Northern Tier Energy 10-K 2013 FY Annual report

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2013
OR
¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from  to

COMMISSION FILE NO.: 001-35612

Northern Tier Energy LP

(Exact name of registrant as specified in its charter)

Delaware	80-0763623
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
38C Grove Street, Suite 100 Ridgefield, Connecticut 06877 (Address of principal executive offices)	06877 (Zip Code)

(Registrant’s telephone number including area code)

(203) 244-6550

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Common Units Representing Limited Partner Interests	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    ý  Yes    ¨  No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    ¨  Yes    ý  No

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    ý  Yes    ¨  No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    ý  Yes    ¨  No

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ¨

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. (Check one)

Large Accelerated Filer	ý	Accelerated Filer	¨
Non-Accelerated Filer	¨	Smaller Reporting Company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    ¨  Yes    ý  No

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed based on the New York Stock Exchange closing price on June 28, 2013 (the last business day of the registrant’s most recently completed second fiscal quarter) was $1,075,915,850.

As of February 26, 2014, Northern Tier Energy LP had 92,309,662 common units outstanding. The common units trade on the New York Stock Exchange under the ticker symbol “NTI.”

DOCUMENTS INCORPORATED BY REFERENCE: None

NORTHERN TIER ENERGY LP

FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2013

TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business.	1
Item 1A.	Risk Factors.	19
Item 1B.	Unresolved Staff Comments.	44
Item 2.	Properties.	44
Item 3.	Legal Proceedings.	45
Item 4.	Mine Safety Disclosures	45
	PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters.	46
Item 6.	Selected Financial Data.	48
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations.	50
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk.	75
Item 8.	Financial Statements and Supplementary Data.	78
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure.	108
Item 9A.	Controls and Procedures.	109
Item 9B.	Other Information.	109
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance.	110
Item 11.	Executive Compensation.	115
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.	129
Item 13.	Certain Relationships and Related Transactions, and Director Independence.	130
Item 14.	Principal Accounting Fees and Services.	132
	PART IV
Item 15.	Exhibits and Financial Statement Schedules

i

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains statements that may constitute forward-looking statements. You can identify these statements by forward-looking words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “plan,” “potential,” “should,” “will,” “would,” or similar words. You should read statements that contain these words carefully because they discuss our current plans, strategies, prospects, and expectations concerning our business, operating results, financial condition, and other similar matters. While we believe that these forward-looking statements are reasonable as and when made, there may be events in the future that we are not able to predict accurately or control, and there can be no assurance that future developments affecting our business will be those that we anticipate. 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. Known material factors that could cause our actual results to differ from those in the forward-looking statements are those described in Part I, “Item 1A. 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 publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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GLOSSARY FOR SELECTED TERMS

“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 a 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 an 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;

“EIA” refers to the Energy Information Administration, an independent agency within the U.S. Department of Energy that develops surveys, collects energy data, and analyzes and models energy issues;

“EPA” refers to the United States Environmental Protection Agency.

“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;

“Marathon” refers to Marathon Petroleum Company LP, an indirect, wholly-owned subsidiary of Marathon Petroleum, and certain affiliates of Marathon Petroleum Company LP.

“Marathon Acquisition” refers to the acquisition by us of our St. Paul Park, Minnesota refinery, a 17% interest in the Minnesota Pipeline, our convenience stores and related assets from Marathon, completed in December 2010;

"Marathon Petroleum” refers to Marathon Petroleum Corporation, a wholly-owned subsidiary of Marathon Oil Corporation until June 30, 2011;

“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;

“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;

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“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 five to six years on industry average;

“Upper Great Plains” refers to a portion of the 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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PART I

Item 1. 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 year ended December 31, 2013, we had total revenues of $5.0 billion, operating income of $238.7 million, net income of $231.1 million and Adjusted EBITDA of $363.2 million. For the year ended December 31, 2012, we had total revenues of $4.7 billion, operating income of $571.0 million, net income of $197.6 million and Adjusted EBITDA of $739.7 million. A definition and reconciliation of Adjusted EBITDA to net income is included herein under the caption “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Adjusted EBITDA.” For financial information related to our business, see "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements included in Part II.

Partnership Structure and Management

We were formed as a Delaware limited partnership by Northern Tier Holdings LLC (“NT Holdings”) in July 2012. Our non-economic general partner interest is held by Northern Tier Energy GP LLC, a Delaware limited liability company. References to our “general partner,” as the context requires, include only Northern Tier Energy GP LLC. Our operations are conducted directly and indirectly through our primary operating subsidiaries. On July 31, 2012, we completed our initial public offering (“IPO”) of 18,687,500 common units, representing an approximate 20.3% ownership interest in the Partnership. In exchange for contributing all of the interests in our operating subsidiaries, NT Holdings received 57,282,000 common units and 18,383,000 payment-in-kind (“PIK”) common units. In November 2012, the PIK common units automatically converted to common units. Through the IPO and a series of secondary offerings during 2013, NT Holdings sold 40,042,500 of its common units in Northern Tier Energy LP ("NTE LP") to the public. On November 12, 2013, NT Holdings formed a new subsidiary, NT InterHoldCo LLC, and contributed its remaining 35,622,500 common units of NTE LP and its ownership rights in Northern Tier Energy GP LLC to NT InterHoldCo LLC. Subsequent to the contribution, NT Holdings sold NT InterHoldCo LLC to Western Refining, Inc. ("Western Refining").

Refining Segment

Our refining segment primarily consists of an 89,500 barrels per calendar day (“bpd”) (96,500 barrels per stream day) refinery located in St. Paul Park, Minnesota. Our refinery’s complexity allows us to process a variety of light, heavy, sweet and sour crudes into higher value refined products.

During the 2013 second quarter, we completed a capacity expansion project on one of our crude units at the refinery and increased our capacity levels to 89,500 barrels per calendar day, or 96,500 barrels per stream day, compared to our prior capacity levels of 81,500 barrels per calendar day, or 84,500 barrels per stream day.

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 years ended December 31, 2013, 2012 and 2011, approximately 50%, 47% and 51%, respectively, was Canadian crude oil and the remainder was primarily comprised of 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 several years, NYMEX WTI has traded on average at an additional discount relative to Brent crude oil.

We expect to continue to benefit from our access to these growing crude oil supplies. By 2030, according to the Canadian Association of Petroleum Producers (“CAPP”), total Canadian crude oil production is expected to grow to 6.7 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 1 million bpd as of December 2013, 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%, 80% and 79% of our total refinery production for the years ended December 31, 2013, 2012 and 2011 was comprised of higher value, light refined products, including gasoline and distillates.

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We also own various storage and transportation assets, including a light products terminal, a heavy products terminal, storage tanks, rail loading/unloading facilities, the Aranco and Cottage Grove pipelines and a Mississippi river dock. Approximately 70%, 78% and 83% of our gasoline and diesel volumes for the years ended December 31, 2013, 2012 and 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 the independently-owned and operated Marathon branded convenience stores in our distribution area. Beginning in December 2012, we initiated a crude oil transportation business in North Dakota to allow us to purchase crude oil at the wellhead in the Bakken Shale while limiting the impact of rising trucking costs for crude oil in North Dakota.

Our refining business also includes our 17% interest in the Minnesota Pipe Line Company, LLC ("MPL"), 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 Segment

As of December 31, 2013, our retail segment operated 164 convenience stores under the SuperAmerica brand and also supported 75 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 beverages, 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 stores and the franchised convenience stores within our distribution area for the years ended December 31, 2013, 2012 and 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, 2013, there were 139 operating oil refineries in the United States, with the 21 smallest each having a refining capacity of 15,000 bpd or less, and the 10 largest having capacities ranging from 311,000 bpd to 560,500 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 4% between January 1982 and January 2013 from 16.1 million bpd to 16.8 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 2012. 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 (inclusive of jet fuel and kerosene) and jet fuel/kerosene from domestic sources outside of PADD II comprised approximately 15%, 10% and 8%, respectively, of demand for these products in 2012. Refining capacity in the PADD II region has decreased approximately 7% between January 1982 and January 2013 from approximately 3.8 million bpd to approximately 3.5 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—2012:

PADD II Gasoline Balance (mbpd)

	2005		2006		2007		2008		2009		2010		2011		2012
Production by Refineries Within PADD II	1,816		1,796		1,769		1,713		1,778		1,807		1,837		1,859
Net Receipts of Products from Domestic Sources Outside PADD II	673		691		673		594		550		482		417		374
Ethanol	136		138		179		243		222		231		225		239
Exports to Non-U.S. Sources	—		(2	)	(11	)	(19	)	(1	)	(5	)	(8	)	(6	)
Imports from Non-U.S. Sources	2		1		2		1		1		3		3		2
Other	(1	)	5		7		12		(15	)	8		(11	)	(21	)
Total	2,626		2,629		2,619		2,544		2,535		2,526		2,463		2,447

PADD II Distillate Balance (mbpd)

	2005		2006		2007		2008		2009		2010		2011		2012
Production by Refineries Within PADD II	908		914		927		987		898		963		989		1,017
Net Receipts of Products from Domestic Sources Outside PADD II	344		332		336		249		180		195		155		109
Exports to Non-U.S. Sources	(9	)	(2	)	(6	)	(12	)	(6	)	(3	)	(5	)	(6	)
Imports from Non-U.S. Sources	4		6		6		5		4		6		2		3
Other	2		5		(8	)	(7	)	1		1		(3	)	16
Total	1,249		1,255		1,255		1,222		1,077		1,162		1,138		1,139

PADD II Jet Fuel/Kerosene Balance (mbpd)

	2005		2006		2007		2008		2009		2010		2011		2012
Production by Refineries Within PADD II	230		220		202		209		208		219		229		232
Net Receipts of Products from Domestic Sources Outside PADD II	145		119		115		74		49		41		36		19
Exports to Non-U.S. Sources	(1	)	(4	)	(7	)	(10	)	(5	)	(4	)	(7	)	(8	)
Imports from Non-U.S. Sources	—		—		—		—		—		—		—		—
Other	(3	)	2		1		2		(4	)	(1	)	(2	)	4
Total	371		337		311		275		248		255		256		247

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

Our Refining Business

Our refinery occupies approximately 170 acres along the Mississippi River 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 an 89,500 bpd (96,500 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. 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. Our refining capital expenditures in the year ended December 31, 2012 were $24.2 million. During the year ended December 31, 2013, we had capital expenditures of $13.6 million towards the upgrade of our waste water treatment facility and had discretionary capital spending of $54.4 million.  Included in this discretionary spending was approximately $40 million for a project which resulted in a 10% capacity expansion at our refinery that, along with other discretionary projects, improved our distillate recovery by 2-3%.

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

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approximately 40% of the total number of operable U.S. refineries as of January 2013 and approximately 52% of the country’s refining capacity as of January 2013. 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 distribution area incur additional transportation costs. This favorable supply/demand imbalance has allowed our refinery to generate higher refining margins, compared to the U.S. Gulf Coast 3:2:1 crack spread. We have realized, on average, a premium of $5.08 per barrel, inclusive of refined product and crude differentials, relative to the benchmark Group 3 3:2:1 crack spread over the past five years through December 31, 2013 assuming a comparable rate of two barrels of Group 3 gasoline and one barrel of Group 3 distillate for every three barrels of WTI crude oil.

The refinery is an integrated refining operation with significant storage and transportation assets. Our transportation assets include our 17% interest in MPL, an eight-bay light product terminal located adjacent to the refinery, a seven-bay heavy product loading rack located on the refinery property, rail facilities for shipping liquefied petroleum gas (“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. Beginning in December 2012, we initiated a crude oil transportation business in North Dakota to allow us to purchase crude oil at the wellhead in the Bakken Shale while limiting the impact of rising trucking costs for crude oil in North Dakota. As of December 31, 2013, our storage assets included 82 hydrocarbon storage tanks with a total capacity of 3.8 million barrels, 0.8 million barrels of crude oil storage and 3.0 million barrels of feedstock and product storage.

Process Summary

Our refinery is an 89,500 bpd (96,500 barrels per stream day) cracking facility with operations including crude fractionation, catalytic cracking, hydrotreating, reforming, alkylation, sulfur recovery and a hydrogen plant. We have 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 year ended December 31, 2013 and the year ended December 31, 2012, the refinery processed 74,237 bpd and 81,779 bpd of crude oil, respectively, and 1,227 bpd and 2,072 bpd of other charge and blendstocks, respectively. Crude throughput for the year ended December 31, 2013 was impacted by planned downtime due to a major plant turnaround at our refinery, which occurs approximately every six years. 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 68%, 80% and 75% for the years ended December 31, 2013, 2012 and 2011, respectively. Please see below for a simplified process flow diagram of the major refining units at our refinery.

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The following table summarizes our refinery’s major process unit capacities as of December 31, 2013. Unit capacities are shown in barrels per stream day. 

Process Unit	Capacity	% of Crude Oil Capacity
No. 1 Crude Oil Unit	38,500	40	%
No. 2 Crude Oil Unit	58,000	60	%
Vacuum Distillation Units	43,500	45	%
Catalytic Reforming Units	24,500	25	%
Fluid Catalytic Cracking Unit	28,500	30	%
HF Alkylation Unit	5,500	60	%
C4/C5/C6 Isom Unit	8,500	90	%
Naphtha Hydrotreaters	25,000	26	%
Kerosene Hydrotreater	9,000	9	%
Distillate Hydrotreater	30,000	31	%
Gas Oil Hydrotreater	29,500	31	%
Hydrogen Plant (MSCF/D)	10,000	—
Sulfur Recovery Units (short tons/day)	122	—

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%, 80% and 79% of our total refinery production for the years ended December 31, 2013, 2012 and 2011, respectively.

Raw Material Supply

The primary input for our refinery is crude oil, which represented approximately 98%, 98% and 95% of our total refinery throughput volumes for the years ended December 31, 2013, 2012 and 2011, respectively. We processed 74,237 bpd, 81,779 bpd and 77,452 bpd of crude oil for the years ended December 31, 2013, 2012 and 2011, respectively. The following

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table describes the historical feedstocks for our refinery:

	Year Ended December 31,
	2013	%		2012	%		2011	%
	(bpd)
Refinery Throughput Crude Oil Feedstocks by Location:
Canadian and Other International	37,045	50	%	38,332	47	%	39,295	51	%
Domestic	37,192	50	%	43,447	53	%	38,157	49	%
Total Crude Oil	74,237	100	%	81,779	100	%	77,452	100	%
Crude Oil Feedstocks by Type:
Light and Intermediate(1)	56,310	76	%	60,326	74	%	56,722	73	%
Heavy(1)	17,927	24	%	21,453	26	%	20,730	27	%
Total Crude Oil	74,237	100	%	81,779	100	%	77,452	100	%
Other Feedstocks/ Blendstocks(2):
Natural Gasoline	—	—	%	145	7	%	1,910	52	%
Butanes	597	49	%	1,294	62	%	1,236	33	%
Gasoil	114	9	%	58	3	%	—	—	%
Other	516	42	%	575	28	%	552	15	%
Total Other Feedstocks/ Blendstocks	1,227	100	%	2,072	100	%	3,698	100	%
Total Inputs	75,464			83,851			81,150

(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.

Of the crude oil processed at our refinery for the years ended December 31, 2013, 2012 and 2011, approximately 50%, 47% 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 crude oil exporter to the United States and representing 25% of all U.S. crude oil imports from foreign sources. By 2030, according to CAPP, total Canadian crude oil production is expected to grow to 6.7 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 1 million bpd as of December 2013, 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.

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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, effective through December 2015, with J.P. Morgan Commodities Canada Corporation (“JPM CCC”), pursuant to which JPM CCC assists us in the purchase of most of the crude oil requirements of our refinery. Once we identify types 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 enters our refinery from the storage tanks located at Cottage Grove. 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 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 the Federal Energy Regulatory Commission (“FERC”) pursuant to the Interstate Commerce Act (“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. Capacity available to new shippers during periods of apportionment is limited to 5% of available transportation space. For the years ended December 31, 2013, 2012 and 2011, our shipments comprised approximately 22%, 24% and 24%, respectively, of the total volumes shipped on the Minnesota Pipeline. Our 17% interest in MPL 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 via railcar in the amount of approximately 7,000 bpd.

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

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 oxygenated fuel mandate levels of the EPA. The state of Minnesota has a current mandate for all gasoline powered motor vehicles for 10% ethanol blending in gasoline or the maximum amount of ethanol allowed under federal law, whichever is greater. 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 was to 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% to July 1, 2014. 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.

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Refined Products—Production, Sales and Transportation

On average over the last three fiscal years, the refinery produced approximately 80,830 bpd of refined products, of which 48% was gasoline, 32% were distillates (including ultra low sulfur diesel and jet fuel), 12% 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.

	Year Ended December 31,
	2013	2012	2011
Refinery product yields (bpd):
Gasoline	34,329	40,825	40,240
Distillate	26,074	27,113	24,841
Asphalt	8,321	11,434	9,888
Other	7,158	5,158	7,110
Total Production	75,882	84,530	82,079

For the years ended December 31, 2013, 2012 and 2011, gasoline accounted for 49%, 52%, and 54% of our total revenue for the refining business for such periods, respectively, and distillates accounted for 38%, 35%, and 33% of our total revenue for the refining business for such periods, respectively.

Approximately 80%, 78% and 90% of the refinery business’s gasoline and diesel volumes were sold within the state of Minnesota for the years ended December 31, 2013, 2012 and 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 stores or franchised convenience stores within our distribution area for the years ended December 31, 2013, 2012 and 2011, as well as supplied the independently-owned and operated Marathon branded stores in our distribution 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 70%, 78% and 83% of our gasoline and diesel volumes for the years ended December 31, 2013, 2012 and 2011, respectively, were sold through this light products terminal to our company-operated or franchised SuperAmerica convenience stores, Marathon branded convenience stores and other resellers throughout our distribution 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%, 98% and 95% of our total refinery throughput volumes for the years ended December 31, 2013, 2012 and 2011. JPM CCC assists us in the purchase of most 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 convenience stores, as well as substantially all of the gasoline and diesel sold in our franchised convenience stores and in independently-owned and operated Marathon branded stores within our distribution area. For the years ended December 31, 2013, 2012 and 2011, Marathon branded stores accounted for approximately 6%, 8% and 9%, respectively, of our refined product sales volumes. For more information about the risks associated with our commercial relationship with Marathon, see “Item 1A. Risk Factors—Risks Related to our Business and Industry—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 (including states, counties, cities and townships), and asphalt roofing shingle manufacturers.

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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 major plant turnaround was completed in 2013. The length of the turnaround is contingent upon the scope of work to be completed. A major turnaround of either the fluid catalytic cracking unit or alkylation unit, two of the main refinery units, 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 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. During 2013, we completed our planned major plant turnaround. We are currently planning another partial turnaround in 2014 for our gas oil hydrotreater unit, for which we have budgeted aggregate spending of approximately $10 million to $15 million.

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.

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. Our sales results indicate that 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 during those months.

Pipeline Assets

We own 17% of the outstanding common interests of MPL and a 17% interest in MPL Investments, Inc. (“MPL Investments”) which owns 100% of the preferred interests of MPL. MPL 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 MPL 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 MPL, 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 additional pump stations.

We also own an 8.6 mile 8” products pipeline, referred to as the Aranco Pipeline, which is leased to Magellan pursuant to an amended and restated agreement dated February 28, 2013, 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 Aranco Pipeline is operated by Magellan as part of their products system. The current annual lease amount is $0.8 million. The initial term of the lease agreement is for three years, subject to one-year auto renewals, and both parties have the right to terminate upon notice at least 180 days prior to the expiration of the then-current initial or renewal term. 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

As of December 31, 2013, we have a retail-marketing network of 239 convenience stores located throughout Minnesota, Wisconsin and South Dakota, of which we operate 164 stores and support 75 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 our company owned convenience stores for the years ended December 31, 2013, 2012 and 2011 was supplied by our refining business.

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In December 2010, we entered into a lease arrangement with Realty Income Properties 3 LLC (“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. 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. As of December 31, 2013, 133 of the SuperAmerica convenience stores and the one support facility remained on the Realty Income lease. Additionally, 29 of our other company-operated properties are leased pursuant to a combination of ground leases and real property leases with third parties and two company-operated properties are owned by us.

The table below sets forth our company-operated and franchised stores by state as of December 31, 2013.

Location	Company- Operated	Franchised	Total
Minnesota	157	69	226
Wisconsin	6	5	11
South Dakota	1	1	2
Total	164	75	239

Of our company-operated sites, approximately 70% 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 beverages 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 75 franchised convenience stores, selling gasoline, merchandise and other services through SuperAmerica Franchising LLC (“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 our distribution area, then the franchise store is not required to purchase any portion of its motor fuel supply from us. As of December 31, 2013, 38 of the 75 existing franchise stores were 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 owned and leased convenience stores averaged 317 million gallons over the period 2011-2013. The demand for gasoline is seasonal in nature, with higher demand during the summer months. 24% of the retail segment’s revenues for the year ended December 31, 2013 were generated from non-fuel sales, including items like cigarettes, beer, milk, food, general merchandise, car wash and other commission-based revenue. The following table summarizes the results of our retail business for the periods indicated.

	Year Ended December 31,
	2013			2012			2011
Company-operated
Fuel gallons sold (in millions)	313.2			312.4			324.0
Retail fuel margin ($/gallon)(1)	$	0.19		$	0.18		$	0.21
Merchandise sales ($ in millions)	$	341.6		$	340.4		$	340.3
Merchandise margin(%)(2)	25.9		%	25.4		%	25.4		%
Number of outlets at year end	164			166			166
Franchised Stores
Fuel gallons sold (in millions)(3)	46.9			45.4			51.5
Royalty income (in millions)	$	2.5		$	2.1		$	1.7
Number of outlets at year end	75			70			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 “Item 7.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Other Non-GAAP Performance Measures.”

(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. Merchandise margin includes all non-fuel sales at our company-operated stores including items like cigarettes, beer, milk, food, general merchandise, car wash and other commission-based revenue. For a reconciliation of merchandise margin to retail segment operating income, the most directly comparable GAAP measure, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Other Non-GAAP Performance Measures.”

(3) Represents fuel gallons sold to franchised stores by our refinery.

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 Company ("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 years ended December 31, 2013, 2012 and 2011, our retail business purchased approximately 74%, 76% and 75%, respectively, 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 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 “Item 1A. 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 239 convenience stores, as of December 31, 2013, located throughout Minnesota, Wisconsin and South Dakota, of which we operate 164 stores and support 75 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. In addition, we compete with producers and marketers in other industries that supply alternative forms of energy and fuels to satisfy the requirements of our industrial, commercial and individual customers. Certain of our competitors have larger, more complex refineries, and may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Some of our principal competitors are integrated, multinational oil companies that are substantially larger and more recognized than we are. 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. 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. Many of these competitors are substantially larger than we are. In addition, these retailers may use promotional pricing or discounts, both at the pump and in the store, to encourage in-store merchandise sales. Our convenience stores compete in large part based

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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.

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 per occurrence 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 60 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 policies covering workers compensation, general liability, directors’ and officers’ liability, environmental liability, information security other business risks. These are supported by safety and other risk management programs. See also “Item 1A. Risk Factors—Risks Related to Our Business and Industry—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 emission and 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 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 disposed of or released. 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 resulting from such changes, 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, carbon monoxide, sulfur dioxide, nitrogen oxides or hazardous air pollutants, face increasingly stringent regulations, including requirements to install various levels of control technology on sources of pollutants as well as the requirement to maintain a risk management program to help prevent accidental releases of certain regulated substances. For example, the EPA has published final amendments to the New Source Performance Standards (NSPS) for petroleum refineries, effective November 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 have installed and operate a continuous emissions monitoring system for nitrogen oxides on a process heater. We will also complete installation and operate additional instrumentation on our flare. In 2013, we spent less than $0.1 million and anticipate spending an additional $0.7 million in 2014 for the flare monitoring. 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 also 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. We submitted an application to the MPCA in June 2012 to make proposed amendments

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to our Title V Operating Permit, and in April 2013 the MPCA issued an amended permit incorporating the 2001 Consent Decree requirements into our Title V Operating Permit. We are in discussions with Marathon and the EPA concerning the filing of a joint motion with the court to terminate the 2001 Consent Decree as to our refinery.

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. In August 2012, we received a request for information from the EPA regarding the flare at our refinery and we responded in September 2012. We received additional requests for information about the refinery’s flare from the EPA in December 2013 and January 2014 and have responded. 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. However, it is possible that the EPA could require additional controls in the event that the agency pursues a flaring consent decree on us. 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 Operating 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 Security Act of 2007, the EPA has issued Renewable Fuel Standards (“RFS”) implementing mandates to blend fuels produced from renewable sources into petroleum fuels produced and sold in the United States. We are subject to the RFS, which requires obligated parties to blend renewable fuels, such as ethanol, into petroleum fuels sold in the United States. One renewable energy identification number (“RIN”) is generated for each gallon of renewable fuel produced under the RFS. At the end of each year, obligated parties must surrender sufficient RINs to meet their renewable fuel obligations under the RFS. 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, The price of RINS was unusually volatile in 2013, at one point climbing well above $1.00, and such volatility could continue into 2014 as well. We cannot 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 was to 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% to July 1, 2014. In 2012, we completed the installation of 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. 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.

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. In 2013, our refinery’s average benzene content was 0.625%. Our refinery’s average benzene content for future years, could 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 would also consider operational changes to lower the benzene content of the gasoline we produce. We cannot predict the costs associated with implementing such

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operational changes, but they could be material. 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. In May 2013, the EPA proposed new “Tier 3” motor vehicle emission and fuel standards. The proposed regulation requires that gasoline contain no more than 10 parts per million of sulfur on an annual average basis by January 1, 2017. Management’s current assessment is that the proposed updated standard will not have a material financial impact on our operations. Preliminary engineering assessments predict we should be able to comply with the new standards without having to incur significant capital expenditures. However, there is no guarantee that our current assessments are correct, and we may at some point in the future be required to make significant capital expenditures and/or incur materially increased operating costs in order to comply with the new standards.

Climate Change

In December 2009, the EPA published its findings that emission of greenhouse gases (“GHGs”), including carbon dioxide and methane, are contributing to the warming of the Earth’s atmosphere and other climatic conditions present a potential danger 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 in January 2011. The EPA has also 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. We have been monitoring GHG emissions, and submitted our first annual report on these emissions to EPA in September 2011. Moreover, in June 2010, the EPA published its final rule to address the permitting of GHG emissions from stationary sources under the Clean Air Act’s 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 sources first subject to permitting. Facilities required to obtain PSD permits for their GHG emissions must also reduce those emissions according to “best available control technology” standards (“BACT”), established by the states or, in some cases, the EPA, on a case-by-case basis. These EPA rulemakings could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources.

Also, 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 December 2011. To date, however, the 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 limit 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.

In addition, from time to time the U.S. Congress has 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 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.

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

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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. Despite the “petroleum exclusion” of section 101(14) of CERCLA, 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 $0.5 million in 2014 and an additional $1.4 million through the year 2023 in connection with continued monitoring and remediation of this contamination at the refinery.

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. Additionally, 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.

