business also includes our 17% interest in 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

As of September 30, 2012, our retail business operated 166 convenience stores under the SuperAmerica brand and also supported 68 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 nine months ended September 30, 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 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 2007 to 2011. 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 17%, 14% and 14%, 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.

 

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The following tables illustrate the balance of certain refined products in PADD II from 2005 – 2011:

PADD II Gasoline Balance (mbpd)

 

		2005				2006				2007				2008				2009				2010				2011
Production by Refineries Within PADD II			1,816				1,796				1,769				1,713				1,778				1,807				1,837
Net Receipts of Products from Domestic Sources Outside PADD II			673				691				673				594				550				482				417
Ethanol			136				138				179				243				222				231				225
Exports to Non-U.S. Sources			0				(2	)			(11	)			(19	)			(1	)			(5	)			(8	)
Imports from Non-U.S. Sources			2				1				2				1				1				3				3
Other			(1	)			5				7				12				(15	)			8				(11	)
Total			2,626				2,629				2,619				2,544				2,535				2,526				2,463

PADD II Distillate Balance (mbpd)

 

		2005				2006				2007				2008				2009				2010				2011
Production by Refineries Within PADD II			908				914				927				987				898				963				989
Net Receipts of Products from Domestic Sources Outside PADD II			344				332				336				249				180				195				155
Exports to Non-U.S. Sources			(9	)			(2	)			(6	)			(12	)			(6	)			(3	)			(5	)
Imports from Non-U.S. Sources			4				6				6				5				4				6				2
Other			2				5				(8	)			(7	)			1				1				(3	)
Total			1,249				1,255				1,255				1,222				1,077				1,162				1,138

PADD II Jet Fuel/Kerosene Balance (mbpd)

 

		2005				2006				2007				2008				2009				2010				2011
Production by Refineries Within PADD II			230				220				202				209				208				219				229
Net Receipts of Products from Domestic Sources Outside PADD II			145				119				115				74				49				41				36
Exports to Non-U.S. Sources			(1	)			(4	)			(7	)			(10	)			(5	)			(4	)			(7	)
Imports from Non-U.S. Sources			0				0				0				0				0				0				0
Other			(3	)			2				1				2				(4	)			(1	)			(2	)
Total			371				337				311				275				248				255				256

 

Source: EIA; see “Market and Industry Data and Forecasts.”

Our Business Strategy

Our primary business objective is to grow our cash flows from operations over the long-term by executing the following business strategies:

 

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Make Distributions Equal to the Available Cash We Generate Each Quarter. The board of directors of our general partner adopted a policy under which distributions for each quarter will equal the amount of available cash we generate each quarter. We do not intend to maintain excess distribution coverage in order to stabilize 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,

 

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accordingly, our unitholders will receive 100% of our cash distributions. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Distribution Policy.”

 

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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 our 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.

 

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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 financial 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.

 

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Maintain Low Leverage and 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 revolving credit facility, trade credit from our crude oil suppliers 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 low leverage and sufficient liquidity to meet unforeseen capital needs. On a pro forma basis for the 2020 Notes offering and related tender offer, as of September 30, 2012, we estimate that we would have had approximately $461 million of available liquidity, comprised of $293 million of cash on hand and $168 million 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. Cash for distributions to our unitholders will be funded from this cash on hand. However, sufficient liquidity will be maintained to manage our operations. Additionally, we seek to maintain low leverage. Our ratio of total debt as of September 30, 2012 to Adjusted EBITDA for the nine months ended September 30, 2012 was 0.5 to 1, which provides us further financial and operating flexibility.

 

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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.

 

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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 September 30, 2012, approximately nine million barrels of our future gasoline and diesel production remained hedged under commodity derivatives contracts, of which four million barrels are 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.

During the nine months ended September 30, 2012, we settled contracts covering approximately three million barrels of our remaining 2012 gasoline and diesel production and recognized a loss of approximately $44.6 million. 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 used $92 million of the net proceeds from our initial public offering to settle the majority of these obligations. The remainder of these deferred losses of approximately $45 million will be paid through the end of 2013.

Our Competitive Strengths

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

 

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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 nine months ended September 30, 2012, 44% 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 the 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 September 30, 2012, we realized an average discount of $2.59 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.

 

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The following chart highlights the recent trend in this discount:

 

Source: Bloomberg; see “Market and Industry Data and Forecasts.”

 

•

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 September 30, 2012, our refinery has realized an average price premium of $2.48 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 $1.85 per barrel relative to the benchmark 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—Summary Historical Condensed Consolidated Financial and Other Data”).

 

•

Substantial Refinery Operating Flexibility. Since 2006, approximately $233 million (including $194 million from January 2006 through November 2010 and $39 million from our inception date of June 23, 2010 through September 30, 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 80% and 79% of our total refinery production for the nine months ended September 30, 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

 

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refinery. Our refinery recorded mechanical availability of 96.9%, 95.8% and 96.6% for the years ended December 31, 2009, 2010 and 2011, respectively, with an average annual mechanical availability of 96.9% from 2005 through 2011, inclusive. We measure our safety track record primarily through the use of injury frequency rates as determined by OSHA. Our refinery had an OSHA Recordable Rate of 0.75, 0.23 and 0.52 during the years ended December 31, 2009, 2010 and 2011, respectively, with an average annual OSHA Recordable Rate of 0.97 during the period from 2005 through 2011, inclusive, and an OSHA Recordable Rate of 0.92 during the nine months ended September 30, 2012.

 

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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 September 30, 2012, 166 company-operated and 68 franchised convenience stores, all of which are operated under the SuperAmerica brand. For the nine months ended September 30, 2012 and the year ended December 31, 2011, we sold 82% 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 and Proven Management Team. Our management team is led by our President and Chief Executive Officer, Hank Kuchta, who 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 Executive 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.

Our Refining Business

Our refinery occupies approximately 170 acres along the Mississippi River in the southeast of St. Paul Park, Minnesota and was originally built in 1939. The refinery was acquired by Ashland Oil, Inc. in 1970 from Northwestern Refining, was jointly owned by Ashland Oil, Inc. and Marathon from 1998 through 2005 and became fully owned by Marathon in 2005. Our refinery is a 74,000 bpd (84,500 barrels per stream day) cracking facility with operations including crude fractionation, catalytic cracking, hydrotreating, reforming, alkylation, sulfur recovery and a hydrogen plant. A major refinery improvement and expansion project was completed in 1993 to enable the refinery to produce environmentally compatible low sulfur fuels. In 2006, the gas oil hydrotreater was revamped, which enables us to produce ultra low sulfur diesel, at a capital cost of approximately $24 million. The fluid catalytic cracking unit was expanded in 2007 for a total capital cost of approximately $37 million, which improved gasoline yield and increased capacity from 27,100 bpd to 28,500 bpd. We completed a multi-year boiler replacement project, which entailed $19.9 million of capital expenditures over the project life, $12.7 million during the period from 2008 through November 30, 2010 and $7.2 million during the period from December 1, 2010 through December 31, 2011. We currently expect to spend

 

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approximately $25-30 million in capital expenditures in 2012. Our capital expenditures in the nine months ended September 30, 2012 were $13.3 million.

A refinery’s location can have an important impact on its refining margins because location can influence access to feedstocks and efficient distribution for refined products. There are five regions in the United States, the PADDs, that have historically experienced varying levels of refining profitability due to regional market conditions. Refiners located in the U.S. Gulf Coast region operate in a highly competitive market due to the fact that this region (“PADD III”) accounts for approximately 39% of the total number of operable U.S. refineries as of January 1, 2012 and approximately 47% of the country’s refining capacity as of January 2012. Our refinery is located in the strategically advantageous PADD II region. In recent years, demand for refined products in the PADD II region has exceeded regional capacity, 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. This favorable supply/demand imbalance has allowed our refinery to generate higher refining margins, as measured by the U.S. Gulf Coast 3:2:1 crack spread. We have realized, on average, a premium of $1.85 per barrel of refined product relative to the benchmark Group 3 3:2:1 crack spread over the past five years through September 30, 2012 assuming a comparable rate of two barrels of gasoline and one barrel of distillate for each of the U.S. Gulf Coast 3:2:1 crack spread and the Group 3 3:2:1 crack spread.

The refinery is an integrated refining operation with significant storage and transportation assets. Our transportation assets include our 17% interest in the Minnesota Pipe Line Company, an eight-bay light product terminal located approximately two miles from the refinery, a seven-bay heavy product loading rack located on the refinery property, rail facilities for shipping LPG and asphalt and receiving butane, isobutane and ethanol and a barge dock on the Mississippi River used primarily for shipping vacuum residue and slurry. As of September 30, 2012, our storage assets included 84 hydrocarbon storage tanks with a total capacity of 3.7 million barrels (156 million gallons), 0.8 million barrels of crude oil storage and 2.9 million barrels of feedstock and product storage.

Process Summary

Our refinery is a 74,000 bpd (84,500 barrels per stream day) cracking facility with operations including crude fractionation, catalytic cracking, hydrotreating, reforming, alkylation, sulfur recovery and a hydrogen plant. We have significant redundancy in our refining assets, which include two crude oil distillation and vacuum towers, two reformers, two sulfur recovery units and five hydrotreating units. This redundancy allows us to continue to receive and process crude oil even if one tower goes out of service and also 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. During the nine months ended September 30, 2012 and the year ended December 31, 2011, the refinery processed nearly 80,158 bpd and 77,452 bpd of crude oil, respectively, and 1,539 bpd and 3,698 bpd of other charge and blendstocks, respectively. The facility processes a mix of light sweet, synthetic and heavy sour crude oils, predominately from Canada and North Dakota, into products such as gasoline, diesel, jet fuel, asphalt, kerosene, propane, LPG, propylene and sulfur. Our refinery utilization rates, using standard industry methodologies for utilization measurement, have been 72%, 75% and 78% for the period from inception to December 31, 2010, for the year ended December 31, 2011 and for the nine months ended

 

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September 30, 2012, respectively. Please see below a simplified process flow diagram of the major refining units at our refinery.

 

The following table summarizes our refinery’s major process unit capacities as of September 30, 2012. Unit capacities are shown in barrels per stream day.

 

Process Unit		Capacity				% of Crude Oil Capacity
No. 1 Crude Oil Unit			37,000				44	%
No. 2 Crude Oil Unit			47,000				56	%
Vacuum Distillation Unit #1			19,000				23	%
Vacuum Distillation Unit #2			22,500				27	%
Catalytic Reforming Unit #1			13,000				15	%
Catalytic Reforming Unit #2			6,500				8	%
Fluid Catalytic Cracking Unit			28,500				34	%
HF Alkylation Unit			5,500				7	%
C4/C5/C6 Isom Unit			8,500				10	%
Isom Desulfurizer			8,500				10	%
Naphtha Hydrotreater #1			13,500				16	%
Naphtha Hydrotreater #2			7,000				8	%
Kerosene Hydrotreater			7,500				9	%
Distillate Hydrotreater			21,500				26	%
Gas Oil Hydrotreater			29,500				35	%
Hydrogen Plant (MSCF/D)			8,500				—
Sulfur Recovery Units (Long Tons/day)			100				—
TailGas Recovery Units (Long Tons/day)			4				—

 

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The complexity of a refinery refers to the number, type and capacity of processing units at the refinery and is measured by its complexity. Our refinery has a Nelson complexity index of 11.5. Our refinery’s complexity allows us to process lower cost crude oils into higher value light refined products or transportation fuels (gasoline and distillates), which comprised approximately 80% and 79% of our total refinery production for the nine months ended September 30, 2012 and the year ended December 31, 2011, respectively.

Raw Material Supply

The primary input for our refinery is crude oil, which represented approximately 98% and 95% of our total refinery throughput volumes for the nine months ended September 30, 2012 and the year ended December 31, 2011, respectively. We processed approximately 80,158 bpd and 77,452 bpd of crude oil for the nine months ended September 30, 2012 and the year ended December 31, 2011, respectively. The following table describes the historical feedstocks for our refinery:

 

		Nine Months Ended September 30,																Year Ended December 31,
		2012				%				2011				%				2011				%				2010				%				2009				%
		(bpd)
Refinery Throughput Crude Oil Feedstocks by Location:
Canadian and Other International			35,626				44	%			40,039				52	%			39,295				51	%			41,156				56	%			48,213				65	%
Domestic			44,532				56	%			36,790				48	%			38,157				49	%			32,986				44	%			26,326				35	%
Total Crude Oil			80,158				100	%			76,829				100	%			77,452				100	%			74,142				100	%			74,539				100	%
Crude Oil Feedstocks by Type:
Light and Intermediate(1)			59,764				75	%			54,914				71	%			56,722				73	%			55,782				75	%			59,112				79	%
Heavy(2)			20,394				25	%			21,915				29	%			20,730				27	%			18,360				25	%			15,427				21	%
Total Crude Oil			80,158				100	%			76,829				100	%			77,452				100	%			74,142				100	%			74,539				100	%
Other Feedstocks/ Blendstocks(2):
Natural Gasoline			193				12	%			2,396				62	%			1,910				52	%			3,839				64	%			4,790				68	%
Butanes			768				50	%			890				23	%			1,236				33	%			1,242				21	%			1,004				14	%
Gasoil			8				1	%			0				0	%			0				0	%			446				7	%			733				11	%
Other			570				37	%			579				15	%			552				15	%			488				8	%			497				7	%
Total Other Feedstocks/ Blendstocks			1,539				100	%			3,865				100	%			3,698				100	%			6,015				100	%			7,024				100	%
Total Inputs			81,697								80,694								81,150								80,157								81,563

 

(1)

Crude oil is classified as light, intermediate or heavy, according to its measured American Petroleum Institute, or API, gravity. API gravity, which is expressed in degrees, is a scale developed for measuring the relative density of various petroleum liquids. It also serves as an approximate measure of crude oil’s value, as the higher the API gravity, the richer the yield in high value refined oil products, such as gasoline, diesel and jet fuel. For purposes of categorizing our crude oil feedstocks by type, light crude oil has an API gravity of 33 degrees or more, intermediate crude oil has API gravity between 28 and 33 degrees, and heavy crude has an API gravity of 28 degrees or less.

(2)

Other Feedstocks/Blendstocks includes only feedstocks/blendstocks that are used at the refinery, and does not include ethanol and biodiesel. Although we also purchase ethanol and biodiesel to supplement the fuels produced at the refinery, we do not include these in the table as those items are blended at the terminal located adjacent to the refinery or at terminals on the Magellan Pipe Line system.

 

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Of the crude oil processed at our refinery for the nine months ended September 30, 2012 and the year ended December 31, 2011, approximately 44% and 51%, respectively, was Canadian crude oil and the remainder was comprised of mostly light sweet crude oil from North Dakota. There is an abundant supply of Canadian crude oil, according to the EIA. Canada exported approximately 2.2 million bpd of crude oil into the United States in 2011, making it the largest exporter to the United States and representing 25% of all U.S. imports from foreign sources. By 2030, according to CAPP, total Canadian crude oil production is expected to grow to 6.2 million bpd from 2011 production of 3.0 million bpd. Additionally, U.S. demand for western Canadian oil supply is expected to reach 3.7 million bpd by 2020.

Crude production from North Dakota has increased significantly from approximately 98,000 bpd in 2005 to approximately 674,000 bpd as of July 2012, according to the EIA. The chart below shows crude oil bpd production in North Dakota, and illustrates the rapid increase in production attributable to the Bakken Shale. We believe production from the Bakken Shale will continue to increase due to continued growth in unconventional production.

North Dakota Crude Oil Production (thousands of BPD)

 

Source: EIA; see “Market and Industry Data and Forecasts.”

Crude Oil Supply

In March 2012, we entered into an amended and restated 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. Once we identify cargos of crude oil and pricing terms that meet our requirements, we notify JPM CCC, which then provides, for a fee, credit, transportation and other logistical services for delivery of the crude oil to the Cottage Grove, Minnesota, storage tanks, which are approximately two miles from our refinery. Title to the crude oil passes from JPM CCC to us as the crude oil exits the storage tanks located at Cottage Grove and moves to the refinery. The Cottage Grove storage tanks are leased by JPM CCC from us for the duration of the crude oil supply and logistics agreement. We believe our crude oil supply and logistics agreement significantly reduces the

 

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no, investment that we are required to maintain in 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. We also benefit from the reduction in the time we are exposed to market fluctuations before the finished product output is sold.

The approximately 455,000 bpd Minnesota Pipeline system is the primary supply route for crude oil to our refinery and has transported a significant majority of our crude oil since its major expansion in 2008. The Minnesota Pipeline extends from Clearbrook, Minnesota to the refinery and receives crude oil from Western Canada and North Dakota through connections with various Enbridge pipelines. The Minnesota Pipeline is an interstate crude oil pipeline regulated by FERC pursuant to the ICA. Access to capacity on the Minnesota Pipeline is governed by the pipeline’s tariff, which is filed with FERC and must comply with the applicable provisions of the ICA. Pursuant to the rules and regulations applicable to the Minnesota Pipeline, if nominations are received for more crude oil than the pipeline can transport in a given month, capacity is pro-rated based on each shipper’s relative use of the line over the preceding twelve-month period ending the month prior to the month the excess nominations were received, with further reductions as necessary to accommodate new shippers. For the year ended December 31, 2011, our shipments comprised approximately 25% of the total volumes shipped on the Minnesota Pipeline. Our 17% interest in the Minnesota Pipe Line Company mitigates the impact of tariff rate increases on the pipeline, as we receive a pro rata share of tariffs. See “—Pipeline Assets” for more information regarding the Minnesota Pipeline system.

In addition to the Minnesota Pipeline, the refinery is also capable of receiving crude oil from the Wood River Pipeline (owned and operated by affiliates of Koch Industries, Inc.). The Wood River Pipeline extends from Wood River, Illinois to a connection with the Minnesota Pipeline near Pine Bend, Minnesota, allowing for deliveries to the refinery and providing the refinery with access to crude supply from the Cushing, Oklahoma area via the Ozark Pipeline and to crude supply from the U.S. Gulf Coast and foreign markets via Capline and Capwood pipelines.

Below is a map illustrating the pipelines that provide the refinery with access to its crude oil supply:

 

 

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Other Feedstocks/Blendstocks

The refinery also purchases ethanol and biodiesel, as well as conventional petroleum based blendstocks such as natural gasoline to supplement the fuels produced at the refinery. We purchase ethanol for blending with gasoline to meet the EPA’s oxygenated fuel mandate levels. The state of Minnesota has a current mandate for all gasoline power motor vehicles for 10% ethanol blending in gasoline or the maximum amount of ethanol allowed under federal law, whichever is greater. The same legislation will require 20% ethanol blending in gasoline or the maximum amount of ethanol allowed under federal law, whichever is greater, effective August 30, 2013. Federal law currently allows a maximum of 15% ethanol for cars and light trucks manufactured since 2001, and 10% ethanol for all other vehicles. In addition, there is a biodiesel mandate in Minnesota requiring the blending of diesel with 5% bio-fuel. 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. We purchase ethanol and biodiesel blendstocks pursuant to month-to-month agreements with market related pricing provisions and receive those volumes primarily via truck. We purchase natural gasoline blendstock from third parties that is delivered to us via third party pipeline.

Refined Products—Production, Sales and Transportation

On average over the last three fiscal years, the refinery produced approximately 81,700 bpd of refined products, of which 51% was gasoline, 29% were distillates (including ultra low sulfur diesel and jet fuel), 11% was asphalt and the remainder was made up of propane, heavy fuel and other specialty products. The following table identifies the product yield of our refinery for each of the periods indicated.

 

		Nine Months  Ended September 30,								Year Ended December 31,
		2012				2011				2011				2010				2009
		(bpd)
Refinery product yields:
Gasoline			39,578				40,238				40,240				41,199				42,674
Distillate			26,464				23,851				24,841				22,546				22,876
Asphalt			11,011				11,169				9,888				9,495				7,688
Other			5,277				5,915				7,110				7,794				8,888
Total Production			82,330				81,173				82,079				81,034				82,126

For the years ended December 2009, 2010 and 2011 and the nine months ended September 30, 2011 and 2012, gasoline accounted for 52%, 51%, 54%, 55% and 53% of our total revenue for the refining business for such periods, respectively, and distillates accounted for 28%, 28%, 33%, 32% and 35% of our total revenue for the refining business for such periods, respectively.

Approximately 84% and 90% of the refinery business’s gasoline and diesel volumes were sold within the state of Minnesota for the nine months ended September 30, 2012 and the year ended December 31, 2011, respectively, with the remainder being sold within Iowa, Nebraska, Oklahoma, South and North Dakota and Wisconsin. Our refinery supplied substantially all of the gasoline and diesel sold in our company-operated or franchised convenience stores for the nine months ended September 30, 2012 and the year ended December 31, 2011, as well as supplied 90 independently owned and operated Marathon branded stores in our marketing area.

Primary distribution for the fuels is through our light products terminal, which is equipped with an eight-bay, bottom-loading truck rack and located adjacent to the refinery. Approximately 82% and 83% of our gasoline and diesel volumes for the nine months ended September 30, 2012 and the year ended December 31, 2011,

 

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respectively, were transported via this light products terminal to our company-operated or franchised SuperAmerica convenience stores, Marathon branded convenience stores and other resellers throughout our market area. Light refined products, which include gasoline and distillates, are distributed from the refinery through a pipeline and terminal system owned by Magellan, which has facilities throughout the Upper Great Plains. Asphalt and heavy fuel oil are transported from the refinery via truck from our seven-bay heavy products terminal and via rail and barge through our rail facilities and Mississippi River barge dock and are sold to a broad customer base. See “—Refining Operations Customers” below.

Refining Operations Suppliers

The primary input for our refinery is crude oil, which represented approximately 98% and 95% of our total refinery throughput volumes for the nine months ended September 30, 2012 and the year ended December 31, 2011, respectively. 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 also purchase ethanol and biodiesel, as well as conventional petroleum based blendstocks such as natural gasoline to supplement the fuels produced at the refinery. For more information, see “—Crude Oil Supply” and “—Other Feedstocks/Blendstocks.

Refining Operations Customers

Our refinery supplies substantially all of the gasoline and diesel sold in our company-operated and franchised convenience stores, as well as substantially all of the gasoline and diesel sold in 90 independently owned and operated Marathon branded stores in our marketing area. For the nine months ended September 30, 2012 and the year ended December 31, 2011, Marathon branded stores accounted for approximately 9% of our refined product sales volumes. For more information about the risks associated with our commercial relationship with Marathon, see “Risk Factors—General Business and Industry Risks—Our arrangements with Marathon expose us to Marathon related credit and performance risk.”

Asphalt and heavy fuel oil are sold to a broad customer base, including asphalt paving contractors, government entities (states, counties, cities and townships), and asphalt roofing shingle manufacturers.

Turnaround and Refinery Reliability

Periodically, we have planned maintenance turnarounds at our refinery, which require the temporary shutdown of certain operating units. 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, during which we replaced a catalyst in the distillate and gas oil hydrotreaters and conducted 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 in early May 2012. The next major turnaround is scheduled for 2013.

Seasonality

Our refining business experiences seasonal effects, as the demand for gasoline products is generally higher during summer months than during winter months due to seasonal increases in highway traffic. Demand for diesel during winter months also decreases due to declines in agricultural work. As a result, our results of operations related to our refinery business for the first and fourth calendar quarters are generally lower than for those for the second and third calendar quarters. In addition, unseasonably cool weather in summer months and/or unseasonably warm weather in winter months in the markets in which we sell our refined products can impact the demand for gasoline and diesel.

 

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Seasonal fluctuations in traffic also affect sales of motor fuels and merchandise in our convenience stores. 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. Unfavorable weather conditions during these months and a resulting lack of the expected seasonal upswings in traffic and sales could impact the demand for such higher profit margin items in those months.

Pipeline Assets

We acquired 17% of the outstanding common interests of the Minnesota Pipe Line Company and a 17% interest in MPL Investments which owns 100% of the preferred interests 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 St. Paul area and which supplies most of our crude oil input. The remaining interests in the Minnesota Pipe Line Company are held by a subsidiary of Koch Industries, Inc., the owner of the only other refinery in Minnesota, with a 74.16% interest, and TROF, Inc. with an 8.84% interest. The Minnesota Pipeline system is also operated by a subsidiary of Koch Industries, Inc. Because we 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 tariff is applied, including the tariff provisions governing the allocation of capacity, or control the decision-making with respect to tariff changes for the pipeline.

The Minnesota Pipeline system has multiple lines that run approximately 300 miles from Clearbrook in Clearwater County, Minnesota to Dakota County, Minnesota, transporting crude oil received through the Enbridge pipeline connections at Clearbrook from Western Canada and North Dakota to our refinery and Koch Industries’ Flint Hills Resources refinery in Minnesota. The system consists of a 24” pipeline, two parallel 16” pipelines and a partial third 16” pipeline with a combined capacity of approximately 455,000 bpd with further expansion capability to 640,000 bpd with the construction of an additional compressor station.

We also own an 8.6 mile 8” products pipeline, referred to as the Aranco Pipeline, which is leased to Magellan and used to ship refined products. The Aranco Pipeline extends from the refinery to a pipeline operated by Magellan as part of its products pipeline system. The pipeline is operated by Magellan as part of their products system. The annual lease fee was originally $450,000, subject to annual adjustment. The current annual lease amount is approximately $550,000. The term of the lease agreement is year-to-year and both parties have the right to terminate upon notice at least 180 days prior to the expiration of the then-current annual term. In November of 2011, we sent a letter to Magellan indicating that the lease agreement would terminate on May 31, 2012. Prior to that date, we entered into discussions with Magellan regarding the renegotiation of the lease and agreed to extend the lease agreement during the negotiations. In addition, we own the Cottage Grove pipelines, which are 16” and 12” pipelines extending from the Cottage Grove tank farm, which is used to house the Cottage Grove storage tanks, to the refinery.

Our Retail Business

We have a retail-marketing network of 234 convenience stores, as of September 30, 2012, located throughout Minnesota, Wisconsin and South Dakota, of which we operate 166 stores and support 68 franchised stores, as set forth by location in the table below. All of our company-operated and franchised convenience stores are operated under the SuperAmerica brand. We also own and operate SuperMom’s Bakery, which prepares and distributes baked goods and other prepared items for sale in our retail outlets and for other third parties. Substantially all of the fuel gallons sold at the 234 convenience stores for the nine months ended September 30, 2012 and the year ended December 31, 2011, was supplied by our refining business.

In December 2010, we entered into a lease arrangement with Realty Income, pursuant to which we leased 135 SuperAmerica convenience stores and one support facility over a 15-year initial term at an aggregate annual rent fixed for five years at an annual rate of $20.3 million, with consumer price index-based rent increases

 

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thereafter. The stores covered under the lease are located in Minnesota and Wisconsin, and average approximately 3,500 leasable square feet on approximately 1.14 acres. In addition, the individual locations have, on average, 6.5 multi-pump gasoline dispensers, and are seasoned stores with long-term operating histories. Additionally, 30 of our other company-operated properties are leased pursuant to a combination of ground leases and real property leases with third parties and one company-operated property is owned by us. The table below sets forth our company-operated and franchised stores by state as of September 30, 2012.

 

Location		Company- Operated				Franchised				Total
Minnesota			159				62				221
Wisconsin			6				5				11
South Dakota			1				1				2
Total			166				68				234

Below is a map illustrating the locations of our convenience stores as of September 30, 2012:

 

Of our company-operated sites, approximately 80% are open 24 hours per day and the remaining sites are open at least 16 hours per day. Our average store size is approximately 3,400 square feet with approximately 95% of our stores being 2,400 or more square feet. Our convenience stores typically offer tobacco products and immediately consumable items such as non-alcoholic beverages, beer and a large variety of snacks and prepackaged items. A significant number of the sites also offer state sanctioned lottery games, ATM services, money orders and car washes. We also provide support to 68 franchised convenience stores, selling gasoline, merchandise, and other services through SAF. SAF has license agreements in place with each franchisee that, among other things, cover the term of the franchise (generally 10 years), set forth the monthly royalty payments to be paid by franchisees to SAF, authorize the use of proprietary marks and provide for consultation services for the construction and opening of stores. Franchisees are required to pay to SAF 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, along with a separate diesel royalty fee. 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

 

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our distribution area, then the franchise store is not required to purchase any portion of its motor fuel supply from us. As of September 30, 2012, 33 of the 68 existing franchise stores are located within our distribution area and, thus, are required to purchase a high minimum percentage of their motor fuel supply from us.

Annual sales of refined products through our 166 owned and leased convenience stores averaged 342 million gallons over the period 2007-2011. The demand for gasoline is seasonal in nature, with higher demand during the summer months. 24.0% of the retail segment’s revenues were generated from non-fuel sales, including items like cigarettes, beer, milk, food and general merchandise for the nine months ended September 30, 2012. The following table summarizes the results of our retail business for the periods indicated.

 

		Nine Months  Ended September 30,								Year Ended December 31,
		2012				2011				2011				2010				2009
Company-operated
Fuel gallons sold (in millions)			231.6				245.8				324.0				345.1				335.7
Retail fuel margin ($/gallon)(1)		$	0.17			$	0.20			$	0.21			$	0.17			$	0.14
Merchandise sales ($ in millions)		$	269.3			$	253.9			$	340.3			$	336.4			$	328.4
Merchandise margin(%)(2)			25.4	%			25.5	%			25.4	%			26.1	%			26.8	%
Number of outlets at year end			166				166				166				166				166
Franchised Stores
Fuel gallons sold (in millions)			33.1				37.5				51.5				52.4				51.3
Royalty income (in millions)		$	1.5			$	1.2			$	1.7			$	1.6			$	1.6
Number of outlets at year end			68				67				67				67				68

 

(1)

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. For a reconciliation of retail fuel gross margin to retail segment operating income, the most directly comparable GAAP measure, see “Summary—Summary Historical Condensed Consolidated Financial and Other Data.”

(2)

Merchandise margin is expressed as a percentage of the merchandise sales, calculated by subtracting the costs of merchandise from the merchandise sales, and then dividing by merchandise sales. Merchandise margin is a non-GAAP performance measure that we believe is important to investors in evaluating our retail performance. Our calculation of merchandise margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. For a reconciliation of merchandise margin to retail segment operating income, the most directly comparable GAAP measure, see “Summary—Summary Historical Condensed Consolidated Financial and Other Data.”

Retail Operations Suppliers

Our refinery supplies substantially all of the gasoline and diesel sold in our company-operated and franchised convenience stores. We also own and operate SuperMom’s Bakery, which prepares and distributes baked goods and other prepared food items for sale in our SuperAmerica company-operated and franchised convenience stores and other third party locations.

Eby-Brown has been the primary supplier of general retail merchandise, including most tobacco and grocery items, for all our company-operated and franchised convenience stores since 1993. For the nine months ended September 30, 2012 and the year ended December 31, 2011, our retail business purchased approximately 75% 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 third-party manufacturers and their wholesalers. All merchandise is delivered directly to our stores by Eby-Brown, other third-party vendors or our SuperMom’s Bakery business. We do not maintain additional

 

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product inventories other than what is in our stores and at SuperMom’s Bakery. For information about the risks associated with our commercial relationship with Eby-Brown, see “Risk Factors—Risks Related to Our Business and Industry—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.”

Retail Operations Customers

Our retail customers primarily include retail end-users, motorists and commercial drivers. We have a retail-marketing network of 234 convenience stores, as of September 30, 2012, located throughout Minnesota, Wisconsin and South Dakota, of which we operate 166 stores and support 68 franchised stores.

Competition

Petroleum refining and marketing is highly competitive. With respect to our wholesale gasoline and distillate sales and marketing, we compete directly with Koch Industries’ Flint Hills Resources Refinery in Pine Bend, Minnesota, as well as the other refiners in the PADD II region and, to a lesser extent, major U.S. and foreign refiners. Many of our principal competitors are integrated, multinational oil companies that are substantially larger and more recognized than we are. The principal competitive factors affecting our refining segment are costs of crude oil and other feedstocks, refinery efficiency, refinery product mix and costs of product distribution and transportation. We have no crude oil reserves and are not engaged in the exploration or production of crude oil. We believe that we will be able to obtain adequate crude oil and other feedstocks at generally competitive prices for the foreseeable future.

Our major retail competitors include Holiday and Kwik Trip. The principal competitive factors affecting our retail segment are location of stores, product price and quality, appearance and cleanliness of stores and brand identification. We expect to continue to face competition from large, integrated oil companies, as well as from other convenience stores that sell motor fuels. Increasingly, grocery and dry goods retailers such as Wal-Mart are entering the motor fuel retailing business.

Insurance and Risk Management

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. Our property damage and business interruption coverage at the refinery has a maximum loss limit of $1 billion combined, with no sublimit for business interruption. Our business interruption coverage is for 24 months from the date of the loss, subject to a deductible of 45 days with a minimum loss of $15 million. Our property damage insurance has a deductible of $1 million. In addition, we have a full suite of insurance covering workers compensation, general products liability, directors’ and officers’ liability, environmental liability, safety and other applicable risk management programs. See also “Risk Factors—General Business and Industry Risks—Our insurance policies may be inadequate or expensive.”

Environmental Regulations

Refining Operations

Our refinery operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may obligate us to obtain and renew permits to conduct regulated activities; incur significant capital expenditures to install pollution control equipment; restrict the manner in which we may release materials into the environment; require remedial activities to mitigate pollution from former or current operations; apply specific health and safety criteria addressing worker protection; and impose substantial

 

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liabilities on us for pollution resulting from our operations. Certain of these environmental laws impose joint and several, strict liability for costs required to remediate and restore sites where petroleum hydrocarbons, wastes or other materials have been released or disposed. Failure to comply with environmental laws and regulations may result in the triggering of administrative, civil and criminal measures, including the assessment of monetary penalties, the imposition of remedial obligations, and the issuance of injunctions limiting or prohibiting some or all of our operations.

The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment and any changes in environmental laws and regulations that result in more restrictive and costly emission limits, operational controls, fuel specifications, waste handling, disposal or remediation requirements could have a material adverse effect on our operations and financial position. In the event of future increases in costs, we may be unable to pass on those increases to our customers. There can be no assurance that our future environmental compliance expenditures will not become material.

Air Emissions

Our operations are subject to the federal Clean Air Act, as amended, and comparable state and local laws and regulations. Under the Clean Air Act, facilities that emit regulated pollutants, including volatile organic compounds, particulates, sulfur, nitrogen oxides or hazardous air pollutants, face increasingly stringent regulations, including requirements to install various levels of control technology on sources of pollutants. For example, EPA published final amendments to the New Source Performance Standards (NSPS) for petroleum refineries on September 12, 2012 to be effective November 13, 2012. These amendments include standards for emissions of nitrogen oxides from process heaters and work practice standards and monitoring requirements for flares. To comply with the amendments, we plan to install and operate a continuous emissions monitoring system for nitrogen oxides on a process heater. We have already installed and will operate additional instrumentation on our flare. We anticipate the total cost for these two projects will be approximately $700,000 to be spent in 2012 and 2013. We continue to evaluate the regulation and amended standards, as may be applicable to the operations at our refinery. We cannot currently predict what additional costs that we may have to incur, if any, to comply with the amended NSPS. The costs could be material, but the time frame for compliance may extend over a number of years or upon changes or modifications to our refinery. In addition, the petroleum refining sector is subject to stringent new regulations adopted by the EPA, that impose maximum achievable control technology, (“MACT”) requirements on refinery equipment emitting certain listed hazardous air pollutants. Air permits are required for our refining operations that result in the emission of regulated air contaminants. These permits incorporate stringent control technology requirements and are subject to extensive review and periodic renewal.

Over the past decade, the EPA has pursued a National Petroleum Refinery Initiative, which is a coordinated, integrated compliance and enforcement strategy to address federal Clean Air Act compliance issues at the nation’s largest petroleum refineries. In connection with the initiative, Marathon (which previously owned the St. Paul Park Refinery) entered into an environmental settlement agreement with the EPA, the U.S. Department of Justice and the state of Minnesota in May 2001 (the “2001 Consent Decree”), pursuant to which pollution control equipment was installed to significantly reduce emissions from stacks, wastewater vents, valves and flares at the refinery, and which imposes additional, and in some cases more stringent, standards and requirements on the refinery beyond applicable regulatory requirements. We are currently participating in negotiations with the EPA, the Minnesota Pollution Control Authority (“MPCA”) and Marathon concerning termination of the 2001 Consent Decree as to our refinery. The EPA and the MPCA have proposed that the MPCA issue an amended Title V Air Permit to the refinery that incorporates the emission limits and requirements of the 2001 Consent Decree into the permit before (or coincidental with) terminating the 2001 Consent Decree as to our refinery. We submitted an application to the MPCA in June 2012 to make the proposed amendments to the Title V Air Permit, and the MPCA is currently evaluating our amendment application. If the MPCA issues an amended Title V Air Permit incorporating the 2001 Consent Decree requirements, we anticipate that the EPA and MPCA will file a motion with the court to terminate the 2001 Consent Decree as to our refinery. Alternatively, the EPA and MPCA may propose to first modify the 2001 Consent Decree to add our

 

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subsidiary as a named party and then move to terminate the decree as to our refinery. Negotiations regarding termination of the 2001 Consent Decree are ongoing.

In August 2012, the EPA issued an Enforcement Alert announcing that it is devoting significant resources to a new enforcement initiative targeting flares used in the petroleum refining and chemical manufacturing industries. Through the initiative, the EPA seeks to improve the operation of flares by, among other things, requiring enhanced monitoring and control systems and work practice standards. the EPA has already entered into flaring consent decrees with two refiners and will likely pursue similar consent decrees with additional refiners. In April 2012, EPA personnel visited our refinery to conduct a flare inspection. On August 14, 2012, we received a request for information from the EPA regarding the flare at our refinery. We responded on September 27, 2012. To date, the EPA has not alleged that we have violated any requirements applicable to our flare or requested that we enter into a flaring consent decree. Some of the additional flare instrumentation that we anticipate the EPA would require under a flaring consent decree has already been installed on our flare and will be put into operation to comply with the EPA’s recent amendments to the NSPS for petroleum refineries, as discussed above. We cannot currently predict the costs that we may have to incur if we were to enter into a flaring consent decree with the EPA, but they could be material.

The refinery is obligated to comply with the conditions of its Title V Permit as well as emissions limitations and other requirements imposed under the Clean Air Act and similar state and local laws and regulations. These requirements are complex and stringent. Any failure to comply with such requirements may result in fines, penalties, and corrective action orders. Such fines, penalties, and corrective action orders could reduce the profitability of our refining operations.

Fuel Quality Requirements

Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Securing Act of 2007, the EPA has issued RFS implementing mandates to blend renewable fuels into petroleum fuels produced and sold in the United States. We are subject to RFS. Under the RFS, the EPA establishes a volume of renewable fuels that obligated refineries must blend into their finished petroleum fuels. The obligated volume increases annually over time until 2022. Our refinery currently generates a surplus of RINS under the RFS for some fuel categories, but we must purchase RINS on the open market for other fuel categories. We must also purchase waiver credits for cellulosic biofuels from the EPA. 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.

Minnesota law currently requires that all diesel sold in the state for combustion 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 deadlines, but instead jointly recommended delaying the increase to 10% by one year, to May 1, 2013. We recently completed installing a new tank at our refinery to store biodiesel to enable us to comply with this mandate at a total cost of approximately $3.0 million dollars. 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. Federal law currently allows a maximum of 15% ethanol for cars and light trucks manufactured since 2001, and 10% ethanol for all other vehicles. Fuels produced at our refinery are currently blended with the appropriate amounts of ethanol or biodiesel to ensure that they comply with applicable federal and state renewable fuel standards. Blending renewable fuels into our finished petroleum fuels to comply with these requirements will displace an increasing volume of a refinery’s product pool.

 

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We also are required to meet the new Mobile Source Air Toxics (“MSAT II”) regulations to reduce the benzene content of gasoline. Under the MSAT II regulations, benzene in the finished gasoline pool was required to be reduced to an annual average of 0.62 volume percent by January 1, 2011 with or without the use of benzene credits and compliance was required to be demonstrated by January 1, 2012. Beginning on July 1, 2012, we must also maintain an annual average of 1.30 volume percent benzene without the use of benzene credits. A refinery may generate benzene credits by making reductions in the benzene content of the gasoline that it produces beyond what is required by the applicable regulations. These credits may be utilized by the refinery that generates them for future compliance, or they may be sold to other refineries. Our refinery’s average benzene content for 2012 may exceed the 0.62% limit. If that occurs, we anticipate using benzene credits we have accumulated in prior years and benzene credits purchased on the open market in order to comply with MSAT II requirements. We are also considering operational changes to lower the benzene content of the gasoline we produce. We may be required to purchase additional benzene credits to meet our compliance obligations in the future. The cost for purchase of credits is variable and market driven. If the market price of credits increases in the future, the costs to obtain the necessary number of benzene credits could become material.

We are also subject to other fuel quality requirements under federal and state law, including federal standards governing the maximum sulfur content of gasoline and diesel fuel manufactured at the refinery. If we fail to comply with any of these fuel quality requirements, we could be subject to fines, penalties and corrective action orders. Moreover, fuel quality standards could change in the future requiring us to incur significant costs to ensure that the fuels we produce continue to comply with all applicable requirements. For example, 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.

Climate Change

In response to certain scientific studies suggesting that emissions of GHGs including carbon dioxide and methane, are contributing to the warming of the Earth’s atmosphere and other climatic conditions, both houses of Congress have actively considered 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. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. Although it is not possible at this time to predict if or when Congress may pass climate change legislation, any future federal laws that may be adopted to address GHG emissions would likely require us to incur increased operating costs and could adversely affect demand for the refined petroleum products we produce.

In addition, on December 15, 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment. These findings allow the EPA to adopt and implement regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted two sets of regulations under the Clean Air Act. The first limits emissions of GHGs from motor vehicles beginning with the 2012 model year. The EPA has asserted that these final motor vehicle GHG emission standards trigger Clean Air Act construction and operating permit requirements for stationary sources, commencing when the motor vehicle standards took effect on January 2, 2011. On June 3, 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V permitting programs. This rule “tailors” these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest

 

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sources first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions also will be required to reduce those emissions according to “best available control technology” standards (“BACT”) for GHG that have yet to be fully developed. The EPA issued guidance in November 2010 to industry and permitting authorities on how to determine BACT for GHG emissions from new and modified sources. In addition, on October 30, 2009, the EPA published a final rule requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, including refineries, on an annual basis, beginning in 2011 for emissions occurring after January 1, 2010. We have been monitoring GHG emissions, and submitted our first annual report on these emissions to EPA in September 2011. Additionally, in December 2010, the EPA reached a settlement agreement with numerous parties pursuant to which it agreed to promulgate NSPS for GHG emissions from petroleum refineries by November 2012. To date, EPA has not proposed the NSPS for GHG emissions from petroleum refineries, and we cannot predict the requirements of these rules. The adoption of any regulations that require reporting of GHGs or otherwise limits emissions of GHGs from our refinery could require us to incur significant costs and expenses or changes in operations and such requirements also could adversely affect demand for the refined petroleum products that we produce.

Hazardous Substances and Wastes

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”), also known as the “Superfund” law, and comparable state and local laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. Such classes of persons include the current and past owners and operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations, such as landfills. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, for costs incurred by third parties and for the costs of certain environmental and health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. In the course of our operations, we generate wastes or handle substances that may be regulated as hazardous substances, and we could become subject to liability under CERCLA and comparable state laws.

We also may incur liability under the Resource Conservation and Recovery Act (“RCRA”), and comparable state and local laws, which impose requirements related to the handling, storage, treatment and disposal of solid and hazardous wastes. In the course of our operations, we generate petroleum product wastes and ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes. In addition, our operations also generate solid wastes, which are regulated under RCRA and state law.

Our refinery site has been used for refining activities for many years. Although prior owners and operators may have used operating and waste disposal practices that were standard in the industry at the time, petroleum hydrocarbons and various wastes have been released on or under our refinery site. There has been remediation of soil and groundwater contamination beneath the refinery for many years, and we are required to continue to monitor and perform corrective actions for this contamination until the applicable regulatory standards have been achieved. This remediation is being overseen by the MPCA pursuant to a compliance agreement entered into by the former owner and the agency in 2007. Based on current investigative and remedial activities, we believe that the contamination can be controlled or remedied without having a material adverse effect on our financial condition. However, such costs are often unpredictable, and there can be no assurance that future costs will not become material. We currently anticipate that we will incur costs of approximately $375,000 in 2012 and an additional $1.7 million through the year 2023 in connection with continued monitoring and remediation of this contamination at the refinery.

 

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Water Discharges

The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and stringent controls on the discharge of pollutants, including oil, into federal and state waters. Such discharges are prohibited, except in accordance with the terms of a permit issued by the EPA or the MPCA. Any unpermitted release of pollutants, including crude oil as well as refined products, could result in penalties, as well as significant remedial obligations. The spill prevention, control, and countermeasure requirements of federal and state laws require containment, such as berms or similar structures, to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak.

The refinery’s wastewater treatment plant utilizes two lagoons. Prior to our ownership of the refinery, Marathon reported to us and to the MPCA several instances in which concentrations of benzene in the wastewater flowing into the first lagoon exceeded the level that could potentially subject the lagoon to regulation as a hazardous waste unit. Between December 2010 and March 2011, we experienced three exceedances of benzene discharges into the first lagoon. We have reported these three instances to the MPCA, and the refinery has engaged in discussions with the MPCA regarding the implications and appropriate responses to these instances. If the benzene level was exceeded, the refinery could be subject to fines and penalties, and if no exemption from hazardous waste regulation applies, the refinery may be required to incur additional capital and operating costs and expenses. The MPCA initiated enforcement against Marathon relating to the instances of potentially excessive concentrations of benzene entering the lagoon that occurred during its period of ownership and against us for the three events between December 2010 and March 2011. Marathon settled with the State of Minnesota in November 2011. The MPCA enforcement against us remains pending. There can be no assurance that any fines, penalties, costs and expenses that we may incur will not become material. Under the agreements that we entered into with Marathon at the time of the acquisitions, we have the ability to seek reimbursement from Marathon on certain capital costs and expenses that we may incur in connection with any such enforcement action. In September 2012 we experienced one additional benzene exceedance that we promptly reported to the MPCA. The MPCA has not taken any enforcement action to date with respect to this event.

Environmental Capital and Maintenance Projects

A number of capital projects are planned for continued environmental compliance at our refinery. For example, in April of 2010, the MPCA issued a new permit that will govern stormwater discharges at the refinery. This new permit included a new effluent standard for total suspended solids (“TSS”). We plan to spend approximately $0.8 million and $1.2 million in 2012 and 2013, respectively, in order that the refinery will comply with the TSS standard by 2013, within the time allowed by the permit. We plan to spend approximately $300,000 over the next four years on a number of additional, smaller capital projects at the refinery related to environmental compliance. Additionally, we are currently implementing upgrades to the refinery’s wastewater treatment plant, including changes to the process used to treat the wastewater, construction of new tanks, closure of one of the existing lagoons, and dredging and disposal of sludge that has accumulated in one of the lagoons. We estimate that costs could be as high as $42.6 million over the next two years, beginning in 2012. Pursuant to the agreements entered into in connection with the Marathon Acquisition, we believe that Marathon is required to reimburse us for a portion of the costs and expenses incurred in these wastewater treatment plant upgrades. In October 2012, we made a claim to Marathon for reimbursement in the amount of $2.6 million and are in discussions with Marathon with respect to that claim.