Our refinery operates a wastewater treatment plant. The refinery’s wastewater treatment plant utilized two lagoons until 2012 when one lagoon was closed as part of the construction project discussed below. 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 occurrences 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 to bring the lagoon into compliance with applicable laws and regulations. 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 be 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. In November 2012, the MPCA requested additional information from us regarding the September 2012 benzene exceedance. We responded to the MPCA’s request in December 2012. The refinery has engaged in discussions with the MPCA regarding the implications and appropriate responses to this incident. The MPCA has not initiated any formal enforcement action to date with respect to this event. In December 2013, we entered into a tolling agreement with the MPCA to extend the statute of limitations to July 31, 2014 with respect to the three exceedances that occurred between December 2010 and March 2011 and expect to continue discussions with the MPCA concerning an appropriate resolution regarding the benezene exceedances. If the MPCA initiates enforcement related to this event, there can be no assurance that any fines, penalties, costs and expenses that we may incur will not be material.

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 spent $0.7 million and $1.1 million in 2012 and 2013,

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respectively, so that the refinery complied with the TSS standard by the end of 2013, within the time allowed by the permit. As described above, we will be spending $0.7 million in 2014 for flare monitoring. 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 spent approximately $32.4 million across 2011, 2012 and 2013, and we estimate that we may spend an additional $10.2 million in 2014 to complete these waste water treatment plant upgrades. Pursuant to the agreements entered into in connection with the Marathon Acquisition, we believed 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 September 2013 we entered into a settlement and release agreement under which Marathon paid us $11.8 million to partially resolve our 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 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 completed the planned installations of Safety Instrumented Systems to enhance its safety program and spent $5.8 million in 2013. Additionally, the refinery spent $7.6 million in 2013 and plans to spend approximately $7.0 million in 2014 through 2017 to replace relief valves to enhance overall safety. Furthermore, the refinery has budgeted approximately $4.3 million for 2014 through 2017 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 general maintenance activities. If a government action or order is adopted after February 28, 2013 that requires any portion of the Aranco Pipeline to be relocated, lowered, adjusted or encased, we are responsible for the associated costs. The term of the agreement will also be extended to enable Magellan to recoup the cost of any other repairs, replacements, inspections, improvements or modifications in excess of $0.5 million that are required as a result of a government action or order adopted after February 28, 2013.

We also own an equity interest in MPL, which owns and operates the pipeline that provides the primary supply of crude oil to the refinery. Between the parties, MPL 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 $0.1 million through the end of 2014, and an additional cost of less than $0.1 million 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.

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Other Government Regulation

Our transportation activities are subject to regulation by multiple governmental agencies. 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.

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 MPL 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.

The EPAct deemed petroleum pipeline rates in effect for the 365-day period ending on the date of enactment of the 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 the 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. The 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 MPL’s financial position, cash flows and results of operations.

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 MPL’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

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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 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.

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 December 31, 2013, we employed 2,896 people, including 483 employees associated with the operations of our refining business and 2,326 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 187 of our 483 employees associated with the operations of our refining business and 24 of our 2,326 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 2016 and August 2014, respectively. We consider our relations with our employees to be satisfactory.

Available Information

We file annual, quarterly and current reports, and amendments to those reports and other information with the Securities and Exchange Commission (“SEC”). You may access and read our filings without charge through the SEC’s website at www.sec.gov. You may also read and copy any document we file at the SEC’s public reference room located at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room.

We 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 Form 10-K and you should not consider such information as part of this report.

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Item 1A. Risk Factors.

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, we may not be able to pay distributions on our common units, the trading price of our common units could decline and our unitholders could lose all or part of their investment.Other risks are also described in “Item 1. Business” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

Risks Related to Our Business and Industry

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. 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.

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 independently-owned and operated Marathon branded stores in our distribution area. Marathon has indemnification obligations to us pursuant to the agreements entered into in connection with the Marathon Acquisition. Marathon’s indemnification obligations 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 discussed above. Nevertheless, relying on Marathon’s ability to honor its fuel requirement 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.

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

The historical financial statements for periods prior to December 1, 2010, presented in "Item 6. Selected Financial Data” of this report, 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, 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 IPO may not be comparable to our results of operations for periods prior to the closing of our IPO as a result of certain transactions undertaken in connection with our IPO. As a result, it is difficult to evaluate our historical results of operations to assess our future prospects and viability utilizing the pre-Marathon Acquisition and pre-IPO historical financial information.

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

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

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

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

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

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

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

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

Our operating results are seasonal and generally 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. Unfavorable weather conditions could significantly negatively impact our financial condition.

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.

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

• diversion of management time and attention from our existing business;

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

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

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

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

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

• difficulties in achieving anticipated operational improvements; and

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

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

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

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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 any 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, in September 2012, the EPA published final amendments to the NSPS for petroleum refineries. 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 have installed 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. In 2013 we spent approximately $13,500 and anticipate spending an additional $660,000 in 2014 for the flare monitoring. 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 May 2013, the EPA proposed new “Tier 3” motor vehicle emission and fuel standards. The proposed regulation requires that gasoline contain no more than 10 parts per million of sulfur on an annual average basis by January 1, 2017. Management’s current assessment is that the proposed updated standard will not have a material financial impact on our operations. Preliminary engineering assessments predict that we should be able to comply with the new standards without having to incur significant capital expenditures. However, there is no guarantee that our current assessments are correct, and we may at some point in the future be required to make significant capital expenditures and/or incur materially increased operating costs in order 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 MPCA pursuant to a remediation settlement agreement entered into between Marathon and the MPCA in 2007. Releases of petroleum hydrocarbons have also occurred at several of our convenience stores, and we have performed and will continue to perform remediation of this known contamination until the applicable regulatory standards are met. Costs for such remediation activities are often unpredictable, and there can be no assurance that the future costs will not be material. It is possible that we may identify additional contamination in the future, which could result in additional remediation obligations and expenses, including fines and penalties.

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

We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, process safety standards and control of occupational exposure to regulated substances, could subject us to significant fines or cause us to spend significant amounts on compliance, which could have a material adverse effect on our results of operations, financial condition and the cash flows of the business and, as a result, our ability to make distributions.

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

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

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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 limited 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 other strategic investments. Our level of indebtedness could affect our operations in several ways, including the following:

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

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

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

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

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

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

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

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

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

Increased costs of capital could adversely affect our business.

Because our refining and retail businesses are capital intensive, 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

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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.

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.

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 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.

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 December 2013, 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 $140.88 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 cost flow methodology. If the market value of our refined product inventory were to decline to an amount less than our LIFO cost, we would record a write-down of inventory and a non-cash charge to cost of sales.

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

• changes in global and local economic conditions;

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

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

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

• availability of and access to transportation infrastructure;

• utilization rates of 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;

• development and marketing of alternative and competing fuels;

• commodities speculation;

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

• federal and state government regulations and taxes; and

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

Our direct operating expense structure also impacts our earnings. Our major direct operating expenses include employee and contract labor, maintenance and energy costs. Our predominant variable direct operating cost is energy, which is comprised primarily of fuel and other utility services. The volatility in costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refinery and other operations affect our operating costs. Fuel and utility prices have been, and will continue to be, affected by factors outside our control, such as supply and demand for fuel and utility services in both local and regional markets. Natural gas prices have historically been volatile and, typically, electricity prices fluctuate with natural gas prices. Future increases in fuel and utility prices may have a negative effect on our earnings and cash flows. Fuel and other utility services costs constituted approximately 14.9%, 13.0% and 13.3% of our total direct operating expenses for the years ended December 31, 2013, 2012 and 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 had widened significantly from 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 December 31, 2013, the discount at which a barrel of NYMEX WTI traded relative to a barrel of Brent increased from $2.12 to $12.38. 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. A significant narrowing of this differential may have a material adverse effect on our results of operations and ability to pay distributions to our unitholders.

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 September 2013, our St. Paul Park refinery experienced a fire in our larger crude distillation unit. Due to this unplanned downtime, the start date of the planned turnaround on our Fluid Catalytic Cracker unit, which was scheduled to begin October 1, 2013, was accelerated into September 2013. All repairs to the refinery were completed at a cost of less than $3 million and both crude towers were restored to full functionality by October 14, 2013.

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, in May 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 the next day. 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

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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 no longer receive crude oil deliveries from the Wood River Pipeline, it is capable of receiving crude oil via railcar in the amount of approximately 7,000 bpd. If the Minnesota Pipeline system experiences another disruption, this would result in an increase in the cost of crude oil and therefore lower refining margins.

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

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

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

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

• unplanned increases in the cost of construction materials or labor;

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

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

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

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

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

Our refinery consists of many processing units, a number of which have been in operation for many years. Equipment, even if properly maintained, may require significant capital expenditures and expenses to keep it operating at optimum efficiency. For example, as part of installing safety instrumentation systems throughout the refinery to improve operational and safety performance, approximately $24 million was spent from 2006 through 2013 to complete the instrumentation project and the refinery spent $7.6 million in 2013 and plans to spend approximately $7.0 million in 2014 through 2017 to replace relief valves to enhance overall safety. 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. 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.

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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 187 of our employees associated with the operations of our refining business are covered by a collective bargaining agreement. During January 2014, we entered into a new collective bargaining agreement with our unionized refining employees that expires in December 2016. In addition, 24 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. In August 2012, we locked out the unionized drivers at the Supermom’s bakery for six days when the parties were unable to come to terms on a new union contract.

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 or on our ability to make distributions.

Laws and regulations restricting emissions of greenhouse gases ("GHG"s) 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 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 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 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. 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 December 2011. To date, however, 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 rules and regulations related to the emission of GHGs.

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, 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. In addition, 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.

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Finally, 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 Fuel Standards (“RFS”) implementing mandates to blend renewable fuels into petroleum fuels produced and sold in the United States. We are subject to the RFS, which requires obligated parties to blend renewable fuels, such as ethanol, into petroleum fuels sold in the United States. One renewable energy identification number (“RIN”) is generated for each gallon of renewable fuel produced under the RFS. At the end of each year, obligated parties must surrender sufficient RINs to meet their renewable fuel obligations under the RFS. 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, The price of RINS was unusually volatile in 2013, at one point climbing well above $1.00, and such volatility could continue into 2014 as well. We cannot 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 was to 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% to July 1, 2014. 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, the 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. The 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. The 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 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 MPL, which we do not control. Because we currently do not operate the Minnesota Pipeline or control the board of managers of MPL, we do not control how the Minnesota Pipeline’s tariff is applied, including the tariff provisions governing the allocation of capacity, or control of decision-making with respect to tariff changes for the pipeline.

FERC can investigate the pipeline’s rates and certain terms of service on its own initiative. In addition, shippers may file with FERC protests against new tariff rates and/or terms and conditions of service or complaints against existing tariff rates

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and/or terms and conditions of services. Under certain circumstances, FERC could order MPL 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-based 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 MPL's 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.

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 MPL and 17% of the outstanding preferred shares of MPL Investments, which owns 100% of the preferred units of MPL. MPL 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 MPL 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 MPL and MPL Investments, see “Item 7. 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 MPL and MPL Investments are limited, we do not have significant influence over or control of the performance of MPL’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.

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

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

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

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

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

As a result, the effectiveness of our risk mitigation strategy could have a material adverse impact on our financial results and our ability to make distributions. See “Item 7A. 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 currently have no plans 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, 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.

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

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

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

Risks Primarily Related to Our Retail Business

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

Eby-Brown 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 years ended December 31, 2013, 2012 and 2011, our retail business purchased approximately 74%, 76% and 75%, respectively, 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:

• competition in targeted market areas;

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

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

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

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

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

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

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

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

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

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

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

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

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

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

In connection with credit and debit card sales at our retail stores, we transmit confidential credit and debit card information securely over public networks. Third parties may have the technology or ability to breach our security measures and obtain 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.

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

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

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

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

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

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

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

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

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

Risks Related to an Investment in our Company

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:

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• 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 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 other cash reserves established by our general partner.

Our partnership agreement does 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 “Item 7. 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 Secured Notes and our revolving credit facility prohibit us from making distributions to unitholders if certain events of default 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 “Item 7. 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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Our Distribution Policy.”

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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 requirement changes as well as extraordinary capital expenditures in the future. See “Item 7. 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.

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 “Item 7. 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 Western Refining and its affiliates, to the detriment of our public unitholders.

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 may experience dilution and the payment of distributions on those additional units may 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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Liquidity and Capital Resources-Our Distribution Policy.”

Our general partner has fiduciary duties to Western Refining, which indirectly owns our general partner. The interests of Western Refining 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 Western Refining, which indirectly owns our general partner. The interests of Western Refining may differ from, or conflict with, the interests of our unitholders. In resolving these conflicts, our general partner may favor its own interests or the interests of its owners over our interests and those of our unitholders.

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

• Neither our partnership agreement nor any other agreement will require Western Refining 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 Western Refining, 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.

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

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

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

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

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

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.

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

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

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

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

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

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

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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.

NT InterHoldCo LLC has the power to appoint and remove our general partner’s directors.

NT InterHoldCo LLC, a wholly-owned subsidiary of Western Refining, 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 “Item 10. Directors, Executive Officers and Corporate Governance-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.

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 NT InterHoldCo LLC 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 NT InterHoldCo LLC’s 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 NT InterHoldCo LLC). NT InterHoldCo LLC owns approximately 38.7% of our common units, which means holders of common units are not able to remove the general partner without the consent of NT InterHoldCo LLC.

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

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distributions to our unitholders. See “Item 7. 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.”

Unitholders may have liability to repay distributions.

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

Likewise, upon the winding up of the partnership, in the event that (1) we do not distribute assets in the following order: (a) to creditors in satisfaction of their liabilities; (b) to partners and former partners in satisfaction of liabilities for distributions owed under our partnership agreement; (c) to partners for the return of their contribution; and finally (d) to the partners in the proportions in which the partners share in distributions and (2) a unitholder knows at the time of such circumstances, then such unitholder will be liable for a period of three years from the impermissible distribution to repay the distribution under Section 17-804 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 Western Refining 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.

Our unit price could fluctuate.

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 earnings (loss) 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 price at which they purchased the units. 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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If we are unable to maintain 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 are required to document and test our internal control procedures, our management is required to assess and issue a report concerning our internal control over financial reporting, and, under the Sarbanes-Oxley Act, our independent auditors are required to issue an opinion on management’s assessment and the effectiveness of our internal control over financial reporting. 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 annual testing, our management may identify material weaknesses, which may not be remedied in time to meet the annual deadline imposed by the SEC. 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 could dilute 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 may 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.

As of February 26, 2013, there were 92,309,662 units outstanding. 18,687,500 common units were sold to the public in our IPO, 12,305,000 were sold by NT Holdings in a secondary offering in January 2013, 13,800,000 common units were sold by NT Holdings in a secondary offering in April 2013, 11,500,000, were sold by NT Holdings in a secondary offering in August 2013 and an aggregate of 35,622,500 common units are owned by NT InterHoldCo LLC. The common units sold in our IPO and the three secondary offerings are 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 NT InterHoldCo LLC, 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.

As a publicly traded limited partnership we qualify for, and will rely on, certain exemptions from the NYSE’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.

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As a result of these exemptions, our general partner’s board of directors is not, and is not required to be, comprised of a majority of independent directors and our general partner’s compensation committee and nominating and corporate governance committee is not, and is not required to be, comprised entirely of independent directors. Accordingly, unitholders will not have the same protections afforded to equity holders of companies that are subject to all of the corporate governance requirements of the NYSE. See “Item 10. Directors, Executive Officers and Corporation Governance.”

Tax Risks

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 Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes, or if we were to become subject to a material additional amount of entity-level taxation for state tax purposes, then our cash available for distribution to you would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on us being treated as a partnership for federal income tax purposes. A publicly traded partnership such as us may be treated as a corporation for federal income tax purposes unless it satisfies a “qualifying income” requirement. “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. Based on our current operations we believe that we satisfy the qualifying income requirement and will be treated as a partnership. Failing to meet the qualifying income requirement 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. We have not requested, and we do not plan to request, a ruling from the IRS on this or any other tax matter affecting us.

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 or deductions would flow through to you. Because a tax would be imposed on 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.

At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such tax on us by any such state will reduce the cash available for distribution to our unitholders.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied 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 or differing interpretations at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. One such legislative proposal would eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. 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. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes.

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 you will be treated as a partner to whom we will allocate a share of our taxable income which could be different than the cash we distribute, you may be required to pay federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, even if you receive no cash distribution from us. You may not receive cash distribution from us equal to your share of our taxable income or even equal to the actual tax liability resulting from that income.

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.

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We have a subsidiary that is treated as a corporation for federal income tax purposes and subject to corporate-level income taxes.

We conduct substantially all of the operations of our retail business through Northern Tier Retail Holdings LLC, which is our subsidiary and is organized as a corporation for federal income tax purposes. Northern Tier Retail Holdings LLC currently holds all of the ownership interests in Northern Tier Retail LLC, Northern Tier Bakery LLC and SuperAmerica Franchising LLC. We may elect to conduct additional operations through this corporate subsidiary in the future. This corporate subsidiary is obligated to pay corporate income taxes, which reduce the corporation’s cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that this corporation has more tax liability than we anticipate or legislation were enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.

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 (a "technical termination").

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. NT InterHoldCo LLC owns approximately 38.7% of the total interests in our capital and profits. If transfers within a twelve-month period 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. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest are counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders receiving two Schedules K-1) for one calendar year 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 calendar year, the closing of our taxable year may also 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. 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 in a timely manner that a termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, the partnership may be permitted to provide only a single Schedule K-1 to its unitholders for the tax year in which the termination occurs. During the year ended December 31, 2013, we had three technical terminations of our partnership.

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 gain or loss equal to the difference between the amount realized and your tax basis in those common units. Because distributions to you 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 ordinary income to you due to potential recapture items, including depreciation recapture. In addition, because the amount realized will include your 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.

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, including individual retirement accounts (“IRAs”), other retirement plans 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 subject to withholding taxes at the highest applicable tax rate, and such non-U.S. persons will be required to file U.S. federal income 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.

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

Due to a number of factors including our inability to match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing and proposed 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.

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We 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 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. Nonetheless, we allocate certain deductions for depreciation of capital additions based upon the date the underlying property is placed in service. 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. If the IRS were to successfully challenge our proration method or new Treasury Regulations were issued, 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 the subject of a securities loan (e.g., a loan to a “short seller” to cover a short sale of common units) may be considered to have 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 are no specific rules governing the federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered to have 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 and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, 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 of their units are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

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 the various jurisdictions in which we conduct business or own assets now or in the future, even if they do not live in any of those jurisdictions. We currently conduct business or own assets in several states, each of which imposes an income tax on corporations and other entities and a personal income tax. As we make acquisitions or expand our business, we may own assets or conduct business in other states or non-U.S. countries that impose personal income tax. 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.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

See “Item 1. Business—Our Refining Business”, “Item 1. Business-Our Retail Business” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” for the location and general character of our refining segment principal facilities, retail locations and other important physical properties. 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 19 to our audited consolidated financial statements. Our corporate headquarters are located at 38C Grove Street, Suite 100, Ridgefield, CT 06877.

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Item 3. 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. For a discussion of certain environmental settlements and consent decrees relating to the assets we acquired from Marathon, see “Item 1. Business—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.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity and Related Unitholder Matters.

Our common units are listed on the New York Stock Exchange under the symbol “NTI.” As of February 26, 2014, we had issued and outstanding 92,309,662 common units, which were held of record by 15 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
December 31, 2013	$	26.00	$	19.36	$	0.41
September 30, 2013	$	25.45	$	17.83	$	0.31
June 30, 2013	$	29.60	$	22.62	$	0.68
March 31, 2013	$	33.24	$	23.62	$	1.23
December 31, 2012	$	27.11	$	19.97	$	1.27
September 30, 2012 (2)	$	21.27	$	13.00	$	1.48

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

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

Cash Distribution Policy

We expect within 60 days after the end of each quarter to make distributions to unitholders of record as of 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. Distributions will be equal to the amount of available cash generated in such quarter. Available cash for each quarter will generally equal our cash flow from operations for the quarter excluding working capital changes, less cash required for maintenance capital expenditures, 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 turnaround and related expenses. 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 the available cash we generate each quarter, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. 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 of crude oil and other feedstocks and the prices received for finished products, (iii) working capital requirements, (iv) capital expenditures and (v) cash reserves deemed necessary or appropriate by the board of directors of our general partner. Such variations in the amount of the quarterly distributions may be significant. Unlike most publicly traded partnerships, we do 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 our 2020 Secured Notes and our revolving credit facility may restrict the ability of Northern Tier Energy LLC, our operating subsidiary, to distribute cash to us. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Description of Our Indebtedness.”

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Unregistered Sales of Equity Securities

None.

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Item 6. Selected Financial Data.

Set forth below is our summary historical consolidated financial data for the years ended December 31, 2013, 2012, 2011 and for the period from June 23, 2010 (inception date) through December 31, 2010. Also set forth below is summary historical combined financial data for the eleven months ended November 30, 2010 and the year ended December 31, 2009, which data represents a carve-out financial statement presentation of several operating units of Marathon, which we refer to as Predecessor. This information may not be indicative of our future results of operations, financial position and cash flows and should be read in conjunction with the consolidated financial statements and notes thereto and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” presented elsewhere in this Annual Report on Form 10-K. We believe that the assumptions underlying the preparation of our historical consolidated financial statements are reasonable.

	Successor												Predecessor
	Year Ended December 31,									June 23, 2010 (inception date) to December 31, 2010			Eleven  Months Ended November 30, 2010			Year Ended December 31, 2009
	2013			2012			2011
Consolidated and combined statements of operations data (in millions):
Revenue	$	4,979.2		$	4,653.9		$	4,280.8		$	344.9		$	3,195.2		$	2,940.5
Costs, expenses and other:
Cost of sales	4,291.6			3,584.9			3,512.4			307.5			2,697.9			2,507.9
Direct operating expenses	262.4			254.1			257.9			21.4			227.0			238.3
Turnaround and related expenses	73.3			26.1			22.6			—			9.5			0.6
Depreciation and amortization	38.1			33.2			29.5			2.2			37.3			40.2
Selling, general and administrative	85.8			88.3			88.7			6.4			59.6			64.7
Formation and offering costs	3.1			1.4			7.4			3.6			—			—
Contingent consideration loss (income)	—			104.3			(55.8		)	—			—			—
Other (income) expense, net	(13.8		)	(9.4		)	(4.5		)	0.1			(5.4		)	(1.1		)
Operating income	238.7			571.0			422.6			3.7			169.3			89.9
Gains (losses) from derivative activities	23.5			(271.4		)	(352.2		)	(27.1		)	(40.9		)	—
Bargain purchase gain	—			—			—			51.4			—			—
Interest expense, net	(26.9		)	(42.2		)	(42.1		)	(3.2		)	(0.3		)	(0.4		)
Loss on early extinguishment of debt	—			(50.0		)	—			—			—			—
Income before income taxes	235.3			207.4			28.3			24.8			128.1			89.5
Income tax provision	(4.2		)	(9.8		)	—			—			(67.1		)	(34.8		)
Net income	$	231.1		$	197.6		$	28.3		$	24.8		$	61.0		$	54.7
Earnings per common unit	$	2.51		$	1.38
Distributions declared per common unit	$	3.49		$	1.48

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	Successor												Predecessor
	Year Ended December 31,									June 23, 2010 (inception date) to December 31, 2010			Eleven  Months Ended November 30, 2010			Year Ended December 31,
	2013			2012			2011									2009
Consolidated and combined statements of cash flow data (in millions):
Cash provided by (used in):
Operating activities	$	229.8		$	308.5		$	209.3		$	—		$	145.4		$	129.4
Investing activities	(95.5		)	(28.7		)	(156.3		)	(363.3		)	(29.3		)	(25.0		)
Financing activities	(321.4		)	(130.4		)	(2.3		)	436.1			(115.4		)	(103.9		)
Capital expenditures	(96.6		)	(30.9		)	(45.9		)	(2.5		)	(29.8		)	(29.0		)

	Successor								Predecessor
	December 31,								November 30,		December 31,
	2013		2012		2011		2010		2010		2009
Consolidated and combined balance sheet data(in millions):
Cash and cash equivalents	$	85.8	$	272.9	$	123.5	$	72.8	$	6.7	$	6.0
Total assets	1,117.8		1,136.8		998.8		930.6		717.8		710.1
Total long-term debt	283.4		282.5		301.9		314.5		—		—
Total liabilities	716.7		653.0		686.6		645.6		405.4		343.9
Total equity	401.1		483.8		312.2		285.0		312.4		366.2

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Item 7. 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 Annual Report on Form 10-K. 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 “Item 1A. Risk Factors” elsewhere in this report. 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 year ended December 31, 2013, we had total revenues of $5.0 billion, operating income of $238.7 million, net income of $231.1 million and Adjusted EBITDA of $363.2 million. A definition and reconciliation of Adjusted EBITDA to net income is included herein under the caption “Adjusted EBITDA.”

Partnership Structure and Management

We commenced operations in December 2010 as Northern Tier Energy LLC ("NTE LLC") through the acquisition of our St. Paul Park, Minnesota refinery, a 17% interest in MPL and in MPL Investments, our convenience stores and related assets (the “Marathon Assets”) from Marathon for $554 million, which included cash and the issuance to Marathon of $80 million of a noncontrolling preferred membership interest in NT Holdings.

In July 2012, Northern Tier Energy LP ("NTE LP") was formed as a Delaware limited partnership by NT Holdings. Our non-economic general partner interest is held by Northern Tier Energy GP LLC, a Delaware limited liability company. References to our “general partner,” as the context requires, include only Northern Tier Energy GP LLC. Our operations are conducted directly and indirectly through our primary operating subsidiaries. On July 31, 2012, we completed our IPO of 18,687,500 common units, representing an approximate 20.3% ownership interest in the Partnership. In exchange for contributing all of the interests in our operating subsidiaries, NT Holdings received 57,282,000 common units and 18,383,000 PIK common units. In November 2012, the PIK common units automatically converted to common units. Through the IPO and a series of secondary offerings during 2013, NT Holdings sold 40,042,500 of its common units in NTE LP. On November 12, 2013, NT Holdings formed a new subsidiary, NT InterHoldCo LLC, and contributed its remaining 35,622,500 common units of NTE LP and its ownership rights in Northern Tier Energy GP LLC, the non-economic general partner of NTE LP, to NT InterHoldCo LLC. Subsequent to the contribution, NT Holdings sold NT InterHoldCo LLC to Western Refining.

Refining Business

Our refining business primarily consists of an 89,500 bpd (96,500 barrels per stream day) refinery located in St. Paul Park, Minnesota. 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%, 80% and 79% of our total refinery production for the years ended December 31, 2013, 2012 and 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 68%, 80% and 75% for the years ended December 31, 2013, 2012 and 2011, respectively. The reduction in utilization during the year ended December 31, 2013 is primary due to the major plant turnaround, capacity expansion and unplanned maintenance during 2013.

We also own various storage and transportation assets, including a light products terminal, a heavy products terminal, storage tanks, rail loading/unloading facilities, the Aranco and Cottage Grove pipelines and a Mississippi river dock. Approximately 70%, 78% and 83% of our gasoline and diesel volumes for the years ended December 31, 2013, 2012 and 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 the independently-owned and operated Marathon branded convenience stores in our distribution area. Beginning in December 2012, we initiated a crude oil

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transportation business in North Dakota to allow us to purchase crude oil at the wellhead in the Bakken Shale while limiting the impact of rising trucking costs for crude oil in North Dakota.

Our refining business also includes our 17% interest in MPL 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.

During September 2013, our St. Paul Park refinery experienced lower utilization primarily due to a fire which occurred in our larger crude distillation unit. Due to this unplanned downtime, the start date of the planned turnaround on our Fluid Catalytic Cracker (“FCC”) unit, which was scheduled to begin October 1, 2013, was accelerated into September 2013. All repairs to the refinery were completed at a cost of less than $3 million and both crude towers were restored to full functionality by October 14, 2013. Beginning on October 14, 2013, our St. Paul Park refinery was operating at a crude oil charge of between 85,000 – 90,000 bpd, which is consistent with throughput constraints related to the FCC turnaround being performed at that time. The FCC turnaround was completed by the end of October and the unit was fully functional within the first week of November. In addition to the repair costs incurred, the unplanned downtime in September and October negatively impacted our refining segment’s operating results due to lower throughput levels requiring us to purchase refined products from third parties for sale to our customers.

Retail Business

As of December 31, 2013, our retail business operated 164 convenience stores under the SuperAmerica brand and also supported 75 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 beverages, 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 stores and franchised convenience stores within our distribution area for the years ended December 31, 2013, 2012 and 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 years ended December 31, 2013, 2012 and 2011 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 “Item 1A. Risk Factors—Risks Primarily Related to Our Refining Business—Our results of operations are affected by crude oil differentials, which may fluctuate substantially.”

Regardless of the relationship in the price differential of WTI to Brent crude oil, we feel our refinery location provides us a strategic advantage. 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 years ended December 31, 2013, 2012 and 2011, approximately 50%, 47% and 51%, respectively, was Canadian crude oil and the remainder was primarily comprised of light sweet crude oil from the Bakken Shale in North Dakota. Many of these crudes have historically priced at a discount to WTI. Demand for these crudes extends to the coastal section of the United States. As pipeline infrastructure continues to develop for the transportation of these crudes, rail transportation will also be required to move significant portions of current and future production volumes. As such, our refinery should continue to benefit from the price advantage between rail transportation to the marginal buyers on the East/Gulf Coasts and pipe transportation to St Paul Park, MN.

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Comparability of Historical Results

The IPO Transactions

Our results of operations for periods subsequent to the closing of our IPO may not be comparable to our results of operations for periods prior to the closing of our IPO as a result of certain aspects of our IPO, including the following:

• Our general and administrative expenses have increased as a result of our IPO. Specifically, we incur certain expenses relating to being a publicly traded partnership, including Exchange Act reporting expenses; expenses associated with Sarbanes-Oxley Act compliance; expenses associated with our listing on the NYSE; independent auditors fees and 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 IPO, Northern Tier Retail Holdings LLC, the subsidiary of Northern Tier Energy LLC through which we conduct our retail business, and Northern Tier Energy Holdings LLC 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 an $8.0 million tax charge to recognize the net deferred tax asset and liability position as of the date of the elections.

2020 Secured Notes Offering and Tender Offer

Our results of operations for periods subsequent to the completion of our 2020 Secured 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 Secured Notes. We used the net proceeds of the offering and cash on hand of $31 million (i) to repurchase our outstanding 2017 Secured Notes that were tendered pursuant to our previously announced tender offer and (ii) to satisfy and discharge any remaining 2017 Secured 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 Secured Notes resulted in an after-tax charge of $50.0 million in the year ended December 31, 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.

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 the Group 3 3:2:1 crack spread. 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 crude oil. The Group 3 3:2:1 crack spread is expressed in dollars per

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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. 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. We completed the planned partial turnaround of the alkylation unit according to schedule in May 2012 and the planned partial turnaround of the No. 1 reformer unit in November 2012. During 2013, we completed our planned major turnaround across our refinery and a partial turnaround involving our FCC unit. We are currently planning a partial turnaround to occur during 2014 for our gas oil hydrotreater unit, for which we have budgeted aggregate spending of approximately $10 million to $15 million.

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 increased cost of sales and decreased income from operations of $1.0 million for the year ended December 31, 2013 and decreased cost of sales and increased income from operations of $4.1 million for the year ended December 31, 2011. There were no such liquidations in the year ended December 31, 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 most 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. This crude oil supply and logistics agreement allows us to take title to and price our crude oil at the refinery, as opposed to the crude oil origination point, which reduces our crude inventories and reduces the time we are exposed to market fluctuations before the finished product is sold.

In addition, we may hedge a portion of the sale 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. As of December 31, 2013, we have no hedged barrels of future gasoline and diesel production.

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

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effect on our retail operating results. Customers are more likely to purchase higher profit margin items at our convenience stores, such as fast foods, fountain drinks and other beverages and more gasoline during the spring and summer months, thereby typically generating higher revenues and gross margins for us in these periods. Margins for transportation fuel sales are equal to the sales price (which includes the motor fuel taxes) less the delivered cost of the fuel and motor fuel taxes, and are measured on a cents per gallon basis. Fuel margins are impacted by local supply, demand and competition.

Margins for retail merchandise sold are equal to retail merchandise sales less the delivered cost of the merchandise, net of any supplier discounts and inventory shrinkage, and are measured as a percentage of merchandise sales. Merchandise sales are impacted by convenience or location, branding and competition. Franchisees are required to pay us an initial license fee (generally, $10,000 for licensees located in Minnesota and Wisconsin and $2,000 for licensees located in South Dakota) and a royalty fee for all products and merchandise sold at the convenience store, including motor fuel and diesel. The initial term of the license is generally 10 years, which is renewable by the licensee for a renewal term of 10 years, subject to the licensee satisfying certain conditions. The license agreements also require that, if a franchise store is located within our distribution area, then the franchise store must purchase a high minimum percentage (often 85% to 100%) of its motor fuel supply, including gasoline and distillate, from us. However, if a franchise store is not located within our distribution area, then the franchise store is not required to purchase any portion of its motor fuel supply from us. As of December 31, 2013, 38 of the 75 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 164 convenience stores primarily in Minnesota. The refining segment also includes our investment in MPL and 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 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. 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 and crude oil 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. 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, including transportation costs, 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 consolidated basis, such intersegment transactions are eliminated.

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

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

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

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

Formation and offering costs. Formation and offering costs represent charges related to offering costs for the sale of common units that did not meet the accounting requirements for deferral and charges recognized or costs incurred related to the creation of Northern Tier Energy LLC and its subsidiaries.

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.

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

Gains (losses) 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 settlement gains or losses related to settled contracts during the period and the change in fair value of outstanding derivatives to partially hedge the crack spread margins for our refining business. Going forward, we plan to hedge a lesser amount of our production than we hedged at the time of the Marathon Acquisition.

Interest expense, net. Interest expense, net relates primarily to interest incurred on our senior secured notes as well as commitment fees and interest on the revolving credit facility and the normal amortization of deferred financing costs.

Income tax provision. Income tax provision represents federal and state income tax expense related to the current year period and includes both current and deferred income tax expense.

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Consolidated Financial Data

	Year Ended December 31,
(in millions)	2013			2012			2011
Revenue	$	4,979.2		$	4,653.9		$	4,280.8
Costs, expenses and other:
Cost of sales	4,291.6			3,584.9			3,512.4
Direct operating expenses	262.4			254.1			257.9
Turnaround and related expenses	73.3			26.1			22.6
Depreciation and amortization	38.1			33.2			29.5
Selling, general and administrative	85.8			88.3			88.7
Formation and offering costs	3.1			1.4			7.4
Contingent consideration loss (income)	—			104.3			(55.8		)
Other income, net	(13.8		)	(9.4		)	(4.5		)
Operating income	238.7			571.0			422.6
Gains (losses) from derivative activities	23.5			(271.4		)	(352.2		)
Interest expense, net	(26.9		)	(42.2		)	(42.1		)
Loss on early extinguishment of debt	—			(50.0		)	—
Income before income taxes	235.3			207.4			28.3
Income tax provision	(4.2		)	(9.8		)	—
Net income	$	231.1		$	197.6		$	28.3

Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012

Revenue. Revenue for the year ended December 31, 2013 was $4,979.2 million compared to $4,653.9 million for the year ended December 31, 2012, an increase of 7.0%. Refining segment revenue increased 7.7% and retail segment revenue decreased 1.6% compared to the year ended December 31, 2012. Refining revenue included a $618.4 million increase in crude oil revenues in the year ended December 31, 2013, partially offset by a 5.8% decrease in sales volumes of refined products versus the year ended December 31, 2012. These crude oil revenues relate to the sale of crude barrels (often accompanied by an offsetting purchase) with the objective of optimizing our crude slate in a given period. The lower refined product volumes are primarily attributable to planned downtime resulting from the turnaround and capacity expansion activities and unplanned maintenance at our St. Paul Park refinery in the year ended December 31, 2013 that reduced refining throughput. Retail revenue decreased primarily due to lower market prices per gallon for fuel sales during the year ended December 31, 2013. Excise taxes included in revenue totaled $316.4 million and $300.1 million for the years ended December 31, 2013 and 2012, respectively.

Cost of sales. Cost of sales totaled $4,291.6 million for the year ended December 31, 2013 compared to $3,584.9 million for the year ended December 31, 2012, an increase of 19.7%, primarily due to higher crude costs in the year ended December 31, 2013 and an increase of $618.7 million related to crude oil sales, partially offset by lower refining sales volumes. Excise taxes included in cost of sales were $316.4 million and $300.1 million for the years ended December 31, 2013 and 2012, respectively.

Direct operating expenses. Direct operating expenses totaled $262.4 million for the year ended December 31, 2013 compared to $254.1 million for the year ended December 31, 2012, an increase of 3.3%, due primarily to the impact of higher catalyst, unplanned maintenance and employee related costs within our refining segment in the year ended December 31, 2013.

Turnaround and related expenses. Turnaround and related expenses totaled $73.3 million for the year ended December 31, 2013 compared to $26.1 million for the year ended December 31, 2012. The turnaround costs in the year ended December 31, 2013 include the costs of a planned major plant turnaround which lasted the entire month of April 2013 and a planned partial turnaround involving our FCC unit which was completed during October 2013. The 2012 partial turnarounds include the alkylation unit, which was completed according to schedule in mid-May, and the No. 1 reformer unit, which was completed in November 2012.

Depreciation and amortization. Depreciation and amortization was $38.1 million for the year ended December 31, 2013 compared to $33.2 million for the year ended December 31, 2012, an increase of 14.8%. This increase was due to increased assets placed in service as a result of our capital expenditures since December 31, 2012, primarily within our refining segment.

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Selling, general and administrative expenses. Selling, general and administrative expenses were $85.8 million for the year ended December 31, 2013 compared to $88.3 million for the year ended December 31, 2012. This decrease of 2.8% from the prior-year period relates primarily to lower employee related and risk management costs.

Formation and offering costs. Formation and offering costs for the years ended December 31, 2013 and 2012 were $3.1 million and $1.4 million, respectively. These formation and offering costs relate to offering costs for the sale of common units that did not meet the accounting requirements for deferral. Formation costs for the year ended December 31, 2013 include a $1.6 million charge related to a prior period adjustment to our intangible assets valuation dating back to our formation.

Contingent consideration loss. Contingent consideration loss was $104.3 million for the year ended December 31, 2012 . The contingent consideration losses relate to the margin support and earn-out agreements entered into with Marathon at the time of the Marathon 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 IPO. There was no contingent consideration loss in the year ended December 31, 2013 as the margin support and earn-out agreements were settled in 2012.

Other income, net. Other income, net was $13.8 million for the year ended December 31, 2013 compared to $9.4 million for the year ended December 31, 2012. This change is driven primarily by $4.4 million of miscellaneous income related to settlements from indemnification arrangements.

Gains (losses) from derivative activities. For the year ended December 31, 2013, we had gains from derivative activities of $23.5 million versus losses from derivative activities of $271.4 million in the year ended December 31, 2012. We had settlement losses of $18.1 million in the year ended December 31, 2013 related to settled contracts compared to $339.4 million in the prior-year period. Offsetting benefits related to these losses were recognized through improved operating margins. We incurred a gain from the change in fair value of outstanding derivatives of $41.6 million for the year ended December 31, 2013 compared to a gain of $68.0 million during the year ended December 31, 2012. These derivatives were entered into to partially hedge the crack spreads for our refining business.

Interest expense, net. Interest expense, net was $26.9 million for the year ended December 31, 2013 and $42.2 million for the year ended December 31, 2012. These interest charges relate primarily to our senior secured notes, commitment fees, interest on the ABL facility and the amortization of deferred financing costs. The decrease from the prior year is primarily due to the reduced principal of, and interest rate on, our new senior secured notes entered into during the fourth quarter of 2012 and the write-off of deferred financing costs in 2012 related to the amendment of our ABL facility.

Loss on early extinguishment of debt. Loss on early extinguishment of debt for the year ended December 31, 2012 of $50.0 million relates to the premiums paid and deferred financing costs written off related to the extinguishment of our senior secured notes due 2017 during the fourth quarter of 2012.

Income tax provision. The income tax provision for the year ended December 31, 2013 was $4.2 million compared to $9.8 million for the year ended December 31, 2012. The 2013 income tax provision represents our first full year as a tax paying entity. Prior to August 1, 2012, we operated as a pass-through entity for federal tax purposes and, as such, only state taxes were recognized. Effective on August 1, 2012, our retail business became a tax paying entity for federal and state income taxes. The 2012 provision 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. Our net income was $231.1 million for the year ended December 31, 2013 compared to $197.6 million for the year ended December 31, 2012. This improvement of $33.5 million was primarily attributable to a $294.9 million favorable variance in gains/losses from derivative activities, a $15.3 million reduction of interest expense, a $6.5 million improvement in our retail segment operating income, a $5.6 million reduction in our income tax provision and the absence of non-recurring losses recognized in the year ended December 31, 2012, including a $50.0 million loss on early extinguishment of debt and charge of $104.3 million related to our contingent consideration arrangements. These year-on-year improvements more than offset the $451.6 million reduction in operating income from our refining segment in the year ended December 31, 2013.

Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011

Revenue. Revenue for the year ended December 31, 2012 was $4,653.9 million compared to $4,280.8 million for the year ended December 31, 2011, an increase of 8.7%. Refining segment revenue increased 10.7% and retail segment revenue decreased 2.5% compared to the year ended December 31, 2011. The refining segment benefited from higher sales volumes and higher average market prices for refined products. 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 $300.1 million and $242.9 million for the years ended December 31, 2012 and 2011, respectively.

Cost of sales. Cost of sales totaled $3,584.9 million for the year ended December 31, 2012 compared to $3,512.4 million for the year ended December 31, 2011, an increase of 2.1%, due to the impact of increased refining throughput,

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partially offset by lower priced crude oil as a result of improved crude differentials in the year ended December 31, 2012. Excise taxes included in cost of sales were $300.1 million and $242.9 million for the years ended December 31, 2012 and 2011, respectively.

Direct operating expenses. Direct operating expenses totaled $254.1 million for the year ended December 31, 2012 compared to $257.9 million for the year ended December 31, 2011, a decrease of 1.5%, due primarily to lower operating expenses at our retail stores and reduced utility expenses at the refinery, which were driven by lower natural gas costs, partially offset by costs recognized in the year ended December 31, 2012 related to environmental compliance projects at our refinery’s wastewater treatment plant and the impact of increased volumes on variable costs at our refinery.

Turnaround and related expenses. Turnaround and related expenses totaled $26.1 million for the year ended December 31, 2012 compared to $22.6 million for the year ended December 31, 2011. Both periods include costs related to planned, partial turnarounds. The 2012 partial turnarounds include the alkylation unit, which was completed according to schedule in mid-May, and the No. 1 reformer unit, which was completed in November 2012. The 2011 partial 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 $33.2 million for the year ended December 31, 2012 compared to $29.5 million for the year ended December 31, 2011, an increase of 12.5%. This increase was due to depreciation of assets placed in service primarily related to our refinery and our systems implementation project.

Selling, general and administrative expenses. Selling, general and administrative expenses were $88.3 million for the year ended December 31, 2012 compared to $88.7 million for the year ended December 31, 2011. This decrease of 0.5% from the prior-year period relates primarily to lower administrative costs as the year ended December 31, 2012 did not include transition services fees to utilize Marathon systems. This reduction is partially offset by higher administrative costs in the first six months of 2012 related to post go-live systems support during the process optimization phase of our standalone systems implementation.

Formation and offering costs. Formation and offering costs for the year ended December 31, 2012 and 2011 were $1.4 million and $7.4 million, respectively. The formation and offering costs in the year ended December 31, 2012 relate to offering costs for sales of common units that did not meet the accounting requirements for deferral. 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 year ended December 31, 2012 compared to contingent consideration income of $55.8 million for the year ended December 31, 2011. The contingent consideration losses relate to the margin support and earn-out agreements entered into with Marathon at the time of the Marathon 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 IPO. The contingent consideration income in the 2011 period relates to changes in the financial performance estimates as of December 31, 2011 for the then remaining period of performance.

Other income, net. Other income, net was $9.4 million for the year ended December 31, 2012 compared to $4.5 million for the year ended December 31, 2011. This change is driven primarily by increases in equity income from our investment in MPL.

Gains (losses) from derivative activities. For the year ended December 31, 2012, we had losses from derivative activities of $271.4 million versus loses of $352.2 million in the year ended December 31, 2011. We had settlement losses of $339.4 million related to settled contracts for the year ended December 31, 2012 compared to $310.3 million in the prior-year period. Offsetting benefits related to these losses were recognized through improved operating margins. We incurred a gain from the change in fair value of outstanding derivatives of $68.0 million for the year ended December 31, 2012 compared to a loss of $41.9 million during the year ended December 31, 2011. These derivatives were entered into to partially hedge the crack spreads for our refining business.

Interest expense, net. Interest expense, net was $42.2 million for the year ended December 31, 2012 and $42.1 million for the year ended December 31, 2011. These interest charges relate primarily to our senior secured notes as well as commitment fees and interest on the ABL facility and the amortization of deferred financing costs.

Loss on early extinguishment of debt. Loss on early extinguishment of debt for the year ended December 31, 2012 relates to the premiums paid and deferred financing costs written off related to the extinguishment of our senior secured notes due 2017 during the fourth quarter of 2012.

Income tax provision. The income tax provision for the year ended December 31, 2012 was $9.8 million compared to less than $0.1 million for the year ended December 31, 2011. Prior to August 1, 2012, we operated as a pass-through entity for federal tax purposes and, as such, only state taxes were recognized. Effective on August 1, 2012 our retail business became a

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tax paying entity for federal and state income taxes. The 2012 provision 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. Our net income was $197.6 million for the year ended December 31, 2012 compared to $28.3 million for the year ended December 31, 2011. This improvement of $169.3 million was primarily attributable to a $319.1 million increase in operating income for our refining segment due to improved refining gross margins in the year ended December 31, 2012 and reduced losses from derivative activities of $80.8 million. These improvements were partially offset by a $50.0 million loss on early extinguishment of debt and change of $160.1 million from our contingent consideration arrangement that negatively impacted net income in the year ended December 31, 2012.

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 consolidated results, such intersegment transactions are eliminated, as shown in the following tables.

	Year Ended December 31, 2013
(in millions)	Refining		Retail		Other/Elim			Consolidated
Revenue:
Sales and other revenue	$	3,520.2	$	1,459.0	$	—		$	4,979.2
Intersegment sales	1,015.8		—		(1,015.8		)	—
Segment revenue	$	4,536.0	$	1,459.0	$	(1,015.8	)	$	4,979.2
Cost of sales:
Cost of sales	$	4,015.8	$	275.8	$	—		$	4,291.6
Intersegment purchases	—		1,015.8		(1,015.8		)	—
Segment cost of sales	$	4,015.8	$	1,291.6	$	(1,015.8	)	$	4,291.6

	Year Ended December 31, 2012
(in millions)	Refining		Retail		Other/Elim			Consolidated
Revenue:
Sales and other revenue	$	3,171.5	$	1,482.4	$	—		$	4,653.9
Intersegment sales	1,041.1		—		(1,041.1		)	—
Segment revenue	$	4,212.6	$	1,482.4	$	(1,041.1	)	$	4,653.9
Cost of sales:
Cost of sales	$	3,303.7	$	281.2	$	—		$	3,584.9
Intersegment purchases	—		1,041.1		(1,041.1		)	—
Segment cost of sales	$	3,303.7	$	1,322.3	$	(1,041.1	)	$	3,584.9

	Year Ended December 31, 2011
(in millions)	Refining		Retail		Other/Elim			Consolidated
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	$	3,208.5	$	303.9	$	—		$	3,512.4
Intersegment purchases	—		1,043.1		(1,043.1		)	—
Segment cost of sales	$	3,208.5	$	1,347.0	$	(1,043.1	)	$	3,512.4

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Refining Segment

	Year Ended December 31,
(in millions)	2013			2012			2011
Revenue	$	4,536.0		$	4,212.6		$	3,804.1
Costs, expenses and other:
Cost of sales	4,015.8			3,303.7			3,208.5
Direct operating expenses	144.1			136.3			131.3
Turnaround and related expenses	73.3			26.1			22.6
Depreciation and amortization	30.4			25.2			21.5
Selling, general and administrative	29.9			26.7			38.6
Other income, net	(13.2		)	(12.7		)	(6.6		)
Operating income	$	255.7		$	707.3		$	388.2
Key Operating Statistics
Refining gross product margin (in millions)(3)	$	520.2		$	908.9		$	595.6
Total refinery production (bpd)(1)	75,882			84,530			82,079
Total refinery throughput (bpd)	75,464			83,851			81,150
Refined products sold (bpd)(2)	84,231			89,162			86,038
Per barrel of throughput:
Refining gross product margin(3)	$	18.89		$	29.62		$	20.11
Direct operating expenses(4)	$	5.23		$	4.44		$	4.43
Per barrel of refined products sold:
Refining gross product margin(3)	$	16.92		$	27.85		$	18.97
Direct operating expenses(4)	$	4.69		$	4.18		$	4.18
Refinery product yields (bpd):
Gasoline	34,329			40,825			40,240
Distillate(5)	26,074			27,113			24,841
Asphalt	8,321			11,434			9,888
Other(6)	7,158			5,158			7,110
Total	75,882			84,530			82,079
Refinery throughput (bpd):
Crude oil	74,237			81,779			77,452
Other feedstocks(7)	1,227			2,072			3,698
Total	75,464			83,851			81,150
Market Statistics:
Crude Oil Average Pricing:
West Texas Intermediate ($/barrel)	$	98.39		$	93.81		$	95.11
PADD II / Group 3 Average Pricing:
Unleaded 87 Gasoline ($/barrel)	$	114.99		$	119.40		$	117.60
Ultra Low Sulfur Diesel ($/barrel)	$	126.31		$	129.02		$	126.26

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

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

(3) Refining gross product margin is calculated by subtracting refining costs of sales from total refining revenues. Refining gross product margin 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 refining gross product margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. For a reconciliation of refining gross product margin to the most directly comparable GAAP measure, see “Results of Operations—Other Non-GAAP Performance Measures.” Refining gross product margin per barrel is a per barrel measurement calculated by dividing refining gross product margin by the total throughput or total refined products sold for the respective periods presented.

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(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.

Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012

Refining gross product margin. Refining gross product margin for the year ended December 31, 2013 was $520.2 million compared to $908.9 million for the year ended December 31, 2012, a decrease of 42.8%, primarily due to lower market crack spreads, higher costs for refined product purchases, which were made during our periods of extended turnarounds and maintenance, and lower sales volumes in the year ended December 31, 2013. Refining gross product margin per barrel of throughput was $18.89 for the year ended December 31, 2013 compared to $29.62 for the year ended December 31, 2012, a decrease of $10.73, or 36.2%, which is mostly attributable to lower crack spreads and higher costs for refined product purchases in the year ended December 31, 2013. The lower sales volumes during the year ended December 31, 2013 are related to the major plant turnaround activities, capacity expansion project and unplanned maintenance, which reduced 2013 refinery throughput.

Direct operating expenses. Direct operating expenses totaled $144.1 million for the year ended December 31, 2013 compared to $136.3 million for the year ended December 31, 2012, a 5.7% increase. This increase was due primarily to the impact of higher catalyst costs, unplanned maintenance and employee related costs within our refining segment in the year ended December 31, 2013.

Turnaround and related expenses. Turnaround and related expenses totaled $73.3 million for the year ended December 31, 2013 compared to $26.1 million for the year ended December 31, 2012. The turnaround costs in the year ended December 31, 2013 include the costs of a planned major plant turnaround which lasted the entire month of April 2013 and a partial turnaround involving our FCC unit which was completed during October 2013. 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 November 2012.

Depreciation and amortization. Depreciation and amortization was $30.4 million for the year ended December 31, 2013 compared to $25.2 million for the year ended December 31, 2012, an increase of 20.6%. This increase was due to increased assets placed in service as a result of our capital expenditures since December 31, 2012, the most significant of which was the expansion project for our crude unit No. 2 which was placed in service in the second quarter of 2013.

Selling, general and administrative expenses. Selling, general and administrative expenses were $29.9 million and $26.7 million for the year ended December 31, 2013 and 2012, respectively, an increase of 12.0%. This increase was primarily due to higher risk management costs in the year ended December 31, 2013.

Other income, net. Other income, net was $13.2 million for the year ended December 31, 2013 compared to $12.7 million for the year ended December 31, 2012. This increase is driven primarily by $2.6 million of miscellaneous income related to a settlement of an indemnification arrangement partially offset by lower equity income from our investment in MPL, which experienced reduced throughput volumes partially due to our turnaround and capital expansion activities.

Operating income. Income from operations was $255.7 million for the year ended December 31, 2013 compared to $707.3 million for the year ended December 31, 2012. This decrease from the prior-year period of $451.6 million is primarily due to less favorable market crack spreads and crude differentials, lower sales volumes and higher turnaround and direct operating expenses during the year ended December 31, 2013.

Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011

Refining gross product margin. Refining gross profit margin totaled $908.9 million for the year ended December 31, 2012 compared to $595.6 million for the year ended December 31, 2011, a 52.6% increase. This increase was primarily due to the impact of improved crude differentials versus benchmark crude prices, favorable market crack spreads and increased sales volumes in the year ended December 31, 2012. Refining gross product margin per barrel of throughput was $29.62 for the year ended December 31, 2012 compared to $20.11 for the year ended December 31, 2011, an increase of $9.51, or 47.3%, which is mostly attributable to improved crack spreads and improved crude differentials in the year ended December 31, 2012.

Direct operating expenses. Direct operating expenses totaled $136.3 million for the year ended December 31, 2012 compared to $131.3 million for the year ended December 31, 2011, a 3.8% increase. This increase was due primarily to the impact of increased volumes on variable costs at our refinery and costs recognized in 2012 related to environmental compliance

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projects at our refinery’s wastewater treatment plant, offset by lower utility expenses at the refinery, which resulted from decreases in natural gas prices during the year ended December 31, 2012.

Turnaround and related expenses. Turnaround and related expenses totaled $26.1 million for the year ended December 31, 2012 compared to $22.6 million for the year ended December 31, 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 November 2012. 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 and was completed in April 2011.