Health, Safety and Maintenance

We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state occupational safety laws. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be available to employees and contractors and, where required, to state and local government

 

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authorities and to local residents. We provide all required information to employees and contractors on how to avoid or protect against exposure to hazardous materials present in our operations. Also, we maintain safety, training and maintenance programs as part of our ongoing efforts to ensure compliance with applicable laws and regulations. We believe that the refinery is in substantial compliance with OSHA and similar state laws, including general industry standards, recordkeeping and reporting, hazard communication and process safety management. The refinery is currently in the process of installing Safety Instrumented Systems to enhance its safety program, and the estimated incremental costs for these installations are $12.5 million over the next two years. The refinery also plans to spend approximately $2.95 million in 2012, with additional costs in future years, depending on project scheduling, to replace relief valves to improve safety. Furthermore, the refinery has budgeted approximately $3.8 million in 2012 for additional safety and process safety management projects.

Pipelines

We own three pipelines: (1) the “Aranco Pipeline,” which connects the refinery to a pipeline owned by Magellan, (2) a 16” pipeline connecting the refinery to the Cottage Grove tank farm and (3) a 12” pipeline connecting the refinery to the Cottage Grove tank farm. Potential environmental liabilities associated with pipeline operation include costs incurred for remediating spills or releases and maintaining the integrity of the pipeline to prevent such spills and releases. Under a lease agreement, Magellan operates the Aranco Pipeline and, as between the parties, bears the responsibility and costs for any leaks or spills from the Aranco Pipeline, as well as for maintenance activities.

We also own an equity interest in the Minnesota Pipe Line Company, which owns and operates the pipeline that provides the primary supply of crude oil to the refinery. Between the parties, the Minnesota Pipe Line Company bears the responsibility and costs for any leaks or spills from the pipeline, as well as for maintenance activities.

Retail Business

Our retail business operates convenience stores with fuel stations in Minnesota, Wisconsin, and South Dakota. Each retail station has underground fuel storage tanks, which are subject to federal, state and local regulations. Complying with these underground storage tank regulations can be costly. The operation of underground storage tanks also poses environmental risks, including the potential for fuel releases and soil and groundwater contamination. We are currently completing the investigation and remediation of reported leaks from underground storage tanks at a number of our convenience stores. We currently anticipate that the known contamination at these stores can be remediated for approximately $160,000 through the end of 2012, and an additional cost of approximately $210,000 through the end of 2015. It is possible that we may identify more leaks or contamination in the future that could result in fines or civil liability for us, as well as remediation obligations and expenses. States, including Minnesota, have established funds to reimburse some expenses associated with remediating leaks from underground storage tanks, but such state reimbursement funds may not cover all remediation costs.

Other Government Regulation

Our transportation activities are subject to regulation by multiple governmental agencies. Our 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. Further, the regulatory burden on the industry increases the cost of doing business and affects profitability. Additional proposals and proceedings that affect the oil industry are regularly considered by Congress, the states, FERC and the courts. We cannot predict when or whether any such proposals may become effective or what impact such proposals may have.

 

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The ICA and its implementing regulations give FERC authority to regulate the rates and the terms and conditions of service of interstate common carrier oil pipelines, such as the Minnesota Pipeline. The ICA and its implementing regulations require that tariff rates and terms and conditions of service of interstate common carrier oil pipelines be just and reasonable and not unduly discriminatory or preferential. The ICA also requires that oil pipeline tariffs setting forth transportation rates and the rules and regulations governing transportation services be filed with FERC.

In October 1992, Congress passed the Energy Policy Act of 1992 (“EPAct”), which, among other things, required FERC to issue rules to establish a simplified and generally applicable ratemaking methodology for petroleum pipelines and to streamline procedures in petroleum pipeline proceedings. FERC responded to this mandate by establishing a methodology for petroleum pipelines to change their rates within prescribed ceiling levels that are tied to an inflation index. Pipelines are allowed to raise their rates to the rate ceiling level generated by application of the index. If the methodology reduces the ceiling level such that it is lower than a pipeline’s filed rate, the pipeline must reduce its rate to conform with the lower ceiling unless doing so would reduce a rate “grandfathered” by EPAct to below the grandfathered level. A pipeline must, as a general rule, use the indexing methodology to change its rates. FERC, however, retained cost-of-service ratemaking, market based rates, agreement with an unaffiliated shipper, and settlement as alternatives to the indexing approach that may be used in certain specified circumstances. The Minnesota Pipeline currently uses the indexing methodology to set its tariff rates. In order for the Minnesota Pipeline to increase rates beyond the maximum allowed by the indexing methodology, it must 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. We do not control the board of managers of the Minnesota Pipe Line Company and thus do not control the decision-making with respect to tariff changes for the Minnesota Pipeline.

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. The current or any revised indexing formula could hamper our ability to recover our costs because: (1) the indexing methodology is tied to an inflation index; (2) it is not based on pipeline-specific costs; and (3) it could be reduced in comparison to the current formula. Further, shippers may protest rate increases made within the ceiling levels, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year. Shippers may also file complaints against index-based rates, but such complaints must either meet the foregoing standard for protests or show that the pipeline is substantially over-recovering its cost of service and that application of the index substantially exacerbates that over-recovery. In addition, due to the common carrier regulatory obligation applicable to interstate oil pipelines, in the event there are nominations in excess of capacity, capacity must be prorated among shippers in an equitable manner in accordance with the tariff then in effect. Therefore, nominations by new shippers or increased nominations by existing shippers may reduce the capacity available to us.

EPAct deemed petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of EPAct that had not been subject to complaint, protest or investigation during that 365-day period to be just and reasonable under the ICA (“grandfathered”). There are grandfathered rates underlying Minnesota Pipeline’s current rates. Absent a successful challenge against the grandfathered rates, these rates act as a floor below which the pipeline’s rates cannot be lowered. Generally, shippers challenging grandfathered rates must show that a substantial change has occurred since the enactment of EPAct in either the economic circumstances of the oil pipeline, or in the nature of the services provided, that were a basis for the rate. EPAct places no such limit on challenges to a provision of an oil pipeline tariff as unduly discriminatory or preferential. If a shipper were to successfully challenge the grandfathered portion of the Minnesota Pipeline’s rates, the Minnesota Pipeline would no longer benefit from the floor provided by these grandfathered rates, which could adversely affect the Minnesota Pipe Line Company’s financial position, cash flows and results of operations.

 

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Under certain circumstances, including a change in FERC’s ratemaking methodology for oil pipelines or a protest or complaint filed by a shipper, FERC could limit the Minnesota Pipe Line Company’s ability to set rates based on its costs, could order it to reduce its rates, and/or could require the payment of refunds and/or reparations to shippers. 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. Conversely, reduced rates on the Minnesota Pipeline will reduce the rates we are charged as a shipper for transportation of crude oil on the Minnesota Pipeline into our refinery. If FERC found the Minnesota Pipeline’s terms of service to be contrary to statutory requirements, FERC could impose conditions it considers appropriate and/or impose penalties. Further, FERC could declare non-jurisdictional 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.

The Aranco Pipeline, currently leased to and operated by Magellan, is part of Magellan’s interstate pipeline system and, as a result, we are not required to maintain a tariff with respect to the Aranco Pipeline. If this lease were to be terminated and the pipeline were used to transport crude oil or petroleum products in interstate commerce, the Aranco Pipeline would be subject to the interstate common carrier regulatory regime discussed above in the context of the Minnesota Pipeline and we would be required to comply with such regulation in order to operate the Aranco Pipeline. In addition, if the 16” and/or 12” pipelines connecting the refinery to the Cottage Grove tank farm were to provide interstate crude oil or petroleum product transportation service, they would be subject to the same interstate common carrier regulatory regime discussed above.

The Federal Trade Commission, FERC and the Commodity Futures Trading Commission hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of oil or other energy commodities, and any related hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations, and financial condition.

Our petroleum pipeline facilities are also subject to regulation by the U.S. Department of Transportation with respect to their design, installation, testing, construction, operation, replacement and management. We are also subject to the requirements of the Federal Occupational Safety and Health Act and other comparable federal and state statutes that address employee health and safety. Compliance costs associated with these regulations can potentially be significant, particularly if higher industry and regulatory safety standards are imposed in the future.

Legal Proceedings

We are not currently a party to any legal proceedings that, if determined adversely against us, individually or in the aggregate, would have a material adverse effect on our financial position, results of operations or cash flows. Marathon, however, is a named defendant in certain lawsuits, investigations and claims arising in the ordinary course of conducting the business relating to the assets we acquired from Marathon, including certain environmental claims and employee-related matters. For a discussion of certain environmental settlements and consent decrees relating to the assets we acquired from Marathon, see “—Environmental Regulations.” While the outcome of these lawsuits, investigations and claims against Marathon cannot be predicted with certainty, we do not expect these matters to have a material adverse impact on our business, results of operations, cash flows or financial condition. We have not assumed any liabilities arising out of these lawsuits, investigations and claims against Marathon. Marathon also 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. In addition, from time to time, we are involved in lawsuits, investigations and claims arising out of our operations in the ordinary course of business.

 

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Intellectual Property

We hold and use certain trade secret and confidential information related specifically to our refining operations. In addition, we are party to various process license agreements that allow us to use certain intellectual property rights of third parties in our refining operations pursuant to fully-paid up licenses. We do not own any patents relating to the refining business but license a limited number of patents from Marathon based on the previous use of such patents in our refining operations.

Employees

As of September 30, 2012, we employed 3,044 people, including 422 employees associated with the operations of our refining business and 2,567 employees associated with the operations of our retail business. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are party to collective bargaining agreements covering approximately 180 of our 422 employees associated with the operations of our refining business and 23 of our 2,567 employees associated with the operations of our retail business. The collective bargaining agreements covering the employees associated with our refining and retail businesses expire in December 2013 and August 2014, respectively. We consider our relations with our employees to be satisfactory.

Properties

Our principal executive offices are located at 38C Grove Street, Suite 100, Ridgefield, Connecticut 06877. The location and general character of our principal refineries, retail locations and other important physical properties have been described by segment under “—Our Refining Business” and “—Our Retail Business.” We believe that our properties and facilities are generally adequate for our operations and that our facilities are maintained in a good state of repair. We are the lessee under a number of cancelable and non-cancelable leases for certain properties. Our leases are discussed more fully in Note 17 to our audited consolidated financial statements.

 

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Management

Our Management

Our general partner, the indirect owners of which include ACON Refining, TPG Refining and Hank Kuchta, our President and Chief Executive Officer and a member of the board of directors of our general partner, manages our operations and activities subject to the terms and conditions specified in our partnership agreement. The operations of our general partner in its capacity as general partner are managed by its board of directors. Actions by our general partner that are made in its individual capacity will be made by its owners, and not by the board of directors of our general partner. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. The executive officers of our general partner will manage our day-to-day activities consistent with the policies and procedures adopted by the board of directors of our general partner.

Limited partners will not be entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Northern Tier Holdings will appoint all of the directors of our general partner. Pursuant to the limited liability company agreement of our general partner, Northern Tier Holdings will appoint two directors designated by ACON Refining (referred to as the “ACON directors”), two directors designated by TPG Refining (referred to as the “TPG directors” and collectively with the ACON directors, the “Sponsor Directors”), up to two members of management and at least three other directors (including independent directors) mutually designated by ACON Refining and TPG Refining. Each member of the board, other than the Sponsor Directors, will have one vote, and each Sponsor Director will have three votes for purposes of calculating whether a majority of the board has voted in favor of or against any action. All actions of the board, other than any matters delegated to a committee, will require approval by majority vote of the directors, which must include votes cast in favor by at least one ACON director and one TPG director. Our partnership agreement contains various provisions which replace default fiduciary duties under applicable law with contractual corporate governance standards. See “The Partnership Agreement.” Our general partner will be liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly non-recourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are non-recourse to it.

Whenever our general partner makes a determination or takes or declines to take an action in its individual, rather than representative, capacity, it is entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to us, any limited partner or assignee, and it is not required to act in good faith or pursuant to any other standard imposed by our partnership agreement or under Delaware law or any other law. Examples include the exercise of its call right, its voting rights and its determination whether or not to consent to any merger or consolidation of the partnership.

As a publicly traded partnership, we qualify for, and 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 and the requirements that the board of directors of our general partner have compensation and nominating/corporate governance committees that are composed entirely of independent directors. As a result of these exemptions, our general partner’s board of directors is not comprised of a majority of independent directors and our general partner’s compensation and nominating & governance committees are not comprised entirely of independent directors. 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.

Board Committees

The board of directors of our general partner may establish a conflicts committee consisting entirely of independent directors. Pursuant to our partnership agreement, our general partner may, but is not required to, seek the approval of the conflicts committee whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any public unitholder, on the other. The conflicts committee may then

 

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determine whether the resolution of the conflict of interest is in our best interests. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the independence standard established by the NYSE and the Exchange Act to serve on an audit committee of a board of directors. While our partnership agreement provides that a conflicts committee may be comprised of one or more directors, it is our intent that any such conflicts committee would consist of at least two independent directors. See “Conflicts of Interest and Fiduciary Duties.”

In addition, as required by the Exchange Act and the listing standards of the NYSE, the board of directors of our general partner will maintain an audit committee comprised of at least three independent directors. The board of directors of our general partner currently has an audit committee comprised of three directors, Messrs. Hofmann, Liaw and Josey. Each of Mr. Hofmann and Mr. Josey meets the independence standards established by the NYSE and the Exchange Act for membership on an audit committee. Within one year of the effectiveness of the registration statement relating to our initial public offering (the “effective date”), all members of the audit committee will be independent.

The audit committee oversees, reviews, acts on and reports to the board of directors of our general partner on various auditing and accounting matters, including: the selection of our independent accountants, the scope of our audits, fees to be paid to the independent accountants, the performance of our independent accountants and our accounting practices. In addition, the audit committee oversees our compliance programs relating to the legal and regulatory requirements as they relate to financial reporting.

The board of directors of our general partner has a compensation committee comprised of Messrs. Aronson, Josey, Liaw and Smith. This committee establishes salaries, incentives and other forms of compensation for officers and certain other employees of our general partner.

In addition, the board of directors of our general partner has a nominating & governance committee comprised of Messrs. Ginns, Hofmann and MacDougall. This committee identifies, evaluates and recommends qualified nominees to serve on the board of directors of our general partner, makes recommendations regarding appropriate corporate governance practices and assists in implementing those practices and maintains a management succession plan.

Executive Officers and Directors

We are managed and operated by the board of directors and executive officers of our general partner. In this prospectus, we refer to the executive officers of our general partner as “our executive officers.” The following table sets forth the names, positions and ages of our executive officers and directors:

 

Name		Age				Title
Dan F. Smith			65			Executive Chairman of the Board of Directors
Hank Kuchta			55			President, Chief Executive Officer and Director
Bernard W. Aronson			65			Director
Jonathan Ginns			47			Director
Michael MacDougall			41			Director
Eric Liaw			31			Director
Thomas Hofmann			60			Director
Scott D. Josey			54			Director
David Bonczek			42			Vice President and Chief Financial Officer
Greg Mullins			59			President, St. Paul Park Refining Company

 

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Set forth below is a description of the backgrounds of our directors and executive officers.

Dan F. Smith has served as Executive Chairman of the board of directors of our general partner since December 2012, as Chairman of the board of directors of our general partner since June 2012 and Northern Tier Energy LLC since November 2011 and as a director of Northern Tier Energy LLC since May 2011. Mr. Smith is the former chairman, president and chief executive officer of Lyondell Chemical Company. He began his career with ARCO (Atlantic Richfield Company) in 1968 as an engineer. He was elected president of Lyondell Chemical Company in August 1994, chief executive officer in December 1996 and chairman of the board of directors in May 2007. Mr. Smith retired in December 2007 from Lyondell Chemical Company following the acquisition of Lyondell by Basell Polyolefins. Mr. Smith also served as chief executive officer of Equistar Chemicals, LP from December 1997 through December 2007 and as chief executive officer of Millennium Chemicals Inc. from November 2004 until December 2007. Equistar and Millennium are wholly owned subsidiaries of Lyondell. Since retiring from Lyondell in December 2007, Mr. Smith has served as a director of a number of companies. Mr. Smith has been a director of Cooper Industries, PLC since 1998, chairman and a director of Kraton Performance Polymers, Inc. since 2008, chairman and a director of Valerus Compression Services, L.P. since 2010, and chairman and a director of Nexeo Solutions, LLC since 2011. He also serves as a member of the College of Engineering Advisory Council at Lamar University. Mr. Smith is a graduate of Lamar University with a B.S. degree in chemical engineering.

Mr. Smith brings valuable expertise to the board due to his extensive executive experience at the highest levels, including more than ten years of experience as the chief executive officer of a major chemical company.

Hank Kuchta has served as President and Chief Executive Officer of our general partner and of Northern Tier Energy LLC since December 2012, and as a director of our general partner since June 2012 and of Northern Tier Energy LLC since December 2010. Prior to December 2012, Mr. Kuchta served as President and Chief Operating Officer of our general partner since June 2012 and of Northern Tier Energy LLC since December 2010. From January 2010 until July 2012, Mr. Kuchta served as an independent director of the general partner of TransMontaigne G.P., LLC. Since 2006, Mr. Kuchta has been a member of NTR Partners LLC. Mr. Kuchta served as a director as well as president and chief operating officer of NTR Acquisition Co. from 2006 to 2009. Prior to NTR Partners LLC, Mr. Kuchta served as president of Premcor, Inc. from 2003 until 2005 and as chief operating officer of Premcor, Inc. from 2002 until 2005. In 2002, Mr. Kuchta served as executive vice president-refining of Premcor. Premcor operated four refineries in the United States and had approximately 750,000 bpd of refining capacity at the time of its sale to Valero Energy Corporation in April 2005. From 2001 until 2002, Mr. Kuchta served as business development manager for Phillips 66 Company following Phillips’ 2001 acquisition of Tosco Corporation. Prior to Phillips, Mr. Kuchta served in various corporate, commercial and refining positions at Tosco Corporation from 1993 to 2001. Before joining Tosco, Mr. Kuchta spent 12 years at Exxon Corporation in various refining, engineering and financial positions, including assignments overseas. He holds a B.S. in chemical engineering from Wayne State University.

Mr. Kuchta’s extensive operational experience in the refining industry gives him an appreciation for the business practices that are critical to the success of a growing business such as ours.

Bernard W. Aronson has served as a director of our general partner since June 2012 and of Northern Tier Energy LLC since December 2010. Mr. Aronson co-founded ACON Investments LLC in 1996 and has served as managing partner of ACON Investments, L.L.C. since 1996. He has previously served as international advisor to Goldman, Sachs & Co., executive speechwriter and special assistant to the Vice President of the United States and Assistant Secretary of State for Inter-American Affairs. Following his State Department service from 1989 to 1993, he was presented the Distinguished Service Award by the Secretary of State, the State Department’s highest honor. Mr. Aronson has served on the board of directors of Hyatt Hotels Corp since 2004, Liz Claiborne Inc. since 1998, Royal Caribbean Cruise Lines since 1993, and Chroma Oil & Gas since 2008. He chairs the governance committee of Hyatt. He served as director and chair of the governance committee of Mariner Energy Inc. until November 2010 when Mariner Energy merged with Apache Oil and Gas. Mr. Aronson also serves on

 

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the board of directors of The National Democratic Institute for International Affairs and the Maryland/D.C. chapter of the Nature Conservancy. He is a member of the Council on Foreign Relations and the Inter-American Dialogue. Mr. Aronson graduated with honors from the University of Chicago.

Mr. Aronson has significant corporate governance experience as a result of having served on a number of public company boards of directors and board committees. He also brings valuable knowledge of the energy industry as a result of his services on the board of directors of Mariner Energy.

Jonathan Ginns has served as a director of our general partner since June 2012 and of Northern Tier Energy LLC since December 2010. Mr. Ginns co-founded ACON Investments LLC in 1996 and has served as managing partner of ACON Investments, L.L.C since 1996. Mr. Ginns has served on a number of public and private boards of directors. He has served on the board of directors of Signal International Inc. since 2003, Milagro Exploration since 2007 and Chroma Oil & Gas Corp since 2008. Mr. Ginns received an M.B.A. from the Harvard Business School, and a B.A. from Brandeis University.

Mr. Ginns’ background as a member of multiple public company boards of directors and familiarity with the energy industry are both assets to the board.

Michael MacDougall has served as a director of our general partner since June 2012 and of Northern Tier Energy LLC since December 2010. Mr. MacDougall is a TPG Partner. Mr. MacDougall leads TPG’s global energy and natural resources investing efforts. Prior to joining TPG in 2002, Mr. MacDougall was a vice president in the Principal Investment Area of the Merchant Banking Division of Goldman, Sachs & Co., where he focused on private equity and mezzanine investments. He is a director of Amber Holdings (successor to certain assets of Alinta Energy), Copano Energy, L.L.C., Energy Future Holdings Corp. (formally TXU Corp.), Graphic Packaging Holding Company, Harvester Holdings, L.L.C., Nexeo Solutions, LLC and Maverick American Natural Gas, LLC, and the general partner of Valerus Compression Services, L.P. He is also a member of the board of directors of the Dwight School Foundation, Islesboro Affordable Property, The Opportunity Network and The University of Texas Development Board. Mr. MacDougall received his B.B.A., with highest honors, from The University of Texas at Austin and received his M.B.A., with distinction, from Harvard Business School.

Mr. MacDougall’s extensive transactional and investment banking experience, his experience as a private equity investor and his experience as a director of other public companies enable Mr. MacDougall to provide valuable insight regarding complex financial and strategic issues in our industry.

Eric Liaw has served as a director of our general partner since June 2012 and of Northern Tier Energy LLC since December 2010. Mr. Liaw is a TPG Vice President. Mr. Liaw is focused on TPG’s global energy and natural resources investing efforts. Prior to joining TPG in 2008, Mr. Liaw attended Harvard Business School from 2006 to 2008. Prior to attending Harvard Business School, Mr. Liaw was an associate at Bain Capital from 2004 to 2006, where he focused on private equity investments. He is a director of Harvester Holdings, L.L.C. and the general partner of Valerus Compression Services, L.P. Mr. Liaw received his B.A., with highest honors, and B.B.A., with highest honors, from the University of Texas at Austin and received his M.B.A., with distinction, from Harvard Business School.

Mr. Liaw’s knowledge of the energy and natural resources industry, his transactional experience as a private equity investor, and his experience on the boards of Harvester Holdings, L.L.C. and the general partner of Valerus Compression Services, L.P. make him a valuable asset to the board.

Thomas Hofmann has served as a director of our general partner since June 2012 and of Northern Tier Energy LLC since May 2011. Since December 2008, Mr. Hofmann has been retired. Mr. Hofmann served as senior vice president and chief financial officer of Sunoco, Inc., an oil refining and marketing company, from January 2002 to December 2008. Mr. Hofmann also serves as a director of West Pharmaceuticals Services, Inc.

 

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and a director of the general partner of Penn Virginia Resource Partners, L.P. In the last five years, he has also served on the board of directors of the general partner of Sunoco Logistics Partners, L.P. and VIASYS Healthcare Inc. Mr. Hofmann received a B.S. degree from the University of Delaware and a master’s degree from Villanova University.

As the former chief financial officer of Sunoco, Inc., Mr. Hofmann has substantial experience and knowledge regarding financial issues related to energy companies and the energy industry. His extensive financial, management and strategic experiences allow him to provide critical insights to the board.

Scott D. Josey has served as a director of our general partner since June 2012 and of Northern Tier Energy LLC since May 2011. Since October 2011, Mr. Josey has been the chief executive officer of Sequitur Energy Management LLC, which performs management oversight services for exploration and production companies. Mr. Josey has owned Chromatic Industries since May 2011, which provides engineered valves to the energy industry. Mr. Josey is the former chairman, president and chief executive officer of Mariner Energy, Inc. He served as the chairman of the board of Mariner Energy, Inc. from August 2001 until November 2010, when Mariner merged with Apache Corporation. He was appointed chief executive officer of Mariner in October 2002 and president in February 2005. From 2000 to 2002, he served as vice president of Enron North America Corp. and co-managed its Energy Capital Resources group. From 1995 to 2000, Mr. Josey provided investment banking services to the oil and gas industry and portfolio management services to institutional investors as a co-founder of Sagestone Capital Partners. From 1993 to 1995, he was a director with Enron Capital & Trade Resources Corp. in its energy investment group. From 1982 to 1993, he worked in all phases of drilling, production, pipeline, corporate planning and commercial activities at Texas Oil and Gas Corp. Since February 2011, Mr. Josey has served as a director of Apache Corporation and currently serves on the executive committee. He is a member of the board and chairman of the compensation committee of the Association of Former Students of Texas A&M University and is also a member of the Society of Petroleum Engineers and the Independent Petroleum Association of America. Mr. Josey obtained a B.S. degree in mechanical engineering from Texas A&M University, his M.B.A. from the University of Texas at Austin and his M.S. in petroleum engineering from the University of Houston.

Mr. Josey has spent his entire 30-year career in the oil and gas industry and as the former chief executive officer of Mariner Energy, Inc., he gained extensive management, financial and technical expertise in the energy field, which brings valuable experience to the board.

David Bonczek has served as Vice President and Chief Financial Officer of our general partner since June 2012 and of Northern Tier Energy LLC since August 2011. Mr. Bonczek previously served as the chief accounting officer for Northern Tier Energy LLC from March to August 2011. Prior to joining Northern Tier Energy LLC, Mr. Bonczek was assistant corporate controller at Chemtura Corporation, a NYSE-listed company, from April 2008 through March 2011. From September 1998 through March 2008, Mr. Bonczek held finance management positions within Eastman Kodak including corporate controller of their Kodak Polychrome Graphics joint venture. Mr. Bonczek began his career with KPMG where his last position was senior manager in their audit practice. Mr. Bonczek received a B.S. degree in accounting from Binghamton University, and he is a Certified Public Accountant.

Greg Mullins has served as President, St. Paul Park Refining Company, since December 2010. Mr. Mullins has a B.S. in chemical engineering from Wayne State University and worked for Marathon Petroleum from 1978 until January 2008. From January 2008 until August 2010, Mr. Mullins was retired. From August 2010 until joining St. Paul Park Refining Co. LLC in December 2010, Mr. Mullins performed consulting work for NTR Partners LLC. During his career with Marathon, Mr. Mullins worked at several of Marathon’s refineries as well as the Findlay, Ohio corporate offices. He has extensive experience in all aspects of refinery operations and management as well as major project development and project management. He has developed and managed refining capital and expense budgets, worked in business development, and led Marathon’s due diligence team for the prospective purchase of BP’s Lima refinery. He developed and sponsored the Detroit refinery expansion

 

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while incorporating the requirements for ultra low sulfur fuels while staging the refinery to include significantly larger volumes of heavy, sour Canadian crudes. Mr. Mullins is currently a member of the American Institute of Chemical Engineers, served as an expert panel member for the 2007 National Petroleum Refiners Association Q & A, a former member of the American Petroleum Institute Operating Practices Committee and chaired the Wayne State University Industrial Advisory Board for the Chemical and Metallurgical Engineering Department from 2002 to 2007.

Compensation Discussion and Analysis

The following discussion and analysis of compensation arrangements (“CD&A”) of our named executive officers for 2012 (as set forth in the Summary Compensation Table below) should be read together with the compensation tables and related disclosures set forth below. This discussion contains forward-looking statements that are based on our current plans, considerations, expectations and determinations regarding future compensation programs. Actual compensation programs that we adopt may differ materially from the currently planned programs summarized in this discussion.

Summary of Our Executive Compensation Program

Our executive compensation program has generally been overseen by our board of directors or an informal subcommittee of our board of directors, along with significant input from our senior management team. The ultimate responsibility for making decisions relating to the compensation of our named executive officers differs depending on the compensation element at issue. For the year ended December 31, 2012, our board of directors generally made all decisions regarding salary, a subcommittee of our board of directors (the “Compensation Committee”) addressed overall compensation for Messrs. Rodriguez and Kuchta (our former and current chief executive officer, respectively), and our senior management team made recommendations to the board of directors regarding all elements of compensation.

We determined that for our fiscal year ended December 31, 2012, the following individuals met the standards of a “named executive officer” for the 2012 fiscal year:

 

•

Hank Kuchta—President and Chief Executive Officer;

 

•

Mario Rodriguez—Former Chief Executive Officer;

 

•

David Bonczek—Vice President and Chief Financial Officer; and

 

•

Greg Mullins—President, St. Paul Park Refining Company.

Mr. Rodriguez left our company on December 20, 2012 and was succeeded in the role of Chief Executive Officer by Mr. Hank Kuchta. We have determined that as of December 31, 2012, no other individual met the standards necessary to classify him or her as a “named executive officer.”

Objectives of Our Executive Compensation Program

We have, and will continue to design, an executive compensation program with the following objectives:

 

•

The recruitment and retention of talented individuals for key leadership positions;

 

•

The linking of compensation to an executive’s individual performance and our financial performance; and

 

•

The alignment of our executives’ compensation opportunities with our short-term and long-term financial objectives.

 

 

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Key Components of Our Compensation Policy

In furtherance of our objectives for our executive compensation program, we have created both fixed and variable compensation elements for our compensation program. We desire to provide a certain level of fixed elements, such as salary and health and welfare benefits, in order to provide stability and reliability to our executives. These fixed compensation elements are important because they allow our executives to keep their main focus on our business objectives. However, we believe that variable compensation elements, such as annual cash bonuses and equity incentive awards, allow us to incentivize and reward our executives in years where they have provided us with superior services, and this “pay for performance” concept aligns the executive’s goals with those of our unitholders. Our named executive officers received compensation in the following forms during the 2012 fiscal year:

 

•

Base salary;

 

•

Annual bonus awards;

 

•

Long-term equity incentive awards in the form of profits interests in NTI Management Company, L.P. (“NTI Management”), one of our affiliates that is owned in part by our President and Chief Executive Officer;

 

•

Eligibility for participation in our 2012 LTIP;

 

•

Severance and change in control provisions;

 

•

Participation in a cash balance retirement plan; and

 

•

Participation in broad-based retirement, health and welfare benefits.

We implemented a new equity-based incentive compensation plan during the 2012 year. See “—2012 Long Term Incentive Plan” below for more details. Mr. Bonczek was the only named executive officer to receive an LTIP award during the 2012 year, which was in the form of restricted units.

In January 2012 our board of directors engaged Pearl Meyer & Partners (“PMP”), an independent compensation consulting firm, to review our current compensation programs and to assist us in identifying our peer group. In September 2012, the Board utilized information received from PMP to establish a peer group that we could use to compare our executive compensation program to the executive compensation programs at our peers. The selected group includes businesses in the refining and convenience store retail businesses, as well as certain companies that are similarly structured.

The structure of each of the compensation elements provided to our named executive officers during the 2012 fiscal year is described in detail below.

Components of Executive Compensation Program

Base Salary

Each named executive officer’s base salary is a fixed component of compensation and does not vary depending on the level of performance achieved. Base salaries are determined for each named executive based on his or her position and responsibility. Our board of directors generally reviews the base salaries for each named executive annually as well as at the time of any promotion or significant change in job responsibilities, and in connection with each review the board of directors considers individual and company performance over the course of that respective year. Our board of directors and our named executive officers worked together to determine appropriate levels of base salary compensation for our named executive officers. They also utilized our internal human resources staff to look at publicly available information regarding salaries at various companies within our industry.

 

 

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With respect to Messrs. Rodriguez and Kuchta, their base salaries are set forth in formal employment agreements that we entered into on December 1, 2010. Mr. Rodriguez had a base salary of $500,000 per year, while Mr. Kuchta has a base salary of $450,000 per year. Mr. Rodriguez’s employment agreement provided and Mr. Kuchta’s employment agreement provides that our board of directors will set and review the base salary, and that our board of directors may increase, but not decrease, the base salary at any time.

Messrs. Bonczek and Mullins also received offer letters prior to beginning their employment with us. Mr. Bonczek originally received his offer letter on February 7, 2011, when he was hired as our Chief Accounting Officer and Corporate Controller. We increased the annual base salary set forth in Mr. Bonczek’s offer letter from $235,000 to $270,000 as of August 29, 2011, in order to reflect the change in his position to Chief Financial Officer. Our offer letter to Mr. Mullins was dated December 1, 2010, and provides him with an annual base salary of $275,000.

The base salary earned by each named executive officer for the 2012 fiscal year is set forth in the Summary Compensation Table below. Following our annual review of each named executive officer’s base salary, we increased the annual base salaries of Messrs. Bonczek and Mullins to $300,000 and $295,000, respectively, effective February 27, 2012.

Bonuses

Each of the named executive officers will be eligible to receive annual bonus payments pursuant to an incentive compensation plan (the “Bonus Plan”), which is designed to encourage our employees to achieve our business objectives and to attract and retain key employees through the opportunity for substantial performance-related incentive compensation. For the 2012 calendar year, the Bonus Plan was designed to fully align employee interests with those of our unitholders through primary focus on financial performance, namely earnings before interest, taxes, depreciation, and amortization (“EBITDA”). While the financial drivers of the 2012 Bonus Plan, such as EBITDA, represented our primary performance measurement, our Compensation Committee retained the right to exercise full discretion to apply other financial or performance measures in determining the payment amount of any individual’s bonus award following its review of our performance during the 2012 year.

The 2012 Bonus Plan set a target bonus award for each participant based upon a percentage of that individual’s base salary. The percentage of salary for the 2012 target Bonus Plan awards was 100% with respect to Messrs. Rodriguez and Kuchta, 70% for Mr. Bonczek, and 65% for Mr. Mullins. Senior management team participants will generally earn 0% to 200% of their target bonus amount under the Bonus Plan subject to any discretionary adjustments made by our Compensation Committee. Once a performance metric for the plan is chosen, the Compensation Committee will assign threshold, target and maximum levels applicable to the performance metric to act as guidelines at the end of the performance period, which will be each full calendar year. If applicable performance targets are earned at a threshold level, the general payout for senior management team participants will be 40% of the target bonus; if performance targets are earned at target, 100% of the target bonus will typically be paid; and if performance targets are earned at maximum levels, up to 200% of the target bonus may be paid.

No participant will be entitled to any payments under the Bonus Plan until the individual’s award is approved by our Compensation Committee. Our Compensation Committee has not yet made bonus determinations for the 2012 year. We expect that our Compensation Committee will set the bonus amounts for the 2012 Bonus Plan during the first quarter of the 2013 year. A participant should also by and large be employed on the date that the awards are paid to employees in order to receive an award payment, although our Compensation Committee has the discretion to award a pro-rata payment in the event of a participant’s death, disability, or retirement.

Mr. Bonczek and certain other non-executive employees in his department received one-time discretionary awards in the 2012 year in order to reward them for their extraordinary efforts related to our initial public

 

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offering. Mr. Bonczek’s award was divided into a cash portion of $25,000, and an equity compensation award granted pursuant to the 2012 LTIP and described below. Mr. Bonczek’s cash award was paid to him in a single lump sum in September of 2012.

Long-Term Equity-Based Incentives

During the 2010 fiscal year, the named executive officers (other than Mr. Bonczek, who received his initial grant in 2011 upon his entry into employment with us) received units in NTI Management, which is a limited partner of Northern Tier Investors, LP (“NTI LP”). See “Prospectus Summary—Organizational Structure” for a description of our relationship to NTI LP. The incentive units were granted to the members of our then-current senior management team on December 1, 2010 following the close of the Marathon Acquisition. The NTI Management units granted were Class C units, which are designed as profits interests rather than capital interests. Class C units are further divided into series, from Class C1 to Class C5 units, which correspond to Class C1 to Class C5 units in NTI LP that NTI Management received from NTI LP. Profits interests in NTI LP have no value for tax purposes on the date of grant, but instead are designed to gain value only after NTI LP has realized a certain level of returns for the holders of other classes of NTI LP’s equity. Under the NTI LP partnership agreement, distributions with respect to NTI LP units are made first to Class A common unit holders, until such holders have received a full return of their capital contributions to NTI LP. Distributions are next made to Class A unit holders, Class C1 unit holders and Class D unit holders in accordance with their sharing percentages, until the Class C2 unit threshold is met. Once the Class C2 unit threshold is met, the holders of Class C2 units become eligible to receive distributions alongside the Class A unit holders, the Class C1 unit holders and the Class D unit holders. This process of adding an additional Class C level to the distribution chain continues until Class C5 unit holders are included. Notwithstanding the preceding, once distributions to Class A unit holders from NTI LP equal an aggregate sum of $3.5 million plus 200% of their capital contributions, then distributions will be made solely to holders of Class D units until the Class D unit holders receive $3.5 million. Following the satisfaction of the distribution thresholds described in the preceding sentence, holders of NTI Management units receive distributions from NTI Management that correspond to the distributions made to NTI Management by NTI LP. All Class C units in NTI Management are subject to a five-year vesting schedule, which will lapse in equal 20% installments on each anniversary of the grant date of the units. The vesting schedule may be accelerated in certain situations, which is described in more detail within the “Potential Payments Upon Termination or a Change in Control” section below.

Messrs. Rodriguez and Kuchta each received a grant of Class C2, Class C3, Class C4 and Class C5 units in NTI Management in December 2010 upon the closing of the Marathon Acquisition. Mr. Mullins received grants of Class C1, Class C2 and Class C3 units in NTI Management in 2010. Messrs. Rodriguez and Kuchta chose to reserve the grant of Class C1 units for other executive officers due to the fact that the Class C1 units will receive a payout, if at all, at an earlier date than the remaining classes of units. Messrs. Rodriguez and Kuchta agreed to receive the Class C4 and Class C5 units, which will pay out at a later date. Mr. Bonczek received grants of Class C1, Class C2 and Class C3 units in NTI Management on March 14, 2011 in connection with his entry into employment with us.

We believe that overall business success creates meaningful value to both our unitholders and, through their equity holdings, our executives. During the 2012 year, our board of directors determined that the Class C NTI Management units were satisfying our goal of aligning executive and unitholder interests, and granted Messrs. Bonczek and Mullins additional Class C NTI Management units. Mr. Bonczek received 113,906 Class C1 units, and 190,008 each of Class C2 and C3 units. Mr. Mullins received 57,759 Class C1 units, and 96,320 each of Class C2 and C3 units. The actual value associated with a potential payment of Messrs. Bonczek’s and Mullins’ units granted in 2012 is described in greater detail in the “Grants of Plan-Based Awards for the 2012 Fiscal Year” table below. The NTI Management Class C units that were granted to our named executive officers from 2010 to 2012 were intended to provide an immediate and significant alignment between our executives and the success of our business. The information provided with respect to these NTI Management Class C units is provided in order to comply with the disclosure rules of the SEC regarding historical and current material compensation items, but

 

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we do not expect that additional grants of NTI Management Class C units or other NTI Management units will comprise a part of our executive compensation program in the future due to our adoption of the 2012 LTIP described below.

In order to incentivize our management to continue to grow our business, our general partner adopted a new long-term incentive plan, the Northern Tier Energy LP 2012 Long-Term Incentive Plan (the “2012 LTIP”), in connection with our initial public offering, for the benefit of employees and directors of us, our general partner and each of our affiliates, who perform services for us. Each of the named executive officers is eligible to participate in the 2012 LTIP. The 2012 LTIP provides us with the flexibility to grant unit options, restricted units, unit awards, phantom units, unit appreciation rights, cash awards, distribution equivalent rights, substitute awards, and other unit-based awards, or any combination of the foregoing. These awards are intended to align the interests of plan participants (including the named executive officers) with those of our unitholders and to give plan participants the opportunity to share in our long-term performance.

At the time of this filing, Mr. Bonczek was the only named executive officer who received an award under the LTIP in 2012. Mr. Bonczek received a grant of 2,778 restricted units in recognition for his services to us during our initial public offering.

Severance and Change in Control Benefits

We maintained certain agreements with our named executive officers during the 2012 fiscal year that provided for severance and/or change in control protections. We believe that severance protection provisions create important retention tools for us, as post-termination payments allow employees to leave our employment with value in the event of certain terminations of employment that were beyond their control. Post-termination payments allow management to focus their attention and energy on making the best objective business decisions that are in our interest without allowing personal considerations to cloud the decision-making process. Further, we believe that change in control protections maximize unitholder value by encouraging the named executive officers to review objectively any proposed transaction in determining whether such proposal or termination is in the best interest of our unitholders, whether or not the executive will continue to be employed. Executive officers at other companies in our industry and the general market against which we compete for executive talent commonly have post-termination payments, and we have provided this benefit to the named executive officers in order to remain competitive in attracting and retaining skilled professionals in our industry.

A more detailed description of the severance and change in control provisions that we provide to our named executive officers can be found in the “Potential Payments Upon Termination or a Change in Control” section below.

Other Benefits

We provide our employees, including our named executive officers, with health and welfare benefits, as well as certain retirement plans. We currently maintain a plan intended to qualify under section 401(k) of the Code, where employees are allowed to contribute portions of their base compensation into a retirement account. We provide a matching contribution in amounts up to 7.0% of the employees’ eligible compensation, and an additional 2.0% non-elective annual contribution that will not vest until the end of a three-year period of service. The amounts that we contributed to each named executive officer’s account for the 2012 year are reflected in the Summary Compensation Table below. Section 401(k) of the Code provides certain limitations on the amounts that a key employee may contribute or receive into his 401(k) plan account each year, thus we also established the Northern Tier Energy LLC Supplemental Plan (the “Supplemental Plan”) in 2012 in order to provide those employees with a means of receiving the same company contributions that our other employees may receive from us. A more detailed description of the Supplemental Plan may be found in the “Nonqualified Deferred Compensation” section below.

 

 

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We adopted a cash balance retirement plan for our employees in November 2011, which is a defined benefit pension plan. Plan benefits are 5% of eligible annual compensation, plus a specified interest credit. Participant account balances are subject to a three-year cliff vesting schedule. Named executive officer account balances at the end of 2012 are listed in the Pension Benefits table.

We believe that our named executive officers should operate under substantially similar conditions as our employees generally, thus we do not generally provide perquisites to our named executive officers.

Other Compensation Items

Separation Agreement with Mr. Rodriguez. In connection with Mr. Rodriguez’s resignation on December 20, 2012, Mr. Rodriguez and Northern Tier Energy LLC entered into a Separation Agreement and General Release (the “Separation Agreement”) that provides Mr. Rodriguez, in exchange for signing a general release of claims in favor of Northern Tier Energy LLC and its affiliates, with certain severance payments. Please see “Potential Payments upon Termination or a Change in Control” for more details about the Separation Agreement.

Unit Ownership Guidelines and Hedging Policies. We do not currently have any unit ownership guidelines or hedging policies in place at this time, although we expect that our Compensation Committee will consider this issue in the near future.

Clawback Policies. If required by the Sarbanes-Oxley Act of 2002 and/or by the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, any incentive or equity-based award provided to one of our employees shall be conditioned on repayment or forfeiture in accordance with applicable law, any company policy, and any relevant provisions in the applicable award agreement.

 

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Summary Compensation Table

The table below sets forth the annual compensation earned during the 2012 fiscal year (and for those individuals that were also considered named executive officers during the 2011 and 2010 years, the 2011 and 2010 fiscal years) by our named executive officers.

 

Name and Principal Position		Year				Salary ($)(1)				Bonus ($)(2)				Option Awards ($)(3)				Stock Awards ($)(4)				Change in Pension Value ($)				All Other Compensation ($)(5)				Total ($)
Hank Kuchta			2012				450,000				450,000				—				—				12,947				22,099				935,046
President and Chief Operating Officer;			2011				450,000				270,000				—								12,250				21,749				753,999
Chief Executive Officer (after 12/20/2012)			2010				37,500				—				1,887,958				—				—				—				1,925,458
Mario Rodriguez			2012				500,000				—				—				—								509,346	(6)			1,009,346
Former Chief Executive Officer			2011				500,000				300,000				—				—				12,250				25,846				838,096
			2010				41,667				—				2,307,504				—				—				—				2,349,171
David Bonczek			2012				294,231				210,000				361,957				71,367				12,870				12,654				963,079
Vice President and Chief Financial Officer			2011				192,211				150,000				121,488				—				6,312				7,572				477,583
																			—
Greg Mullins			2012				291,154				191,750				183,500				—				13,138				17,500				697,042
President, St. Paul Park Refining Company			2011				275,000				290,000				—				—				11,421				13,327				589,748

 

(1)	Amounts in this column for the 2012 year reflect an increase in salary in February 2012 to $300K and $295K for Mr. Bonczek and Mr. Mullins, respectively.

(2)

The amounts reported in this column for the 2012 year reflect estimates of the amounts that will be paid pursuant to our Bonus Plan for the 2012 year. These values reflect each named executive officer’s “target” bonus amount. Senior management team participants will generally earn 0% to 200% of their target bonus amount under the Bonus Plan subject to any discretionary adjustments made by our Compensation Committee. We expect that the bonuses will be determined and paid in the first quarter of 2013, and we will file a Form 8-K at that time in order to disclose the amounts that are actually paid.

(3)

Despite the fact that profits interests such as the NTI Management Class C units do not require the payment of an exercise price, we believe that these awards are economically similar to stock options due to the fact that they have no value for tax purposes at grant and will obtain value only as the price of the underlying security rises, and as such, are required to be reported in this title under the “Option Awards” column. Amounts included reflect the grant date fair value of the NTI Management Class C units granted to Messrs. Bonczek and Mullins on February 28, 2012, computed in accordance with FASB ASC Topic 718. The assumptions used to calculate these values for the 2012 grants were as follows: (a) the expected term was 6.5 years; (b) current price of the underlying unit was $1.58; (c) the expected volatility was 55.5%; (d) the expected dividend yield was 0.0%; and (e) the risk-free investment rate was 1.4%.

(4)

The amount in this column for Mr. Bonczek represents the grant date fair value of the restricted units granted to him in December of 2012. The restricted unit values were computed in accordance with FASB ASC Topic 718, which used the closing trading price of our common units on the grant date of December 19, 2012 of $25.69, multiplied by the number of restricted units granted (2,778).

(5)	Other than with respect to Mr. Rodriguez, amounts included here reflect the contribution that each named executive officer received from us in the form of matching contributions into their 401(k) plan accounts for

 

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the 2012 year. To the extent that the 401(k) plan account could not receive the full amount of our matching contributions, we made those contributions into the Supplemental Plan. Amounts contributed to the Supplemental Plan were as follows: $6,250 for Mr. Kuchta, $4,519 for Mr. Bonczek and $6,250 for Mr. Mullins. In addition, we paid a life insurance premium on behalf of Mr. Kuchta to MetLife in the amount of $4,599.

(6)	This number reflects a $500,000 payment as set forth in Mr. Rodriguez’s separation agreement, and $9,346 for life insurance policy premiums that we paid on behalf of Mr. Rodriguez.

Grants of Plan-Based Awards for the 2012 Fiscal Year

 

Name

Grant Date

Number of Securities Underlying Options (#)(1)

Exercise or Base Price of Option Awards ($/Sh)

All Other Stock Awards: Number of Units (#)

Grant Date Fair Value of Stock and Option Awards ($)(2)

David Bonczek

Class C1 Units

2/28/2012

113,906

N/A

N/A

97,243

Class C2 Units

2/28/2012

190,008

N/A

N/A

141,652

Class C3 Units

2/28/2012

190,008

N/A

N/A

123,061

Restricted Units

12/19/2012

2,778

71,367

Greg Mullins

Class C1 Units

2/28/2012

57,759

N/A

N/A

49,310

Class C2 Units

2/28/2012

96,320

N/A

N/A

71,807

Class C3 Units

2/28/2012

96,320

N/A

N/A

62,383

 

(1)

As explained in Footnote 3 to the Summary Compensation Table above, awards reflected in this column represent the number of NTI Management Class C units granted to Messrs. Bonczek and Mullins (the only named executive officers that received such awards during the 2012 fiscal year), rather than actual “option” awards.

(2)	Amounts reflected in this column reflect the grant date fair value of the NTI Management Class C units, or our restricted units, as applicable, in accordance with FASB ASC Topic 718.