Depreciation and amortization. Depreciation and amortization was $25.2 million for the year ended December 31, 2012 compared to $21.5 million for the year ended December 31, 2011, an increase of 17.2%. This increase was due to increased assets placed in service as a result of our capital expenditures, 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 $26.7 million and $38.6 million for the year ended December 31, 2012 and 2011, respectively, a decrease of 30.8%. 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 year ended December 31, 2012.

Other income, net. Other income, net was $12.7 million for the year ended December 31, 2012 compared to $6.6 million for the year ended December 31, 2011. This increase is driven primarily by an increase in equity income from our investment in MPL, which increased its tariff rates in the third quarter of 2011.

Operating income. Income from operations was $707.3 million for the year ended December 31, 2012 compared to $388.2 million for the year ended December 31, 2011. This increase from the prior-year period of $319.1 million is primarily due to favorable crack spreads, crude differentials and higher throughput rates during the 2012 period.

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Retail Segment

	Year Ended December 31,
(in millions)	2013			2012			2011
Revenue	$	1,459.0		$	1,482.4		$	1,519.8
Costs, expenses and other:
Cost of sales	1,291.6			1,322.3			1,347.0
Direct operating expenses	119.2			118.8			126.6
Depreciation and amortization	7.1			7.5			7.2
Selling, general and administrative	25.9			25.1			25.0
Operating income	$	15.2		$	8.7		$	14.0
Operating data:
Retail gross product margin (1)	$	167.4		$	160.1		$	172.8
Company-owned stores:
Fuel gallons sold (in millions)	313.2			312.4			324.0
Fuel margin per gallon (2)	$	0.19		$	0.18		$	0.21
Merchandise sales (in millions)	$	341.6		$	340.4		$	340.3
Merchandise margin % (3)	25.9		%	25.4		%	25.4		%
Number of stores at period end	164			166			166
Franchisee stores:
Fuel gallons sold (in millions)(4)	46.9			45.4			51.5
Royalty income (in millions)	$	2.5		$	2.1		$	1.7
Number of stores at period end	75			70			67
Market Statistics:
PADD II gasoline prices ($/gallon)	$	3.52		$	3.61		$	3.53

(1) Retail gross product margin is calculated by subtracting retail costs of sales from total retail revenues. Retail gross product margin is a non-GAAP performance measure that we believe is important to investors in evaluating our retail performance as a general indication of the amount above our cost of products that we are able to sell retail 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 retail gross product 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 gross product margin to the most directly comparable GAAP measure, see “Results of Operations—Other Non-GAAP

(2) Fuel margin per gallon is calculated by dividing fuel margin by the fuel gallons sold at company-operated stores. Fuel margin is a non-GAAP performance measure that we believe is important to investors in evaluating our retail performance. Our calculation of fuel margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. For a reconciliation of fuel margin to the most directly comparable GAAP measure, see “Results of Operations—Other Non-GAAP Performance Measures.”

(3) 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. Merchandise margin includes all non-fuel sales at our company-operated stores including items like cigarettes, beer, milk, food, general merchandise, car wash and other commission-based revenue. For a reconciliation of merchandise margin to the most directly comparable GAAP measure, see “Results of Operations—Other Non-GAAP Performance Measures.”

(4) Represents fuel gallons sold to franchised stores by our St. Paul Park, MN refinery.

Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012

Retail gross product margin. Retail gross product margin for the year ended December 31, 2013 was $167.4 million compared to $160.1 million for the year ended December 31, 2012, an increase of 4.6%. This increase was primarily due to higher fuel margin at our company operated stores which increased $4.1 million from the prior year. For company-operated stores, fuel margin per gallon was $0.19 for the year ended December 31, 2013 compared to $0.18 per gallon for the year ended

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December 31, 2012. Additionally, fuel gallons sold in our company operated stores increased by 0.3% in the year ended December 31, 2013.

Direct operating expenses. Direct operating expenses totaled $119.2 million for the year ended December 31, 2013 compared to $118.8 million for the year ended December 31, 2012, an increase of 0.3% from the 2012 period.

Depreciation and amortization. Depreciation and amortization was $7.1 million for the year ended December 31, 2013 compared to $7.5 million for the year ended December 31, 2012, a decrease of $0.4 million.

Selling, general and administrative expenses. Selling, general and administrative expenses were $25.9 million and $25.1 million for the year ended December 31, 2013 and 2012, respectively. The slight increase primarily relates to higher information technology costs in the year ended December 31, 2013.

Operating income. Operating income was $15.2 million for the year ended December 31, 2013 compared to $8.7 million for the year ended December 31, 2012, an increase of $6.5 million. The increase is primarily attributable to higher fuel margins per gallon and improved gross profit margins on merchandise sales during the year ended December 31, 2013.

Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011

Retail gross product margin. Retail gross product margin for the year ended December 31, 2012 was $160.1 million compared to $172.8 million for the year ended December 31, 2011, a decrease of 7.3%. This decrease was primarily due to lower fuel margin at our company operated stores which decreased $10.4 million from the prior year. For company-operated stores, fuel margin per gallon was $0.18 for the year ended December 31, 2012 compared to $0.21 per gallon for the year ended December 31, 2011. Additionally, fuel gallons sold in our company operated stores decreased by 3.6% in the year ended December 31, 2012 compared to the year ended December 31, 2011.

Direct operating expenses. Direct operating expenses totaled $118.8 million for the year ended December 31, 2012 compared to $126.6 million for the year ended December 31, 2011, a decrease of 6.2% from the 2011 period due to reductions in convenience store operating costs as a result of cost reduction efforts, primarily related to store personnel and contractor costs.

Depreciation and amortization. Depreciation and amortization was $7.5 million for the year ended December 31, 2012 compared to $7.2 million for the year ended December 31, 2011, an increase of 4.2%. The increase is due to increased depreciation from capital expenditures at our stores and for our new systems infrastructure, offset by a change in treatment for certain sale leaseback assets. During 2011, our continuing involvement ended for a subset of our retail stores which did not meet the criteria for sale 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.

Selling, general and administrative expenses. Selling, general and administrative expenses were $25.1 million and $25.0 million for the year ended December 31, 2012 and 2011, respectively. The slight increase relates to higher professional service fees and personnel costs, offset by lower back office costs in 2012 period. In the year ended December 31, 2011, our back office costs were higher as we developed our stand-alone infrastructure while continuing to pay transition services fees to utilize the Speedway LLC back office infrastructure of Marathon.

Operating income. Operating income was $8.7 million for the year ended December 31, 2012 compared to $14.0 million for the year ended December 31, 2011, a reduction of $5.3 million. The reduction is primarily attributable to lower fuel margins per gallon and lower fuel volumes partially offset by higher merchandise margin and lower operating expenses during the year ended December 31, 2012.

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 our senior secured notes and the revolving credit facility. Adjusted EBITDA should not be considered as an alternative to operating earnings or net earnings as 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

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and related expenses, equity-based compensation expense, gains (losses) from derivative activities, contingent consideration, formation and offering costs, bargain purchase gain and adjustments to reflect proportionate depreciation expense from MPL 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 MPL investment, but includes 17% of the calculated EBITDA of MPL;

• does not reflect gains and losses from derivative 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 income (loss) as reflected in the results of operations tables and segment footnote disclosures to Adjusted EBITDA for the periods presented:

	Year Ended December 31, 2013
	Refining		Retail		Other			Total
(in millions)
Net income (loss)	$	255.7	$	15.2	$	(39.8	)	$	231.1
Adjustments:
Interest expense	—		—		26.9			26.9
Income tax provision	—		—		4.2			4.2
Depreciation and amortization	30.4		7.1		0.6			38.1
EBITDA subtotal	286.1		22.3		(8.1		)	300.3
MPL proportionate depreciation expense	2.9		—		—			2.9
Turnaround and related expenses	73.3		—		—			73.3
Equity-based compensation expense	—		—		7.1			7.1
Formation and offering costs	—		—		3.1			3.1
Gains from derivative activities	—		—		(23.5		)	(23.5		)
Adjusted EBITDA	$	362.3	$	22.3	$	(21.4	)	$	363.2

	Year Ended December 31, 2012
	Refining		Retail		Other			Total
(in millions)
Net income (loss)	$	707.3	$	8.7	$	(518.4	)	$	197.6
Adjustments:
Interest expense	—		—		42.2			42.2
Income tax provision	—		—		9.8			9.8
Depreciation and amortization	25.2		7.5		0.5			33.2
EBITDA subtotal	732.5		16.2		(465.9		)	282.8
MPL proportionate depreciation expense	2.8		—		—			2.8
Turnaround and related expenses	26.1		—		—			26.1
Equity-based compensation expense	—		—		0.9			0.9
Contingent consideration loss	—		—		104.3			104.3
Loss on early extinguishment of debt	—		—		50.0			50.0
Formation and offering costs	—		—		1.4			1.4
Losses from derivative activities	—		—		271.4			271.4
Adjusted EBITDA	$	761.4	$	16.2	$	(37.9	)	$	739.7

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	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
MPL proportionate depreciation expense	2.8		—		—			2.8
Turnaround and related expenses	22.6		—		—			22.6
Equity-based compensation expense	—		—		1.6			1.6
Contingent consideration income	—		—		(55.8		)	(55.8		)
Formation and offering costs	—		—		7.4			7.4
Losses from derivative activities	—		—		352.2			352.2
Adjusted EBITDA	$	435.1	$	21.2	$	(25.6	)	$	430.7

Other Non-GAAP Performance Measures

Refining gross product margin per barrel, retail fuel margin and merchandise margin are non-GAAP performance measures that we believe are important to investors in analyzing our segment performance.     

Refining gross product margin per barrel is a financial measurement calculated by subtracting refining costs of sales from total refining revenues and dividing the difference by the total throughput or total refined products sold for the respective periods presented. Refining gross product margin is a non-GAAP performance measure that we believe is important to investors in evaluating our refining 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 these calculations (revenues and cost of sales) can be reconciled directly to our statements of operations. Our calculation of refining gross product margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure.

The following table shows the reconciliation of refining gross product margin to refining revenue and refining cost of sales for the periods indicated. A reconciliation of refining revenue and refining cost of sales to consolidated revenue and cost of sales in our consolidated statements of operations and comprehensive income is included above in “—Segment Financial Data.”

	Year Ended December 31,
(in millions)	2013		2012		2011
Refining revenue	$	4,536.0	$	4,212.6	$	3,804.1
Refining cost of sales	4,015.8		3,303.7		3,208.5
Refining gross product margin	$	520.2	$	908.9	$	595.6

Retail fuel margin and merchandise margin are non-GAAP measures that we believe are important to investors in evaluating our retail segment’s operating results as these measures provide an indication of our performance on significant product categories within the segment. Our calculation of fuel margin and merchandise margin may differ from similar calculations of other companies in our industry, thereby limiting their usefulness as comparative measures.

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The following table shows the reconciliations of fuel margin and merchandise margin to retail revenue and retail cost of sales for the periods indicated. A reconciliation of retail revenue and retail cost of sales to consolidated revenue and cost of sales in our consolidated statements of operations and comprehensive income is included above in “—Segment Financial Data.”

	Year Ended December 31,
(in millions)	2013			2012			2011
Retail revenue:
Fuel revenue	$	1,089.5		$	1,114.5		$	1,149.6
Merchandise revenue	341.6			340.4			340.3
Other revenue	46.7			45.9			49.2
Intercompany eliminations	(18.8		)	(18.4		)	(19.3		)
Retail revenue	1,459.0			1,482.4			1,519.8
Retail cost of sales:
Fuel cost of sales	1,029.3			1,058.4			1,083.1
Merchandise cost of sales	253.2			254.1			254.0
Other cost of sales	27.9			28.2			29.2
Intercompany eliminations	(18.8		)	(18.4		)	(19.3		)
Retail cost of sales	1,291.6			1,322.3			1,347.0
Retail gross product margin:
Fuel margin	60.2			56.1			66.5
Merchandise margin	88.4			86.3			86.3
Other margin	18.8			17.7			20.0
Intercompany eliminations	—			—			—
Retail gross product margin	$	167.4		$	160.1		$	172.8

Liquidity and Capital Resources

Our primary sources of liquidity have traditionally been cash generated from our operating activities and availability 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. We may make strategic investments with the objective of increasing cash available for distribution to our unitholders. These strategic investments would be financed via debt or equity issuances. Our ability to make these investments 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 “Description of Our Indebtedness—Senior Secured Asset-Based Revolving Credit Facility.”

On July 31, 2012, we closed our IPO of 18,687,500 common units. We used the net proceeds from our IPO of approximately $245 million and cash on hand of approximately $56 million 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, TPG Refining and entities in which our President and Chief Executive Officer held 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 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.

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On November 8, 2012, we completed a private placement of the 2020 Secured Notes. We used the net proceeds of the offering and cash on hand of $31 million (i) to repurchase our outstanding 2017 Secured Notes that were tendered pursuant to our previously announced tender offer and (ii) to satisfy and discharge any remaining 2017 Secured 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.

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. However, we may increase future liquidity via the sale of additional common units.

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 “Item 7A. Quantitative and Qualitative Disclosures About Market Risk.”

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 does not generate enough RINs to meet the current year requirement for some fuel categories, so we must purchase RINs on the open market for these categories. We project that our 2014 RINs requirement will exceed the amount of RINs we obtain through our normal blending operations by between 15 and 20 million RINs. This shortfall, net of RIN credits on hand as of December 31, 2013 will require us to purchase between 10 and 15 million RINs on the open market in 2014. The expense related to these RINs requirements are recognized throughout the year as incurred and are included within cost of sales in our consolidated statements of operations.

Cash Flows

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

	Year Ended December 31,
(in millions)	2013			2012			2011
Net cash provided by operating activities	$	229.8		$	308.5		$	209.3
Net cash used in investing activities	(95.5		)	(28.7		)	(156.3		)
Net cash used in financing activities	(321.4		)	(130.4		)	(2.3		)
Net increase (decrease) in cash and cash equivalents	(187.1		)	149.4			50.7
Cash and cash equivalents at beginning of period	272.9			123.5			72.8
Cash and cash equivalents at end of period	$	85.8		$	272.9		$	123.5

Net Cash Provided By Operating Activities. Net cash provided by operating activities for the year ended December 31, 2013 was $229.8 million. The most significant providers of cash were our net income ($231.1 million) adjusted for non-cash items, such as depreciation and amortization expense ($38.1 million), gain from the change in fair value of outstanding derivatives ($41.6 million) and equity-based compensation expense ($7.1 million). Additionally, cash was minimally impacted by net working capital changes.

Net cash provided by operating activities for the year ended December 31, 2012 was $308.5 million. The most significant providers of cash were our net income ($197.6 million) adjusted for non-cash adjustments, such as depreciation and amortization expense ($33.2 million), deferred income taxes ($9.8 million), loss on extinguishment of debt ($50.0 million), gain from the change in fair value of outstanding derivatives ($68.0 million) and contingent consideration loss ($104.3 million). Additionally, cash was negatively impacted by a net working capital increase of $26.8 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 income ($28.3 million) adjusted for non-cash adjustments, such as depreciation and amortization expense ($29.5 million), loss gain from the change in fair value of outstanding derivatives ($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) mainly driven by the expansion of our trade credit.

Net Cash Used In Investing Activities. Net cash used in investing activities for the year ended December 31, 2013 was $95.5 million, relating primarily to capital expenditures of $96.6 million. Capital spending for the year ended December 31,

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2013 primarily included the capacity expansion project on our crude unit No. 2 and our waste water treatment plant construction at our refinery and safety related enhancements and facility improvements at the refinery and retail store locations.

Net cash used in investing activities for the year ended December 31, 2012 was $28.7 million, relating primarily to capital expenditures of $30.9 million. Capital spending for the year ended December 31, 2012 primarily included safety related enhancements and facility improvements at the refinery and retail store locations.

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 the 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 Financing Activities. Net cash used in financing activities for the year ended December 31, 2013 of $321.4 million was primarily related to our quarterly distributions to unitholders.

Net cash used in financing activities for the year ended December 31, 2012 was $130.4 million. The net proceeds from our IPO of $230.4 million were the primary source of cash from financing activities. Out of those proceeds, we repaid $29.0 million of the 2017 Secured Notes and distributed $124.2 million to NT Holdings. Additionally, during the second quarter of 2012 we made an equity distribution in the amount of $40 million to NT Holdings. During the fourth quarter of 2012 we refinanced our senior secured notes, retiring our 2017 Secured Notes for their face value of $290 million plus early extinguishment premiums of $39.5 million and we received gross proceeds of $275 million related to the our 2020 Secured Notes. These proceeds were offset by related offering costs of $6.1 million. Additionally, in the fourth quarter of 2012, we issued our initial distribution to unitholders of $136.0 million.

Net cash used in financing activities was $2.3 million for the year ended December 31, 2011, representing tax distributions to NT Holdings.

Working Capital

Working capital at December 31, 2013 was $109.5 million, consisting of $525.0 million in total current assets and $415.5 million in total current liabilities. The reduction in working capital from the prior year primarily relates to a decrease in cash as a result of our distributions to unitholders of $321.4 million and our capital expenditures of $96.6 million offset by our cash provided by operations of $229.8 million for the year ended December 31, 2013.

Working capital at December 31, 2012 was $248.0 million, consisting of $599.5 million in total current assets and $351.5 million in total current liabilities. Working capital at December 31, 2012 was impacted by the short-term liability for the fair value of our outstanding derivatives of $43.7 million related to our crack spread risk management program. The offsetting benefits related to this liability should be realized over future periods as improved crack spread margins are realized.

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 as of 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. Distributions will be based on the amount of available cash generated in such quarter. Available cash for each quarter will generally equal our cash flow from operations for the quarter excluding working capital changes, less cash required for maintenance capital expenditures, 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 turnaround and related expenses. 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

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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 the available cash we generate each quarter, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. 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 of crude oil and other feedstocks and the prices received for finished products, (iii) working capital requirements, (iv) capital expenditures and (v) cash reserves deemed necessary or appropriate by the board of directors of our general partner. Such variations in the amount of the quarterly distributions may be significant. Unlike most publicly traded partnerships, we do 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.

The following table details the quarterly distributions paid to common unitholders since our IPO in July 2013 (in millions, except per unit amounts):

Date Declared	Date Paid	Common Units (in millions)	Distribution per common unit		Total Distribution (in millions)
2012 Distributions:
November 12, 2012	November 29, 2012	91.9	$	1.48	$	136.0
Total distributions paid during 2012			$	1.48	136.0
2013 Distributions:
February 11, 2013	February 28, 2013	91.9	$	1.27	116.7
May 13, 2013	May 30, 2013	92.2	$	1.23	113.4
August 13, 2013	August 29, 2013	92.2	$	0.68	62.7
November 11, 2013	November 27, 2013	92.2	$	0.31	28.6
Total distributions paid during 2013			$	3.49	321.4
2014 Distributions:
February 7, 2014	February 28, 2014	92.3	$	0.41	37.8
Distributions declared during 2014			$	0.41	37.8
Total distributions declared since our IPO			$	5.38	$	495.2

Notwithstanding our distribution policy, certain provisions of the indenture governing the 2020 Secured 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.”

Capital Spending

Total capital spend was $96.6 million for the year ended December 31, 2013.  Non-discretionary capital spending was $42.2 million for the year ended December 31, 2013 which included $13.6 million towards the upgrade of our waste water treatment facility.  The remaining non-discretionary capital spending primarily related to the replacement or major maintenance of equipment at the refinery, as well as to make safety enhancements.  Discretionary spending was $54.4 million for the year ended December 31, 2013.  Included in this discretionary spending was approximately $40 million for a project which resulted in a 10% capacity expansion at our refinery that, along with other discretionary projects, improved our distillate recovery by 2-3%. We estimate that these discretionary projects will have an average payback of less than eighteen months. 

Capital spending was $30.9 million for the year ended December 31, 2012, which primarily included spending to replace or maintain equipment at the refinery, as well as to make safety enhancements.

We currently expect to spend approximately $30 - $40 million on non-discretionary capital projects in 2014, including approximately $10 - 15 million to complete the upgrade of our waste water treatment facility. The remaining non-discretionary projects relate to the ongoing replacement spending also referred to as maintenance capital.

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Contractual Obligations and Commitments

We have the following contractual obligations and commitments as of December 31, 2013 (in millions):

	Less than 1 year		1-3 years		3-5 years		More than 5 years		Total
Long-term debt(1)	$	21.1	$	42.2	$	40.0	$	311.7	$	415.0
Lease obligations(2)	23.9		46.1		43.7		145.6		259.3
Capital expenditures(3)	16.1		—		—		—		16.1
Environmental remediation costs	0.7		1.1		0.7		6.4		8.9

(1) Long-term debt represents (i) the repayment of the $275 million of the 2020 Secured Notes at their 2020 maturity date, (ii) cash interest payments for the 2020 Secured Notes through the 2020 maturity date and (iii) commitment fees of 0.5% on an assumed $300 million undrawn balance under our revolving credit facility with a maturity date of 2017.

(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, including trucks to transport crude oil, 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.

Off-Balance Sheet Arrangements

In connection with the closing of the Marathon Acquisition, we entered into a lease arrangement with Realty Income (the "Realty Income Lease"), 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. As of December 31, 2013, we have 133 SuperAmerica convenience stores and the one support facility remaining under the Realty Income Lease.

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, 2013, the availability under our revolving credit facility was $134.6 million. This availability is net of $34.2 million in outstanding letters of credit as of December 31, 2013. We had no borrowings under our revolving credit facility at December 31, 2013.

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 December 31, 2013, the most recent determination date, the fixed charge coverage ratio was 6.5 to 1.0.

Our revolving credit facility contains customary 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.

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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 Secured 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 Secured Notes and cash on hand of $31 million were used to repurchase the 2017 Secured Notes tendered pursuant to the tender offer for the 2017 Secured Notes and to satisfy and discharge any remaining 2017 Secured 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 Secured Notes. Effective in October 2013, the 2020 Secured Notes were registered with the SEC and became publicly traded debt.

The Notes Issuers’ obligations under the 2020 Secured 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 Secured Notes and (ii) all other material wholly-owned domestic subsidiaries of NTE LLC. The 2020 Secured 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 Secured 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 Secured 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 Secured 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 Secured 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 Secured 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 Secured 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 Secured 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 Secured 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 Secured 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 Secured 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 Secured Notes on the relevant record date to receive interest due on the relevant interest payment date.

Except pursuant to the preceding paragraphs, the 2020 Secured 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 Secured 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 Secured 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 Secured 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 Secured 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.

Under the terms of the 2020 Secured Notes, the sale of NT InterHoldCo LLC to Western Refining during the fourth quarter of 2013 represented a change in control. This change in control required us to extend a thirty day offer to our noteholders to repurchase any or all of the notes they held at a price equivalent to 101% of the aggregate principal amount. Upon expiration of the thirty day term, none of our noteholders had accepted the repurchase offer.

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 years ended December 31, 2013, 2012 and 2011. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy.

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

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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.

Investment in MPL and MPL Investments

Our 17% common interest in MPL 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 earnings attributed to common owners generated by MPL.

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 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 MPL. Dividends received from MPL Investments are recorded as return of capital from cost method investment and in other income.

Intangible Assets

Intangible assets primarily include a retail marketing trade name and franchise agreements. The marketing trade name and franchise agreements have indefinite lives 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. If the estimated fair value is less than the carrying amount of the asset, an impairment loss is recognized based on the estimated fair value of the asset. Significant assumptions in determining the estimated fair value of the indefinite lived intangibles include projected store growth, estimated market royalty rates, market growth rates and the estimated discount rate.

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

Defined Benefit Plans

Our pension plan and a retiree medical plan are considered defined benefit plans. Expenses and liabilities related to these plans are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets, and assumed discount rates and demographic data.

Pension and retiree medical plan expenses and liabilities are determined based on actuarial valuations. Inherent in these valuations are key assumptions including discount rates, future compensation increases, expected return on plan assets, health care cost trends, and demographic data. Changes in our actuarial assumptions are primarily influenced by factors outside of our control and could have a significant effect on our pension and retiree medical liabilities and costs.

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. A conditional asset retirement obligation for removal and disposal of fire-retardant material from certain refining assets has been recognized. The amounts recorded for this obligation is 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.

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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 may use derivative instruments associated with the purchase or sale of crude oil and refined products. Crack spread option contracts may be 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. As of December 31, 2013, we have no outstanding derivatives.

Recent Accounting Pronouncements

In February 2013, the FASB issued ASU No. 2013-2, “Reporting of Amounts Reclassified Out of Other Comprehensive Income,” which requires public companies to present information about reclassification adjustments from accumulated other comprehensive income in their annual and interim financial statements in a single note or on the face of the financial statements. This standard is effective prospectively for annual and interim reporting periods beginning after December 15, 2012. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

In July 2012, the FASB issued guidance intended to simplify the impairment test for indefinite-lived intangible assets other than goodwill by giving entities the option to first assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired. The results of the qualitative assessment would be used as a basis in determining whether it is necessary to perform the two-step quantitative impairment testing. An entity can choose to perform the qualitative assessment on none, some or all of its indefinite-lived intangible assets, or may bypass the qualitative assessment and proceed directly to the quantitative impairment test. This guidance is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted in certain circumstances. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

We are exposed to various market risks, including changes in commodity prices and interest rates. We may use financial instruments such as puts, calls, swaps, forward agreements and other financial instruments to 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 year ended December 31, 2013 of 75,464 bpd, would result in a change of $27.5 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. Assuming all other factors remained constant, a $1 per barrel change in our gasoline and distillate basis would result in an annual change of $12.5 million and $9.5 million in our gross product margin on gasoline and distillate sales, respectively, based on our average refinery production for the year ended December 31, 2013 of 34,329 bpd and 26,074 bpd, respectively.

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 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 December 31, 2013, we have no hedged barrels of future gasoline and diesel production. Our hedge positions for 2011 and 2012 production were established at the time of the Marathon Acquisition.

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 levels of expected production, we intend to hedge significantly less than what we hedged at the time of the Marathon Acquisition on an ongoing

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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, 2013, the availability under our revolving credit facility was $134.6 million. This availability is net of $34.2 million in outstanding letters of credit as of December 31, 2013. We had no borrowings under our revolving credit facility at December 31, 2013. 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 “Item 7. 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 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 wholesale refining 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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Item 8.         Financial Statements and Supplementary Data.

NORTHERN TIER ENERGY LP

Index to Financial Statements

Management’s Report on Internal Control Over Financial Reporting	79
Report of Independent Registered Accounting Firm	80
Consolidated Balance Sheets	81
Consolidated Statements of Operations and Comprehensive Income	82
Consolidated Statements of Cash Flows	83
Consolidated Statements of Partners’ Capital and Member’s Interest	84
Notes to Consolidated Financial Statements	85

78

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934, as amended, as a process designed by, or under the supervision of, our principal executive and principal financial officers and effected by our board of directors, management, and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:

• Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect our transactions and dispositions of the assets;

• Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and the receipts and expenditures are being made only in accordance with authorizations of our management and directors; and

• Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of our assets that could have a material effect on our financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2013. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) in Internal Control-Integrated Framework (1992). Based on its assessment, our management concludes that, as of December 31, 2013, our internal control over financial reporting is effective based on those criteria.

The effectiveness of our internal control over financial reporting as of December 31, 2013 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm as stated in their report which appears herein.

79

Report of Independent Registered Public Accounting Firm

To the Board of Directors, General Partner and Unitholders of Northern Tier Energy LP

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations and comprehensive income, of partners’ capital and member’s interest and of cash flows present fairly, in all material respects, the financial position of Northern Tier Energy LP and its subsidiariesat December 31, 2013 and 2012, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2013 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on criteria established in Internal Control - Integrated Framework (1992) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our audits (which was an integrated audit in 2013). We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included 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. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 27, 2014

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NORTHERN TIER ENERGY LP

CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)

	December 31, 2013			December 31, 2012
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	85.8		$	272.9
Receivables, less allowance for doubtful accounts	242.0			129.3
Inventories	173.5			162.4
Other current assets	23.7			34.9
Total current assets	525.0			599.5
NON-CURRENT ASSETS
Equity method investment	86.2			87.5
Property, plant and equipment, net	446.2			386.0
Intangible assets	33.8			35.4
Other assets	26.6			28.4
Total Assets	$	1,117.8		$	1,136.8
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	367.0		$	230.4
Accrued liabilities	48.5			77.4
Derivative liability	—			43.7
Total current liabilities	415.5			351.5
NON-CURRENT LIABILITIES
Long-term debt	275.0			275.0
Lease financing obligation	8.4			7.5
Other liabilities	17.8			19.0
Total liabilities	716.7			653.0
Commitments and contingencies	—			—
EQUITY
Accumulated other comprehensive loss	(2.0		)	(2.5		)
Partners' capital (92,100,363 and 91,921,112 units issued and outstanding at December 31, 2013 and 2012, respectively)	403.1			486.3
Total equity	401.1			483.8
Total Liabilities and Equity	$	1,117.8		$	1,136.8

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

(in millions, except unit and per unit data)

	For the year ended December 31,
	2013			2012			2011
REVENUE (a)	$	4,979.2		$	4,653.9		$	4,280.8
COSTS, EXPENSES AND OTHER
Cost of sales (a)	4,291.6			3,584.9			3,512.4
Direct operating expenses	262.4			254.1			257.9
Turnaround and related expenses	73.3			26.1			22.6
Depreciation and amortization	38.1			33.2			29.5
Selling, general and administrative	85.8			88.3			88.7
Formation and offering costs	3.1			1.4			7.4
Contingent consideration loss	—			104.3			(55.8		)
Other income, net	(13.8		)	(9.4		)	(4.5		)
OPERATING INCOME	238.7			571.0			422.6
Gains (losses) from derivative activities	23.5			(271.4		)	(352.2		)
Interest expense, net	(26.9		)	(42.2		)	(42.1		)
Loss on early extinguishment of debt	—			(50.0		)	—
INCOME BEFORE INCOME TAXES	235.3			207.4			28.3
Income tax provision	(4.2		)	(9.8		)	—
NET INCOME	231.1			197.6			28.3
Other comprehensive income (loss), net of tax	0.5			(2.1		)	(0.4		)
COMPREHENSIVE INCOME	$	231.6		$	195.5		$	27.9
EARNINGS PER UNIT INFORMATION:
Net Income	$	231.1		$	197.6		$	28.3
Net Income prior to initial public offering on July 31, 2012	—			(70.7		)	(28.3		)
Net Income available to common unitholders	$	231.1		$	126.9		$	—
BASIC AND DILUTED:
Weighted average number of units outstanding	91,915,335			91,915,000
Earnings per common unit	$	2.51		$	1.38
SUPPLEMENTAL INFORMATION:
(a) Excise taxes included in revenue and cost of sales	$	316.4		$	300.1		$	242.9

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)

	Twelve Months Ended
Increase (decrease) in cash	2013			2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	231.1		$	197.6		$	28.3
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	38.1			33.2			29.5
Non-cash interest expense	2.4			7.5			3.9
Equity-based compensation expense	7.1			0.9			1.6
Loss on extinguishment of debt	—			50.0			—
Deferred income taxes	0.9			9.8			—
Contingent consideration loss (income)	—			104.3			(55.8		)
(Gain) loss from the change in fair value of outstanding derivatives	(41.6		)	(68.0		)	41.9
Changes in assets and liabilities, net:
Accounts receivable	(112.7		)	(47.7		)	18.3
Inventories	(11.1		)	(8.3		)	2.3
Other current assets	8.3			5.6			(6.8		)
Accounts payable and accrued expenses	110.3			29.9			146.4
Other, net	(3.0		)	(6.3		)	(0.3		)
Net cash provided by operating activities	229.8			308.5			209.3
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(96.6		)	(30.9		)	(45.9		)
Acquisition, net of cash acquired	—			—			(112.8		)
Return of capital from investments	1.1			2.2			2.4
Net cash used in investing activities	(95.5		)	(28.7		)	(156.3		)
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from senior secured notes	—			275.0			—
Repayments of senior secured notes	—			(290.0		)	—
Premiums paid to extinguish debt	—			(39.5		)	—
Borrowings from revolving credit arrangement	50.0			—			95.0
Repayments of revolving credit arrangement	(50.0		)	—			(95.0		)
Proceeds from IPO, net of direct costs of issuance	—			230.4			—
Financing costs	—			(6.1		)	—
Equity distributions	(321.4		)	(300.2		)	(2.3		)
Net cash used in financing activities	(321.4		)	(130.4		)	(2.3		)
CASH AND CASH EQUIVALENTS
Change in cash and cash equivalents	(187.1		)	149.4			50.7
Cash and cash equivalents at beginning of period	272.9			123.5			72.8
Cash and cash equivalents at end of period	$	85.8		$	272.9		$	123.5

The accompanying notes are an integral part of these consolidated financial statements.

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NORTHERN TIER ENERGY LP

CONSOLIDATED STATEMENTS OF

PARTNERS' CAPITAL AND MEMBER'S INTEREST

(in millions, except unit and per unit data)

				Partners' Capital				Accumulated Other Comprehensive Income
	Member's Interest			Common Units	Value						Total
Balance at December 31, 2010	$	285.0		—	$	—		$	—		$	285.0
Net income	28.3			—	—			—			28.3
Capital distributions	(2.3		)	—	—			—			(2.3		)
Other comprehensive loss	—			—	—			(0.4		)	(0.4		)
Equity-based compensation	1.6			—	—			—			1.6
Balance at December 31, 2011	312.6			—	—			(0.4		)	312.2
Net income attributable to the period from January 1, 2012 through July 31, 2012	70.7			—	—			—			70.7
Capital distributions	(164.1		)	—	—			—			(164.1		)
Capital contribution from parent	45.0			—	—			—			45.0
Equity-based compensation	1.0			—	—			—			1.0
Balance - July 31, 2012 prior to contribution of assets	265.2			—	—			(0.4		)	264.8
Net income attributable to the period from August 1, 2012 through December 31, 2012	—			—	126.9			—			126.9
Exchange with NTH of all partnership units in NTE LP for 100% membership interest in NTE LLC	(265.2		)	91,915,000	265.2						—
Proceeds from IPO, net of direct costs of issuance	—			—	230.4			—			230.4
Distributions to limited partners	—			—	(136.1		)	—			(136.1		)
Other comprehensive loss	—			—				(2.1		)	(2.1		)
Equity-based compensation, net of forfeitures	—			6,112	(0.1		)	—			(0.1		)
Balance at December 31, 2012	—			91,921,112	486.3			(2.5		)	483.8
Net income					231.1						231.1
Distributions to limited partners					(321.4		)				(321.4		)
Other comprehensive gain								0.5			0.5
Equity-based compensation, net of forfeitures				179,251	7.1						7.1
Balance at December 31, 2013	$	—		92,100,363	$	403.1		$	(2.0	)	$	401.1

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” 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. 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 of NTE LP (the “IPO,” 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., 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 includes the operations of NTE LLC, St. Paul Park Refining Co. LLC (“SPPR”), Northern Tier Retail Holdings LLC (“NTRH”) and Northern Tier Oil Transport LLC (“NTOT”). 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 (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). NTOT is a crude oil trucking business in North Dakota that collects crude oil directly from wellheads in the Bakken Shale and transports it to regional pipeline and rail facilities.

On November 12, 2013, NT Holdings formed a new subsidiary, NT InterHoldCo LLC, and contributed all of their interest in NTE LP and Northern Tier Energy GP LLC, the non-economic general partner of NTE LP, to NT InterHoldCo LLC. Subsequent to the contribution, NT Holdings entered into a definitive agreement to sell all of their interests in NT InterHoldCo LLC to Western Refining, Inc. (“Western Refining”) for total consideration of $775 million plus the distribution on the common units acquired with respect to the quarter ended September 30, 2013. As a result of this transaction, Western Refining indirectly owns 100% of Northern Tier Energy GP LLC, the general partner of NTE LP, and 35,622,500 common units, or 38.7%, of NTE LP. The balance of the limited partner units remain publicly traded. NTE LP received no proceeds from this transaction.

As of December 31, 2013, SPPR, which is located in St. Paul Park, Minnesota, has total crude oil throughput capacity of 89,500 barrels per calendar day or 96,500 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 December 31, 2013, NTR operates 164 convenience stores under the SuperAmerica brand and SAF supports 75 franchised stores which also utilize the SuperAmerica brand. These 239 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 financial statements have been prepared in accordance with United States generally accepted accounting principles (“GAAP”). 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.

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2. SUMMARY OF PRINCIPAL ACCOUNTING POLICIES

Principles of Consolidation

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, which were subsequently converted into common 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.

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.

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 value of $6.8 million as of December 31, 2013 and $6.9 million as of December 31, 2012 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.

Operating Segments

The Company has two reportable operating segments; Refining and Retail (see Note 21 for further information on the Company’s operating segments). The Refining and Retail operating segments consist of the following:

•Refining – operates the St. Paul Park, Minnesota refinery, terminal and related assets, NTOT and includes the Company’s interest in MPL and MPLI, and

•Retail – operates 164 convenience stores primarily in Minnesota and Wisconsin. The retail segment also includes the operations of NTB and SAF.

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 the consolidated statements of operations. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of sale. 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.

86

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 the purchase or sale of crude oil and refined products. Crack spread future and swap contracts may be 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 operations. These gains and losses are reported as operating activities within the consolidated statement of cash flows.

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.

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 $316.4 million, $300.1 million and $242.9 million for the years ended December 31, 2013, 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 related to NTRH as of the election date. Additionally, the Company recorded current period income taxes for all periods subsequent to August 1, 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. The Company’s policy is to recognize interest related to any underpayment of taxes as interest expense and any penalties as administrative expenses.

Product Exchanges

The Company enters into exchange contracts whereby it agrees to deliver a particular quantity and quality of crude oil or 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 crude oil or 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 inventories held in the ordinary course of business to facilitate sales to customers or delivery of feedstocks to our refinery. The exchange transactions are recognized at the carrying amount of the inventory transferred plus or minus any cash settlement due to grade or location differentials.

Advertising

The Company expenses the costs of advertising as incurred. Advertising expense was $2.0 million, $1.5 million and less than $1.0 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Receivables and Allowance for Doubtful Accounts

Receivables of the Company primarily consist of customer accounts receivable. The accounts receivable are due from a diverse base including companies in the petroleum industry, airlines and governmental entities. 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 $0.2 million and less than $0.1 million as of December 31, 2013 and 2012, receptively.

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 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 inventory held by the retail stores in its Retail segment.

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Internal-Use Software Development Costs

The Company capitalizes certain external 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. If the estimated fair value is less than the carrying amount of the asset, an impairment loss is recognized based on the estimated fair value of the asset. Significant assumptions in determining the estimated fair value of the indefinite lived intangibles include projected store growth, estimated market royalty rates, market growth rates and the estimated discount rate.

Financing Costs

Financing origination fees on our senior secured notes, revolving credit facility and sales-leaseback transaction are deferred and classified within other assets on the consolidated balance sheets. Amortization is provided on a straight-line basis over the term of the agreement, which approximates the effective interest method.

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 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.

Defined Benefit Plans

The Company has a pension plan and a retiree medical plan that are considered defined benefit plans. Expenses and liabilities related to defined benefit plans are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets, and assumed discount rates and demographic data.

Pension and retiree medical plan expenses and liabilities are determined based on actuarial valuations. Inherent in these valuations are key assumptions including discount rates, future compensation increases, expected return on plan assets, health care cost trends, and demographic data. Changes in our actuarial assumptions are primarily influenced by factors outside of our control and could have a significant effect on our pension and retiree medical liabilities and costs. See further information on our plans in Note 17.

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.

Equity-Based Compensation

The Company recognizes compensation expense for equity-based awards issued over the requisite service period. Equity-based compensation costs are measured at the date of grant, based on the fair value of the award.

Comprehensive Income

The Company has unrecognized prior service cost related to its defined benefit cash balance plan as of December 31, 2013, 2012 and 2011 and unrecognized actuarial losses and prior service cost related to its retiree benefits plan as of December 31, 2013 and 2012 (see Note 17). The accumulated unrecognized costs related to these plans amount to $2.0 million and $2.5

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million as of December 31, 2013, and 2012, respectively. These gains/(losses) of $0.5 million, ($2.1) million and ($0.4) million were recognized directly to equity as an element of other comprehensive income in the years ended December 31, 2013, 2012 and 2011, respectively.

Concentrations of Risk

The Company 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 MPL, 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 is exposed to concentrated geographical risk as most of its operations are conducted in the Upper Great Plains of the United States.

Reclassification

Certain reclassifications have been made to the prior-year financial information in order to conform to the Company’s current presentation. Realized losses from derivative activities and unrealized (losses) gains from derivative activities have been combined into a single line item, gains (losses) from derivative activities, within the consolidated statements of operations and comprehensive income.

Accounting Developments

In February 2013, the FASB issued ASU No. 2013-2, “Reporting of Amounts Reclassified Out of Other Comprehensive Income,” which requires public companies to present information about reclassification adjustments from accumulated other comprehensive income in their annual and interim financial statements in a single note or on the face of the financial statements. This standard is effective prospectively for annual and interim reporting periods beginning after December 15, 2012. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

In July 2012, the FASB issued guidance intended to simplify the impairment test for indefinite-lived intangible assets other than goodwill by giving entities the option to first assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired. The results of the qualitative assessment would be used as a basis in determining whether it is necessary to perform the two-step quantitative impairment testing. An entity can choose to perform the qualitative assessment on none, some or all of its indefinite-lived intangible assets, or may bypass the qualitative assessment and proceed directly to the quantitative impairment test. This guidance is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted in certain circumstances. Our adoption did not have a material impact on our financial position, results of operations or cash flows.

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);

• The Company’s management services agreement with ACON Refining Partners L.L.C and TPG Refining L.P. (see Note 4) was terminated;

• 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;

• NTE LP issued 18,687,500 common units to the public, representing a 20.3% limited partner interest; and

• 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 included ACON Refining Partners L.L.C. and TPG Refining L.P., were related parties of the Company through November 12, 2013, the date they sold their interest NT InterHoldCo LLC to Western Refining (see Note 1). 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 supply transactions with MPL. Subsequent to November 12, 2013, Western Refining is a related party.

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 $3.1 million and $2.1 million for the years ended December 31, 2012 and 2011, respectively. As a result of the 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 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 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, 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 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. The Company also agreed, pursuant to the settlement agreement, to relinquish all claims to margin support payments under the margin support agreement. While outstanding, this preferred interest in NT Holding was not dilutive to NTE LP unitholders. 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 $104.3 million recognized during the year ended December 31, 2012.

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

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employees providing such operations services, plus the agreed burden rates. For the year ended December 31, 2011, the Company recognized expenses of approximately $14.0 million related to administrative and support services. The Company also paid $6.7 million in December 2010 of which $6.1 million was amortized to expense during the year ended December 31, 2011 as these services were incurred. The majority of transition services were completed as of December 31, 2011 and, as such, the year ended December 31, 2012 includes less than $0.1 million of 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.

	Year Ended December 31,
(in millions)	2013		2012		2011
Current tax expense	$	3.3	$	—	$	—
Deferred tax expense	$	0.9	$	9.8	$	—
Total tax expense	$	4.2	$	9.8	$	—

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 Company’s effective tax rate for the years ended December 31, 2013 and 2012, was 1.8% and 4.7%, respectively as compared to the Company's consolidated federal and state expected statutory tax rate of 40.4% for both periods. The Company's effective tax rate for the years ended December 31, 2013 and 2012 was primarily due to the fact that only the retail operations of the Company are taxable entities. Additionally, the year ended December 31, 2012 was impacted by the opening deferred tax charge of $8.0 million which had the effect of increasing the effective tax rate.

The following is a reconciliation of the income tax expense to income taxes computed by applying the applicable statutory federal income tax rate to income before income taxes for the applicable periods:

	Year Ended December 31,
(in millions)	2013			2012			2011
Federal statutory rate applied to income before taxes	$	82.4		$	72.6		$	9.9
Taxes on earnings attributable to flow-through entities	(78.6		)	(71.6		)	(9.9		)
State and local income taxes, net of federal income tax effects	0.9			—			—
Initial charge upon NTRH's election to be treated as a corporation	—			8.0			—
Work opportunity tax credit	(0.6		)	—			—
Other, net	0.1			0.8			—
Income tax expense	$	4.2		$	9.8		$	—

As a result of the Company’s analysis, management has determined that the Company does not have any material uncertain tax positions. As of December 31, 2012, the Company had tax loss carryforwards of approximately $2.1 million which were fully utilized to satisfy 2013 taxes. As of December 31, 2013, the Company had no deferred tax assets arising from net operating losses. The Company is subject to U.S. federal and state income tax examinations for tax years from its date of inception.

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The net deferred tax assets (liabilities) as of December 31, 2013 and 2012 consisted of the following components:

		December 31,
(in millions)		2013			2012
Deferred tax liabilities:
	Accelerated depreciation	$	(3.4	)	$	(2.9	)
	Intangible assets	(11.7		)	(12.2		)
	Other	(0.2		)	—
Deferred tax liabilities		(15.3		)	(15.1		)
Deferred tax assets:
	Lease financing obligations	2.6			2.7
	Customer loyalty accrual	0.9			1.1
	Net operating loss carryforwards	—			0.8
	Other	1.1			0.7
Deferred tax assets		4.6			5.3
Total deferred taxes, net		$	(10.7	)	$	(9.8	)

The net deferred tax assets (liabilities) are included in the December 31, 2013 and 2012 balance sheets as components of other current assets and other liabilities.

7. INVENTORIES

	December 31,
(in millions)	2013		2012
Crude oil and refinery feedstocks	$	29.4	$	9.7
Refined products	106.7		117.0
Merchandise	22.6		20.8
Supplies and sundry items	14.8		14.9
Total	$	173.5	$	162.4

The LIFO method accounted for 78% of total inventory value at both December 31, 2013 and 2012.

During 2013, reductions in quantities of refined products inventory resulted in a liquidation of LIFO inventory quantities acquired at higher costs in prior years. The 2013 LIFO liquidation resulted in an increase in cost of sales of approximately $1.0 million. 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. There were no such LIFO liquidations during 2012.

8. EQUITY METHOD INVESTMENT

The Company has a 17% common equity interest in MPL. The carrying value of this equity method investment was $86.2 million and $87.5 million at December 31, 2013 and 2012, respectively.

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Summarized financial information for MPL is as follows:

	Year Ended December 31,
(in millions)	2013		2012		2011
Revenues	$	161.9	$	153.6	$	115.6
Operating costs and expenses	74.5		52.7		53.8
Income from operations	68.2		82.1		43.2
Net income	68.2		82.1		43.2
Net income available to common common shareholders	58.6		72.4		33.5

			December 31,
(in millions)			2013		2012
Balance sheet data:
	Current assets		$	26.1	$	13.0
	Noncurrent assets		462.9		477.3
		Total assets	$	489.0	$	490.3
	Current liabilities		$	19.8	$	14.6
	Noncurrent liabilities		—		—
		Total liabilities	$	19.8	$	14.6
	Members capital		$	469.2	$	475.7

As of December 31, 2013 and 2012, the carrying amount of the equity method investment was $6.4 million and $6.7 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 $11.1 million, $14.5 million and $8.0 million for the years ended December 31, 2013, 2012 and 2011 respectively. Equity income from MPL was $10.0 million, $12.3 million and $5.7 million for the years ended December 31, 2013, 2012 and 2011, respectively.

9. PROPERTY, PLANT AND EQUIPMENT

Major classes of property, plant and equipment (“PP&E”) consisted of the following:

	Estimated	December 31,
(in millions)	Useful Lives	2013		2012
Land		$	9.0	$	8.9
Retail stores and equipment	2 - 22 years	54.9		49.1
Refinery and equipment	5 - 24 years	403.5		330.4
Buildings and building improvements	25 years	8.9		8.3
Software	5 years	18.6		17.8
Vehicles	5 years	4.7		2.9
Other equipment	2 - 7 years	8.5		6.1
Precious metals		10.2		10.5
Assets under construction		26.3		14.3
		544.6		448.3
Less: accumulated depreciation		98.4		62.3
Property, plant and equipment, net		$	446.2	$	386.0

PP&E includes gross assets acquired under capital leases of $8.6 million and $7.9 million at December 31, 2013 and 2012, respectively, with related accumulated depreciation of $1.2 million and $0.7 million, respectively. The Company had

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depreciation expense related to capitalized software of $3.7 million, $3.2 million and $0.7 million for years ended December 31, 2013, 2012 and 2011, respectively.

10. INTANGIBLE ASSETS

Intangible assets are comprised of franchise rights and trade name amounting to $33.8 million and $35.4 million at December 31, 2013 and 2012, respectively. At December 31, 2013, the franchise rights and trade name intangible asset values were $12.4 million and $21.4 million, respectively. 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.

During the Company’s intangible assets impairment test for the year ended December 31, 2013, the Company identified a prior period error in the initial valuation of intangibles at inception on December 1, 2010. The impact of the error, which was immaterial to previously issued financial statements, resulted in an overstatement in the value of intangible assets at inception of $1.6 million. In the fourth quarter of 2013, an out-of-period adjustment was recorded to reduce intangible assets by $1.6 million and to reduce other liabilities by $0.6 million, for the related impact on long-term deferred tax liabilities. The Company recognized a $1.6 million charge, included in formation and offering costs, and a $0.6 million income tax benefit to correct this immaterial error.

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 operations. 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 December 31, 2013, the Company had no open commodity derivative instruments. At December 31, 2012, the Company had open commodity derivative instruments consisting of crude oil futures to buy approximately five million barrels and refined products futures and swaps to sell approximately five million barrels primarily to mitigate the volatility of refining margins through 2013.

All derivative contracts are marked to market at period end and the resulting gains and losses are recognized in earnings.

Recognized gains and losses on derivatives were as follows:

	For the year ended December 31,
(in millions)	2013			2012			2011
Gain (loss) on the change in fair value of outstanding derivatives	$	41.6		$	68.0		$	(41.9	)
Settled derivative gains (losses)	(18.1		)	(339.4		)	(310.3		)
Total recognized gain (loss)	$	23.5		$	(271.4	)	$	(352.2	)

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 settlement 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 began to come due beginning in September 2012 and will be fully paid by January 2014. The early extinguishments were treated as a current period loss as of the date of extinguishment. Interest accrues on the deferred loss liabilities at a weighted average interest rate of 7.1%. Interest expense related to these liabilities was $0.7 million and $2.5 million for the years ended December 31, 2013 and 2012, respectively. The remaining deferred payment obligations related to these early extinguishment losses of $0.9 million are included in the December 31, 2013 balance sheet within current liabilities. At December 31, 2012, $28.9 million of these deferred payment obligations are included in the balance sheet within current liabilities and $0.9 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 December 31, 2013 and 2012:

		December 31,
(in millions)	Balance Sheet Classification	2013		2012
Commodity swaps and futures	Other current assets	$	—	$	2.1
Commodity swaps and futures	Derivative liability	—		(43.7		)
Net asset (liability) position		$	—	$	(41.6	)

The Company is exposed to credit risk in the event of nonperformance by its counterparties on its risk mitigating arrangements. 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 of the counterparties involved in its risk mitigation arrangements.

The Company is not subject to any margin calls for these crack spread derivatives and the counterparties do not have the right to demand collateral.

12. DEBT

During the year ended December 31, 2012, the Company redeemed the $290 million outstanding of its 10.50% Senior Secured Notes due December 1, 2017 (“2017 Secured Notes”), completed a $275 million private placement of its 7.125% Senior Secured Notes due November 15, 2020 (“2020 Secured Notes”) and amended its $300 million secured asset-based revolving credit facility established in 2010 (“Initial ABL Facility”). The 2017 Senior Secured Notes and Initial ABL Facility were entered into in connection with the Marathon Acquisition.

2020 Secured Notes

On November 8, 2012, NTE LLC privately placed $275 million in aggregate principal amount of 7.125% senior secured notes due 2020. The 2020 Secured Notes are guaranteed, jointly and severally, on a senior secured basis by all of the Company’s existing and future 100% direct and indirect subsidiaries on a full and unconditional basis; however, there are certain obligations 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. The 2020 Secured Notes and the subsidiary note guarantees are secured on a pari passu basis with certain hedging agreements by a first-priority security interest in substantially all present and hereinafter acquired tangible and intangible assets of NTE LLC and each of the subsidiary guarantors and by a second-priority security interest in the inventory, accounts receivable, investment property, general intangibles, deposit accounts and cash and cash equivalents collateralized by the ABL facility. Additionally, the 2020 Secured Notes are fully and unconditionally guaranteed on a senior unsecured basis by NTE LP. The Company is required to make interest payments on May 15 and November 15 of each year, which commenced on May 15, 2013. There are no scheduled principal payments required prior to the notes maturing on November 15, 2020. Effective in October 2013, the 2020 Secured Notes were registered with the SEC and became publicly traded debt.

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.

Under the terms of the 2020 Secured Notes, the sale of NT InterHoldCo LLC to Western Refining on November 12, 2013 (see Note 1) represented a change in control. This change in control required the Company to extend a thirty day offer to noteholders to repurchase any or all of the notes they held at a price equivalent to 101% of the aggregate principal amount. Upon expiration of the thirty day term, none of the noteholders had accepted the repurchase offer.

The 2020 Secured Notes contain certain covenants that, among other things, limit the ability, subject to certain exceptions, of the Company to incur additional debt or issue preferred stock, to purchase, redeem or otherwise acquire or retire our equity interests, to make certain investments, loans and advances, to sell, lease or transfer any of our property or assets, to merge, consolidate, lease or sell substantially all of the Company’s assets, to suffer a change of control and to enter into new lines of business.

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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”) is a $300 million secured asset-based revolving credit facility with a maturity date of July 17, 2017.

The Amended ABL Facility includes a 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 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.

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 December 31, 2013, the borrowing base under the Amended ABL Facility was $168.8 million and availability under the Amended ABL Facility was $134.6 million (which is net of $34.2 million in outstanding letters of credit). The Company had no borrowings under the Amended ABL Facility at December 31, 2013 or 2012.

2017 Secured Notes

The 2017 Secured Notes were 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 was required to make interest payments on June 1 and December 1 of each year, which commenced on June 1, 2011. There were no scheduled principal payments required prior to the notes maturing on December 1, 2017. Borrowings bore interest at 10.50%.