Narrative Description to the Summary Compensation Table and the Grant of Plan-Based Awards Table for the 2012 Fiscal Year

We entered into a formal employment agreement with Mr. Kuchta on December 1, 2010. The employment agreement has a term of employment of one year, with automatic one-year renewals, absent notice by either the executive or us of the intention not to renew the agreement. Mr. Kuchta has an annual base salary of $450,000, and an annual cash incentive bonus target of 100% of his annual base salary. Mr. Kuchta is eligible to participate in our employee benefit programs, plans and practices in accordance with the terms and conditions of the individual plans, and we provide a life insurance benefit to him in an amount that will equal no less than 200% of his base salary. The employment agreement contains severance protections, standard confidentiality, non-solicitation and non-compete provisions, each of which is described in greater detail in the “Potential Payments Upon a Termination or Change in Control” section below.

Mr. Bonczek’s offer letter originally provided him with a salary of $235,000, which was increased to $270,000 by our board of directors in August of 2011 in order to reflect his new position as Chief Financial Officer, and again in 2012 to $300,000. The potential severance benefits for Mr. Bonczek are further described in the “Potential Payments Upon a Termination or Change in Control” below. Mr. Mullins’ offer letter was provided to him on December 1, 2010, and set forth his base salary of $275,000, which was modified by our board of directors in 2012 to $295,000.

 

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While Mr. Rodriguez previously had an employment agreement that set forth his salary and bonus opportunities, upon his resignation the Separation Agreement terminated those provisions and he received payments and benefits disclosed in the “Potential Payments Upon Termination or a Change of Control” pursuant to the Separation Agreement.

The NTI Management Class C units are generally subject to a five year, equal installment vesting schedule. The potential acceleration or forfeiture events relating to these units are described in greater detail within the “Potential Payments Upon Termination or a Change of Control” section below.

Percentage of Salary and Bonus in Comparison to Total Compensation

 

Name		Salary and Bonus Percentage of Total Compensation*
Hank Kuchta			98	%
David Bonczek			61	%
Greg Mullins			76	%

 

*	These numbers were calculated using our bonus estimates, and may change following a final determination of bonus numbers.

Outstanding Equity Awards at 2012 Fiscal Year-End

The following table provides information on the current restricted units and NTI Management Class C units held by the named executive officers. This table includes unvested NTI Management Class C units. The vesting dates for each award are shown in the accompanying footnotes.

 

Option Awards (1)

Stock Awards Number of Units that have not Vested (#)

Market Value of Units that have not Vested ($)

Name

Number of Securities Underlying Unexercised Options (#) Unexercisable

Number of Securities Underlying Unexercised Options (#) Exercisable

Option Exercise Pric ($)

Option Expiration Date

Hank Kuchta

Class C2 Units(2)

742,500

495,000

N/A

N/A

Class C3 Units(2)

742,500

495,000

N/A

N/A

Class C4 Units(2)

1,316,250

877,500

N/A

N/A

Class C5 Units(2)

1,316,250

877,500

N/A

N/A

Mario Rodriguez

Class C2 Units

0

453,750

N/A

N/A

Class C3 Units

0

453,750

N/A

N/A

Class C4 Units

0

804,375

N/A

N/A

Class C5 Units

0

804,375

N/A

N/A

David Bonczek

Class C1 Units(3)

161,906

12,000

N/A

N/A

Class C2 Units(4)

306,008

29,000

N/A

N/A

Class C3 Units(5)

306,008

29,000

N/A

N/A

Restricted Units(6)

2,778

71,367

Greg Mullins

Class C1 Units(7)

177,759

80,000

N/A

N/A

Class C2 Units(8)

276,320

120,000

N/A

N/A

Class C3 Units(9)

276,320

120,000

N/A

N/A

 

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(1)

As explained above, unless otherwise indicated, the applicable equity awards that are disclosed in these tables are NTI Management Class C units rather than traditional “option” awards. Awards reflected as “Unexercisable” are NTI Management Class C units that have not yet vested. Awards reflected as “Exercisable” are NTI Management Class C units that have vested, but have not yet been settled. For a description of how and when the NTI Management Class C units could become exercisable (including as a result of the offering contemplated in this prospectus) and be settled and paid out, see the discussion in the “Potential Payments upon Termination or a Change in Control” below.

(2)	Each unexercisable unit reflected in this row has the same vesting schedule, which will vest in equal installments on December 1, 2013, 2014 and 2015.

(3)	Of the unexercised awards reflected in this row, 48,000 will vest in equal installments on March 14th of each of years 2013, 2014, 2015 and 2016; 113,906 will vest in equal installments on February 28th of each of years 2013, 2014, 2015, 2016 and 2017.

(4)	Of the unexercised awards reflected in this row, 116,000 will vest in equal installments on March 14th of each of years 2013, 2014, 2015 and 2016; 190,008 will vest in equal installments on February 28th of each of years 2013, 2014, 2015, 2016 and 2017.

(5)	Of the unexercised awards reflected in this row, 116,000 will vest in equal installments on March 14th of each of years 2013, 2014, 2015 and 2016; 190,008 will vest in equal installments on February 28th of each of years 2013, 2014, 2015, 2016 and 2017.

(6)	The restricted units will vest in three equal tranches upon December 19, 2013, 2014 and 2015.

(7)	Of the unexercised awards reflected in this row, 120,000 will vest in equal installments on December 1st of each of years 2013, 2014 and 2015; 57,759 will vest in equal installments on February 28th of each of years 2013, 2014, 2015, 2016 and 2017.

(8)	Of the unexercised awards reflected in this row, 180,000 will vest in equal installments on December 1st of each of years 2013, 2014 and 2015; 96,320 will vest in equal installments on February 28th of each of years 2013, 2014, 2015, 2016 and 2017.

(9)	Of the unexercised awards reflected in this row, 180,000 will vest in equal installments on December 1st of each of years 2013, 2014 and 2015; 96,320 will vest in equal installments on February 28th of each of years 2013, 2014, 2015, 2016 and 2017.

Option Exercises and Stock Vested in the 2012 Fiscal Year

 

		Option Awards(1)
Name		Number of Units Acquired on Exercise (#)(1)						Value Realized on Exercise ($)(2)
Hank Kuchta					1,372,500				0
Mario Rodriguez					838,750				0
Greg Mullins					160,000				0
Dave Bonczek					70,000				0

 

(1)

As explained above, the applicable equity awards that are disclosed in these tables are NTI Management Class C units rather than traditional “option” awards. The numbers shown here reflect only the number of NTI Management units that became vested during the 2012 year. The NTI Management Units were not designed with exercise features, therefore there was no settlement associated with the vesting of the units.

(2)	Amounts shown in this column reflect our best estimate of the value of the NTI Management Class C units that each named executive officer actually received upon the vesting of the awards.

 

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Pension Benefits

Each of the named executive officers is eligible to participate in the cash balance pension plan that we adopted during November 2011.

 

Name		Plan Name		Number of Years Credited Service (#)				Present Value of Accumulated Benefit ($)				Payments During 2012 Fiscal Year ($)
Hank Kuchta		Northern Tier Energy Retirement Plan			2.08				25,197				—
David Bonczek		Northern Tier Energy Retirement Plan			1.8				19,182				—
Greg Mullins		Northern Tier Energy Retirement Plan			2.08				24,559				—

The Northern Tier Energy Retirement Plan (the “Plan”) is a funded, tax-qualified, noncontributory defined benefit pension plan that covers certain employees. Eligible employees under the Plan include all employees with benefit classifications of refinery, corporate or terminal who have attained age 21 and completed three months of service. Excluded employees include all those with other benefit classification codes, temporary employees, independent contractors and collectively bargained employees under an agreement that does not provide for participation in the Plan. The Plan is designed as a cash balance plan wherein a participant’s account is credited each year with a pay credit and an interest credit such that increases and decreases in the value of the Plan’s investments do not directly affect the benefit amounts promised to participants.

As of the end of the Plan year, the Plan provides for a pay credit equal to 5% of Compensation (as defined below) for each participant who has completed an hour of service during the Plan year. If a participant’s employment is terminated during the Plan year, he is entitled to the pay credit as of the date of termination. Compensation under the Plan includes wages under Section 3401(a) of the Code excluding severance pay, sign-on bonuses, or any signing bonuses paid to collectively bargained employees.

In addition, each calendar month, the Plan also provides for an interest credit equal to the participant’s account balance times the one plus the applicable interest rate to the 1/12th power minus 1. Participants are not entitled to interest credits beginning on or after the annuity starting date unless the benefit is paid solely to satisfy Section 401(a)(9) of the Code or during the Plan year of termination. The applicable interest rate is the average annual yield on 30-year U.S. Treasury bonds for September of the immediately preceding calendar year. For 2013, the interest crediting rate will be 2.77%.

A participant is 100% vested in his or her account upon completion of three years of vesting service (includes service with Marathon Oil and Marathon Petroleum based on the most recent date of hire). If a participant terminates for a reason other than death or disability before completion of this time period, he or she forfeits all benefits under the Plan. If a participant attains normal retirement age, dies or becomes disabled, then he or she is entitled to 100% vesting. A participant attains normal retirement age at age 65. A participant is deemed to be disabled if he or she qualifies for benefits under the long-term disability plan or qualifies for Federal Social Security disability benefits.

The amount of benefit payable with respect to a participant will be his or her vested account balance if payable in lump sum or the actuarially equivalent of such balance if paid in another form; however, where a participant terminated after attaining his or her normal retirement date, the benefit is the greater of the vested account balance or the actuarial increase in such balance as of the end of the preceding Plan year (or, of later, his or her normal retirement date). The normal form of distribution is a qualified joint and survivor annuity if the participant is married on his or her annuity starting date or a single life annuity if he or she is unmarried on that date. Optional forms of distribution include as follows: (1) lump sum, (2) single life annuity, (3) qualified joint and survivor annuity, or (4) the optional joint and survivor annuity.

 

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Nonqualified Deferred Compensation

 

Name		Registrant Contributions In the 2012 Fiscal Year ($)*				Aggregate Earnings in 2012 Fiscal Year ($)				Aggregate Withdrawals Or  Distributions ($)						Aggregate Balance At 2012 Year End ($)
Hank Kuchta			6,250				163						0				6,431
David Bonczek			4,519				57						0				4,576
Greg Mullins			6,250				150						0				6,400

 

*	Each of the amounts in this column are reflected in the “All Other Compensation” column of the Summary Compensation Table above for the 2012 year.

We established the Supplemental Plan during the 2012 year. Eligible participants in the plan will be active employees that are required to receive a reduced company matching contribution into our 401(k) plan due to the non-discrimination requirements in the 401(k) plan. At this time the employees are not allowed to contribute any of their own compensation into the plan, thus the only amounts that will be deferred into the plan will be company contributions and any earnings thereon.

The Supplemental Plan participants are not vested in their accounts until they have completed three years of service with us. However, in the event that the participant reaches retirement (at age 65), or separates from service due to his death or disability (defined below), the account will receive immediate vesting. If the participant separates from service for any other reason prior to the account being vested, the account balance will be forfeited. If the participant is terminated for cause (defined below), the account balance, whether vested or unvested, will be forfeited. The Supplemental Plan accounts will also receive immediate vesting in the event of a change in control (which is defined by reference to such term in the regulations published for Section 409A of the Code). A “disability” is defined in the Supplemental Plan to have occurred with our long term disability insurance program (which is compliant with Section 409A of the Code) has deemed the participant to be disabled, or when the Social Security Administration or the Railroad Retirement Board would deem the participant to be totally disabled. The term “cause” generally means the participant’s act or failure that results in the participant’s conviction of, or plea of guilty to, a misdemeanor involving moral turpitude or any non-traffic related felony; the willful breach of a fiduciary duty, gross negligence or material misconduct; material or intentional repeated violation of our internal policies or procedures; fraud, embezzlement, theft or intentional misrepresentation related to us or our clients; willful engagement in a conflict of interest, self-dealing or usurpation of an opportunity belonging to us; or intentional breach of any covenants made with us involving trade secrets, confidentiality, noncompetition or other similar covenant.

Participants must make certain elections upon becoming eligible to participate in the Supplemental Plan. Participants are allowed to make investment decisions regarding their accounts, and such decisions may be subsequently changed or modified by the participant. The investment fund options and the respective interest rates for the 2012 year are generally the same as these that are provided to our 401(k) participants. For a quantification of the earnings the Supplemental Plan participants received due to their investment choices, see the “Aggregate Earnings in 2012 Fiscal Year” above. The participant must also establish when and how the participant desires to receive distributions from the Supplemental Plan, otherwise the default distribution form will be a lump sum cash payment. If a participant separates from service, the election options will be a lump sum cash payment or five years of annual installment payments (subject to any delay that may be required pursuant to Section 409A of the Code). If a change in control is to occur, a participant may choose to receive his or her account balance, which would override the elections made for a separation from service. If an account balance still exists at the time of a participant’s death, the participant’s beneficiaries will receive the balance of the Supplemental Plan account in the form of a lump sum cash payment.

The plan administrator may approve an early distribution from the Supplemental Plan if the participant has suffered a financial hardship or an unforeseeable emergency, in an amount limited to the amount necessary to alleviate the hardship.

 

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While we enter each participant’s accounts as a bookkeeping entry, we have set up a rabbi trust to assist us in funding the Supplemental Plan. This trust will only be used to fund payments to the Supplemental Plan, although it will remain subject to our creditors.

Potential Payments Upon Termination or a Change in Control

We provide our named executive officers with certain severance and change in control benefits. The rationale for providing these benefits to our executives is described in detail in the CD&A above.

Employment Agreement and Offer Letters, Separation Agreement

On termination of Mr. Kuchta’s employment by us or the executive due to a notice of non-renewal, he will receive any earned but yet unpaid base salary, any earned but yet unpaid bonus for the year that precedes the year in which his termination occurs, reimbursement of any business expenses incurred and all employee benefits he may be entitled to receive under our employee benefit plans (the “Accrued Rights”), and a pro-rata portion of any annual performance bonus that he would have been entitled to receive for the year in which the termination occurs (the “Pro-rata Bonus”). If we deliver the notice of non-renewal to Mr. Kuchta, he will also receive continued base salary payments for a period of twenty-four months.

In the event that Mr. Kuchta is terminated by us without Cause or by him with Good Reason (each term defined below), he will be entitled to the Accrued Rights, his Pro-rata Bonus, his annual base salary for the twenty-four month period following the date of his termination of employment and certain health care continuation benefits for the eighteen-month period following the date of termination of his employment (the “Medical Benefits”). If he incurs Disability (as defined below) during his employment with us, he will receive the Accrued Rights, the Medical Benefits, any amounts that may be payable to him pursuant to any long-term disability plan that we may maintain at the time of his termination from service due to that Disability (that will be paid through insurance policies rather than by the company directly), and continued payments of his base salary for the period of time, if any, that our short-term disability policy covering him is in effect before the long-term disability policy becomes effective. A termination of employment for Cause or due to death will result solely in the payment of any Accrued Rights. “Cause” is generally defined for Mr. Kuchta as (1) the executive’s failure to comply with any reasonable instruction from our board of directors; (2) the executive’s misconduct, resulting from willful or grossly negligent conduct, which is materially injurious to us or our affiliates; (3) the executive’s intentional or knowingly fraudulent act against us, our customers, clients or employees; (4) the executive’s material breach of his employment agreement; or (5) the executive being charged with, convicted of, or pleading guilty or no contest to a felony or a crime involving fraud, dishonesty or moral turpitude. “Good Reason” is defined in the employment agreement as: (1) our failure to continue the executive in his current position, or to reelect or reappoint the executive to our board of directors, (2) our material breach of the employment agreement, (3) a substantial adverse reduction in the executive’s duties or responsibilities, or (4) our relocation of our business offices more than twenty miles away from its present location. Mr. Kuchta may be considered to have incurred a “Disability” if he meets the definition for such term in our long-term disability plan in effect at such time.

Mr. Kuchta will only receive the severance benefits described above upon his execution of a general release in our favor, and subject to his continued compliance with the restrictive covenants in his employment agreement. He will be subject to restrictive covenants following his termination of employment, including non-compete, non-disclosure of confidential information and non-solicitation provisions, in the case of the non-compete provision, for a one year period and in the case of the non-solicitation provision, for a two year period.

If Mr. Kuchta is a “specified employee” under Section 409A of the Code at the time of his termination of employment, there are certain severance payments that could create an excise tax for him if the timing of that payment occurs immediately following his termination of employment. In the event that Mr. Kuchta is deemed to

 

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be a “specified employee” and the severance or any portion of the severance payment due to him would create excise taxes under Section 409A of the Code, his employment agreement states that we will defer the payment of that amount until the date that is six months following the executive’s termination of employment.

Both Messrs. Bonczek and Mullins have an offer letter that sets forth certain potential severance and change in control benefits. During the 2012 year our board of directors reviewed the offer letters that we provided to Messrs. Bonczek and Mullins upon the beginning of their employment, and made certain modifications to the severance benefits that were contained within Mr. Bonczek’s letter to make it consistent with Mr. Mullins letter. Both Messrs. Bonczek and Mullins will now receive a severance payment equal to one (1) year of their respective then-current annual base salaries, and the acceleration of vesting for any outstanding equity awards, in the event that the executive is terminated in connection with a change in control. In the event that either of the executive’s employment is terminated for any other reason (other than for Cause), or he resigns for Good Reason, he would receive a severance payment equal to one (1) year of his then-current annual base salary.

For purposes of the offer letters, “cause” shall generally mean (i) the executive’s continuous failure to substantially perform his duties (other than any failures due to a disability); (ii) gross misconduct or gross negligence; or (iii) the executive’s conviction of, or entering a plea of, guilty or nolo contendere to the commission of a felony. A “good reason” termination could occur following (a) a material diminution of the executive’s position, duties or responsibilities; (b) a reduction in the executive’s base salary or bonus opportunities; (c) a material reduction of the executive’s employee benefit plan opportunities; (d) a required relocation of more than 40 miles from Ridgefield Connecticut; or (e) our breach of the offer letter. A “change in control” is defined in the offer letters as (A) the consummation of (1) any consolidation, reorganization, merger or similar transaction involving the Northern Tier Energy LLC, other than a consolidation, reorganization, merger or similar transaction in which the shareholders immediately prior to such transaction own more than 50% of the combined voting power of the voting securities of the surviving corporation, (2) any sale, lease, exchange or other transfer (in one transaction or a series of related transactions) of all or substantially all of the assets of Northern Tier Energy LLC, or (3) the liquidation or dissolution of the Northern Tier Energy LLC; (B) when any person (as defined in Sections 13(d) and 14(d)(2) of the Exchange Act), other than an employee benefit plan or trust maintained by the Northern Tier Energy LLC or any of its subsidiaries, becomes the “beneficial owner” (as defined in Rule 13d-3 under the Exchange Act), directly or indirectly, of more than 25% of the voting power of the Northern Tier Energy LLC; or (C) when, during any period of 24 months or less, the individuals who constituted the board of directors of Northern Tier Energy LLC at the beginning of such period shall cease for any reason to constitute at least a majority thereof, unless the election or the nomination for election by Northern Tier Energy LLC’s shareholders, as the case may be, of each new director during such period was approved by a vote of at least two-thirds of the directors then still in office who were directors at the beginning of such period.

In connection with Mr. Rodriguez’s resignation on December 20, 2012, Mr. Rodriguez and Northern Tier Energy LLC entered into a Separation Agreement and General Release (the “Separation Agreement”) that provides Mr. Rodriguez, in exchange for signing a general release of claims in favor of Northern Tier Energy LLC and its affiliates, with (i) a severance payment of $750,000, less applicable taxes and withholdings, that will be paid out over an 18 month period beginning in 2013, (ii) a one-time payment of $500,000, less applicable taxes and withholdings and (iii) reimbursement of premiums payable for continued coverage under NTE LLC’s group health and dental coverage through the Consolidated Omnibus Budget Reconciliation Act of 1995, as amended, for up to 18 months. Through a reaffirmation of certain provisions of the employment agreement previously entered into between Northern Tier Energy LLC and Mr. Rodriguez, effective as of December 1, 2010, the Separation Agreement also contains various restrictive covenants, including covenants relating to non-solicitation, confidentiality, and cooperation.

NTI Management Class C Unit Agreements and 2012 LTIP Awards

Class C unit agreements and the NTI Management partnership agreement set forth the treatment of the NTI Management Class C units upon a termination of employment or a change in control as of December 31, 2012.

 

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The normal five-year NTI Management Class C unit vesting schedule will be accelerated upon the occurrence of an MoM Event (defined below) prior to the termination of an executive’s employment by us, NTI LP or any of our subsidiaries or the subsidiaries of NTI LP. Full acceleration would also occur in the event that the holder is terminated without Cause or terminates for Good Reason (each term as defined below) in the two-year period following a Change in Control (as defined below). The NTI Management Class C units would also receive partial accelerated vesting upon the holder’s death or Disability (as defined below), as the holder would be credited with one additional year of service. All other terminations of employment would result in forfeiture of unvested units. Once a NTI Management Class C unit becomes vested, it will remain outstanding unless and until it is repurchased by NTI Management in accordance with the procedures set forth in the NTI Management partnership agreement. NTI Management’s partnership agreement generally states that NTI Management will have the right, but not the obligation, to repurchase the Class C units upon a termination of the holder’s employment for any reason. Any such repurchase would use the fair market value of the Class C unit on the date that NTI Management exercises its right to repurchase that unit, except in the case of a termination for Cause or in the event that the holder joins a competitor within a twelve-month period, in which case the purchase price would be the lower of the fair market value or any purchase or strike price assigned to the unit. “Fair market value” is generally defined as the value of a unit, as of the determination date, assuming (a) (i) the sale of interests in us by Northern Tier Holdings, LLC (“NT Holdings”) at the volume weighted average price of our units as reported by Bloomberg for the ten day period prior to such a determination; (ii) the existence of no indebtedness at NT Holdings other than the face value of the outstanding preferred units in NT Holdings issued to Marathon Petroleum Company, LP; (iii) the existence of no guarantees granted by NT Holdings, and (iv) the distribution by NT Holdings of all the proceeds of such sale, and (b) the equity ownership of NT Holdings mirrors the equity ownership of NTI LP assuming that all of the Class C units of NTI LP are held by the holders of the corresponding NTI Management Class C units.

The NTI Management partnership agreement defines an “MoM Event” as the distribution of an amount that, when distributed pursuant to the normal distribution process set forth in the NTI LP partnership agreement (described above in the CD&A), results in the holders of the Class A common units receiving total distributions in an amount equal to 200% of their capital contributions. Our initial public offering did not trigger an MoM Event for the NTI Management Class C units. Secondary offerings such as the offering contemplated in this prospectus may trigger an MoM Event for the NTI Management Class C Units, which would result in the full acceleration of all NTI Management Class C units. The term “Cause” is defined in the NTI Management partnership agreement in substantially the same terms as that found in Mr. Kuchta’s employment agreement described above. A “Good Reason” termination will generally occur if there is a material reduction to the executive’s base salary, authority, duties or responsibilities, a material change to the executive’s primary work location, or we take any other action that constitutes a material breach of our employment relationship with that executive. A “Change in Control” would generally have been deemed to have occurred upon the date that (1) any person or group, other than members of the NTI GenPar, LLC (the “General Partner”), NTI LP or their affiliates (including sponsor partners), becomes the beneficial owner, by way of merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the voting power of the voting securities of the General Partner, NTI LP, us or Northern Tier Energy GP, LLC; (2) the members of the General Partner approve a plan of liquidation of the General Partner or NTI LP; (3) the sale or other disposition by either the General Partner or NTI LP of all or substantially all of its assets to an unaffiliated entity; (4) the General Partner, an affiliate, a sponsor partner ceases to be the general partner of NTI LP; or (5) an affiliate of the General Partner or an affiliate of a sponsor partner ceases to be our general partner.

In exchange for Mr. Rodriguez’s release of claims against NTI Management, NTI LP and their affiliates, Mr. Rodriguez, NTI Management and NTI LP came to the agreement that Mr. Rodriguez will retain any NTI Management Class C units that vested in the 2011 year and that vesting occurred in 2012 of the following units, of which he will also retain: 151,250 of the NTI Management Class C2 units; 151,250 of the NTI Management Class C3 units; 268,125 of the NTI Management Class C4 units and 268,125 of the NTI Management Class C5 units All other NTI Management Class C units that he held at the time of his resignation will no longer be eligible to vest.

 

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Mr. Bonczek received an award of restricted units pursuant to the 2012 LTIP in December of 2012. The awards will generally vest in three equal installments on the anniversary of the grant date, but in the event that Mr. Bonczek’s termination of employment occurs due to his death or disability, a termination without cause, or a termination for good reason, the tranche of restricted units that was scheduled to vest next will become immediately vested. If Mr. Bonczek’s employment is terminated without cause or for good reason within the twelve month period immediately following a change of control, all unvested restricted units will become vested. The terms used in this paragraph with respect to Mr. Bonczek’s restricted units are generally given the same definition as the same term within his offer letter described above.

The table below shows our best estimate of the amount of payments and benefits that each of the named executive officers other than Mr. Rodriguez would receive upon a termination of employment or a change in control if that event had occurred on December 31, 2012. Amounts payable upon any event will not be determinable until the actual occurrence of any particular event. Estimates below do not include the value of any Accrued Rights, vacation, sick or holiday pay, as all such amounts have been assumed to be paid current at the time of the event in question, and amounts in the Supplemental Plan would be paid in accordance with the terms of such plan.

 

Executive

Termination of Employment due to Our Non-Renewal of Employment Agreement ($)

Termination of Employment for Cause ($)

Termination of Employment without Cause or for Good Reason ($)

Termination of Employment for Disability ($)(4)

Termination of Employment for Death ($)(5)

Termination of Employment without Cause or Good Reason within a Two Year Period of a Change in Control (6)($)

MoM Event ($)(7)

Hank Kuchta

Base Salary and Bonus(1)

1,350,000

N/A

1,800,000

225,000

900,000

1,800,000

N/A

Continued Medical(2)

N/A

N/A

N/A

N/A

N/A

N/A

N/A

Accelerated Equity(3)

N/A

N/A

N/A

N/A

N/A

N/A

3,602,825

Total

1,350,000

1,800,000

225.000

900,000

1,800,000

3,602,825

David Bonczek

Base Salary

N/A

N/A

300,000

150,000

N/A

300,000

N/A

Accelerated Equity(3)

N/A

N/A

23,789

23,789

23,789

71,367

340,984

Total

383,789

173,789

23,789

371,367

340,984

Greg Mullins

Base Salary

N/A

N/A

295,000

147,500

N/A

295,000

N/A

Accelerated Equity(3)

N/A

N/A

N/A

N/A

N/A

N/A

747,025

Total

295,000

147,500

N/A

295,000

747,025

 

(1)

Amounts in this row reflect a continuation of the executive’s base salary for a period of twenty-four months, assuming that the executive has signed a proper release form in our favor. While Mr. Kuchta would receive a Pro-Rata Bonus in the event of a termination of employment during the year, a termination occurring on December 31, 2012 would have resulted in a payment equal to the full amount of the bonus that he received for the 2012 year (which at this time, is our best estimate of that amount).

(2)	Mr. Kuchta would not have been eligible to receive any continued medical benefits from us as of December 31, 2012, as he was still being covered by a previous employer’s medical plans. Our obligation to cover him and his family may change in future years.

(3)

The amounts in this row for Mr. Bonczek are a combination of his restricted unit awards and his NTI Management Class C units. The restricted units were valued by multiplying the applicable number of restricted units at issue times the closing price of our common stock on December 31, 2012 ($25.69). Other than with respect to Mr. Bonczek’s restricted units, amounts reflect the value of accelerated value of the applicable outstanding NTI Management Class C units as of December 31, 2012. As discussed above, the vesting of an NTI Management Class C unit does not result in a distribution or settlement of the award at the time of vesting. Solely for purposes of providing values in this table, we have assumed that NTI Management did not exercise its discretion to repurchase any units at the time of the executives’ termination of employment, although as described above, upon the actual termination of employment of any executive,

 

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NTI Management will have the sole discretion to determine whether a repurchase of the units would occur. Amounts that are reflected in the “MoM Event” column relate to the payments that we estimate could be received by the named executive officers due to their NTI Management Class C units following an MoM Event. These amounts were calculated assuming that a distribution to the holders occurs which would result in the NTI Management Class A common units receiving distributions in an amount equal to 200% of their capital contributions.

(4)

Our company’s long-term disability benefit plan (“LTD Plan”) will provide benefits to employees following a 180 day period of short-term disability. The LTD Plan will provide up to 60% of base pay up to a maximum of $20,000 per month, which will not be paid by us but by an insurance company. Amounts shown here reflect only the continuation of base salary payments that we will provide to the executives during their 180 days of short term disability.

(5)

While we would not provide any further base salary or bonus amounts to the estate of Mr. Kuchta upon termination of employment due to a death, his estate would receive the payout of the life insurance policy that we maintain on behalf of the executive. We pay the premiums on these policies, but the payment of the policy proceeds to the executive’s estate would come directly from the insurance company rather than us. We have assumed that the policy is worth exactly two times the amount of the executive’s annual base salary as of December 31, 2012.

(6)

Amounts reflected in the “Base Salary and Bonus” row, as well as the “Continued Medical” row, are the same amounts as those reflected in the “Termination of Employment without Cause or for Good Reason” column, as these amounts will be paid upon these termination events with or without change in control under their employment agreements; however, amounts would only be paid once. With respect to Mr. Bonczek’s restricted units, this column would be applicable to a termination of employment due to a without cause or good reason termination that occurs within a one year period, rather than two year period, following a change in control.

(7)	Secondary offerings such as the offering contemplated in this prospectus may trigger an MoM Event for all classes of the NTI Management Class C Units, which would result in the full acceleration of all NTI Management Class C units held by each of the named executive officers within the table.

Director Compensation

During each period that a non-employee director serves on our board of directors, he or she will receive an annual cash retainer fee of $60,000 which will be paid in quarterly installments. During the 2012 year, that fee was increased for Mr. Smith (as the chairman our board of directors) to $100,000 as of May 9, 2012, and for Mr. Hoffman (as the chairman of the audit committee) to $75,000 on September 6, 2012. Also on May 9, 2012 Mr. Smith received a one-time grant of 300,000 Class B profits interest awards in NTI LP. Directors will also be reimbursed for certain reasonable expenses in connection with their services to us.

 

Name		Fees Earned or Paid in Cash ($)(1)				Option Awards ($)(2)				Total ($)
Dan F. Smith			90,000				318,954				408,954
Thomas Hofmann			67,500				—				67,500
Scott D. Josey			60,000				—				60,000

 

(1)	Amounts in this column reflect the actual amount received by each director during the 2012 year.

(2)

Mr. Smith received a grant of 300,000 Class B profits interests in NTI LP on May 9, 2012. Despite the fact that profits interests such as the Class B profits interest awards in NTI LP do not require the payment of an exercise price, we believe that these awards are economically similar to stock options due to the fact that they have no value for tax purposes at grant and will obtain value only as the price of the underlying security rises, and as such, are required to be reported in this title under the “Option Awards” column. Please note that no “options” in the traditional sense have been granted to our directors during 2012 fiscal year. Amounts included reflect the grant date fair value of the units computed in accordance with FASB ASC Topic 718. The assumptions used to calculate these values were as follows: (a) the expected term was 6.0 years; (b) current price of the underlying unit was $2.03; (c) the expected volatility was 55.5%; (d) the

 

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expected dividend yield was 0.0%; and (e) the risk-free investment rate was 1.4%. The number of outstanding Class B profits interest awards in NTI LP held as of December 31, 2012 are as follows: Mr. Smith, 375,000; Mr. Hofmann, 75,000; and Mr. Josey, 75,000.

Risk Assessment

Our board of directors has reviewed our compensation policies as generally applicable to our employees and believes that our policies do not encourage excessive and unnecessary risk-taking, and that the level of risk that

they do encourage is not reasonably likely to have a material adverse effect on us. Our board of directors has reviewed and discussed the design features, characteristics, and performance metrics utilized at our company and our approval mechanisms of total compensation for all employees, including salaries, incentive plans, and equity-based compensation awards, to determine whether any of these policies or programs could create risks that are reasonably likely to have a material adverse effect on us.

Our compensation philosophy and culture support the use of base salary, performance-based compensation, and retirement plans that are generally uniform in design and operation throughout our organization and with all levels of employees. These compensation policies and practices are centrally designed and administered. In addition, the following specific factors, in particular, reduce the likelihood of excessive risk-taking:

 

•

Our overall compensation levels are competitive with the market.

 

•

Our compensation mix is balanced among (i) fixed components like salary and benefits, and (ii) annual and long-term incentives that will only reward our executives upon our overall financial performance, business unit financial performance, operational measures and individual performance.

 

•

The compensation committee has discretion to reduce annual or performance-based awards when it determines that such adjustments would be appropriate based on our interests and the interests of our unitholders.

Certain Relationships and Related Person Transactions

Following the closing of this offering, Northern Tier Holdings will own approximately 69.9% of our common units (or approximately 68.4% of our common units if the underwriters exercise their option to purchase additional common units in full). Our general partner will be indirectly owned by ACON Refining, TPG Refining and an entity in which Hank Kuchta has an ownership interest.

The terms of the transactions and agreements disclosed in this section were determined by and among affiliated entities and, consequently, are not the result of arm’s length negotiations. These terms are not necessarily as favorable to us as the terms that could have been obtained from unaffiliated third parties.

Distributions and Payments to Our General Partner and its Affiliates

The following table summarizes the distributions and payments made or to be made by us to our general partner and its affiliates in connection with the formation, ongoing operation and any liquidation of Northern Tier Energy LP.

 

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Formation Stage
The consideration received by our general partner and its affiliates in connection with the contribution of Northern Tier Energy LLC by Northern Tier Holdings to Northern Tier Energy LP		•   The non-economic general partner interest issued to our general partner;   •   54,844,500 common units issued to Northern Tier Holdings;   •   18,383,000 PIK units issued to Northern Tier Holdings. The repurchase and satisfaction and discharge of the 2017 Notes resulted in a termination of the PIK Period, as such term is defined in our First Amended and Restated Limited Partnership Agreement. Upon termination of the PIK Period, all of the PIK units automatically converted into common units and thereafter were entitled to receive cash distributions when and as decided by the board of directors of our general partner;
		•   The net proceeds received from the exercise of the underwriters’ option to purchase additional common units were distributed to Northern Tier Holdings. Upon the underwriters’ exercise their option to purchase additional common units in full, we will made an additional distribution of approximately $32.0 million to Northern Tier Holdings, of which $31.2 million was distributed to ACON Refining and TPG Refining and $0.8 million was distributed to entities in which Mr. Kuchta has an ownership interest. See “Use of Proceeds;” and
		•   A success fee in the aggregate amount of $7.5 million. See “—Agreements with Affiliates of Our Central Partner—Management Services Agreement.”
Operational Stage
Distributions to affiliates of our general partner		We expect to make distributions each quarter to our unitholders, including Northern Tier Holdings LLC. Distributions on our units will be in cash. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Distribution Policy.”
Payments to our general partner and its affiliates		Neither our general partner nor its affiliates will receive any management fee in connection with the management of our business, 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.

 

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Liquidation Stage
Liquidation		Upon our liquidation, the partners, including our general partner, will be entitled to receive liquidating distributions.

Agreements with Affiliates of Our General Partner

In connection with our formation, we entered into several agreements with affiliates of our general partner that govern the business relations among us, our general partner and such affiliates. In connection with the transactions that we entered into to effect our initial public offering, we entered into new agreements with affiliates of our general partner. The agreements amended included our partnership agreement, the terms of which are more fully described under “The Partnership Agreement” and elsewhere in this prospectus.

Transaction Agreement

In connection with the IPO Transactions, we entered into a contribution, conveyance and assumption agreement with various affiliates of our general partner in order to facilitate the consummation of the IPO Transactions. Pursuant to this agreement, (1) Northern Tier Holdings LLC and our general partner executed an amended and restated partnership agreement; (2) Northern Tier Holdings LLC and our general partner contributed all of the membership interests in Northern Tier Energy LLC to us; and (3) we issued common units and PIK units and distributed a portion of the net proceeds from our initial public offering to Northern Tier Holdings LLC.

Registration Rights Agreement

In connection with our initial public offering, we entered into an amended and restated registration rights agreement with Northern Tier Investors, LLC, Northern Tier Holdings, ACON Refining, TPG Refining, NTR Partners LLC, NTR Partners II LLC and NTI Management. Under the registration rights agreement, Northern Tier Holdings, ACON Refining and TPG Refining can cause, and after ACON Refining and TPG Refining and their transferees no longer hold registrable securities, NTR Partners LLC and NTR Partners II LLC can cause, Northern Tier Energy LP to register their common units under the Securities Act and to maintain a shelf registration statement effective with respect to such units. In addition, under the agreement, Northern Tier Holdings LLC, ACON Refining, TPG Refining, NTR Partners LLC, NTR Partners II LLC and NTI Management are entitled to participate in certain other registration statements and offerings conducted on behalf of Northern Tier Energy LP or third parties. See “Common Units Eligible for Future Sale.”

Management Services Agreement

In 2010, Northern Tier Energy LLC entered into a management services agreement with ACON Management and TPG Management pursuant to which they provided Northern Tier Energy LLC with ongoing management, advisory and consulting services, which agreement was amended and restated in January 2012. In connection with the entry into the management services agreement, ACON Management and TPG Management received a one-time aggregate transaction fee of $12.5 million, as well as reimbursements of out-of-pocket expenses incurred by them in connection with the Marathon Acquisition. Pursuant to the amended and restated management services agreement, ACON Management and TPG Management also received quarterly management fees equal to 1% of our “Adjusted EBITDA” (as defined in the agreement) for the previous quarter (subject to a minimum quarterly fee of $500,000), as well as reimbursements for out-of-pocket expenses incurred by them in connection with providing such management services. ACON Management and TPG Management were also entitled to specified success fees in connection with advice they provided in relation with certain corporate transactions. ACON Management and TPG Management received a success fee in the aggregate amount of $7.5 million upon the closing of our initial public offering. This management services agreement terminated in connection with the closing of our initial public offering.

 

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Historical Transactions

ACON Refining and TPG Refining are equal owners of 97.5% of the Class A Common Units in Northern Tier Investors LP. An entity in which Hank Kuchta has an ownership interest holds the remaining 2.5% Class A Common Units in Northern Tier Investors LP. ACON Refining and TPG Refining made capital contributions to Northern Tier Investors LP totaling an aggregate of $195 million and an entity in which Mr. Kuchta has an ownership interest made capital contributions of $5 million.

Transactions with Marathon

From time to time, we may enter into related person transactions in the ordinary course of business.

During the Predecessor period, our related persons included:

 

•

Marathon, which refines, markets and transports crude oil and petroleum products, primarily in the Midwest, Upper Great Plains, U.S. Gulf Coast and southeastern regions of the United States.

 

•

Marathon Oil Company, which is a wholly owned subsidiary of Marathon Oil. It purchases or produces crude oil in the United States that is used at Marathon’s refineries.

 

•

Marathon Petroleum Company Canada, Ltd., which is a wholly owned subsidiary of Marathon. It purchases crude oil in Canada to be used at Marathon’s refineries.

 

•

Marathon Petroleum Trading Canada LLC, which is a wholly owned subsidiary of Marathon. It purchases crude oil in Canada to be used at Marathon’s refineries.

 

•

Minnesota Pipe Line Company, in which we own a 17% interest. Minnesota Pipe Line Company owns and operates the Minnesota Pipeline.

 

•

Pilot Travel Centers LLC (“PTC”), in which Marathon sold its 50% interest in October 2008. PTC owns and operates travel centers in the United States.

 

•

Speedway SuperAmerica LLC (“SSA”), which changed its name to Speedway LLC, and is a wholly owned subsidiary of Marathon Petroleum. Under the Predecessor, SSA was the owner of SuperAmerica branded convenience stores that were sold to us as part of the Marathon Acquisition.

We have historically sold refined products to Marathon. Refined product sales to Marathon were recorded at intercompany transfer prices that were market-based prices. There were no related party sales for periods subsequent to the Marathon Acquisition. Revenues from sales to related parties totaled $210.1 million for the eleven months ended November 30, 2010, which represented 6.6% of total revenues for that period. For more information on these related party sales, see Note 3 to our audited consolidated financial statements.

During the Predecessor period, we made purchases from our related parties, including:

 

•

purchases from Marathon Oil Company, Marathon Petroleum Company Canada, Ltd. and Marathon Petroleum Trading Canada LLC consisting primarily of crude oil. Purchases from Marathon Oil Company are recorded at contracted prices that are market-based. Purchases from Marathon Petroleum Company Canada, Ltd. and Marathon Petroleum Trading Canada LLC are recorded at contracted prices based on their acquisition cost, plus an administrative fee;

 

•

purchases from Marathon consisting primarily of refined products and refinery feedstocks, certain general and administrative costs and costs associated with employees associated with our refining segment participating in Marathon’s multi-employer benefit plans. Refined product and refinery feedstock purchases from Marathon are recorded at intercompany transfer prices that are market-based prices;

 

•

purchases from Minnesota Pipe Line Company consisting primarily of crude oil transportation services, which are based on published tariffs; and

 

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•

purchases from SSA consisting of certain overhead costs and costs associated with employees associated with our retail segment participating in SSA’s multi-employer benefit plans.

There were no related party purchases for periods subsequent to the Marathon Acquisition. Purchases from related parties totaled $1,378.3 million for the eleven months ended November 30, 2010. For more information on these related party purchases, see Note 3 to our audited consolidated financial statements.

Marathon has provided certain services to us such as marketing, crude acquisition, engineering, human resources, insurance, treasury, accounting, tax, legal, procurement and information technology services. Charges for these services were allocated based on usage or other methods, such as headcount, capital employed or store count, which management believes to be reasonable. There were no related party purchases for periods subsequent to the Marathon Acquisition. Related party purchases reflect charges for these services of $26.5 million for the eleven months ended November 30, 2010.

Until November 30, 2010, we participated in Marathon’s centralized cash management programs under which cash receipts were remitted to and cash disbursements were funded by Marathon or SSA. All intercompany activity associated with the transfer of cash was included in the net investment value.

For the eleven months ended November 30, 2010, we were considered to have participated in multi-employer benefit plans of Marathon. Our allocated share of Marathon’s employee benefit plan expenses, including costs related to stock-based compensation plans, was included in related party purchases and was $21.5 million for the eleven months ended November 30, 2010. There were no related party purchases for periods subsequent to the Marathon Acquisition. Expenses for employee benefit plans other than stock-based compensation plans were allocated to us primarily as a percentage of salary and wage expense. For the stock-based compensation plans, we were charged with the expenses directly attributed to our employees, which were $0.3 million for the eleven months ended November 30, 2010. For more information on these related party transactions, see Note 3 to our audited consolidated financial statements.

Transactions with Marathon

Our refinery supplies the gasoline and diesel sold in 90 independently owned and operated Marathon branded convenience stores in our marketing area. In connection with the Marathon Acquisition, we entered into an agreement with Marathon to supply substantially all of the gasoline and diesel requirements for the 90 independently owned and operated Marathon branded convenience stores in our marketing area. For the year ended December 31, 2011, Marathon purchased $275 million of gasoline and diesel pursuant to this agreement. In addition, Marathon was issued $80 million of noncontrolling preferred interests in Northern Tier Holdings in connection with the Marathon Acquisition. Under the terms of the settlement agreement with Marathon, Marathon received approximately $40 million of the net proceeds from our initial public offering and Northern Tier Holdings LLC redeemed Marathon’s existing preferred interest with a portion of the net proceeds from our initial public offering and issued Marathon a new $45 million noncontrolling preferred interest in Northern Tier Holdings LLC. The settlement was contingent upon the consummation of our initial public offering.

Other Related Person Transactions

Chet Kuchta is our Vice President, Supply and has served in that position since August 2011. He is the brother of Hank Kuchta, our President and Chief Executive Officer and a member of our board of directors. During 2012, Mr. Chet Kuchta received aggregate compensation in the amount of $522,563.

 

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Security Ownership of Certain Beneficial Owners and Management

The following sets forth certain information with respect to the beneficial ownership of our common units that are issued and outstanding as of January 15, 2013 and held by:

 

•

each unitholder, including the selling unitholder in this offering, known by us to be the beneficial owner of more than 5% of our common units;

 

•

our general partner;

 

•

each of the directors and named executive officers of our general partner; and

 

•

all of the executive officers and directors of our general partner as a group.

Beneficial ownership is determined in accordance with the rules of the SEC. These rules generally attribute beneficial ownership of securities to persons who possess sole or shared voting power or investments power with respect to such securities. Except as otherwise indicated, we believe that all persons listed below have sole voting and investment power with respect to the units beneficially owned by them, except to the extent this power may be shared with a spouse, based on information provided to us by such persons.

Unless otherwise indicated by us, the address of each person or entity named in the table is 38C Grove Street, Suite 100, Ridgefield, Connecticut 06877.

 

Name of Beneficial Owner and Management		Common Units Beneficially Owned				Percentage of Common Units Beneficially Owned				Percentage of Common Units Beneficially Owned
Northern Tier Holdings LLC(1)			73,227,500				79.7	%			79.7	%
Northern Tier Energy GP LLC(2)			—				—				—
ACON Refining Partners, L.L.C.(3)			73,227,500				79.7	%			79.7	%
TPG Refining, L.P.(4)			73,227,500				79.7	%			79.7	%
Mario E. Rodriguez(5)			4,900				*				*
Hank Kuchta(6)			3,200				*				*
Dave Bonczek			2,778				*				*
Greg Mullins			—				—				—
Bernard W. Aronson			—				—				—
Jonathan Ginns(2)			—				—				—
Michael MacDougall(7)			—				—				—
Eric Liaw(8)			—				—				—
Scott D. Josey			—				—				—
Thomas Hofmann			—				—				—
Dan F. Smith			—				—				—
All directors and executive officers as a group (10 persons)			—				—				—

 

*	Represents less than 1%.

(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 Class A Common Units in Northern Tier Investors LP are held by ACON Refining (48.75%), TPG Refining (48.75%) and entities in which Hank Kuchta has an ownership interest (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 holds a $45 million preferred interest in Northern Tier Holdings.

(2)	Northern Tier Energy GP LLC, which is owned by Northern Tier Holdings, is our general partner and manages and operates our business and has a non-economic general partner interest in us.

 

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(3)

ACON Management is the managing member of AIP V GenPar, L.L.C., which in turn is the managing member of ACON Refining. ACON Management may be deemed, pursuant to Rule 13d-3 under the Exchange Act, to beneficially own the securities held by Northern Tier Holdings. Jonathan Ginns, Ken Brotman, Bernard Aronson, Daniel Jinich and Guillermo Bron are managing members and sole equity holders of ACON Management, and therefore, Messrs. Ginns, Brotman, Aronson, Jinich and Bron may be deemed to be the beneficial owners of, with indirect voting and dispositive authority over, the equity securities held by ACON Refining. Messrs. Ginns, Brotman, Aronson, Jinich and Bron disclaim beneficial ownership of the securities of ARP except to the extent of their pecuniary interest therein. The address of ACON Management and Messrs. Ginns, Brotman, Aronson, Jinich and Bron is c/o ACON Funds Management, L.L.C., 1133 Connecticut Avenue, NW, Suite 700, Washington, D.C. 20036.

(4)

The general partner of TPG Refining is TPG VI AIV SLP SD, L.P., a Delaware limited partnership, whose general partner is TPG VI AIV SLP SD Advisors, LLC, a Delaware limited liability company, whose general partner is TPG Holdings II, L.P., a Delaware limited partnership, whose general partner is TPG Holdings II-A, LLC, a Delaware limited liability company, whose sole member is TPG Group Holdings (SBS), L.P., a Delaware limited partnership, whose general partner is TPG Group Holdings (SBS) Advisors, Inc. (“Group Advisors”), a Delaware corporation. David Bonderman and James G. Coulter are officers, directors and sole shareholders of Group Advisors and may therefore be deemed to be the beneficial owners of the common units held by Northern Tier Holdings. Messrs. Bonderman and Coulter disclaim beneficial ownership of such units except to the extent of their pecuniary interest therein. The address of Group Advisors and Messrs. Bonderman and Coulter is c/o TPG Global, LLC, 301 Commerce Street, Suite 3300, Fort Worth, TX 76102.