At any time prior to the maturity date of the notes, the Company could, 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.

During the year ended December 31, 2012, NTE LLC redeemed the 2017 Secured Notes in multiple transactions, $29 million of the principal amount at a redemption price of 103% of the principal thereof out of the proceeds from its IPO (see note 3), $258 million of the principal amount at a weighted average redemption price of 114.9% of the principal thereof with proceeds from the concurrent issuance of the 2020 Secured Notes and the remaining $3 million of the principal amount at a redemption price of 103% of the principal thereof just subsequent to the second anniversary of the original issuance date. Due to these early redemptions, the Company recognized a non-cash charge of $10.5 million to write off the unamortized deferred financing cost on these bonds and redemption premiums of $39.5 million. The total loss on the early redemptions of $50.0 million is included in the loss on early extinguishment of debt caption on the statement of operations.

13. EQUITY

Public Offerings

As discussed in Note 3, concurrent with the closing of the 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 as of the IPO of 91,915,000, all of which represent limited partnership interests in NTE LP. In November 2012, the PIK common units initially issued to NT Holdings were converted into common units in conjunction with an amendment to the indenture governing the 2017 Secured Notes.

Additionally, during the year ended December 31, 2013, NT Holdings completed three secondary public offerings of 37,605,000 common units in total. These offerings did not increase the total common units outstanding and the Company received no proceeds. Under the Company’s partnership agreement, the offering costs from subsequent offerings of common units to the public by NT Holdings are incurred by the Company. During the year ended December 31, 2013, the Company incurred $1.5 million of offering costs from these secondary offerings.

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Western Refining Acquisition

On November 12, 2013, NT Holdings formed a new subsidiary, NT InterHoldCo LLC, and contributed all of their interest in NTE LP and Northern Tier Energy GP LLC, the non-economic general partner of NTE LP, to NT InterHoldCo LLC. Subsequent to the contribution, NT Holdings entered into a definitive agreement to sell all of their interests in NT InterHoldCo LLC to Western Refining for total consideration of $775 million plus the distribution on the common units acquired with respect to the quarter ended September 30, 2013. As a result of this transaction, Western Refining indirectly owns 100% of Northern Tier Energy GP LLC and 35,622,500 common units, or 38.7%, of NTE LP. The balance of the limited partner units remain publicly traded. NTE LP received no proceeds from this transaction. As of the purchase date, NT InterHoldCo LLC, as the owner of the general partner of NTE LP, has the ability to appoint all of the members of the general partner’s board of directors.

Distribution Policy

The Company 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 the Company’s cash flow from operations for the quarter excluding working capital changes, less cash required for maintenance capital expenditures, reimbursement of expenses incurred by the general partner of NTE LP and its affiliates, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of the general partner of NTE LP 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 of crude oil and other feedstocks and the prices received for finished products, (iii) working capital requirements, (iv) capital expenditures and (v) cash reserves deemed necessary or appropriate by the board of directors of NTE LP’s general partner. Such variations in the amount of the quarterly distributions may be significant. The Company’s general partner has no incentive distribution rights.

The following table details the quarterly distributions paid to common unitholders since our IPO in July 2013 (in millions, except per unit amounts):

Date Declared	Date Paid	Common Units (in millions)	Distribution per common unit		Total Distribution (in millions)
2012 Distributions:
November 12, 2012	November 29, 2012	91.9	$	1.48	$	136.0
Total distributions paid during 2012			$	1.48	$	136.0
2013 Distributions:
February 11, 2013	February 28, 2013	91.9	$	1.27	$	116.7
May 13, 2013	May 30, 2013	92.2	$	1.23	113.4
August 13, 2013	August 29, 2013	92.2	$	0.68	62.7
November 11, 2013	November 27, 2013	92.2	$	0.31	28.6
Total distributions paid during 2013			$	3.49	$	321.4

On February 7, 2014, the Company declared a quarterly distribution of $0.41 per unit to common unitholders of record on February 21, 2014, payable on February 28, 2014. This distribution of approximately $38 million in aggregate is based on available cash generated during the three months ended December 31, 2013.

Other Distributions

In conjunction with its IPO, NTE LP distributed $124.2 million to NT Holdings. 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 2012 and 2011, respectively.

Earnings per Unit

The following tables illustrate the computation of basic and diluted earnings per unit for the years ended December 31, 2013 and 2012. For the year ended December 31, 2011, NTE LP did not have publicly traded equity and thus did not calculate earnings per unit. The Company has outstanding restricted common units under its LTIP program (see note 16) that participate in non-forfeitable distributions, which requires the Company to calculate earnings per unit under the two-class method. Under

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this method, distributed earnings and undistributed earnings (loss) are allocated between unrestricted common units and restricted common units.

	Year ended December 31,
(in millions, except unit and per-unit data)	2013			2012
Net income available to common unitholders (a)	$	231.1		$	126.9
Less: distributed earnings to participating restricted common units	(0.6		)	—
Net income attributable to unrestricted common units	$	230.5		$	126.9
Weighted average unrestricted common units - basic & diluted	91,915,335			91,915,000
Basic & diluted earnings per share	$	2.51		$	1.38
(a) for 2012 calculations, net income available to common unitholders excludes earnings attributable to the period prior to our IPO date of July 31, 2012

14. FAIR VALUE MEASUREMENTS

As defined in GAAP, 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. GAAP 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.

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.

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The following table provides the assets and liabilities carried at fair value measured on a recurring basis at December 31, 2013 and 2012:

	Balance at		Quoted prices in active markets		Significant other observable inputs		Unobservable inputs
(in millions)	December 31, 2013		(Level 1)		(Level 2)		(Level 3)
ASSETS
Cash and cash equivalents	$	85.8	$	85.8	$	—	$	—
	$	85.8	$	85.8	$	—	$	—

	Balance at		Quoted prices in active markets		Significant other observable inputs		Unobservable inputs
(in millions)	December 31, 2012		(Level 1)		(Level 2)		(Level 3)
ASSETS
Cash and cash equivalents	$	272.9	$	272.9	$	—	$	—
Other current assets
Derivative asset - current	2.1		—		2.1		—
	$	275.0	$	272.9	$	2.1	$	—
LIABILITIES
Derivative liability - current	$	43.7	$	—	$	43.7	$	—
	$	43.7	$	—	$	43.7	$	—

As of December 31, 2013 and 2012, the Company had no Level 3 fair value assets or liabilities. During the third quarter of 2012 and in conjunction with the 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 and by the Company forgiving the $30 million margin support receivable owed by MPC to the Company. The Company recorded $104.3 million of contingent consideration losses during the year ended December 31, 2012 related to the changes in value and settlement of these arrangements. The $45 million preferred interest in NT Holdings held by MPC was redeemed during the year ended December 31, 2013.

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. 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 using management projections of future period EBITDA levels. Changes in the fair value of the Company’s Level 3 contingent consideration arrangements during the year ended December 31, 2012 were due to updated financial performance estimates and are as follows:

	Margin						Net
(in millions)	Support			Earnout			Impact
Fair Value at December 31, 2011	$	20.2		$	(30.9	)	$	(10.7	)
Change in fair value of remaining years	(20.2		)	(84.1		)	(104.3		)
Settlement of contingent consideration agreements	—			115.0			115.0
Fair Value at December 31, 2012	$	—		$	—		$	—

The significant unobservable inputs used in the fair value measurement of the Company’s Level 3 instruments 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.

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The Company’s policy is to recognize transfers in and transfers out as of the actual date of the event or of the change in circumstances that caused the transfer. For the years ended December 31, 2013 and 2012, there were no transfers in or out of Levels 1, 2 or 3.

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 years ended December 31, 2013, 2012 and 2011 there were no adjustments to the fair value of such assets.

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 2020 Secured Notes disclosed below was determined based on quoted prices in active markets (Level 1).

	December 31, 2013				December 31, 2012
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2020 Secured Notes	$	275.0	$	291.1	$	275.0	$	282.9

15. ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in asset retirement obligations:

	Year Ended December 31,
(in millions)	2013		2012		2011
Asset retirement obligation balance at beginning of period	$	1.9	$	1.5	$	2.1
Revisions of previous estimates	—		0.2		(0.9		)
Accretion expense	0.3		0.2		0.3
Asset retirement obligation balance at end of period	$	2.2	$	1.9	$	1.5

16. EQUITY-BASED COMPENSATION

The Company maintains an equity-based compensation plan designed to encourage employees and directors of the Company to achieve superior performance. The current plan is maintained by the general partner of NTE LP and is referred to as the 2012 Long-Term Incentive Plan (“LTIP”). A former equity-based plan (the “NT Investor Plan”) was sponsored by members of NT Investors, the parent company of NT Holdings, and granted profit unit interests in NT Investors. All equity-based compensation expense related to both plans is recognized by the Company. The Company recognized equity-based compensation expense of $7.1 million , $0.9 million and $1.6 million for the years ended December 31, 2013, 2012 and 2011, respectively, related to these plans.

LTIP

Approximately 9.2 million NTE LP common units are reserved for issuance under the LTIP. The LTIP was created concurrent with the 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 December 31, 2013, approximately 0.3 million units were outstanding under the LTIP, the majority of these units are restricted.

For the majority of these awards, fifty percent of the restricted unit grant is subject to time-based vesting conditions and fifty percent are subject to performance-based vesting conditions. For the performance based restricted units, the target number of units granted may be proportionally adjusted up or down subject to the Company meeting certain financial metrics, namely cash available for distribution for the 2013 award. The Company recognizes the expense on these restricted units ratably from the grant date until all units become unrestricted. Awards generally vest ratably over a three-year period beginning on the award's first anniversary date. Compensation expense related to these restricted units is based on the grant date fair value as determined by the closing market price on the grant date, reduced by the fair value of estimated forfeitures. For awards to employees, the Company estimates a 10% forfeiture rate which is subject to revision depending on the actual forfeiture experience.

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A summary of the LTIP unit activity is set forth below:

	Number of		Weighted		Weighted
	LTIP units		Average Grant		Average Term
	(in thousands)		Date Price		Until Maturity
Outstanding at December 31, 2011	—		$	—	0
Awarded	6.1		25.69		3
Outstanding at December 31, 2012	6.1		25.69		3
Awarded	321.9		27.02		3.5
Cancelled	(3.5	)	28.28		2.8
Vested	(17.9	)	26.38		0
Outstanding at December 31, 2013	306.6		$	27.02	2.9

As of December 31, 2013 and 2012, the total unrecognized compensation cost for LTIP restricted units was $6.1 million and $0.2 million, respectively.

NT Investor Plan

The NT Investor Plan was an equity participation plan which provided for the award of profit interest units in NT Investors to certain employees and independent non-employee directors of NTE LLC. Approximately 29 million profit interest units in NT Investors were 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 were to 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 would 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 were satisfied by cash distributions made from NT Holdings and did not dilute cash available for distribution to the unitholders of NTE LP.

In January 2013, upon completion of the Company’s secondary public offering of 10.7 million common units owned by NT Holdings, all outstanding and unvested profit interest units under the NT Investor Plan became immediately fully-vested. As a result, the Company accelerated all remaining unrecognized expense related to this plan resulting in a non-cash expense of $5.3 million recorded during the year ended December 31, 2013 related to this plan. This expense is included in selling, general and administrative expenses in the consolidated statements of operations and comprehensive income. No further awards will 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, 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
Granted	1.5		2.57
Cancelled	(6.2	)	(1.78	)
Outstanding at December 31, 2012	19.5		1.96		8.1
Vested	(19.5	)	1.96
Outstanding at December 31, 2013	—		—		0

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The estimated weighted average fair value as of the grant date for NT Investor Plan profit interest units granted during the year ended December 31, 2012, the year ended December 31, 2011 were $0.88 and $0.57, respectively, based upon the following assumptions:

	2012	2011
Expected life (years)	6.5	5.75 - 6.5
Expected volatility	55.5%	40.6% - 49.6%
Expected dividend yield	0.0%	0.0%
Risk-free interest rate	1.4%	2.5% - 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.

For the years ended December 31, 2013, 2012 and 2011, the Company recognized $5.3 million, $0.9 million and $1.6 million, respectively, of compensation costs related to profit interest units. There was no unrecognized compensation cost for NT Investor Plan profit interest units at December 31, 2013.

17. 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 $6.1 million, $3.7 million and $0.6 million for the years ended December 31, 2013, 2012 and 2011, respectively.

Cash Balance 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.

Retiree Medical Plan

During 2012, the Company began to sponsor a plan to provide retirees with health care benefits prior to age 65 (the “Retiree Medical Plan”) for eligible employees. Eligible employees may participate in the Company’s health care benefits after retirement subject to cost-sharing features. To be eligible for the Retiree Medical Plan employees must have completed at least 10 years of service with the Company, inclusive of years of service with Marathon, and be between the ages of 55 and 65 years old.

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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 and the Retiree Medical Plan (the “Plans”) for the years ended December 31, 2013, 2012 and 2011 were as follows:

			Cash Balance Plan									Retiree Medical Plan
			Year ended December 31,									Year ended December 31,
(in millions)			2013			2012			2011			2013			2012
Change in benefit obligation:
	Benefit obligation at beginning of year		$	2.3		$	0.5		$	—		$	2.4		$	—
		Service cost	1.9			1.7			0.1			0.3			0.1
		Interest cost	0.2			0.1			—			0.1			0.1
		Actuarial loss (gain)	0.3			0.1			—			(0.6		)	0.8
		Plan amendments	—			—			0.4			—			1.4
		Benefits paid	(0.1		)	(0.1		)	—			(0.1		)	—
	Benefit obligation at end of year		$	4.6		$	2.3		$	0.5		$	2.1		$	2.4
Change in plan assets:
	Fair value of plan assets at beginning of year		2.1			0.1			—			—			—
		Employer contributions	2.5			2.1			0.1			0.1			—
		Return on plan assets	0.1			—			—			—			—
		Benefits paid	(0.1		)	(0.1		)	—			(0.1		)	—
	Fair value of plan assets at end of year		$	4.6		$	2.1		$	0.1		$	—		$	—
Reconciliation of funded status:
	Fair value of plan assets at end of year		4.6			2.1			0.1			—			—
	Benefit obligation at end of year		4.6			2.3			0.5			2.1			2.4
	Funded status at end of year		$	—		$	(0.2	)	$	(0.4	)	$	(2.1	)	$	(2.4	)

At December 31, 2013 and 2012, the projected benefit obligations exceeded the fair value of the Plans’ assets by $2.1 million and $2.6 million, respectively. This unfunded obligation is classified in other liabilities on the consolidated balance sheets.

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The components of net periodic benefit cost and other amounts recognized in equity related to the Plans for the years ended December 31, 2013, 2012 and 2011 were as follows:

		Cash Balance Plan								Retiree Medical Plan
		Year ended December 31,								Year ended December 31,
(in millions)		2013			2012			2011		2013			2012
Components of net periodic benefit cost:
	Service cost	$	1.9		$	1.7		$	0.1	$	0.3		$	0.1
	Amortization of prior service cost	—			—			—		0.2			0.1
	Interest cost	0.2			0.1			—		0.1			0.1
	Expected return on plan assets	$	(0.1	)	$	—		$	—	$	—		$	—
	Net periodic benefit cost	$	2.0		$	1.8		$	0.1	$	0.6		$	0.3
Changes recognized in other comprehensive loss:
	Prior service cost addition (amortization)	$	—		$	(0.1	)	$	0.4	$	(0.2	)	$	1.3
	Actuarial (gain) loss	0.3			—			—		(0.6		)	0.8
	Experience loss	—			0.1			—		—			—
	Total changes recognized in other comprehensive loss	$	0.3		$	—		$	0.4	$	(0.8	)	$	2.1

Assumptions

The weighted average assumptions used to determine the Company’s benefit obligations are as follows:

	Cash Balance Plan			Retiree Medical Plan
	Year ended December 31,			Year ended December 31,
	2013	2012	2011	2013	2012
Discount rate	5.00%	4.00%	4.75%	5.00%	4.00%
Rate of compensation increase	4.00%	4.00%	4.00%	N/A	N/A
Health care cost trend rate:
Initial rate	N/A	N/A	N/A	7.00%	7.50%
Ultimate rate	N/A	N/A	N/A	5.00%	5.00%
Years to ultimate	N/A	N/A	N/A	4	5

The weighted average assumptions used to determine the net periodic benefit cost are as follows:

	Cash Balance Plan			Retiree Medical Plan
	Year ended December 31,			Year ended December 31,
	2013	2012	2011	2013	2012
Discount rate	4.00%	4.75%	5.00%	4.00%	4.75%
Expected long-term rate of return on plan assets	4.25%	4.50%	4.50%	N/A	N/A
Rate of compensation increase	4.00%	4.00%	4.00%	N/A	N/A
Heather care cost trend rate:
Initial rate	N/A	N/A	N/A	7.50%	7.50%
Ultimate rate	N/A	N/A	N/A	5.00%	5.00%
Years to ultimate	N/A	N/A	N/A	5	5

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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 and Retiree Medical Plan’s respective 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 to the Cash Balance Plan of $2.5 million, $2.1 million and $0.1 million were made during the years ended December 31, 2013, 2012 and 2011, respectively. These contributions were invested into equity and bond mutual funds and money market funds which are deemed Level 1 assets as described in Note 14. The Company expects funding requirements of approximately $2.2 million during the year ending December 31, 2014.

At December 31, 2013, anticipated benefit payments to participants from the Plans in future years are as follows:

(in millions)	Cash Balance Plan		Retiree Medical Plan
2014	$	0.1	$	—
2015	0.3		—
2016	0.4		0.1
2017	0.5		0.1
2018	0.6		0.1
2019-2023	5.5		0.7

18. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information is as follows:

	Year ended December 31,
(in millions)	2013		2012			2011
Net cash from operating activities included:
Interest paid	$	26.7	$	32.9		$	37.9
Income taxes paid	3.7		—			—
Noncash investing and financing activities include:
Capital expenditures included in accounts payable	$	10.2	$	1.2		$	—
PP&E derecognized in sale leaseback	—		(4.7		)	(12.1		)
PP&E additions resulting from a capital lease	1.2		1.0			—

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 assumed the leasing of these properties from the real estate investment trust on a long-term basis. All stores owned at the conclusion of these transactions were sold and leased back from the equity real estate investment trust. As of December 31, 2013, 133 of the SuperAmerica convenience stores and the SuperMom’s bakery remain under the lease with the equity real estate investment trust.

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. Subsequent to the initial transaction,

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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.

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)
2014	$	23.9
2015	23.3
2016	22.8
2017	22.1
2018	21.6
Thereafter	145.6
Total noncancelable operating lease payments	$	259.3

Rental expense was $24.0 million, $23.5 million, $24.2 million for the years ended December 31, 2013, 2012 and 2011, respectively.

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.

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 December 31, 2013 and 2012, liabilities for remediation totaled $1.5 million and $3.0 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 $0.1 million and $0.3 million at December 31, 2013 and 2012, 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.

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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, NTOT and related assets, and includes the Company’s interest in MPL and MPLI, and

•Retail – operates 164 convenience stores primarily in Minnesota and Wisconsin. The retail segment also includes the operations of NTB and SAF.

Operating results for the Company’s operating segments are as follows:

(in millions)
Year ended December 31, 2013	Refining		Retail		Other			Total
Revenues
Customer	$	3,520.2	$	1,459.0	$	—		$	4,979.2
Intersegment	1,015.8		—		—			1,015.8
Segment revenues	4,536.0		1,459.0		—			5,995.0
Elimination of intersegment revenues	—		—		(1,015.8		)	(1,015.8		)
Total revenues	$	4,536.0	$	1,459.0	$	(1,015.8	)	$	4,979.2
Income (loss) from operations	$	255.7	$	15.2	$	(32.2	)	$	238.7
Income from equity method investment	$	10.0	$	—	$	—		$	10.0
Depreciation and amortization	$	30.4	$	7.1	$	0.6		$	38.1
Capital expenditures	$	88.7	$	7.7	$	0.2		$	96.6

(in millions)
Year ended December 31, 2012	Refining		Retail		Other			Total
Revenues
Customer	$	3,171.5	$	1,482.4	$	—		$	4,653.9
Intersegment	1,041.1		—		—			1,041.1
Segment revenues	4,212.6		1,482.4		—			5,695.0
Elimination of intersegment revenues	—		—		(1,041.1		)	(1,041.1		)
Total revenues	$	4,212.6	$	1,482.4	$	(1,041.1	)	$	4,653.9
Income (loss) from operations	$	707.3	$	8.7	$	(145.0	)	$	571.0
Income from equity method investment	$	12.3	$	—	$	—		$	12.3
Depreciation and amortization	$	25.4	$	6.6	$	1.2		$	33.2
Capital expenditures	$	24.2	$	4.6	$	2.1		$	30.9

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(in millions)
Year ended December 31, 2011	Refining		Retail		Other			Total
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 (loss) 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

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 December 31, 2013	$	875.6	$	138.2	$	104.0	$	1,117.8
At December 31, 2012	$	706.1	$	134.7	$	296.0	$	1,136.8

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. SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

		First			Second		Third		Fourth
(in millions, except per unit data)		Quarter			Quarter		Quarter		Quarter		Total
2013
	Revenue	$	1,115.0		$	1,131.2	$	1,440.9	$	1,292.1	$	4,979.2
	Operating income	131.9			47.6		27.3		31.9		238.7
	Net income	119.4			63.9		27.2		20.6		231.1
	Earnings per common unit - basic and diluted	1.30			0.70		0.30		0.22		2.51
2012
	Revenue	$	999.1		$	1,155.2	$	1,263.5	$	1,236.1	$	4,653.9
	Operating income	2.7			224.7		199.4		144.2		571.0
	Net income	(193.6		)	245.6		61.1		84.5		197.6
	Net income subsequent to IPO on July 31, 2012						42.4		84.5		126.9
	Earnings per common unit - basic and diluted						$	0.46	$	0.92	$	1.38

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Item 9.Changes In and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A.Controls and Procedures

Evaluation of disclosure controls and procedures. Our chief executive officer and chief financial officer, after evaluating the effectiveness of our “disclosure controls and procedures” (as defined in the Securities Exchange Act of 1934 Rules 13a-15(e) and 15d-15(e)) as of December 31, 2013 (the “Evaluation Date”), concluded that as of the Evaluation Date, our disclosure controls and procedures were effective. Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Security Exchange Act of 1934, as amended, is recorded, processed, summarized and reported, within the time periods specified in the Commission's rules and forms, and that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure.

Management’s Report on Internal Control Over Financial Reporting.  Included herein under the caption “Management’s Report on Internal Control Over Financial Reporting” on page 79 of this report.

Changes in internal control over financial reporting. There were no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2013, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B.Other Information

None.

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PART III

Item 10.Directors, Executive Officers, and Corporate Governance.

Our Management

On November 12, 2013, NT Holdings formed a new subsidiary, NT InterHoldCo LLC, and contributed its remaining 35,622,500 common units of NTE LP and its ownership rights in Northern Tier Energy GP LLC to NT InterHoldCo LLC. Subsequent to the contribution, NT Holdings sold NT InterHoldCo LLC to Western Refining, for total consideration of $775 million plus the distribution on the common units acquired with respect to the quarter ended September 30, 2013. As a result of this transaction, Western Refining indirectly owns 100% of Northern Tier Energy GP LLC, the general partner of NTE LP, and 35,622,500 common units, or 38.7%, of NTE LP. The balance of the limited partner units remain publicly traded.

Our general partner, the indirect owner of which is Western Refining, 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 or its affiliates 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. NT InterHoldCo LLC, a Delaware limited liability company and wholly-owned subsidiary of Western Refining, will appoint all of the directors of our general partner. All actions of the board, other than any matters delegated to a committee, will require approval by majority vote of the directors. Each member of the board has one vote. Our partnership agreement contains various provisions which replace default fiduciary duties under applicable law with contractual corporate governance standards. 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.

Independence Determinations

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.

To be considered independent under NYSE listing standards, our board of directors must determine that a director has no material relationship with us other than as a director. The standards specify the criteria by which the independence of directors will be determined, including guidelines for directors and their immediate family members with respect to employment or affiliation with us or with our independent public accountants. The board of directors has determined that Messrs. Smith, Hofmann, Duckworth and Bennett are independent under applicable NYSE rules.

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 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

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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.

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, Mr. Hofmann, Mr. Duckworth and Mr. Bennett, each of whom meets the independence standards established by the NYSE and the Exchange Act for membership on an audit committee. The Board has also determined that Mr. Hofmann and Mr. Duckworth are financially sophisticated and qualify as “Audit Committee Financial Experts,” as defined by SEC rules.

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.

In fulfilling its oversight responsibilities, the audit committee reviewed and discussed with management the audited financial statements contained in this Annual Report on Form 10-K. The audit committee discussed with PricewaterhouseCoopers LLP, the Company’s independent registered accounting firm, the matters required to be discussed by Auditing Standards No. 16, as issued by the Public Company Accounting Oversight Board. The committee (i) received written disclosures and the letter from PricewaterhouseCoopers LLP required by applicable requirements of the Public Company Accounting Oversight Board regarding PricewaterhouseCoopers LLP’s communications with the audit committee concerning independence (ii) and has discussed with PricewaterhouseCoopers LLP its independence from management and the Company. Based on the reviews and discussions referred to above, the audit committee recommended to the board of directors that the audited financial statements be included in the Annual Report on Form 10-K for the year ended December 31, 2013 for filing with the SEC.

Although not required by NYSE listing standards, the board of directors of our general partner has a compensation committee comprised of Messrs. Barfield, Smith and Weaver. None of the members of our compensation committee is required to be “independent.” The compensation committee has the sole authority to retain any compensation consultants to be used to assist the committee. This committee establishes salaries, incentives and other forms of compensation for officers and certain other employees of our general partner.

The board of directors of our general partner has a nominating & governance committee comprised of Messrs. Barfield, Hofmann and Weaver. None of the members of our nominating and governance committee is required to be “independent.” 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.

In addition, the board of directors of our general partner has an executive committee comprised of Messrs. Foster, Smith, Stevens and Weaver. This committee handles matters that arise during the intervals between meetings of the board of directors of the general partner that do not warrant convening a special meeting of the general partner’s board but should not be postponed until the next scheduled meeting of that board and also exercises the approval authority delegated by the board of directors of the general partner to the committee under our Delegation of Authority Policy.

Meetings and Other Information

During the last fiscal year, our board of directors had eight meetings, our audit committee had six meetings, our compensation committee had five meetings and our nominating and governance committee had two meetings. All directors have access to members of management and a substantial amount of information transfer and informal communication occurs between meetings. None of our directors attended fewer than 75% of the aggregate number of meetings of the board of directors and committees of the board on which the director served.

As described above, the governance of our general partner is, in effect, the governance of our company, and directors of our general partner are designated or elected by the members of our general partner. Accordingly, unlike holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business or governance, subject in all cases to any specific unitholder rights contained in our partnership agreement. As a result, we do not hold annual meetings of unitholders.

All of our standing committees have charters. Our committee charters and governance guidelines, as well as our Code of Business Conduct and Ethics and our Financial Code of Ethics, which apply to our principal executive officer, principal financial officer and principal accounting officer, are available on our internet website at http://www.ntenergy.com. We intend to disclose any amendment to or waiver of the Financial Code of Ethics and any waiver of our Code of Business Conduct and Ethics on behalf of an executive officer or director either on our internet website or in an 8-K filing.