(5)

Includes 1,400 common units held by Mr. Rodriguez’s spouse as UTMA custodian for Mr. Rodriguez’s minor daughters and 3,500 common units held by Mr. Rodriguez’s spouse as UTMA custodian for Mr. Rodriguez’s minor son. The address of Mr. Rodriguez is c/o NTR Partners, 570 Lexington Avenue, 27th Floor, New York, NY 10022.

(6)	Includes 1,100 common units held by Mr. Kuchta’s son, who shares his household. Mr. Kuchta disclaims beneficial ownership of the securities except to the extent of his pecuniary interest therein.

(7)

Mr. MacDougall, who is one of our directors, is a TPG Partner. Mr. MacDougall has no voting or investment power over and disclaims beneficial ownership of the common units held by Northern Tier Holdings. The address of Mr. MacDougall is c/o TPG Global, LLC, 301 Commerce Street, Suite 3300, Fort Worth, TX 76102.

(8)

Mr. Liaw, who is one of our directors, is a TPG Vice President. Mr. Liaw has no voting or investment power over and disclaims beneficial ownership of the common units held by Northern Tier Holdings. The address of Mr. Liaw is c/o TPG Global, LLC, 301 Commerce Street, Suite 3300, Fort Worth, TX 76102.

Selling Unitholder

This prospectus covers the offering for resale of 9,000,000 common units, or 10,350,000 if the underwriters exercise their option to purchase additional common units in full, owned by the selling unitholder. These common units were obtained by the selling unitholder as consideration in respect of the contribution of Northern Tier Energy LLC by Northern Tier Holdings to Northern Tier Energy LP in connection with our initial public offering.

Immediately before this offering, the selling unitholder owned 73,227,500 of our outstanding common units, representing an approximate 79.7% limited partner interest in us. Following this offering, the selling unitholder will own 64,227,500 common units, or 62,877,500 common units if the underwriters exercise in full their option to purchase additional common units, representing an approximate 69.9% and 68.4% limited partner interest in us, respectively. Please read “Security Ownership of Certain Beneficial Owners and Management.” For further discussion of the relationships between us, our general partner and its affiliates, please read “Certain Relationships and Related Person Transactions.”

 

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The selling unitholder is not a broker-dealer registered under Section 15 of the Exchange Act or an affiliate of a broker-dealer registered under Section 15 of the Exchange Act.

The following table sets forth information relating to the selling unitholder as of December 7, 2012, based on information supplied to us by the selling unitholder on or prior to that date. Assuming that the selling unitholder sells all of the common units owned or beneficially owned by them that are offered by this prospectus and does not acquire any additional common units following this offering, the selling unitholder will not own any common units other than those appearing in the column entitled “Common Units Held Following Offering.” In addition, the selling unitholder may have sold, transferred or otherwise disposed of, or may sell, transfer or otherwise dispose of, at any time and from time to time, common units in transactions exempt from the registration requirements of the Securities Act of 1933 after the date as of which the information is set forth on the table below.

 

Selling Unitholder		Common Units Held Prior to Offering				Common Units That May Be Offered				Common Units Held Following Offering				Percentage of Outstanding Common Units
Northern Tier Holdings LLC(1)			73,227,500				9,000,000				64,227,500				69.9

 

(1)	For information on the beneficial ownership of our common units held by Northern Tier Holdings LLC, see “Security Ownership of Certain Beneficial Owners and Management.”

Conflicts of Interest and Fiduciary Duties

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its owners, on the one hand, and us and our public unitholders, on the other hand. Conflicts may arise as a result of the duties of our general partner to act for the benefit of its owners, which may conflict with our interests and the interests of our public unitholders. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to its owners. At the same time, our general partner has a duty to manage us in a manner that it believes is in our best interests. Our partnership agreement specifically defines the remedies available to unitholders for actions taken that, without these defined liability standards, might constitute breaches of fiduciary duty under applicable Delaware law. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to the limited partners and the partnership.

Whenever a conflict arises between our general partner and its owners, on the one hand, and us and our public unitholders, on the other, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action in respect of such conflict of interest is:

 

•

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

 

•

approved by the holders of a majority of the outstanding units, excluding any units owned by the general partner or any of its affiliates.

Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of the board of our general partner or from the holders of a majority of the outstanding units as described above. If our general partner does not seek approval from the conflicts committee or from holders of units as described above and the board of directors of our general partner approves the

 

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resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our partnership agreement, a determination, other action or failure to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) will be deemed to be “in good faith” unless our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) believed such determination, other action or failure to act was adverse to the interests of the partnership. See “Management—Board Committees” for information about the conflicts committee of our general partner’s board of directors.

Conflicts of interest could arise in the situations described below, among others.

Our general partner’s affiliates may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

Our partnership agreement provides that our general partner is restricted from engaging in any business activities other than those in connection with or incidental to its ownership of interests in us. However, affiliates of our general partner (which include our sponsors) are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Our general partner or its affiliates may acquire, construct or dispose of assets in the future without any obligation to offer us the opportunity to acquire those assets. In addition, under our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, will not apply to our general partner and its affiliates. As a result, neither our general partner nor any of its affiliates have any obligation to present business opportunities to us.

Our general partner is allowed to take into account the interests of parties other than us (such as our sponsors) in exercising certain rights under our partnership agreement.

Our partnership agreement contains provisions that permissibly 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 in its capacity as our 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, us, our affiliates or any limited partner. Examples include the exercise of its call right, its voting rights with respect to any units it owns and its determination whether or not to consent to any merger or consolidation.

Our partnership agreement limits the liability of, and replaces the duties owed by, our general partner and also restricts the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty.

In addition to the provisions described above, our partnership agreement contains provisions that restrict the remedies available to our unitholders for actions that might otherwise constitute breaches of fiduciary duty. For example, 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 decision was not adverse to the interests of the partnership;

 

•

our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment

 

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entered by a court of competent jurisdiction determining that our general partner or its officers or directors acted in bad faith or, in the case of a criminal matter, acted with knowledge that its conduct was unlawful; and

 

•

in resolving conflicts of interest, it will be presumed that in making its decision our general partner, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of any limited partner or us, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

Our partnership agreement provides that a conflicts committee may be comprised of one or more directors. If we establish a conflicts committee with only one director, your interests may not be as well served as if we had a conflicts committee comprised of at least two independent directors.

By purchasing a common unit, a common unitholder will agree to become bound by the provisions in our partnership agreement, including the provisions discussed above. See “—Fiduciary Duties.”

Actions taken by our general partner may affect the amount of cash available to pay distributions to unitholders.

The amount of cash that is available for distribution to unitholders is affected by decisions of the board of directors of our general partner regarding such matters as:

 

•

amount and timing of asset purchases and sales;

 

•

cash expenditures;

 

•

borrowings;

 

•

entry into and repayment of current and future indebtedness, including the redemption or defeasance of the senior secured notes;

 

•

issuance of additional units; and

 

•

creation, reduction or increase of cash reserves in any quarter.

Our partnership agreement permits us to borrow funds to make a distribution on all outstanding units, and further provides that we and our subsidiaries may borrow funds from our general partner and its affiliates.

Our general partner and its affiliates are not required to own any of our common units. If Northern Tier Holdings were to sell all or substantially all of its common units, this would heighten the risk that our general partner would act in ways that are more beneficial to itself and its owners than to our common unitholders.

Upon the closing of this offering, Northern Tier Holdings will own a majority of our outstanding units, but there is no requirement that it continue to do so. Northern Tier Holdings is permitted to sell all of its common units. In addition, Northern Tier Holdings may cause our general partner to sell its general partner interest to an unrelated third party. If neither our general partner nor its affiliates owned any common units, this would heighten the risk that our general partner would act in ways that are more beneficial to itself and its owners than to our common unitholders.

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

If at any time our general partner and its affiliates own more than 90% of the common 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 units held by unaffiliated persons at the market price calculated in accordance with the

 

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terms of our partnership agreement. As a result, you may be required to sell your common 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 common 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 exercising its call right. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right. As a result, a common unitholder may have his common units purchased from him at an undesirable time or place. See “The Partnership Agreement—Call Right.”

Contracts between us, on the one hand, and our general partner and its affiliates, on the other, will not be the result of arm’s-length negotiations.

Neither our partnership agreement nor any of the other agreements, contracts and arrangements between us and our general partner and its affiliates are or will be the result of arm’s length negotiations. Our general partner will determine, in good faith, the terms of any such future transactions.

Common unitholders will have no right to enforce obligations of our general partner and its affiliates under agreements with us.

Any agreements between us, on the one hand, and our general partner and its affiliates, on the other, will not grant to the unitholders, separate and apart from us, the right to enforce the obligations of our general partner and its affiliates in our favor.

We may choose not to retain separate counsel for ourselves or for the holders of common units.

Attorneys, independent accountants and others who perform services for us are selected by our general partner or the conflicts committee of our general partner and may perform services for our general partner and its affiliates. We may retain separate counsel for ourselves or the conflicts committee in the event of a conflict of interest between our general partner and its affiliates, on the one hand, and us or the holders of common units, on the other, depending on the nature of the conflict. We do not intend to do so in most cases.

Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

Under our partnership agreement, our general partner has full power and authority to do all things, other than those items that require unitholder approval or on such terms as it determines to be necessary or appropriate to conduct our business including, but not limited to, the following:

 

•

expending, lending or borrowing money, assuming or guaranteeing or otherwise contracting for, indebtedness and other liabilities, issuing evidences of indebtedness, including indebtedness that is convertible into our securities, and incurring any other obligations;

 

•

preparing and transmitting tax, regulatory and other filings, periodic or other reports to governmental or other agencies having jurisdiction over our business or assets;

 

•

acquiring, disposing, mortgaging, pledging, encumbering, hypothecating or exchanging our assets or merging or otherwise combining us with or into another person;

 

•

negotiating, executing and performing contracts, conveyances or other instruments;

 

•

distributing cash;

 

•

selecting and dismissing employees and agents, outside attorneys, accountants, consultants and contractors and determining their compensation and other terms of employment or hiring;

 

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•

maintaining insurance for our benefit;

 

•

forming, acquiring an interest in, and contributing property and lending money to any further limited partnerships, joint ventures, corporations, limited liability companies or other entities;

 

•

controlling all matters affecting our rights and obligations, including bringing and defending actions at law or in equity or otherwise litigating, arbitrating or mediating and incurring legal expense and settling claims and litigation;

 

•

indemnifying any person against liabilities and contingencies to the extent permitted by law;

 

•

purchasing, selling or otherwise acquiring or disposing of our partnership interests, or the issuing additional options, rights, warrants, appreciation rights, phantom or tracking interests relating to our partnership interests; and

 

•

entering into agreements with any of its affiliates to render services to us or to itself in the discharge of its duties as our general partner.

See “The Partnership Agreement” for information regarding the voting rights of unitholders.

Fiduciary Duties

Duties owed to unitholders by our general partner are prescribed by law and in our partnership agreement. The Delaware Act provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties otherwise owed by the general partner to limited partners and the partnership.

Our partnership agreement contains various provisions modifying and restricting the fiduciary duties that might otherwise be owed by our general partner. We have adopted these provisions to allow our general partner or its affiliates to engage in transactions with us that otherwise might be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to our interests when resolving conflicts of interest. We believe this is appropriate and necessary because the board of directors of our general partner has a duty to manage our partnership in good faith and a duty to manage our general partner in a manner beneficial to its owners. Without these modifications, our general partner’s ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards benefit our general partner by enabling it to take into consideration all parties involved in the proposed action. These modifications also strengthen the ability of our general partner to attract and retain experienced and capable directors. These modifications represent a detriment to our public unitholders because they restrict the remedies available to our public unitholders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit our general partner to take into account the interests of third parties in addition to our interests when resolving conflicts of interests.

The following is a summary of the material restrictions of the fiduciary duties owed by our general partner to the limited partners:

 

State law fiduciary duty standards

Fiduciary duties are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally require that any action taken or transaction engaged in be entirely fair to the partnership.

 

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Partnership agreement modified standards

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, our partnership agreement provides that when our general partner is acting in its capacity as our general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when our general partner is acting in its individual capacity, as opposed to in its capacity as our general partner, it may act without any fiduciary obligation to us or the unitholders whatsoever. These contractual standards reduce the obligations to which our general partner would otherwise be held.

 

If our general partner does not seek approval from the conflicts committee of its board of directors or the unitholders, excluding any units owned by our general partner or its affiliates, and its board of directors approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors, which may include board members affected by the conflict of interest, 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. These standards reduce the obligations to which our general partner would otherwise be held.

 

Rights and remedies of limited partners

The Delaware Act generally provides that a limited partner may institute legal action on behalf of the partnership to recover damages from a third party where a general partner has refused to institute the action or where an effort to cause a general partner to do so is not likely to succeed. These actions include actions against a general partner for breach of its duties or of our partnership agreement. In addition, the statutory or case law of some jurisdictions may permit a limited partner to institute legal action on behalf of itself and all other similarly situated limited partners to recover damages from a general partner for violations of its fiduciary duties to the limited partners.

 

Partnership agreement modified standards

The Delaware Act provides that, unless otherwise provided in a partnership agreement, a partner or other person shall not be liable to a limited partnership or to another partner or to another person that is a party to or is otherwise bound by a partnership agreement for breach of fiduciary duty for the partner’s or other person’s good faith reliance on the provisions of the partnership agreement. Under our partnership agreement, to the extent that, at law or in equity an indemnitee has duties (including fiduciary duties) and liabilities relating thereto to us or to our partners, our general partner and any other indemnitee acting in connection with our business or affairs shall not be liable to us or to any partner for its good faith reliance on the provisions of our partnership agreement.

 

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By purchasing our common units, each common unitholder automatically agrees to be bound by the provisions in our partnership agreement, including the provisions discussed above. This is in accordance with the policy of the Delaware Act favoring the principle of freedom of contract and the enforceability of partnership agreements. The failure of a limited partner to sign a partnership agreement does not render our partnership agreement unenforceable against that person.

Under our partnership agreement, we must indemnify our general partner and its officers, directors, managers and certain other specified persons, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by our general partner or these other persons. We must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith. We also must provide this indemnification for criminal proceedings unless our general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, our general partner could be indemnified for its negligent acts if it meets the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC such indemnification is contrary to public policy and therefore unenforceable. See “The Partnership Agreement—Indemnification.”

Description of our Common Units

Our Common Units

The common units offered hereby represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and exercise the rights and privileges provided to limited partners under our partnership agreement. For a description of the rights and privileges of holders of our common units to partnership distributions, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Distribution Policy.” For a description of the rights and privileges of limited partners under our partnership agreement, including voting rights, see “The Partnership Agreement.”

Transfer Agent and Registrar

American Stock Transfer & Trust Company will serve as registrar and transfer agent for the common units. We pay all fees charged by the transfer agent for transfers of common units, except the following, which must be paid by unitholders:

 

•

surety bond premiums to replace lost or stolen certificates, taxes and other governmental charges;

 

•

special charges for services requested by a holder of a common unit; and

 

•

other similar fees or charges.

There is no charge to unitholders for disbursements of our quarterly cash distributions. We will indemnify the transfer agent, its agents and each of their shareholders, directors, officers and employees against all claims and losses that may arise out of acts performed or omitted for its activities in that capacity, except for any liability due to any gross negligence or intentional misconduct of the indemnified person or entity.

The transfer agent may resign, by notice to us, or be removed by us. The resignation or removal of the transfer agent will become effective upon our appointment of a successor transfer agent and registrar and its acceptance of the appointment. If a successor has not been appointed or has not accepted its appointment within 30 days after notice of the resignation or removal, our general partner may act as the transfer agent and registrar until a successor is appointed.

 

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Transfer of Common Units

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission is reflected in our books and records. Each transferee:

 

•

represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

 

•

automatically agrees to be bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

 

•

gives the consents and approvals contained in our partnership agreement, such as the approval of all transactions and agreements entered into in connection with our formation and initial public offering.

A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records from time to time as necessary to accurately reflect the transfers.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a limited partner in our partnership for the transferred common units.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

Listing

Our common units are listed on the New York Stock Exchange under the symbol “NTI.”

The Partnership Agreement

The following is a summary of the material provisions of our partnership agreement. We will provide prospective investors with a copy of our partnership agreement upon request at no charge.

We summarize the following provisions of our partnership agreement elsewhere in this prospectus:

 

•

with regard to distributions of cash, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Distribution Policy”;

 

•

with regard to the fiduciary duties of, and standard of care applicable to, our general partner, see “Conflicts of Interest and Fiduciary Duties”;

 

•

with regard to the authority of our general partner to manage our business and activities, see “Management—Our Management”;

 

•

with regard to the transfer of common units, see “Description of Our Common Units—Transfer of Common Units”; and

 

•

with regard to allocations of taxable income and taxable loss, see “Material Federal Income Tax Consequences.”

 

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Organization and Duration

Northern Tier Energy, Inc. was incorporated in October 2011. Northern Tier Energy, Inc. was converted into Northern Tier Energy LP in June 2012. We will have a perpetual existence unless terminated pursuant to the terms of our partnership agreement.

Purpose

Our purpose, as set forth in our partnership agreement, is limited to engaging in any business activity that is approved by our general partner and that lawfully may be conducted by a limited partnership organized under Delaware law; provided that our general partner shall not cause us to take any action that the general partner determines would be reasonably likely to cause us to be treated as an association taxable as a corporation or otherwise taxable as an entity for federal income tax purposes.

Although our general partner has the ability to cause us and our subsidiaries to engage in activities other than those related to the refining or retail business and activities now or hereafter customarily conducted in conjunction with this business, our general partner may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or our limited partners. In general, our general partner is authorized to perform all acts it determines to be necessary or appropriate to carry out our purposes and to conduct our business.

Distributions

Our partnership agreement specifies the manner in which we will make distributions to holders of our common units. For a description of these distributions, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Distribution Policy.”

Capital Contributions

Unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Voting Rights

The following is a summary of the unitholder vote required for the matters specified below. Matters requiring the approval of a “unit majority” require the approval of a majority of the common units, voting as a single class.

Northern Tier Holdings has, and after this offering will continue to have, the ability to ensure the passage of, as well as the ability to ensure the defeat of, any amendment which requires a unit majority by virtue of its 79.7% (69.9% after the offering, assuming no exercise of the underwriters’ option to purchase additional units). ownership of our common units.

In voting their units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.

 

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The following is a summary of the vote requirements specified for certain matters under our partnership agreement:

 

Issuance of additional partnership interests

No approval right. See “—Issuance of Additional Partnership Interests.”

 

Amendment of our partnership agreement

Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. See “—Amendment of Our Partnership Agreement.”

 

Merger of our partnership or the sale of all or substantially all of our assets

Unit majority in certain circumstances. See “—Merger, Consolidation, Conversion, Sale or Other Disposition of Assets.”

 

Dissolution of our partnership

Unit majority. See “—Dissolution.”

 

Continuation of our partnership upon dissolution

Unit majority. See “—Dissolution.”

 

Withdrawal of our general partner

Under most circumstances, the approval of a majority of the common units, voting as a single class, excluding units held by our general partner and its affiliates, is required for the withdrawal of our general partner prior to September 30, 2022 in a manner that would cause a dissolution of our partnership. See “—Withdrawal or Removal of Our General Partner.”

 

Removal of our general partner

Not less than two-thirds of the outstanding common units, voting as a single class, including units held by our general partner and its affiliates. See “—Withdrawal or Removal of Our General Partner.”

 

Transfer of the general partner interest

No approval right. See “—Transfer of General Partner Interest.”

 

Transfer of ownership interests in our general partner

No approval right. See “—Transfer of Ownership Interests in Our General Partner.”

If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of such units. This loss of voting rights does not apply to any person or group that acquires the units from our general partner or its affiliates and any transferees of that person or group approved by our general partner or to any person or group who acquires the units with the specific approval of our general partner.

Applicable Law; Forum, Venue and Jurisdiction

Our partnership agreement is governed by Delaware law. Our partnership agreement requires that any claims, suits, actions or proceedings:

 

•

arising out of or relating in any way to the partnership agreement (including any claims, suits or actions to interpret, apply or enforce the provisions of the partnership agreement or the duties, obligations or liabilities among limited partners or of limited partners to us, or the rights or powers of, or restrictions on, the limited partners or us);

 

•

brought in a derivative manner on our behalf;

 

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•

asserting a claim of breach of a fiduciary duty owed by any director, officer or other employee of us or our general partner, or owed by our general partner, to us or the limited partners;

 

•

asserting a claim arising pursuant to any provision of the Delaware Act; or

 

•

asserting a claim governed by the internal affairs doctrine,

shall be exclusively brought in the Court of Chancery of the State of Delaware (or, if such court does not have subject matter jurisdiction thereof, any other court located in the State of Delaware with subject matter jurisdiction), regardless of whether such claims, suits, actions or proceedings sound in contract, tort, fraud or otherwise, are based on common law, statutory, equitable, legal or other grounds, or are derivative or direct claims. The enforceability of similar choice of forum provisions in the certificate of incorporation of Delaware corporations has been challenged in legal proceedings, and it is possible that a court could find these types of analogous provisions in a partnership agreement to be inapplicable or unenforceable.

By purchasing a common unit, a limited partner is irrevocably consenting to these limitations and provisions regarding claims, suits, actions or proceedings and submitting to the exclusive jurisdiction of the Court of Chancery of the State of Delaware in connection with any such claims, suits, actions or proceedings.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Act and that it otherwise acts in conformity with the provisions of our partnership agreement, its liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital it is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by the limited partners as a group:

 

•

to remove or replace our general partner;

 

•

to approve some amendments to our partnership agreement; or

 

•

to take other action under our partnership agreement

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under the laws of Delaware to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years.

Our subsidiaries conduct business in several states and we and our subsidiaries may conduct business in other states or countries in the future. Maintenance of our limited liability as owner of our operating subsidiaries may require compliance with legal requirements in the jurisdictions in which the operating subsidiaries conduct business, including qualifying our subsidiaries to do business there.

 

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Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our operating subsidiaries or otherwise, it were determined that we were conducting business in any jurisdiction without compliance with the applicable limited partnership or limited liability company statute, or that the right, or exercise of the right by the limited partners as a group, to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then the limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of the limited partners.

Issuance of Additional Partnership Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the unitholders.

It is possible that we will fund acquisitions through the issuance of additional common units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing holders of common units in our distributions. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing holders of common units in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have rights to distributions or special voting rights to which the common units are not entitled or are senior in right of distribution to the common units. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior to the common units.

Our general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units or other partnership units, whenever, and on the same terms that, we issue those interests to persons other than our general partner and its affiliates (other than the issuance of common units upon exercise by the underwriters of their option to purchase additional common units), to the extent necessary to maintain the percentage interest of our general partner and its affiliates, including such interest represented by common units, that existed immediately prior to each issuance. The holders of common units will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests.

Amendment of Our Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by our general partner. However, our general partner will have no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below under “—No Unitholder Approval,” our general partner is required to seek written approval of the holders of the number of units required to approve the amendment or to call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

 

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Prohibited Amendments

No amendment may be made that would:

 

•

enlarge the obligations of any limited partner without its consent, unless approved by at least a majority of the type or class of limited partner interests so affected; or

 

•

enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by us to our general partner or any of its affiliates without the consent of our general partner, which consent may be given or withheld in its sole discretion.

The provision of our partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units, voting as a single class (including units owned by our general partner and its affiliates). Following the closing of this offering, Northern Tier Holdings will own approximately 69.9% of our common units (or approximately 68.4% of our common units if the underwriters exercise their option to purchase additional common units in full).

No Unitholder Approval

Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

 

•

a change in our name, the location of our principal place of business, our registered agent or our registered office;

 

•

the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

 

•

a change that our general partner determines to be necessary or appropriate to qualify or continue our qualification as a limited partnership or other entity in which the limited partners have limited liability under the laws of any state or to ensure that neither we nor any of our subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed);

 

•

an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

 

•

an amendment that our general partner determines to be necessary or appropriate in connection with the creation, authorization or issuance of additional partnership interests or rights to acquire partnership interests;

 

•

any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

 

•

an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

 

•

any amendment that our general partner determines to be necessary or appropriate to reflect and account for the formation by us of, or our investment in, any corporation, partnership, joint venture, limited liability company or other entity, as otherwise permitted by our partnership agreement;

 

•

a change in our fiscal year or taxable year and related changes;

 

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•

conversions into, mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the conversion, merger or conveyance other than those it receives by way of the conversion, merger or conveyance; or

 

•

any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement without the approval of any limited partner if our general partner determines that those amendments:

 

•

do not adversely affect in any material respect the limited partners considered as a whole or any particular class of limited partners;

 

•

are necessary or appropriate to satisfy any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

 

•

are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the limited partner interests are or will be listed for trading;

 

•

are necessary or appropriate for any action taken by our general partner relating to splits or combinations of common units under the provisions of our partnership agreement; or

 

•

are required to effect the intent expressed in this prospectus or the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

Opinion of Counsel and Unitholder Approval

Any amendment that our general partner determines adversely affects in any material respect one or more particular classes of limited partners will require the approval of at least a majority of the class or classes so affected, but no vote will be required by any class or classes of limited partners that our general partner determines are not adversely affected in any material respect. Any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that would reduce the voting percentage required to take any action, other than to remove the general partner or call a meeting of unitholders is required to be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced. Any amendment that would increase the percentage of units required to remove the general partner or call a meeting of unitholders must be approved by the affirmative vote of limited partners whose aggregate outstanding units constitute not less than the percentage sought to be increased.

For amendments of the type not requiring unitholder approval, our general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in our being treated as a taxable entity for federal income tax purposes in connection with any of the amendments. No other amendments to our partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless we first obtain an opinion of counsel to the effect that the amendment will not affect the limited liability under Delaware law of any of our limited partners.

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

A merger, consolidation or conversion of us requires the prior consent of our general partner. However, our general partner will have no duty or obligation to consent to any merger, consolidation or conversion and may decline to do so free of any fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interest of us or the limited partners.

 

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In addition, our partnership agreement generally prohibits our general partner, without the prior approval of the holders of a unit majority, from causing us to sell, exchange or otherwise dispose of all or substantially all of our assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination. Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our assets without such approval. Our general partner may also sell all or substantially all of our assets under a foreclosure or other realization upon those encumbrances without such approval.

Finally, our general partner may consummate any merger without the prior approval of our unitholders if we are the surviving entity in the transaction, our general partner has received an opinion of counsel regarding limited liability and tax matters, the transaction would not result in an amendment to the partnership agreement (other than an amendment that the general partner could adopt without the consent of other partners), each of our units will be an identical unit of our partnership following the transaction and the partnership securities to be issued do not exceed 20% of our outstanding partnership interests immediately prior to the transaction.

If the conditions specified in our partnership agreement are satisfied, our general partner may convert us or any of our subsidiaries into a new limited liability entity or merge us or any of our subsidiaries into, or convey all of our assets to, a newly formed entity, if the sole purpose of that conversion, merger or conveyance is to effect a mere change in our legal form into another limited liability entity, we have received an opinion of counsel regarding limited liability and tax matters and our general partner determines that the governing instruments of the new entity provide the limited partners and our general partner with substantially the same rights and obligations as contained in our partnership agreement. Our unitholders are not entitled to dissenters’ rights of appraisal under our partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of our assets or any other similar transaction or event.

Dissolution

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

 

•

the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

 

•

there being no limited partners, unless we are continued without dissolution in accordance with applicable Delaware law;

 

•

the entry of a decree of judicial dissolution of our partnership; or

 

•

the withdrawal or removal of our general partner or any other event that results in its ceasing to be our general partner other than by reason of a transfer of its general partner interest in accordance with our partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under the last clause above, the holders of a unit majority may also elect, within specific time limitations, to continue our business on the same terms and conditions described in our partnership agreement by appointing as a successor general partner an entity approved by the holders of units representing a unit majority, subject to our receipt of an opinion of counsel to the effect that:

 

•

the action would not result in the loss of limited liability under Delaware law of any limited partner; and

 

•

neither our partnership nor any of our subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

 

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Liquidation and Distribution of Proceeds

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply the proceeds of the liquidation as described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Our Distribution Policy.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Except as described below, our general partner has agreed not to withdraw voluntarily as our general partner prior to September 30, 2022 without obtaining the approval of the holders of at least a majority of the outstanding units excluding units held by our general partner and its affiliates and furnishing an opinion of counsel regarding limited liability and tax matters. On or after September 30, 2022, our general partner may withdraw as general partner without first obtaining approval of any unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our partnership agreement. Notwithstanding the information above, our general partner may withdraw without unitholder approval upon 90 days’ notice to the limited partners if at least 50% of the outstanding units are held or controlled by one person and its affiliates other than our general partner and its affiliates. In addition, our partnership agreement permits our general partner to sell or otherwise transfer all of its general partner interest in us without the approval of the unitholders. See “—Transfer of General Partner Interest.”

Upon withdrawal of our general partner under any circumstances, other than as a result of a transfer by our general partner of all or a part of its general partner interest in us, the holders of a unit majority may select a successor to that withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue our business and to appoint a successor general partner. See “—Dissolution.”

Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% of the outstanding units, voting together as a single class, including units held by our general partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of our general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding units, voting together as a single class. The ownership of more than 33 1/3% of the outstanding units by our general partner and its affiliates gives them the ability to prevent our general partner’s removal. At the closing of this offering, our general partner and its affiliates will own approximately 69.9% of the outstanding common unit (68.4% if the underwriters exercise in full their option to purchase additional common units).

In the event the general partner withdraws or is removed, upon the admission of a successor general partner, the general partner interest of the departing general partner shall be cancelled.

Transfer of General Partner Interest

At any time, our general partner may transfer all or any of its general partner interest to another person without the approval of our unitholders. As a condition of this transfer, the transferee must, among other things, assume the rights and duties of our general partner, agree to be bound by the provisions of our partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters.

 

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Transfer of Ownership Interests in Our General Partner

At any time, the owners of our general partner may sell or transfer all or part of their ownership interests in our general partner to an affiliate or a third party without the approval of our unitholders.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove Northern Tier Energy GP LLC as our general partner or from otherwise changing our management. See “—Withdrawal or Removal of Our General Partner” for a discussion of certain consequences of the removal of our general partner. If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply in certain circumstances. See “—Voting Rights.”

Call Right

If at any time our general partner and its affiliates own more than 90% of the then-issued and outstanding common units, our general partner will have the right, which it may assign in whole or in part to any of its affiliates or beneficial owners or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons, as of a record date to be selected by our general partner, on at least 10 but not more than 60 days’ notice.

The purchase price in the event of such an acquisition is the greater of:

 

(1)

the highest price paid by our general partner or any of its affiliates for common units purchased within the 90 days preceding the date on which our general partner first mails notice of its election to purchase such units; and

 

(2)

the average of the daily closing prices of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed.

As a result of our general partner’s right to purchase outstanding common units, a holder of common units may have its units purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The federal income tax consequences to a unitholder of the exercise of this call right are the same as a sale by that unitholder of his common units in the market. See “Material Federal Income Tax Consequences—Disposition of Units.”

Non-Taxpaying Holders; Redemption

If our general partner, with the advice of counsel, determines that the tax status (or lack of proof thereof) of one or more of our limited partners or their owners has, or is reasonably likely to have, a material adverse effect on the rates chargeable to customers by us or our subsidiaries with respect to assets that are subject to regulation by the Federal Energy Regulatory Commission or similar regulatory body, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

•

obtain proof of the federal income tax status of our limited partners (and their owners, to the extent relevant); and

 

•

permit us to redeem the units held by any person whose tax status has or is reasonably likely to have a material adverse effect on the rates or who fails to comply with the procedures instituted by our general partner to obtain proof of the federal income tax status. The redemption price in the case of such a redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

 

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Non-Citizen Assignees; Redemption

If our general partner, with the advice of counsel, determines we are subject to federal, state or local laws or regulations that create a substantial risk of cancellation or forfeiture of any property that we have an interest in because of the nationality, citizenship or other related status of any limited partner, then our general partner may adopt such amendments to our partnership agreement as it determines necessary or advisable to:

 

•

obtain proof of the nationality, citizenship or other related status of our limited partner (and their owners, to the extent relevant); and

 

•

permit us to redeem the units held by any person whose nationality, citizenship or other related status creates substantial risk of cancellation or forfeiture of any property or who fails to comply with the procedures instituted by our general partner to obtain proof of the nationality, citizenship or other related status. The redemption price in the case of such redemption will be the average of the daily closing prices per unit for the 20 consecutive trading days immediately prior to the date set for redemption.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our unitholders and to act upon matters for which approvals may be solicited. Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called, represented in person or by proxy, will constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum will be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. See “—Issuance of Additional Partnership Interests.” However, if at any time any person or group, other than our general partner and its affiliates or a direct or subsequently approved transferee of our general partner or its affiliates and purchasers specifically approved by our general partner acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum, or for other similar purposes. Units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Except as our partnership agreement otherwise provides, common units will vote together, and will otherwise be treated, as a single class.

Any notice, demand, request, report, or proxy material required or permitted to be given or made to record holders of units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Status as Limited Partner

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books and records. Except as described above under “—Limited Liability,” the common units will be fully paid, and unitholders will not be required to make additional contributions.

Indemnification

Under our partnership agreement, we will indemnify the following persons in most circumstances, to the fullest extent permitted by law, from and against all losses, claims, damages, or similar events:

 

•

our general partner;

 

•

any departing general partner;

 

•

any person who is or was an affiliate of our general partner or any departing general partner;

 

•

any person who is or was a director, officer, fiduciary, trustee, general partner, manager or managing member of us or any of our subsidiaries, our general partner or any departing general partner or any of their affiliates;

 

•

any person who is or was serving as a director, officer, employee, agent, fiduciary, trustee, general partner, manager or managing member of another person owing a fiduciary duty to us or any of our subsidiaries;

 

•

any person who controls our general partner or any departing general partner; or

 

•

any person designated by our general partner.

Any indemnification under these provisions will only be out of our assets. Unless our general partner otherwise agrees, it will not be personally liable for, or have any obligation to contribute or lend funds or assets to us to enable us to effectuate, indemnification. We may purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our partnership agreement.

Reimbursement of Expenses

Our partnership agreement requires us to reimburse our general partner for all direct and indirect expenses it incurs or payments it makes on our behalf and all other expenses allocable to us or otherwise incurred by our general partner in connection with operating our business. The partnership agreement does not limit the amount of expenses for which our general partner and its affiliates may be reimbursed. These expenses include salary, bonus, incentive compensation and other amounts paid to persons who perform services for us or on our behalf and expenses allocated to our general partner and its affiliates. Our general partner is entitled to determine in good faith the expenses that are allocable to us.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. For tax and fiscal reporting purposes, our fiscal year is the calendar year.

We will furnish or make available to record holders of our common units, within 105 days after the close of each fiscal year, an annual report containing audited consolidated financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available a report containing our unaudited consolidated financial statements within 50 days after the close of each quarter. We will be deemed to have made any such report available if we file such report with the SEC on EDGAR or make the report available on a publicly available website which we maintain.

 

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We will furnish each record holder of a unit with information reasonably required for federal and state tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on their cooperation in supplying us with specific information. Every unitholder will receive information to assist it in determining its federal and state tax liability and in filing its federal and state income tax returns, regardless of whether it supplies us with information.

Right to Inspect Our Books and Records

Our partnership agreement provides that a limited partner can, upon reasonable demand and at his own expense, have furnished to it:

 

•

a current list of the name and last known address of each record holder;

 

•

copies of our partnership agreement, our certificate of limited partnership, related amendments and powers of attorney under which they have been executed;

 

•

information regarding the status of our business and financial condition (provided that obligation shall be satisfied to the extent the limited partner is furnished our most recent annual report and any subsequent quarterly or periodic reports required to be filed (or which would be required to be filed) with the SEC pursuant to Section 13 of the Exchange Act); and

 

•

any other information regarding our affairs that our general partner determines is just and reasonable.

Under our partnership agreement, however, each of our limited partners and other persons who acquire interests in us, do not have rights to receive information from us or any of the persons we indemnify as described under “—Indemnification” for the purpose of determining whether to pursue litigation or assist in pending litigation against us or those indemnified persons relating to our affairs, except pursuant to the applicable rules of discovery relating to the litigation commenced by the person seeking information.

Our general partner may, and intends to, keep confidential from the limited partners’ trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests, could damage us or our business or that we are required by law or by agreements with third parties to keep confidential.

Registration Rights

In connection with our initial public offering, we entered into an amended and restated registration rights agreement with Northern Tier Investors, LLC, Northern Tier Holdings, ACON Refining, TPG Refining, NTR Partners LLC, NTR Partners II LLC and NTI Management. Under the registration rights agreement, Northern Tier Holdings, ACON Refining and TPG Refining can cause, and after ACON Refining and TPG Refining and their transferees no longer hold registrable securities, NTR Partners LLC and NTR Partners II LLC can cause, Northern Tier Energy LP to register their common units under the Securities Act and to maintain a shelf registration statement effective with respect to such units. In addition, under the agreement, Northern Tier Holdings, ACON Refining, TPG Refining, NTR Partners, NTR Partners II LLC, and NTI Management are entitled to participate in certain other registration statements and offerings conducted on behalf of Northern Tier Energy LP or third parties. See “Common Units Eligible for Future Sale.”

Common Units Eligible for Future Sale

As of January 9, 2013, there were 91,921,112 common units outstanding, 73,227,500 of which are owned by Northern Tier Holdings LLC. The sale of these common units could have an adverse impact on the price of our common units or on any trading market that may develop.

 

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The 18,687,500 common units sold in our initial public offering are generally freely transferable without restriction or further registration under the Securities Act. However, any common units held by an “affiliate” of ours may not be resold publicly except in compliance with the registration requirements of the Securities Act or under an exemption from the registration requirements of the Securities Act pursuant to Rule 144 or otherwise. Rule 144 permits securities acquired by an affiliate of ours to be sold into the market in an amount that does not exceed, during any three-month period, the greater of:

 

•

1% of the total number of the class of securities outstanding; or

 

•

the average weekly reported trading volume of the common units for the four calendar weeks prior to the sale.

Sales under Rule 144 by our affiliates are also subject to specific manner of sale provisions, holding period requirements, notice requirements and the availability of current public information about us. A person who is not deemed to have been an affiliate of ours at any time during the three months preceding a sale, and who has beneficially owned common units for at least six months, would be entitled to sell those common units under Rule 144 without regard to the volume, manner of sale and notice requirements of Rule 144 so long as we comply with the current public information requirement for the next six months after the six-month holding period expires.

Our partnership agreement provides that we may issue an unlimited number of limited partner interests of any type without a vote of the unitholders. Any issuance of additional common units or other equity interests would result in a corresponding decrease in the proportionate ownership interest in us represented by, and could adversely affect the distributions to and market price of, common units then outstanding. See “The Partnership Agreement—Issuance of Additional Partnership Interests.”

In connection with our initial public offering, we entered into an amended and restated registration rights agreement with Northern Tier Investors, LLC, Northern Tier Holdings, ACON Refining, TPG Refining, NTR Partners LLC, NTR Partners II LLC and NTI Management. Under the registration rights agreement, Northern Tier Holdings, ACON Refining and TPG Refining can cause, and after ACON Refining and TPG Refining and their transferees no longer hold registrable securities, NTR Partners LLC and NTR Partners II LLC can cause, Northern Tier Energy LP to register their common units under the Securities Act and to maintain a shelf registration statement effective with respect to such units. In addition, under the agreement, Northern Tier Holdings, ACON Refining, TPG Refining, NTR Partners LLC, NTR Partners II LLC and NTI Management are entitled to participate in certain other registration statements and offerings conducted on behalf of Northern Tier Energy LP or third parties.

In addition, we filed a registration statement on Form S-8 under the Securities Act on August 30, 2012 to register common units issuable under our long-term incentive plan. Units issued under our long-term incentive plan are eligible for resale in the public market without restriction, subject to Rule 144 limitations applicable to affiliates.

Material Federal Income Tax Consequences

This section summarizes the material federal income tax consequences that may be relevant to prospective common unitholders. To the extent this section discusses federal income taxes, that discussion is based upon current provisions of the Code, Treasury Regulations, and current administrative rulings and court decisions, all of which are subject to change. Changes in these authorities may cause the federal income tax consequences to a prospective unitholder to vary substantially from those described below. Unless the context otherwise requires, references in this section to “we” or “us” are references to the partnership and its subsidiaries.

Legal conclusions contained in this section, unless otherwise noted, are the opinion of Vinson & Elkins L.L.P. and are based on the accuracy of representations made by us to them for this purpose. However, this

 

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section does not address all federal income tax matters that affect us or our unitholders. Furthermore, this section focuses on unitholders who are individual citizens or residents of the United States (for federal income tax purposes), whose functional currencies are the U.S. dollar and who hold units as capital assets (generally, property that is held for investment). This section has limited applicability to corporations, partnerships, entities treated as partnerships for federal income tax purposes, estates, trusts, non-resident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, non-U.S. persons, IRAs, employee benefit plans, real estate investment trusts or mutual funds. Accordingly, because each unitholder may have unique circumstances beyond the scope of the discussion herein, we encourage each unitholder to consult such unitholder’s own tax advisor in analyzing the federal, state, local and non-U.S. tax consequences that are particular to that unitholder resulting from ownership or disposition of its units.

We are relying on opinions and advice of Vinson & Elkins L.L.P. with respect to the matters described herein. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or courts. Accordingly, the opinions and statements made herein may not be sustained by a court if contested by the IRS. Any such contest of the matters described herein may materially and adversely impact the market for our units and the prices at which such units trade. In addition, 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. Furthermore, our tax treatment, or the tax treatment of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions, which might be retroactively applied.

For the reasons described below, Vinson & Elkins L.L.P. has not rendered an opinion with respect to the following federal income tax issues: (1) the treatment of a unitholder whose units are loaned to a short seller to cover a short sale of units (please see “—Tax Consequences of Unit Ownership—Treatment of Short Sales”); (2) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations (please see “—Disposition of Units—Allocations Between Transferors and Transferees”); and (3) whether our method for taking into account Section 743 adjustments is sustainable in certain cases (please see “—Tax Consequences of Unit Ownership—Section 754 Election” and “—Uniformity of Units”).

Taxation of the Partnership

Partnership Status

We are treated as a partnership for federal income tax purposes and, therefore, generally are not liable for federal income taxes. Instead, as described below, each of our unitholders takes into account its respective share of our items of income, gain, loss and deduction in computing its federal income tax liability as if the unitholder had earned such income directly, even if no cash distributions are made to the unitholder. Distributions by us to a unitholder generally will not give rise to income or gain taxable to such unitholder, unless the amount of cash distributed to a unitholder exceeds the unitholder’s adjusted tax basis in its units.

Section 7704 of the Code generally provides that publicly traded partnerships will be treated as corporations for federal income tax purposes. However, if 90% or more of a partnership’s gross income for every taxable year it is publicly traded consists of “qualifying income,” the partnership may continue to be treated as a partnership for federal income tax purposes (the “Qualifying Income Exception”). 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. We estimate that less than 5% of our current gross income is not qualifying income; however, this estimate could change from time to time.

Based upon factual representations made by us and our general partner regarding the composition of our income and the other representations set forth below, Vinson & Elkins L.L.P. is of the opinion that we will be treated as a partnership and each of our partnership or limited liability company subsidiaries, other than Northern

 

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Tier Retail Holdings LLC and Northern Tier Energy Holdings LLC, or any of their subsidiaries, will be treated as a partnership or will be disregarded as an entity separate from us for federal income tax purposes. In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which Vinson & Elkins L.L.P. has relied include, without limitation:

 

(1)

Neither we nor any of our partnership or limited liability company subsidiaries, other than Northern Tier Retail Holdings LLC and Northern Tier Energy Holdings LLC, has elected to be treated as a corporation for federal income tax purposes;

 

(2)

For each taxable year since and including the year of our initial public offering, more than 90% of our gross income has been and will be income of a character that Vinson & Elkins L.L.P. has opined is “qualifying income” within the meaning of Section 7704(d) of the Code; and

 

(3)

Each hedging transaction that we treat as resulting in qualifying income has been and will be appropriately identified as a hedging transaction pursuant to applicable Treasury Regulations, and has been and will be associated with our refining operations, our purchases of crude oil or our sales of refinery products thereof that are held or to be held by us in activities that Vinson & Elkins L.L.P. has opined or will opine result in qualifying income.

We believe that these representations are true and will be true in the future.

If we fail to meet the Qualifying Income Exception, other than a failure that is determined by the IRS to be inadvertent and that is cured within a reasonable time after discovery (in which case the IRS may also require us to make adjustments with respect to our unitholders or pay other amounts), we will be treated as transferring all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation and then distributing that stock to our unitholders in liquidation of their units. This deemed contribution and liquidation should not result in the recognition of taxable income by our unitholders or us so long as our liabilities do not exceed the tax basis of our assets. Thereafter, we would be treated as an association taxable as a corporation for federal income tax purposes.

If for any reason we are taxable as a corporation in any taxable year, our items of income, gain, loss and deduction would be taken into account by us in determining the amount of our liability for federal income tax, rather than being passed through to our unitholders. Accordingly, our taxation as a corporation would materially reduce our cash distributions to unitholders and thus would likely substantially reduce the value of our units. In addition, any distribution made to a unitholder would be treated as (i) a taxable dividend to the extent of our current or accumulated earnings and profits, then (ii) a nontaxable return of capital to the extent of the unitholder’s tax basis in our units, and thereafter (iii) taxable capital gain.

The remainder of this discussion is based on the opinion of Vinson & Elkins L.L.P. that we will be treated as a partnership for federal income tax purposes.

Tax Consequences of Unit Ownership

Limited Partner Status

Unitholders who are admitted as limited partners of the partnership, as well as unitholders whose units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of units, will be treated as partners of the partnership for federal income tax purposes. For a discussion related to the risks of losing partner status as a result of short sales, please see “—Tax Consequences of Unit Ownership—Treatment of Short Sales.” Unitholders who are not treated as partners in us as described above are urged to consult their own tax advisors with respect to the tax consequences applicable to them under the circumstances.

 

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Flow-Through of Taxable Income

Subject to the discussion below under “—Entity-Level Collections of Unitholder Taxes” with respect to payments we may be required to make on behalf of our unitholders, we will not pay any federal income tax. Rather, each unitholder will be required to report on its income tax return its share of our income, gains, losses and deductions for our taxable year or years ending with or within its taxable year without regard to whether we make cash distributions to him. Consequently, we may allocate income to a unitholder even if that unitholder has not received a cash distribution. The income we allocate to common unitholders will generally be taxable as ordinary income.

Basis of Units

A unitholder’s tax basis in its units initially will be the amount it paid for those units plus its initial share of our liabilities. That basis generally will be (i) increased by the unitholder’s share of our income and any increases in such unitholder’s share of our nonrecourse liabilities, and (ii) decreased, but not below zero, by distributions to it, by its share of our losses, any decreases in its share of our nonrecourse liabilities and its share of our expenditures that are neither deductible nor required to be capitalized.

Treatment of Distributions

Distributions made by us to a unitholder generally will not be taxable to the unitholder, unless such distributions are of cash or marketable securities that are treated as cash and exceed the unitholder’s tax basis in its units, in which case the unitholder will recognize gain taxable in the manner described below under “—Disposition of Units.”

Any reduction in a unitholder’s share of our “nonrecourse liabilities” (liabilities for which no partner bears the economic risk of loss) will be treated as a distribution by us of cash to that unitholder. A decrease in a unitholder’s percentage interest in us because of our issuance of additional units will decrease the unitholder’s share of our nonrecourse liabilities. For purposes of the foregoing, a unitholder’s share of our nonrecourse liabilities generally will be based upon that unitholder’s share of the unrealized appreciation (or depreciation) in our assets, to the extent thereof, with any excess liabilities allocated based on the unitholder’s share of our profits. Please see “Disposition of Units.”

A non-pro rata distribution of money or property (including a deemed distribution described above) may cause a unitholder to recognize ordinary income, if the distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture and substantially appreciated “inventory items,” both as defined in Section 751 of the Code (“Section 751 Assets”). To the extent of such reduction, the unitholder would be deemed to receive its proportionate share of the Section 751 Assets and exchange such assets with us in return for an allocable portion of the non-pro rata distribution. This latter deemed exchange generally will result in the unitholder’s realization of ordinary income in an amount equal to the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis (generally zero) in the Section 751 Assets deemed to be relinquished in the exchange.

Limitations on Deductibility of Losses

The deduction by a unitholder of its share of our losses will be limited to the lesser of (i) the unitholder’s tax basis in its units, and (ii) in the case of a unitholder who is an individual, estate, trust or corporation (if more than 50% of the corporation’s stock is owned directly or indirectly by or for five or fewer individuals or a specific type of tax exempt organization), the amount for which the unitholder is considered to be “at risk” with respect to our activities. In general, a unitholder will be at risk to the extent of its tax basis in its units, reduced by (1) any portion of that basis attributable to the unitholder’s share of our liabilities, (2) any portion of that basis representing amounts otherwise protected against loss because of a guarantee, stop loss agreement or similar

 

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arrangement and (3) any amount of money the unitholder borrows to acquire or hold its units, if the lender of those borrowed funds owns an interest in us, is related to another unitholder or can look only to the units for repayment.

A unitholder subject to the basis and at risk limitation must recapture losses deducted in previous years to the extent that distributions (including distributions as a result of a reduction in a unitholder’s share of nonrecourse liabilities) cause the unitholder’s at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable as a deduction in a later year to the extent that the unitholder’s tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon a taxable disposition of units, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but not losses suspended by the basis limitation. Any loss previously suspended by the at risk limitation in excess of that gain can no longer be used.

In addition to the basis and at risk limitations, passive activity loss limitations generally limit the deductibility of losses incurred by individuals, estates, trusts, some closely held corporations and personal service corporations from “passive activities” (generally, trade or business activities in which the taxpayer does not materially participate). The passive loss limitations are applied separately with respect to each publicly traded partnership. Consequently, any passive losses we generate will be available to offset only our passive income generated in the future. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when the unitholder disposes of all of its units in a fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk and basis limitations.

Limitations on Interest Deductions

The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” Investment interest expense includes:

 

•

interest on indebtedness properly allocable to property held for investment;

 

•

interest expense attributed to portfolio income; and

 

•

the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses other than interest directly connected with the production of investment income. Such term generally does not include qualified dividend income or gains attributable to the disposition of property held for investment. A unitholder’s share of a publicly traded partnership’s portfolio income and, according to the IRS, net passive income will be treated as investment income for purposes of the investment interest expense limitation.

Entity-Level Collections of Unitholder Taxes

If we are required or elect under applicable law to pay any federal, state, local or non-U.S. tax on behalf of any current or former unitholder, we are authorized to pay those taxes and treat the payment as a distribution of cash to the relevant unitholder. Where the relevant unitholder’s identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend our partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of

 

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distributions otherwise applicable under our partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of a unitholder, in which event the unitholder may be entitled to claim a refund of the overpayment amount. Unitholders are urged to consult their tax advisors to determine the consequences to them of any tax payment we make on their behalf.

Allocation of Income, Gain, Loss and Deduction

In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among our unitholders in accordance with their percentage interests in us. If we have a net loss, our items of income, gain, loss and deduction will be allocated first among our unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and thereafter to our general partner.

Specified items of our income, gain, loss and deduction will be allocated under Section 704(c) of the Code to account for any difference between the tax basis and fair market value of our assets at the time such assets are contributed to us and at the time of any subsequent offering of our units by us (a “Book-Tax Disparity”). In addition, items of recapture income will be specially allocated to the extent possible to the unitholder who was allocated the deduction giving rise to that recapture income in order to minimize the recognition of ordinary income by other unitholders.

An allocation of items of our income, gain, loss or deduction, generally must have “substantial economic effect” as determined under Treasury Regulations. If an allocation does not have substantial economic effect, it will be reallocated to our unitholders on the basis of their interests in us, which will be determined by taking into account all the facts and circumstances, including:

 

•

our partners’ relative contributions to us;

 

•

the interests of all of our partners in our profits and losses;

 

•

the interest of all of our partners in our cash flow; and

 

•

the rights of all of our partners to distributions of capital upon liquidation.

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “—Section 754 Election” and “—Disposition of Units—Allocations Between Transferors and Transferees,” allocations under our partnership agreement will have substantial economic effect.

Treatment of Liquidation and Termination

In general, if we liquidate or terminate the partnership and sell all of our assets, any gain or loss recognized upon such sale generally will be allocated among our unitholders in the manner described under “—Allocation of Income, Gain, Loss and Deduction.” Please read “—Treatment of Distributions” for a discussion of the termination of any distributions that may result from a liquidation of the partnership. For a general discussion of the events and circumstances of a liquidation and termination of the partnership, please read “The Partnership Agreement—Termination and Dissolution” and “The Partnership Agreement—Liquidation and Distribution of Proceeds.”

Treatment of Short Sales

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be treated as having disposed of those units. If so, such unitholder would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period (i) any of our income, gain, loss or deduction allocated to those units would not be reportable by the unitholder, and (ii) any cash distributions received by the unitholder as to those units would be fully taxable, possibly as ordinary income.

 

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Due to lack of controlling authority, Vinson & Elkins L.L.P. has not rendered an opinion regarding the tax treatment of a unitholder whose units are loaned to a short seller to cover a short sale of our units. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing and lending their units. The IRS has announced that it is studying issues relating to the tax treatment of short sales of partnership interests. Please see “—Disposition of Units—Recognition of Gain or Loss.”

Alternative Minimum Tax

If a unitholder is subject to federal alternative minimum tax, such tax will apply to such unitholder’s distributive share of any items of our income, gain, loss or deduction. The current alternative minimum tax rate for non-corporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders are urged to consult with their tax advisors with respect to the impact of an investment in our units on their alternative minimum tax liability.

Tax Rates

The highest marginal federal income tax rate applicable to ordinary income and long-term capital gains of individuals are 39.6% and 20%, respectively. These rates are subject to change by new legislation at any time.

In addition, a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts may apply. For these purposes, investment income generally includes a unitholder’s allocable share of our income and gain realized by a unitholder from a sale of units. In the case of an individual, the tax will be imposed on the lesser of (i) the unitholder’s net investment income from all investments, or (ii) the amount by which the unitholder’s modified adjusted gross income exceeds $250,000 (if the unitholder is married and filing jointly or a surviving spouse), $125,000 (if the unitholder is married and filing separately) or $200,000 (in any other case). In the case of an estate or trust, the tax will be imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

Section 754 Election

We have in place an effective election under Section 754 of the Code that permits us to adjust the tax bases in our assets as to specific purchased units under Section 743(b) of the Code to reflect the unit purchase price. The Section 743(b) adjustment separately applies to each purchaser of units based upon the values and bases of our assets at the time of the relevant purchase. The Section 743(b) adjustment does not apply to a person who purchases units directly from us. For purposes of this discussion, a unitholder’s basis in our assets will be considered to have two components: (1) its share of the tax basis in our assets as to all unitholders (“common basis”) and (2) its Section 743(b) adjustment to that tax basis (which may be positive or negative).

Under Treasury Regulations, a Section 743(b) adjustment attributable to property depreciable under Section 168 of the Code, such as our storage assets, may be amortizable over the remaining cost recovery period for such property, while a Section 743(b) adjustment attributable to properties subject to depreciation under Section 167 of the Code, must be amortized straight-line or using the 150% declining balance method. As a result, if we owned any assets subject to depreciation under Section 167 of the Code, the amortization rates could give rise to differences in the taxation of unitholders purchasing units from us and unitholders purchasing units from other unitholders.

 

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Under our partnership agreement, we are authorized to take a position to preserve the uniformity of units even if that position is not consistent with these or any other Treasury Regulations. Please see “—Uniformity of Units.” Consistent with this authority, we intend to treat properties depreciable under Section 167, if any, in the same manner as properties depreciable under Section 168 for this purpose. These positions are consistent with the methods employed by other publicly traded partnerships but are inconsistent with the existing Treasury Regulations, and Vinson & Elkins L.L.P. has not opined on the validity of this approach.

The IRS may challenge our position with respect to depreciating or amortizing the Section 743(b) adjustment we take to preserve the uniformity of units due to lack of controlling authority. Because a unitholder’s tax basis for its units is reduced by its share of our items of deduction or loss, any position we take that understates deductions will overstate a unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please see “—Disposition of Units—Recognition of Gain or Loss.” If a challenge to such treatment were sustained, the gain from the sale of units may be increased without the benefit of additional deductions.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our assets subject to depreciation to goodwill or nondepreciable assets. Goodwill, as an intangible asset, is generally nonamortizable or amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure any unitholder that the determinations we make will not be successfully challenged by the IRS or that the resulting deductions will not be reduced or disallowed altogether. Should the IRS require a different tax basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than it would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year

We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income its share of our income, gain, loss and deduction for each taxable year ending within or with its taxable year. In addition, a unitholder who has a taxable year ending on a date other than December 31 and who disposes of all of its units following the close of our taxable year but before the close of its taxable year must include its share of our income, gain, loss and deduction in income for its taxable year, with the result that it will be required to include in income for its taxable year its share of more than one year of our income, gain, loss and deduction. Please see “—Disposition of Units—Allocations Between Transferors and Transferees.”

Tax Basis, Depreciation and Amortization

The tax basis of our assets is used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by our partners holding interests in us prior to this offering. Please see “—Tax Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction.”

If we dispose of depreciable property by sale, foreclosure or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a unitholder who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of its interest in us. Please see “—Tax

 

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Consequences of Unit Ownership—Allocation of Income, Gain, Loss and Deduction” and “—Disposition of Units—Recognition of Gain or Loss.”

The costs we incur in offering and selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. While there are uncertainties regarding the classification of costs as organization expenses, which may be amortized by us, and as syndication expenses, which may not be amortized by us, the underwriting discount we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties

The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values and the initial tax bases of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates and determinations of tax basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deduction previously reported by unitholders could change, and unitholders could be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Units

Recognition of Gain or Loss

A unitholder will be required to recognize gain or loss on a sale of units equal to the difference between the unitholder’s amount realized and tax basis for the units sold. A unitholder’s amount realized will equal the sum of the cash or the fair market value of other property it receives plus its share of our liabilities with respect to such units. Because the amount realized includes a unitholder’s share of our liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Except as noted below, gain or loss recognized by a unitholder on the sale or exchange of a unit held for more than one year generally will be taxable as long-term capital gain or loss. However, gain or loss recognized on the disposition of units will be separately computed and taxed as ordinary income or loss under Section 751 of the Code to the extent attributable to Section 751 Assets, primarily inventory items and depreciation recapture. Ordinary income attributable to Section 751 Assets may exceed net taxable gain realized on the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method, which generally means that the tax basis allocated to the interest sold equals an amount that bears the same relation to the partner’s tax basis in its entire interest in the partnership as the value of the interest sold bears to the value of the partner’s entire interest in the partnership.

Treasury Regulations under Section 1223 of the Code allow a selling unitholder who can identify units transferred with an ascertainable holding period to elect to use the actual holding period of the units transferred. Thus, according to the ruling discussed above, a unitholder will be unable to select high or low basis units to sell as would be the case with corporate stock, but, according to the Treasury Regulations, a unitholder may designate specific units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of units transferred must consistently use that identification method for all subsequent sales or exchanges of our units. A unitholder considering the purchase of additional units or a sale of

 

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units purchased in separate transactions is urged to consult its tax advisor as to the possible consequences of this ruling and application of the Treasury Regulations.

Specific provisions of the Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:

 

•

a short sale;

 

•

an offsetting notional principal contract; or

 

•

a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of the Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees

In general, our taxable income or loss will be determined quarterly, will be prorated on a monthly basis and will be subsequently apportioned among the common unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets or, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction will be allocated among the unitholders on the Allocation Date in the month in which such income, gain, loss or deduction is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

Although simplifying conventions are contemplated by the Code and most publicly traded partnerships use similar simplifying conventions, the use of this method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders, although such tax items must be prorated on a daily basis. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between transferee and transferor unitholders. If this method is not allowed under the Treasury Regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between transferee and transferor unitholders, as well as among unitholders whose interests vary during a taxable year, to conform to a method permitted under future Treasury Regulations.

A unitholder who disposes of our units prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deduction attributable to the month of disposition but will not be entitled to receive a cash distribution for that period.

Notification Requirements

A unitholder who sells or purchases any of our units is generally required to notify us in writing of that transaction within 30 days after the transaction (or, if earlier, January 15 of the year following the transaction).

 

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Upon receiving such notifications, we are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. Failure to notify us of a transfer of units may, in some cases, lead to the imposition of penalties. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale through a broker who will satisfy such requirements.

Constructive Termination

We will be considered to have terminated our partnership for federal income tax purposes upon the sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For such purposes, multiple sales of the same unit are counted only once. A constructive termination results in the closing of our taxable year for all unitholders. 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 result in more than twelve months of our taxable income or loss being includable in such unitholder’s taxable income for the year of termination.

A constructive termination occurring on a date other than December 31 will result in us filing two tax returns for one fiscal year and the cost of the preparation of these returns will be borne by all unitholders. However, pursuant to an IRS relief procedure the IRS may allow, among other things, a constructively terminated partnership to provide a single Schedule K-1 for the calendar year in which a termination occurs. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units and for other reasons, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity could result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6), which is not anticipated to apply to a material portion of our assets. Any non-uniformity could have a negative impact on the value of the units. Please see “—Tax Consequences of Unit Ownership—Section 754 Election.”

If necessary to preserve the uniformity of our units, our partnership agreement permits our general partner to take positions in filing our tax returns even when contrary to a literal application of regulations like the one described above. These positions may include reducing for some unitholders the depreciation, amortization or loss deductions to which they would otherwise be entitled or reporting a slower amortization of Section 743(b) adjustments for some unitholders than that to which they would otherwise be entitled. The general partner does not anticipate needing to take such positions, but if they were necessary, Vinson & Elkins L.L.P. would be unable to opine as to validity of such filing positions in the absence of direct and controlling authority.

A unitholder’s basis in units is reduced by its share of our deductions (whether or not such deductions were claimed on an individual income tax return) so that any position that we take that understates deductions will overstate the unitholder’s basis in its units, and may cause the unitholder to understate gain or overstate loss on any sale of such units. Please see “—Disposition of Units—Recognition of Gain or Loss” above and “—Tax Consequences of Unit Ownership—Section 754 Election” above. The IRS may challenge one or more of any positions we take to preserve the uniformity of units. If such a challenge were sustained, the uniformity of units might be affected, and, under some circumstances, the gain from the sale of units might be increased without the benefit of additional deductions.

 

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Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, non-U.S. corporations and other non-U.S. persons raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them. Prospective unitholders who are tax-exempt entities or non-U.S. persons should consult their tax advisor before investing in our units. Employee benefit plans and most other tax-exempt organizations, including IRAs and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income will be unrelated business taxable income and will be taxable to a tax-exempt unitholder.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of their ownership of our units. Consequently, they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. Moreover, under rules applicable to publicly traded partnerships, distributions to non-U.S. unitholders are subject to withholding at the highest applicable effective tax rate. Each non-U.S. unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8BEN or applicable substitute form in order to obtain credit for these withholding taxes. A change in applicable law may require us to change these procedures.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which is effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Code.

A foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized from the sale or disposition of that unit to the extent the gain is effectively connected with a U.S. trade or business of the foreign unitholder. Under a ruling published by the IRS, interpreting the scope of “effectively connected income,” a foreign unitholder would be considered to be engaged in a trade or business in the U.S. by virtue of the U.S. activities of the partnership, and part or all of that unitholder’s gain would be effectively connected with that unitholder’s indirect U.S. trade or business. Moreover, under the Foreign Investment in Real Property Tax Act, a foreign unitholder generally will be subject to federal income tax upon the sale or disposition of a unit if (i) it owned (directly or constructively applying certain attribution rules) more than 5% of our units at any time during the five-year period ending on the date of such disposition and (ii) 50% or more of the fair market value of all of our assets consisted of U.S. real property interests at any time during the shorter of the period during which such unitholder held the units or the 5-year period ending on the date of disposition. We believe that currently less than 50% of our assets consist of U.S. real property interests. However, because this determination depends on the fair market value of our U.S. real property relative to the fair market value of our other business assets, there can be no assurance that our current analysis is correct or that the percentage of our assets consisting of U.S. real property interests will not equal or exceed 50% in the future.

Administrative Matters

Information Returns and Audit Procedures

We intend to furnish to each unitholder, within 90 days after the close of each taxable year, specific tax information, including a Schedule K-1, which describes its share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine each unitholder’s share of income, gain, loss and deduction. We cannot assure our unitholders that those positions will yield a result that conforms to the requirements of the Code, Treasury Regulations or administrative interpretations of the IRS.

 

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Neither we, nor Vinson & Elkins L.L.P. can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible, and such a contention could negatively affect the value of the units. The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of its own return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to its returns.

Partnerships generally are treated as entities separate from their owners for purposes of federal income tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Code requires that one partner be designated as the “Tax Matters Partner” for these purposes, and our partnership agreement designates our general partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of common unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the common unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate in that action.

A unitholder must file a statement with the IRS identifying the treatment of any item on its federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting

Persons who hold an interest in us as a nominee for another person are required to furnish to us:

 

(1)

the name, address and taxpayer identification number of the beneficial owner and the nominee;

 

(2)

a statement regarding whether the beneficial owner is:

 

(a)

a non-U.S. person;

 

(b)

a non-U.S. government, an international organization or any wholly owned agency or instrumentality of either of the foregoing; or

 

(c)

a tax-exempt entity;

 

(3)

the amount and description of units held, acquired or transferred for the beneficial owner; and

 

(4)

specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are U.S. persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $100 per failure, up to a maximum of $1.5 million per calendar year, is imposed by the Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

 

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Accuracy-Related Penalties

An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for the underpayment of that portion and that the taxpayer acted in good faith regarding the underpayment of that portion.

For individuals, a substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000. The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:

 

(1)

for which there is, or was, “substantial authority;” or

 

(2)

as to which there is a reasonable basis and the relevant facts of that position are disclosed on the return.

If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the relevant facts on our returns. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns and to take other actions as may be appropriate to permit unitholders to avoid liability for this penalty. More stringent rules apply to “tax shelters,” which we do not believe includes us, or any of our investments, plans or arrangements.

A substantial valuation misstatement exists if (a) the value of any property, or the tax basis of any property, claimed on a tax return is 150% or more of the amount determined to be the correct amount of the valuation or tax basis, (b) the price for any property or services (or for the use of property) claimed on any such return with respect to any transaction between persons described in Code Section 482 is 200% or more (or 50% or less) of the amount determined under Section 482 to be the correct amount of such price, or (c) the net Code Section 482 transfer price adjustment for the taxable year exceeds the lesser of $5 million or 10% of the taxpayer’s gross receipts. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for a corporation other than an S Corporation or a personal holding company). The penalty is increased to 40% in the event of a gross valuation misstatement. We do not anticipate making any valuation misstatements.

In addition, the 20% accuracy-related penalty also applies to any portion of an underpayment of tax that is attributable to transactions lacking economic substance. To the extent that such transactions are not disclosed, the penalty imposed is increased to 40%. Additionally, there is no reasonable cause defense to the imposition of this penalty to such transactions.

Reportable Transactions

If we were to engage in a “reportable transaction,” we (and possibly our unitholders and others) would be required to make a detailed disclosure of the transaction to the IRS. A transaction may be a reportable transaction based upon any of several factors, including the fact that it is a type of tax avoidance transaction publicly identified by the IRS as a “listed transaction” or that it produces certain kinds of losses for partnerships, individuals, S corporations, and trusts in excess of $2 million in any single tax year, or $4 million in any combination of six successive tax years. Our participation in a reportable transaction could increase the likelihood that our federal income tax information return (and possibly our unitholders’ tax return) would be audited by the IRS. Please see “—Administrative Matters—Information Returns and Audit Procedures.”

 

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Moreover, if we were to participate in a reportable transaction with a significant purpose to avoid or evade tax, or in any listed transaction, our unitholders may be subject to the following provisions of the American Jobs Creation Act of 2004:

 

•

accuracy-related penalties with a broader scope. significantly narrower exceptions, and potentially greater amounts than described above at “—Administrative Matters—Accuracy-Related Penalties”;

 

•

for those persons otherwise entitled to deduct interest on federal tax deficiencies, nondeductibility of interest on any resulting tax liability; and

 

•

in the case of a listed transaction, an extended statute of limitations.

We do not expect to engage in any “reportable transactions.”

State, Local and Other Tax Considerations

In addition to federal income taxes, unitholders will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangibles taxes that may be imposed by the various jurisdictions in which we conduct business or own property or in which the unitholder is a resident. We currently conduct business or own property in several states, each of which imposes an income tax on corporations and a personal income tax. Moreover, we may also own property or do business in other states in the future that impose income or similar taxes on nonresident individuals. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on its investment in us.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of its investment in us. Vinson & Elkins L.L.P. has not rendered an opinion on the state, local, or non-U.S. tax consequences of an investment in us. We strongly recommend that each prospective unitholder consult, and depend on, its own tax counsel or other advisor with regard to those matters. It is the responsibility of each unitholder to file all tax returns that may be required of it.

Investment in Northern Tier Energy LP by Employee Benefit Plans

An investment in us by an employee benefit plan is subject to additional considerations because the investments of these plans are subject to the fiduciary responsibility and prohibited transaction provisions of ERISA and restrictions imposed by Section 4975 of the Code. For these purposes the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to:

 

•

whether the investment is prudent under Section 404(a)(1)(B) of ERISA;

 

•

whether in making the investment, that plan will satisfy the diversification requirements of Section 404(a)(1)(C) of ERISA; and

 

•

whether the investment will result in recognition of unrelated business taxable income by the plan and, if so, the potential after-tax investment return.

The person with investment discretion with respect to the assets of an employee benefit plan, often called a fiduciary, should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for the plan.

Section 406 of ERISA and Section 4975 of the Code prohibit employee benefit plans, and also IRAs that are not considered part of an employee benefit plan, from engaging in specified transactions involving “plan assets”

 

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with parties that are “parties in interest” under ERISA or “disqualified persons” under the Code with respect to the plan.

In addition to considering whether the purchase of common units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether the plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under some circumstances. Under these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things:

 

(1)

the equity interests acquired by employee benefit plans are publicly offered securities—i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered under some provisions of the federal securities laws;

 

(2)

the entity is an “operating company,” meaning it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority-owned subsidiary or subsidiaries; or

 

(3)

there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest is held by the employee benefit plans referred to above and IRAs.

Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (1) and (2) above.

Plan fiduciaries contemplating a purchase of common units are encouraged to consult with their own counsel regarding the consequences under ERISA and the Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

 

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Underwriting

We, the selling unitholder and the underwriters named below have entered into an underwriting agreement with respect to the common units being offered. Subject to certain conditions, each underwriter has severally agreed to purchase the number of common units indicated in the following table. Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Goldman, Sachs & Co., Citigroup Global Markets Inc. and UBS Securities LLC are the representatives of the underwriters.

 

Underwriters		Number of Common Units
Barclays Capital Inc.
Merrill Lynch, Pierce, Fenner & Smith                       Incorporated
Goldman, Sachs & Co.
Citigroup Global Markets Inc.
UBS Securities LLC
Credit Suisse Securities (USA) LLC
Deutsche Bank Securities Inc.
J.P. Morgan Securities LLC
Macquarie Capital (USA) Inc.
Total			9,000,000

The underwriters are committed to take and pay for all of the common units being offered, if any are taken, other than the units covered by the option described below unless and until this option is exercised.

The underwriters have an option to buy up to an additional 1,350,000 common units from the selling unitholder to cover sales by the underwriters of a greater number of units than the total number set forth in the table above. They may exercise that option for 30 days. If any common units are purchased pursuant to this option, the underwriters will severally purchase common units in approximately the same proportion as set forth in the table above.

The following table shows the per unit and total underwriting discount to be paid to the underwriters by the selling unitholder. Such amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units.

Paid by the Selling Unitholder

 

		No Exercise				Full Exercise
Per Unit		$				$
Total		$				$

Common units sold by the underwriters to the public will initially be offered at the public offering price set forth on the cover of this prospectus. Any units sold by the underwriters to securities dealers may be sold at a discount of up to $         per unit from the initial offering price. After the initial offering of the units, the representatives may change the offering price and the other selling terms. The offering of the common units by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

We, our general partner, the executive officers and directors of our general partner and the selling unitholder have agreed with the underwriters, subject to certain exceptions, including an exception for sales of common units to satisfy tax withholding and other obligations in connection with the equity awards issued under our LTIP, not to dispose of or hedge any of their common units or securities convertible into or exchangeable for

 

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common units during the period from the date of this prospectus continuing through the date 90 days after the date of this prospectus, except with the prior written consent of the representatives. This agreement does not apply to any existing employee benefit plans. See “Common Units Eligible for Future Sale” for a discussion of certain transfer restrictions.

The 90-day restricted period described in the preceding paragraph will be automatically extended if: (1) during the last 17 days of the 90-day restricted period we issue an earnings release or announce material news or a material event; or (2) prior to the expiration of the 90-day restricted period, we announce that we will release earnings results during the 15-day period following the last day of the 90-day period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release of the announcement of the material news or material event.

Our common units are listed on the NYSE under the symbol “NTI.”

In connection with the offering, the underwriters may purchase and sell common units in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Short sales involve the sale by the underwriters of a greater number of units than they are required to purchase in the offering, and a short position represents the amount of such sales that have not been covered by subsequent purchases. A “covered short position” is a short position that is not greater than the amount of additional units for which the underwriters’ option described above may be exercised. The underwriters may cover any covered short position by either exercising their option to purchase additional common units or purchasing units in the open market. In determining the source of units to cover the covered short position, the underwriters will consider, among other things, the price of units available for purchase in the open market as compared to the price at which they may purchase additional units pursuant to the option described above. “Naked” short sales are any short sales that create a short position greater than the amount of additional units for which the option described above may be exercised. The underwriters must cover any such naked short position by purchasing units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering. Stabilizing transactions consist of various bids for or purchases of common units made by the underwriters in the open market prior to the completion of the offering.

The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because a representative has repurchased units sold by or for the account of such underwriter in stabilizing or short covering transactions.

Purchases to cover a short position and stabilizing transactions, as well as other purchases by the underwriters for their own accounts, may have the effect of preventing or retarding a decline in the market price of our common units, and together with the imposition of the penalty bid, may stabilize, maintain or otherwise affect the market price of the common units. As a result, the price of the common units may be higher than the price that otherwise might exist in the open market. The underwriters are not required to engage in these activities and may end any of these activities at any time. These transactions may be effected on the NYSE, in the over-the-counter market or otherwise.

Electronic Distribution

A prospectus in electronic format may be made available on the Internet sites or through other online services maintained by one or more of the underwriters and/or selling group members participating in this offering, or by their affiliates. In those cases, prospective investors may view offering terms online and, depending upon the particular underwriter or selling group member, prospective investors may be allowed to place orders online. The underwriters may agree with the selling unitholder to allocate a specific number of shares for sale to online brokerage account holders. Any such allocation for online distributions will be made by the representatives on the same basis as other allocations.

 

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Other than the prospectus in electronic format, the information on any underwriter’s or selling group member’s web site and any information contained in any other web site maintained by an underwriter or selling group member is not part of the prospectus or the registration statement of which this prospectus forms a part, has not been approved and/or endorsed by us, the selling unitholder or any underwriter or selling group member in its capacity as underwriter or selling group member and should not be relied upon by investors.

The underwriters do not expect sales to discretionary accounts to exceed 5% of the total number of units offered.

We estimate that our share of the total expenses of the offering, excluding the underwriting discount, will be approximately $1.2 million.

We, our general partner and the selling unitholder have agreed to indemnify the several underwriters against certain liabilities, including liabilities under the Securities Act.

The underwriters and their respective affiliates are full service financial institutions engaged in various activities, which may include sales and trading, commercial and investment banking, advisory, investment management, investment research, principal investment, hedging, market making, brokerage and other financial and non-financial activities and services. Certain of the underwriters and their respective affiliates have provided, and may in the future provide, a variety of these services to us and the selling unitholder and to persons and entities with relationships with us and the selling unitholder, for which they received or will receive customary fees and expenses. Each of Goldman, Sachs & Co., Deutsche Bank Securities Inc., J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Macquarie Capital (USA) Inc. and UBS Securities LLC were underwriters in the initial public offering of our common units and received customary fees in conjunction with that transaction. Regarding our ABL Facility, J.P. Morgan Chase Bank, N.A. (an affiliate of J.P. Morgan Securities LLC) is the administrative agent and collateral agent, Bank of America, N.A. (an affiliate of Merrill Lynch, Pierce, Fenner & Smith Incorporated) is syndication agent, Macquarie Capital (USA) Inc. is a co-documentation agent, and each of J.P. Morgan Chase Bank, N.A., Bank Of America, N.A., Deutsche Bank Trust Company Americas (an affiliate of Deutsche Bank Securities Inc.), UBS Loan Finance LLC (an affiliate of UBS Securities LLC), Barclays Bank PLC (an affiliate of Barclays Capital Inc.), MIHI LLC (an affiliate of Macquarie Capital (USA) Inc.), Goldman Sachs Bank USA (an affiliate of Goldman, Sachs & Co.) and Credit Suisse AG, Cayman Islands Branch (an affiliate of Credit Suisse Securities (USA) LLC) are lenders. J. Aron & Company (an affiliate of Goldman, Sachs & Co.) and Macquarie Bank Limited (an affiliate of Macquarie Capital (USA) Inc.) are counterparties to our Hedge Agreements. Each of them received customary fees in conjunction with that transaction. Goldman, Sachs & Co., Deutsche Bank Securities Inc., J.P. Morgan Securities LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Barclays Capital Inc., Credit Suisse Securities (USA) LLC, Macquarie Capital (USA) Inc. and UBS Securities LLC were each initial purchasers in our senior secured notes offering described in “Summary—Recent Developments—2020 Notes Offering and Tender Offer”. Each of them received customary fees in conjunction with that transaction. Goldman, Sachs & Co. served as the dealer manager and solicitation agent for the tender offer for our senior secured notes described in “Summary—Recent Developments—2020 Notes Offering and Tender Offer”.

In the ordinary course of their various business activities, the underwriters and their respective affiliates, officers, directors and employees may purchase, sell or hold a broad array of investments and actively trade securities, derivatives, loans, commodities, currencies, credit default swaps and other financial instruments for their own account and for the accounts of their customers, and such investment and trading activities may involve or relate to assets, securities and/or instruments of us and the selling unitholder (directly, as collateral securing other obligations or otherwise) and/or persons and entities with relationships to us and the selling unitholder. The underwriters and their respective affiliates may also communicate independent investment recommendations, market color or trading ideas and/or publish or express independent research views in respect of such assets,

 

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securities or instruments and may at any time hold, or recommend to clients that they should acquire, long and/or short positions in such assets, securities and instruments.

Because the Financial Industry Regulatory Authority, or FINRA, views our common units as interests in a direct participation program, the offering is being made in compliance with Rule 2310 of the FINRA Rules. Investor suitability with respect to the common units will be judged similarly to the suitability with respect to other securities that are listed for trading on a national securities exchange.

Notice to Prospective Investors in the EEA

In relation to each member state of the European Economic Area that has implemented the Prospectus Directive (each, a relevant member state), other than Germany, with effect from and including the date on which the Prospectus Directive is implemented in that relevant member state (the relevant implementation date), an offer of securities described in this prospectus may not be made to the public in that relevant member state other than:

 

•

to any legal entity which is a qualified investor as defined in the Prospectus Directive;

 

•

to fewer than 100 or, if the relevant member state has implemented the relevant provision of the 2010 PD Amending Directive, 150, natural or legal persons (other than qualified investors as defined in the Prospectus Directive), as permitted under the Prospectus Directive, subject to obtaining the prior consent of the relevant Dealer or Dealers nominated by the Issuer for any such offer; or

 

•

in any other circumstances falling within Article 3(2) of the Prospectus Directive;

provided that no such offer of securities shall require us or any underwriter to publish a prospectus pursuant to Article 3 of the Prospectus Directive.

For purposes of this provision, the expression an “offer of securities to the public” in any relevant member state means the communication in any form and by any means of sufficient information on the terms of the offer and the securities to be offered so as to enable an investor to decide to purchase or subscribe for the securities, as the expression may be varied in that member state by any measure implementing the Prospectus Directive in that member state, and the expression “Prospectus Directive” means Directive 2003/71/EC (and amendments thereto, including the 2010 PD Amending Directive, to the extent implemented in the relevant member state), and includes any relevant implementing measure in each relevant member state. The expression “2010 PD Amending Directive” means Directive 2010/73/EU.

The selling unitholder has not authorized and does not authorize the making of any offer of securities through any financial intermediary on their behalf, other than offers made by the underwriters with a view to the final placement of the securities as contemplated in this prospectus. Accordingly, no purchaser of the securities, other than the underwriters, is authorized to make any further offer of the securities on behalf of the selling unitholder or the underwriters.

Notice to Prospective Investors in the United Kingdom

Our partnership may constitute a “collective investment scheme” as defined by section 235 of the Financial Services and Markets Act 2000 (FSMA) that is not a “recognised collective investment scheme” for the purposes of FSMA (CIS) and that has not been authorised or otherwise approved. As an unregulated scheme, it cannot be marketed in the United Kingdom to the general public, except in accordance with FSMA. This prospectus is only being distributed in the United Kingdom to, and is only directed at:

 

(1)

if our partnership is a CIS and is marketed by a person who is an authorised person under FSMA, (a) investment professionals falling within Article 14(5) of the Financial Services and Markets Act 2000 (Promotion of Collective Investment Schemes) (Exemptions) Order 2001, as amended (the CIS

 

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Promotion Order) or (b) high net worth companies and other persons falling within Article 22(2)(a) to (d) of the CIS Promotion Order; or

 

(2)

otherwise, if marketed by a person who is not an authorised person under FSMA, (a) persons who fall within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005, as amended (the Financial Promotion Order) or (b) Article 49(2)(a) to (d) of the Financial Promotion Order; and

 

(3)

in both cases (1) and (2) to any other person to whom it may otherwise lawfully be made (all such persons together being referred to as “relevant persons”).

Our partnership’s common units are only available to, and any invitation, offer or agreement to subscribe, purchase or otherwise acquire such common units will be engaged in only with, relevant persons. Any person who is not a relevant person should not act or rely on this document or any of its contents.

An invitation or inducement to engage in investment activity (within the meaning of Section 21 of FSMA) in connection with the issue or sale of any common units which are the subject of the offering contemplated by this prospectus will only be communicated or caused to be communicated in circumstances in which Section 21(1) of FSMA does not apply to our partnership.

Notice to Prospective Investors in Switzerland

This prospectus is being communicated in Switzerland to a small number of selected investors only. Each copy of this prospectus is addressed to a specifically named recipient and may not be copied, reproduced, distributed or passed on to third parties. Our common units are not being offered to the public in Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be distributed in connection with any such public offering. We have not been registered with the Swiss Financial Market Supervisory Authority FINMA as a foreign collective investment scheme pursuant to Article 120 of the Collective Investment Schemes Act of June 23, 2006 (CISA). Accordingly, our common units may not be offered to the public in or from Switzerland, and neither this prospectus, nor any other offering materials relating to our common units may be made available through a public offering in or from Switzerland. Our common units may only be offered and this prospectus may only be distributed in or from Switzerland by way of private placement exclusively to qualified investors (as this term is defined in the CISA and its implementing ordinance).

Notice to Prospective Investors in Germany

This document has not been prepared in accordance with the requirements for a securities or sales prospectus under the German Securities Prospectus Act (Wertpapierprospektgesetz), the German Capital Investment Act (Vermôgensanlagengesetz), or the German Investment Act (Investmentgesetz). Neither the German Federal Financial Services Supervisory Authority (Bundesanstalt für Finanzdienstleistungsaufsicht – BaFin) nor any other German authority has been notified of the intention to distribute our common units in Germany. Consequently, our common units may not be distributed in Germany by way of public offering, public advertisement or in any similar manner and this document and any other document relating to the offering, as well as information or statements contained therein, may not be supplied to the public in Germany or used in connection with any offer for subscription of our common units to the public in Germany or any other means of public marketing. Our common units are being offered and sold in Germany only to qualified investors which are referred to in Section 3, paragraph 2 no. 1, in connection with Section 2, no. 6, of the German Securities Prospectus Act, Section 2 no. 4 of the German Capital Investment Act, and in Section 2 paragraph 11 sentence 2 no. 1 of the German Investment Act. This document is strictly for use of the person who has received it. It may not be forwarded to other persons or published in Germany.

The offering does not constitute an offer to sell or the solicitation of an offer to buy our common units in any circumstances in which such offer or solicitation is unlawful.

 

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Notice to Prospective Investors in the Netherlands

Our common units may not be offered or sold, directly or indirectly, in the Netherlands, other than to qualified investors (gekwalificeerde beleggers) within the meaning of Article 1:1 of the Dutch Financial Supervision Act (Wet op het financieel toezicht).

 

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Legal Matters

The validity of the common units offered by this prospectus and certain other legal matters will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. The underwriters are being represented by Baker Botts L.L.P., Houston, Texas.

Experts

The consolidated financial statements as of December 31, 2011 and 2010 and for the year ended December 31, 2011 and for the period from June 23, 2010 (date of inception) to December 31, 2010 of Northern Tier Energy LLC, Successor, included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

The combined financial statements for the eleven months ended November 30, 2010 and for the year ended December 31, 2009 of the St. Paul Park Refinery & Retail Marketing Business, a component of Marathon Oil Corporation, Predecessor, included in this prospectus have been so included in reliance on the report of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.

Where You Can Find More Information

We have filed with the SEC a registration statement on Form S-1 (including the exhibits, schedules and amendments thereto) under the Securities Act, with respect to our common units offered hereby. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules thereto. For further information with respect to us and the common units offered hereby, we refer you to the registration statement and the exhibits and schedules filed therewith. Statements contained in this prospectus as to the contents of any contract, agreement or any other document are summaries of the material terms of this contract, agreement or other document and are not necessarily complete. With respect to each of these contracts, agreements or other documents filed as an exhibit to the registration statement, reference is made to the exhibits for a more complete description of the matter involved. A copy of the registration statement, and the exhibits and schedules thereto, may be inspected without charge at the public reference facilities maintained by the SEC at 100 F Street NE, Washington, D.C. 20549. Copies of these materials may be obtained, upon payment of a duplicating fee, from the Public Reference Section of the SEC at 100 F Street NE, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public reference facility. The SEC maintains a website that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC. The address of the SEC’s website is www.sec.gov.

We also make available free of charge on our internet website at www.ntenergy.com our annual reports on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K and any amendments to those reports, as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information contained on our website is not incorporated by reference into this prospectus and you should not consider information contained on our website as part of this prospectus.

 

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Index to Financial Statements

 

Northern Tier Energy LP (Successor)
Consolidated Financial Statements for the Nine Months Ended September 30, 2012 and 2011
Consolidated Balance Sheet (Unaudited)			F-1
Consolidated Statements of Operations and Comprehensive Income (Loss) (Unaudited)			F-2
Consolidated Statements of Cash Flows (Unaudited)			F-3
Notes to Consolidated Financial Statements (Unaudited)			F-4
Northern Tier Energy LLC (Successor) and St. Paul Park Refinery and Retail Marketing Business (Predecessor)
Consolidated Financial Statements for the Year Ended December 31, 2011 and from June 23, 2010 (inception date) to December 31, 2010 and Combined Financial Statements for the Eleven Months Ended November 30, 2010 and the Year Ended December 31, 2009
Report of Independent Registered Accounting Firm (Successor statements)			F-24
Report of Independent Registered Accounting Firm (Predecessor statements)			F-25
Consolidated and Combined Balance Sheets			F-26
Consolidated and Combined Statements of Income			F-27
Consolidated and Combined Statements of Cash Flows			F-28
Consolidated and Combined Statements of Member’s Interest and Net Investment Interest			F-29
Notes to Consolidated and Combined Financial Statements			F-30

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

NORTHERN TIER ENERGY LP

CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)

 

		September 30,				December 31,
		2012				2011
		(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	323.5			$	123.5
Receivables, less allowance for doubtful accounts			134.3				81.9
Inventories			156.2				154.1
Other current assets			28.8				65.5
Total current assets			642.8				425.0
NON-CURRENT ASSETS
Equity method investment			88.3				89.9
Property, plant and equipment, net			376.7				391.2
Intangible assets			35.4				35.4
Other assets			34.2				57.3
Total Assets		$	1,177.4			$	998.8
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable		$	185.7			$	207.4
Accrued liabilities			87.3				30.3
Derivative liability			71.2				109.9
Total current liabilities			344.2				347.6
NON-CURRENT LIABILITIES
Long-term debt			261.0				290.0
Lease financing obligation			7.5				11.9
Derivative liability			8.0				—
Other liabilities			18.8				37.1
Total liabilities			639.5				686.6
Commitments and contingencies
EQUITY
Comprehensive loss			(0.4	)			(0.4	)
Member’s interest			—				312.6
Partners’ capital:
Common unitholders (73,532,000 units issued and outstanding at September 30, 2012)			430.7				—
PIK common unitholders (18,383,000 units issued and outstanding at September 30, 2012)			107.6				—
Total equity			537.9				312.2
Total Liabilities and Equity		$	1,177.4			$	998.8

The accompanying notes are an integral part of these consolidated financial statements.

 

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NORTHERN TIER ENERGY LP

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(in millions, except unit and per unit data)

(unaudited)

 

		Three Months Ended								Nine Months Ended
		September 30,				September 30,				September 30,				September 30,
		2012				2011				2012				2011
REVENUE (a)		$	1,263.5			$	1,159.5			$	3,417.8			$	3,192.0
COSTS, EXPENSES AND OTHER
Cost of sales (a)			929.2				890.2				2,594.0				2,578.2
Direct operating expenses			66.9				67.3				189.1				192.5
Turnaround and related expenses			2.1				—				17.1				22.5
Depreciation and amortization			8.3				7.4				24.6				22.3
Selling, general and administrative			22.0				24.4				67.1				63.3
Formation costs			—				1.7				1.0				6.1
Contingent consideration loss (income)			38.5				3.4				104.3				(37.6	)
Other income, net			(2.9	)			(0.6	)			(6.2	)			(2.4	)
OPERATING INCOME			199.4				165.7				426.8				347.1
Realized losses from derivative activities			(44.7	)			(112.5	)			(165.0	)			(246.4	)
Loss on early extinguishment of derivatives			—				—				(136.8	)			—
Unrealized (losses) gains from derivative activities			(70.3	)			(40.6	)			32.6				(334.5	)
Interest expense, net			(15.6	)			(10.4	)			(36.7	)			(30.6	)
INCOME (LOSS) BEFORE INCOME TAXES			68.8				2.2				120.9				(264.4	)
Income tax provision			(7.7	)			—				(7.8	)			—
NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)		$	61.1			$	2.2			$	113.1			$	(264.4	)
EARNINGS PER UNIT INFORMATION:
Allocation of net income used for earnings per unit calculation:
Net Income		$	61.1							$	113.1
Net Income prior to initial public offering on July 31, 2012			(18.7	)							(70.7	)
Net Income subsequent to initial public offering on July 31, 2012		$	42.4							$	42.4
Earnings per common and PIK common unit, basic and diluted		$	0.46							$	0.46
Weighted average number of units outstanding:
Common and PIK common units, basic and diluted			91,915,000								91,915,000
SUPPLEMENTAL INFORMATION:
(a) Excise taxes included in revenue and cost of sales		$	78.2			$	64.9			$	215.0			$	181.5

The accompanying notes are an integral part of these consolidated financial statements.

 

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NORTHERN TIER ENERGY LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions, unaudited)

 

		Nine Months Ended
		September 30,				September 30,
Increase (decrease) in cash		2012				2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)		$	113.1			$	(264.4	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization			24.6				22.3
Non-cash interest expense			8.1				2.9
Equity-based compensation expense			1.4				1.1
Deferred income taxes			7.7				—
Contingent consideration loss (income)			104.3				(37.6	)
Unrealized (gains) losses from derivative activities			(32.6	)			334.5
Loss on early extinguishment of derivatives			136.8				—
Changes in assets and liabilities, net:
Accounts receivable			(52.7	)			(3.1	)
Inventories			(2.1	)			3.6
Other current assets			9.2				15.9
Accounts payable and accrued expenses			(136.4	)			119.2
Other, net			(6.6	)			0.5
Net cash provided by operating activities			174.8				194.9
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures			(13.3	)			(27.4	)
Acquisition, net of cash acquired			—				(112.8	)
Return of capital from investments			1.3				1.7
Net cash used in investing activities			(12.0	)			(138.5	)
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments of senior secured notes			(29.0	)			—
Borrowings from revolving credit arrangement			—				55.0
Repayments of revolving credit arrangement			—				(55.0	)
Proceeds from IPO, net of direct costs of issuance			230.4				—
Equity distributions			(164.2	)			(2.5	)
Net cash provided by (used in) financing activities			37.2				(2.5	)
CASH AND CASH EQUIVALENTS
Change in cash and cash equivalents			200.0				53.9
Cash and cash equivalents at beginning of period			123.5				72.8
Cash and cash equivalents at end of period		$	323.5			$	126.7

 

The accompanying notes are an integral part of these consolidated financial statements.

 

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NORTHERN TIER ENERGY LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

1.	DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Description of the Business

Northern Tier Energy LP (“NTE LP”) is an independent downstream energy company with refining, retail and pipeline operations that serve the Petroleum Administration for Defense District II (“PADD II”) region of the United States. NTE LP holds 100% of the membership interest in Northern Tier Energy LLC (“NTE LLC”) and was organized in such a way as to be treated as a master limited partnership (“MLP”) for tax purposes. NTE LLC was a wholly-owned subsidiary of Northern Tier Holdings LLC (“NT Holdings”) until July 31, 2012. On July 31, 2012, NT Holdings contributed all of its membership interests in NTE LLC to NTE LP in connection with the closing of the underwritten initial public offering (“IPO”) of NTE LP (see Note 3). NT Holdings is a wholly-owned subsidiary of Northern Tier Investors LLC (“NT Investors”). NT Investors, NT Holdings and NTE LLC were formed by ACON Refining Partners L.L.C. and TPG Refining L.P. and certain members of management (collectively, the “Investors”) during 2010. The St. Paul Park Refinery and Retail Marketing Business were formerly owned and operated by subsidiaries of Marathon Oil Corporation (“Marathon Oil”). These subsidiaries, Marathon Petroleum Company, LP (“MPC LP”), Speedway LLC (“Speedway”) and MPL Investments LLC, are together referred to as “MPC” or “Marathon” and are now subsidiaries of Marathon Petroleum Corporation (“Marathon Petroleum”). Marathon Petroleum was a wholly-owned subsidiary of Marathon Oil until June 30, 2011. Effective December 1, 2010, NTE LLC acquired the business from Marathon for approximately $608 million (the “Marathon Acquisition,” see Note 5).