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Meeting of Non-Management Directors and Communications with Directors

At least quarterly, during a meeting of the board of directors of our general partner, all of our directors meet in an executive session without management participation. In 2013, Dan F. Smith, our then Executive Chairman, presided over these executive sessions. In 2014, Paul Foster, as Chairman of the Board, will preside over these executive sessions. The board of directors of our general partner welcomes questions or comments about us and our operations. Unitholders or interested parties may contact the board of directors, including any individual director, by contacting the Secretary of the board of directors of our general partner at the following address and fax number: Secretary, Northern Tier Energy LP, 38C Grove Street, Suite 100, Ridgefield, Connecticut 06877, (203) 244 6550. Letters to a Director should be sent to the attention of the Secretary at the same address.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires the board of directors and executive officers of our general partner, and persons who own more than 10 percent of a registered class of our equity securities, to file with the SEC and any exchange or other system on which such securities are traded or quoted initial reports of ownership and reports of changes in ownership of our common units and other equity securities. Officers, directors and greater than 10 percent unitholders are required by the SEC’s regulations to furnish to us and any exchange or other system on which such securities are traded or quoted with copies of all Section 16(a) forms they filed with the SEC. To our knowledge, based solely on a review of the copies of such reports furnished to us, we believe that all reporting obligations of the officers, directors and greater than 10 percent unitholders of our general partner under Section 16(a) were satisfied during the year ended December 31, 2013 except for (i) a Form 4 for the partial vesting of an award of restricted common units granted to Mr. Bonczek in December 2012 due by December 23, 2013, which was reported in a Form 5 filing on January 3, 2014 and (ii) a Form 3 related to NT InterHoldCo LLC acquiring beneficial ownership of more than 10% of our common units on November 11, 2013, which was reported in a late Form 4 filing on November 22, 2013.

Executive Officers and Directors

We are managed and operated by the board of directors of our general partner and executive officers of NTE LP. In this report, we refer to the executive officers of our general partner as “our executive officers.” The following table sets forth the names, positions and ages (as of February 15, 2014) of our executive officers and directors:

Name	Age	Title
Paul L. Foster	56	Chairman of the Board of Directors
Lowry Barfield	56	Director
Timothy Bennett	56	Director
Rocky Duckworth	63	Director
Thomas Hofmann	62	Director
Dan F. Smith	67	Director
Jeff A. Stevens	50	Director
Scott D. Weaver	55	Director and Interim Vice President
Hank Kuchta	57	President and Chief Executive Officer
Chet Kuchta	50	Vice President and Chief Operating Officer
David Bonczek	44	Vice President and Chief Financial Officer
Greg Mullins	61	President, St. Paul Park Refining Company

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

Paul L. Foster has served as a director of our general partner since November 2013 and Chairman of the Board since January 2014. Mr. Foster is currently the executive chairman of Western Refining, a publicly-traded refining and marketing company, and has served as its chairman of the board since September 2005. Previously, Mr. Foster served as Western Refining’s chief executive officer from September 2005 to January 2010, its president from September 2005 to February 2009, and as president of one of its affiliates since 1997. Mr. Foster also serves as chairman of the board of the general partner of Western Refining Logistics, LP, a publicly-traded master limited partnership; as chairman of the University of Texas System Board of Regents; as a director of WestStar Bank, an El Paso-based bank; as a director of Vomaris Innovations, Inc., a privately held medical device company; as a member of the board of managers of Jordan Foster Construction, LLC, a Texas based privately owned construction firm; and on various other civic and professional organizations. Mr. Foster has spent virtually his entire career working in the refined product production and marketing industry.

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Mr. Foster’s extensive understanding of the production and marketing of refined products, his past history as the president and chief executive officer of a publicly-traded refining and marketing company and his extensive history with and shareholdings in the sole member of the general partner are key attributes, among others, that make him well qualified to serve as a director of the Company.

Lowry Barfield has served as a director of our general partner since November 2013. Mr. Barfield is currently the senior vice president - legal, general counsel and secretary of Western Refining, a publicly-traded refining and marketing company, and of the general partner of Western Refining Logistics, LP, a publicly-traded master limited partnership. Previously, he served as vice president - legal, general counsel and secretary of Western Refining from 2005 to 2007. Mr. Barfield has represented Western Refining and its affiliates in various legal capacities since 1999, as well as other large manufacturing and business clients since 1984, both at his own law firm and as a partner in several national firms. From 1982 to 1984, Mr. Barfield served as a law clerk to Federal District Judge Norman W. Black in Houston, Texas.

Mr. Barfield’s extensive experience in addressing legal matters in the refining and marketing industry, his service as the general counsel and secretary of publicly-traded refining and logistics entities and his background providing counsel to large industrial and manufacturing entities are key attributes, among others, that make him well qualified to serve as a director of the Company.

Timothy Bennett has served as a director of our general partner since January 2014. Since June 30, 2009, Mr. Bennett has been retired. Mr. Bennett served as executive vice president of CIT Group, Inc. a financial services company, from March 1999 to June 30, 2009. Mr. Bennett worked at several commercial finance companies from 1980 through 1985. In 1986, he joined CIT Group. Over his tenure at CIT Group, Mr. Bennett oversaw the risk management of all of CIT’s commercial finance units, including Transportation, Project Financing, Energy, Telecommunications, Healthcare, and Asset-Based financing.

Mr. Bennett’s extensive executive, finance and risk management experience at the highest levels of a leading financial services company are key attributes, among others, that make him well qualified to serve as a director of the Company.

Rocky Duckworth has served as a director of our general partner since May 2013. Since October 2010, Mr. Duckworth has been retired and a private investor. Mr. Duckworth is a former partner of KPMG LLP, who retired from KPMG after more than 38 years including more than 29 years as a partner. Mr. Duckworth became a KPMG partner in 1981, partner in-charge of the audit practice in Oklahoma City in 1984, and he was the Managing Partner of the Oklahoma City office from 1987 to 2000 when he relocated to the Houston office to serve global energy clients and as the energy industry leader of the audit practice. Mr. Duckworth served as the lead audit engagement partner on large, multi-national clients operating in different segments of the energy industry including upstream oil and gas exploration and production companies, energy marketing and trading companies, and merchant independent power producers and retail power providers. Mr. Duckworth is a member of the Texas State Board of Public Accountancy. Mr. Duckworth is also a member of the board of directors and audit committee of Magnum Hunter Resources Corporation, a Houston-based oil, natural gas and natural gas liquids exploration and production company. He has a Bachelor of Science degree with honors in accounting from Oklahoma State University and is a certified public accountant.

Mr. Duckworth’s extensive experience as a partner at a major accounting firm including but not limited to serving as the lead audit engagement partner on large, multi-national clients operating in different segments of the energy industry including upstream oil and gas exploration and production companies, energy marketing and trading companies, and merchant independent power producers and retail power providers are key attributes, among others, that make him well qualified to serve as a director of the Company.

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. and a director of the general partner of PVR Partners, L.P. Mr. Hofmann received a B.S. degree from the University of Delaware and a master’s degree from Villanova University.

Mr. Hofmann’s substantial experience and knowledge regarding financial issues related to energy companies and the energy industry and his extensive financial, management and strategic experiences are key attributes, among others, that make him well qualified to serve as a director of the Company.

Dan F. Smith served as Executive Chairman of the board of directors of our general partner and Northern Tier Energy LLC from December 20, 2012 through January 2, 2014 and previously served as Chairman of the board of directors of our general partner from June to December 2012 and of Northern Tier Energy LLC from November 2011 to December 2012. Mr. Smith has served as a director of our general partner since June 2012 and 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

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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 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’s extensive executive experience at the highest levels, including more than ten years of experience as the chief executive officer of a major chemical company are key attributes, among others, that make him well qualified to serve as a director of the Company.

Jeff A. Stevens has served as a director of our general partner since November 2013. Mr. Stevens is currently the President and Chief Executive Officer of Western Refining, a publicly-traded refining and marketing company, and of the general partner of Western Refining Logistics, LP, a publicly-traded master limited partnership. Mr. Stevens has served on the boards of directors of Western Refining since September 2005 and of Western Refining Logistics’ general partner since October 2013. Previously, Mr. Stevens served as Western Refining’s president since February 2009, its chief operating officer since April 2008, its executive vice president since September 2005 and as executive vice president of one of its affiliates since 2000. Mr. Stevens also serves on the board of directors of Vomaris Innovations, Inc., a privately held medical device company. Mr. Stevens has spent his entire career working in the refined product production and marketing industry.

Mr. Stevens’ extensive operational experience in the refining industry and executive experience, including service as the president and chief executive officer of publicly-traded refining and logistics entities, are key attributes, among others, that make him well qualified to serve as a director of the Company.

Scott D. Weaver has served as a director of our general partner since November 2013. Mr. Weaver is currently the Interim Vice President-Administration of our general partner and Vice President, Assistant Treasurer and Assistant Secretary of Western Refining, a publicly-traded refining and marketing company, and has served on its board of directors since September 2005. Previously, Mr. Weaver served as an executive officer of Western Refining in various capacities, including as its interim Treasurer from September 2009 to January 2010, its Chief Administrative Officer from September 2005 to December 2007, and as Chief Financial Officer of one of its affiliates from 2000 to August 2005. Mr. Weaver currently serves on the boards of directors of the general partner of Western Refining Logistics, LP, a publicly-traded master limited partnership; Encore Wire Corporation, a publicly-traded copper wire manufacturing company; WIG Holdings, Inc., a privately held insurance holding company; Vomaris Innovations, Inc., a privately held medical device company and as a member of the board of managers of Jordan Foster Construction, LLC, a Texas based privately owned construction firm..

Mr. Weaver’s extensive experience as a chief financial officer of other public entities, his background in the refining and marketing industry and his knowledge of public company finance matters are key attributes, among others, that make him well qualified to serve as a director of the 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 served as a director of our general partner from June 2012 to January 2014 and a director of Northern Tier Energy LLC from December 2010 to January 2014. Prior to December 2012, Mr. Kuchta served as President and Chief Operating Officer of our general partner from June to December 2012 and of Northern Tier Energy LLC from December 2010 to December 2012. 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. Hank Kuchta is the brother of Chet Kuchta, our Vice President and Chief Operating Officer.

Chet Kuchta has served as Vice President and Chief Operating Officer of our general partner since February 2013. Mr. Kuchta previously served as our Vice President, Supply. Prior to joining Northern Tier Energy in August 2011, Mr. Kuchta held the position of Chief Operating Officer of Petroplus Holdings AG, a leading European independent refiner and wholesaler of petroleum products. He worked as Petroplus’ Chief Commercial Officer from June 2006 until November 2009, when he was

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promoted to Chief Operating Officer. In January 2012, subsequent to his departure from Petroplus, Petroplus entered into various insolvency proceedings in Switzerland, England and Wales, France, Germany and Belgium. Mr. Kuchta was previously Vice President of Crude Oil Supply and Trading at the Premcor Refining Group Inc. from 2002 until Premcor’s sale to Valero Energy Corporation in 2005. Mr. Kuchta also served as Crude Oil Supply Manager for Phillips 66 Company’s East Coast and Gulf Coast Systems, following Phillips’ acquisition of Tosco Corp. in 2001. Additionally, he served in various commercial and refining positions at Tosco from 1996 to 2001. Prior to joining Tosco, Mr. Kuchta spent five years at the Exxon Corporation in various refining, economic and environmental engineering positions. Chet Kuchta is the brother of Hank Kuchta, the President and Chief Executive Officer of our general partner.

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 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.

Item 11.Executive Compensation

The following discussion and analysis of compensation arrangements (the "Compensation Discussion and Analysis") of our named executive officers for 2013 (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 or a subcommittee of our board of directors (the “Compensation Committee”), 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, 2013, our board of directors generally made all decisions regarding salary, the Compensation Committee addressed overall compensation for Mr. Hank Kuchta (our chief executive officer), 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, 2013, the following individuals met the standards of a “named executive officer” for the 2013 fiscal year:

•Hank Kuchta—President and Chief Executive Officer;

•Chet Kuchta - Vice President and Chief Operating Officer;

•David Bonczek—Vice President and Chief Financial Officer; and

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

We have determined that as of December 31, 2013, no other individual met the standards necessary to classify him or her as a “named executive officer.” We expect that our named executive officers will change in the 2014 year. Mr. Hank Kuchta will be retiring in March of 2014, and Mr. David L. Lamp has been hired to serve as our new President and Chief

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Executive Officer following Mr. Kuchta’s retirement. At the time of this filing we are still negotiating the compensation arrangements that will be applicable to Mr. Lamp for the 2014 year.

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.

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, currently in the form of restricted units under 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.

As in the 2012 year, over the 2013 year our Compensation Committee continued to utilize Pearl Meyer & Partners (“PMP”), an independent compensation consulting firm, to review our current compensation programs and to assist us in validating our peer group. The selected group includes businesses in the refining and convenience store retail businesses, as well as certain companies that are similarly structured, and include Calumet Specialty Product Partners, L.P., CVR Energy, Inc., HollyFrontier Corporation, NuStar Energy L.P., PBF Energy Inc., Tesoro Corporation, Western Refining, Casey's General Stores, Inc., Delek US Holdings, Inc., The Pantry, Inc., Susser Holdings Corporation, and TravelCenters of America LLC. In addition to their assistance with peer groups, Pearl Meyer was engaged by the Committee to conduct a complete executive compensation review of 14 of our executive positions against the market peer group. This review included an analysis of base salary, bonuses, and long-term equity based incentives. Pearl Meyer presented to the Compensation Committee norms for long term incentives and recommended award levels for the this executive team. Details of such awards are contained below in Long-Term Equity-Based Incentives. An updated executive compensation review was provided to the Committee in October 2013 when all peer groups reported their compensation data.

Pearl Meyer was also engaged by the board of directors in 2013 to provide a review of Ownership Guidelines and Director Compensation. Their report was utilized when considering levels of director fees.

The structure of each of the compensation elements provided to our named executive officers during the 2013 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 with input from our Chief Executive Officer 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 Mr. Hank Kuchta, his original base salary of $450,000 is set forth in the formal employment agreement that we entered into with him on December 1, 2010. His current base salary is $675,000. 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. Chet Kuchta, Bonczek and Mullins also received offer letters prior to beginning their employment with us. Mr. Chet Kuchta originally received his offer letter on May 24, 2011, when he was hired as our Vice President Supply. We increased the annual base salary set forth in Mr. Chet Kuchta’s offer from $350,000 to $500,000 as of February 11, 2013, in order to reflect the change in his position to Chief Operating Officer. 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, effective February 2013, we increased base salaries of Mr. Hank Kuchta to $675,000 due to his new role as our Chief Executive Officer. We also determined that Mr. Bonczek’s base salary should be increased to $375,000 and Mr. Mullins to $325,000, effective in February 2013.

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 2013 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 2013 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 2013 year.

The 2013 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 2013 target Bonus Plan awards was 100% with respect to Messrs. Hank Kuchta and Chet 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.

During the first quarter of 2014, the Compensation Committee will review and approve the payment of the 2013 bonuses. When making decisions regarding the 2013 amounts to be paid to each named executive officer, our Compensation Committee will review our EBITDA results for the 2013 year, the general target bonus amounts that had been previously set for each executive, individual and overall performance during the 2013 year. At the time of this filing, amounts for the 2013 bonus had not yet been approved.

Long-Term Equity-Based Incentives

In order to incentivize our management to continue to grow our business, our general partner adopted a long-term incentive plan, the Northern Tier Energy LP 2012 Long-Term Incentive Plan (the “LTIP”), in connection with our IPO, for the benefit of employees and directors of us, our general partner and each of our affiliates, who perform services for us. 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.

During 2013, each named executive officer received grants of restricted common units under the LTIP. Fifty percent of each named executive officer's restricted unit grant is subject to time-based vesting conditions and fifty percent is subject to performance-based vesting conditions. The number of restricted unit awarded to the named executive officers was based on a multiple of salary determined to be appropriate by the Compensation Committee, divided by the closing price of our common

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units on the date the Compensation Committee approved the award. For the time vested restricted units, the Compensation Committee authorized the following unit awards to the named executive officers on May 20, 2013: (i) 28,790 restricted units to Mr. Hank Kuchta, (ii) 21,320 restricted units to Mr. Chet Kuchta, (iii) 10,660 restricted units to Mr. Bonczek, and (iv) 9,240 to Mr. Mullins. In accordance with the terms of the time vested unit agreements, these restricted unit awards vest in three equal annual installments beginning on the first anniversary of the date of grant and have accompanying unit distribution rights, which provide that the award recipient receives quarterly distributions on the restricted unit awards as and when declared by our board of directors.

For the performance based restricted units, the target number of units granted may be proportionally adjusted up or down subject to us meeting certain 2013 financial metrics, namely cash available for distribution (the “2013 Financial Condition”) in the target amount of $198,000,000. In the event that the target 2013 Financial Condition is satisfied, the restricted units will be eligible to vest at 100% of the target amount of units awarded. If the 2013 Financial Condition is met at threshold levels of $100,000,000, only fifty percent of the target number of restricted units will be eligible to continue to vest, while if the 2013 Financial Condition is met at or above maximum levels of $350,000,000, 150% of the target restricted units will be eligible to continue vesting. If threshold, target or maximum levels are met for the 2013 Financial Condition, then the units will vest over three years with the first vesting date beginning on January 1, 2015. For the performance based restricted units, the Compensation Committee authorized the following unit awards to the named executive officers on May 20, 2013: (i) 28,790 restricted units to Mr. Hank Kuchta based on target performance, (ii) 21,320 restricted units to Mr. Chet Kuchta based on target performance, (iii) 10,660 restricted units to Mr. Bonczek based on target performance, and (iv) 9,240 to Mr. Mullins based on target performance. Each named executive officer will not be entitled to unit distribution rights payments with respect to the performance awards prior to determining if the 2013 Financial Condition has been met; if met, the executives will receive unit distribution rights with respect to the restricted units at the same time as our unitholders generally. Upon the 2013 financial conditions being met, payments on unit distribution rights will be made in arrears. The termination and change in control provisions of these restricted unit awards are described below in the section titled “Potential Payments Upon Termination or a Change in Control.” As of the date of this filing, it has been determined that the 2013 Financial Condition target was exceeded slightly and the number of units will be adjusted to reflect 115% of target levels.

Prior to the adoption of our LTIP, our named executive officers were granted long-term profits interest awards in NTI Management Company, L.P. that have been described more fully in our Form 10-K filed for the 2012 fiscal year. We did not grant the awards nor carry any financial responsibility for distributions that were made with respect to such awards. During the 2013 year, those awards vested and were fully settled for each of the named executive officers that held the awards. The amounts received by each of the named officers is as follows: Mr. Hank Kuchta, $50.6 million; Mr. Chet Kuchta, $14.8 million; Mr David Bonczek, $6.1 million; and Mr. Mullins $7.9 million. Neither we nor our general partner has any reimbursement obligation or other financial responsibility with respect to the settlement distributions made in 2013.

Severance and Change in Control Benefits

We maintained certain agreements with our named executive officers during the 2013 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.

In connection with the transaction with Western Refining in November of 2013, we entered into retention agreements with each of the named executive officers other than Mr. Hank Kuchta. The retention agreements are intended to incentivize the named executive officers to stay with the company through May 15, 2014, and in exchange the executives will be guaranteed certain salary and benefits through that time.

A more detailed description of the severance and change in control provisions that we provide to our named executive officers, as well as the potential benefits provided by the retention agreements, 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

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amounts up to 6.0% of the employees’ eligible compensation that will not vest until the end of a three-year period of service, and an additional 3.0% non-elective annual contribution that will vest immediately. The amounts that we contributed to each named executive officer’s account for the 2013 year are reflected in the Summary Compensation Table below.

We established the Northern Tier Energy LLC Supplemental Plan (the “Supplemental Plan”) in 2012 for those active employees that were required to receive a reduced company matching contribution into the 401(k) plan due to the non-discrimination requirements in the 401(k) plan. 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. While this Supplemental Plan is still in place, no new contributions were made to the plan in 2013. A more detailed description of the Supplemental Plan may be found in the “Nonqualified Deferred Compensation” section below.

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

Unit Ownership Guidelines and Hedging Policies. During 2013, the board of directors of our general partner adopted unit ownership guidelines for our named executive officers and directors in order to further align their interest and actions with the interests of our common unit holders. Generally the ownership guidelines are 3x and 1.5x annual base salary for our CEO and other named executive officers, respectively. Ownership guidelines for directors are 3x the amount of their annual retainer. Ownership guidelines are required within five years of adoption or appointment, whichever is later.

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.

Compensation Committee Report

The Compensation Committee of our board of directors has reviewed and discussed with management the Compensation Discussion and Analysis contained in this Annual Report on Form 10-K. Based on those reviews and discussions, the Compensation Committee of the board of directors has recommended that the Compensation Discussion and Analysis be included in the Annual Report on Form 10-K for the year ended December 31, 2013 for filing with the SEC.

The Compensation Committee

Mr. Dan F. Smith, Chairman

Mr. Lowry Barfield

Mr. Scott D. Weaver

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Summary Compensation Table

The table below sets forth the annual compensation earned during the 2013, 2012 and 2011 fiscal years and for those current named executives that were considered named executive officers for each applicable year.

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	2013	640,000			1,558,474	25,698	83,899	2,308,071
President and Chief Executive	2012	450,000	900,000	—	—	12,947	22,099	1,385,046
Officer	2011	450,000	270,000	—	—	12,250	21,749	753,999
Chet Kuchta
Chief Operating Officer	2013	476,900			1,154,417	28,464	62,600	1,722,391
David Bonczek	2013	363,500			577,214	19,594	45,300	1,005,608
Vice President and	2012	294,231	420,000	361,957	71,367	12,870	12,654	1,173,079
Chief Financial Officer	2011	192,211	150,000	121,488	—	6,312	7,572	477,583
Greg Mullins	2013	320,400			500,254	24,862	35,800	881,316
President, St. Paul Park	2012	291,154	575,520	183,500	—	13,138	17,500	1,080,812
Refining Company	2011	275,000	290,000	—	—	11,421	13,327	589,748

(1) Amounts in this column for the 2013 year reflect an increase in salary in February 2013 to $675K for Mr. Hank Kuchta, $500K for Mr. Chet Kuchta, $375K for Mr. Bonczek and $325K for Mr. Mullins.

(2) At the time of this filing, 2013 bonus amounts have not been approved or paid. When determined we will file an 8-K to disclose amounts paid to each named executive officer. The amounts reported in this column for the 2012 year reflect actual bonuses that were paid in 2013 pursuant to our Bonus Plan for the 2012 year. These values reflect each named executive officer’s “maximum” 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.

(3) We did not grant any option awards during the 2013 year. Amounts included in the 2012 columns reflect the grant date fair value of the NTI Management Company L.P. profit interests granted to Messrs. Bonczek and Mullins in 2011 and 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%. The assumptions used to calculate these values for the 2011 grant was as follows: (a) the expected term was 6.5 years; (b) current price of the underlying unit was $1.00; (c) the expected volatility was 40.6%; (d) the expected dividend yield was 0.0%; and (e) the risk-free investment rate was 2.7%.

(4) For the 2013 stock award, the amount in this column represents the grant date fair value of both the time vested and performance based restricted units computed in accordance with FASB ASC Topic 718. The time based restricted units were computed using the closing trading price of our common units on the grant date of May 20, 2013 of $27.07 multiplied by the number of restricted units granted for each named executive officer 28,786 for Mr. Hank Kuchta, 21,323 for Mr. Chet Kuchta, 10,661 for Mr, Bonczek, and 9,240 for Mr. Mullins. The performance based units were calculated based on achieving the probable level of target (100%) performance metric, multiplied by the closing trading price on the grant date of May 20, 2013 of $27.07. The number of units at target performance would equal 28,786 for Mr. Hank Kuchta, 21,323 for Mr. Chet Kuchta, 10,661 for Mr, Bonczek, and 9,240 for Mr. Mullins. Should the performance awards be valued at maximum performance (150%) the value for such performance awards would be $1,168,856 for Mr. Hank Kuchta representing 43,179 restricted units valued at $27.07, $865,834 for Mr. Chet Kuchta representing 31,985 units valued at $27.07, $432,903 for Mr. Bonczek representing 15,992 units valued at $27.07, and $375,190 for Mr. Mullins representing 13,860 units valued at $27.07. Please see Note 16 to our consolidated financial statements for the assumptions used in valuing our common units.

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(5) 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 the 2013 year. Other compensation also includes quarterly dividends paid in 2013 on the restricted units. Mr. Hank Kuchta received $64,000 in quarterly dividends, Mr. Chet Kuchta received $47,300, Mr. Bonczek received $30,000, and Mr. Mullins received $20,500. In addition, we paid a life insurance premium on behalf of Mr. Kuchta to MetLife in the amount of $4,599.

Grants of Plan-Based Awards for the 2013 Fiscal Year

		Estimated Future Payouts Under Equity Incentive Plan Awards			All Other Option Awards: Number of Units (#)(4)	Grant Date Fair Value of Stock and Option Awards ($)(5)
Name	Grant Date	Threshold ($)(1)	Target ($)(2)	Maximum ($)(3)
Mr. Hank Kuchta	5/20/13	14,393	28,786	43,179	28,786	1,558,474
Mr. Chet Kuchta	5/20/13	10,662	21,323	31,985	21,323	1,154,427
Mr. Dave Bonczek	5/20/13	5,331	10,661	15,992	10,661	577,214
Mr. Greg Mullins	5/20/13	4,620	9,240	13,860	9,240	500,524

(1) Amounts reflected in this column represent performance units at 50% of the target grant.

(2) Amounts reflected in this column represent performance units at target, or 100%.

(3) Amounts reflected in this column represent performance units at 150% of the target grant.

(4) Amounts reflected in this column represent the time based restricted unit awards granted on May 20, 2013.

(5) Amounts in this column reflect the grant date fair value of both the performance units at target and the time based restricted units, in accordance with FASB ASC Topic 718. The units were computed using the closing trading price of our common units on the grant date of May 20, 2013 of $27.07

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Narrative Description to the Summary Compensation Table and the Grant of Plan-Based Awards Table for the 2013 Fiscal Year

We entered into a formal employment agreement with Mr. Hank 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. Hank Kuchta has an annual base salary of $675,000, and an annual cash incentive bonus target of 100% of his annual base salary. Mr. Hank 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. Chet Kuchta’s offer letter was provided to him on May 24, 2011 with a salary of $350,000, which was increased to $500,000 by our board of directors in February 2013 to reflect his new position as Chief Operating Officer. 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.

The terms and conditions of each of the restricted common units granted to our named executive officers under the LTIP have been previously described in our Compensation Discussion and Analysis. For a description of the impact of a termination or a change in control upon the restricted units, see the “Potential Payments Upon Termination or Change in Control” section below.

Percentage of Salary and Bonus in Comparison to Total Compensation

Name	Salary and Bonus Percentage of Total Compensation
Mr. Hank Kuchta	28	%
Mr. Chet Kuchta	28	%
Mr. David Bonczek	36	%
Mr. Greg Mullins	36	%

Outstanding Equity Awards at 2013 Fiscal Year-End

The following table provides information on the current restricted units held by the named executive officers.