NTE LP and NTE LLC (collectively, the “Company”) includes the operations of St. Paul Park Refining Co. LLC (“SPPR”) and Northern Tier Retail Holdings LLC (“NTRH”). NTRH is the parent company of Northern Tier Retail LLC (“NTR”) and Northern Tier Bakery LLC (“NTB”). NTR is the parent company of SuperAmerica Franchising LLC (“SAF”). In connection with the IPO of NTE LP (see Note 3), NTE LLC contributed all of its membership interests in NTR, NTB and SAF to NTRH in exchange for all of the membership interests in NTRH. Effective August 1, 2012, NTRH elected to be treated as a corporation for income tax purposes in order to preserve the MLP tax status of NTE LP. SPPR has a 17% interest in MPL Investments Inc. (“MPLI”) and a 17% interest in Minnesota Pipe Line Company, LLC (“MPL”). MPLI owns 100% of the preferred interest in MPL which owns and operates a 455,000 barrel per day (“bpd”) crude oil pipeline in Minnesota (see Note 2).

SPPR, which is located in St. Paul Park, Minnesota, has total crude oil throughput capacity of 84,500 barrels per stream day. Refining operations include crude fractionation, catalytic cracking, hydrotreating, reforming, alkylation, sulfur recovery and a hydrogen plant. The refinery processes predominately North Dakota and Canadian crude oils into products such as gasoline, diesel, jet fuel, kerosene, asphalt, propane, propylene and sulfur. The refined products are sold to markets primarily located in the Upper Great Plains of the United States.

As of September 30, 2012, NTR operates 166 convenience stores under the SuperAmerica brand and SAF supports 68 franchised stores which also utilize the SuperAmerica brand. These 234 SuperAmerica stores are primarily located in Minnesota and Wisconsin and sell gasoline, merchandise, and in some locations, diesel fuel. There is a wide range of merchandise sold at the stores including prepared foods, beverages and non-food items. The merchandise sold includes a significant number of proprietary items.

NTB prepares and distributes food products under the SuperMom’s Bakery brand primarily to SuperAmerica branded retail outlets.

 

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Basis of Presentation

NTE LP conducts all of its operations through NTE LLC and its subsidiaries. NTE LP’s consolidated financial statements are substantially identical to NTE LLC’s consolidated financial statements, with the following exceptions:

 

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Earnings per unit (disclosed on NTE LP’s consolidated statement of operations);

 

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Partners’ capital and distributions (see Note 13); and

 

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Formation cost expense of $1.0 million recorded for NTE LP during the second quarter of 2012.

The accompanying unaudited consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation of the results for the periods reported have been included. Operating results for the nine months ended September 30, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012, or for any other period.

The consolidated balance sheet at December 31, 2011 has been derived from the audited financial statements of NTE LLC at that date but does not include all of the information and footnotes required by GAAP for complete financial statements. The accompanying consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto in the final prospectus of NTE LP, dated July 25, 2012, included in NTE LP’s Registration Statement on Form S-1 (File No. 333-178457).

 

2.	SUMMARY OF PRINCIPAL ACCOUNTING POLICIES

Principles of Consolidation and Combination

NTE LP is a Delaware limited partnership that was established as Northern Tier Energy, Inc. on October 24, 2011 and was subsequently converted into NTE LP as of June 4, 2012. On July 31, 2012, NTE LP closed its IPO whereby it sold 18,687,500 limited partnership units to the public. In connection with the closing of the IPO, NT Holdings contributed all of its membership interests in NTE LLC to NTE LP in exchange for 54,844,500 common units and 18,383,000 PIK units of NTE LP (see Note 3). Upon the closing of the IPO, the consolidated historical financial statements of NTE LLC became the historical financial statements of NTE LP. NTE LP consolidates all accounts of NTE LLC and its subsidiaries. NTE LLC consolidates all accounts of SPPR and NTRH. All significant intercompany accounts have been eliminated in these consolidated financial statements.

NTE LLC was formed on June 23, 2010. The Marathon Acquisition agreement was entered into on October 6, 2010 and closed on December 1, 2010. Accordingly, the accompanying financial statements present the consolidated accounts of such acquired businesses.

The Company’s common equity interest in MPL is accounted for using the equity method of accounting in accordance with the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”) Topic 323. Equity income from MPL represents the Company’s proportionate share of net income available to common equity owners generated by MPL.

The equity method investment is assessed for impairment whenever changes in facts or circumstances indicate a loss in value has occurred. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net income. See Note 8 for further information on the Company’s equity method investment.

 

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MPLI owns all of the preferred membership units of MPL. This investment in MPLI, which provides the Company no significant influence over MPLI, is accounted for as a cost method investment. The investment in MPLI is carried at a cost of $6.9 million as of September 30, 2012 and December 31, 2011 and is included in other noncurrent assets within the consolidated balance sheets.

Use of Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from those estimates. In addition, significant estimates were used in accounting for the Marathon Acquisition under the purchase method of accounting.

Operating Segments

The Company has two reportable operating segments:

 

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Refining – operates the St. Paul Park, Minnesota refinery, terminal and related assets, and includes the Company’s interest in MPL and MPLI, and

 

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Retail – operates 166 convenience stores primarily in Minnesota and Wisconsin. The retail segment also includes the operations of NTB and SAF.

See Note 21 for further information on the Company’s operating segments.

Cash and Cash Equivalents

The Company considers all highly liquid investments with maturities of three months or less from the date of purchase to be cash equivalents.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets. Such assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset.

When property, plant and equipment depreciated on an individual basis is sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are generally recognized when the assets are classified as held for sale.

Expenditures for routine maintenance and repair costs are expensed when incurred. Refinery process units require periodic major maintenance and repairs that are commonly referred to as “turnarounds.” The required frequency of the maintenance varies by unit, but generally is every two to six years depending on the processing unit involved. Turnaround costs are expensed as incurred.

Derivative Financial Instruments

The Company is exposed to earnings and cash flow volatility based on the timing and change in refined product prices and crude oil prices. To manage these risks, the Company may use derivative instruments associated with

 

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the purchase or sale of crude oil and refined products. Crack spread option and swap contracts are used to hedge the volatility of refining margins. The Company also may use futures contracts to manage price risks associated with inventory quantities above or below target levels. The Company does not enter into derivative contracts for speculative purposes. All derivative instruments are recorded in the consolidated balance sheet at fair value and are classified depending on the maturity date of the underlying contracts. Changes in the fair value of its contracts are accounted for by marking them to market and recognizing any resulting gains or losses in its statements of income. These gains and losses are reported as operating activities within the consolidated statements of cash flows.

Excise Taxes

The Company is required by various governmental authorities, including federal and state, to collect and remit taxes on certain products. Such taxes are presented on a gross basis in revenue and cost of sales in the consolidated statements of operations. These taxes totaled $78.2 million and $64.9 million for the three months ended September 30, 2012 and 2011, respectively, and $215.0 million and $181.5 million for the nine months ended September 30, 2012 and 2011, respectively.

Income Taxes

Effective August 1, 2012, NTRH elected to be treated as a corporation for income tax purposes in order to preserve the MLP tax status of NTE LP. As such, the Company has recorded deferred tax assets and deferred tax liabilities as of the election date. Additionally, the Company recorded current period income taxes for the period from August 1, 2012 through September 30, 2012 (see Note 6) at the NTRH level. Prior to August 1, 2012, all of the Company’s income was derived from subsidiaries which were limited liability companies and were therefore pass-through entities for federal income tax purposes. As a result, the Company did not incur federal income taxes prior to this date.

Reclassification

Certain reclassifications have been made to the prior-year financial information in order to conform to the Company’s current presentation.

Accounting Developments

On January 1, 2012, the Company adopted Accounting Standard Update (“ASU”) No. 2011-05, “Comprehensive Income (ASC Topic 220): Presentation of Comprehensive Income” (“ASU 2011-05”), which amends current comprehensive income guidance. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. Also effective January 1, 2012, the Company adopted ASU 2011-12 “Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05” (“ASU 2011-12”). ASU 2011-12 defers the effectiveness for the requirement to present on the face of our financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income. The Company’s presentation of comprehensive income in this quarterly report complies with these accounting standards.

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”). ASU 2011-11 retains the existing offsetting requirements and enhances the disclosure requirements to allow investors to better compare financial statements prepared under GAAP with those prepared under IFRS. This new guidance is to be applied retrospectively. ASU 2011-11 will be effective for the

 

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Company’s quarterly and annual financial statements beginning with the first quarter 2013 reporting. The Company believes that the adoption of ASU 2011-11 will not have a material impact on its consolidated financial statements.

In July 2012, the FASB issued ASU No. 2012-02, “Intangibles – Goodwill and other” (“ASU 2012-02”). ASU 2012-02 provides guidance on annual impairment testing of indefinite-lived intangible assets. The standards update allows an entity to first assess qualitative factors to determine if it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount. If based on its qualitative assessment an entity concludes it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount, quantitative impairment testing is required. However, if an entity concludes otherwise, quantitative impairment testing is not required. The standards update is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted. The Company believes that the adoption of ASU 2012-02 will not have a material impact on its consolidated financial statements.

 

3.	INITIAL PUBLIC OFFERING OF NORTHERN TIER ENERGY LP

On July 25, 2012, NTE LP priced 16,250,000 common units in its IPO at a price of $14.00 per unit, and on July 26, 2012, NTE LP common units began trading on the New York Stock Exchange (ticker symbol: NTI). NTE LP closed its IPO of 18,687,500 common units, which included 2,437,500 common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, on July 31, 2012.

The net proceeds from the IPO of approximately $245 million, after deducting the underwriting discount, along with approximately $56 million of cash on hand were used to: (i) distribute approximately $124 million to NT Holdings, of which approximately $92 million was used to redeem Marathon’s existing preferred interest in NT Holdings and $32 million was distributed to ACON Refining Partners L.L.C., TPG Refining L.P. and entities in which certain members of the Company’s management team hold an ownership interest, (ii) pay $92 million to J. Aron & Company, an affiliate of Goldman, Sachs & Co., related to deferred payment obligations from the early extinguishment of derivatives (see Note 11), (iii) pay $40 million to Marathon, which represents the cash component of a settlement agreement NTE LLC entered into with Marathon in satisfaction of a contingent consideration arrangement that was part of the Marathon Acquisition (see Note 5), (iv) redeem $29 million of NTE LLC senior secured notes at a redemption price of 103% of the principal amount thereof, plus accrued interest, for an estimated $31 million, and (v) pay other offering costs of approximately $15 million.

In connection with the closing of the IPO the following transactions and events occurred in the third quarter of 2012:

 

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The settlement agreement with Marathon with respect to the contingent consideration arrangements that were entered into in connection with the Marathon Acquisition became effective (see Note 5);

 

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The Company’s management services agreement with ACON Refining Partners L.L.C and TPG Refining L.P. (see Note 4) was terminated;

 

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NT Holdings contributed all of its membership interests in NTE LLC to NTE LP in exchange for 54,844,500 common units and 18,383,000 PIK units;

 

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NTE LP issued 18,687,500 common units to the public, representing a 20.3% limited partner interest; and

 

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NTRH elected to be treated as a corporation for federal income tax purposes, subjecting it to corporate-level tax.

 

4.	RELATED PARTY TRANSACTIONS

The Investors, which include ACON Refining Partners L.L.C. and TPG Refining L.P., are related parties of the Company. MPL is also a related party of the Company. Subsequent to the Marathon Acquisition (see Note 5), the Company entered into a crude oil supply and logistics agreement with a third party and no longer has direct transactions with MPL.

 

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Upon completion of the Marathon Acquisition, the Company entered into a management services agreement with the Investors pursuant to which they provided the Company with ongoing management, advisory and consulting services. This management services agreement was terminated in conjunction with the IPO of NTE LP as of July 31, 2012. While this agreement was in effect, the Investors also received quarterly management fees equal to 1% of the Company’s “Adjusted EBITDA” (as defined in the agreement) for the previous quarter (subject to a minimum annual fee of $2 million), as well as reimbursements for out-of pocket expenses incurred by them in connection with providing such management services. The Company recognized management fees relating to these services of $0.3 million and $0.5 million for the three months ended September 30, 2012 and 2011, respectively, and $2.5 million and $1.5 million for the nine months ended September 30, 2012 and 2011, respectively. As a result of the NTE LP IPO, the Company was required to pay the Investors a specified success fee of $7.5 million that is a part of the IPO offering expenses discussed in Note 3.

 

5.	MARATHON ACQUISITION

As previously described in Note 1, effective December 1, 2010, the Company acquired the business from MPC for $608 million. The Marathon Acquisition was accounted for by the purchase method of accounting for business combinations. Included in this amount was the estimated fair value of earn-out payments of $54 million as of the acquisition date. Of the remainder of the $608 million purchase price, $361 million was paid in cash as of December 31, 2010 and $80 million was satisfied by issuing MPC a perpetual payment in kind preferred interest in NT Holdings. The residual purchase price of $113 million (excluding the contingent earn-out consideration) was paid during the three months ended March 31, 2011. Upon the closing of the NTE LP IPO, MPC’s perpetual payment in kind preferred interest in NT Holdings was redeemed at par plus accrued interest for a total of approximately $92 million.

The cash component of the purchase price along with acquisition related costs were financed by an approximately $180 million cash investment by the Investors and aggregate borrowings of $290 million. See Note 12 for a description of the Company’s financing arrangements.

Concurrent with the Marathon Acquisition, the following transactions also occurred:

 

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Certain Marathon assets (including real property interests and land related to 135 of the SuperAmerica convenience stores and the SuperMom’s bakery) were sold to a third party equity real estate investment trust. In connection with the closing of the Marathon Acquisition, the Company is leasing these properties from the real estate investment trust on a long-term basis.

 

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A third-party purchased substantially all of the crude oil inventory associated with operations of the refinery directly from Marathon.

The Marathon Acquisition included contingent consideration arrangements under which the Company could have received margin support payments of up to $60 million from MPC or could have paid MPC net earn-out payments of up to $125 million over the term of the arrangements, depending on the Company’s Adjusted EBITDA as defined in the arrangements. On May 4, 2012, NTE LLC entered into a settlement agreement with MPC regarding the contingent consideration. The settlement agreement was contingent upon the consummation of the IPO of NTE LP, which occurred on July 31, 2012 (see Note 3). Pursuant to this settlement agreement, MPC received $40 million of the net proceeds from the IPO of NTE LP and NT Holdings issued MPC a new $45 million perpetual payment in kind preferred interest in NT Holdings in consideration for relinquishing all claims with respect to earn-out payments under the contingent consideration agreement. This preferred interest in NT Holding will not be dilutive to NTE LP unitholders. The Company also agreed, pursuant to the settlement agreement, to relinquish all claims to margin support payments under the margin support agreement. Upon the consummation of the NTE LP IPO, the Company reversed the amounts recorded for the margin support and earn-out arrangements and recorded a liability of $85 million representing the amount of the settlement agreement. The net impact of these adjustments resulted in a charge of $38.5 million recognized during the three months ended September 30, 2012.

 

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MPC agreed to provide the Company with administrative and support services subsequent to the Marathon Acquisition pursuant to a transition services agreement, including finance and accounting, human resources, and information systems services, as well as support services generally for a period of up to eighteen months in connection with the transition from being a part of MPC’s systems and infrastructure to having its own systems and infrastructure. The transition services agreement required the Company to pay MPC for the provision of the transition services, as well as to reimburse MPC for compensation paid to MPC employees providing such transition services. In addition, under the agreement, Marathon provided support services for the operation of the refining and retail business segments, using the employees that were ultimately expected to be transitioned to the Company. The Company was obligated to reimburse MPC for the compensation paid to MPC employees providing such operations services, plus the agreed burden rates. For the three and nine months ended September 30, 2011, the Company recognized expenses of approximately $3.9 million and $14.0 million, respectively, related to administrative and support services. The Company also paid $6.7 million in December 2010 of which $1.7 million and $5.0 million was amortized during the three and nine months ended September 30, 2011, respectively. The majority of transition services were completed as of December 31, 2011 and, as such, the nine months ended September 30, 2012 include no transition service charges from MPC.

 

6.	INCOME TAXES

On July 31, 2012, NTRH was established as the parent company of NTR and NTB. NTRH elected to be taxed as a corporation for federal and state income tax purposes effective August 1, 2012. Prior to that, no provision for federal income tax was calculated on earnings of the Company or its subsidiaries as all entities were non-taxable. The Company’s policy is to recognize interest related to any underpayment of taxes as interest expense, and any penalties as administrative expenses.

On August 1, 2012, the Company recorded an $8.0 million tax charge to recognize its deferred tax asset and liability positions as of NTRH’s election to be taxed as a corporation. As of NTRH’s election date, the Company recorded a current deferred tax asset of $2.2 million, included in other current assets, and a non-current deferred tax liability of $10.2 million, included in other liabilities.

The income tax provision in the accompanying consolidated financial statements consists of the following:

 

		Three Months Ended				Nine Months Ended
(in millions)		September 30, 2012				September 30, 2012
Current tax expense		$	—			$	0.1
Deferred tax expense			7.7				7.7
Total tax expense		$	7.7			$	7.8

The Company’s effective tax rate for the three and nine months ended September 30, 2012 was 11.2% and 6.5%, respectively, as compared to the Company’s combined federal and state expected statutory tax rate of 40.4%. The Company’s effective tax rate for the three and nine months ended September 30, 2012 is lower than the statutory rate primarily due to the fact that only the retail operations of the Company are taxable entities. This lowering of the effective tax rate is partially offset by the impact of the opening deferred tax charge of $8.0 million as of the effective date of NTRH electing to be treated as a taxable entity.

As a result of the Company’s analysis, management has determined that the Company does not have any material uncertain tax positions.

 

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7.	INVENTORIES

 

		September 30,				December 31,
(in millions)		2012				2011
Crude oil and refinery feedstocks		$	3.5			$	9.1
Refined products			118.6				109.1
Merchandise			19.6				21.1
Supplies and sundry items			14.5				14.8
Total		$	156.2			$	154.1

The LIFO method accounted for 78% and 77% of total inventory value at September 30, 2012 and December 31, 2011, respectively. Current acquisition costs were estimated to exceed the LIFO inventory value by $3.4 million and $20.0 million at September 30, 2012 and December 31, 2011, respectively.

 

8.	EQUITY METHOD INVESTMENT

The Company has a 17% common equity interest in MPL. The carrying value of this equity method investment was $88.3 million and $89.9 million at September 30, 2012 and December 31, 2011, respectively.

As of September 30, 2012 and December 31, 2011, the carrying amount of the equity method investment was $6.7 million and $6.9 million higher than the underlying net assets of the investee, respectively. The Company is amortizing this difference over the remaining life of MPL’s primary asset (the fixed asset life of the pipeline).

Distributions received from MPL were $4.2 million and $2.5 million for the three months ended September 30, 2012 and 2011, respectively, and $10.0 million and $4.9 million for the nine months ended September 30, 2012 and 2011, respectively. Equity income from MPL was $2.8 million and $0.9 million for the three months ended September 30, 2012 and 2011, respectively, and $8.7 million and $3.2 million for the nine months ended September 30, 2012 and 2011, respectively.

 

9.	PROPERTY, PLANT AND EQUIPMENT

Major classes of property, plant and equipment (“PP&E”) consisted of the following:

 

		Estimated		September 30,				December 31,
(in millions)		Useful Lives		2012				2011
Land				$	8.7			$	8.7
Retail stores and equipment		2 - 22 years			46.6				50.4
Refinery and equipment		5 - 24 years			329.2				318.1
Software		5 years			16.3				14.7
Other equipment		2 - 7 years			6.5				1.9
Precious metals					10.5				10.5
Assets under construction					12.8				17.4
					430.6				421.7
Less: accumulated depreciation					53.9				30.5
Property, plant and equipment, net				$	376.7			$	391.2

PP&E included gross assets acquired under capital leases of $7.9 million and $12.5 million at September 30, 2012 and December 31, 2011, respectively, with related accumulated depreciation of $0.6 million and $1.4 million, respectively.

 

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10.	INTANGIBLE ASSETS

Intangible assets are comprised of franchise rights amounting to $19.8 million and trademarks amounting to $15.6 million at both September 30, 2012 and December 31, 2011. These assets have an indefinite life and therefore are not amortized, but rather are tested for impairment annually or sooner if events or changes in circumstances indicate that the fair value of the intangible asset has been reduced below carrying value.

 

11.	DERIVATIVES

The Company is subject to crude oil and refined product market price fluctuations caused by supply conditions, weather, economic conditions and other factors. In October 2010, at the request of the Company, MPC initiated a strategy to mitigate refining margin risk on a portion of the business’s 2011 and 2012 projected refining production. In connection with the Marathon Acquisition, derivative instruments executed pursuant to this strategy, along with all corresponding rights and obligations, were assumed by the Company. The Company also may periodically use futures contracts to manage price risks associated with inventory quantities above or below target levels.

Under the risk mitigation strategy, the Company may buy or sell an amount equal to a fixed price times a certain number of barrels, and to buy or sell in return an amount equal to a specified variable price times the same amount of barrels. Physical volumes are not exchanged and these contracts are net settled with cash. The contracts are not being accounted for as hedges for financial reporting purposes. The Company recognizes all derivative instruments as either assets or liabilities at fair value on the balance sheet and any related net gain or loss is recorded as a gain or loss in the derivative activity captions on the consolidated statements of income. Observable quoted prices for similar assets or liabilities in active markets (Level 2 as described in Note 14) are considered to determine the fair values for the purpose of marking to market the derivative instruments at each period end. At September 30, 2012 and December 31, 2011, the Company had open commodity derivative instruments consisting of crude oil futures to buy 9 million and 17 million barrels, respectively, and refined products futures and swaps to sell 9 million and 17 million barrels, respectively, primarily to mitigate the volatility of refining margins through 2012 and 2013.

For the three months ended September 30, 2012 and 2011, the Company recognized losses of $115.0 million and $153.1 million, respectively related to derivative activities. Of these total losses, $44.7 million and $112.5 million represented realized losses on settled contracts for the three months ended September 30, 2012 and 2011, respectively. Additionally, the Company recognized unrealized losses of $70.3 million and $40.6 million on open contracts for the three months ended September 30, 2012 and 2011, respectively. For the nine months ended September 30, 2012 and 2011, there were losses related to derivative activities of $269.2 million and $580.9 million, respectively. Of these total losses, $301.8 million and $246.4 million represented realized losses on settled contracts (including early extinguishments as noted below) for the nine months ended September 30, 2012 and 2011, respectively. Additionally, the Company recognized unrealized gains of $32.6 million and unrealized losses of $334.5 million on open contracts for the nine months ended September 30, 2012 and 2011, respectively.

During the first and second quarter of 2012, the Company entered into arrangements to settle or re-price a portion of its existing derivative instruments ahead of their respective expiration dates. The Company incurred $136.8 million of realized losses related to these early extinguishments. The cash payments for the early extinguishment of these derivative instruments were deferred at the time of settlement. In August 2012, the Company paid $92 million related to these early settlements with the proceeds from the IPO (see Note 3). The remainder of these losses come due beginning in September 2012 and ending in January 2014. The early extinguishments were treated as a current period loss as of the date of extinguishment. Interest accrues on the remaining deferred loss liabilities at a weighted average interest rate of 7.1%. Interest expense related to these liabilities in the three and nine months ended September 30, 2012 was $1.0 and $2.0 million, respectively. The deferred payment obligations related to these early extinguishment losses are included in the September 30, 2012 balance sheet as $35.9 million within current liabilities and $5.2 million in long-term liabilities under the accrued liabilities and other liabilities captions, respectively.

 

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The following table summarizes the fair value amounts of the Company’s outstanding derivative instruments by location on the balance sheet as of September 30, 2012 and December 31, 2011:

 

(in millions)		Balance Sheet Classification		September 30, 2012				December 31, 2011
Commodity swaps and futures		Current assets		$	0.2			$	—
Commodity swaps and futures		Noncurrent assets			1.9				—
Commodity swaps and futures		Current liabilities			(71.2	)			(109.9	)
Commodity swaps and futures		Noncurrent liabilities			(8.0	)			—
Net liability position				$	(77.1	)		$	(109.9	)

The Company is exposed to credit risk in the event of nonperformance by its counterparty on these derivative instruments. The counterparties are large financial institutions with credit ratings of at least BBB by Standard and Poor’s and A3 by Moody’s. In the event of default, the Company would potentially be subject to losses on a derivative instrument’s mark-to-market gains. The Company does not expect nonperformance on any of its derivative instruments.

The Company is not subject to any margin calls for these crack spread derivatives and the counterparty does not have the right to demand any additional collateral. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument.

 

12.

DEBT

In connection with the Marathon Acquisition, NTE LLC entered into various financing arrangements including $290.0 million of 10.50% Senior Secured Notes due December 1, 2017 (“Secured Notes”) and a $300 million secured asset-based revolving credit facility (“Initial ABL Facility”).

Secured Notes

The Secured Notes are guaranteed, jointly and severally, on a senior secured basis by all of the Company’s existing and future direct and indirect subsidiaries; however, not on a full and unconditional basis as a result of subsidiaries being able to be released as guarantors under certain customary circumstances for such arrangements. A subsidiary guarantee can be released under customary circumstances, including (a) the sale of the subsidiary, (b) the subsidiary is declared “unrestricted,” (c) the legal or covenant defeasance or satisfaction and discharge of the indenture, or (d) liquidation or dissolution of the subsidiary. Separate condensed consolidating financial information is not included as the Company does not have independent assets or operations. The Company is required to make interest payments on June 1 and December 1 of each year, which commenced on June 1, 2011. There are no scheduled principal payments required prior to the notes maturing on December 1, 2017. Borrowings bear interest at 10.50%.

At any time prior to the maturity date of the notes, the Company may, at its option, redeem all or any portion of the notes for the outstanding principal amount plus unpaid interest and a make-whole premium as defined in the indenture. If the Company experiences a change in control or makes certain asset dispositions, as defined under the indenture, the Company may be required to repurchase all or part of the notes plus unpaid interest and in certain cases pay a redemption premium. During the third quarter of 2012, the Company used a portion of the NTE LP IPO proceeds to redeem $29 million of the principal amount of the Secured Notes at a redemption price of 103% of the principal amount thereof, plus accrued interest, for approximately $31 million (see Note 3), leaving $261.0 million outstanding at September 30, 2012. Due to this call payment, the Company recognized a non-cash charge to interest expense of $1.1 million for a proportionate impairment of the capitalized origination costs from the bond issuance. Additionally, the Company recorded a $0.9 million charge to interest expense related to the 3% premium on the redemption.

 

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At issuance, the Secured Notes contained a number of covenants that, among other things, restricted the ability, subject to certain exceptions, of the Company and its subsidiaries to sell or otherwise dispose of assets, including capital stock of subsidiaries, incur additional indebtedness or issue preferred stock, repay other indebtedness, pay dividends and distributions or repurchase capital stock, create liens on assets, make investments, loans or advances, make certain acquisitions, engage in mergers or consolidations, engage in certain transactions with affiliates, change the business conducted by itself and its subsidiaries, and enter into agreements that restrict dividends from restricted subsidiaries.

Subsequent to September 30, 2012, NTE LLC completed a cash tender offer for any and all of the $261 million outstanding principal amount of the Secured Notes and, in conjunction therewith, amended the indenture governing the Secured Notes to eliminate most covenants, certain events of default and certain other provisions contained in the indenture. Additionally, NTE LLC and its subsidiary, Northern Tier Finance Corporation, completed a private offering of $275 million in aggregate principal amount of 7.125% senior secured notes due 2020 (see Note 22 – Subsequent Events).

ABL Facility

On July 17, 2012, the Company entered into an amendment of its Initial ABL Facility. The amendment to the Initial ABL Facility (the “Amended ABL Facility”), among other things, (i) changed the amount by which the aggregate principal amount of the revolving credit facility can be increased from $100 million to $150 million for a maximum aggregate principal amount of $450 million subject to borrowing base availability and lender approval, (ii) reduced the rates at which borrowings under the revolving credit facility bear interest, and (iii) extended the maturity of the revolving credit facility from December 1, 2015 to July 17, 2017.

The amendment to the revolving credit facility removed the requirement that the Company satisfy a pro forma minimum fixed charge coverage test in connection with consummating certain transactions, including the making of certain Restricted Payments and Permitted Payments (each as defined in the Amended ABL Facility). In connection with the removal of this requirement, the Amended ABL Facility also revised the springing financial covenant to provide that, if the amount available under the revolving credit facility is less than the greater of (i) 12.5% (changed from 15%) of the lesser of (x) the $300 million commitment amount and (y) the then-applicable borrowing base and (ii) $22.5 million, the Company must comply with a minimum Fixed Charge Coverage Ratio (as defined in the Amended ABL Facility) of at least 1.0 to 1.0. Other covenants that were common to both the Initial ABL Facility and the Amended ABL Facility include, but are not limited to: restrictions, subject to certain exceptions, on the ability of the Company and its subsidiaries to sell or otherwise dispose of assets, incur additional indebtedness or issue preferred stock, pay dividends and distributions or repurchase capital stock, create liens on assets, make investments, loans or advances, make certain acquisitions, engage in mergers or consolidations, and engage in certain transactions with affiliates.

In connection with this amendment, the Company recognized a one-time, non-cash charge to interest expense of approximately $3.5 million during the third quarter of 2012 related to the write-off of previously capitalized deferred financing costs.

Borrowings under the Amended ABL Facility bear interest, at the Company’s option, at either (a) an alternative base rate, plus an applicable margin (ranging between 1.00% and 1.50%) or (b) a LIBOR rate plus applicable margin (ranging between 2.00% and 2.50%). The alternate base rate is the greater of (a) the prime rate, (b) the Federal Funds Effective rate plus 50 basis points, or (c) the one-month LIBOR rate plus 100 basis points and a spread of up to 225 basis points based upon percentage utilization of this facility. In addition to paying interest on outstanding borrowings, the Company is also required to pay an annual commitment fee ranging from 0.375% to 0.500% and letter of credit fees.

As of September 30, 2012, the borrowing base under the Amended ABL Facility was $192.0 million and availability under the Amended ABL Facility was $168.0 million (which is net of $24.0 million in outstanding letters of credit). The Company had no borrowings under the Amended ABL Facility at September 30, 2012 or December 31, 2011.

 

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13.	PARTNERS’ CAPITAL, DISTRIBUTIONS AND MEMBER’S INTEREST

Northern Tier Energy LP

Initial Public Offering

As discussed in Note 3, concurrent with the closing of the NTE LP IPO, NT Holdings contributed its membership interests in NTE LLC to NTE LP in exchange for 54,844,500 common units and 18,383,000 PIK common units. Additionally, NTE LP issued 18,687,500 common units to the public for total common units outstanding of 91,915,000, all of which represent limited partnership interests in NTE LP. NT Holdings is also the sole member in Northern Tier Energy GP LLC, the non-economic general partner of NTE LP.

From the closing of the NTE LP IPO on July 31, 2012 through September 30, 2012, NTE LP had a total of 91,915,000 issued and outstanding common and PIK common units.

PIK Common Units

At issuance, PIK common units had all the same rights and limitations as common units, with the exception of cash distribution rights. PIK common unit distributions were to be made at the same time and on equal basis per unit as common units. However, during the “PIK period” which ran from July 31, 2012 through the earlier of (i) December 1, 2017 (the maturity date of the Secured Notes) and (ii) the date by which the Company redeems, repurchases, defeases or retires all of the Secured Notes, or amends the indenture governing the Secured Notes that limited the Company’s ability to pay cash distributions on all units, distributions on PIK common units were to be paid in additional PIK common units, rather than cash. At the end of the PIK period, each outstanding PIK common unit would automatically convert into a common unit with the same rights and limitations as existing common units.

Subsequent to September 30, 2012 and in conjunction with a cash tender offer for the outstanding Secured Notes on November 6, 2012, the Company amended the indenture governing the Secured Notes and, as a result of such amendment, the PIK common units of NTE LP were converted into common units of NTE LP (see Note 22 – Subsequent Events).

Distribution Policy

NTE LP expects to make cash distributions to unitholders of record on the applicable record date within 60 days after the end of each quarter. Distributions will be equal to the amount of available cash generated in such quarter. Available cash for each quarter will generally equal NTE LP’s cash flow from operations for the quarter, less cash required for maintenance capital expenditures, working capital changes, reimbursement of expenses incurred by NTE LP’s 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 NTE LP’s general partner deems necessary or appropriate, including reserves for turnaround and related expenses. The amount of quarterly distributions, if any, will vary based on operating cash flow during such quarter. As a result, 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) operating performance, (ii) cash flows caused by, among other things, fluctuations in the prices paid for crude oil and other feedstocks and the prices received for finished products, working capital or capital expenditures and (iii) cash reserves deemed necessary or appropriate by the board of directors of NTE LP’s general partner. NTE LP’s general partner has no incentive distribution rights.

On November 12, 2012, NTE LP declared a quarterly distribution of $1.48 per unit to common unitholders of record on November 21, 2012. This distribution of $136 million in aggregate is based on available cash generated from the date of the NTE LP IPO July 31, 2012, through September 30, 2012.

 

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Distributions

In conjunction with its IPO, NTE LP distributed $124.2 million to NT Holdings in the third quarter of 2012. NT Holdings used approximately $92 million of the distribution to redeem MPC’s existing perpetual payment in kind preferred interest in NT Holdings. Prior to the NTE LP IPO, NTE LLC also made distributions of $40.0 million and $2.5 million to NT Holdings in the second quarter of 2012 and the third quarter of 2011, respectively.

Northern Tier Energy LLC

Member’s Interest

Subsequent to July 31, 2012, NTE LP held the sole membership interest in NTE LLC. In the third quarter of 2012, NTE LP contributed the net proceeds of its IPO to NTE LLC. Subsequently, NTE LLC distributed $124.2 million to NTE LP who, in turn, distributed that amount to NT Holdings of which approximately $92 million was used to redeem MPC’s existing perpetual payment in kind preferred interest in NT Holdings as discussed above. Prior to July 31, 2012, NT Holdings held the sole membership interest in NTE LLC. NTE LLC also made distributions of $40.0 million and $2.5 million to NT Holdings in the second quarter of 2012 and the third quarter of 2011, respectively, also as discussed above.

 

14.	FAIR VALUE MEASUREMENTS

As defined in accounting guidance, fair value is the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance describes three approaches to measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

Accounting guidance does not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. Accounting guidance establishes a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

 

•

Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

 

•

Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

 

•

Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

The Company uses a market or income approach for recurring fair value measurements and endeavors to use the best information available. Accordingly, valuation techniques that maximize the use of observable inputs are favored. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

 

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The Company’s current asset and liability accounts contain certain financial instruments, the most significant of which are trade accounts receivables and trade payables. The Company believes the carrying values of its current assets and liabilities approximate fair value. The Company’s fair value assessment incorporates a variety of considerations, including the short-term duration of the instruments, the Company’s historical incurrence of insignificant bad debt expense and the Company’s expectation of future insignificant bad debt expense, which includes an evaluation of counterparty credit risk.

The following table provides the assets and liabilities carried at fair value measured on a recurring basis at September 30, 2012 and December 31, 2011:

 

		Balance at				Quoted prices in active markets				Significant other observable inputs				Unobservable inputs
(in millions)		September 30, 2012				(Level 1)				(Level 2)				(Level 3)
ASSETS
Cash and cash equivalents		$	323.5			$	323.5			$	—			$	—
Other current assets
Derivative asset - current			0.2				—				0.2				—
Other assets
Derivative asset - long-term			1.9				—				1.9				—
		$	325.6			$	323.5			$	2.1			$	—
LIABILITIES
Derivative liability - current		$	71.2			$	—			$	71.2			$	—
Other liabilities
Derivative liability - long-term			8.0				—				8.0				—
		$	79.2			$	—			$	79.2			$	—
		Balance at				Quoted prices in active markets				Significant other observable inputs				Unobservable inputs
(in millions)		December 31, 2011				(Level 1)				(Level 2)				(Level 3)
ASSETS
Cash and cash equivalents		$	123.5			$	123.5			$	—			$	—
Other assets
Contingent consideration - margin support			20.2				—				—				20.2
		$	143.7			$	123.5			$	—			$	20.2
LIABILITIES
Derivative liability - current		$	109.9			$	—			$	109.9			$	—
Other liabilities
Contingent consideration - earn-out			30.9				—				—				30.9
		$	140.8			$	—			$	109.9			$	30.9

As of September 30, 2012, the Company had no Level 3 fair value assets or liabilities. During the third quarter of 2012 and in conjunction with the NTE LP IPO, the Company terminated the contingent consideration arrangements (margin support and earn-out) with MPC and settled all outstanding assets and liabilities by paying MPC $40 million in cash and by NT Holdings issuing a $45 million perpetual payment in kind preferred interest in NT Holdings to MPC. The Company recorded $38.5 million and $104.3 million of contingent consideration losses during the three and nine months ended September 30, 2012, respectively, related to the valuation adjustments of these arrangements.

 

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Prior to the settlement, the Company determined the fair value of its contingent consideration arrangements based on a probability-weighted income approach derived from financial performance estimates. The impacts of changes in the fair value of these arrangements were recorded in the statements of operations as contingent consideration (loss) income. During the three and nine months ended September 30, 2011, the Company recorded a $3.4 million loss and a $37.6 million gain, respectively, related to changes in the fair value of contingent consideration income. These contingent consideration arrangements were reported at fair value using Level 3 inputs due to such arrangements not having observable market prices. The fair value of the arrangements was determined based on a Monte Carlo simulation prepared by a third party service provider using management projections of future period EBITDA levels.

The significant unobservable inputs used in the fair value measurement of the Company’s Level 3 arrangements were the management projections of EBITDA. In developing these management projections, the Company used the forward market prices for various crude oil types, other feedstocks and refined products and applied its historical operating performance metrics against those forward market prices to develop its projected future EBITDA. Significant increases (decreases) in the projected future EBITDA levels would have resulted in significantly higher (lower) fair value measurements.

Assets not recorded at fair value on a recurring basis, such as property, plant and equipment, intangible assets and cost method investments, are recognized at fair value when they are impaired. During both the nine months ended September 30, 2012 and 2011, there were no adjustments to the fair value of such assets. The Company recorded assets acquired and liabilities assumed in the Marathon Acquisition at fair value.

The carrying value of debt, which is reported on the Company’s consolidated balance sheets, reflects the cash proceeds received upon its issuance, net of subsequent repayments. The fair value of the Secured Notes disclosed below was determined based on quoted prices in active markets (Level 1).

 

		September 30, 2012								December 31, 2011
		Carrying				Fair				Carrying				Fair
(in millions)		Amount				Value				Amount				Value
Secured Notes		$	261.0			$	289.4			$	290.0			$	316.5

 

15.	ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in asset retirement obligations:

 

		Nine Months Ended
		September 30,				September 30,
(in millions)		2012				2011
Asset retirement obligation balance at beginning of period		$	1.5			$	2.1
Revisions of previous estimates			0.3				—
Accretion expense			0.2				0.1
Asset retirement obligation balance at end of period		$	2.0			$	2.2

 

16.	EQUITY-BASED COMPENSATION

The Company and its affiliates maintain two distinct equity based compensation plans designed to encourage employees and directors of the Company and its affiliates to achieve superior performance. The initial plan (the “NT Investor Plan”) is sponsored by members of NT Investors, the parent company of NT Holdings, and granted profit unit interests in NT Investors. The second plan is maintained by the general partner of NTE LP and is referred to as the 2012 Long-Term Incentive Plan (“LTIP”). All share based compensation expense related to both plans is recognized by the Company.

 

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LTIP

Approximately 9.2 million NTE LP common units are reserved for issuance under the LTIP. The LTIP was created concurrent with NTE LP’s IPO and permits the award of unit options, restricted units, phantom units, unit appreciation rights and other awards that derive their value from the market price of NTE LP’s common units. As of September 30, 2012, no equity based awards had been granted under the LTIP.

NT Investor Plan

The NT Investor Plan is an equity participation plan which provides for the award of profit interest units in NT Investors to certain employees and independent non-employee directors of the Company. Approximately 29 million profit interest units in NT Investors are reserved for issuance under the plan. The exercise price for a profit interest unit shall not be less than 100% of the fair market value of NT Investors equity units on the date of grant. Profit interest units vest in annual installments over a period of five years after the date of grant and expire ten years after the date of grant. Upon NT Investors meeting certain thresholds of distributions from NTE LLC and NTE LP, profit interest unit vesting will accelerate. Continued employment in any subsidiary of NT Investors is a condition of vesting and, as such, compensation expense is recognized in the Company’s financial statements based upon the fair value of the award on the date of grant. This compensation expense is a non-cash expense of the Company. The NT Investor Plan awards are satisfied by cash distributions made to NT Holdings and will not dilute cash available for distribution to the unitholders of NTE LP. No further awards are planned to be issued from the NT Investor Plan.

A summary of the NT Investor Plan’s profit interest unit activity is set forth below:

 

Weighted

Number of

Weighted

Average

NT Investor

Average

Remaining

Profit Units

Exercise

Contractual

(in millions)

Price

Term

Outstanding at December 31, 2011

24.2

$

1.87

9.2

Granted

1.5

2.57

Outstanding at September 30, 2012

25.7

$

1.91

8.3

The estimated weighted average fair value as of the grant date for NT Investor Plan profit interest units granted during the nine months ended September 30, 2012 and 2011 were $0.88 and $0.57, respectively, based upon the following assumptions:

 

		2012				2011
Expected life (years)			6.5				6.5
Expected volatility			55.5	%			40.6	%
Expected dividend yield			0.0	%			0.0	%
Risk-free interest rate			1.4	%			2.7	%

The weighted average expected life for the grants was calculated using the simplified method, which defines the expected life as the average of the contractual term of the options and the weighted average vesting period. The expected volatility for the grants was based primarily on the historical volatility of a representative group of peer companies for a period consistent with the expected life of the awards.

As of September 30, 2012 and 2011, the total unrecognized compensation cost for NT Investor Plan profit interest units was $7.0 million and $6.4 million, respectively. This non-cash expense will be recognized on a straight-line basis through 2017.

 

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17.	DEFINED BENEFIT PLAN

During 2011, the Company initiated a defined benefit cash balance pension plan (the “Cash Balance Plan”) for eligible employees. Company contributions are made to the cash account of the participants equal to 5.0% of eligible compensation. Participants’ cash accounts also receive interest credits each year based upon the average thirty-year United States Treasury bond rate published in September preceding the respective plan year. Participants become fully vested in their accounts after three years of service. The Cash Balance Plan was not in place during the nine months ended September 30, 2011. The net periodic benefit cost related to the Cash Balance Plan for the nine months ended September 30, 2012 of $1.2 million related primarily to current period service costs.

 

18.	SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information is as follows:

 

		Nine Months Ended
		September 30,				September 30,
(in millions)		2012				2011
Net cash from operating activities included:
Interest paid		$	18.6			$	17.7
Noncash investing and financing activities include:
Capital expenditures included in accounts payable		$	—			$	1.3

 

19.	LEASING ARRANGEMENTS

As described in Note 5, concurrent with the Marathon Acquisition, certain Marathon assets (including real property interests and land related to 135 of the SuperAmerica convenience stores and the SuperMom’s bakery) were sold to a third party equity real estate investment trust. In connection with the closing of the Marathon Acquisition, the Company has assumed the leasing of these properties from the real estate investment trust on a long-term basis.

In accordance with ASC Topic 840-40 “Sale Leaseback Transactions,” the Company determined that subsequent to the sale, it had a continuing involvement for a portion of these property interests due to potential environmental obligations or due to subleasing arrangements. For these respective properties, the fair value of the assets and the related financing obligation will remain on the Company’s consolidated balance sheet until the end of the lease term or until the continuing involvement is resolved. The assets are included in property, plant and equipment and are being depreciated over their remaining useful lives. The lease payments relating to these property interests are recognized as interest expense. During December 2011 and September 2012, the Company’s continuing involvement ended for a subset of these stores and, as such, the related fair value of the assets and the financing obligation for these stores have been removed from the Company’s consolidated balance sheet.

The remainder of properties sold to the third party real estate investment trust are treated as operating leases. The Company also leases a variety of facilities and equipment under other operating leases, including land and building space, office equipment, vehicles, rail tracks for storage of rail tank cars near the refinery and numerous rail tank cars.

 

20.	COMMITMENTS AND CONTINGENCIES

The Company is the subject of, or party to, contingencies and commitments involving a variety of matters. Certain of these matters are discussed below. The ultimate resolution of these contingencies could, individually or in the aggregate, be material to the Company’s consolidated financial statements. However, management believes that the Company will remain a viable and competitive enterprise even though it is possible that these contingencies could be resolved unfavorably.

 

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Environmental Matters

The Company is subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance. At September 30, 2012 and December 31, 2011, liabilities for remediation totaled $5.4 million and $4.7 million, respectively. These liabilities are expected to be settled over at least the next 10 years. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties that may be imposed. Furthermore, environmental remediation costs may vary from estimates because of changes in laws, regulations and their interpretation; additional information on the extent and nature of site contamination; and improvements in technology. Receivables for recoverable costs from the state, under programs to assist companies in clean-up efforts related to underground storage tanks at retail marketing outlets, and others were $0.3 million and $0.2 million at September 30, 2012 and December 31, 2011, respectively.

Franchise Agreements

In the normal course of its business, SAF enters into ten-year license agreements with the operators of franchised SuperAmerica brand retail outlets. These agreements obligate SAF or its affiliates to provide certain services including information technology support, maintenance, credit card processing and signage for specified monthly fees.

Guarantees

Certain agreements related to assets sold in the normal course of business contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require the Company to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications were part of the normal course of selling assets. The Company has assumed these guarantees and indemnifications upon the Marathon Acquisition. However, in certain cases, MPC LP has also provided an indemnification in favor of the Company.

The Company is not typically able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the Company has little or no past experience associated with the underlying triggering event upon which a reasonable prediction of the outcome can be based. The Company is not currently making any payments relating to such guarantees or indemnifications.

 

21.	SEGMENT INFORMATION

The Company has two reportable operating segments: Refining and Retail. Each of these segments is organized and managed based upon the nature of the products and services they offer. The segment disclosures reflect management’s current organizational structure.

 

•

Refining – operates the St. Paul Park, Minnesota refinery, terminal and related assets, and includes the Company’s interest in MPL and MPLI, and

 

•

Retail – operates 166 convenience stores primarily in Minnesota and Wisconsin. The retail segment also includes the operations of NTB and SAF.

 

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Operating results for the Company’s operating segments are as follows:

 

(in millions)		Refining				Retail				Other				Total
Three months ended September 30, 2012
Revenues
Customer		$	866.4			$	397.1			$	—			$	1,263.5
Intersegment			284.7				—				—				284.7
Segment revenues			1,151.1				397.1				—				1,548.2
Elimination of intersegment revenues			—				—				(284.7	)			(284.7	)
Total revenues		$	1,151.1			$	397.1			$	(284.7	)		$	1,263.5
Income (loss) from operations		$	246.7			$	1.2			$	(48.5	)		$	199.4
Income from equity method investment		$	2.8			$	—			$	—			$	2.8
Depreciation and amortization		$	6.4			$	1.8			$	0.1			$	8.3
Capital expenditures		$	5.4			$	0.7			$	0.2			$	6.3
(in millions)		Refining				Retail				Other				Total
Three months ended September 30, 2011
Revenues
Customer		$	740.2			$	419.3			$	—			$	1,159.5
Intersegment			293.8				—				—				293.8
Segment revenues			1,034.0				419.3				—				1,453.3
Elimination of intersegment revenues			—				—				(293.8	)			(293.8	)
Total revenues		$	1,034.0			$	419.3			$	(293.8	)		$	1,159.5
Income (loss) from operations		$	174.0			$	4.9			$	(13.2	)		$	165.7
Income from equity method investment		$	0.9			$	—			$	—			$	0.9
Depreciation and amortization		$	5.4			$	2.0			$	—			$	7.4
Capital expenditures		$	7.2			$	1.9			$	2.2			$	11.3
(in millions)		Refining				Retail				Other				Total
Nine months ended September 30, 2012
Revenues
Customer		$	2,296.5			$	1,121.3			$	—			$	3,417.8
Intersegment			788.3				—				—				788.3
Segment revenues			3,084.8				1,121.3				—				4,206.1
Elimination of intersegment revenues			—				—				(788.3	)			(788.3	)
Total revenues		$	3,084.8			$	1,121.3			$	(788.3	)		$	3,417.8
Income (loss) from operations		$	560.3			$	5.2			$	(138.7	)		$	426.8
Income from equity method investment		$	8.7			$	—			$	—			$	8.7
Depreciation and amortization		$	18.5			$	5.6			$	0.5			$	24.6
Capital expenditures		$	10.7			$	1.7			$	0.9			$	13.3

 

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(in millions)		Refining				Retail				Other				Total
Nine months ended September 30, 2011
Revenues
Customer		$	2,026.4			$	1,165.6			$	—			$	3,192.0
Intersegment			831.3				—				—				831.3
Segment revenues			2,857.7				1,165.6				—				4,023.3
Elimination of intersegment revenues			—				—				(831.3	)			(831.3	)
Total revenues		$	2,857.7			$	1,165.6			$	(831.3	)		$	3,192.0
Income from operations		$	326.7			$	7.2			$	13.2			$	347.1
Income from equity method investment		$	3.2			$	—			$	—			$	3.2
Depreciation and amortization		$	16.0			$	6.0			$	0.3			$	22.3
Capital expenditures		$	19.7			$	2.6			$	5.1			$	27.4

Intersegment sales from the Refining segment to the Retail segment consist primarily of sales of refined products which are recorded based on contractual prices that are market based. Revenues from external customers are nearly all in the United States.

Total assets by segment were as follows:

 

(in millions)		Refining				Retail				Corporate/Other				Total
At September 30, 2012		$	687.5			$	139.7			$	350.2			$	1,177.4
At December 31, 2011		$	646.5			$	130.2			$	222.1			$	998.8

Total assets for the refining and retail segments exclude all intercompany balances. All cash and cash equivalents are included as corporate/other assets. All property, plant and equipment are located in the United States.

 

22.	SUBSEQUENT EVENTS

On October 17, 2012, NTE LLC announced the commencement of a cash tender offer for any and all of the $261 million outstanding principal amount of the Secured Notes. In conjunction with the tender offer, the Company solicited consents to eliminate most of the covenants, certain events of default and certain other provisions contained in the indenture governing the Secured Notes. At the completion of the early tender period, November 1, 2012, $253.1 million of the outstanding principal amount had been tendered and related consents received. As of November 8, 2012, the Company amended the indenture governing the Secured Notes in accordance with the approved consents. As a result of the amendment, the PIK common units of NTE LP were converted into common units of NTE LP with the same rights and limitations as the existing common units effective November 9, 2012. On November 9, 2012, NTE LLC called the remaining $7.9 million of outstanding Secured Notes at its contractual redemption price of 103% of the principal amount.

On November 8, 2012, NTE LLC and its subsidiary, Northern Tier Finance Corporation, completed a private offering of $275 million in aggregate principal amount of 7.125% senior secured notes due 2020. NTE LLC used the net proceeds of the offering to fund a portion of the tender offer for its outstanding 10.5% secured notes due 2017.

 

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Report of Independent Registered Public Accounting Firm

To the Board of Directors of Northern Tier Energy LLC:

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, cash flows and member’s interest present fairly, in all material respects, the financial position of Northern Tier Energy LLC and its subsidiaries at December 31, 2011 and 2010, and the results of their operations and their cash flows for the year ended December 31, 2011 and for the period from June 23, 2010 (date of inception) to December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Houston, Texas

April 10, 2012

 

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Report of Independent Registered Public Accounting Firm

To Marathon Oil Corporation:

In our opinion, the accompanying combined statements of income, cash flows and net investment present fairly, in all material respects, the results of operations and cash flows of the St. Paul Refinery & Retail Marketing Business, a component of Marathon Oil Corporation, for the eleven month period ended November 30, 2010 and the year ended December 31, 2009 in conformity with accounting principles generally accepted in the United States of America. These combined financial statements are the responsibility of management. Our responsibility is to express an opinion on these combined financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP

Houston, Texas

April 12, 2011, except for the change in the composition of reportable segments discussed in Note 19 to the combined financial statements, as to which the date is December 12, 2011.

 

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NORTHERN TIER ENERGY LLC

CONSOLIDATED BALANCE SHEETS

(in millions)

 

		December 31, 2011				December 31, 2010
ASSETS
CURRENT ASSETS
Cash and cash equivalents		$	123.5			$	72.8
Receivables, less allowance for doubtful accounts			81.9				100.2
Inventories			154.1				156.4
Other current assets			65.5				28.7
Total current assets			425.0				358.1
NON-CURRENT ASSETS
Equity method investment			89.9				92.4
Property, plant and equipment, net			391.2				386.3
Intangible assets			35.4				35.4
Other assets			57.3				58.4
Total Assets		$	998.8			$	930.6
LIABILITIES AND MEMBER’S INTEREST
CURRENT LIABILITIES
Accounts payable		$	207.4			$	183.4
Accrued liabilities			30.3				20.5
Derivative liability			109.9				45.6
Total current liabilities			347.6				249.5
NON-CURRENT LIABILITIES
Long-term debt			290.0				290.0
Lease financing obligation			11.9				24.5
Derivative liability			—				22.4
Other liabilities			37.1				59.2
Total liabilities			686.6				645.6
Commitments and contingencies (Note 18)
EQUITY
Member’s interest			312.2				285.0
Total Liabilities and Member’s Interest		$	998.8			$	930.6

The accompanying notes are an integral part of these consolidated and combined financial statements.

 

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NORTHERN TIER ENERGY LLC

CONSOLIDATED AND COMBINED STATEMENTS OF INCOME

(in millions)

 

		Successor								Predecessor
		Year Ended December 31, 2011				June 23, 2010 (inception date) to December 31, 2010				Eleven Months Ended November 30, 2010				Year Ended December 31, 2009
REVENUE(a)			$4,280.8				$344.9				$3,195.2				$2,940.5
COSTS, EXPENSES AND OTHER
Cost of sales(a)			3,508.0				307.5				2,697.9				2,507.9
Direct operating expenses			260.3				21.4				227.0				238.3
Turnaround and related expenses			22.6				—				9.5				0.6
Depreciation and amortization			29.5				2.2				37.3				40.2
Selling, general and administrative			90.7				6.4				59.6				64.7
Formation costs			7.4				3.6				—				—
Contingent consideration income			(55.8	)			—				—				—
Other (income) expense, net			(4.5	)			0.1				(5.4	)			(1.1	)
OPERATING INCOME			422.6				3.7				169.3				89.9
Realized losses from derivative activities			(310.3	)			—				—				—
Unrealized losses from derivative activities			(41.9	)			(27.1	)			(40.9	)			—
Bargain purchase gain			—				51.4				—				—
Interest expense, net			(42.1	)			(3.2	)			(0.3	)			(0.4	)
EARNINGS BEFORE INCOME TAXES			28.3				24.8				128.1				89.5
Income tax provision			—				—				(67.1	)			(34.8	)
NET EARNINGS		$	28.3			$	24.8			$	61.0			$	54.7
(a)      Excise taxes included in revenue and cost of sales		$	242.9			$	25.1			$	271.8			$	289.6

 

The accompanying notes are an integral part of these consolidated and combined financial statements.

 

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NORTHERN TIER ENERGY LLC

CONSOLIDATED AND COMBINED STATEMENTS OF CASH FLOWS

(in millions)

 

		Successor										Predecessor
Increase (decrease) in cash		Year Ended December 31, 2011				June 23, 2010 (inception date) to December 31 2010						Eleven Months Ended November 30, 2010				Year Ended December 31, 2009
CASH FLOWS FROM OPERATING ACTIVITIES
Net earnings		$	28.3			$	24.8					$	61.0			$	54.7
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation and amortization			29.5				2.2						37.3				40.2
Stock-based compensation expense			1.6				0.1						0.3				0.3
Bargain purchase gain			—				(51.4	)					—				—
Equity method investment, net			—				0.6						0.6				0.3
Contingent consideration income			(55.8	)			—						—				—
Unrealized loss from derivative activities			41.9				27.1						40.9				—
Deferred taxes			—				—						(0.8	)			0.5
Changes in assets and liabilities, net:
Accounts receivable			18.3				(100.2	)					(16.3	)			(14.7	)
Inventories			2.3				38.6						2.5				(6.8	)
Other current assets			(6.8	)			(27.7	)					—				—
Accounts payable and accrued expenses			146.4				86.4						23.8				31.2
Receivables from and payables to related parties			—				—						(1.2	)			23.8
Other, net			3.6				(0.5	)					(2.7	)			(0.1	)
Net cash provided by operating activities			209.3				—						145.4				129.4
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures			(45.9	)			(2.5	)					(29.8	)			(29.0	)
Acquisition, net of cash acquired			(112.8	)			(360.8	)					—				—
Disposals of assets			—				—						0.4				0.7
Return of capital from investments			2.4				—						0.1				3.3
Net cash used in investing activities			(156.3	)			(363.3	)					(29.3	)			(25.0	)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from senior secured notes			—				290.0						—				—
Borrowings from revolving credit arrangement			95.0				—						—				—
Repayments of revolving credit arrangement			(95.0	)			—						—				—
Financing costs			—				(34.1	)					—				—
Investment from members			—				180.2						—				—
Distributions to Member’s Interest			(2.3	)			—						—				—
Distributions to Marathon, net			—				—						(115.4	)			(103.9	)
Net cash (used in) provided by financing activities			(2.3	)			436.1						(115.4	)			(103.9	)
CASH AND CASH EQUIVALENTS
Change in cash and cash equivalents			50.7				72.8						0.7				0.5
Cash and cash equivalents at beginning of period			72.8				—						6.0				5.5
Cash and cash equivalents at end of period		$	123.5			$	72.8					$	6.7			$	6.0

The accompanying notes are an integral part of these consolidated and combined financial statements.

 

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NORTHERN TIER ENERGY LLC

CONSOLIDATED AND COMBINED STATEMENTS OF MEMBER’S INTEREST AND NET INVESTMENT

(in millions)

 

		Equity
		Net Investment				Member’s Interest
Balance at January 1, 2009 (Predecessor)		$	415.5			$	—
Net earnings			54.7				—
Distributions to Marathon, net			(104.0	)			—
Balance at December 31, 2009 (Predecessor)			366.2				—
Net earnings			61.0				—
Distributions to Marathon, net			(114.8	)			—
Balance at November 30, 2010 (Predecessor)		$	312.4			$	—
Balance at June 23, 2010 (Successor Inception Date)		$	—			$	—
Net earnings			—				24.8
Capital contribution			—				260.1
Stock-based compensation			—				0.1
Balance at December 31, 2010 (Successor)			—				285.0
Net earnings			—				28.3
Capital distributions			—				(2.3	)
Other comprehensive loss			—				(0.4	)
Stock-based compensation			—				1.6
Balance at December 31, 2011 (Successor)		$	—			$	312.2

The accompanying notes are an integral part of these consolidated and combined financial statements.

 

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NOTES TO CONSOLIDATED AND COMBINED FINANCIAL STATEMENTS

1. DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Description of the Business

Northern Tier Energy LLC (“NTE” or the “Company”) is an independent downstream energy company with refining, retail and pipeline operations that serve the Petroleum Administration for Defense District II (“PADD II”) region of the United States. The Company is a Delaware limited liability company and is a wholly-owned subsidiary of Northern Tier Holdings LLC (“NT Holdings” or the “Member”). NT Holdings is wholly-owned by Northern Tier Investors LLC (“NTI”). Additionally, NT Holdings has issued preferred stock that is solely owned by an indirect subsidiary of Marathon Petroleum Corporation (“Marathon Petroleum”). Marathon Petroleum was a wholly-owned subsidiary of Marathon Oil Corporation (“Marathon Oil”) until June 30, 2011. NTI, NT Holdings and the Company were formed by ACON Investments L.L.C. and TPG Refining, L.P. and certain members of management (collectively, the “Investors”) during 2010.

Predecessor interests represent the St. Paul Park Refinery & Retail Marketing Business formerly owned and operated by subsidiaries of Marathon Oil. These subsidiaries, Marathon Petroleum Company LP (“MPC LP”), Speedway LLC (“Speedway”) and MPL Investments LLC, are together referred to as “MPC” or “Marathon” and are subsidiaries of Marathon Petroleum. Predecessor interests are hereinafter referred to as the “Predecessor.” Effective December 1, 2010, the Company acquired the Predecessor business from Marathon for approximately $608 million (the “Acquisition”).

The Company includes the operations of the St. Paul Park Refining Co. LLC (“SPPR”) and Northern Tier Retail LLC (“NTR”). The Company also includes Northern Tier Bakery LLC (“NTB”), SuperAmerica Franchising LLC (“SAF”), a 17% interest in MPL Investments Inc. (“MPLI”) and a 17% interest in Minnesota Pipe Line Company, LLC (“Minnesota Pipe Line”). MPLI owns 100% of the preferred interest in Minnesota Pipe Line which owns and operates a 455,000 barrels per day crude oil pipeline in Minnesota (see Note 2).

SPPR, which is located in St. Paul Park, Minnesota, has total crude oil throughput capacity of 74,000 barrels per calendar day. Refinery operations include crude fractionation, catalytic cracking, hydrotreating, reforming, alkylation, sulfur recovery and a hydrogen plant. The refinery processes predominately North Dakota and Canadian crude oils into products such as gasoline, diesel, jet fuel, kerosene, asphalt, propane, propylene and sulfur. The refined products are sold to markets primarily located in the Upper Great Plains of the United States.

NTR operates 166 convenience stores under the SuperAmerica brand. SAF supports 67 franchised stores which also utilize the SuperAmerica brand. The SuperAmerica stores are primarily located in Minnesota and Wisconsin and sell gasoline, merchandise, and in some locations, diesel fuel. There is a wide range of merchandise sold at the stores including prepared foods, beverages and non-food items. The merchandise sold includes a significant number of proprietary items.

NTB prepares and distributes food products under the SuperMom’s Bakery brand primarily to SuperAmerica branded retail outlets.

Basis of Presentation

The accompanying consolidated and combined financial statements present separately the financial position, results of operations, cash flows and changes in equity for both the Company and the Predecessor. In connection with the Acquisition, further described in Note 4, a new accounting basis was established for the Company as of the acquisition date based upon the fair value of the assets acquired and liabilities assumed, in accordance with the guidance for business combinations. Financial information for the pre- and post-acquisition periods has been separated by a line on the face of the consolidated and combined financial statements to highlight the fact that the

 

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financial information for such periods have been prepared under two different historical-cost bases of accounting. For all periods prior to the closing of the Acquisition, the accompanying combined financial statements reflect all assets, liabilities, revenues, expenses and cash flows directly attributable to the Predecessor.

Subsequent Events

Events and transactions subsequent to the balance sheet date have been evaluated through April 10, 2012, the date these consolidated and combined financial statements were available to be issued, for potential recognition or disclosure in the financial statements.

2. SUMMARY OF PRINCIPAL ACCOUNTING POLICIES

Principles of Consolidation and Combination

Prior to the closing of the Acquisition, the Predecessor was legally held by multiple subsidiaries and affiliates of Marathon Oil. As such, the accompanying Predecessor financial statements present the combined accounts of such businesses for all periods prior to the Acquisition. The Company was incorporated on June 23, 2010. NTI entered into the Acquisition agreement with Marathon on October 6, 2010. After the closing of the Acquisition on December 1, 2010, the Company acquired the stock or net assets of those Predecessor businesses from NTI. Accordingly, the accompanying financial statements present the consolidated accounts of such acquired businesses for all periods subsequent to December 1, 2010. The Company had no operating activities between its June 23, 2010 inception date and the date the Predecessor businesses were acquired although it incurred various transaction and formation costs which have been included in the total successor period of June 23, 2010 through December 31, 2010 (the “Successor Period”).

All significant intercompany accounts have been eliminated in these consolidated and combined financial statements.

The Company’s and the Predecessor’s 17% common interest in Minnesota Pipe Line is accounted for using the equity method of accounting in accordance with Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”) Topic 323. Income from equity method investment represents the Company’s and the Predecessor’s proportionate share of net income available to common owners generated by Minnesota Pipe Line.

The equity method investment is assessed for impairment whenever changes in facts or circumstances indicate a loss in value has occurred. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net income. See Note 7 for further information on the Company’s equity investment.

MPLI owns all of the preferred membership units of Minnesota Pipe Line. This investment in MPLI which provides the Company (and previously, the Predecessor) no significant influence over Minnesota Pipe Line is accounted for as a cost method investment. The investment in MPLI is carried at a cost of $6.9 million as of December 31, 2011 and $7.0 as of December 31, 2010 and is included in other noncurrent assets on the consolidated balance sheets.

Use of Estimates

The preparation of financial statements in accordance with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated and combined financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from those estimates. In addition, significant estimates were used in accounting for the Acquisition under the purchase method of accounting.

 

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The Predecessor financial statements include allocations of general, administrative and overhead costs of Marathon that are attributable to the Predecessor’s operations. Management believes the assumptions and allocations underlying the combined financial statements are reasonable. However, these combined financial statements do not include all of the actual expenses that would have been incurred had the Predecessor been a stand-alone entity during the periods presented and do not reflect the Predecessor’s combined results of operations, financial position and cash flows had it been a stand-alone company during the periods presented.

Operating Segments

The Company has two reportable operating segments:

 

•

Refining—operates the St. Paul Park, Minnesota, refinery, terminal and related assets, including the Company’s interest in MPLI and Minnesota Pipe Line, and

 

•

Retail—operates 166 convenience stores primarily in Minnesota and Wisconsin. The Retail segment also includes the operations of NTB and SAF.

See Note 19 for further information on the Company’s operating segments.

Revenue Recognition

Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. Revenues are recorded net of discounts granted to customers. Shipping and other transportation costs billed to customers are presented on a gross basis in revenues and cost of sales.

Rebates from vendors are recognized as a reduction of cost of sales when the initiating transaction occurs. Incentives that are derived from contractual provisions are accrued based on past experience and recognized in cost of sales.

Excise Taxes

The Company (and previously, the Predecessor) is required by various governmental authorities, including federal and state, to collect and remit taxes on certain products. Such taxes are presented on a gross basis in revenues and costs and expenses in the consolidated and combined statements of income. These taxes totaled $242.9 million for the year ended December 31, 2011, $25.1 million for the Successor Period, $271.8 million for the eleven months ended November 30, 2010 and $289.6 million for the year ended December 31, 2009.

Refined Product Exchanges

The Company (and previously, the Predecessor) enters into exchange contracts whereby it agrees to deliver a particular quantity and quality of refined products at a specified location and date to a particular counterparty and to receive from the same counterparty a particular quantity and quality of refined products at a specified location on the same or another specified date. The exchange receipts and deliveries are nonmonetary transactions, with the exception of associated grade or location differentials that are settled in cash. These transactions are not recorded as revenue because they involve the exchange of refined product inventories held for sale in the ordinary course of business to facilitate sales to customers. The exchange transactions are recognized at the carrying amount of the inventory transferred plus any cash settlement due to grade or location differentials.

Advertising

The Company (and previously, the Predecessor) expenses the costs of advertising as incurred. Advertising expense was $1.0 million for the year ended December 31, 2011, less than $0.1 million for the Successor Period, $2.6 million for the eleven months ended November 30, 2010 and $2.1 million for the year ended December 31, 2009.

 

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Income Taxes

After the Acquisition, the Company and its subsidiaries are limited liability companies and are therefore pass-through entities for federal income tax purposes. As a result, the Company does not incur federal income taxes. The Predecessor’s taxable income has historically been included in the consolidated U.S. federal income tax returns of Marathon Oil and also in a number of state income tax returns, which were filed as consolidated returns.

For the Predecessor, the provision for income taxes was computed as if the Predecessor were a stand-alone tax-paying entity and as if it paid the amount of its current federal and state tax liabilities to Marathon Oil in each period. As such, the accrual and payment of the current federal and state tax liabilities are recorded within the net investment in the combined financial statements of the Predecessor in the period incurred.

Deferred tax assets and liabilities were recognized based on temporary differences between the financial statement carrying amounts of the Predecessor’s assets and liabilities and their tax bases as reported in Marathon Oil’s tax filings with the respective taxing authorities. The realization of deferred tax assets was assessed periodically based on several interrelated factors. These factors include the Predecessor’s expectation to generate sufficient future taxable income in order to utilize tax credits and operating loss carry-forwards.

Cash and Cash Equivalents

The Company considers all highly liquid investments with maturities of three months or less from the date of purchase to be cash equivalents.

Receivables and Allowance for Doubtful Accounts

Receivables of the Company (and previously, the Predecessor) primarily consist of customer accounts receivable. The accounts receivable are due from a diverse base including companies in the petroleum industry, airlines and the federal government. The allowance for doubtful accounts is reviewed quarterly for collectability. All customer receivables are recorded at the invoiced amounts and generally do not bear interest. When it becomes probable the receivable will not be collected, the balances for customer receivables are charged directly to bad debt expense. The allowance for doubtful accounts was less than $0.1 million as of December 31, 2011 and 2010.

Inventories

Inventories are carried at the lower of cost or market value. Cost of inventories is determined primarily under the last-in, first-out (“LIFO”) method. However, the Company (and previously, the Predecessor) maintains some inventories whose cost is primarily determined using the first-in, first-out method. The Company has LIFO pools for crude oil and other feedstocks and for refined products in its Refining segment and a LIFO pool for refined products in its Retail segment for inventory held by the retail stores.

Property, Plant and Equipment

Property, plant and equipment is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets. Such assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset.

When property, plant and equipment depreciated on an individual basis are sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. If a loss on disposal is expected, such losses are generally recognized when the assets are classified as held for sale.

 

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Expenditures for routine maintenance and repair costs are expensed when incurred. Refinery process units require periodic major maintenance and repairs that are commonly referred to as “turnarounds.” The required frequency of the maintenance varies by unit, but generally is every two to six years depending on the processing unit involved. Turnaround costs are expensed as incurred.

Internal-Use Software Development Costs

The Company capitalizes certain external and internal computer software costs incurred during the application development stage. The application development stage generally includes software design and configuration, coding, testing and installation activities. Training and maintenance costs are expensed as incurred, while upgrades and enhancements are capitalized if it is probable that such expenditures will result in additional functionality. Capitalized software costs are depreciated over the estimated useful life of the underlying project on a straight-line basis, generally not exceeding five years.

Intangible Assets

Intangible assets primarily include a retail marketing trade name and franchise agreements. These assets have an indefinite life and therefore are not amortized, but rather are tested for impairment annually and when events or changes in circumstances indicate that the fair value of the intangible asset has been reduced below carrying value.

Financing Costs

Financing origination fees are deferred and classified within other assets on the consolidated balance sheet. Amortization is provided on a straight-line basis over the term of the agreement, which approximates the effective interest method.

Derivative Financial Instruments

The Company (and previously, the Predecessor) is exposed to earnings and cash flow volatility based on the timing and change in refined product prices and crude oil prices. To manage these risks, the Company uses derivative instruments associated with the purchase or sale of crude oil and refined products. Crack spread option contracts are used to hedge the volatility of refining margins. The Company also may use futures contracts to manage price risks associated with inventory quantities above or below target levels. The Company does not enter into derivative contracts for speculative purposes. All derivative instruments are recorded in the consolidated balance sheet at fair value and are classified depending on the maturity date of the underlying contracts. Changes in the fair value of its contracts are accounted for by marking them to market and recognizing any resulting gains or losses in its statements of income. These gains and losses are reported within operating activities on the consolidated statements of cash flows.

Environmental Costs

Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. The Company (and previously, the Predecessor) provides for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed and determinable. If recoveries of remediation costs from third parties are probable, a receivable is recorded and is discounted to net present value when the estimated amount is reasonably fixed and determinable.

 

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Asset Retirement Obligations

The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. Conditional asset retirement obligations for removal and disposal of fire-retardant material from certain refining assets have been recognized. The amounts recorded for such obligations are based on the most probable current cost projections. Asset retirement obligations have not been recognized for the removal of materials and equipment from or the closure of certain refinery, pipeline, terminal and retail marketing assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminable.

Current inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is determined on a straight-line basis, while accretion escalates over the lives of the assets.

Employee Benefit Plans

The Predecessor’s employees participated in various employee benefit plans of Marathon. These plans include qualified, non-contributory defined benefit retirement plans, employee savings plans, employee and retiree medical and life insurance plans, dental plans and other such benefits. For the purposes of the combined financial statements, the Predecessor was considered to be participating in multi-employer benefit plans of Marathon. As a participant in multi-employer benefit plans, the Predecessor recognized as expense in each period the required allocations from Marathon, and it did not recognize any employee benefit plan liabilities.

Subsequent to the Acquisition, the majority of the Predecessor’s employees still participated in the employee benefit plans of Marathon under a transition services agreement. See Note 4 for a further description of this transition services agreement.

Any employee not covered under an employee benefit plan of Marathon participates in retirement plans, medical and life insurance plans, dental plans and other such benefits sponsored by the Company (see Note 15).

Stock-Based Compensation

The Company recognizes compensation expense for stock-based awards issued over the requisite service period for each separately vesting tranche, as if multiple awards were granted. Stock-based compensation costs are measured at the date of grant, based on the fair value of the award. Stock-based compensation expense recognized was $1.6 million, $0.1 million, $0.3 million and $0.3 million for the year ended December 31, 2011, the Successor Period ended December 31, 2010, the eleven months ended November 30, 2010, and the year ended December 31, 2009, respectively.

Net Investment

The net investment represents a net balance reflecting Marathon’s initial investment in the Predecessor and subsequent adjustments resulting from the operations of the Predecessor and various transactions between the Predecessor and Marathon. The balance is the result of the Predecessor’s participation in Marathon’s centralized cash management programs under which the Predecessor’s 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 are allocated to the Predecessor. There are no terms of settlement or interest charges associated with the net investment balance.

Comprehensive Income

The Company has unrecognized prior service cost related to its defined benefit cash balance plan as of December 31, 2011 (see Note 15). This unrecognized prior service cost of $0.4 million is recognized directly to

 

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member’s interest as an element of other comprehensive income. The Predecessor has reported no comprehensive income due to the absence of items of other comprehensive income in the periods presented.

Concentrations of Risk

The Predecessor is exposed to related party risk as a portion of both sales revenues and costs are derived from transactions with Marathon Oil’s subsidiaries and affiliates. Sales to related parties for eleven months ended November 30, 2010 and for the year ended December 31, 2009 were both 7% of total sales. For the eleven months ended November 30, 2010 and for the year ended December 31, 2009 purchases from related parties were both 45% of total costs and expenses.

The Company (and previously, the Predecessor) is exposed to credit risk in the event of nonpayment by customers. The creditworthiness of customers is subject to continuing review. No single non-related party customer accounts for more than 10% of annual revenues.

Crude oil is the principal raw material for the Company and the majority of the crude oil processed is delivered to the refinery through a pipeline that is owned by Minnesota Pipe Line, a related party. A prolonged disruption of that pipeline’s operations would materially impact the Company’s ability to economically obtain raw materials.

The Company (and previously, the Predecessor) is exposed to concentrated geographical risk as most of its operations are conducted in certain states.

Accounting Developments

In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” (“ASU 2011-04”). ASU 2011-04 changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between U.S. GAAP and International Financial Reporting Standards (“IFRS”). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is to be applied prospectively. ASU 2011-04 will be effective for the Company’s quarterly and annual financial statements beginning with our first quarter 2012 reporting. The Company believes that the adoption of this standard will not materially impact its consolidated financial statements because the guidance only provides for enhanced disclosure requirements.

In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (ASC Topic 220): Presentation of Comprehensive Income,” (“ASU 2011-05”) which amends current comprehensive income guidance. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. ASU 2011-05 will be effective for the Company’s quarterly and annual financial statements beginning with our first quarter 2012 reporting. However, in December 2011 the FASB issued ASU 2011-12 Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05. ASU 2011-12 defers the effectiveness for the requirement to present on the face of our financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income. The Company believes that the adoption of ASU 2011-05, as amended by ASU 2011-12, will not have a material impact on its consolidated financial statements.

 

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In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”). ASU 2011-11 retains the existing offsetting requirements and enhances the disclosure requirements to allow investors to better compare financial statements prepared under U.S. GAAP with those prepared under IFRS. This new guidance is to be applied retrospectively. ASU 2011-11 will be effective for the Company’s quarterly and annual financial statements beginning with our first quarter 2013 reporting. The Company believes that the adoption of ASU 2011-11 will not have a material impact on its consolidated financial statements.

3. RELATED PARTY TRANSACTIONS

The Investors, which include ACON Investments L.L.C. and TPG Refining, L.P., are related parties of the Company. Minnesota Pipe Line is also a related party of the Company. Subsequent to the Acquisition (see Note 4), the Company entered into a crude oil supply and logistics agreement with a third party and no longer has direct transaction with Minnesota Pipe Line.

Related parties for the Predecessor include the following:

 

•

Marathon Oil Company (“MOC”), which is a wholly-owned subsidiary of Marathon Oil. MOC purchases or produces crude oil in the United States that is used at MPC’s refineries.

 

•

MPC LP, which changed its name from Marathon Petroleum Company LLC on October 1, 2010, was a wholly-owned subsidiary of Marathon Oil. MPC LP refines, markets and transports crude oil and petroleum products, primarily in the Midwest, Upper Great Plains, Gulf Coast and southeastern regions of the United States.

 

•

Marathon Petroleum Trading Canada LLC (“MP Trading Canada”), which was a wholly-owned subsidiary of MPC LP. MP Trading Canada purchases crude oil in Canada to be used at MPC LP’s refineries.

 

•

Minnesota Pipe Line, in which Marathon owned (and now the Company owns) a 17 percent interest. Minnesota Pipe Line owns and operates a crude oil pipeline running from Clearbrook, Minnesota to Pine Bend, Minnesota.

 

•

Speedway was a wholly-owned subsidiary of Marathon Oil. Under the Predecessor, Speedway was the owner of the SuperAmerica branded convenience stores that were sold to NTR as part of the Acquisition.

Predecessor revenues from related parties for the eleven months ended November 30, 2010 were $210.1 million and $216.7 million for the year ended December 31, 2009 and represented sales to MPC LP. Related party sales to MPC LP consisted primarily of sales of refined products. Refined product sales to MPC LP were recorded at intercompany transfer prices that were market-based prices.

Predecessor purchases from related parties were as follows:

 

(in millions)		Eleven Months  Ended November 31, 2010				Year Ended December 31, 2009
MOC		$	276.9			$	155.6
MPC LP			67.5				64.2
MP Trading Canada			992.3				1,027.7
Minnesota Pipe Line			25.3				26.4
Speedway			16.3				16.4
Total		$	1,378.3			$	1,290.3

 

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Related party purchases from MOC and MP Trading Canada consisted primarily of crude oil. Purchases from MOC were recorded at contracted prices that were market-based. Purchases from MP Trading Canada were recorded at contracted prices based on MP Trading Canada’s acquisition cost, plus an administrative fee. Related party purchases from MPC LP consisted primarily of purchases of refined products and refinery feedstocks, certain general and administrative costs, and costs associated with the Refining segment participating in MPC LP’s multi-employer benefit plans. Refined product and refinery feedstock purchases from MPC LP were recorded at intercompany transfer prices that were market-based prices. Related party purchases from Minnesota Pipe Line consisted primarily of crude oil transportation services which were based on published tariffs. Related party purchases from Speedway consisted of certain overhead costs and costs associated with the Retail segment participating in Speedway’s multi-employer benefit plans.

MPC LP and Speedway provided certain services to the Predecessor such as marketing, crude acquisition, engineering, human resources, insurance, treasury, accounting, tax, legal, procurement and information technology services. Charges for these services were allocated based on usage or other methods, such as headcount, capital employed or store count, which management believes to be reasonable. Related party purchases reflect charges for these services of $26.5 million and $29.1 million for the eleven months ended November 30, 2010 and the year ended December 31, 2009, respectively. The allocation methods included in the combined income statements were consistently applied.

For the purposes of the combined financial statements, the Predecessor was considered to participate in multi-employer benefit plans of MPC LP and Speedway. The Predecessor’s allocated share of MPC LP and Speedway’s employee benefit plan expenses, including costs related to stock-based compensation plans, is included in related party purchases and was $21.5 million and $20.3 million for the eleven months ended November 30, 2010 and the year ended December 31, 2009, respectively. Expenses for employee benefit plans other than stock-based compensation plans were allocated to the Predecessor primarily as a percentage of salary and wage expense. For the stock-based compensation plans, the Predecessor was charged with the expenses directly attributed to its employees which were $0.3 million for the eleven months ended November 30, 2010 and the year ended December 31, 2009.

Upon completion of the Acquisition, the Company entered into a management services agreement with the Investors pursuant to which they provide the Company with ongoing management, advisory and consulting services. The Investors also receive quarterly management fees equal to 1% of the Company’s “Adjusted EBITDA” (as defined in the agreement) for the previous quarter (subject to a minimum annual fee of $2 million), as well as reimbursements for out-of pocket expenses incurred by them in connection with providing such management services. The Company also pays the Investors’ specified success fees in connection with advice they provide in relation with certain corporate transactions. For the year ended December 31, 2011, the Company incurred fees relating to these services of $2.1 million.

4. ACQUISITION

As previously described in Note 1, effective December 1, 2010, the Company acquired the Predecessor business from MPC for $608 million. Included in this amount was the estimated fair value of earn-out payments of $54 million as of the Acquisition date. Of the $608 million purchase price, $361 million was paid in cash as of December 31, 2010 and $80 million was satisfied by issuing MPC a perpetual payment in kind preferred interest in NT Holdings. The residual purchase price of $113 million (excluding the contingent earn-out consideration) was paid during the three months ended March 31, 2011.

The Company will be required to pay Marathon the earn-out payments if the Company’s Adjusted EBITDA (as defined in the agreement, the “Agreement Adjusted EBITDA”) exceeds $165 million less, among other things, any rental expense related to the real estate lease arrangement (described below) during any year in each of the next eight years following the Acquisition. Agreement Adjusted EBITDA adjusts for, among other items, (i) any unrealized gains or losses relating to derivative activities, (ii) any gains or losses generated by the

 

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liquidation of any LIFO inventory layers, (iii) any losses related to lower of cost or market inventory adjustments, and (iv) any gains on the sale of property, plant or equipment and certain other assets. Marathon will receive 40% of the amount by which Agreement Adjusted EBITDA exceeds the specified threshold in any year during the eight years following the Acquisition not to exceed $125 million over the eight years following the Acquisition. The Acquisition agreement also includes a margin support component that requires Marathon to pay the Company up to $30 million per year to the extent the Agreement Adjusted EBITDA is below $145 million less, among other things, any rental expense related to the real estate lease arrangement (described below), in either of the first two twelve month periods ending November 30, 2011 or 2012 up to a maximum of $60 million. Any such payments made by Marathon will increase the amount that we may be required to pay Marathon over the earn-out period (see Note 18). Subsequent fair value adjustments to these collective contingent consideration arrangements (earn-out arrangement and margin support arrangement) will be recorded in the statement of income based on quarterly remeasurements. See Note 12 for further information on the Company’s fair value measurements.

The cash component of the purchase price along with acquisition related costs were financed by an approximate $180 million cash investment by the Investors and aggregate borrowings of $290 million. See Note 11 for a description of the Company’s financing arrangements.

Concurrent with the Acquisition, the following transactions also occurred:

 

•

Certain Marathon assets (including real property interests and land related to 135 of the SuperAmerica convenience stores and the SuperMom’s bakery) were sold to a third party equity real estate investment trust. In connection with the closing of the Acquisition, the Company is leasing these properties from the real estate investment trust on a long-term basis.

 

•

A third-party purchased substantially all of the crude oil inventory associated with operations of the refinery directly from Marathon.

The Acquisition was accounted for by the purchase method of accounting for business combinations. The excess of the estimated fair value of the net assets acquired over total purchase consideration was recorded as an estimated bargain purchase gain during 2010. This gain was a result of the market dynamics from the time the purchase price was agreed upon compared to the market as of the closing date of the Acquisition.

The accompanying consolidated financial statements include the following fair value allocation of the purchase of the net assets acquired:

 

(in millions)
Total consideration		$	608.0
Allocation of consideration:
Store cash acquired			0.6
Inventory			195.0
Property, plant and equipment			385.0
Minnesota Pipe Line investment			93.0
MPLI investment			7.0
Intangible assets			35.4
Margin support contract			17.3
Derivative liability			(40.9	)
Lease financing obligation			(24.5	)
Other, net			(8.5	)
Bargain purchase gain		$	(51.4	)

At this time, the valuations and other studies needed to provide a final basis for estimating the fair value of the net assets acquired have been completed.

 

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MPC agreed to provide the Company with administrative and support services subsequent to the Acquisition pursuant to a transition services agreement, including finance and accounting, human resources, and information systems services, as well as support services generally for a period of up to eighteen months in connection with the transition from being a part of MPC’s systems and infrastructure to having its own systems and infrastructure. The transition services agreement required the Company to pay MPC for the provision of the transition services, as well as to reimburse MPC for compensation paid to MPC employees providing such transition services. In addition, under the agreement, Marathon provided support services for the operation of the refining and retail business segments, using the employees that were ultimately expected to be transitioned to the Company. The Company was obligated to reimburse MPC for the compensation paid to MPC employees providing such operations services, plus the agreed burden rates. MPC was obligated to provide these services to the Company for twelve months from the Acquisition date, but the services could be extended for an additional six months beyond the initial twelve month period, if necessary. The transition services agreement may be terminated by a mutual agreement of the parties, and the Company or MPC may also unilaterally terminate the agreement upon a material breach by the other party. For the year ended December 31, 2011, the Company has recognized expenses of approximately $15.0 million related to administrative and support services. The Company also paid $6.7 million in December 2010 of which $6.1 million was amortized during 2011 as these services were incurred. The majority of transition services have been completed as of December 31, 2011.

5. INCOME TAXES

For the period subsequent to the Acquisition, the Company is a pass through entity for federal income tax purposes. As a result, there are no federal income taxes incurred. For the year ended December 31, 2011 and the Successor Period ended December 31, 2010 the Company incurred state income taxes of less than $0.1 million.

For all periods prior to the Acquisition, the taxable results of the Predecessor were included in the consolidated U.S. federal and various state and local tax returns of Marathon Oil. Also, in certain state, local and foreign jurisdictions, the Predecessor filed on a stand-alone basis. The tax provisions and related balance sheet disclosures for the period prior to the closing of the Acquisition have been prepared assuming the Predecessor was a stand-alone taxpayer for the periods presented.

The components of the Predecessor’s income tax provision are as follows:

 

		Predecessor
(in millions)		Eleven Months  Ended November 30, 2010				Year Ended December 31, 2009
Income Tax Provision
Federal
Current		$	51.2			$	25.9
Deferred			(0.6	)			0.4
		$	50.6			$	26.3
State and local
Current		$	16.7			$	8.4
Deferred			(0.2	)			0.1
		$	16.5			$	8.5
Total
Current		$	67.9			$	34.3
Deferred			(0.8	)			0.5
		$	67.1			$	34.8

 

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A reconciliation of the federal statutory income tax rate (35 percent) for the Predecessor applied to income before income taxes to the provision for income taxes is as follows:

 

		Predecessor
(in millions)		Eleven Months  Ended November 30, 2010				Year Ended December 31, 2009
Statutory rate applied to income before taxes		$	44.8			$	31.3
State and local income taxes, net of federalincome tax effects			10.7				5.5
Domestic manufacturing deductions			(2.6	)			(1.2	)
Valuation allowance for capital loss carryforward			14.3				—
Dividend received deduction			(0.2	)			(0.9	)
Other, net			0.1				0.1
Actual income tax provision		$	67.1			$	34.8

As further described in Note 10, net income for the eleven months ended November 30, 2010 included unrealized losses of $40.9 million related to derivative instruments held on November 30, 2010. For income tax purposes, MPC must classify gains and losses on these instruments as capital gains and losses. These capital losses may only be deducted for tax purposes to the extent of capital gains. For the purposes of the combined financial statements, management believes it is more likely than not that the Predecessor will not generate sufficient future capital gains to realize the capital losses. As such, a valuation allowance has been provided for the full value of the tax benefits related to these unrealized losses.

The results of Speedway, SuperMom’s LLC and the interest in Minnesota Pipe Line were included in the income tax returns of MPC LP prior to January 1, 2010. Beginning in 2010, the activity of these businesses was included in Marathon Oil’s income tax returns. MPC LP and Marathon Oil are continuously undergoing examination of their U.S. federal income tax returns by the Internal Revenue Service. Such audits have been completed through the 2007 tax year. MPC LP and Marathon Oil believe they have made adequate provision for federal income taxes and interest which may become payable for years not yet settled. Further, MPC LP and Marathon Oil are routinely involved in Minnesota tax audits. MPC LP and Marathon Oil believe all other audits will be resolved within the amounts paid and/or provided for these liabilities.

The Company (and previously, the Predecessor) follows the provisions of ASC 740 related to accounting for uncertainties in income taxes. No unrecognized tax benefits are recorded by the Company as of December 31, 2011 and 2010.

6. INVENTORIES

 

(in millions)		December 31, 2011				December 31, 2010
Crude oil and refinery feedstocks		$	9.1			$	24.3
Refined products			109.1				102.7
Merchandise			21.1				14.8
Supplies and sundry items			14.8				14.6
Total		$	154.1			$	156.4

The LIFO method accounted for 77% and 81% of total inventory value at December 31, 2011 and 2010, respectively. Current acquisition costs were estimated to exceed the LIFO inventory value by $20.0 million and

 

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$2.1 million at December 31, 2011 and 2010, respectively. During 2011, reductions in quantities of crude oil and refinery feedstocks inventory resulted in a liquidation of LIFO inventory quantities acquired at lower costs in prior years. The 2011 LIFO liquidation resulted in a decrease in cost of sales of approximately $4.1 million. As a result of LIFO inventory liquidations in prior periods, cost of sales decreased and income from operations increased by $2.1 million, $2.1 million and $1.7 million for the Successor Period ended December 31, 2010, the eleven months ended November 30, 2010, and the year ended December 31, 2009, respectively.

7. EQUITY METHOD INVESTMENT

The Company (and previously, the Predecessor) has a 17% common interest in Minnesota Pipe Line. The carrying value of this equity method investment was $89.9 million and $92.4 million at December 31, 2011 and 2010, respectively.

Summarized financial information for Minnesota Pipe Line is as follows:

 

		Successor										Predecessor
(in millions)		Year Ended December  31, 2011				One Month Ended December  31, 2010						Eleven Months  Ended November 30, 2010				Year Ended December  31, 2009
Revenues		$	115.6			$	8.7					$	101.6			$	101.5
Operating costs and expenses			53.8				7.4						36.8				55.6
Income from operations			43.2				1.3						42.4				18.4
Net income			43.2				1.3						42.4				18.4
Net income available to common shareholders			33.5				0.5						33.6				8.7

 

		Successor
(in millions)		December 31, 2011				December 31, 2010
Balance sheet data:
Current assets		$	12.1			$	8.0
Noncurrent assets			492.8				507.6
Total assets		$	504.9			$	515.6
Current liabilities		$	16.6			$	13.8
Noncurrent liabilities			0.1				0.2
Total liabilities		$	16.7			$	14.0
Members capital		$	488.2			$	501.6

As of December 31, 2011 and 2010, the carrying amount of the equity method investment was $6.9 million and $7.1 million higher than the underlying net assets of the investee, respectively. The Company is amortizing this difference over the remaining life of Minnesota Pipe Line’s primary asset (the fixed asset life of the pipeline).

Distributions received from Minnesota Pipe Line were $8.0 million for the year ended December 31, 2011, $0.7 for the Successor Period ended December 31, 2010, $6.0 million for the eleven months ended November 30, 2010 and $1.4 million for the year ended December 31, 2009.

 

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8. PROPERTY, PLANT AND EQUIPMENT

Major classes of property, plant and equipment (“PP&E”) consisted of the following:

 

(in millions)		Estimated Useful Lives		December 31, 2011				December 31, 2010
Land				$	8.7			$	8.7
Retail stores and equipment		2 - 22 years			50.4				61.2
Refinery and equipment		5 - 24 years			318.1				271.2
Software		5 years			14.7				—
Other equipment		2 - 7 years			1.9				1.8
Precious metals					10.5				10.5
Assets under construction					17.4				35.1
					421.7				388.5
Less: accumulated depreciation					30.5				2.2
Property, plant and equipment, net				$	391.2			$	386.3

PP&E included gross assets acquired under capital leases of $12.5 million and $12.5 million with related amounts of accumulated depreciation and amortization of $1.4 million and less than $0.1 million at December 31, 2011 and 2010, respectively.

9. INTANGIBLE ASSETS

Intangible assets were ascribed value as a result of the Acquisition and are comprised of franchise rights amounting to $19.8 million and trademarks amounting to $15.6 million at both December 31, 2011 and 2010. These assets have an indefinite life and therefore are not amortized, but rather are tested for impairment annually or sooner if events or changes in circumstances indicate that the fair value of the intangible asset has been reduced below carrying value.

10. DERIVATIVES

The Company is subject to crude oil and refined product market price fluctuations caused by supply conditions, weather, economic conditions and other factors. In October 2010, at the request of the Company, MPC initiated a crack spread derivative strategy to mitigate refining margin risk on a portion of the business’ 2011 and 2012 projected refinery production. In connection with the Acquisition, derivative instruments executed pursuant to this strategy, along with all corresponding rights and obligations, were assumed by the Company. The Company also may periodically use futures contracts to manage price risks associated with inventory quantities above or below target levels.

Under the derivative strategy, the Company agrees to buy or sell an amount equal to a fixed price times a certain number of barrels, and to buy or sell in return an amount equal to a specified variable price times the same amount of barrels. Physical volumes are not exchanged and these contracts are net settled with cash. The contracts are not being accounted for as hedges for financial reporting purposes. The Company recognizes all derivative instruments as either assets or liabilities at fair value on the balance sheet and any related net gain or loss is recorded as a gain or loss in the derivative activity caption on the consolidated and combined statements of income. Observable quoted prices for similar assets or liabilities in active markets (Level 2 as described in Note 12) are considered to determine the fair values for the purpose of marking to market the derivative instruments at each period end. At December 31, 2011, the Company had open commodity derivative instruments consisting of crude oil futures to buy 17 million barrels and refined products futures and swaps to sell 17 million barrels primarily to protect the value of refining margins through 2012. For the year ended December 31, 2011, there were losses related to derivative activities of $352.2 million. Of these total losses, $310.3 million represented realized losses on settled contracts and $41.9 million represented unrealized losses on open contracts for the year ended December 31, 2011.

 

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At December 31, 2010, the Company had open commodity derivative instruments consisting of crude oil futures and finished product swaps on 35 million barrels. For the Successor Period ended December 31, 2010 and for the eleven months ended November 30, 2010, there were unrealized losses related to derivative activities of $27.1 million and $40.9 million, respectively.

The following table summarizes the fair value amounts of the Company’s outstanding derivative instruments by location on the balance sheet as of December 31, 2011 and 2010:

 

(in millions)		Balance Sheet Classification				December 31, 2011				December 31, 2010
Commodity swaps and futures			Current liabilities			$	109.9			$	45.6
Commodity swaps and futures			Noncurrent liabilities				—				22.4
						$	109.9			$	68.0

Under the Company’s crack spread derivative strategy, the Company is exposed to credit risk in the event of nonperformance by its counterparty on these derivative instruments. The counterparty is a large financial institution with a credit rating as of December 31, 2011 of at least A- by Standard and Poor’s and A1 by Moody’s. In the event of default, the Company would potentially be subject to losses on a derivative instrument’s mark-to-market gains. The Company does not expect nonperformance on any of its derivative instruments.