	Option Awards				Stock Awards Number of Units that have not Vested (#)(1)	Market Value of Units that have not Vested ($)(2)
Name	Number of Securities Underlying Unexercised Options(#) Unexercisable	Number of Securities Underlying Unexercised Options(#) Exercisable	Option Exercise Price ($)	Option Expiration Date
Mr. Hank Kuchta
Restricted units					57,572	1,416,271
Mr. Chet Kuchta
Restricted units					42,646	1,049,092
Mr. Dave Bonczek
Restricted units					23,175	570,105
Mr. Greg Mullins
Restricted units					18,480	454,608

(1) Amounts in this column represent all outstanding LTIP awards as of December 31, 2013 and include the time vested awards and performance based awards at target which were awarded on May 20, 2013. For Mr. Bonczek, outstanding awards also include his 2012 LTIP grant of 2,778 units of which 2/3^rds, or 1,852 units, has not vested. The time vested awards granted on May 20, 2013 will vest ratably in three year increments beginning on date of grant. The performance vested awards granted on May 20, 2013 will vest ratably in three year increments beginning on January

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1, 2015 once it has been determined if the financial condition has been met. Mr. Bonczek’s December 19, 2012 LTIP award will vest ratably in three year increments beginning on date of grant.

(2) Market values on unvested units were computed using the closing trading price as of December 31, 2013 of $24.60.

Option Exercises and Stock Vested in the 2013 Fiscal Year

	Option Awards(1)
Name	Number of Units Acquired on Exercise (#)(1)	Value Realized on Exercise ($)(2)
Mr. Hank Kuchta	—	—
Mr. Chet Kuchta	—	—
Mr. Dave Bonczek	926	23,094
Mr. Greg Mullins	—	—

(1) During 2013, Mr. Bonczek had 1/3 of his 2012 LTIP award vest. None of the remaining named executive officers had any LTIP awards vested during the 2013 year. The amount in this column represents the 1/3^rd vesting of his 2,778 restricted units that were granted on December 19, 2012.

(2) Value was calculated by multiplying the number of restricted units that vested by $24.94, the closing price of our common units on the vesting date of December 19, 2013.

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 ($)	Payments During 2013 Fiscal Year ($)
Mr. Hank Kuchta	Northern Tier Energy Retirement Plan	3.08	38,645	—
Mr. Chet Kuchta	Northern Tier Energy Retirement Plan	2.42	28,464	—
Mr. Dave Bonczek	Northern Tier Energy Retirement Plan	2.80	32,464	—
Mr. Greg Mullins	Northern Tier Energy Retirement Plan	3.08	38,000	—

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 corporate and refining employees who have attained age 21 and completed three months of service. Excluded employees include all retail employees, 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 2014, the interest crediting rate will be 3.76%.

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.

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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.

Nonqualified Deferred Compensation

Name	Registrant Contributions in the 2013 Fiscal Year ($)	Aggregate Earnings in 2013 Fiscal Year ($)	Aggregate Withdrawals or Distributions ($)	Aggregate Balance at December 31, 2013
Mr. Hank Kuchta	—	848	—	7,261
Mr. Chet Kuchta	—	1,074	—	6,996
Mr. Dave Bonczek	—	947	—	5,523
Mr. Greg Mullins	—	760	—	7,161

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, although no company contributions were made into the plan for the 2013 year.

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 2013 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 2013 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.

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.

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Potential Payments Upon Termination or a Change in Control

We provide our named executive officers with certain severance and double-trigger change in control benefits through their employment agreements, offer letters and LTIP awards. The rationale for providing these benefits to our executives is described in detail in the Compensation Discussion and Analysis above.

Employment Agreement and Offer Letters

On termination of Mr. Hank 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. Hank Kuchta, he will also receive continued base salary payments for a period of twenty-four months.

In the event that Mr. Hank 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. Hank 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. Hank 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. Hank 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. Hank 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 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.

Messrs. Chet Kuchta, Bonczek and Mullins have an offer letter that sets forth certain potential severance and change in control benefits. Messrs. Chet Kuchta, Bonczek and Mullins will 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

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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.

LTIP Awards

For all named executive officers, as outlined in their LTIP award agreements, in the event that the employee’s termination of employment with us occurs due to (i) the employee’s death or Disability, or (ii) termination by us (or an applicable affiliate) without Cause, or (ii) by the employee for Good Reason, in any case, prior to the time that the restricted units have become vested, the tranche of restricted units that would have become vested upon the applicable vesting date that immediately follows the date of the employee’s termination of employment will be immediately accelerated and become vested (as capitalized term defined below). With respect to the performance based vesting units granted in 2013, the acceleration of the next tranche of units could only occur if the 2013 Financial Condition has been satisfied prior to the date of the employee’s termination of employment. In the event that the employee is terminated by us without Cause, or by the employee without Good Reason, in each case within a twelve month period immediately following a Change in Control (as defined below), all unvested restricted units will become vested. With respect to the performance based vesting units granted in 2013, the Change in Control related acceleration would only occur if the 2013 Financial Condition had been met prior to the occurrence of the termination of employment.

For purposes of the current LTIP restricted unit agreements, the definition of a “Disability” will be defined by reference to the same term in our then-current long-term disability plan. The term “Cause” is generally defined to mean the continuous failure to perform his duties for us or one of or affiliates (other than as a result of a physical or mental incapacity), the employee’s gross misconduct or negligence, or the employee’s conviction of a felony. “Good Reason” is generally defined as a material decrease in the employee’s position, responsibilities or title; a reduction in the employee’s base salary or incentive compensation opportunities; a material reduction in benefits; or a relocation of the employee’s principal place of business by more than forty miles.

The LTIP generally defines a “Change in Control” as (i) any person or group, other than our general partner, us or an affiliate of either our general partner or us, Acon or TPG becoming the beneficial owner by way or merger, consolidation, recapitalization, reorganization or otherwise, of 50% or more of the voting power of our general partner or us; (ii) out limited partners or the limited partners of our general partner approve a plan of complete liquidation of us or our general partner; (iii) the sale or other disposition by us or our general partner of all or substantially all of its assets to any person other than an affiliated entity; (iv) our general partner or an affiliate of our general partner ceases to be our general partner; or (v) any other event defined as a “Change in Control” within an individual award agreement provided pursuant to the LTIP. If an LTIP award is subject to Section 409A of the Code, a “Change in Control” shall not be deemed to occur unless that event also constitutes a “change in the ownership of a corporation,” a “change in the effective control of a corporation,” or a “change in the ownership of a substantial portion of a corporation’s assets,” in each case, within the meaning of Section 409A of the Code.

Retention Agreements

In December of 2013 we entered into retention agreements with Messrs. Chet Kuchta, Bonczek and Mullins. If the executives commit to providing services to us through May 15, 2014, they are guaranteed to receive the same base salary and benefits that they were receiving prior to the Western Refining transaction unless they are terminated for Cause. A “Cause” termination would generally occur under the retention agreements if there is a continuous failure by the executive to substantially perform his duties; the executive commits gross misconduct or gross negligence, or the executive is convicted of, or pleads guilty or nolo contendere to a felony. As additional incentive for the executives to remain employed through May 15, 2014, if we (i) terminate the executive without Cause, (ii) eliminate the executive’s position, or (iii) require the executive to relocate as a condition of his employment and the executive chooses not to relocate (each a “Separation Event”), we will pay the executive a lump sum cash payment equal to six months of the executive’s base salary following the executive’s execution of a release and a restrictive covenant agreement (the “Separation Release”) in our favor. For Messrs. Chet Kuchta, Bonczek and Mullins, that amount would be $250,000, $187,500, and $162,500, respectively.

If the executive signs the Separation Release following a Separation Event, we will (i) continue to pay the employer portion of the executive’s healthcare for a period of six months, (ii) provide outplacement services to the executive, and (iii) if

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the executive is eligible, and we have determined to pay bonuses for the 2013 year, the executive may receive a bonus for the 2013 year. Following the six month period of paid continued medical coverage, the executive will be eligible for eighteen months of COBRA rights. For Messrs. Chet Kuchta, Bonczek, and Mullins, the six month continuation of healthcare benefits represents $4,283, $4,283 and $4,902, respectively of healthcare benefits.

If the executive incurs a Separation Event but does not sign a Separation Release, he would receive the benefits that were set forth in his employment agreement or offer letter, or his LTIP award agreements, as applicable, and he will receive a payment equal to unused vacation benefits. Such amounts have been disclosed below.

Quantification of Payments

The table below shows our best estimate of the amount of payments and benefits that each of the named executive officers would receive upon a termination of employment or a change in control under their employment agreement, offer letter and LTIP awards if that event had occurred on December 31, 2013. Amounts that could be paid pursuant to retention agreements have been quantified above. 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 ($)(5)	Termination of Employment without Cause or Good Reason within a Twelve Month Period of a Change in Control (6)($)
Mr. Hank Kuchta
Base Salary & Bonus(1)	2,025,000	N/A	2,025,000	337,500	1,350,000	2,025,000
Continued Medical(2)	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	1,416,000
Total	2,025,000		2,025,000	337,500	1,350,000	3,441,000
Mr. Chet Kuchta
Base Salary	N/A	N/A	500,000	250,000	N/A	500,000
Accelerated Equity(3)	N/A	N/A	349,700	349,700	349,700	1,049,092
Total			849,700	599,700	349,700	1,549,092
Mr. Dave Bonczek
Base Salary	N/A	N/A	375,000	187,500	N/A	375,000
Accelerated Equity(3)	N/A	N/A	220,406	220,406	220,406	592,885
Total			595,406	407,906	220,406	967,885
Mr. Greg Mullins
Base Salary	N/A	N/A	325,000	162,500	N/A	325,000
Accelerated Equity(3)	N/A	N/A	151,534	151,534	151,534	454,608
Total			476,534	314,034	151,534	779,608

(1) For Mr. Hank Kuchta 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. Hank Kuchta would receive a Pro-rata Bonus in the event of a termination of employment during the year, a termination occurring on December 31, 2013 would have resulted in a payment equal to the full amount of the target bonus that was set for the 2013 year. The amounts reflected in this row for Messrs. Chet Kuchta, Bonczek, and Mullins reflect payment equal to one years’ salary as of December 31, 2013.

(2) Mr. Hank Kuchta would not have been eligible to receive any continued medical benefits from us as of December 31, 2013, 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 represent acceleration of outstanding restricted unit awards. Amounts were calculated based on total LTIP awards outstanding at the December 31^st closing price of $24.60 per unit, assuming that performance-based vesting awards would accelerate at target levels.

(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

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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. Hank 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, 2013.

(6) Amounts reflected in the “Termination of Employment without Cause or for Good Reason” column will be paid upon termination events with or without change in control as outlined in the employment agreement for Mr. Hank Kuchta, and as outlined in offer letter for each Messrs. Chet Kuchta, Bonczek, and Mullins.

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 2013, Mr. Smith received an incremental fee of $40,000 as chairman of our board of directors and Mr. Hofmann received an incremental fee of $15,000 as the chairman of the audit committee. Each director also receives an annual equity grant equal to $90,000. Beginning in 2014, the board of directors maintained the annual cash retainer of $60,000 and also approved an additional $15,000 to be paid to the Chairman of the Audit Committee, and an additional $10,000 to be paid to the Chairmen of the Compensation and Nominating and Governance Committees.

Directors will also be reimbursed for certain reasonable expenses in connection with their services to us.

Name	Fees Earned or paid in Cash ($)(1)	Stock Awards ($)(2)	All Other Compensation ($)(3)	Total ($)
Mr. Dan F. Smith	100,000	86,051	7,766	193,817
Mr. Thomas Hofmann	75,000	86,051	7,766	168,817
Mr. Scott D. Josey	60,000	86,051	7,766	153,817
Mr. Rocky Duckworth	30,000	82,213	7,419	119,632
Mr. Paul Foster(4)	—	—	—	—
Mr. Lowry Barfield(4)	—	—	—	—
Mr. Jeff Stevens(4)	—	—	—	—
Mr. Scott Weaver(4)	—	—	—	—

(1) Amounts in this column reflect the actual amount received by each director during the 2013 year.

(2) Messrs. Smith, Hofmann, and Josey were granted 3,498 restricted units on May 9, 2013 under our 2012 Long Term Incentive Plan. Mr. Duckworth was granted 3,342 restricted units on May 20, 2013. Please see Note 16 to our Consolidated Financial Statements for assumptions used in valuing our common units. These awards represent the aggregate amount of equity awards that each director holds as of December 31, 2013.

(3) Amounts in this column reflect the quarterly dividends paid in 2013 on the restricted units.

(4) These directors did not join our board of directors until November 2013, and did not receive any compensation for the 2013 year.

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 supports 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.

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• 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.

Compensation Committee Interlocks and Insider Participation

Messrs. Josey and Smith served as a member of our Compensation Committee throughout 2013. Messrs. Liaw and Aronson served as members of our Compensation Committee until November 12, 2013. No other persons served on the Compensation Committee during 2013. Mr. Josey resigned as a member of the Compensation Committee and as a Director on January 2, 2014. Messrs. Barfield and Weaver were appointed to the Compensation Committee on January 2, 2014 and joined Mr. Smith who remains a member of the Compensation Committee. During 2013, none of the members of the Compensation Committee was an officer or employee of us or any of our subsidiaries, or served as an officer of any company with respect to which any of our executive officers served on such company’s board of directors. In addition, none of the members of the Compensation Committee are former employees of ours or any of our subsidiaries. On December 23, 2013, Mr. Weaver was appointed Interim Vice President-Administration of the General Partner and of the Partnership’s subsidiary Northern Tier Energy LLC.

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

The following sets forth certain information with respect to the beneficial ownership of our common units that are issued and outstanding as of February 26, 2014 and held by:

• each unitholder 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 or Management	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned			Percentage of Common Units Beneficially Owned
NT InterHoldCo LLC(1)	35,622,500	38.7	%	%	38.7	%	%
Northern Tier Energy GP LLC(2)	—	—		*	—		*
Hank Kuchta(3)(4)	66,199	—		*	—		*
Chet Kuchta(4)	55,338	—		*	—		*
Dave Bonczek(4)	25,697	—		*	—		*
Greg Mullins(4)	19,866	—		*	—		*
Paul Foster(5)	4,129	—		*	—		*
Jeff Stevens(5)	4,129	—		*	—		*
Scott D. Weaver (5)	—	—		*	—		*
Lowry Barfield(5)	4,129	—		*	—		*
Timothy Bennett(5)	4,129	—		*	—		*
Rocky Duckworth(5)	7,471	—		*	—		*
Dan F. Smith(5)	7,627	—		*	—		*
Thomas Hofmann(5)	7,627	—		*	—		*
All directors and executive officers as a group (12 persons)	206,341	—		*	—		*

 * Represents less than 1%.

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(1) All of the membership interests in NT InterHoldCo LLC are owned by Western Refining, a Delaware corporation.

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

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

(4) Executive officer of our general partner.

(5) Director of our general partner.

Equity Compensation Plan Information

The following table provides information as of December 31, 2013, regarding compensation plans (including individual compensation arrangements) under which our common units are authorized for issuance.

Plan Category	Number of Securities to be Issued upon Exercise of Outstanding Options	Weighted Average Exercise Price of Outstanding Options	Number of Securities Remaining Available for Future Issuance under Equity Comp. Plans (Excluding Securities Shown in the First Column)
Equity compensation plans approved by security holders	—		—
Equity compensation plans not approved by security holders(1)	179,251	N/A	9,006,137
Total:	179,251		9,006,137

(1) Consists of the 2012 Long Term Incentive Plan, which was approved by the Board of our general partner in connection with our IPO. Please read Item 11 of this Annual Report on Form 10-K for additional information regarding the 2012 Long Term Incentive Plan.

Item 13.Certain Relationships and Related Transactions, and Director Independence

On November 12, 2013, ACON Refining Partners L.L.C. ("ACON Refining") and TPG Refining L.P. ("TPG Refining") contributed all of their interests in NTE LP, including their interest in Northern Tier Energy GP LLC, our non-economic general partner, to NT InterHoldCo LLC, which they subsequently sold to Western Refining for total consideration of $775 million plus the distribution on the common units acquired with respect to the quarter ended September 30, 2013. As a result of this transaction, Western Refining indirectly owns 100% of our general partner and approximately 38.7% of our outstanding common units.

Prior to this transaction, NT Holdings owned approximately 38.7% of our common units and our general partner was 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.

For a discussion of director independence, see Item 10. “Directors and Executive Officers of our General Partner and Corporate Governance.”

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 NT Holdings to Northern Tier Energy LP	•   The non-economic general partner interest issued to our general partner;
	•   54,844,500 common units issued to NT Holdings;
	•   18,383,000 PIK common units issued to NT Holdings. The repurchase and satisfaction and discharge of the 2017 Secured 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 common 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 NT Holdings. Upon the underwriters’ exercise their option to purchase additional common units in full, we made an additional distribution of approximately $32.0 million to NT 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 General Partner—Management Services Agreement.”

Operational Stage

Distributions to affiliates of our general partner	We expect to make distributions each quarter to our unitholders, including NT Holdings and NT InterHoldCo LLC
	Distributions on our units will be in cash. See “Item 7. 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.

Liquidation Stage

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

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Historical Transactions

Transactions with Marathon

Our refinery supplies the gasoline and diesel sold in the 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 independently-owned and operated Marathon branded convenience stores in our marketing area. For the year ended December 31, 2013, Marathon purchased $170 million of gasoline and diesel pursuant to this agreement. In addition, Marathon was issued $80 million of noncontrolling preferred interests in NT 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 IPO and NT Holdings redeemed Marathon’s existing preferred interest with a portion of the net proceeds from our IPO and issued Marathon a new $45 million noncontrolling preferred interest in NT Holdings. The settlement was contingent upon the consummation of our IPO.

Other Related Person Transactions

Chet Kuchta is our Chief Operating Officer and has served in that role since February 2013. Prior to being named Chief Operating Officer he was our Vice President, Supply and had served in that position since August 2011. He is the brother of Hank Kuchta, our President and Chief Executive Officer. During 2013, Mr. Chet Kuchta received aggregate compensation in the amount of $567,964.

Director Independence

For information related to our directors' independence, see "Item 10. Directors, Executive Officers, and Corporate Governance."

Item 14.Principal Accountant Fees and Services

We have engaged PricewaterhouseCoopers LLP as our independent registered public accounting firm. The following table presents fees for the audit of the Partnership’s annual consolidated financial statements for the last two fiscal years and for other services provided by PricewaterhouseCoopers LLP:

Thousands	2013		2012
Audit fees	$	1,572	$	1,734
Audit related	41		—
All other fees	2		2
Total	$	1,615	$	1,736

For 2013, audit fees consisted of fees billed for professional services rendered for (i) the audit of the Company’s 2013 consolidated financial statements, (ii) the audit of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2013, (iii) the review of the Company’s interim consolidated financial statements included in quarterly reports and (iv) other services that were regularly provided by PricewaterhouseCoopers LLP in connection with statutory and regulatory filings or engagements.

For 2012, audit fees consisted of fees billed for professional services rendered for (i) the audit of the Company’s 2012 consolidated financial statements, (ii) the review of the Company’s interim consolidated financial statements included in quarterly reports and (iii) other services that were regularly provided by PricewaterhouseCoopers LLP in connection with statutory and regulatory filings or engagements.

Audit Committee Approval of Audit and Non-Audit Services

The Audit Committee of the Partnership’s general partner has adopted a Pre-Approval Policy with respect to services that may be performed by PricewaterhouseCoopers LLP. This policy lists specific audit-related services as well as any other services that PricewaterhouseCoopers LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional Audit Committee authorization. The Audit Committee receives quarterly reports on the status of expenditures pursuant to that Pre-Approval Policy. The Audit Committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the Audit Committee or by its Chairperson, to whom such authority has been conditionally delegated, prior to engagement. During 2013, all fees reported above were approved in accordance with the Pre-Approval Policy.

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PART IV

Item 15.Exhibits and Financial Statement Schedules

(a) The following documents are filed as part of this Report:

(1)     Management's Report on Internal Controls Over Financial Reporting

Report of Independent Registered Public Accounting Firm

Consolidated Balance Sheets as of December 31, 2013 and 2012

Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2013, 2012 and 2011

Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011

Consolidated Statements of Partners' Capital and Member's Interest for the Years Ended December 31, 2013, 2012 and 2011

Notes to Consolidated Financial Statements

(2)     Exhibits

The following documents are filed or furnished as part of this annual report on Form 10-K. The Company will furnish a copy of any exhibit listed to requesting stockholders upon payment of the Company’s reasonable expenses in furnishing those materials.

Exhibit Number	Description
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).
3.3(a)	Third Amended and Restated Limited Liability Company Agreement of Northern Tier Energy GP LLC, dated November 12, 2013.
4.1	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).
4.2	Supplemental Indenture, dated as of November 2, 2012, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, the subsidiary guarantors party thereto and Deutsche Bank Trust Company Americas, as trustee and collateral agent (Incorporated by reference to our Current Report on Form 8-K, File No. 001-35162, filed on November 6, 2012).

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4.3	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).
10.1	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(c)	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).
10.5(c)	Retention Letter between Northern Tier Energy LLC and Dave Bonczek, dated December 20, 2013 (Incorporated by reference to Exhibit 10.1 to our current report on Form 8-K, File No. 001-35612, filed on December 26, 2013).
10.6(c)	Retention Letter between Northern Tier Energy LLC and Greg Mullins, dated December 1, 2010 (Incorporated by reference to Exhibit 10.2 to our current report on Form 8-K, File No. 001-35612, filed on December 26, 2013).
10.7	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).
10.8(c)	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).
†10.9	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).
10.10	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).
10.11	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).
10.12(c)	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).
10.13(c)	Form of Restricted Unit Agreement (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on December 17, 2012).
10.14(a)(c)	Form of 2012 Long Term Incentive Plan Restricted Unit Agreement (Performance-Based)

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21.1(a)	List of subsidiaries of Northern Tier Energy LP.
23.1(a)	Consent of PricewaterhouseCoopers LLP—Independent Registered Public Accounting Firm.
31.1(a)	Certification of Hank Kuchta, President and Chief Executive Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, for the December 31, 2013 Annual Report on Form 10-K, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2(a)	Certification of David Bonczek, Vice President and Chief Financial Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, for the December 31, 2013 Annual Report on Form 10-K, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1(b)	Certification of Hank Kuchta, President and Chief Executive Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, for the December 31, 2013 Annual Report on Form 10-K, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2(b)	Certification of David Bonczek, Vice President and Chief Financial Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, for the December 31, 2013 Annual Report on Form 10-K, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS(b)	XBRL Instance Document.
101.SCH(b)	XBRL Taxonomy Extension Schema Document.
101.CAL(b)	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF(b)	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB(b)	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE(b)	XBRL Taxonomy Extension Presentation Linkbase Document.

(a) Filed herewith.

(b) Furnished herewith.

(c) Denotes management contract, compensatory plan or arrangement

† Certain portions have been omitted pursuant to a confidential treatment request granted on May 14, 2012. Omitted information has been separately filed with the SEC.

135

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

Northern Tier Energy LP
By:	Northern Tier Energy GP LLC,
	its general partner

By:	/s/ Hank Kuchta
Name:	Hank Kuchta
Title:	President and Chief Executive Officer of Northern Tier Energy GP LLC (Principal Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the registrant and in the capacities and on the dates indicated:

Signature	Title	Date
/s/ HANK KUCHTA	President and Chief Executive Officer of Northern Tier Energy GP LLC (Principal Executive Officer)	February 27, 2014
Hank Kuchta
/s/ DAVID BONCZEK	Vice President and Chief Financial Officer of Northern Tier Energy GP LLC (Principal Financial Officer and Principal Accounting Officer)	February 27, 2014
David Bonczek
/s/ PAUL FOSTER	Director and Chairman of Northern Tier Energy GP LLC	February 27, 2014
Paul Foster
/s/ LOWRY BARFIELD	Director of Northern Tier Energy GP LLC	February 27, 2014
Lowry Barfield
/s/ TIMOTHY BENNETT	Director of Northern Tier Energy GP LLC	February 27, 2014
Timothy Bennett
/s/ ROCKY DUCKWORTH	Director of Northern Tier Energy GP LLC	February 27, 2014
Rocky Duckworth
/s/ THOMAS HOFMANN	Director of Northern Tier Energy GP LLC	February 27, 2014
Thomas Hofmann
/s/ DAN F. SMITH	Director of Northern Tier Energy GP LLC	February 27, 2014
Dan F. Smith
/s/ JEFF STEVENS	Director of Northern Tier Energy GP LLC	February 27, 2014
Jeff Stevens
/s/ SCOTT WEAVER	Director of Northern Tier Energy GP LLC	February 27, 2014
Scott Weaver

EXHIBIT INDEX

The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K.

Exhibit Number	Description
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).
3.3(a)	Third Amended and Restated Limited Liability Company Agreement of Northern Tier Energy GP LLC, dated November 12, 2013.
4.1	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).
4.2	Supplemental Indenture, dated as of November 2, 2012, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, the subsidiary guarantors party thereto and Deutsche Bank Trust Company Americas, as trustee and collateral agent (Incorporated by reference to our Current Report on Form 8-K, File No. 001-35162, filed on November 6, 2012).
4.3	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).
10.1	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(c)	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).
10.5(c)	Retention Letter between Northern Tier Energy LLC and Dave Bonczek, dated December 20, 2013 (Incorporated by reference to Exhibit 10.1 to our current report on Form 8-K, File No. 001-35612, filed on December 26, 2013).
10.6(c)	Retention Letter between Northern Tier Energy LLC and Greg Mullins, dated December 20, 2013 (Incorporated by reference to Exhibit 10.2 to our current report on Form 8-K, File No. 001-35612, filed on December 26, 2013).
10.7	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).
10.8(c)	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).
†10.9	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).
10.10	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).
10.11	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).
10.12(c)	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).
10.13(c)	Form of Restricted Unit Agreement (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on December 17, 2012).
10.14(a)(c)	Form of 2012 Long Term Incentive Plan Restricted Unit Agreement (Performance-Based)
21.1(a)	List of subsidiaries of Northern Tier Energy LP.
23.1(a)	Consent of PricewaterhouseCoopers LLP—Independent Registered Public Accounting Firm.
31.1(a)	Certification of Hank Kuchta, President and Chief Executive Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, for the December 31, 2013 Annual Report on Form 10-K, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2(a)	Certification of David Bonczek, Vice President and Chief Financial Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, for the December 31, 2013 Annual Report on Form 10-K, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1(b)	Certification of Hank Kuchta, President and Chief Executive Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, for the December 31, 2013 Annual Report on Form 10-K, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2(b)	Certification of David Bonczek, Vice President and Chief Financial Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, for the December 31, 2013 Annual Report on Form 10-K, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS(b)	XBRL Instance Document.
101.SCH(b)	XBRL Taxonomy Extension Schema Document.
101.CAL(b)	XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF(b)	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB(b)	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE(b)	XBRL Taxonomy Extension Presentation Linkbase Document.

(a) Filed herewith.

(b) Furnished herewith.

(c) Denotes management contract, compensatory plan or arrangement

† Certain portions have been omitted pursuant to a confidential treatment request granted on May 14, 2012. Omitted information has been separately filed with the SEC.