The Company has provided letters of credit for a fixed dollar amount under its asset-based revolving credit facility (as discussed in Note 11) to the counterparty on the derivative instruments utilized under the crack spread derivative strategy. The Company is not subject to any margin calls for these crack spread derivatives and the counterparty does not have the right to demand any additional collateral beyond the aforementioned fixed dollar letters of credit. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument.

11. DEBT

In connection with the Acquisition, the Company entered into various financing arrangements including $290.0 million of 10.50% Senior Secured Notes due December 1, 2017 (“Secured Notes”) and a $300 million secured asset-based revolving credit facility (“ABL Facility”).

Secured Notes

The Secured Notes are guaranteed, jointly and severally, on a senior secured basis by all of the Company’s existing and future direct and indirect subsidiaries; however, not on a full and unconditional basis as a result of subsidiaries being able to be released as guarantors under certain customary circumstances for such arrangements. A subsidiary guarantee can be released under customary circumstances, including (a) the sale of the subsidiary, (b) the subsidiary is declared “unrestricted,” (c) the legal or covenant defeasance or satisfaction and discharge of the indenture, or (d) liquidation or dissolution of the subsidiary. Separate condensed consolidating financial information is not included as the Company does not have independent assets or operations. The Company is required to make interest payments on June 1 and December 1 of each year, commencing on June 1, 2011. There are no scheduled principal payments required prior to the notes maturing on December 1, 2017. Borrowings bear interest at 10.50%.

At any time prior to the maturity date of the notes, the Company may, at its option, redeem all or any portion of the notes for the outstanding principal amount plus unpaid interest and a make-whole premium as defined in the indenture. If the Company experiences a change in control or makes certain asset dispositions, as defined under the indenture, the Company may be required to repurchase all or part of the notes plus unpaid interest and in certain cases pay a redemption premium.

 

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The Secured Notes contain a number of covenants that, among other things, restrict the ability, subject to certain exceptions, of the Company and its subsidiaries to sell or otherwise dispose of assets, including capital stock of subsidiaries, incur additional indebtedness or issue preferred stock, repay other indebtedness, pay dividends and distributions or repurchase capital stock, create liens on assets, make investments, loans or advances, make certain acquisitions, engage in mergers or consolidations, engage in certain transactions with affiliates, change the business conducted by itself and its subsidiaries, and enter into agreements that restrict dividends from restricted subsidiaries.

ABL Facility

The ABL Facility provides for revolving credit financing through December 1, 2015 in an aggregate principal amount of up to $300 million (of which $150 million may be utilized for the issuance of letters of credit and up to $30 million may be short-term borrowings upon same-day notice, referred to as swingline loans) and may be increased up to a maximum aggregate principal amount of $400 million, subject to borrowing base availability and lender approval. Availability under the ABL Facility at any time will be the lesser of (a) the aggregate commitments under the ABL Facility or (b) the borrowing base, less any outstanding borrowings and letters of credit. The borrowing base is calculated based on a percentage of eligible accounts receivable, petroleum inventory and other assets.

Borrowings under the ABL Facility bear interest, at the Company’s option, at either (a) an alternative base rate, plus an applicable margin (ranging between 1.75% and 2.25%) or (b) a LIBOR rate plus applicable margin (ranging between 2.75% and 3.25%). The alternate base rate is the greater of (a) the prime rate, (b) the Federal Funds Effective rate plus 50 basis points, or (c) one-month LIBOR rate plus 100 basis points and a spread of up to 225 basis points based upon percentage utilization of this facility. In addition to paying interest on outstanding borrowings, the Company is also required to pay an annual commitment fee ranging from 0.375% to 0.625% and letter of credit fees.

As of December 31, 2011, the availability under the ABL Facility was $108.0 million. This availability is net of $61.6 million in outstanding letters of credit. The Company had no borrowings under the ABL Facility at December 31, 2011 and 2010.

The ABL Facility has a minimum fixed charge coverage ratio financial covenant requirement of at least 1.0 to 1.0. The covenant is operative when the Company’s availability under the facility is less than the greater of (a) 15% of the lesser of the $300 million commitment amount or the borrowing base or (b) $22.5 million.

The ABL Facility also contains a number of covenants that, among other things, restrict, subject to certain exceptions, the ability of the Company and its subsidiaries to sell or otherwise dispose of assets, incur additional indebtedness or issue preferred stock, pay dividends and distributions or repurchase capital stock, create liens on assets, make investments, loans or advances, make certain acquisitions, engage in mergers or consolidations, and engage in certain transactions with affiliates.

12. FAIR VALUE MEASUREMENTS

As defined in accounting guidance, fair value is the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Accounting guidance describes three approaches to measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The

 

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cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

Accounting guidance does not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. Accounting guidance establishes a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

 

•

Level 1—Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

 

•

Level 2—Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

 

•

Level 3—Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

The Company uses a market or income approach for recurring fair value measurements and endeavors to use the best information available. Accordingly, valuation techniques that maximize the use of observable inputs are favored. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

The Company’s current asset and liability accounts contain certain financial instruments, the most significant of which are trade accounts receivables and trade payables. The Company believes the carrying values of its current assets and liabilities approximate fair value. The Company’s fair value assessment incorporates a variety of considerations, including the short-term duration of the instruments, the Company’s historical incurrence of insignificant bad debt expense and the Company’s expectation of future insignificant bad debt expense, which includes an evaluation of counterparty credit risk.

The following table provides the assets and liabilities carried at fair value measured on a recurring basis at December 31, 2011 and 2010:

 

(in millions)		Balance at December 31, 2011				Quoted prices  in active markets (Level 1)				Significant other observable inputs (Level 2)				Unobservable inputs (Level 3)
ASSETS
Cash and cash equivalents		$	123.5			$	123.5			$	—			$	—
Other assets
Contingent consideration—margin support			20.2				—				—				20.2
		$	143.7			$	123.5			$	—			$	20.2
LIABILITIES
Derivative liability—current		$	109.9			$	—			$	109.9			$	—
Other liabilities
Contingent consideration—earn-out			30.9				—				—				30.9
		$	140.8			$	—			$	109.9			$	30.9

 

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(in millions)		Balance at December 31, 2010				Quoted prices  in active markets (Level 1)				Significant other observable inputs (Level 2)				Unobservable inputs (Level 3)
ASSETS
Cash and cash equivalents		$	72.8			$	72.8			$	—			$	—
Other assets
Contingent consideration—margin support			17.3				—				—				17.3
		$	90.1			$	72.8			$	—			$	17.3
LIABILITIES
Derivative liability—current		$	45.6			$	—			$	45.6			$	—
Derivative liability—long-term			22.4				—				22.4				—
Other liabilities
Contingent consideration—earn-out			53.8				—				—				53.8
		$	121.8			$	—			$	68.0			$	53.8

The Company determines the fair value of its contingent consideration arrangements (margin support and earn-out) based on a probability-weighted income approach derived from financial performance estimates. The impacts of changes in the fair value of these arrangements are recorded in the statements of income as contingent consideration income, net. Changes in the fair value of the Company’s Level 3 contingent consideration arrangements during the year ended December 31, 2011 were due to updated financial performance estimates and are as follows:

 

(in $ millions)		Margin Support				Earnout				Net Impact
Fair Value at December 31, 2010		$	17.3			$	(53.8	)		$	(36.5	)
Transfer to Receivable from MPC (included in other current assets)			(30.0	)			—				(30.0	)
Change in fair value of remaining years			32.9				22.9				55.8
Fair Value at December 31, 2011		$	20.2			$	(30.9	)		$	(10.7	)

Assets not recorded at fair value on a recurring basis, such as property, plant and equipment, intangible assets and cost method investments are recognized at fair value when they are impaired. During the year ended December 31, 2011, there were no adjustments to the fair value of such assets. The Company recorded assets acquired and liabilities assumed in the Acquisition at fair value.

The carrying value of debt, which is reported on the Company’s consolidated balance sheets, reflects the cash proceeds received upon its issuance, net of subsequent repayments. The fair value of the Secured Notes disclosed below was determined based on quoted prices in active markets.

 

		December 31, 2011								December 31, 2010
(in millions)		Carrying Amount				Fair Value				Carrying Amount				Fair Value
Secured Notes		$	290.0			$	316.5			$	290.0			$	299.4

 

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13. ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in asset retirement obligations:

 

		Successor										Predecessor
(in millions)		Year Ended December  31, 2011				June  23, 2010 (inception date) to December 31, 2010						Eleven Months Ended November 30, 2010				Year Ended December  31, 2009
Asset retirement obligation balance at beginning of period		$	2.1			$	2.1					$	3.3			$	3.3
Revisions of previous estimates			(0.9	)			—						—				(0.1	)
Accretion expense (included in depreciation and amortization)			0.3				—						0.2				0.2
Liabilities settled			—				—						(0.1	)			(0.1	)
Asset retirement obligation balance at end of year		$	1.5			$	2.1					$	3.4			$	3.3

As a result of the Acquisition, the asset retirement obligation of the Predecessor was adjusted to a fair value of $2.1 million. Accretion expense for the year ended December 31, 2011 and the Successor Period ended December 31, 2010 was $0.3 million and less than $0.1 million, respectively.

14. STOCK-BASED COMPENSATION

NTI sponsors an equity participation plan which provides for the grant of profit interest units to certain employees and independent non-employee directors of the Company. The plan has reserved approximately 29 million units for issuance under the plan. The exercise price for a unit shall not be less than 100% of the fair market value of our equity units on the date of grant. Units vest in annual installments over a period of five years after the date of grant and expire ten years after the date of grant.

A summary of profit interest unit activity is set forth below:

 

		Number of Units (in millions)				Weighted Average Exercise Price				Weighted Average Remaining Contractual Term
Outstanding at inception			—			$	—
Granted			22.7				1.78
Outstanding at December 31, 2010			22.7				1.78				9.9
Granted			3.5				2.23
Cancelled			(2.0	)			(1.38	)
Outstanding at December 31, 2011			24.2			$	1.87				9.2

 

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The estimated weighted average fair value as of grant date of units granted during 2011 and 2010 was $0.57 and $0.30, respectively, based upon the following assumptions:

 

		2011		2010
Expected life (years)		5.75 - 6.5		6.5
Expected volatility		40.6% - 49.6%		40.6%
Expected dividend yield		0.0%		0.0%
Risk-free interest rate		2.5% - 2.7%		2.7%

The weighted average expected life for the grants is calculated using the simplified method, which defines the expected life as the average of the contractual term of the options and the weighted average vesting period. Expected volatility for the grants is based primarily on the historical volatility of a representative group of peer companies for a period consistent with the expected life of the awards.

For the year ended December 31, 2011 and the Successor Period ended December 31, 2010, the Company recognized $1.6 million and $0.1 million, respectively, of compensation costs related to profit interest units. As of December 31, 2011, the total unrecognized compensation cost for profit interest units was $7.0 million. This non-cash expense will be recognized on a straight line basis through 2016.

15. EMPLOYEE BENEFIT PLANS

Defined Contribution Plans

During 2011, the Company began sponsoring qualified defined contribution plans (collectively, the “Retirement Savings Plans”) for eligible employees. Eligibility is based upon a minimum age requirement and a minimum level of service. Participants may make contributions for a percentage of their annual compensation subject to Internal Revenue Service limits. The Company provides a matching contribution at the rate of 100% of up to between 4.5% and 7.0% (depending on the participant group) of a participant’s contribution. The Company also provides a non-elective fixed annual contribution of 2.0% to 3.5% of eligible compensation depending on the participant group. Total Company contributions to the Retirement Savings Plans were $0.6 million for the year ended December 31, 2011.

Defined Benefit Plan

During 2011, the Company also began to sponsor a defined benefit cash balance pension plan (the “Cash Balance Plan”) for eligible employees. Company contributions are made to the cash account of the participants equal to 5.0% of eligible compensation. Participants’ cash accounts also receive interest credits each year based upon the average thirty year United States Treasury bond rate published in September preceding the respective plan year. Participants become fully vested in their accounts after three years of service.

 

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Funded Status and Net Period Benefit Costs

The changes to the benefit obligation, fair value of plan assets and funded status of the Cash Balance Plan for the year ended December 31, 2011 were as follows:

 

(in millions)		Year Ended December 31, 2011
Change in benefit obligation:
Benefit obligation at beginning of year		$	—
Service cost			0.1
Plan amendments			0.4
Benefit obligation at end of year		$	0.5
Change in plan assets:
Fair value of plan assets at beginning of year		$	—
Employer contributions			0.1
Fair value of plan assets at end of year		$	0.1
Reconciliation of funded status:
Fair value of plan assets at end of year		$	0.1
Benefit obligation at end of year			0.5
Funded status at end of year		$	(0.4	)

At December 31, 2011, the projected benefit obligations exceeded the fair value of plan assets by $0.4 million. This unfunded pension obligation is classified in other liabilities on the consolidated balance sheet.

The components of net period benefit cost and other amounts recognized in member’s interest related to the Cash Balance Plan for the year ended December 31, 2011 were as follows:

 

		Year Ended December 31, 2011
Components of net periodic benefit cost:
Service cost		$	0.1
Net periodic benefit cost		$	0.1
Changes recognized in member’s interest:
Prior service cost		$	0.4
Total changes recognized in member’s interest		$	0.4

Assumptions

The weighted average assumptions used to determine the Company’s benefit obligation are as follows:

 

		December 31, 2011
Discount rate			4.75	%
Rate of compensation increase			4.00	%

 

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The weighted average assumptions used to determine the net period benefit cost are as follows:

 

		Year Ended December 31, 2011
Discount rate			5.00	%
Expected long-term rate of return on plan assets			4.50	%
Rate of compensation increase			4.00	%

The assumptions used in the determination of the Company’s obligations and benefit cost are based upon management’s best estimates as of the annual measurement date. The discount rate utilized was based upon bond portfolio curves over a duration similar to the Cash Balance Plan’s expected future cash flows as of the measurement date. The expected long-term rate of return on plan assets is the weighted average rate of earnings expected of the funds invested or to be invested based upon the targeted investment strategy for the plan. The assumed average rate of compensation increase is the average annual compensation increase expected over the remaining employment periods for the participating employees.

Contributions, Plan Assets and Estimated Future Benefit Payments

Employer contributions were made during December 2011 based upon ERISA’s minimum required funding amounts. These contributions were invested entirely into a money market fund which is deemed a Level 1 asset as described in Note 12. The Company expects funding requirements of approximately $0.4 million during 2012.

At December 31, 2011, anticipated benefit payments to participants from the Cash Balance Plan in future years are as follows:

 

(in millions)
2012		$	—
2013			0.1
2014			0.2
2015			0.3
2016			0.4
2017-2021			3.8

16. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information is as follows:

 

		Successor										Predecessor
(in millions)		Year Ended December 31, 2011				June 23, 2010 (inception date) to December 31, 2010						Eleven Months Ended November 30, 2010				Year Ended December  31, 2009
Net cash from operating activities included:
Interest paid		$	37.9			$	—					$	—			$	—
Income taxes paid through MPC LP and Speedway			—				—						67.9				34.3
Noncash investing and financing activities include:
PP&E recognized (derecognized) in sale leaseback		$	(12.1	)		$	24.5					$	—			$	—
Acquisition consideration funded by Investors			—				80.0						—				—
PP&E contributions by (distributions to) Marathon			—				—						0.6				(0.1	)

 

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17. LEASING ARRANGEMENTS

As described in Note 4, concurrent with the Acquisition, certain Marathon assets (including real property interests and land related to 135 of the SuperAmerica convenience stores and the SuperMom’s bakery) were sold to a third party equity real estate investment trust. In connection with the closing of the Acquisition, the Company has assumed the leasing of these properties from the real estate investment trust on a long-term basis.

In accordance with ASC 840-40, the Company determined that subsequent to the sale, it had a continuing involvement for a portion of these property interests due to potential environmental obligations or due to subleasing arrangements. For these respective properties, the fair value of the assets and the related financing obligation will remain on the Company’s consolidated balance sheet until the end of the lease term or until the continuing involvement is resolved. The assets are included in property, plant and equipment and are being depreciated over their remaining useful lives. The lease payments relating to these property interests are recognized as interest expense. During 2011, the Company’s continuing involvement ended for a subset of these stores and, as such, the related fair value of the assets and the financing obligation for these stores have been removed from the Company’s consolidated balance sheet.

The remainder of properties sold to the third party real estate investment trust are treated as operating leases. The Company (and previously, the Predecessor) also leases a variety of facilities and equipment under other operating leases, including land and building space, office equipment, vehicles, rail tracks for storage of rail tank cars near the refinery and numerous rail tank cars.

Future minimum commitments for operating lease obligations having an initial or remaining non-cancelable lease terms in excess of one year are as follows:

 

(in millions)
2012		$	22.2
2013			21.9
2014			21.7
2015			21.2
2016			20.9
Thereafter			180.3
Total noncancelable operating lease payments		$	288.2

Rental expense was $24.2 million, $2.2 million, $5.3 million and $5.2 million for the year ended December 31, 2011, the Successor Period ended December 31, 2010, the eleven month period ended November 30, 2010, and for the year ended December 31, 2009, respectively. Rental expense includes operating leases with initial or remaining non-cancelable terms of less than one year.

18. CONTINGENCIES AND COMMITMENTS

The Company and the Predecessor are the subject of, or party to, contingencies and commitments involving a variety of matters. Certain of these matters are discussed below. The ultimate resolution of these contingencies could, individually or in the aggregate, be material to the Company’s consolidated and combined financial statements. However, management believes that the Company will remain a viable and competitive enterprise even though it is possible that these contingencies could be resolved unfavorably.

Contingent Consideration

As described in Note 4, the Acquisition provides for contingent consideration, or earn-out payments, that could result in additional payments of up to a total of $125 million to MPC over an eight year period ending December 1, 2018 based on operating performance. The Acquisition agreement also includes a margin support

 

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component that requires Marathon to pay the Company up to $30 million per year to the extent the Agreement Adjusted EBITDA is below $145 million less, among other things, any rental expense related to the real estate lease arrangement, in either of the first two twelve month periods ending November 30, 2011 or 2012 up to a maximum of $60 million. Any such payments made by Marathon will increase the amount that we may be required to pay Marathon over the earn-out period. See Note 12 for additional information relating to the fair value of contingent arrangements related to the Acquisition. As of December 31, 2011, the Company has recorded a receivable of $30.0 million relating to the margin support component of the contingent consideration arrangement for the first twelve months ended November 30, 2011. MPC has disputed approximately $12 million of this amount. While the Company cannot predict the resolution of the dispute at this time, management believes the outcome will not have a material effect on the Company’s consolidated financial position or liquidity.

Environmental Matters

The Company and the Predecessor are subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance. At December 31, 2011 and 2010, liabilities for remediation totaled $4.7 million and $3.5 million, respectively. These liabilities are expected to be settled over at least the next 10 years. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties that may be imposed. Furthermore, environmental remediation costs may vary from estimates because of changes in laws, regulations and their interpretation; additional information on the extent and nature of site contamination; and improvements in technology. Receivables for recoverable costs from the state, under programs to assist companies in clean-up efforts related to underground storage tanks at retail marketing outlets, were $0.2 million at both December 31, 2011 and 2010.

Franchise Agreements

In the normal course of its business, SAF enters into ten year license agreements with the operators of franchised SuperAmerica brand retail outlets. These agreements obligate SAF or its affiliates to provide certain services including information technology support, maintenance, credit card processing and signage for specified monthly fees.

Guarantees

Over the years, the Predecessor has sold various assets in the normal course of business. Certain of the related agreements contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require the Predecessor to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications are part of the normal course of selling assets. The Company has assumed these guarantees and indemnifications upon the Acquisition. However, in certain cases, MPC has also provided an indemnification in favor of the Company.

The Company is not typically able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the Company has little or no past experience associated with the underlying triggering event upon which a reasonable prediction of the outcome can be based. The Company is not currently making any payments relating to such guarantees or indemnifications.

 

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19. SEGMENT INFORMATION

The Company has two reportable operating segments: Refining and Retail. Each of these segments is organized and managed based upon the nature of the products and services they offer. The segment disclosures reflect management’s current organizational structure.

 

•

Refining—operates the St. Paul Park, Minnesota, refinery, terminal and related assets, including the Company’s interest in MPLI and Minnesota Pipe Line, and

 

•

Retail—operates 166 convenience stores primarily in Minnesota and Wisconsin. The Retail segment also includes the operations of NTB and SAF.

The Company’s interest in MPLI and Minnesota Pipe Line were previously presented within the “Other” segment by the Predecessor. Additionally, the Company’s presentation of certain sales to franchisees is different from the Predecessor’s practice. All Predecessor period information has been recast to conform to the current presentation.

Operating results for the Company’s operating segments are as follows:

 

(in millions)		Refining				Retail				Other				Total
Year ended December 31, 2011
Revenues
Customer		$	2,761.0			$	1,519.8			$	—			$	4,280.8
Intersegment			1,043.1				—				—				1,043.1
Segment revenues			3,804.1				1,519.8				—				5,323.9
Elimination of intersegment revenues			—				—				(1,043.1	)			(1,043.1	)
Total revenues		$	3,804.1			$	1,519.8			$	(1,043.1	)		$	4,280.8
Income from operations		$	388.2			$	14.0			$	20.4			$	422.6
Income from equity method investment		$	5.7			$	—			$	—			$	5.7
Depreciation and amortization		$	21.5			$	7.2			$	0.8			$	29.5
Capital expenditures		$	33.9			$	9.2			$	2.8			$	45.9
(in millions)		Refining				Retail				Other				Total
Period ended December 31, 2010 (Successor)
Revenues
Customer		$	242.0			$	102.9			$	—			$	344.9
Intersegment			70.2				—				—				70.2
Segment revenues			312.2				102.9				—				415.1
Elimination of intersegment revenues			—				—				(70.2	)			(70.2	)
Total revenues		$	312.2			$	102.9			$	(70.2	)		$	344.9
Income (loss) from operations		$	9.1			$	0.5			$	(5.9	)		$	3.7
Income from equity method investment		$	0.1			$	—			$	—			$	0.1
Depreciation and amortization		$	1.7			$	0.5			$	—			$	2.2
Capital expenditures		$	2.5			$	—			$	—			$	2.5

 

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(in millions)		Refining				Retail				Other				Total
Eleven months ended November 30, 2010 (Predecessor)
Revenues
Customer		$	1,778.3				1,206.8				—			$	2,985.1
Intersegment			811.4				—				—				811.4
Related parties			210.1				—				—				210.1
Segment revenues			2,799.8				1,206.8				—				4,006.6
Elimination of intersegment revenues			—				—				(811.4	)			(811.4	)
Total revenues		$	2,799.8			$	1,206.8			$	(811.4	)		$	3,195.2
Income from operations		$	142.8			$	26.5			$	—			$	169.3
Income from equity method investment		$	5.4			$	—			$	—			$	5.4
Depreciation and amortization		$	24.9			$	12.4			$	—			$	37.3
Capital expenditures		$	29.4			$	0.4			$	—			$	29.8
(in millions)		Refining				Retail				Other				Total
Year ended December 31, 2009 (Predecessor)
Revenues
Customer		$	1,594.6				1,129.2				—			$	2,723.8
Intersegment			719.4				—				—				719.4
Related parties			216.7				—				—				216.7
Segment revenues			2,530.7				1,129.2				—				3,659.9
Elimination of intersegment revenues			—				—				(719.4	)			(719.4	)
Total revenues		$	2,530.7			$	1,129.2			$	(719.4	)		$	2,940.5
Income from operations		$	70.6			$	19.3			$	—			$	89.9
Income from equity method investment		$	1.1			$	—			$	—			$	1.1
Depreciation and amortization		$	26.0			$	14.2			$	—			$	40.2
Capital expenditures		$	26.1			$	2.9			$	—			$	29.0

Intersegment sales from the Refining segment to the Retail segment consist primarily of sales of refined products which are recorded based on contractual prices that are market based. Revenues from external customers are nearly all in the United States.

Total assets by segment were as follows:

 

(in millions)		Refining				Retail				Other				Total
At December 31, 2011		$	655.2			$	219.8			$	123.8			$	998.8
At December 31, 2010		$	667.7			$	136.7			$	126.2			$	930.6

All property, plant and equipment are located in the United States.

 

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Glossary of Terms Used in This Prospectus

The terms defined in this section are used throughout this prospectus:

“3:2:1 crack spread” refers to the approximate refining margin resulting from processing three barrels of crude oil to produce two barrels of gasoline and one barrel of distillate;

“Barrel” refers to common unit of measure in the oil industry, which equates to 42 gallons;

“Barrels per stream day” as defined by the EIA, represents the maximum number of barrels of input that a distillation facility can process within a 24-hour period when running at full capacity under optimal crude and product slate conditions with no allowance for downtime.

“Blendstocks” refers to various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel; these may include natural gasoline, fluid catalytic cracking unit or FCCU gasoline, ethanol, reformate or butane, among others;

“Bpd” refers to an abbreviation for barrels per calendar day, which is defined by the EIA as the amount of input that a distillation facility can process under usual operating conditions reduced for regular limitations that may delay, interrupt, or slow down production such as downtime due to such conditions as mechanical problems, repairs, and slowdowns;

“Catalyst” refers to a substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process;

“Coke” refers to a coal-like substance that is produced during the refining process;

“Complexity” refers to the number, type and capacity of processing units at a refinery, measured by the Nelson index, which is often used as a measure of a refinery’s ability to process lower cost crude oils into higher value light refined products, including transportation fuels, such as gasoline and distillates;

“Crack spread” refers to a simplified calculation that measures the difference between the price for light products and crude oil;

“Distillates” refers to primarily diesel, kerosene and jet fuel;

“Ethanol” refers to a clear, colorless, flammable oxygenated hydrocarbon. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate;

“Feedstocks” refers to petroleum products, such as crude oil, that are processed and blended into refined products;

“Group 3 3:2:1 crack spread” refers to the 3:2:1 crack spread calculated using the market value of PADD II Group 3 conventional gasoline and ultra low sulfur diesel against the market value of NYMEX WTI;

“Light products” refers to the group of refined products with lower boiling temperatures, including gasoline and distillates;

“Mechanical availability” refers to unit rate capacity less lost capacity due to unplanned downtime less downtime due to planned maintenance divided by unit rated capacity less downtime due to planned maintenance.

 

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“OSHA Recordable Rate” means the injury frequency rate reported by the Company to OSHA, which is equal to the number of recordable injures in a particular period multiplied by 200,000 and divided by the total hours worked in such period, including both employees and contractors;

“PADD II” refers to the Petroleum Administration for Defense District II region of the United States, which covers Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, South Dakota, Ohio, Oklahoma, Tennessee and Wisconsin;

“Refined products” refers to petroleum products, such as gasoline, diesel and jet fuel, which are produced by a refinery;

“Sour crude oil” refers to a crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil;

“Sweet crude oil” refers to a crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil;

“Throughput” refers to the volume processed through a unit or a refinery;

“Turnaround” refers to a periodically required standard procedure to refurbish and maintain a refinery that involves the shutdown and inspection of major processing units and occurs every three to four years on industry average;

“Upper Great Plains” refers to a portion of PADD II region and includes Minnesota, North Dakota, South Dakota and Wisconsin;

“WTI” refers to West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an American Petroleum Institute gravity, or API gravity, between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils; and

“Yield” refers to the percentage of refined products that is produced from crude oil and other feedstocks.

 

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9,000,000 Common Units

Representing Limited Partner Interests

 

Northern Tier Energy LP

 

 

Prospectus

                        , 2013

 

 

Barclays

BofA Merrill Lynch

Goldman, Sachs & Co.

Citigroup

UBS Investment Bank

Credit Suisse

Deutsche Bank Securities

J.P. Morgan

 

 

Macquarie Capital

 

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Part II

Information required in the registration statement

 

ITEM 13.

OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION.

Set forth below are the expenses (other than underwriting discounts and commissions and structuring fees) expected to be incurred in connection with the issuance and distribution of the securities registered hereby. With the exception of the SEC registration fee and the FINRA filing fee, the amounts set forth below are estimates.

 

SEC registration fee		$	34,100
FINRA filing fee			38,000
Printing and engraving expenses			200,000
Fees and expenses of legal counsel			750,000
Accounting fees and expenses			200,000
Transfer agent and registrar fees			1,000
Total		$	1,223,100

 

ITEM 14.

INDEMNIFICATION OF DIRECTORS AND OFFICERS.

The section of the prospectus entitled “The Partnership Agreement—Indemnification” is incorporated herein by reference and discloses that we will generally indemnify our executive officers and the directors and officers of our general partner and our sponsors to the fullest extent permitted by law against all losses, claims, damages or similar events. Subject to any terms, conditions or restrictions set forth in the first amended and restated partnership agreement, Section 17-108 of the Delaware Revised Uniform Limited Partnership Act empowers a Delaware limited partnership to indemnify and hold harmless any partner or other person from and against all claims and demands whatsoever.

Section 18-108 of the Delaware Limited Liability Company Act provides that a Delaware limited liability company may indemnify and hold harmless any member or manager or other person from and against any and all claims and demands whatsoever. The limited liability company agreement of Northern Tier Energy GP LLC, our general partner, provides for the indemnification of its directors and officers against liabilities they incur in their capacities as such. The Registrant may enter into indemnity agreements with each of its current directors and officers to give these directors and officers additional contractual assurances regarding the scope of the indemnification set forth in the Registrant’s limited liability company agreement and to provide additional procedural protections.

The underwriting agreement that we expect to enter into with the underwriters, filed as Exhibit 1.1 to this registration statement, will contain indemnification and contribution provisions.

 

ITEM 15.

RECENT SALES OF UNREGISTERED SECURITIES.

On October 24, 2011, Northern Tier Energy, Inc. issued 100 shares of common stock, par value $0.01 per share, to Northern Tier Investors, LLC for $1.00. The issuance of such shares of common stock was not registered under the Securities Act, because the shares were offered and sold in a transaction exempt from registration under Section 4(2) of the Securities Act.

On June 6, 2012, Northern Tier Energy, Inc. issued 10 shares of common stock, par value $0.01 per share, to Northern Tier Energy GP LLC, for $0.10. The issuance of such shares of common stock were not registered

 

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under the Securities Act, because the shares were offered and sold in a transaction exempt from registration under Section 4(2) of the Securities Act.

On June 6, 2012, in connection with our conversion from Northern Tier Energy Inc. to Northern Tier Energy LP, we issued (i) 100% of our limited partner interests to Northern Tier Holdings LLC and (ii) a non-economic general partner interest to Northern Tier Energy GP LLC. The issuance of such partnership interests was not registered under the Securities Act, because the interests were offered and sold in a transaction exempt from registration under Section 4(2) of the Securities Act.

On July 31, 2012, in connection with the closing of our initial public offering, we issued to Northern Tier Holdings LLC an aggregate of (i) 54,844,500 common units and (ii) 18,383,000 PIK units in exchange for the contribution to us by Northern Tier Holdings LLC of all of the membership interests in Northern Tier Energy LLC. Northern Tier Holdings LLC also owns all of the interest in our general partner who holds a non-economic interest in us. This issuance was exempt from registration under Section 4(2) of the Securities Act.

Each of the PIK units converted into common units effective November 9, 2012.

On November 8, 2012 Northern Tier Energy LLC and Northern Tier Finance Corporation completed a private placement of $275,000,000 in aggregate principal amount of 7.125% senior secured notes due 2020. The issuance of such notes was not registered under the Securities Act, because the notes were offered and sold to qualified institutional buyers in reliance on Rule 144A under the Securities Act and to non-U.S. persons in offshore transactions in reliance on Regulation S under the Securities Act. The joint book-running managers of the offering were Goldman, Sachs & Co., Deutsche Bank Securities Inc. and J.P. Morgan Securities LLC. The aggregate offering price for the offering was $275,000,000 million, and the underwriting discount was $4,125,000. In connection with the offering, Northern Tier Energy LP issued a parent guarantee which fully and unconditionally guarantees on a senior unsecured basis the obligations under the notes.

There have been no other sales of unregistered securities by us within the past three years.

 

ITEM 16.

EXHIBITS.

The following documents are filed as exhibits to this registration statement:

 

Exhibit Number		Description
**1.1		Form of Underwriting Agreement.
**2.1		Formation Agreement, dated October 6, 2010, by and among Marathon Petroleum Company LP, Speedway SuperAmerica LLC and Northern Tier Investors, LLC (Incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**2.2		St. Paul Park Refining Co. LLC Contribution Agreement, dated October 6, 2010, by and among Marathon Petroleum Company LP, St. Paul Park Refining Co. LLC and Northern Tier Investors, LLC (Incorporated by reference to Exhibit 2.2 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**2.3		Northern Tier Retail LLC Contribution Agreement, dated October 6, 2010, by and among Speedway SuperAmerica LLC, Northern Tier Retail LLC and Northern Tier Investors, LLC (Incorporated by reference to Exhibit 2.3 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**2.4		Northern Tier Bakery LLC Contribution Agreement, dated October 6, 2010, by and among Speedway SuperAmerica LLC, SuperMom’s LLC, Northern Tier Retail LLC and Northern Tier Investors, LLC (Incorporated by reference to Exhibit 2.4 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).

 

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Exhibit Number		Description
**3.1		Certificate of Limited Partnership of Northern Tier Energy LP (Incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1, File No. 333-178457, filed on July 2, 2012).
**3.2		First Amended and Restated Agreement of Limited Partnership of Northern Tier Energy LP, dated July 31, 2012 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K, File No. 001-35612, filed on August 2, 2012).
**4.1		Indenture, dated as of December 1, 2010, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, the subsidiary guarantors parties thereto and Deutsche Bank Trust Company Americas (Incorporated by reference to Exhibit 4.2 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**4.2		Indenture, dated as of November 8, 2012, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, Northern Tier Energy LP, the subsidiary guarantors parties thereto and Deutsche Bank Trust Company Americas (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K, File No. 001-35612, filed on November 13, 2012).
5.1		Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered.
8.1		Opinion of Vinson & Elkins L.L.P. relating to tax matters.
**10.1		Transaction Agreement, dated July 25, 2012 by and among Northern Tier Holdings LLC, Northern Tier Energy GP LLC, Northern Tier Energy LLC, Northern Tier Energy Holdings LLC, Northern Tier Retail Holdings LLC and Northern Tier Energy LP (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on July 30, 2012).
**10.2		Amended and Restated Registration Rights Agreement, dated July 31, 2012, by and among TPG Refining, L.P., ACON Refining Partners, L.L.C., NTI Management Company, L.P., NTR Partners LLC, NTR Partners II LLC, Northern Tier Investors, LLC, Northern Tier Holdings LLC and Northern Tier Energy LP (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K, File No. 001-35612, filed on August 2, 2012).
**10.3		Credit Agreement, dated December 1, 2010, by and among the financial institutions party thereto, J.P. Morgan Chase Bank, N.A., Bank of America, N.A., Macquarie Capital (USA) Inc., Royal Bank of Canada and SunTrust Bank, St. Paul Park Refining Co. LLC, Northern Tier Bakery LLC, Northern Tier Retail LLC, SuperAmerica Franchising LLC, Northern Tier Energy LLC and each other subsidiary of Northern Tier Energy LLC from time to time party thereto (Incorporated by reference to Exhibit 10.5 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**10.4		Employment Agreement between Northern Tier Energy LLC and Mario Rodriguez (Incorporated by reference to Exhibit 10.6 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**10.5		Employment Agreement between Northern Tier Energy LLC and Hank Kuchta (Incorporated by reference to Exhibit 10.7 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**10.6		Offer Letter between Northern Tier Energy LLC and Dave Bonczek, dated February 7, 2011 (Incorporated by reference to Exhibit 10.9 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**10.7		Offer Letter between Northern Tier Energy LLC and Greg Mullins, dated December 1, 2010 (Incorporated by reference to Exhibit 10.8 to the Registration Statement on Form S-1, File No. 333-178457, filed on July 2, 2012).

 

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Exhibit Number		Description
**10.8		Amended and Restated Management Services Agreement, dated as of January 1, 2012, by and among Northern Tier Energy, LLC, TPG VI Management, LLC and ACON Funds Management L.L.C. (Incorporated by reference to Exhibit 10.11 to the Registration Statement on Form S-1, File No. 333-178457, filed on February 10, 2012).
**10.9		Northern Tier Energy LP 2012 Long-Term Incentive Plan (Incorporated by reference to our Current Report on Form 8-K, File No. 001-35612, filed on July 30, 2012).
†**10.10		Amended and Restated Crude Oil Supply Agreement dated March 29, 2012, by and between J.P. Morgan Commodities Canada Corporation and St. Paul Park Refining Co. LLC. (Incorporated by reference to Exhibit 10.9 to Northern Tier Energy LLC’s Registration Statement on Form S-4, File No. 333-178458, filed on April 20, 2012).
**10.11		Settlement Agreement and Release dated May 4, 2012, by and between Northern Tier Energy LLC and Marathon Petroleum Company LP. (Incorporated by reference to Exhibit 10.14 to the Registration Statement on Form S-1, File No. 333-178457, filed on May 7, 2012).
**10.12		First Amendment to the Credit Agreement, dated as of July 17, 2012, by and among the financial institutions party thereto, as the lenders, J.P. Morgan Chase Bank, N.A., as administrative agent and collateral agent, Bank of America, N.A., as syndication agent, and Macquarie Capital (USA) Inc. and SunTrust Bank, as co-documentation agents, and Northern Tier Energy LLC and certain subsidiaries of Northern Tier Energy LLC party thereto (Incorporated by reference to Exhibit 10.13 to the Registration Statement on Form S-1, File No. 333-178457, filed on July 18, 2012).
**10.13		Registration Rights Agreement, dated as of November 8, 2012, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, Northern Tier Energy LP, the subsidiary guarantors parties thereto and Deutsche Bank Trust Company Americas (Incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K, File No. 001-35612, filed on November 13, 2012)
**10.14		Separation Agreement and General Release dated December 21, 2012, between Mario E. Rodriguéz and Northern Tier Energy LLC (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on December 21, 2012).
**21.1		List of subsidiaries of Northern Tier Energy LP.
23.1		Consent of PricewaterhouseCoopers LLP (pertaining to Northern Tier Energy LLC).
23.2		Consent of PricewaterhouseCoopers LLP (pertaining to St. Paul Park Refinery and Retail Marketing Business).
23.3		Consent of Vinson & Elkins L.L.P. (included in Exhibit 5.1).
23.4		Consent of Vinson & Elkins L.L.P. (included in Exhibit 8.1).
**24.1		Power of Attorney.
101.INS		XBRL Instance Document.
101.SCH		XBRL Taxonomy Extension Schema Document.
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB		XBRL Taxonomy Extension Label Linkbase Document.
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

 

*	To be filed by amendment.

**	Previously filed.

†	Certain portions have been omitted pursuant to a confidential treatment request granted on May 14, 2012. Omitted information has been separately filed with the Securities and Exchange Commission.

 

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ITEM 17.

UNDERTAKINGS.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the registrant pursuant to the foregoing provisions, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer or controlling person of the registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.

 

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Signatures

Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Ridgefield, State of Connecticut, on January 16, 2013.

 

Pursuant to the requirements of the Securities Act of 1933, as amended, this Registration Statement has been signed below by the following persons in the capacities and the dates indicated.

 

Signature		Title		Date
/s/ HANK KUCHTA* Hank Kuchta		President, Chief Executive Officer and Director of Northern Tier Energy GP LLC		January 16, 2013
/s/ DAVID BONCZEK* David Bonczek		Chief Financial Officer of Northern Tier Energy GP LLC (Principal Financial Officer and Principal Accounting Officer)		January 16, 2013
/s/ DAN F. SMITH * Dan F. Smith		Director and Executive Chairman of Northern Tier Energy GP LLC		January 16, 2013
/s/ BERNARD W. ARONSON* Bernard W. Aronson		Director of Northern Tier Energy GP LLC		January 16, 2013
/s/ JONATHAN GINNS* Jonathan Ginns		Director of Northern Tier Energy GP LLC		January 16, 2013
/s/ THOMAS HOFMANN* Thomas Hofmann		Director of Northern Tier Energy GP LLC		January 16, 2013
/s/ SCOTT D. JOSEY* Scott D. Josey		Director of Northern Tier Energy GP LLC		January 16, 2013
/s/ ERIC LIAW* Eric Liaw		Director of Northern Tier Energy GP LLC		January 16, 2013
/s/ MICHAEL MACDOUGALL* Michael MacDougall		Director of Northern Tier Energy GP LLC		January 16, 2013

 

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Exhibit Number		Description
**1.1		Form of Underwriting Agreement.
**2.1		Formation Agreement, dated October 6, 2010, by and among Marathon Petroleum Company LP, Speedway SuperAmerica LLC and Northern Tier Investors, LLC (Incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**2.2		St. Paul Park Refining Co. LLC Contribution Agreement, dated October 6, 2010, by and among Marathon Petroleum Company LP, St. Paul Park Refining Co. LLC and Northern Tier Investors, LLC (Incorporated by reference to Exhibit 2.2 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**2.3		Northern Tier Retail LLC Contribution Agreement, dated October 6, 2010, by and among Speedway SuperAmerica LLC, Northern Tier Retail LLC and Northern Tier Investors, LLC (Incorporated by reference to Exhibit 2.3 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**2.4		Northern Tier Bakery LLC Contribution Agreement, dated October 6, 2010, by and among Speedway SuperAmerica LLC, SuperMom’s LLC, Northern Tier Retail LLC and Northern Tier Investors, LLC (Incorporated by reference to Exhibit 2.4 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**3.1		Certificate of Limited Partnership of Northern Tier Energy LP (Incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1, File No. 333-178457, filed on July 2, 2012).
**3.2		First Amended and Restated Agreement of Limited Partnership of Northern Tier Energy LP, dated July 31, 2012 (Incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K, File No. 001-35612, filed on August 2, 2012).
**4.1		Indenture, dated as of December 1, 2010, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, the subsidiary guarantors parties thereto and Deutsche Bank Trust Company Americas (Incorporated by reference to Exhibit 4.2 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**4.2		Indenture, dated as of November 8, 2012, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, Northern Tier Energy LP, the subsidiary guarantors parties thereto and Deutsche Bank Trust Company Americas (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K, File No. 001-35612, filed on November 13, 2012).
5.1		Opinion of Vinson & Elkins L.L.P. as to the legality of the securities being registered.
8.1		Opinion of Vinson & Elkins L.L.P. relating to tax matters.
**10.1		Transaction Agreement, dated July 25, 2012 by and among Northern Tier Holdings LLC, Northern Tier Energy GP LLC, Northern Tier Energy LLC, Northern Tier Energy Holdings LLC, Northern Tier Retail Holdings LLC and Northern Tier Energy LP (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on July 30, 2012).
**10.2		Amended and Restated Registration Rights Agreement, dated July 31, 2012, by and among TPG Refining, L.P., ACON Refining Partners, L.L.C., NTI Management Company, L.P., NTR Partners LLC, NTR Partners II LLC, Northern Tier Investors, LLC, Northern Tier Holdings LLC and Northern Tier Energy LP (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K, File No. 001-35612, filed on August 2, 2012).

 

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Exhibit Number		Description
**10.3		Credit Agreement, dated December 1, 2010, by and among the financial institutions party thereto, J.P. Morgan Chase Bank, N.A., Bank of America, N.A., Macquarie Capital (USA) Inc., Royal Bank of Canada and SunTrust Bank, St. Paul Park Refining Co. LLC, Northern Tier Bakery LLC, Northern Tier Retail LLC, SuperAmerica Franchising LLC, Northern Tier Energy LLC and each other subsidiary of Northern Tier Energy LLC from time to time party thereto (Incorporated by reference to Exhibit 10.5 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**10.4		Employment Agreement between Northern Tier Energy LLC and Mario Rodriguez (Incorporated by reference to Exhibit 10.6 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**10.5		Employment Agreement between Northern Tier Energy LLC and Hank Kuchta (Incorporated by reference to Exhibit 10.7 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**10.6		Offer Letter between Northern Tier Energy LLC and Dave Bonczek, dated February 7, 2011 (Incorporated by reference to Exhibit 10.9 to the Registration Statement on Form S-1, File No. 333-178457, filed on December 13, 2011).
**10.7		Offer Letter between Northern Tier Energy LLC and Greg Mullins, dated December 1, 2010 (Incorporated by reference to Exhibit 10.8 to the Registration Statement on Form S-1, File No. 333-178457, filed on July 2, 2012).
**10.8		Amended and Restated Management Services Agreement, dated as of January 1, 2012, by and among Northern Tier Energy, LLC, TPG VI Management, LLC and ACON Funds Management L.L.C. (Incorporated by reference to Exhibit 10.11 to the Registration Statement on Form S-1, File No. 333-178457, filed on February 10, 2012).
**10.9		Northern Tier Energy LP 2012 Long-Term Incentive Plan (Incorporated by reference to our Current Report on Form 8-K, File No. 001-35612, filed on July 30, 2012).
†**10.10		Amended and Restated Crude Oil Supply Agreement dated March 29, 2012, by and between J.P. Morgan Commodities Canada Corporation and St. Paul Park Refining Co. LLC. (Incorporated by reference to Exhibit 10.9 to Northern Tier Energy LLC’s Registration Statement on Form S-4, File No. 333-178458, filed on April 20, 2012).
**10.11		Settlement Agreement and Release dated May 4, 2012, by and between Northern Tier Energy LLC and Marathon Petroleum Company LP. (Incorporated by reference to Exhibit 10.14 to the Registration Statement on Form S-1, File No. 333-178457, filed on May 7, 2012).
**10.12		First Amendment to the Credit Agreement, dated as of July 17, 2012, by and among the financial institutions party thereto, as the lenders, J.P. Morgan Chase Bank, N.A., as administrative agent and collateral agent, Bank of America, N.A., as syndication agent, and Macquarie Capital (USA) Inc. and SunTrust Bank, as co-documentation agents, and Northern Tier Energy LLC and certain subsidiaries of Northern Tier Energy LLC party thereto (Incorporated by reference to Exhibit 10.13 to the Registration Statement on Form S-1, File No. 333-178457, filed on July 18, 2012).
**10.13		Registration Rights Agreement, dated as of November 8, 2012, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, Northern Tier Energy LP, the subsidiary guarantors parties thereto and Deutsche Bank Trust Company Americas (Incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K, File No. 001-35612, filed on November 13, 2012)
**10.14		Separation Agreement and General Release dated December 21, 2012, between Mario E. Rodriguéz and Northern Tier Energy LLC (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on December 21, 2012).

 

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Exhibit Number		Description
**21.1		List of subsidiaries of Northern Tier Energy LP.
23.1		Consent of PricewaterhouseCoopers LLP (pertaining to Northern Tier Energy LLC).
23.2		Consent of PricewaterhouseCoopers LLP (pertaining to St. Paul Park Refinery and Retail Marketing Business).
23.3		Consent of Vinson & Elkins L.L.P. (included in Exhibit 5.1).
23.4		Consent of Vinson & Elkins L.L.P. (included in Exhibit 8.1).
**24.1		Power of Attorney.
101.INS		XBRL Instance Document.
101.SCH		XBRL Taxonomy Extension Schema Document.
101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB		XBRL Taxonomy Extension Label Linkbase Document.
101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

 

*	To be filed by amendment.

**	Previously filed.

†	Certain portions have been omitted pursuant to a confidential treatment request granted May 14, 2012. Omitted information has been separately filed with the Securities and Exchange Commission.

 

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